10-K

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Table of Contents
Index to Consolidated Financial Statements

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-K

ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2009
or
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
for the transition period from                        to

Commission File Number 001-31239

MARKWEST ENERGY PARTNERS, L.P.
(Exact name of registrant as specified in its charter)

Delaware (State or other jurisdiction of incorporation or organization)	27-0005456 (I.R.S. Employer Identification No.)
1515 Arapahoe Street, Tower 2, Suite 700, Denver, CO 80202-2126 (Address of principal executive offices)

Registrant's telephone number, including area code: 303-925-9200

         Securities registered pursuant to Section 12(b) of the Act: Common units representing limited partner interests, New York Stock Exchange

         Securities registered pursuant to Section 12(g) of the Act: None

         Indicate by check mark whether the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý    No o

         Indicate by check mark if the registrant is not required file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o    No ý

         Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý    No o

         Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o    No o

         Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

         Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer ý Accelerated filer o Non-accelerated filer o
(Do not check if a smaller
reporting company) Smaller reporting company o

         Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes o    No ý

         The aggregate market value of common units held by non-affiliates of the registrant on June 30, 2009 was approximately $944 million. As of February 22, 2010, the number of the registrant's common units were 66,545,872.

DOCUMENTS INCORPORATED BY REFERENCE:

         The information required by Part III of this Report, to the extent not set forth herein, is incorporated herein by reference from the registrant's definitive proxy statement relating to the Annual Meeting of Unitholders to be held in 2010, which definitive proxy statement shall be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year to which this Report relates.

MarkWest Energy Partners, L.P.
Form 10-K

Table of Contents

PART I
	Item 1.	Business	5
	Item 1A.	Risk Factors	29
	Item 1B.	Unresolved Staff Comments	48
	Item 2.	Properties	49
	Item 3.	Legal Proceedings	53
	Item 4.	Reserved	54
PART II
	Item 5.	Market for Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities	54
	Item 6.	Selected Financial Data	57
	Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	60
	Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	85
	Item 8.	Financial Statements and Supplementary Data	86
	Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	158
	Item 9A.	Controls and Procedures	158
	Item 9B.	Other Information	160
PART III
	Item 10.	Directors, Executive Officers and Corporate Governance	160
	Item 11.	Executive Compensation	160
	Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	160
	Item 13.	Certain Relationships and Related Transactions, and Director Independence	160
	Item 14.	Principal Accountant Fees and Services	160
PART IV
	Item 15.	Exhibits and Financial Statement Schedules	160
SIGNATURES			169

        Throughout this document we make statements that are classified as "forward-looking." Please refer to the "Forward-Looking Statements" included later in this section for an explanation of these types of assertions. Also, in this document, unless the context requires otherwise, references to "we," "us," "our," "MarkWest Energy" or the "Partnership" are intended to mean MarkWest Energy Partners, L.P., and its consolidated subsidiaries owned as of December 31, 2009. References to "MarkWest Hydrocarbon" or the "Corporation" are intended to mean MarkWest Hydrocarbon, Inc, a wholly-owned taxable subsidiary of the Partnership.

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Glossary of Terms

        The abbreviations, acronyms and industry technology used in this report are defined as follows.

Bbl	Barrels of oil
Bbl/d	Barrels of oil per day
Btu	One British thermal unit, an energy measurement
Dth/d	Dekatherms per day
EBITDA	Earnings Before Interest, Taxes, Depreciation and Amortization
FERC	Federal Energy Regulatory Commission
FASB	Financial Accounting Standards Board
GAAP	Accounting principles generally accepted in the United States of America
Gal	Gallon
Gal/d	Gallons per day
LIBOR	London Interbank Offered Rate
Mcf/d	One thousand cubic feet of natural gas per day
Merger	On February 21, 2008, the Partnership completed the transactions contemplated by its plan of redemption and merger with MarkWest Hydrocarbon, Inc. and MWEP, L.L.C., a wholly-owned subsidiary of the Partnership. Refer to Note 3 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.
MMBtu	One million British thermal units, an energy measurement
MMBtu/d	One million British thermal units per day
MMcf/d	One million cubic feet of natural gas per day
Net operating margin (a non-GAAP financial measure)	Revenue, excluding any derivative gain (loss), less purchased product costs, excluding any derivative gain (loss)
NGL	Natural gas liquids, such as ethane, propane, butanes and natural gasoline
N/A	Not applicable
OTC	Over-the-Counter
SEC	Securities and Exchange Commission

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Forward-Looking Statements

        Statements included in this Annual Report on Form 10-K that are not historical facts are forward-looking statements. We use words such as "could," "may," "will," "predict," "should," "expect," "hope," "continue," "potential," "plan," "project," "anticipate," "believe," "estimate," "intend" and similar expressions to identify forward-looking statements.

        These forward-looking statements are made based upon management's expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements.

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PART I

ITEM 1.    Business

General

        MarkWest Energy Partners, L.P. is a publicly traded Delaware limited partnership formed in January 2002. We are a master limited partnership engaged in the gathering, processing and transportation of natural gas; the transportation, fractionation, storage, and marketing of NGLs; and the gathering and transportation of crude oil. We conduct our operations in four geographical operating segments: Southwest, Northeast, Liberty and Gulf Coast. A map representing the location of the assets that comprise our segments is set forth below. Additional maps detailing the individual assets can be found on our Internet website, www.markwest.com. For more information on these segments, see the Our Operating Segments discussion below.

        The following table summarizes the operating performance for each segment for the year ended December 31, 2009 (amounts in thousands). For further discussion of our segments and a reconciliation to our consolidated statement of operations, see Note 26 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

		Southwest		Northeast		Liberty		Gulf Coast		Total
Revenue		$	492,369	$	260,529	$	47,968	$	57,769	$	858,635
Operating expenses:
	Purchased product costs		221,021		175,326		12,479		—		408,826
	Facility expenses		73,621		20,339		16,268		16,094		126,322
Total operating expenses before items not allocated to segments			294,642		195,665		28,747		16,094		535,148
Portion of operating income attributable to non-controlling interests			2,613		—		6,637		—		9,250
	Operating income before items not allocated to segments	$	195,114	$	64,864	$	12,584	$	41,675	$	314,237

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Organizational Structure

        On February 21, 2008, the Partnership and the Corporation completed the Merger by which the Corporation became a wholly owned subsidiary of the Partnership. In connection with the Merger, the 2% economic interest and incentive distribution rights in the Partnership owned by MarkWest Energy GP, L.L.C. (the "General Partner") and the Partnership common units owned by the Corporation were exchanged for Partnership Class A units. In a separate transaction completed simultaneously with the closing of the Merger, the Partnership acquired 100% of the Class B membership interests in the General Partner that had been held by current and former management and certain directors of the Corporation and the General Partner. The organizational structure resulting from this series of transactions is shown in the chart below. Please refer to Note 3 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further details about the Merger.

        The Corporation and the General Partner collectively own 22.6 million Class A units of the Partnership that were received in the Merger in exchange for the incentive distribution rights and the 2% economic interest in the Partnership held by the General Partner and common units held by the Corporation prior to the Merger. The following table provides the aggregate number of units and relative ownership interests of the Class A units and common units as of February 22, 2010 as follows (units in millions):

	Units		%
Class A units		22.6		25	%
Common units		66.5		75	%
Total units		89.1		100	%

        Class A units represent limited partner interests in the Partnership and have identical rights and obligations of the Partnership common units except that Class A units (i) do not have the right to vote on, approve or disapprove, or otherwise consent to or not consent to any matter (including mergers, share exchanges and similar statutory authorizations) except as otherwise required by any non-waivable provision of law and (ii) do not share in any cash and cash equivalents on hand, income, gains, losses, deductions and credits that are derived from or attributable to the Partnership's ownership of, or sale or disposition of, the shares of MarkWest Hydrocarbon common stock. The transaction structure involving the issuance of the Class A units in exchange for Partnership interests owned by the Corporation and the General Partner was adopted partially for tax purposes. The Class A units held by MarkWest Hydrocarbon and the General Partner are not treated as outstanding common units in the accompanying Consolidated Balance Sheets in accordance with GAAP related to consolidations.

        The ownership percentages in the graphic depicted below reflect the Partnership structure from the basis of the consolidated financial statements with the Class A units eliminated.

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        The primary benefit realized from the organizational structure resulting from the Merger is the elimination of the incentive distribution rights which represented the General Partner's right to receive an increasing percentage of quarterly distributions of available cash after a minimum quarterly distribution and certain target distribution levels had been achieved. The elimination of incentive distribution rights substantially lowers our cost of equity capital and increases the cash available to be distributed to our common unitholders. This enhances our ability to compete for new acquisitions and improves the returns to our unitholders on all future expansion projects.

Recent Developments

Liberty Joint Venture

        On February 27, 2009, we entered into a joint venture with M&R MWE Liberty LLC ("M&R"), an affiliate of NGP Midstream & Resources, L.P. and its affiliated funds, which is a private equity firm focused on investments in selected areas of the energy infrastructure and natural resources sectors. The joint venture entity MarkWest Liberty Midstream & Resources, L.L.C. ("MarkWest Liberty Midstream") operates in the natural gas midstream business in and around the Marcellus Shale in western Pennsylvania and northern West Virginia. MarkWest Liberty Midstream currently provides gathering and processing services under an agreement with an affiliate of Range Resources Corporation ("Range") and has agreements to begin providing these processing services to several other producers in 2010. MarkWest Liberty Midstream is managed by a Board of Managers, which currently consists of three managers designated by us and three managers designated by M&R. One of our wholly-owned subsidiaries serves as the operator of MarkWest Liberty Midstream and provides field operating and general and administrative services.

        Upon closing of the joint venture, we contributed our existing Marcellus Shale natural gas gathering and processing assets to MarkWest Liberty Midstream in exchange for a 60% ownership interest. M&R contributed cash of $50.0 million and agreed to contribute at least an additional $150.0 million during 2009 in exchange for a 40% ownership interest. Effective November 1, 2009, we

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and M&R executed the second amended and restated joint venture agreement whereby M&R agreed to increase its participation in MarkWest Liberty Midstream by at least an additional $150.0 million. Pursuant to the second amended and restated agreement, we and M&R members will maintain a 60%/40% respective ownership interest in MarkWest Liberty Midstream until January 1, 2011, at which time M&R's ownership interest will increase from 40% to 49%. We and M&R will continue to jointly fund the capital requirements of MarkWest Liberty Midstream at agreed upon levels until our contributed capital is proportionate to our 51% ownership interest (the "Equalization Date"), which is expected to occur on or before December 31, 2012. Following the Equalization Date, M&R will have pre-emptive rights to maintain its ownership interest in MarkWest Liberty Midstream in a range of between 45% and 49%. The joint venture will allow us to achieve our long-term objectives in the Marcellus Shale while significantly reducing capital requirements, which is a critical component of our balance sheet and liquidity objectives. For further discussion, please see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Note 4 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

Pioneer Joint Venture

        MarkWest Pioneer, L.L.C. ("MarkWest Pioneer") is the owner and operator of the Arkoma Connector Pipeline, a 50-mile FERC regulated pipeline that was placed in service in July 2009 and provides approximately 638,000 Dth/d of Woodford Shale takeaway capacity and interconnects with the Midcontinent Express Pipeline and the Gulf Crossing Pipeline.

        On May 1, 2009, we entered into a joint venture with Arkoma Pipeline Partners, LLC ("ArcLight"), an affiliate of ArcLight Capital Partners, LLC which is an investment firm focused on opportunities throughout the energy industry. ArcLight acquired a 50% equity interest in MarkWest Pioneer for a total purchase price of $62.5 million. We retained a 50% equity interest and were obligated to fund all capital expenditures necessary to complete construction of the Arkoma Connector Pipeline in excess of $125.0 million (the "Excess Capital Expenditures"). A wholly-owned subsidiary of the Partnership serves as the operator of MarkWest Pioneer and provides field operating and general and administrative services for fixed fees. For further discussion, please see Note 4 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

Sale of Steam Methane Reformer ("SMR Transaction")

        On September 1, 2009, we completed the sale of the steam methane reformer ("SMR") currently being constructed at our Javelina gas processing and fractionation facility in Corpus Christi, Texas. Under the terms of the agreement, we received proceeds of $73.1 million and the purchaser will complete the construction of the SMR, which is expected to cost an additional $20 million. We and the purchaser also executed a related hydrogen supply agreement under which we will receive all of the hydrogen produced by the SMR for the next 20 years in exchange for processing fees and the reimbursement of certain other expenses. The processing fee payments will begin when the SMR is capable of commencing operations, which is expected to occur in March 2010. In accordance with generally accepted accounting principles, we are deemed to have continuing involvement with the SMR as a result of certain provisions in the related agreements. Therefore, the SMR Transaction is treated as a financing arrangement, not an asset sale. For further discussion, please see Note 6 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

Sale of Starfish

        On December 31, 2009, we sold our 50% equity interest in Starfish Pipeline Company, LLC ("Starfish") to Enbridge Offshore (Gas Transmission), L.L.C. for a base purchase price of approximately $25.0 million, subject to post-closing adjustments for net working capital. For further discussion, please see Note 6 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

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Business Strategy

        Our primary business strategy is to provide top-tier midstream service by developing high-quality, strategically-located assets in the United States. We plan to accomplish this through the following:

•

Developing long-term integrated relationships with our producer customers.  As a top-rated midstream service provider, MarkWest has worked to redefine its relationships with its key producer customers as evidenced by our relationships with the primary producers in the Woodford Shale and the Marcellus Shale. We will continue to develop relationships that are characterized by joint planning for the development of the emerging resource plays and our commitment to grow to meet the specific needs of our customers.

•

Expanding operations through organic growth projects.  By expanding our existing infrastructure and customer relationships, we intend to continue growing in our primary areas of operation to meet the anticipated demand for additional midstream services. During 2009, we spent approximately $486.6 million of total capital to develop midstream infrastructure in the Marcellus Shale through MarkWest Liberty Midstream and to expand several of our gathering and processing operations in our Southwest segment including the expansion of our Woodford gathering system in the Arkoma Basin, the construction of the Arkoma Connector Pipeline in southeastern Oklahoma, and expansions of processing facilities in East Texas and in western Oklahoma, including our operations at Stiles Ranch. Other projects included completion of the expansion of our processing and fractionation facilities in the Northeast segment.

•

Maintaining our financial flexibility.  During 2009, we received net proceeds of $178.6 million from the issuance of equity and $113.8 million from the issuance of long-term debt. We also entered into an amendment to our credit agreement to expand our borrowing capacity under the revolving facility by $85.6 million from $350.0 million to $435.6 million. Our goal is to maintain a capital structure with approximately equal amounts of debt and equity on a long-term basis. We also consider the use of alternative financing strategies such as entering into joint venture arrangements and the sale of selected assets that are not a core component of our long-term objectives. We believe our credit facility, our ability to issue additional partnership units and long-term debt, our strong relationships with our joint venture partners, and the sale of non-strategic assets will provide us with the financial flexibility to facilitate the execution of our business strategy.

•

Reducing the sensitivity of our cash flows to commodity price fluctuations.  We intend to continue to secure long-term, fee-based contracts in order to further reduce our exposure to short-term changes in commodity prices. We expect that our fee-based contracts will account for approximately 50% our net operating margin by 2012. We also engage in risk management activities in order to reduce the effect of commodity price volatility related to future sales of natural gas, NGLs and crude oil. We may utilize a combination of fixed-price forward contracts, fixed-for-floating price swaps, and options available in the over-the-counter market. We monitor these activities through enforcement of our commodity risk management policy. Please refer to Note 7 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of our policy.

•

Increasing utilization of our facilities.  We seek to increase the utilization of our existing facilities by providing additional services to our existing customers, and by establishing relationships with new customers. We also continue to develop additional capacity at several of our facilities, which enables us to increase throughput with minimal incremental costs.

•

Expanding operations through strategic acquisitions.  We intend to continue pursuing strategic acquisitions of assets and businesses in our existing areas of operation that leverage our current asset base, personnel and customer relationships. We may also seek to acquire assets in certain regions outside of our current areas of operation. We believe that our capital structure, which no

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longer includes incentive distribution rights, positions us to compete more effectively for future transactions.

        Execution of our business strategy has allowed us to grow substantially since our inception. The majority of our growth since 2007 has focused on the development of natural gas supplies in emerging resource plays. As a result we now have a strong presence in the Woodford Shale, Haynesville Shale, Granite Wash and Marcellus Shale, four emerging resource plays that are expected to be a significant source of domestic natural gas production. The following table summarizes the magnitude of the growth projects and acquisitions that we have completed since 2004 (amounts in millions).

        We believe that the following competitive strengths position us to continue to successfully execute our primary business strategy:

•

Leading position in the early development of the Marcellus Shale.  As a result of strategic agreements with key producers, we are currently the largest gatherer and processor of natural gas in the Marcellus Shale. These long-term agreements include significant acreage dedications in the rich-gas areas of the shale. Our gathering systems and processing plants in the Marcellus are new and highly efficient and we continue to expand these facilities with a strong financial partner under the MarkWest Liberty Midstream joint venture arrangement. Leveraging our current and planned fractionation capacity, our strategic transportation and storage agreements that provide access to NGL markets, and our extensive marketing experience in the northeast region, we are positioned to offer fully integrated midstream services for the producers in the Marcellus Shale.

•

Strategic and growing position with high-quality assets in the Southwest and the Gulf Coast. Our acquisitions and internal growth projects have allowed us to establish and expand our presence in several long-lived natural gas supply basins in the Southwest, particularly in Texas and Oklahoma. In late 2006, we began expanding this strategy through our agreement with Newfield Exploration Mid-Continent Inc. by building the largest gathering system to date in the Woodford Shale play in Southeast Oklahoma. Our Gulf Coast assets provide high quality service to six strategically located gulf coast refineries that we believe will continue to play a key role in supporting U.S. demand for refined petroleum products in the long term. All of our major acquisitions in these regions have been characterized by several common critical success factors that include:

•

an existing strong competitive position;

•

access to a significant reserve or customer base with a stable or growing production profile;

•

ample opportunities for long-term continued organic growth;

•

ready access to markets; and

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•

close proximity to other acquisition or expansion opportunities.

Specifically, our East Texas and Appleby gathering systems are located in the East Texas Basin, producing from both the Cotton Valley and Travis Peak reservoirs as well as the Haynesville Shale. Our Foss Lake gathering system and the associated Arapaho gas processing plants are located in the Anadarko Basin in Oklahoma and are connected to the Granite Wash area in the Texas panhandle. Additionally, as mentioned above, our Woodford gathering system is located in the Woodford Shale reservoir. Our gathering systems are relatively new and provide producers with low-pressure and fuel-efficient service, a significant competitive advantage for us over many competing gathering systems in those areas. We believe this competitive advantage is evidenced by our growing throughput volumes in our East Texas, Appleby, Woodford and Western Oklahoma operations.

•

Leading position and continued expansion in the Appalachian Basin.  We are the largest processor of natural gas in Appalachia. We believe our significant presence and asset base provide us with a competitive advantage in capturing and contracting for new supplies of natural gas. The Appalachian Basin is a large natural gas-producing region characterized by long-lived reserves with modest decline rates and natural gas with high NGL content. Our concentrated infrastructure, and available land, storage assets and expansion plans in Appalachia should continue to provide us with a platform for additional cost-effective expansion opportunities. In 2009, we completed the expansion of our Cobb facility and the expansion of our Siloam fractionation facility.

•

Long-term Contracts.  We believe our long-term contracts, which we define as contracts with remaining terms of four years or more, lend greater stability to our cash flow profile. In East Texas, approximately 73% of our current gathering volumes are under contract for longer than five years as of December 31, 2009. Due to new contracts signed in late 2008 and 2009, approximately 57% of our current daily throughput in the Western Oklahoma gathering system and Arapaho processing plants are subject to contracts with remaining terms of more than eight years. Approximately 94% of our throughput in the Woodford gathering system is subject to contracts with remaining terms of more than seven years. Also in the Southwest segment, two of our lateral pipelines operate under fixed-fee contracts for the transmission of natural gas that expire in approximately 19 and 11 years, respectively. In Appalachia, our natural gas processing and NGL fractionation contracts with remaining terms of more than five years account for approximately 83% of our volumes. In the Gulf Coast segment, approximately 56% of our volumes are under contract for more than four years. In the Liberty segment, all of our current gathering and processing agreements with significant dedicated acreage have remaining terms of at least ten years.

•

Experienced management with operational, technical and acquisition expertise.  Each member of our executive management team has substantial experience in the energy industry. Our facility managers have extensive experience operating our facilities. Our operational and technical expertise has enabled us to upgrade our existing facilities, as well as to design and build new ones. Since our initial public offering in May 2002, our management team has utilized a disciplined approach to analyze and evaluate numerous acquisition opportunities, and has completed eleven acquisitions.

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Industry Overview

        We provide services in the midstream sector of the natural gas industry which includes natural gas gathering, transportation, processing and fractionation. The following diagram illustrates the typical natural gas gathering, processing and fractionation process:

        The natural gas gathering process begins with the drilling of wells into gas-bearing rock formations. Once completed, the well is connected to a gathering system. Gathering systems typically consist of a network of small diameter pipelines and, if necessary, compression systems, that collect natural gas from points near producing wells, and transport it to larger pipelines for further transmission.

        Historically, the majority of the domestic on-shore natural gas supply has been produced from conventional reservoirs that are characterized by large pockets of natural gas that are accessed successfully using vertical drilling techniques. In the past decade, the supply of natural gas production from the conventional sources has declined as these reservoirs are being depleted. Due to advances in well completion technology and horizontal drilling techniques, unconventional sources such as shale, tight sand and coal bed methane formations, have become the most significant source of current and expected future natural gas production. Due to the ability to economically produce natural gas from these emerging sources, current U.S. natural gas reserves are expected to provide at least 90 years of supply based on projected annual domestic consumption.

        Natural gas has a widely varying composition, depending on the field, the formation reservoir or facility from which it is produced. The principal constituents of natural gas are methane and ethane. Most natural gas also contains varying amounts of heavier components, such as propane, butane, natural gasoline and inert substances that may be removed by any number of processing methods.

        Most natural gas produced at the wellhead is not suitable for long-haul pipeline transportation or commercial use. It must be gathered, compressed and transported via pipeline to a central facility, and then processed to remove the heavier hydrocarbon components and other constituents or contaminants that may interfere with pipeline transportation or the end-use of the gas. Our business includes providing these services either for a fee or a percentage of the NGLs removed or gas units processed. The industry as a whole is characterized by regional competition, based on the proximity of gathering systems and processing plants to producing natural gas wells, or to facilities that produce natural gas as a byproduct of refining crude oil. Due to the shift in the source of natural gas production, midstream providers with a significant presence in the emerging resource plays will likely have a competitive advantage.

        We also provide processing and fractionation services to crude oil refineries in the Corpus Christi, Texas, area through our Javelina Gas Processing and Fractionation facility. While similar to the natural

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gas industry diagram outlined above, the following diagram illustrates the significant gas processing and fractionation processes at the Javelina facility:

        Natural gas processing and treating involves the separation of raw natural gas into pipeline-quality natural gas, principally methane, and NGLs, as well as the removal of contaminants. Raw natural gas from the wellhead is gathered at a processing plant, typically located near the production area, where it is dehydrated and treated, and then processed to recover a mixed NGL stream. In the case of our Javelina facilities, the natural gas delivered to our processing plant is a byproduct of the crude oil refining process.

        The removal and separation of individual hydrocarbons and other constituents by processing is possible because of differences in physical properties. Each component has a distinctive weight, boiling point, vapor pressure and other physical characteristics. Natural gas may also be diluted or contaminated by water, sulfur compounds, carbon dioxide, nitrogen, helium or other components. We also produce a high quality hydrogen stream that is delivered back to certain refinery customers.

        After being separated from natural gas at the processing plant, the mixed NGL stream is typically transported to a centralized facility for fractionation. Fractionation is the process by which NGLs are further separated into individual, more marketable components, primarily ethane, propane, normal butane, isobutane and natural gasoline. Fractionation systems typically exist either as an integral part of a gas processing plant or as a "central fractionator," often located many miles from the primary production and processing facility. A central fractionator may receive mixed streams of NGLs from many processing plants.

        Five basic NGL products and their typical uses are discussed below. The basic products are sold in all of our segments except as noted.

•

Ethane is used primarily as feedstock in the production of ethylene, one of the basic building blocks for a wide range of plastics and other chemical products.

Ethane is not produced at our Siloam fractionator, as there is little petrochemical demand for ethane in Appalachia. It remains, therefore, in the natural gas stream. Ethane, however, is produced and sold in our East Texas, Gulf Coast and Oklahoma operations.

•

Propane is used for heating, engine and industrial fuels, agricultural burning and drying, and as a petrochemical feedstock for the production of ethylene and propylene. Propane is principally used as a fuel in our operating areas.

•

Normal butane is principally used for gasoline blending, as a fuel gas, either alone or in a mixture with propane, and as a feedstock for the manufacture of ethylene and butadiene, a key ingredient of synthetic rubber.

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•

Isobutane is principally used by refiners to enhance the octane content of motor gasoline.

•

Natural gasoline is principally used as a motor gasoline blend stock or petrochemical feedstock.

Our Operating Segments

        We conduct our operations in four geographical operating segments: Southwest, Northeast, Liberty, and Gulf Coast. Our assets and operations in each of these segments are described below.

Southwest Segment

•

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 region, we purchase the NGLs from the producers primarily under percent-of-proceeds arrangements, or we transport volumes for a fee. Approximately 83% of our natural gas volumes in the East Texas System result from contracts with six producers. We sell substantially all of the purchased and retained NGLs produced at our East Texas processing facility to Targa Resources Partners, L.P. ("Targa") under a long-term contract. Such sales represent approximately 15.7% of our consolidated revenue in 2009. For the year ended December 31, 2009, the contract contributed 7% to net operating margin (a non-GAAP measure, see Our Contracts below for discussion and reconciliation of net operating margin). The original term of the Targa agreement expires in December 2015.

•

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. The majority of the gathered gas ultimately is compressed and delivered to the processing plants. 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. Approximately 66% of our Oklahoma volumes result from contracts with three producers. The Oklahoma region has one customer to which we sell NGLs which account for a significant portion of the Southwest segment revenue, but sales to this customer do not account for a significant portion of our consolidated revenue in 2009.

Through our joint venture MarkWest Pioneer, we operate the Arkoma Connector Pipeline, a 50-mile FERC regulated pipeline that provides approximately 638,000 Dth/d of Woodford Shale takeaway capacity and interconnects with Midcontinent Express Pipeline and Gulf Crossing Pipeline at Bennington, Oklahoma. For a complete discussion of the formation of, and accounting treatment for, MarkWest Pioneer, see Note 4 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

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Other Southwest.  We own a number of natural gas-gathering systems located in Texas, Louisiana, Mississippi and New Mexico, including the Appleby gathering system in Nacogdoches County, Texas. We gather a significant portion of the gas produced from fields adjacent to our gathering systems, including from wells targeting the Haynesville formation. 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. The Other

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Southwest area does not have any customers which we consider to be significant to the Southwest segment revenue or our consolidated revenue.

Northeast Segment

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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. The Appalachia area has one customer which accounts for a significant portion of the Northeast segment revenue, but this customer does not account for a significant portion of our consolidated revenue.

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Michigan.  We own and operate a FERC regulated crude oil pipeline in Michigan ("Michigan Crude Pipeline") providing transportation service for six shippers. Effective November 1, 2009, the Partnership sold its interest in Basin Pipeline, LLC for nominal consideration.

Liberty Segment

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Marcellus Shale.  We operate natural gas gathering systems and processing facilities located primarily in western Pennsylvania and northern West Virginia through MarkWest Liberty Midstream. We have a 35 MMcf/d cryogenic plant, and a 120 MMcf/d cryogenic plant at our Houston, Pennsylvania processing complex. We plan to complete the installation of a 120 MMcf/d cryogenic plant at our Majorsville site in the third quarter of 2010. We also plan to complete a 37,000 Bbl/d fractionation facility at our Houston complex in the first half of 2011. We are currently designing additional expansions of our processing capacity and in 2011, we expect to further increase our gas gathering and cryogenic processing capacity in the Marcellus Shale to as much as 475 MMcf/d, all of which we expect to be supported by long-term agreements with our producer customers. We are also constructing a connection to a key interstate NGL pipeline providing a market outlet for the propane produced at our Liberty facilities. For a complete discussion of the formation of, and accounting treatment for, MarkWest Liberty Midstream, see Note 4 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

Gulf Coast Segment

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Javelina.  We own and operate the Javelina Processing Facility, a natural gas processing facility in Corpus Christi, Texas, which treats and processes off-gas from six local refineries operated by three different refinery customers. We have a hydrogen supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the hydrogen processed by the SMR that is operated by a third party (see Note 6 of the accompanying Notes to Consolidated Financial Statements for further discussion of this agreement and the related SMR Transaction). The hydrogen received under this agreement will be sold to a refinery customer pursuant to a corresponding long-term agreement.

        The following summarizes the percentage of our revenue and net operating margin (a non-GAAP financial measure, see Our Contracts discussion below) generated by our assets, by segment, for the year ended December 31, 2009:

	Southwest			Northeast			Liberty			Gulf Coast			Total
Revenue		57	%		30	%		6	%		7	%		100	%
Net operating margin		60	%		19	%		8	%		13	%		100	%

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        For further financial information regarding our segments, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations and Item 8. Financial Statements and Supplementary Data included in this Form 10-K.

        We own a 40% non-operating membership interest in Centrahoma Processing LLC ("Centrahoma"), a joint venture with Antero Midstream Resources Corporation that is accounted for using the equity method. 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 play to Centrahoma through March 1, 2018. The financial results for Centrahoma are included in Earnings from unconsolidated affiliates and are not included in our segment results.

Our Contracts

        We generate the majority of our revenues and net operating margin (a non-GAAP measure, see below 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:

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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 generally 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. If a sustained decline in commodity prices were to result in a decline in volumes, however, our revenues from these arrangements would be reduced. In certain cases, our arrangements provide for minimum annual payments, fixed demand charges, or fixed returns on gathering system expenditures.

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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.

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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.

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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

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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 or the relative price of NGLs to natural gas. 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.

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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.

        As of December 31, 2009, our primary exposure to keep-whole contracts was limited to our Appalachian, Western Oklahoma (Arapaho), East Texas (Carthage), and Woodford processing agreements.

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Approximately 59% of the NGLs sold from Appalachia relate to keep-whole contracts for the year ended December 31, 2009.

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At the inlets to the Arapaho plants, natural gas meets the downstream pipeline specification; however, we have the option of extracting NGLs when the processing margin environment is favorable. All of our gas gathering contacts in Western Oklahoma are keep-whole, but some of the contracts include additional fees to cover plant operating costs, fuel costs and shrinkage costs in a low-processing margin environment. Our keep-whole contract exposure is further mitigated due to our ability to operate the Arapaho plants in several recovery modes.

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Approximately 6% of the gas processed in East Texas for producers was processed under keep-whole terms for the year ended December 31, 2009.

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Approximately 40 MMcf/d of the gas in the Woodford system is rich with NGLs and is processed under keep-whole contracts. Our keep-whole contract exposure is partially mitigated by our ability to operate in several recovery modes.

        Our keep-whole exposure in all areas was partially offset by the settlement margin related to certain gathering and compression arrangements. The excess natural gas retained under these arrangements reduced the amount of replacement natural gas purchases required to keep our producers whole on an MMBtu basis, thereby creating a partial natural hedge. We also have an active commodity risk management program in place to reduce the impacts of changing NGL and natural gas prices and our keep-whole exposure.

        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

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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 use 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 from operations, the most comparable GAAP financial measure of this non-GAAP financial measure (in thousands):

		Year ended December 31,
		2009			2008			2007
Revenue		$	858,635		$	1,060,662		$	845,727
Purchased product costs			408,826			615,902			487,892
	Net operating margin		449,809			444,760			357,835
Facility expenses			126,977			103,682			70,863
Total derivative loss (gain)			188,862			(254,813	)		175,148
Selling, general and administrative expenses			63,728			68,975			72,484
Depreciation			95,537			67,480			41,281
Amortization of intangible assets			40,831			38,483			16,672
Loss on disposal of property, plant and equipment			1,677			178			7,743
Accretion of asset retirement obligations			198			129			114
Impairment of goodwill and long-lived assets			5,855			36,351			356
	(Loss) income from operations	$	(73,856	)	$	384,295		$	(26,826	)

        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 7 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K. For the year ended December 31, 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		20	%		38	%		6	%		36	%		100	%
Net operating margin		39	%		26	%		4	%		31	%		100	%

(1)

Includes condensate sales and other types of arrangements tied to NGL prices.

(2)

Includes arrangements tied to natural gas prices.

(3)

Includes 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 18%, respectively.

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Competition

        In each of our operating segments, we face competition for natural gas and crude oil transportation and in obtaining natural gas supplies for our processing and related services operations; in obtaining unprocessed NGLs for fractionation; and in marketing our products and services. 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. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and industry marketing centers, and cost efficiency and reliability of service. Competition for customers is based primarily on price, delivery capabilities, flexibility and maintenance of high-quality customer relationships.

        Our competitors include:

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other large natural gas gatherers that gather, process and market natural gas and NGLs;

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major integrated oil companies;

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medium and large sized independent exploration and production companies;

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major interstate and intrastate pipelines; and

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a large number of smaller gas gatherers of varying financial resources and experience.

        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 that our customer focus in all segments, demonstrated by our ability to offer an integrated package of services and our flexibility in considering various types of contractual arrangements allows us to compete more effectively. Additionally, we have critical connections to the key market outlets for NGLs and natural gas in each of our segments. In our Gulf Coast segment, the strategic location of our assets and the long-term nature of our contracts provide a significant competitive advantage. In the Southwest segment our major gathering systems are relatively new and provide producers with low-pressure and fuel-efficient service, which differentiates us from many competing gathering systems in those areas. In the Northeast segment, our operational experience of over 20 years and our existing presence in the Appalachian Basin provide a significant competitive advantage. In the Liberty segment, our early entrance in the Marcellus Shale through our strategic gathering and processing agreements with key producers enhances our competitive position to participate in the further development of the Marcellus Shale.

Seasonality

        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.

Regulatory Matters

        Our operations are subject to extensive regulations. The failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on our operations increases our

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cost of doing business and, consequently, affects our profitability. However, we do not believe that we are affected in a significantly different manner by these laws and regulations than are our competitors. Due to the myriad of complex federal, state, provincial and local regulations that may affect us, directly or indirectly, reliance on the following discussion of certain laws and regulations should not be considered an exhaustive review of all regulatory considerations affecting our operations.

Pipeline and Gathering Regulation

        FERC Regulated Gas Pipelines.    Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Specifically, our Hobbs, New Mexico natural gas pipeline, our Arkoma Connector natural gas pipeline in Oklahoma, and our Michigan Crude Pipeline and related assets are subject to regulation by FERC. Federal regulation extends to such matters as:

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rate structures;

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return on equity;

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recovery of costs;

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the services that our regulated assets are permitted to perform;

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the acquisition, construction and disposition of assets; and

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to an extent, the level of competition in that regulated industry.

        Under the Natural Gas Act ("NGA"), FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service. The rates and terms and conditions for our service will be found in FERC-approved tariffs. Pursuant to FERC's jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot assure you that FERC will continue to pursue its approach of procompetitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, and transportation facilities. Any successful complaint or protest against our rates, or loss of market-based rate authority by FERC could have an adverse impact on our revenues associated with providing interstate gas transportation services.

        Energy Policy Act of 2005.    On August 8, 2005, President Bush signed into law the Domenici-Barton Energy Policy Act of 2005 ("2005 EP Act"). Under the 2005 EP Act, FERC may impose civil penalties of up to $1,000,000 per day for each current violation of the NGA or the Natural Gas Policy Act of 1978. The 2005 EP Act also amends the NGA to add an anti-market manipulation provision, which makes it unlawful for any entity to engage in prohibited behavior in contravention of rules and regulations to be prescribed by FERC. FERC issued Order No. 670 to implement the anti-market manipulation provision of 2005 EP Act. This order makes it unlawful for gas pipelines and storage companies that provide interstate services to: (1) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; (2) to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (3) to engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule and

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enhanced civil penalty authority reflect an expansion of FERC's enforcement authority. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot assure you that present policies pursued by FERC and Congress will continue.

        Standards of Conduct.    On October 16, 2008, FERC issued a Final Rule ("Order 717") revising the FERC Standards of Conduct for natural gas and electric transmission providers by eliminating its earlier concept of Energy Affiliates and corporate separation in favor of an employee functional approach. A transmission provider is prohibited from disclosing to a marketing function employee non-public information about the transmission system or a transmission customer. Order 717 also retains the long-standing no-conduit rule, which prohibits a transmission function provider from disclosing non-public information to marketing function employees by using a third party conduit. Additionally, Order 717 requires that a transmission provider provide annual training on the Standards of Conduct to all transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information. This rule became effective November 26, 2008.

        FERC issued Order 717-A, an order on rehearing and clarification of Order 717, on October 15, 2009. FERC issued a second rehearing order, Order 717-B, on November 15, 2009. Requests for rehearing of Order 717-B have been filed and are currently pending before FERC. We have no way to predict with certainty whether and to what extent FERC will revise the new standards of conduct in response to those requests for rehearing.

        Market Transparency Rulemakings.    In 2007, FERC issued a final rule on the annual natural gas transaction reporting requirements, as amended by subsequent orders on rehearing ("Order 704"). The order became effective February 4, 2008. Under Order 704, wholesale buyers and sellers of more than 2.2 million MMBtu of physical natural gas in the previous calendar year, including interstate and intrastate natural gas pipelines, natural gas gatherers, natural gas processors and natural gas marketers, are now required to report, on May 1 of each year, beginning in 2009, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to, or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which transactions should be reported based on the guidance of Order 704. Order 704 will require most, if not all of our natural gas pipelines to report annual volumes of relevant transactions to FERC. On November 20, 2008, FERC issued a final rule on daily scheduled flows and capacity posting requirements ("Order 720"). Under Order 720, certain non-interstate pipelines delivering, on an annual basis, more than an average of 50 million MMBtu of gas over the previous three (3) calendar years, are required to post daily certain information regarding the pipeline's capacity and scheduled flows for each receipt and delivery point that has a design capacity equal to or greater than 15,000 MMBtu per day. In response to requests for clarification and rehearing, FERC issued Order 720-A on January 21, 2010, which clarified certain of the rules promulgated under Order 720 and established July 1, 2010 as the deadline for applicable non-interstate pipelines to meet the daily posting requirement. A petition for review of Orders 720 and 720-A has been filed and is currently pending before the Court of Appeals for the Fifth Circuit. In addition, requests for clarification and/or rehearing of Order 720-A are currently pending before FERC. We have no way to predict with certainty whether and to what extent Orders 720 and 720-A may be modified as a result of the petition for review or the requests for clarification and/or rehearing.

        FERC Equity Return Allowance.    On April 17, 2008, FERC adopted a new policy under Docket No. PL07-2-000 that will allow master limited partnerships to be included in proxy groups for the purpose of determining rates of return for both interstate natural gas and oil pipelines. The policy statement will govern all future gas and oil rate proceedings involving the establishment of a return on equity, as well as those cases that are currently pending before either FERC or an administrative law

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judge. On May 19, 2008, an application for rehearing was filed by The American Public Gas Association. On June 13, 2008, FERC dismissed the request for rehearing.

        Gathering and Intrastate Pipeline Regulation.    Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC. We own a number of facilities that we believe meet the traditional tests FERC has used to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. In the states in which we operate, regulation of gathering facilities and intrastate pipeline facilities generally includes various safety, environmental and, in some circumstances, open access, nondiscriminatory take requirement and complaint- based rate regulation. For example, some of our natural gas gathering facilities are subject to state ratable take and common purchaser statutes. Ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase gas without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

        Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a less stringent approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional capital expenditures and increased costs depending on future legislative and regulatory changes.

        Our intrastate gas pipeline facilities are subject to various state laws and regulation that affect the rates we charge and terms of service. Although state regulation is typically less onerous than at FERC, state regulation typically requires pipelines to charge just and reasonable rates and to provide service on a non-discriminatory basis. The rates and service of an intrastate pipeline generally are subject to challenge by complaint.

        Our Appalachian pipeline carries NGLs across state lines. We are the only shipper on the pipeline. We neither operate our Appalachian pipeline as a common carrier, nor hold it out for service to the public. Generally, there are currently no third-party shippers on this pipeline and the pipeline is, and will continue to be, operated as a proprietary facility. The likelihood of other entities seeking to utilize our Appalachian pipeline is remote, so it should not be subject to regulation by FERC in the future. We cannot provide assurance, however, that FERC will not at some point assert that such transportation is within its jurisdiction, or that such an assertion would not adversely affect our results of operations. In such a case, we would be required to file a tariff with FERC and provide a cost justification for the transportation charge.

        The natural gas pipeline connecting the Stiles Ranch gathering assets to our Arapaho processing plants carries natural gas across state lines. This pipeline is a gathering line that is not subject to FERC jurisdiction. We cannot provide assurance, however, that FERC will not at some point assert that such transportation is within its jurisdiction, or that such an assertion would not adversely affect our results of operations. In such a case, we would be required to file a tariff with FERC and provide a cost justification for the transportation charge.

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        Propane Regulation.    National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states these laws are administered by state agencies, and in others they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the DOT. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We maintain various permits that are necessary to operate our facilities, some of which may be material to our propane operations. We believe that the procedures currently in effect at all of our facilities for the handling, storage and distribution of propane are consistent with industry standards and are in compliance in all material respects with applicable laws and regulations.

        Crude Common Carrier Pipeline Operations.    Our Michigan Crude Pipeline is a crude oil pipeline that is a common carrier and subject to regulation by FERC under the October 1, 1977 version of the Interstate Commerce Act ("ICA") and the Energy Policy Act of 1992 ("EPAct 1992"). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on the interstate common carrier liquids pipelines and generally require the rates and practices of interstate liquids pipelines to be just and reasonable and nondiscriminatory. The ICA also requires tariffs to be maintained on file with FERC that set forth the rates it charges for providing transportation services on its interstate common carrier liquids pipelines as well as the rules and regulations governing these services. EPAct 1992 and its implementing regulations allow interstate common carrier oil pipelines to annually index their rates up to a prescribed ceiling level. In addition, FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.

        With respect to our Michigan Crude Pipeline, on February 24, 2009, we filed to increase rates effective April 1, 2009 to incorporate index increases that were not fully taken over the prior three years because of a previously effective settlement that had since expired. FERC rejected the filing. On May 29, 2009 we filed to increase rates pursuant to FERC's 2009-2010 index adjustment, and those rate increases took effect July 1, 2009.

Environmental Matters

General.

        Our processing and fractionation plants, pipelines, and associated facilities are subject to multiple obligations and potential liabilities under a variety of stringent and comprehensive federal, state and local laws and regulations governing discharges of materials into the environment or otherwise relating to environmental protection. Such laws and regulations affect many aspects of our present and future operations, such as requiring the acquisition of permits or other approvals to conduct regulated activities that may impose burdensome conditions or potentially cause delays, restricting the manner in which we handle or dispose of our wastes, limiting or prohibiting activities in sensitive areas such as wetlands, ecologically-sensitive areas, or areas inhabited by endangered species, incurring capital costs to construct, maintain and upgrade equipment and facilities, restricting the locations in which we may construct our compressor stations and other facilities or requiring the relocation of existing stations and facilities, and requiring remedial actions to mitigate pollution caused by our operations or attributable to former operations. Failure to comply with these stringent and comprehensive requirements may expose us to the assessment of administrative, civil and criminal penalties, the imposition of remedial requirements and the issuance of orders enjoining or limiting some or all of our operations.

        We believe that our operations and facilities are in substantial compliance with applicable environmental laws and regulations, and that the cost of continued compliance with such laws and regulations will not have a material adverse effect on our results of operations or financial condition.

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We cannot ensure, however, that existing environmental laws and regulations will not be reinterpreted or revised or that new laws and regulations will not be adopted or become applicable to us. The clear trend in environmental law is to place more restrictions and limitations on activities that may be perceived to affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental-regulation compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional environmental requirements that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial condition, results of operations and cash flow. We may not be able to recover some or any of these costs from insurance.

Hazardous Substance and Waste.

        To a large extent, the environmental laws and regulations affecting our operations relate to the release of hazardous substances or solid wastes into soils, groundwater, and surface water, and include measures to control environmental pollution of the environment. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, also known as the "Superfund" law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to a release of "hazardous substance" into the environment. These persons include current and prior owners or operators of a site where a release occurred and companies that transported or disposed or arranged for the transportation or disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to strict and, under certain circumstances, joint and several liability for the costs of removing or remediating hazardous substances that have been released into the environment, for restoration costs and damages to natural resources, and for the costs of certain health studies. Additionally, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment. While we generate materials in the course of our operations that are regulated as hazardous substances under CERCLA or similar state statutes, we do not believe that we have any material liability for cleanup costs under such laws. We also may incur liability under the Resource Conservation and Recovery Act, as amended, or RCRA, and comparable state statutes, which impose requirements relating to the handling and disposal of hazardous wastes and nonhazardous solid wastes. We are not currently required to comply with a substantial portion of the RCRA requirements because our operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by us that are currently classified as nonhazardous may in the future be designated as hazardous wastes, resulting in the wastes being subject to more rigorous and costly disposal requirements.

        We currently own or lease, and have in the past owned or leased, properties that have been used over the years for natural gas gathering, processing and transportation, for NGL fractionation, or for the storage, gathering and transportation of crude oil. Although solid waste disposal practices within the NGL industry and other oil and natural gas related industries have improved over the years, a possibility exists that petroleum hydrocarbons and other solid wastes or hazardous wastes may have been disposed of on or under various properties owned or leased by us during the operating history of those facilities. In addition, a number of these properties may have been operated by third parties whose treatment and disposal or release of petroleum hydrocarbons or other wastes was not under our control. These properties and wastes disposed thereon may be subject to CERCLA, RCRA, and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes or property contamination, including groundwater contamination or to perform remedial operations to prevent future contamination. We do not believe that there presently exists significant surface and subsurface contamination of our properties by petroleum hydrocarbons or other solid wastes for which we are currently responsible.

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Ongoing Remediation and Indemnification from a Third Party.

        The previous owner or operator of our Cobb, Boldman, Kenova, Kermit and Majorsville facilities has been, or is currently involved in, investigatory or remedial activities with respect to the real property underlying this facility. These investigatory and remedial obligations arise out of a September 1994 "Administrative Order by Consent for Removal Actions" with EPA Regions II, III, IV, and V; and with respect to the Boldman facility, an "Agreed Order" entered into by the previous owner/operator with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The previous owner/operator has accepted sole liability and responsibility for, and indemnifies us against, any environmental liabilities associated with the EPA Administrative Order, the Kentucky Agreed Order or any other environmental condition related to the real property prior to the effective dates of our lease or purchase of the real property. In addition, the previous owner/operator has agreed to perform all the required response actions at its expense in a manner that minimizes interference with our use of the properties. To date, the previous owner/operator has been performing all actions required under these agreements and, accordingly, we do not believe that the remediation obligation of these properties will have a material adverse impact on our financial condition or results of operations.

Water.

        The Federal Water Pollution Control Act of 1972, as amended, also known as the "Clean Water Act," and analogous state laws impose restrictions and controls on the discharge of pollutants into federal and state waters. Such discharges are prohibited, except in accord with the terms of a permit issued by the EPA or the analogous state agency. Spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a hydrocarbon tank spill, rupture or leak. Any unpermitted release of pollutants, including oil, natural gas liquids or condensates, could result in penalties, as well as significant remedial obligations. In June 2009, MarkWest Liberty Midstream agreed to pay civil penalties and administrative oversight costs in an aggregate amount of $0.2 million and to perform certain corrective actions, the cost of which is not expected to have a material impact on our financial condition, liquidity, or results of operations. In addition, the The Clean Water Act and analogous state law may also require individual permits or coverage under general permits for discharges of stormwater from certain types of facilities, but these requirements are subject to several exemptions specifically related to oil and gas operations and facilities. We conduct regular review of the applicable laws and regulations, and maintain discussions with the various state agencies with regard to the application of those laws and regulations to our facilities. We have been in negotiations with the Pennsylvania State enumerated agency regarding the permitting process and categories of applicable permits for stream crossings that may be required for the construction or operation of certain of our facilities in the state. We believe that we are in substantial compliance with the Clean Water Act.

        Activities of natural gas exploration and production operators with whom we have a business relationship may include the performance of hydraulic fracturing to enhance the production of natural gas from formations with low permeability, such as shales. Due to concerns raised concerning potential impacts of hydraulic fracturing on groundwater quality, legislative and regulatory efforts at the federal level and in some states have been initiated to render permitting and compliance requirements more stringent for hydraulic fracturing. Such efforts could have an adverse effect on natural gas production activities in shale formations, including the Marcellus Shale, which in turn could have an adverse effect on the gathering, transportation, processing and/or fracturing operations that we render for our exploration and production customers

Air and Greenhouse Gases.

        The Clean Air Act, as amended, and comparable state laws restrict the emission of air pollutants from many sources in the U.S., including processing plants and compressor stations, and also impose

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various monitoring and reporting requirements. These laws and any implementing regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements, or utilize specific equipment or technologies to control emissions, or may be subject to reinterpretation and require the co-location of our facilities for permitting purposes. As the result of changes to the Clean Air Act, we may be required to incur certain capital expenditures for air pollution control equipment in connection with maintaining or obtaining operating permits addressing other air emission-related issues, and we may encounter construction delays in connection with the applying for and receiving required permits. We believe that our operations are in substantial compliance with applicable air permitting and control technology requirements.

        Some scientific studies have suggested that anthropogenic emissions of certain gases, commonly referred to as "greenhouse gases" and including carbon dioxide and methane, may be contributing to warming of the Earth's atmosphere. In response to such studies, President Obama has expressed support for legislation to restrict or regulate emissions of greenhouse gases.

        As a result of the United States Supreme Court's 2007 decision in Massachusetts, et al. v. EPA, the EPA may regulate greenhouse gas emissions from mobile sources such as cars and trucks. The Court's holding in Massachusetts that greenhouse gases including carbon dioxide fall under the federal Clean Air Act's definition of "air pollutant" may also result in future regulation of carbon dioxide and other greenhouse gas emissions from stationary sources, including natural gas liquids fractionators. In July 2008, EPA released an "Advance Notice of Proposed Rulemaking" regarding possible future regulation of greenhouse gas emissions under the Clean Air Act, in response to the Supreme Court's decision in Massachusetts, and on April 17, 2009, the EPA issued a notice of its proposed finding and determination that emissions of carbon dioxide, methane, and other greenhouse gases presented an endangerment to human health and the environment. This finding and determination was finalized by the EPA on December 7, 2009, which could provide the basis to permit the EPA to begin regulating emissions of greenhouse gases under existing provisions of the federal Clean Air Act.

        On June 26, 2009, the U.S. House of Representatives passed the "American Clean Energy and Security Act of 2009", also known as the "Waxman-Markey legislation," which would establish an economy-wide cap-and-trade program to reduce emissions of carbon dioxide and other greenhouse gases in the United States and would require an overall reduction in greenhouse gas emissions of 17% (from 2005 levels) by 2020, and by over 80% by 2050. Covered sources of greenhouse gases would be required to obtain emission allowances based upon their annual emissions of greenhouse gases. The number of emission allowances issued each year would decline to satisfy the overall emission reduction goals, which could cause the cost of the allowances to increase significantly over time. The Senate is also considering legislation to reduce greenhouse gas emissions. Depending on the particular requirements of any cap and trade program that might ultimately be enacted, we could be required to purchase allowances or surrender allowances for the greenhouse gas emissions resulting from our operations or from the combustion of fuels that we process. It is also possible that the requirements of any such cap and trade program could extend to the NGLs that we process or hold in inventory, such that we may be required to purchase or surrender allowances for those NGLs even though we are not the ultimate end user. In addition, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to inventory and/or reduce emissions of greenhouse gases, primarily through the planned development of emission inventories or regional greenhouse gas cap and trade programs.

        It is not possible at this time to predict the scope of legislation or new regulations that may be adopted to address greenhouse gas emissions or the impact of such legislation or regulations on our business. However, any such new federal, regional or state restrictions on emissions of carbon dioxide or other greenhouse gases that may be imposed in areas in which we conduct business could have an adverse affect on our cost of doing business and on the demand for the natural gas and crude oil we

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gather as well as the natural gas and natural gas liquids we process, which in turn could adversely affect our cash available for distribution to our unitholders.

Anti-Terrorism Measures.

        Our operations and the operations of the natural gas and oil industry in general may be subject to laws and regulations regarding the security of industrial facilities, including natural gas and oil facilities. The Department of Homeland Security Appropriations Act of 2007 required the Department of Homeland Security ("DHS"), to issue regulations establishing risk-based performance standards for the security of chemical and industrial facilities, including oil and gas facilities that are deemed to present "high levels of security risk." The DHS issued an interim final rule, known as the Chemical Facility Anti-Terrorism Standards interim rule, in April 2007 regarding risk-based performance standards to be attained pursuant to the act and on November 20, 2007 further issued an Appendix A to the interim rule that established the chemicals of interest and their respective threshold quantities that will trigger compliance with these interim rules. Covered facilities that are determined by DHS to pose a high level of security risk are required to prepare and submit Security Vulnerability Assessments and Site Security Plans as well as comply with other regulatory requirements, including those regarding inspections, audits, recordkeeping, and protection of chemical-terrorism vulnerability information. In January 2008, we prepared and submitted to the DHS initial screening surveys for facilities operated by us that possess regulated chemicals of interest in excess of the Appendix A threshold levels. During 2008, the DHS requested that we perform a Security Vulnerability Assessment for our Javelina plant. The DHS did not require us to perform any assessments with respect to our other facilities. We completed the assessment for our Javelina plant and submitted the assessment to the DHS for review in December 2008. We are also required to develop a written security plan for our Javelina plant and train our employees accordingly. While we do not currently anticipate incurring significant costs in connection with complying with these requirements, we have not yet received a response from the DHS regarding our assessment. It is possible that additional requirements could be imposed by the DHS in connection with this program, and complying with such requirements could result in additional costs that may be substantial.

Pipeline Safety Regulations

        Our pipelines are subject to regulation by the U.S. Department of Transportation ("DOT") under the Natural Gas Pipeline Safety Act of 1986, as amended ("NGPSA"), with respect to natural gas and the Hazardous Pipeline Safety Act of 1979, as amended ("HLPSA"), with respect to crude oil, NGLs and condensates. The NGPSA and HLPSA govern the design, installation, testing, construction, operation, replacement and management of natural gas, oil and NGL pipeline facilities. The NGPSA and HLPSA require any entity that owns or operates pipeline facilities to comply with the regulations implemented under these acts, permit access to and allow copying of records, and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable existing NGPSA and HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, future compliance with the NGPSA and HLPSA could result in increased costs.

        Our pipelines are also subject to regulation by the DOT under the Pipeline Safety Improvement Act of 2002, which was amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. The DOT, through the Pipeline and Hazardous Materials Safety Administration ("PHMSA"), has established a series of rules under 49 C.F.R. Part 192 that require pipeline operators to develop and implement integrity management programs for gas transmission pipelines that, in the event of a failure, could affect high consequence areas. "High consequence areas" are currently defined to include high population areas, areas unusually sensitive to environmental damage and commercially navigable

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waterways. Similar rules are also in place under 49 C.F.R. Part 195 for operators of hazardous liquid pipelines including lines transporting NGLs and condensates. The DOT also adopted rules in June 2008 pursuant to authorization granted by the Pipeline Inspections, Protection, Enforcement, and Safety Act of 2006 that amends the pipeline safety regulations to extend regulatory coverage to certain rural onshore hazardous liquid gathering lines and low stress pipelines located in specified "unusually sensitive areas," including non-populated areas requiring extra protection because of the presence of sole source drinking water resources, endangered species or other ecological sources. While we believe that our pipeline operations are in substantial compliance with applicable requirements, due to the possibility of new or amended laws and regulations, or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the requirements will not have a material adverse effect on our results of operations or financial position.

Employee Safety

        The workplaces associated with the processing and storage facilities and the pipelines we operate are also subject to oversight pursuant to the federal Occupational Safety and Health Act, as amended, ("OSHA"), as well as comparable state statutes that regulate the protection of the health and safety of workers. In addition, the OSHA hazard-communication standard requires that we maintain information about hazardous materials used or produced in operations, and that this information be provided to employees, state and local government authorities, and citizens. We believe that we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record-keeping requirements and monitoring of occupational exposure to regulated substances.

        In general, we expect industry and regulatory safety standards to become stricter over time, resulting in increased compliance expenditures. While these expenditures cannot be accurately estimated at this time, we do not expect such expenditures will have a material adverse effect on our results of operations.

Employees

        Through our subsidiary MarkWest Hydrocarbon, Inc., we employ approximately 520 individuals to operate our facilities and provide general and administrative services. We have no employees represented by unions and consider our labor relations to be satisfactory at this time.

Available Information

        Our principal executive office is located at 1515 Arapahoe Street, Tower 2, Suite 700, Denver, Colorado 80202-2126. Our telephone number is 303-925-9200. Our common units trade on the New York Stock Exchange under the symbol "MWE." You can find more information about us at our Internet website, www.markwest.com. Our annual reports on Form 10-K, our quarterly reports on Form 10-Q, our current reports on Form 8-K and any amendments to those reports are available free of charge through our Internet website as soon as reasonably practicable after we electronically file or furnish such material with the Securities and Exchange Commission. The filings are also available through the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549 or by calling 1-800-SEC-0330. Also, these filings are available on the Internet website www.sec.gov.

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ITEM 1A.    Risk Factors

In addition to the other information set forth elsewhere in this Form 10-K, you should carefully consider the following factors when evaluating us.

Risks Inherent in Our Business

Our substantial debt and other financial obligations could impair our financial condition, results of operations and cash flows, and our ability to fulfill our debt obligations.

        We have substantial indebtedness and other financial obligations. Subject to the restrictions governing our indebtedness and other financial obligations, including the indentures governing our outstanding notes, we may incur significant additional indebtedness and other financial obligations.

        Our substantial indebtedness and other financial obligations could have important consequences. For example, they could:

•

make it more difficult for us to satisfy our obligations with respect to our existing debt;

•

impair our ability to obtain additional financings in the future for working capital, capital expenditures, acquisitions, or general partnership and other purposes;

•

have a material adverse effect on us if we fail to comply with financial and restrictive covenants in our debt agreements, and an event of default occurs as a result of that failure that is not cured or waived;

•

require us to dedicate a substantial portion of our cash flow to payments on our indebtedness and other financial obligations, thereby reducing the availability of our cash flow to fund working capital, capital expenditures, distributions and other general partnership requirements;

•

limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate; and

•

place us at a competitive disadvantage compared to our competitors that have proportionately less debt.

        Furthermore, these consequences could limit our ability, and the ability of our subsidiaries, to obtain future financings, make needed capital expenditures, withstand the prevailing economic uncertainty or any future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise. Our existing credit facility contains covenants requiring us to maintain specified financial ratios and satisfy other financial conditions, which may limit our ability to grant liens on our assets, make or own certain investments, enter into any swap contracts other than in the ordinary course of business, merge, consolidate, or sell assets, incur indebtedness senior to the credit facility, make distributions on equity investments, and declare or make, directly or indirectly, any distribution on our common units. Our obligations under the credit facility are secured by substantially all of our assets and guaranteed by all of our wholly-owned subsidiaries, including our operating company (please read Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources). We may be unable to meet those ratios and conditions. Any future breach of any of these covenants or our failure to meet any of these ratios or conditions could result in a default under the terms of our credit facility, which could result in acceleration of our debt and other financial obligations. If we were unable to repay those amounts, the lenders could initiate a bankruptcy or liquidation proceeding, or proceed against the collateral.

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Global economic conditions may have adverse impacts on our business and financial condition.

        Changes in economic conditions could adversely affect our financial condition and results of operations. A number of economic factors, including, but not limited to, gross domestic product, consumer interest rates, strength of U.S. currency, consumer confidence and debt levels, retail trends, housing starts, sales of existing homes, the level of mortgage refinancing, inflation and foreign currency exchange rates, may generally affect our business. Recessionary economic cycles, higher unemployment rates, higher fuel and other energy costs, and higher tax rates may adversely affect demand for natural gas, NGLs and crude oil. A decline in economic activity and conditions in the United States and any other markets in which we operate could adversely affect our financial condition and results of operations.

        The significant disruption in the global markets and financial systems and the decline in the U.S. economy in 2008, which continued through 2009 and into 2010 has only recently begun to improve, increased both the volatility and the amplitude of the risk associated with the other risk factors identified in this report. In particular, these events impacted our yield and unit price, and substantially increased our cost of capital during 2009. If the prevailing economic uncertainty persists or in the event of renewed turmoil in the financial systems, there could be an incremental tightening in the capital markets. Our ability to access the capital markets may be restricted or be available only on unfavorable terms, which could significantly and adversely impact our ability to execute our long term organic growth projects and meet obligations to our producer customers. Limited access to the capital markets could also adversely impact our ability to otherwise take advantage of business opportunities or react to changing economic and business conditions. Our ability to obtain capital from our Amended Partnership Credit Agreement could be adversely impacted by the failure of one or more of the members of the participating bank group. Although the members of the participating bank group are investment grade, an increased risk does exist. Ultimately we may be required to substantially reduce our future capital expenditures. The prevailing economic uncertainty could also have an impact on our producers, other customers, or counterparties to our commodity hedging arrangements causing them to fail to meet their obligations to us. These factors could have a material adverse effect on our revenues, income from operations, cash flows and our quarterly distribution on the common units. The uncertainty and volatility of the global economy may have further impacts on our business and financial condition that we currently cannot predict or anticipate.

        Furthermore, the current conditions of the global financial markets have contributed, and recent declines in commodity prices may have contributed, to a decline in our unit price and corresponding market capitalization in 2009, and could recur in 2010. Continued declines in our market capitalization could result in an additional noncash impairment of our recorded goodwill. Continued declines in commodity prices could have an adverse impact on cash flows from operations that could result in noncash impairments of long-lived assets, as well as other-than-temporary noncash impairments of our equity method investments.

We may not have sufficient cash after the establishment of cash reserves and payment of our expenses to enable us to pay distributions at the current level.

        The amount of cash we can distribute on our units depends principally on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

•

the fees we charge and the margins we realize for our services and sales;

•

the prices of, level of production of, and demand for natural gas and NGLs;

•

the relative prices of NGLs and crude oil, which impact the effectiveness of our hedging program;

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•

the volumes of natural gas we gather, process and transport;

•

the level of our operating costs; and

•

prevailing economic conditions.

        In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

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our debt service requirements;

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fluctuations in our working capital needs;

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our ability to borrow funds and access capital markets;

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restrictions contained in our debt agreements;

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the level of capital expenditures we make, including capital expenditures incurred in connection with our enhancement projects;

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the cost of acquisitions, if any; and

•

the amount of cash reserves established by our general partner.

        Unitholders should be aware that the amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which is affected by non-cash items. As a result, we may make cash distributions during periods when we record losses for financial accounting purposes and may not make cash distributions during periods when we record net earnings for financial accounting purposes.

Our profitability and cash flows are affected by the volatility of NGL product and natural gas prices.

        We are subject to significant risks associated with frequent and often substantial fluctuations in commodity prices. In the past, the prices of natural gas and NGLs have been volatile, and we expect this volatility to continue. The New York Mercantile Exchange ("NYMEX") daily settlement price of natural gas for the prompt month contract in 2008 ranged from a high of $13.58 per MMBtu to a low of $5.29 per MMBtu. In 2009, the same index ranged from a high of $6.07 per MMBtu to a low of $2.51 per MMBtu. A composite of the weighted monthly average NGLs price at our Appalachian facilities based on our average NGLs composition in 2008 ranged from a high of approximately $2.24 per gallon to a low of approximately $0.55 per gallon. In 2009, the same composite ranged from approximately $1.44 per gallon to approximately $0.68 per gallon. The markets and prices for natural gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors, including:

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the level of domestic oil, natural gas and NGL production;

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demand for natural gas and NGL products in localized markets;

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changes in interstate pipeline gas quality specifications;

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imports of crude oil, natural gas and NGLs;

•

seasonality;

•

the condition of the U.S. economy;

•

political conditions in other oil-producing and natural gas-producing countries; and

•

government regulation, legislation and policies.

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        Our net operating margins under various types of commodity-based contracts are directly affected by changes in NGL product prices and natural gas prices, and thus are more sensitive to volatility in commodity prices than our fee-based contracts. Additionally, our purchase and resale of gas in the ordinary course of business exposes us to significant risk of volatility in gas prices due to the potential difference in the time of the purchases and sales, and the potential existence of a difference in the gas price associated with each transaction. Significant declines in commodity prices could have an adverse impact on cash flows from operations that could result in noncash impairments of long-lived assets, as well as other-than-temporary noncash impairments of our equity method investments.

Relative changes in NGL product and natural gas prices may adversely impact our results due to frac spread, natural gas and liquids exposure.

        Under our keep-whole arrangements, our principal cost is delivering dry gas of an equivalent Btu content to replace Btus extracted from the gas stream in the form of NGLs, or consumed as fuel during processing. The spread between the NGL product sales price and the purchase price of natural gas with an equivalent Btu content is called the "frac spread." Generally, the frac spread and, consequently, the net operating margins are positive under these contracts. In the event natural gas becomes more expensive on a Btu equivalent basis than NGL products, the cost of keeping the producer "whole" results in operating losses.

        Due to timing of gas purchases and liquid sales, direct exposure to changes in market prices of either gas or liquids can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through our marketing and derivatives activity, direct exposure may occur naturally or we may choose direct price exposure to either gas or liquids when we favor that exposure over frac spread risk. Given that we have derivative positions, adverse movement in prices to the positions we have taken will negatively impact results.

Our commodity derivative activities may reduce our earnings, profitability and cash flows.

        Our operations expose us to fluctuations in commodity prices. We utilize derivative financial instruments related to the future price of crude oil, natural gas and certain NGLs with the intent of reducing volatility in our cash flows due to fluctuations in commodity prices.

        The extent of our commodity price exposure is related largely to the effectiveness and scope of our derivative activities. We have a policy to enter into derivative transactions related to only a portion of the volume of our expected production or fuel requirements and, as a result, we will continue to have direct commodity price exposure to the unhedged portion. Our actual future production or fuel requirements may be significantly higher or lower than we estimate at the time we enter into derivative transactions for such period. If the actual amount is higher than we estimate, we will have greater commodity price exposure than we intended. If the actual amount is lower than the amount that is subject to our derivative financial instruments, we might be forced to settle all or a portion of our derivative transactions without the benefit of the cash flow from our sale or purchase of the underlying physical commodity, which could result in a substantial diminution of our liquidity. Additionally, because we primarily use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price risk, the volatility or our future cash flows and net income may increase if there is a change in the pricing relationship between crude oil and NGLs. As a result of these factors, our hedging activities may not be as effective as we intend in reducing the downside volatility of our cash flows, and in certain circumstances may actually increase the volatility of our cash flows. In addition, our hedging activities are subject to the risks that a counterparty may not perform its obligation under the applicable derivative instrument, the terms of the derivative instruments are imperfect, and our hedging policies and procedures are not properly followed. It is possible that the steps we take to monitor our derivative financial instruments may not detect and prevent violations of our risk management policies and procedures, particularly if deception or other intentional misconduct

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is involved. For further information about our risk management policies and procedures, please read Note 7 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of our policy.

We conduct risk management activities but we may not accurately predict future commodity price fluctuations and therefore expose us to financial risks and reduce our opportunity to benefit from price increases.

        We evaluate our exposure to commodity price risk from an overall portfolio basis. We have discretion in determining whether and how to manage the commodity price risk associated with our physical and derivative positions.

        To the extent that we do not manage the commodity price risk relating to a position that is subject to commodity price risk, and commodity prices move adversely, we could suffer losses. Such losses could be substantial, and could adversely affect our operations and cash flows available for distribution to our unitholders. In addition, managing the commodity risk may actually reduce our opportunity to benefit from increases in the market or spot prices.

The adoption of derivatives legislation by Congress could have an adverse impact on our ability to hedge risks associated with our business.

        Congress currently is considering broad financial regulatory reform legislation that among other things would impose comprehensive regulation on the OTC derivatives marketplace and could affect the use of derivatives in hedging transactions. The financial regulatory reform bill adopted by the House of Representatives on December 11, 2009, would subject swap dealers and "major swap participants" to substantial supervision and regulation, including capital standards, margin requirements, business conduct standards, and recordkeeping and reporting requirements. It also would require central clearing for transactions entered into between swap dealers or major swap participants. For these purposes, a major swap participant generally would be someone other than a dealer who maintains a "substantial" net position in outstanding swaps, excluding swaps used for commercial hedging or for reducing or mitigating commercial risk, or whose positions create substantial net counterparty exposure that could have serious adverse effects on the financial stability of the U.S. banking system or financial markets. The House-passed bill also would provide the Commodity Futures Trading Commission ("CFTC") with express authority to impose position limits for OTC derivatives related to energy commodities. Separately, in late January, 2010, the CFTC proposed regulations that would impose speculative position limits for certain futures and option contracts in natural gas, crude oil, heating oil, and gasoline. These proposed regulations would make an exemption available for certain bona fide hedging of commercial risks. Although it is not possible at this time to predict whether or when Congress will act on derivatives legislation or the CFTC will finalize its proposed regulations, any laws or regulations that subject us to additional capital or margin requirements relating to, or to additional restrictions on, our trading and commodity positions could have an adverse effect on our ability to hedge risks associated with our business or on the cost of our hedging activity.

A significant decrease in natural gas production in our areas of operation would reduce our ability to make distributions to our unitholders.

        Our gathering systems are connected to natural gas reserves and wells, from which the production will naturally decline over time, which means that our cash flows associated with these wells will also decline over time. To maintain or increase throughput levels on our gathering systems and the utilization rate at our processing plants and our treating and fractionation facilities, we must continually obtain new natural gas supplies. Our ability to obtain additional sources of natural gas depends in part on the level of successful drilling activity near our gathering systems.

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        We have no control over the level of drilling activity in the areas of our operations, the amount of reserves associated with the wells or the rate at which production from a well will decline. In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital. The cost of capital in the current market environment may make it more difficult for producers to finance drilling programs around our systems which could lead to decreased volumes. In addition, fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. During 2009, we saw decreases in the prices of natural gas in connection with the prevailing economic uncertainty, and we cannot predict if these prices will recover or continue to decline in the future. Declines in natural gas prices, if sustained, could lead to a material decrease in such production activity and ultimately to a decrease in exploration activity.

        Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves. If we are not able to obtain new supplies of natural gas to replace the natural decline in volumes from existing wells due to reductions in drilling activity or competition, throughput on our pipelines and the utilization rates of our treating and processing facilities would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.

Alternative financing strategies may not be successful.

        Periodically, we will consider the use of alternative financing strategies such as joint venture arrangements and the sale of non-strategic assets. Joint venture agreements may not share the risks and rewards of ownership in proportion to the voting interests. Joint venture arrangements may require us to pay certain costs or to make certain capital investments and we may have little control over the amount or the timing of these payments and investments. We may not be able to negotiate terms that adequately reimburse us for our costs to fulfill service obligations for those joint ventures where we are the operator. In addition, our joint venture partners may be unable to meet their economic or other obligations and we may be required to fulfill those obligations alone.

        We may periodically sell assets or portions of our business. Separating the existing operations from our assets or operations of which we dispose may result in significant expense and accounting charges, disrupt our business or divert management's time and attention. We may not achieve expected cost savings from these dispositions or the proceeds from sales of assets or portions of our business may be lower than the net book value of the assets sold. We may not be relieved of all of our obligations related to the assets or businesses sold. These factors could have a material adverse effect on our revenues, income from operations, cash flows and our quarterly distribution on our common units.

We depend on third parties for the natural gas and refinery off-gas we process, and the NGLs we fractionate at our facilities, and a reduction in these quantities could reduce our revenues and cash flow.

        Although we obtain our supply of natural gas, refinery off-gas and NGLs from numerous third-party producers, a significant portion comes from a limited number of key producers/suppliers who are committed to us under processing contracts. According to these contracts or other supply arrangements, however, the producers are usually under no obligation to deliver a specific quantity of natural gas or NGLs to our facilities. If these key suppliers, or a significant number of other producers, were to decrease the supply of natural gas or NGLs to our systems and facilities for any reason, we could experience difficulty in replacing those lost volumes. Because our operating costs are primarily fixed, a reduction in the volumes of natural gas or NGLs delivered to us would result not only in a reduction of revenues, but also a decline in net income and cash flow.

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Growing our business by constructing new pipelines and processing and treating facilities subjects us to construction risks and risks that natural gas supplies will not be available upon completion of the facilities.

        One of the ways we intend to grow our business is through the construction of additions to our existing gathering systems and construction of new gathering, processing and treating facilities. The construction of gathering, processing and treating facilities requires the expenditure of significant amounts of capital, which may exceed our expectations, and involves numerous regulatory, environmental, political, legal and inflationary uncertainties, which may delay our construction activities. If we undertake these projects, we may not be able to complete them on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project, if at all.

        Furthermore, we may have only limited natural gas supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize. We may also rely on estimates of proved reserves in our decision to construct new pipelines and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved reserves. As a result, new facilities may not be able to attract enough natural gas to achieve our expected investment return, which could adversely affect our operations and cash flows available for distribution to our unitholders.

The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation and storage agreements may not escalate sufficiently to cover increases in costs, or the agreements may not be renewed or may be suspended in some circumstances.

        Our costs may increase at a rate greater than the fees we charge to third parties. Furthermore, third parties may not renew their contracts with us. Additionally, some third parties' obligations under their agreements with us may be permanently or temporarily reduced due to certain events, some of which are beyond our control, including force majeure events wherein the supply of either natural gas, NGLs or crude oil are curtailed or cut off. Force majeure events include (but are not limited to): revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions and mechanical or physical failures of equipment affecting our facilities or facilities of third parties. If the escalation of fees is insufficient to cover increased costs, if third parties do not renew or extend their contracts with us or if any third party suspends or terminates its contracts with us, our financial results would suffer.

We are exposed to the credit risks of our key customers, and any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders.

        We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any material nonpayment or nonperformance by our key customers could reduce our ability to make distributions to our unitholders. The prevailing economic uncertainty may increase this risk. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us.

We may not be able to retain existing customers, or acquire new customers, which would reduce our revenues and limit our future profitability.

        The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other gatherers, processors, pipelines, fractionators, and the price of, and demand for,

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natural gas, NGLs and crude oil in the markets we serve. Our competitors include large oil, natural gas, refining and petrochemical companies, some of which have greater financial resources, more numerous or greater capacity pipelines, processing and other facilities, and greater access to natural gas and NGL supplies than we do. Additionally, our customers that gather gas through facilities that are not otherwise dedicated to us may develop their own processing and fractionation facilities in lieu of using our services. Certain of our competitors may also have advantages in competing for acquisitions, or other new business opportunities, because of their financial resources and synergies in operations.

        As a consequence of the increase in competition in the industry, and the volatility of natural gas prices, end-users and utilities are reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternative fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could affect our profitability. For more information regarding our competition, please read Item 1. Business—Competition of Part I of this report.

Transportation on certain of our pipelines may be subject to federal or state rate and service regulation, and the imposition and/or cost of compliance with such regulation could adversely affect our operations and cash flows available for distribution to out unitholders.

        Some of our gas, liquids and crude oil transmission operations are subject to rate and service regulations under FERC or various state regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas and oil in interstate commerce, and FERC's regulatory authority includes: facilities construction, acquisition, extension or abandonment of services or facilities; accounts and records; and depreciation and amortization policies. FERC's action in any of these areas or modifications of its current regulations can adversely impact our ability to compete for business, the costs we incur in our operations, the construction of new facilities or our ability to recover the full cost of operating our pipelines. Intrastate natural gas pipeline operations and transportation on proprietary natural gas or petroleum products pipelines are generally not subject to regulation by FERC, and the Natural Gas Act, which is referred to as "NGA," specifically exempts some gathering systems. Yet such operations may still be subject to regulation by various state agencies. The applicable statutes and regulations generally require that our rates and terms and conditions of service provide no more than a fair return on the aggregate value of the facilities used to render services. We cannot assure unitholders that FERC will not at some point determine that such gathering and transportation services are within its jurisdiction, and regulate such services. FERC rate cases can involve complex and expensive proceedings. For more information regarding regulatory matters that could affect our business, please read Item 1. Business—Regulatory Matters as set forth in this report.

Some of our natural gas transportation operations are subject to FERC's rate-making policies that could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating our pipelines including a reasonable return.

        Action by FERC on currently pending matters as well as matters arising in the future could adversely affect our ability to establish reasonable rates that cover operating costs and allow for a reasonable return. An adverse determination in any future rate proceeding brought by or against us could have a material adverse effect on our business, financial condition and results of operations.

        For example, one such matter relates to FERC's policy regarding allowances for income taxes in determining a regulated entity's cost of service. In May 2005, FERC adopted a policy statement ("Policy Statement"), stating that it would permit entities owning public utility assets, including oil

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pipelines, to include an income tax allowance in such utilities' cost-of-service rates to reflect actual or potential tax liability attributable to their public utility income, regardless of the form of ownership. Pursuant to the Policy Statement, a tax pass-through entity seeking such an income tax allowance would have to establish that its partners or members have an actual or potential income tax obligation on the entity's public utility income. This tax allowance policy was upheld by the D.C. Circuit in May 2007. Whether a pipeline's owners have actual or potential income tax liability will be reviewed by FERC on a case-by-case basis. How the Policy Statement is applied in practice to pipelines owned by publicly traded partnerships could impose limits on our ability to include a full income tax allowance in cost of service.

If we are unable to obtain new rights-of-way or the cost of renewing existing rights-of-way increases, then we may be unable to fully execute our growth strategy, which may adversely affect our operations and cash flows available for distribution to unitholders.

        The construction of additions to our existing gathering assets or in the expansion of Liberty may require us to obtain new rights-of-way prior to constructing new pipelines and other transportation facilities. We may be unable to obtain such rights-of-way to connect new natural gas supplies to our existing gathering lines, to connect our existing facilities to new natural gas or natural gas liquids markets, or capitalize on other attractive expansion opportunities. Additionally, it may become more expensive for us to obtain new rights-of-way or to renew existing rights-of-way. If the cost of obtaining new rights-of-way or renewing existing rights-of-way increases, it may adversely affect our operations and cash flows available for distribution to unitholders.

We are indemnified for liabilities arising from an ongoing remediation of property on which certain of our facilities are located and our results of operation and our ability to make distributions to our unitholders could be adversely affected if the indemnifying party fails to perform its indemnification obligation.

        Columbia Gas is the previous or current owner of the property on which our Kenova, Boldman, Cobb, Kermit and Majorsville facilities are located and is the previous operator of our Boldman and Cobb facilities. Columbia Gas has been or is currently involved in investigatory or remedial activities with respect to the real property underlying the Boldman, Cobb and Majorsville facilities pursuant to an "Administrative Order by Consent for Removal Actions" entered into by Columbia Gas and the U.S. Environmental Protection Agency and, in the case of the Boldman facility, an "Agreed Order" with the Kentucky Natural Resources and Environmental Protection Cabinet.

        Columbia Gas has agreed to retain sole liability and responsibility for, and to indemnify us against, any environmental liabilities associated with these regulatory orders or the real property underlying these facilities to the extent such liabilities arose prior to the effective date of the agreements pursuant to which such properties were acquired or leased from Columbia Gas. Our results of operation and our ability to make cash distributions to our unitholders could be adversely affected if in the future Columbia Gas fails to perform under the indemnification provisions of which we are the beneficiary.

Our business is subject to federal, state and local laws and regulations with respect to environmental, safety and other regulatory matters, and the violation of, or the cost of compliance with, such laws and regulations could adversely affect our operations and cash flows available for distribution to our unitholders.

        Numerous governmental agencies enforce comprehensive and stringent federal, state, regional and local laws and regulations on a wide range of environmental, safety and other regulatory matters. We could be adversely affected by increased costs due to stricter pollution-control requirements or liabilities resulting from non-compliance with operating or other regulatory permits. Strict and, under certain circumstances, joint and several liability may be incurred without regard to fault, or the legality of the original conduct, under certain of the environmental laws for remediation of contaminated areas, including the Comprehensive Environmental Response, Compensation and Liability Act, as amended,

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the Resource Conservation and Recovery Act, as amended, and analogous state laws. Private parties, including the owners of properties located near our storage, fractionation and processing facilities or through which our pipeline systems pass, also may have the right to pursue legal actions to enforce compliance, as well as seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. New, more stringent environmental laws, regulations and enforcement policies might adversely influence our products and activities, and existing laws, regulations and policies could be reinterpreted or modified to impose additional requirements or constraints on our operations. Federal, state and local agencies also could impose additional safety requirements, any of which could affect our profitability. Local governments may adopt more stringent zoning ordinances requiring the relocation of our facilities or increasing our costs to construct and operate our facilities. In addition, we face the risk of accidental releases or spills associated with our operations. These could result in material costs and liabilities, including those relating to claims for damages to property, natural resources and persons. Our failure to comply with environmental or safety-related laws and regulations could result in administrative, civil and criminal penalties, the imposition of investigatory and remedial obligations and even injunctions that restrict or prohibit our operations. For more information regarding the environmental, safety and other regulatory matters that could affect our business, please read Item 1. Business—Regulatory Matters, Item 1. Business—Environmental Matters, and Item 1. Business—Pipeline Safety Regulations, each as set forth in this report.

The adoption of legislation by Congress or states, or additional regulations by the EPA, to control and reduce the emissions of greenhouse gases could increase our operating costs and adversely affect the cash flows available for distribution to our unitholders.

        Congress is currently considering legislation to reduce the emissions of carbon dioxide and other greenhouse gases in the United States. In June 2009, the U.S. House of Representatives passed such legislation, calling for the establishment of an economy-wide cap-and-trade program to reduce these emissions and requiring covered sources of greenhouse gases to obtain emission allowances based upon their annual emissions of greenhouse gases. Over time the number of the allowances would decline while the cost of such allowances is expected to increase significantly. The Senate is also considering greenhouse gas emission legislation. While the scope and requirements of legislation that might ultimately be enacted is unknown, based upon the legislation that is currently being considered, it is possible that we could be required to purchase allowances or surrender allowances for the greenhouse gas emissions resulting from our operations, from the combustion of fuels that we process, or from the NGLs that we process or hold in inventory even though we are not the ultimate end user of those NGLs. States may also pass legislation to reduce the emission of greenhouse gases, and the EPA may adopt regulations controlling the emission of greenhouse gases under the existing provisions of the Clean Air Act. The imposition of a cap and trade program or other regulations on the emission of greenhouse gases could increase our cost of doing business by increasing our compliance costs, and have an adverse impact on our revenues and cash flow by reducing the demand for the natural gas and crude oil that we gather and the natural gas and NGLs that we process, which in turn could adversely affect our cash available for distribution to our unitholders. For more information regarding greenhouse gas emission and regulation, please read Item 1. Business—Environmental Matters—Air and Greenhouse Gases. Finally, it should be noted that some scientists have concluded that increasing concentrations of greenhouse gases in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events; if any such effects were to occur, they could have an adverse effect on our assets and operations.

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Federal legislation and state legislative and regulatory initiatives relating to hydraulic fracturing could result in reduced volumes available for us to gather, process and fractionate.

        Congress is currently considering two companions bills for the "Fracturing Responsibility and Awareness of Chemicals Act," or "FRAC Act." The bills would repeal an exemption in the federal Safe Drinking Water Act ("SWDA") for the underground injection of hydraulic fracturing fluids near drinking water sources. Hydraulic fracturing is an important and commonly used process for the completion of natural gas, and to a lesser extent, oil wells in shale formations, and involves the pressurized injection of water, sand and chemicals into rock formations to stimulate natural gas production. Sponsors of the FRAC Act have asserted that chemicals used in the fracturing process could adversely affect drinking water supplies. If enacted, the FRAC Act could result in additional regulatory burdens such as permitting, construction, financial assurance, monitoring, recordkeeping, and plugging and abandonment requirements. The FRAC Act also proposes requiring the disclosure of chemical constituents used in the fracturing process to state or federal regulatory authorities, who would then make such information publicly available. The availability of this information could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, various state and local governments are considering increased regulatory oversight of hydraulic fracturing through additional permit requirements, operational restrictions, and temporary or permanent bans on hydraulic fracturing in certain environmentally sensitive areas such as watersheds. The adoption of the FRAC Act or any other federal or state laws or regulations imposing reporting obligations on, or otherwise limiting, the hydraulic fracturing process could make it more difficult to complete natural gas wells in shale formations and increase our producers' costs of compliance. This could significantly reduce the volumes that we gather, process and fractionate which could adversely impact our earnings, profitability and cash flows.

The amount of gas we process, gather and transmit, or the crude oil we gather and transport, may be reduced if the pipelines to which we deliver the natural gas or crude oil cannot, or will not, accept the gas or crude oil.

        All of the natural gas we process, gather and transmit is delivered into pipelines for further delivery to end-users. If these pipelines cannot, or will not, accept delivery of the gas due to downstream constraints on the pipeline or changes in interstate pipeline gas quality specifications, we will be forced to limit or stop the flow of gas through our pipelines and processing systems. In addition, interruption of pipeline service upstream of our processing facilities would limit or stop flow through our processing facilities. Likewise, if the pipelines into which we deliver crude oil are interrupted, we will be limited in, or prevented from conducting, our crude oil transportation operations. Any number of factors beyond our control could cause such interruptions or constraints on pipeline service, including necessary and scheduled maintenance, or unexpected damage to the pipeline. Because our revenues and net operating margins depend upon (1) the volumes of natural gas we process, gather and transmit, (2) the throughput of NGLs through our transportation, fractionation and storage facilities and (3) the volume of crude oil we gather and transport, any reduction of volumes could adversely affect our operations and cash flows available for distribution to our unitholders.

Interruptions in operations at any of our facilities may adversely affect our operations and cash flows available for distribution to our unitholders.

        Our operations depend upon the infrastructure that we have developed, including processing and fractionation plants, storage facilities, and various means of transportation. Any significant interruption at these facilities or pipelines, or our inability to transmit natural gas or NGLs, or to transport crude oil to or from these facilities or pipelines for any reason, would adversely affect our operations and cash flows available for distribution to our unitholders.

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        Operations at our facilities could be partially or completely shut down, temporarily or permanently, as the result of circumstances not within our control, such as:

•

unscheduled turnarounds or catastrophic events at our physical plants;

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labor difficulties that result in a work stoppage or slowdown; and

•

a disruption in the supply of crude oil to our crude oil pipeline, natural gas to our processing plants or gathering pipelines, or a disruption in the supply of NGLs to our transportation pipeline and fractionation facility.

Due to our lack of asset diversification, adverse developments in our gathering, processing, transportation, transmission, fractionation and storage businesses could reduce our operations and cash flows available for distribution to our unitholders.

        We rely exclusively on the revenues generated from our gathering, processing, transportation, transmission, fractionation and storage businesses. An adverse development in one of these businesses would have a significantly greater impact on our operations and cash flows available for distribution to our unitholders than if we maintained more diverse assets.

We may not be able to successfully execute our business plan and may not be able to grow our business, which could adversely affect our operations and cash flows available for distribution to our unitholders.

        Our ability to successfully operate our business, generate sufficient cash to pay the quarterly cash distributions to our unitholders, and to allow for growth, is subject to a number of risks and uncertainties. Similarly, we may not be able to successfully expand our business through acquiring or growing our assets, because of various factors, including economic and competitive factors beyond our control. If we are unable to grow our business, or execute on our business plan including increasing or maintaining distributions, the market price of the common units is likely to decline.

We are subject to operating and litigation risks that may not be covered by insurance.

        Our industry is subject to numerous operating hazards and risks incidental to processing, transporting, fractionating and storing natural gas and NGLs and to transporting and storing crude oil. These include:

•

damage to pipelines, plants, related equipment and surrounding properties caused by floods, hurricanes, and other natural disasters and acts of terrorism;

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inadvertent damage from construction and farm equipment;

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leakage of crude oil, natural gas, NGLs and other hydrocarbons;

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fires and explosions; and

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other hazards, including those associated with high-sulfur content, or sour gas that could also result in personal injury and loss of life, pollution and suspension of operations.

        As a result, we may be a defendant in various legal proceedings and litigation arising from our operations. We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. Market conditions could cause certain insurance premiums and deductibles to become unavailable, or available only for reduced amounts of coverage. For example, insurance carriers now require broad exclusions for losses due to war risk and terrorist acts. If we were to incur a significant liability for which we were not fully insured, it could have a material adverse effect on our operations and cash flows available for distribution to our unitholders.

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Our business may suffer if any of our key senior executives or other key employees discontinues employment with us or if we are unable to recruit and retain highly skilled staff.

        Our future success depends to a large extent on the services of our key employees. Our business depends on our continuing ability to recruit, train and retain highly qualified employees, including accounting, business operations, finance and other key back-office and mid-office personnel. The competition for these employees is intense, and the loss of these employees could harm our business. Our equity based long-term incentive plans are a significant component of our strategy to retain key employees. Further, our ability to successfully integrate acquired companies or handle complexities related to managing joint ventures depends in part on our ability to retain key management and existing employees at the time of the acquisition.

A shortage of skilled labor may make it difficult for us to maintain labor productivity, and competitive costs could adversely affect our operations and cash flows available for distribution to our unitholders.

        Our operations require skilled and experienced laborers with proficiency in multiple tasks. In recent years, a shortage of workers trained in various skills associated with the midstream energy business has caused us to conduct certain operations without full staff, which decreases our productivity and increases our costs. This shortage of trained workers is the result of the previous generation's experienced workers reaching the age for retirement, combined with the difficulty of attracting new laborers to the midstream energy industry. Thus, this shortage of skilled labor could continue over an extended period. If the shortage of experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our operations and cash flows available for distribution to our unitholders.

If we do not make acquisitions on economically acceptable terms, our future growth may be limited.

        Our ability to grow depends in part on our ability to make acquisitions that result in an increase in the cash generated from operations per unit. If we are unable to make these accretive acquisitions because we are (1) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (2) unable to obtain financing for these acquisitions on economically acceptable terms, or (3) outbid by competitors, then our future growth and ability to increase distributions will be limited.

If we are unable to timely and successfully integrate our future acquisitions, our future financial performance may suffer, and we may fail to realize all of the anticipated benefits of the transaction.

        Our future growth will depend in part on our ability to integrate our future acquisitions. We cannot guarantee that we will successfully integrate any acquisitions into our existing operations, or that we will achieve the desired profitability and anticipated results from such acquisitions. Failure to achieve such planned results could adversely affect our operations and cash flows available for distribution to our unitholders.

        The integration of acquisitions with our existing business involves numerous risks, including:

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operating a significantly larger combined organization and integrating additional midstream operations into our existing operations;

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difficulties in the assimilation of the assets and operations of the acquired businesses, especially if the assets acquired are in a new business segment or geographical area;

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the loss of customers or key employees from the acquired businesses;

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the diversion of management's attention from other existing business concerns;

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the failure to realize expected synergies and cost savings;

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coordinating geographically disparate organizations, systems and facilities;

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integrating personnel from diverse business backgrounds and organizational cultures; and

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consolidating corporate and administrative functions.

        Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. Following an acquisition, we may discover previously unknown liabilities including those under the same stringent environmental laws and regulations relating to releases of pollutants into the environment and environmental protection as are applicable to our existing plants, pipelines and facilities. If so, our operation of these new assets could cause us to incur increased costs to address these liabilities or to attain or maintain compliance with such requirements. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Terrorist attacks aimed at our facilities could adversely affect our business.

        Since the September 11, 2001 terrorist attacks, the U.S. government has issued warnings that energy assets, specifically the nation's pipeline infrastructure, may be future targets of terrorist organizations. These developments will subject our operations to increased risks. Any future terrorist attack that may target our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.

We have partial ownership interests in a number of joint venture legal entities, including Liberty, Pioneer, Wirth, and Centrahoma, which could adversely affect our ability to control certain decisions of these entities. In addition, we may be unable to control the amount of cash we will receive from the operation of these entities and where we do not have control, we could be required to contribute significant cash to fund our share of their operations, which could adversely affect our ability to distribute cash to our unitholders.

        Our inability, or limited ability, to control certain aspects of management of joint venture legal entities that we have a partial ownership interest in may mean that we will not receive the amount of cash we expect to be distributed to us. In addition, for entities where we have a non-controlling ownership interest such as in Centrahoma we will be unable to control ongoing operational decisions, including the incurrence of capital expenditures that we may be required to fund. Specifically,

•

We may have limited ability to influence certain management decisions with respect to these entities and their subsidiaries, including decisions with respect to incurrence of expenses and distributions to us;

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These entities may establish reserves for working capital, capital projects, environmental matters and legal proceedings which would otherwise reduce cash available for distribution to us;

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These entities may incur additional indebtedness, and principal and interest made on such indebtedness may reduce cash otherwise available for distribution to us; and

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These entities may require us to make additional capital contributions to fund working capital and capital expenditures, our funding of which could reduce the amount of cash otherwise available for distribution.

        All of these things could significantly and adversely impact our ability to distribute cash to our unitholders.

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Certain changes in accounting and/or financial reporting standards issued by the FASB, the SEC or other standard-setting bodies could have a material adverse impact on our financial position or results of operations.

        We are subject to the application of GAAP, which periodically is revised and/or expanded. As such, we periodically are required to adopt new or revised accounting and/or financial reporting standards issued by recognized accounting standard setters or regulators, including the FASB and the SEC. It is possible that future requirements, including the recently proposed implementation of International Financial Reporting Standards ("IFRS"), could change our current application of GAAP, resulting in a material adverse impact on our financial position or results of operations.

The potential requirement to convert our financial statements from being prepared in conformity with GAAP to IFRS may strain our resources and increase our annual expenses.

        As a public entity, the SEC may require in the future that we report our financial results under IFRS instead of GAAP. IFRS is a set of accounting principles that has been gaining acceptance on a worldwide basis. These standards are published by the London-based International Accounting Standards Board and are more focused on objectives and principles and less reliant on detailed rules than GAAP. Today, there remain significant and material differences in several key areas between GAAP and IFRS which would affect us. Additionally, GAAP provides specific guidance in classes of accounting transactions for which equivalent guidance in IFRS does not exist. The adoption of IFRS is highly complex and would have an impact on many aspects and operations of us, including but not limited to financial accounting and reporting systems, internal controls, taxes, borrowing covenants and cash management. It is expected that a significant amount of time, internal and external resources and expenses over a multi-year period would be required for this conversion.

Risks Related to Our Partnership Structure

We may issue additional common units without unitholder approval, which would dilute your ownership interests.

        The General Partner, without your approval, may cause us to issue additional common units or other equity securities of equal rank with or senior to the common units.

        The issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

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the unitholders' proportionate ownership interest will decrease;

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the amount of cash available for distribution on each common unit may decrease;

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the relative voting strength of each previously outstanding common unit may be diminished;

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the market price of the common units may decline; and

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the ratio of taxable income to distributions may increase.

Unitholders have less ability to influence management's decisions than holders of common stock in a corporation.

        Unlike the holders of common stock in a corporation, unitholders have more limited voting rights on matters affecting our business, and therefore a more limited ability to influence management's decisions regarding our business. The amended and restated partnership agreement provides that the General Partner may not withdraw and may not be removed at any time for any reason whatsoever. Furthermore, if any person or group other than the General Partner and its affiliates acquires beneficial ownership of 20% or more of any class of units (without the prior approval of the General

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Partner board), that person or group loses voting rights on all of its units. However, if unitholders are dissatisfied with the performance of our General Partner, they have the right to annually elect its board of directors.

Unitholders may not have limited liability if a court finds that unitholder action constitutes control of our business.

        Under Delaware law, unitholders could be held liable for our obligations as a general partner if a court determined that the right or the exercise of the right by unitholders as a group to approve certain transactions or amendments to the agreement of limited partnership, or to take other action under the Partnership Agreement was considered participation in the "control" of our business. Unitholders elect the members of the General Partner board, which may be deemed to be participation in the "control" of our business. This could subject unitholders to liability as a general partner.

        In addition, Section 17-607 of the Delaware Revised Uniform Limited Partnership Act provides that, under some circumstances, a unitholder may be liable to us for the amount of a distribution for a period of three years from the date of the distribution.

Tax Risks Related to Owning our Common Units

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service ("IRS") were to treat us as a corporation for federal income tax purposes or we were to become subject to a material amount of entity-level taxation then our cash available for distribution to unitholders could be substantially reduced.

        The anticipated after-tax benefit of an investment in the common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

        Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. Although we do not believe based on our current operations that we are so treated, a change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of the common units.

        Current law may change, causing us to be treated as a corporation for federal income tax purposes or otherwise subjecting us to entity-level taxation. The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative, judicial, or administrative changes and differing interpretations at any time. Any modification to the federal income tax laws and interpretations thereof may or may not be applied retroactively. For example, members of Congress are considering substantive changes to the existing U.S. tax laws that affect certain publicly traded partnerships. Although the proposed legislation would not affect our tax treatment as a partnership as proposed, we are unable to predict whether any of these changes, or other proposals, will be modified or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

44

        The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution amount and the target distribution amounts will be reduced to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to unitholders.

        Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders. For example, the state of Texas and the state of Michigan have both instituted income-based taxes that result in an entity level tax for us. We are required to pay a Texas franchise tax at a maximum effective rate of 1.0% of our gross income apportioned to Texas in the prior year. Additionally, the Michigan Business Tax, which contains two prongs, also imposes a tax on us. The two prongs comprise a tax at the rate of 0.8% of a taxpayer's modified gross receipts and a tax at the rate of 4.95% of the taxpayer's business income. Each of the above mentioned rates also includes a surcharge of 21.99% resulting in overall rates of 0.97% and 6.03%. The imposition of entity level taxes on us by Texas and Michigan and, if applicable, by any other state will reduce the cash available for distribution to our unitholders.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

        We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and the General Partner because the costs will reduce our cash available for distribution.

A unitholder may be required to pay taxes on his share of our income even if the unitholder does not receive any cash distributions from us.

        Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, each unitholder will be required to pay any federal income taxes and, in some cases, state and local income taxes on his share of our taxable income even if the unitholder receives no cash distributions from us. A unitholder may not receive cash distributions from us equal to his share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

        If a unitholder sells his common units, he will recognize a gain or loss equal to the difference between the amount realized and his tax basis in those common units. Because distributions in excess of the unitholder's allocable share of our net taxable income decrease the unitholder's tax basis in his common units, the amount, if any, of such prior excess distributions with respect to the common units the unitholder sells will, in effect, become taxable income to the unitholder if the unitholder sells such common units at a price greater than his tax basis in those common units, even if the price the

45

unitholder receives is less than his original cost. Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, if the unitholder sells his units, the unitholder may incur a tax liability in excess of the amount of cash the unitholder receives from the sale.

Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

        Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and could be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file federal tax returns and pay tax on their share of our taxable income. If a unitholder is a tax exempt entity or a non-U.S. person, the unitholder should consult a tax advisor before investing in our common units.

We treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

        Due to a number of factors including our inability to match transferors and transferees of our common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder's sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder's tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our common units each month based upon the ownership of the common units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

        We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of the units on the first day of each month, instead of on the basis of the date a particular common unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. Recently, however, the Department of the Treasury and the IRS issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Although existing publicly traded partnerships are entitled to rely on these proposed Treasury Regulations, they are not binding on the IRS and are subject to change until final Treasury Regulations are issued.

A unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

        Because a unitholder whose common units are loaned to a "short seller" to cover a short sale of common units may be considered as having disposed of the loaned units, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan to the

46

short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

We have adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between the Class A unitholders and our common unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

        When we issue additional common units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our common unitholders and the Class A unitholders. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders, which may have an unfavorable effect. Moreover, under our valuation methods, subsequent purchasers of common units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our unitholders.

        A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of gain from the sale of common units by our unitholders and could have a negative impact on the value of our common units or result in audit adjustments to the tax returns of our unitholders without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

        We will be considered to have terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in our filing two tax returns for one fiscal year and may result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but would result in our being treated as a new partnership for tax purposes. If we were treated as a new partnership, we would be required to make new tax elections and could be subject to penalties if we were unable to determine that a termination occurred.

47

Our unitholders will likely be subject to state and local taxes and return filing requirements in states where the unitholders do not live as a result of investing in common units.

        In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if our unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently do business or own property in nine states, most of which, other than Texas, impose personal income taxes. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own assets or conduct business in additional states that impose a personal income tax. It is our unitholder's responsibility to file all United States federal, foreign, state and local tax returns.

ITEM 1B.    Unresolved Staff Comments

        None.

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ITEM 2.    Properties

        The following tables set forth certain information relating to our gas processing facilities, fractionation facility, natural gas gathering systems, NGL pipelines, natural gas pipeline and crude oil pipeline as of and for the year ended December 31, 2009.

Gas Processing Facilities:

							Year ended December 31, 2009
Facility		Location	Year of Initial Construction		Design Throughput Capacity		Natural Gas Throughput		Utilization of Design Capacity			NGL Throughput
					(Mcf/d)		(Mcf/d)					(Gal/d)
Southwest
East Texas:
	East Texas processing plant	Panola County, TX		2005		280,000		246,600		88	%		673,400
Oklahoma:
	Arapaho processing plants	Custer County, OK		2000		160,000		153,200		96	%		347,600
Northeast
Appalachia:
	Kenova processing plant(1)	Wayne County, WV		1996		160,000		126,400		79	%		N/A
	Boldman processing plant(1)	Pike County, KY		1991		70,000		42,500		61	%		N/A
	Cobb processing plant	Kanawha County, WV		2005		65,000		25,700		40	%		N/A
	Kermit processing plant(1)(2)	Mingo County, WV		2001		32,000		N/A		N/A			N/A
Liberty
Marcellus Shale:
	Houston processing plants(3)	Washington County, PA		2009		155,000		53,500		35	%		94,300
Gulf Coast
	Javelina processing plant	Corpus Christi, TX		1989		142,000		120,200		85	%		976,300

(1)

A portion of the gas processed at the Boldman plant, and all of the gas processed at the Kermit plant, is further processed at the Kenova plant to recover additional NGLs.

(2)

The Kermit processing plant is operated by a third party solely to prevent liquids from condensing in the gathering and transmission pipelines upstream of our Kenova plant. We do not receive Kermit gas volume information but do receive all of the liquids produced at the Kermit facility.

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(3)

The Houston processing plants' volume is the average daily production for the full year of 2009. During December 2009 the processing capacity increased by 55,000 Mcf/d. The net change is a result of the 120,000 Mcf/d Houston II plant being placed in service and the 65,000 Mcf/d leased interim plant going out of service. The calculated utilization is not based on the capacity that existed throughout the year. Utilization as of December 31, 2009 was approximately 56%.

Fractionation Facility:

							Year ended December 31, 2009
Facility		Location	Year of Initial Construction		Design Throughput Capacity		NGL Throughput		Utilization of Design Capacity
					(Gal/d)		(Gal/d)
Northeast
Appalachia:
	Siloam fractionation plant	South Shore, KY		1957		1,008,000		714,600		71	%

        Our Siloam facility has both above ground, pressurized storage facilities, with capacity of three million gallons, and underground storage facilities, with capacity of 11 million gallons. Product can be received by truck, pipeline or rail car and can be transported from the facility by truck, rail car or barge. There are ten automated 24-hour-a-day truck loading and unloading slots, a modern rail loading/unloading rack with 14 unloading slots, and a river barge facility capable of loading barges with a capacity of up to 840,000 gallons. We generate revenue from our underground storage facilities by charging an annual fee.

50

Natural Gas Gathering Systems:

							Year ended December 31, 2009
Facility		Location	Year of Initial Construction		Design Throughput Capacity		Natural Gas Throughput		Utilization of Design Capacity
					(Mcf/d)		(Mcf/d)
Southwest
East Texas:
	East Texas gathering system	Panola County, TX		1990		500,000		454,400		91	%
Oklahoma:
	Foss Lake gathering system	Roger Mills, Ellis and Custer Counties, OK		1998		130,000		86,600		67	%
	Stiles Ranch gathering system	Wheeler County, TX		2008		250,000		89,300		36	%
	Grimes gathering system	Beckham and Roger Mills Counties, OK		2005		25,000		9,700		39	%
	Southeast Oklahoma gathering system	Hughes, Pittsburg and Coal Counties, OK		2006		500,000		416,800		83	%
Other Southwest:
	Appleby gathering system	Nacogdoches County, TX		1990		85,000		47,300		56	%
	Other gathering systems(4)	Various		Various		36,500		10,300		28	%
Liberty
Marcellus Shale:
	Gas gathering system	Washington County, PA		2008		175,000		53,500		31	%

(4)

Excludes lateral pipelines where revenue is not based on throughput.

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NGL Pipelines:

							Year ended December 31, 2009
Pipeline		Location	Year of Initial Construction		Design Throughput Capacity		NGL Throughput		Utilization of Design Capacity
					(Gal/d)		(Gal/d)
Northeast
Appalachia:
	Ranger to Kenova(5)	Lincoln County, WV to Wayne County, WV		1976		831,000		243,700		29	%
	Kenova to Siloam	Wayne County, WV to South Shore, KY		1957		831,000		267,600		32	%
Southwest
East Texas:
	East Texas liquid line	Panola County, TX		2005		1,050,000		673,400		64	%

(5)

NGLs transported through the Ranger to Kenova pipeline are combined with NGLs recovered at the Kenova facility and the combined NGL stream is transported in the Kenova to Siloam pipeline.

Natural Gas Pipeline:

							Year ended December 31, 2009
Pipeline		Location	Year of Initial Construction		Design Throughput Capacity		Natural Gas Throughput		Utilization of Design Capacity
					(Dth/d)		(Dth/d)
Southwest
Oklahoma
	Arkoma Connector Pipeline(6)	Coal County, OK to Bryan County, OK		2009		638,000		286,300		45	%

(6)

The Arkoma Connector Pipeline is FERC regulated and was placed into service in July 2009. The volume reported is the average daily rate for the days of operation.

Crude Oil Pipeline:

							Year ended December 31, 2009
Pipeline		Location	Year of Initial Construction		Design Throughput Capacity		NGL Throughput		Utilization of Design Capacity
					(Bbl/d)		(Bbl/d)
Northeast
Michigan:
	Michigan crude pipeline	Manistee County, MI to Crawford County, MI		1973		60,000		12,300		21	%

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Title to Properties

        Substantially all of our pipelines are constructed on rights-of-way granted by the owners of record of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where determined necessary, permits, leases, license agreements and franchise ordinances from public authorities to cross over or under, or to lay facilities in or along water courses, county roads, municipal streets and state highways, as applicable. We also have obtained easements and license agreements from railroad companies to cross over or under railroad properties or rights-of-way. Many of these authorizations and grants are revocable at the election of the grantor. In some cases, property on which our pipelines were built was purchased in fee or held under long-term leases. Our Siloam fractionation plant, Kenova processing plant and Houston processing facilities are on land that we own in fee.

        Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that were transferred to us required the consent of the then-current landowner to transfer these rights, which in some instances was a governmental entity. We believe that we have obtained sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business. We also believe we have satisfactory title or other right to all of our material land assets. Title to these properties is subject to encumbrances in some cases; however, we believe that none of these burdens will materially detract from the value of these properties or from our interest in these properties, or will materially interfere with their use in the operation of our business.

        We have pledged substantially all of our assets and those of our wholly-owned subsidiaries as collateral for borrowings under our new credit agreement entered into on February 20, 2008 ("Partnership Credit Agreement").

ITEM 3.    Legal Proceedings

        We are subject to a variety of risks and disputes, and are a party to various legal proceedings in the normal course of our business. We maintain insurance policies in amounts and with coverage and deductibles as we believe are reasonable and prudent. However, we cannot assure that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect us from all material expenses related to future claims for property loss or business interruption to us, or for third-party claims of personal and property damage, or that the coverages or levels of insurance we currently have will be available in the future at economical prices. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the consolidated financial statements.

        In June 2006, the Office of Pipeline Safety ("OPS") issued a Notice of Probable Violation and Proposed Civil Penalty ("NOPV") (CPF No. 2-2006-5001) to both MarkWest Hydrocarbon and Equitable Production Company ("Equitable"). The NOPV is associated with the pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 in Ivel, Kentucky on an NGL pipeline owned by Equitable and leased and operated by a subsidiary, MarkWest Energy Appalachia, L.L.C. The NOPV sets forth six counts of violations of applicable regulations, and a proposed civil penalty in the aggregate amount of $1.1 million. An administrative hearing on the matter, previously set for the last week of March 2007, was postponed to allow the administrative record to be produced and to allow OPS an opportunity to respond to our and Equitable's motions to dismiss count one of the NOPV, which involves $0.8 million of the $1.1 million proposed penalty. This count arises out of alleged activity in 1982 and 1987, which predates our leasing and operation of the pipeline. We believe we have viable and mitigating defenses to the remaining counts and will vigorously defend all applicable assertions of violations. The administrative hearing request was withdrawn by us and

53

Equitable in October 2009, and the case will proceed to initial resolution on the briefs, exhibits and other documents filed or submitted by the parties in the matter.

        MarkWest Javelina Company, L.L.C. is a party to an action styled Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al., Case No. A-060352-C, 128^th Judicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from previously dismissed petition captioned Jesus Villarreal v. Koch Refining Co. et al., Cause No. 05-01977-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005), which sets forth claims for wrongful death, personal injury or property damage, and nuisance type claims, allegedly incurred as a result of operations and emissions from MarkWest Javelina's gas processing plant and from various petroleum, petrochemical and metal processing and refining operations located in the area, which were also named as defendants in the action. The action has been and is being vigorously defended, and it appears at this time that this action should not have a material adverse impact on our financial position or results of operations.

        On June 26, 2009, MarkWest Liberty Midstream entered into a Consent Order and Agreement with the Commonwealth of Pennsylvania, Department of Environmental Protection relating to alleged violations of Pennsylvania's stormwater and dam safety regulations in connection with the construction of facilities installed or acquired by MarkWest Liberty Midstream. Under the Consent Order and Agreement, MarkWest Liberty Midstream agreed to pay civil penalties and administrative oversight costs in an aggregate amount of $0.2 million and to perform certain corrective actions, the cost of which is not expected to have a material impact on our financial condition, liquidity, or results of operations.

        In the ordinary course of business, we are a party to various other legal and regulatory actions. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on our financial condition, liquidity or results of operations.

ITEM 4.    Reserved

PART II

ITEM 5.    Market for Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities

        Our common units have been listed on the New York Stock Exchange ("NYSE"), under the symbol "MWE," since May 2, 2007. Our common units had been traded on the American Stock Exchange, under the symbol "MWE," from May 24, 2002 to May 2, 2007. Prior to May 24, 2002, our equity securities were not listed on any exchange, or traded on any public trading market.

        The following table sets forth the high and low sales prices of the common units as reported by NYSE, as well as the amount of cash distributions paid per quarter for 2009 and 2008:

	Unit Price
					Distributions Per Common Unit
Quarter Ended	High		Low				Record Date		Payment Date
December 31, 2009	$	29.94	$	22.20	$	0.64		February 5, 2010		February 12, 2010
September 30, 2009		24.00		17.87		0.64		November 2, 2009		November 13, 2009
June 30, 2009		20.00		11.20		0.64		August 3, 2009		August 14, 2009
March 31, 2009		14.30		7.30		0.64		May 4, 2009		May 15, 2009
December 31, 2008		25.75		6.55		0.64		February 6, 2009		February 13, 2009
September 30, 2008		36.00		21.22		0.64		November 4, 2008		November 14, 2008
June 30, 2008		38.50		30.70		0.63		August 4, 2008		August 15, 2008
March 31, 2008		37.00		29.53		0.60		May 5, 2008		May 15, 2008

        As of February 22, 2010 there were approximately 160 holders of record of our common units.

54

Distributions of Available Cash

        Within 45 days after the end of each quarter, we will distribute all of our "Available Cash" to unitholders of record on the applicable record date. We will make distributions of "Available Cash" to all unitholders (common and Class A), pro rata and we will make distributions of Hydrocarbon Available Cash (as defined in our amended and restated partnership agreement) pro rata to common unitholders. We define "Available Cash" in our amended and restated partnership agreement, and we generally mean, for each fiscal quarter:

•

all cash and cash equivalents on hand at the end of the quarter;

•

less the amount of cash that the General Partner determines in its reasonable discretion is necessary or appropriate to:

•

provide for the proper conduct of our business;

•

comply with applicable law, any of our debt instruments, or other agreements; or

•

provide funds for distributions to unitholders for any one or more of the next four quarters;

•

plus all cash and cash equivalents on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

        Generally, Hydrocarbon Available Cash is defined as all cash and cash equivalents on hand derived from or attributable to our ownership of, or sale or other disposition of, the shares of common stock of MarkWest Hydrocarbon, Inc.

        Our ability to distribute available cash is contractually restricted by the terms of our credit facilities. Our credit facilities contain covenants requiring us to maintain certain financial ratios and a minimum net worth. We are prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under our credit facilities. In addition, our credit facilities prohibit us from borrowing more than $0.75 per outstanding unit during any consecutive 12-month period for the purpose of making distributions to unitholders. Our credit facilities provide that any amount so borrowed must be repaid once annually.

        There is no guarantee that we will pay a quarterly distribution on the common units in any quarter.

Distributions of Cash Upon Liquidation

        If we dissolve in accordance with the amended and restated partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of its creditors. We will distribute any remaining proceeds to the unitholders, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

55

Securities Authorized for Issuance under Equity Compensation Plans

        The following table provides information as of December 31, 2009, regarding our common units that may be issued upon conversion of outstanding phantom units granted under all of our existing equity compensation plans.

		Number of securities to be issued upon exercise of outstanding options, warrants and rights		Weighted average exercise price of outstanding options, warrants and rights(1)		Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders:
	2008 Long-Term Incentive Plan(2)		968,835	$	—		1,325,361
	2006 Hydrocarbon Stock Incentive Plan(3)(4)		8,406	$	—		—
Equity compensation plans not approved by security holders:
	Long-Term Incentive Plan(4)		69,555	$	—		—
Total			1,046,796				1,325,361

(1)

Phantom units are granted with no exercise price.

(2)

Includes 437,100 performance-based units which vest if we achieve established performance goals determined by the Compensation Committee of the General Partner's board of directors.

(3)

Outstanding shares of restricted stock under this plan were converted to phantom units pursuant to the terms of the Merger. The converted phantom units will remain outstanding under the terms of their original plan until their respective settlement dates.

(4)

No further awards will be made pursuant to this plan.

Recent Sales of Unregistered Units

        None.

Repurchase of Equity by MarkWest Energy Partners, L.P.

        None.

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ITEM 6.    Selected Financial Data

        The following table sets forth selected consolidated historical financial and operating data for MarkWest Energy Partners. For periods prior to the Merger, the information presented represents the consolidated financial position and results of operations for the Corporation. The selected financial data should be read in conjunction with the consolidated financial statements, including the notes thereto, and Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operation in this Form 10-K.

			Year ended December 31,
			2009			2008			2007			2006			2005(1)
Statement of Operations:
Revenue:
	Revenue		$	858,635		$	1,060,662		$	845,727		$	829,298		$	759,381
	Derivative (loss) gain(2)			(120,352	)		277,828			(159,970	)		10,383			(3,198	)
		Total revenue		738,283			1,338,490			685,757			839,681			756,183
Operating expenses:
	Purchased product costs			408,826			615,902			487,892			560,597			625,090
	Derivative loss related to purchased product costs(2)			68,883			22,371			15,192			5,689			—
	Facility expenses			126,977			103,682			70,863			57,403			45,577
	Derivative (gain) loss related to facility expenses(2)			(373	)		644			(14	)		—			—
	Selling, general and administrative expenses			63,728			68,975			72,484			63,360			33,757
	Depreciation			95,537			67,480			41,281			31,010			20,829
	Amortization of intangible assets			40,831			38,483			16,672			16,047			9,656
	Loss (gain) on disposal of property, plant and equipment			1,677			178			7,743			(322	)		(407	)
	Accretion of asset retirement obligations			198			129			114			102			160
	Impairment of goodwill and long-lived assets			5,855			36,351			356			—			—
		Total operating expenses		812,139			954,195			712,583			733,886			734,662
		(Loss) income from operations		(73,856	)		384,295			(26,826	)		105,795			21,521
Other income (expense):
	Earnings (loss) from unconsolidated affiliates			3,505			90			5,309			5,316			(2,153	)
	Impairment of unconsolidated affiliate			—			(41,449	)		—			—			—
	Gain on sale of unconsolidated affiliate			6,801			—			—			—			—
	Interest income			349			3,769			4,547			1,574			1,060
	Interest expense			(87,419	)		(64,563	)		(39,435	)		(40,942	)		(22,622	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(9,718	)		(8,299	)		(2,983	)		(9,229	)		(6,979	)
	Derivative gain related to interest expense(2)			2,509			—			—			—			—
	Miscellaneous income (expense), net(2)			2,459			(241	)		233			11,984			658
		(Loss) income before provision for income tax		(155,370	)		273,602			(59,155	)		74,498			(8,515	)
Provision for income tax expense (benefit):
	Current			8,072			15,032			23,869			(179	)		554
	Deferred			(50,088	)		53,798			(48,518	)		5,431			(2,358	)
		Total provision for income tax		(42,016	)		68,830			(24,649	)		5,252			(1,804	)
		Net (loss) income		(113,354	)		204,772			(34,506	)		69,246			(6,711	)
Net (income) loss attributable to non-controlling interest				(5,314	)		3,301			(4,853	)		(59,709	)		(91	)
		Net (loss) income attributable to the Partnership	$	(118,668	)	$	208,073		$	(39,359	)	$	9,537		$	(6,802	)
Net (loss) income attributable to the Partnership's common unitholders per common unit(3) (Note 25):
	Basic		$	(1.97	)	$	4.02		$	(1.72	)	$	0.42		$	(0.30	)
	Diluted		$	(1.97	)	$	4.02		$	(1.72	)	$	0.42		$	(0.30	)
Cash distribution declared per common unit(3)			$	2.560		$	2.059		$	0.703		$	0.416		$	0.191

57

			Year ended December 31,
			2009			2008			2007			2006			2005(1)
Balance Sheet Data (at December 31):
	Working capital		$	13,536		$	51,237		$	21,932		$	66,030		$	61,156
	Property, plant and equipment, net			1,981,644			1,569,525			830,809			554,335			494,698
	Total assets			3,014,737			2,673,054			1,524,695			1,203,241			1,132,304
	Total long-term debt			1,170,072			1,172,965			552,695			526,865			608,762
	Total partners' capital			1,379,393			1,207,759			563,974			483,061			340,997
Cash Flow Data:
	Net cash flow provided by (used in):
		Operating activities	$	223,101		$	226,995		$	133,237		$	165,969		$	16,874
		Investing activities		(461,753	)		(909,265	)		(314,792	)		(122,046	)		(445,848	)
		Financing activities		333,083			647,896			170,406			(16,047	)		437,098
Other Financial Data:
	Maintenance capital expenditures(4)		$	7,483		$	7,161		$	4,140		$	2,460		$	2,181
	Growth capital expenditures(4)			479,140			568,137			312,499			77,620			69,162
		Total capital expenditures	$	486,623		$	575,298		$	316,639		$	80,080		$	71,343

(1)

We made our initial investment in Starfish on March 31, 2005, and acquired Javelina (Gulf Coast) on November 1, 2005.

(2)

As discussed further in Note 2 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, volatility in any given period related to unrealized gains and losses on our derivative positions can be significant. We ultimately expect unrealized gains and losses to be offset when they become realized. The following table summarizes the realized and unrealized gains and losses impacting Revenue, Purchased product costs, Facility expenses, Interest expense and Miscellaneous income (expense), net (in thousands):

		Year ended December 31,
		2009			2008			2007			2006			2005
Realized gain (loss)—revenue		$	87,289		$	(15,704	)	$	(15,901	)	$	17		$	(2,541	)
Unrealized (loss) gain—revenue			(207,641	)		293,532			(144,069	)		10,366			(657	)
Realized (loss) gain—purchased product costs			(53,052	)		7,368			(8,829	)		153			—
Unrealized loss—purchased product costs			(15,831	)		(29,739	)		(6,363	)		(5,842	)		—
Unrealized gain (loss)—facility expenses			373			(644	)		14			—			—
Realized gain—interest expense			2,000			—			—			—			—
Unrealized gain—interest expense			509			—			—			—			—
Unrealized gain—miscellaneous income (expense), net			336			—			—			—			—
	Total derivative (loss) gain	$	(186,017	)	$	254,813		$	(175,148	)	$	4,694		$	(3,198	)

(3)

All per unit data where applicable has been adjusted to reflect the Exchange Ratio to give effect to the Merger (see Note 3 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K).

(4)

Maintenance capital includes capital expenditures made to maintain our operating capacity and asset base. Growth capital includes expenditures made to expand the existing operating capacity, to increase the efficiency of our existing assets, and to facilitate an increase in volumes within our operations. Growth capital also includes costs associated with new well connections. Growth capital excludes expenditures for third-party acquisitions and equity investments.

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Operating Data

			Year ended December 31,
			2009		2008		2007		2006		2005
Southwest
	East Texas
		Gathering systems throughput (Mcf/d)		454,400		442,900		413,700		378,100		321,000
		NGL product sales (gallons)		245,787,000		193,534,100		179,601,000		161,437,000		126,476,000
	Oklahoma
		Foss Lake gathering system throughput (Mcf/d)		86,600		95,800		104,000		87,500		75,800
		Stiles Ranch gathering system throughput (Mcf/d)(1)		89,300		84,800		N/A		N/A		N/A
		Grimes gathering system throughput (Mcf/d)(2)		9,700		12,900		12,500		N/A		N/A
		Arapaho NGL product sales (gallons)		126,870,500		79,416,400		87,522,000		79,093,000		60,903,000
		Southeast Oklahoma gathering systems throughput (Mcf/d)(3)		416,800		318,700		114,000		34,000		N/A
		Arkoma Connector Pipeline throughput (Mcf/d)(4)		277,300		N/A		N/A		N/A		N/A
	Other Southwest
		Appleby gathering system throughput (Mcf/d)		47,300		58,400		58,700		34,200		33,400
		Other gathering systems throughput (Mcf/d)(5)		10,300		11,000		8,700		18,300		16,500
Northeast
	Appalachia(6)
		Natural gas processed (Mcf/d)		194,600		202,200		200,200		203,000		197,000
		Keep-whole sales (gallons)		145,493,100		140,847,500		126,192,600		118,581,000		120,300,000
		Percent-of-proceeds sales (gallons)		99,910,200		53,987,900		43,815,100		43,271,000		41,700,000
		Total NGL product sales (gallons)(7)		245,403,300		194,835,400		170,007,700		161,852,000		162,000,000
	Michigan
		Crude oil transported for a fee (Bbl/d)		12,300		13,300		14,000		14,500		14,200
Liberty
	Marcellus Shale(8)
		Gathering system throughput (Mcf/d)		53,500		18,700		N/A		N/A		N/A
		NGL product sales (gallons)		34,409,000		N/A		N/A		N/A		N/A
Gulf Coast(9)
		Refinery off-gas processed (Mcf/d)		120,200		122,900		114,500		124,300		115,000
		Liquids fractionated (Bbl/d)		23,200		24,400		25,000		26,200		19,400

(1)

The 2008 volume reported for the Stiles Ranch gathering system is the average daily rate for the period of operation, which began November 2008.

(2)

We acquired the Grimes gathering system on December 29, 2006.

(3)

We began gathering gas on that the Woodford gathering system in December 2006. The volume reported for 2006 is the average daily rate for the month of December.

(4)

The Arkoma Connector Pipeline was placed into service in July 2009. The volume reported is the average daily rate for the days of operation.

(5)

Excludes lateral pipelines where revenue is not based on throughput.

59

(6)

Includes throughput from the Kenova, Cobb, and Boldman processing plants.

(7)

Represents sales at the Siloam fractionator. The total sales in 2009 exclude 23.3 million gallons sold by the Northeast on behalf of Liberty; those volumes are included in the NGL product sales for Liberty.

(8)

The 2009 and 2008 volumes reported represent the average daily rate for the period of operation.

(9)

We acquired the Javelina system (Gulf Coast) on November 1, 2005. The volume reported is the average daily rate for the days of operation.

ITEM 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

Management's Discussion and Analysis ("MD&A") contains statements that are forward-looking and should be read in conjunction with "Selected Consolidated Financial Data" and our consolidated financial statements and accompanying notes included elsewhere in this report. 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

        Significant financial and other highlights for the year ended December 31, 2009 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

•

Total segment operating income before items not allocated to segments decreased approximately $27.9 million, or 8%, for the year ended December 31, 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:

•

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.

•

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

•

Continued expansion of our Marcellus Shale operations in the Liberty segment which commenced in October 2008.

•

During the year ended December 31, 2009, the prices of NGLs relative to the price of crude oil were below historical averages. This reduced the effectiveness of our hedging program and adversely impacted our cash flows and results of operations. The declines in segment operating income before items not allocated to segments were partially offset by $34.2 million of realized gains on derivative positions.

•

In May 2009, we received net proceeds of $113.8 million from a private placement of senior notes. These notes, with an aggregate principal amount of $150.0 million, are due in November 2014.

60

•

In June 2009, we received net proceeds of $57.7 million from a public offering of approximately 3.34 million newly issued common units.

•

In August 2009, we received net proceeds of $120.9 million from a public offering of approximately 6.03 million newly issued common units.

•

We received $194.5 million of net contributions to MarkWest Liberty Midstream.

•

We received $60.7 million of net proceeds from the sale of a 50% equity interest in MarkWest Pioneer.

•

In September 2009, we sold the SMR, located in Corpus Christi, TX, for net proceeds of approximately $71.6 million.

•

In December 2009, we sold our equity interest in Starfish and received net proceeds of approximately $24.5 million, subject to post-closing adjustments for net working capital.

Impact of Acquisitions on Comparability of Financial Results

        In reviewing our historical results of operations, investors should be aware of the impact of our past acquisitions, which fundamentally affect the comparability of our results of operations over the periods discussed.

        Two acquisitions occurred in 2008 and are included in the results of operations from the acquisition date.

•

On March 1, 2008, we acquired a 20% interest in Centrahoma Processing LLC ("Centrahoma") for $11.6 million, which is accounted for under the equity method. On May 9, 2008, we acquired an additional 20% interest in Centrahoma for $12.0 million including a capital call, which brought our total ownership interest to 40%. As a result, our share of Centrahoma's net loss from March 2008 to December 2008 is included in Earnings from unconsolidated affiliates in the accompanying Consolidated Statements of Operations for the year ended December 31, 2008.

•

The PQ Gathering Assets, L.L.C. ("PQ Assets") acquisition closed on July 31, 2008 for consideration of $41.3 million. As a result, five months of activity for PQ Assets is reflected in the accompanying Consolidated Statements of Operations for the year ended December 31, 2008.

Results of Operations

Segment Reporting

        We classify our business in four reportable segments: Southwest, Northeast, Liberty and Gulf Coast. We capture information in this MD&A by geographical segment. Items below (Loss) income from operations in the accompanying 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 2009 segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests; non-controlling interest were immaterial prior to 2009. The segment information appearing in Note 26 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K is presented on a basis consistent with our internal management reporting and in accordance with GAAP. As a result of the new Liberty segment, segment information for the year ended December 31, 2008 has been recast.

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Year Ended December 31, 2009, Compared to Year Ended December 31, 2008

        The tables below present information about operating income for the reported segments for the years ended December 31, 2009 and 2008.

Southwest

		Year ended December 31,
		2009		2008		$ Change			% Change
		(in thousands)
Revenue		$	492,369	$	652,365	$	(159,996	)		(25	)%
Operating expenses:
	Purchased product costs		221,021		387,516		(166,495	)		(43	)%
	Facility expenses		73,621		62,369		11,252			18	%
Total operating expenses before items not allocated to segments			294,642		449,885		(155,243	)		(35	)%
Portion of operating income attributable to non-controlling interests			2,613		—		2,613			N/A
	Operating income before items not allocated to segments	$	195,114	$	202,480	$	(7,366	)		(4	)%

        Revenue.    Revenue decreased primarily due to lower commodity prices. Revenue from NGL, natural gas and condensate sales decreased across the segment by $191.2 million. The change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest area also contributed to the decline in revenue. The revenue decreases were partially offset by increased volumes processed at the Arapaho facilities associated with the Stiles Ranch gathering system that began operations in the fourth quarter of 2008 and by an increase of $33.0 million in gathering, treating, and transportation fee revenue due primarily to the continued expansion of our operations in the Woodford Shale, 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 for a significant producer in the Other Southwest area.

        Facility Expenses.    Facility expenses increased due primarily to the continued expansion of operations for the Woodford gathering system, including the PQ Assets acquisition in July of 2008, the expansion of the Foss Lake gathering and processing operations, 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' interest in the net operating income of MarkWest Pioneer and Wirth Gathering Partnership.

62

Northeast

		Year ended December 31,
		2009		2008		$ Change			% Change
		(in thousands)
Revenue		$	260,529	$	313,921	$	(53,392	)		(17	)%
Operating expenses:
	Purchased product costs		175,326		228,386		(53,060	)		(23	)%
	Facility expenses		20,339		20,869		(530	)		(3	)%
Total operating expenses before items not allocated to segments			195,665		249,255		(53,590	)		(22	)%
	Operating income before items not allocated to segments	$	64,864	$	64,666	$	198			0	%

        Revenue.    Revenue decreased due mainly to lower commodity prices realized on NGL sales from the Appalachia region. This decrease was partially offset by changes in contract terms and increased volumes from a large producer in the Appalachia region. Revenue also decreased $4.2 million in our Western Michigan area due to the shut-in and subsequent sale or abandonment of the assets in this area.

        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 increased volumes and changes in market value. Purchased product costs in 2008 included an expense of $6.7 million to write down inventories to market value at December 31, 2008. Purchased product costs also decreased $2.8 million in our Western Michigan area due to the shut-in and subsequent sale or abandonment of the assets in this area.

Liberty

		Year ended December 31,
		2009		2008		$ Change		% Change
		(in thousands)
Revenue		$	47,968	$	2,334	$	45,634		1,955	%
Operating expenses:
	Purchased product costs		12,479		—		12,479		N/A
	Facility expenses		16,268		2,006		14,262		711	%
Total operating expenses before items not allocated to segments			28,747		2,006		26,741		1,333	%
Portion of operating income attributable to non-controlling interests			6,637		—		6,637		N/A
	Operating income before items not allocated to segments	$	12,584	$	328	$	12,256		3,737	%

        The results of operations for the year ended December 31, 2009 include our operations in the northern West Virginia and western Pennsylvania areas. Revenue for the year ended December 31, 2009 consists of approximately $30.1 million of fee-based revenue. Approximately $17.9 million of the revenue relates to NGL product sales under percent-of-proceeds arrangements. The portion of operating income attributable to non-controlling interest represents M&R's interest in the net operating income of MarkWest Liberty Midstream.

63

        We began construction in the second quarter of 2008 and commenced gas gathering and processing operations in the fourth quarter of 2008.

Gulf Coast

		Year ended December 31,
		2009		2008		$ Change			% Change
		(in thousands)
Revenue		$	57,769	$	92,042	$	(34,273	)		(37	)%
Operating expenses:
	Facility expenses		16,094		17,368		(1,274	)		(7	)%
Total operating expenses before items not allocated to segments			16,094		17,368		(1,274	)		(7	)%
	Operating income before items not allocated to segments	$	41,675	$	74,674	$	(32,999	)		(44	)%

        Revenue.    Revenue decreased due to lower commodity prices and decreased inlet volumes. The decrease in revenue was partially offset by a higher percent-of-proceeds received from one of our refinery customers under a variable percent-of-proceeds contract.

        Facility Expenses.    Facility expenses decreased primarily due to lower electricity rates. The decrease was partially offset by the cost of the plant turnaround completed in March 2009.

64

Reconciliation of Segment Operating Income to Consolidated (Loss)
Income Before Provision for Income Tax

        The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated (loss) income before provision for income tax for the years ended December 31, 2009 and 2008. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

			Year ended December 31,
			2009			2008			$ Change			% Change
			(in thousands)
Total segment revenue			$	858,635		$	1,060,662		$	(202,027	)		(19	)%
Derivative (loss) gain not allocated to segments				(120,352	)		277,828			(398,180	)		(143	)%
		Total revenue	$	738,283		$	1,338,490		$	(600,207	)		(45	)%
Operating income before items not allocated to segments			$	314,237		$	342,148		$	(27,911	)		(8	)%
	Portion of operating income attributable to non-controlling interests			9,250			—			9,250			N/A
	Derivative (loss) gain not allocated to segments			(188,862	)		254,813			(443,675	)		(174	)%
	Compensation expense included in facility expenses not allocated to segments			(1,032	)		(1,070	)		38			(4	)%
	Facility expenses elimination			377			—			377			N/A
	Selling, general and administrative expenses			(63,728	)		(68,975	)		5,247			(8	)%
	Depreciation			(95,537	)		(67,480	)		(28,057	)		42	%
	Amortization of intangible assets			(40,831	)		(38,483	)		(2,348	)		6	%
	Loss on disposal of property, plant and equipment			(1,677	)		(178	)		(1,499	)		842	%
	Accretion of asset retirement obligations			(198	)		(129	)		(69	)		53	%
	Impairment of goodwill and long-lived assets			(5,855	)		(36,351	)		30,496			(84	)%
		(Loss) income from operations		(73,856	)		384,295			(458,151	)		(119	)%
	Earnings from unconsolidated affiliates			3,505			90			3,415			3,794	%
	Impairment of unconsolidated affiliate			—			(41,449	)		41,449			(100	)%
	Gain on sale of unconsolidated affiliate			6,801			—			6,801			N/A
	Interest income			349			3,769			(3,420	)		(91	)%
	Interest expense			(87,419	)		(64,563	)		(22,856	)		35	%
	Amortization of deferred financing costs and discount (a component of interest expense)			(9,718	)		(8,299	)		(1,419	)		17	%
	Derivative gain related to interest expense			2,509			—			2,509			N/A
	Miscellaneous income (expense), net			2,459			(241	)		2,700			(1,120	)%
		(Loss) income before provision for income tax	$	(155,370	)	$	273,602		$	(428,972	)		(157	)%

        Derivative (Gain) Loss Not Allocated to Segments.    Unrealized loss from the mark-to-market of our derivative instruments was $223.1 million in 2009 compared to unrealized gain of $263.1 million in 2008. Realized gain from the settlement of our derivative instruments was $34.2 million in 2009 compared to realized loss of $8.3 million in 2008. The total change of $443.7 million is due mainly to volatility in commodity prices when comparing prices in 2009 with 2008. Realized gains in 2009 also include net gains of $15.2 million due to the early settlement of certain positions as discussed in Note 7 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

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        Selling, General and Administrative Expenses.    Selling, general and administrative expenses decreased primarily due to lower expense related to share-based incentive compensation plans as the established targets for certain awards are not currently expected to be fully achieved. Additionally, we incurred $2.6 million of expenses related to the Merger during 2008 which did not recur in 2009. These costs are partially offset by increases in headcount and short-term incentive compensation.

        Depreciation and Amortization of Intangible Assets.    Depreciation and amortization expense increased partially due to a $4.4 million increase caused by the step-up in value of property, plant, and equipment and intangible assets as a result of the Merger. The remaining increase is due to depreciation on additional projects completed during 2008 and 2009.

        Impairment of Goodwill and Long-Lived Assets.    During the year ended December 31, 2009, we recognized an impairment of $5.9 million related to certain gas-gathering and intangible assets in the Southwest segment.

        During the year ended December 31, 2008, we recognized an impairment charge of $7.6 million related to certain gas-gathering assets in the Northeast segment. See Note 15 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion.

        During the year ended December 31, 2008, we recognized an impairment charge of $28.7 million related to goodwill that was recorded a result of the purchase accounting for the Merger. The impairment was due primarily to a reduction in our forecasted cash flows caused by a significant decline in commodity prices in the fourth quarter of 2008. See Note 15 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion.

        Earnings from Unconsolidated Affiliates.    Earnings from unconsolidated affiliates is related to our investment in Starfish and Centrahoma. The increase in our earnings from unconsolidated affiliates is due mainly to increased volumes and prices at Starfish. Additionally, operations at Starfish were disrupted in the third and fourth quarter of 2008 due to damage caused by Hurricane Ike. We sold our interest in Starfish effective December 31, 2009. See Note 6 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

        Impairment of Unconsolidated Affiliate.    During the year ended December 31, 2008, we recognized an impairment charge of $41.4 million related to an other-than-temporary decline in the fair value of our equity investment in Starfish. See Note 16 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion.

        Gain on Sale of Unconsolidated Affiliate.    During the year ended December 31, 2009, we sold our equity investment in Starfish. See Note 6 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion.

        Interest Income.    Interest income decreased due to a significant reduction in the excess cash available for short-term investments as a result of our capital spending requirements during 2009. Interest rates were also lower on the amounts that were invested in 2009.

        Interest Expense.    Interest expense increased primarily due to additional borrowings in 2008 and 2009 to fund the Merger and our capital plan. The increase in interest expense was partially offset by a $2.7 million increase in capitalized interest.

        Amortization of Deferred Financing Costs and Discount.    Amortization of deferred financing costs and discount increased due mainly to the amortization of deferred financing costs associated with the issuance of senior notes in May 2009.

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        Derivative Gain Related to Interest Expense.    Derivative gain related to interest expense relates to changes in the fair value of interest rate swaps which we use to manage the interest rate risk associated with the fair value of our fixed rate borrowings. The interest rate swaps effectively convert a portion of the underlying cash flows related to our long-term fixed rate debt securities into variable rate cash flows in order to achieve a desired mix of fixed and variable rate debt. We settled all of the outstanding interest rate swaps in January 2010. See Note 7 and Note 31 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further details.

        Provision for Income Tax.    The total provision for income tax benefit was $42.0 million which includes a deferred benefit of $50.1 million related primarily to MarkWest Hydrocarbon's ownership of Class A units and the net unrealized derivative loss during the period. The current provision for income tax expense was $8.1 million. Approximately $7.3 million is attributable to MarkWest Hydrocarbon, Inc. and the remaining $0.8 million is related to taxes payable by the Partnership associated with the Texas Margin Tax and Michigan Business Taxes. See Note 24 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for a discussion of the significant changes in the provision.

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

        The tables below present information about operating income for the reported segments for the years ended December 31, 2008 and 2007.

Southwest

		Year ended December 31,
		2008		2007		$ Change		% Change
		(in thousands)
Revenue		$	652,365	$	503,461	$	148,904		30	%
Operating expenses:
	Purchased product costs		387,516		310,888		76,628		25	%
	Facility expenses		62,369		44,045		18,324		42	%
	Total operating expenses before items not allocated to segments		449,885		354,933		94,952		27	%
Operating income before items not allocated to segments		$	202,480	$	148,528	$	53,952		36	%

        Revenue.    Revenue increased due primarily to an increase in volumes and higher average annual pricing in most areas of the segment. Revenue in East Texas increased $75.2 million from the sale of greater NGL and condensate volumes and higher prices for most of the year. Additionally, continued expansion in the Woodford gathering system, including the purchase of PQ Assets from PetroQuest Energy, L.L.C., and the start of gas processing operations in this area increased revenue approximately $63.4 million. Revenue from the Other Southwest area increased approximately $39.3 million due to higher average annual prices and increased volumes of approximately 2,000 Mcf/d in the gathering systems. Revenue generated by the Foss Lake region decreased $28.9 million mainly due to lower volumes.

        Purchased Product Costs.    Purchased product costs increased due primarily to the increased NGL purchases in East Texas related to percent-of-proceeds arrangements. Additional increases are related to the increased volumes and higher prices in the Other Southwest area. Additional NGL and gas purchases associated with the Woodford expansion also contributed to the increase.

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        Facility Expenses.    Facility expenses increased due primarily to the increased operations for the Woodford gathering system. Expanded operations in East Texas and Western Oklahoma also contributed to the increase in facility expenses.

Northeast

		Year ended December 31,
		2008		2007		$ Change			% Change
		(in thousands)
Revenue		$	313,921	$	265,152	$	48,769			18	%
Operating expenses:
	Purchased product costs		228,386		177,004		51,382			29	%
	Facility expenses		20,869		16,347		4,522			28	%
	Total operating expenses before items not allocated to segments		249,255		193,351		55,904			29	%
Operating income before items not allocated to segments		$	64,666	$	71,801	$	(7,135	)		(10	)%

        Revenue.    Revenue increased due mainly to higher average annual prices and increased volumes of NGLs sold from the Appalachia region. The increase in volumes resulted from the expanded production of a large producer customer in the area and upgrades to our processing facilities.

        Purchased Product Costs.    Purchased product costs increased mainly due to higher average annual prices for natural gas that must be purchased to satisfy the keep-whole arrangements in the Appalachia area, and an increase in the volumes of natural gas purchased. Purchased product costs also includes an expense of $6.7 million to write down inventories to market value at December 31, 2008. The increase in purchased product costs was partially offset by a $3.0 million decrease in trucking expenses resulting from a change in contractual terms with a producer.

        Facility Expenses.    Facility expenses increased due primarily to increases in plant fuel costs, repairs and maintenance expense and labor and benefits expense to support the increased level of operations in the Appalachia region.

Liberty

		Year ended December 31,
		2008		2007		$ Change		% Change
		(in thousands)
Revenue		$	2,334	$	—	$	2,334		N/A
Operating expenses:
	Facility expenses		2,006		—		2,006		N/A
	Total operating expenses before items not allocated to segments		2,006		—		2,006		N/A
Operating income before items not allocated to segments		$	328	$	—	$	328		N/A

        The results of operations for the year ended December 31, 2008 include our operations in the northern West Virginia and western Pennsylvania areas. We began construction in the second quarter of 2008 and commenced gas gathering and processing operations in the fourth quarter of 2008.

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Gulf Coast

		Year ended December 31,
		2008		2007		$ Change		% Change
		(in thousands)
Revenue		$	92,042	$	77,114	$	14,928		19	%
Operating expenses:
	Facility expenses		17,368		10,471		6,897		66	%
	Total operating expenses before items not allocated to segments		17,368		10,471		6,897		66	%
Operating income before items not allocated to segments		$	74,674	$	66,643	$	8,031		12	%

        Revenue.    Revenue increased due mainly to higher pricing and inlet volumes partially offset by a slightly lower percent-of-proceeds ("POP") received. Effective March 1, 2008, a significant contract changed from a fixed POP to variable POP, resulting in a lower POP received. In addition, the sale of pentanes generated $10.2 million of revenue for the year ended December 31, 2008, compared to $4.8 million for the same period in 2007. Historically, pentanes had to be stored and were sold seasonally. However, with the completion of a new pentane hydrotreater in March 2008, the quality of the pentanes has been improved, and they can be sold on a recurring basis as they are produced.

        Facility Expenses.    Facility expenses increased due partially to a refund of $3.6 million from a utility rate case concluded in the first quarter of 2007. Excluding the refund, facility expenses were $3.2 million higher due mainly to increased energy expenses related to a new contract in March 2008 whereby the Partnership shares the cost of electricity. In 2007 these expenses were fully reimbursed by the customer.

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Reconciliation of Segment Operating Income to Consolidated Income (Loss)
Before Provision for Income Tax

        The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income (loss) before provision for income tax for the years ended December 31, 2008 and 2007. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

			Year ended December 31,
			2008			2007			$ Change			% Change
			(in thousands)
Total segment revenue			$	1,060,662		$	845,727		$	214,935			25	%
Derivative gain (loss) not allocated to segments				277,828			(159,970	)		437,798			(274	)%
		Total revenue	$	1,338,490		$	685,757		$	652,733			95	%
Operating income before items not allocated to segments			$	342,148		$	286,972		$	55,176			19	%
	Derivative gain (loss) not allocated to segments			254,813			(175,148	)		429,961			(245	)%
	Compensation expense included in facility expenses not allocated to segments			(1,070	)		—			(1,070	)		N/A
	Selling, general and administrative expenses			(68,975	)		(72,484	)		3,509			(5	)%
	Depreciation			(67,480	)		(41,281	)		(26,199	)		63	%
	Amortization of intangible assets			(38,483	)		(16,672	)		(21,811	)		131	%
	Loss on disposal of property, plant and equipment			(178	)		(7,743	)		7,565			(98	)%
	Accretion of asset retirement obligations			(129	)		(114	)		(15	)		13	%
	Impairment of goodwill and long-lived assets			(36,351	)		(356	)		(35,995	)		10,111	%
		Income (loss) from operations		384,295			(26,826	)		411,121			(1,533	)%
	Earnings from unconsolidated affiliates			90			5,309			(5,219	)		(98	)%
	Impairment of unconsolidated affiliate			(41,449	)		—			(41,449	)		N/A
	Interest income			3,769			4,547			(778	)		(17	)%
	Interest expense			(64,563	)		(39,435	)		(25,128	)		64	%
	Amortization of deferred financing costs and discount (a component of interest expense)			(8,299	)		(2,983	)		(5,316	)		178	%
	Miscellaneous (expense) income, net			(241	)		233			(474	)		(203	)%
		Income (loss) before provision for income tax	$	273,602		$	(59,155	)	$	332,757			(563	)%

        Derivative Gain (Loss) Not Allocated to Segments.    Derivative gains were $254.8 million for the year ended December 31, 2008, compared to derivative losses of $175.1 million for the year ended December 31, 2007. The change of $430.0 million is primarily attributable to the significant decline in commodity prices in the fourth quarter of 2008. Approximately $413.6 million of the change relates to unrealized gains due to mark-to-market adjustments. Settlements of our derivative instruments resulted in a $16.4 million decrease in realized losses, when comparing 2008 to 2007 results. The decrease in realized derivative losses is primarily attributable to management's decision to settle certain 2010 and 2011 frac spread positions in November and December of 2008. We recognized $28.0 million of net gains during the year ended December 31, 2008 resulting from the settlement of these 2010 and 2011 positions. The settlements were completed prior to 2010 and 2011 to improve liquidity and to mitigate credit risk with certain counterparties, and as such does not represent trading activity. These gains on the early settlement of the 2010 and 2011 positions partially offset the $36.3 million of realized losses resulting from the scheduled settlement of the 2008 positions.

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        Selling, General and Administrative Expenses.    Selling, general and administrative expenses decreased during the year ended December 31, 2008, relative to 2007, due primarily to a $12.2 million decrease in compensation expense related to the Participation Plan and a decrease in Merger-related expenses of $3.8 million. Refer to Note 22 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of the Participation Plan. These decreases in costs were partially offset by an $8.7 million increase in compensation expenses related to phantom unit awards. Increases in professional consulting expenses, office rent expense, letter of credit fees, and novation expenses also partially offset the overall decrease in selling, general, and administrative expenses.

        Depreciation and Amortization of Intangible Assets.    Depreciation and amortization expense increased during the year ended December 31, 2008, relative to 2007, due primarily to a $32.5 million increase caused by the step-up in value of property, plant, and equipment and intangible assets as a result of the Merger. The remainder is due to depreciation on additional projects completed during the fiscal years ended 2008 and 2007.

        Impairment of Goodwill and Long-Lived Assets.    During the year ended December 31, 2008, we recognized an impairment charge of $28.7 million related to goodwill that was recorded a result of the purchase accounting for the Merger. The impairment is due primarily to a reduction in our forecasted cash flows caused by a significant decline in commodity prices in the fourth quarter of 2008. Refer to Note 15 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion.

        During the year ended December 31, 2008, we recognized an impairment charge of $7.6 million related to certain gas-gathering assets in the Northeast segment. During the year ended December 31, 2007, we recognized an impairment charge of $0.4 million related to assets in the Southwest segment. Refer to Note 15 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion.

        Loss on Disposal of Property, Plant, and Equipment.    The loss from disposal of property, plant and equipment decreased during the year ended December 31, 2008, relative to 2007. The $7.7 million loss during the year ended 2007 related primarily to the conveyance of the Maytown facility to Equitable and the write-off of leasehold improvements as a result of the termination of the pipeline lease with Equitable in November 2007. There were no significant disposals during 2008.

        Earnings from Unconsolidated Affiliates.    Earnings from unconsolidated affiliates are primarily related to our investment in Starfish, a joint venture with Enbridge Offshore Pipelines L.L.C. which is accounted for using the equity method. The decrease in our earnings from unconsolidated affiliates for the year ended December 31, 2008, relative to 2007, is due mainly to the damage and business interruption caused by Hurricane Ike in September 2008.

        Impairment of Unconsolidated Affiliate.    During the year ended December 31, 2008, we recognized an impairment charge of $41.4 million related to an other-than-temporary decline in the fair value of our equity investment in Starfish. See Note 16 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further details regarding this impairment charge.

        Interest Income.    Interest income decreased during the year ended December 31, 2008, relative to 2007, mainly due to proceeds received in the first quarter of 2007 from a rate case in our Gulf Coast segment. This decrease was partially offset by interest earnings on additional money market investments resulting from the cash raised in the debt and equity offerings in April 2008.

        Interest Expense.    Interest expense increased during the year ended December 31, 2008, relative to 2007, primarily due to increased borrowings in 2008 to fund the Merger and to raise funds for acquisitions and organic growth projects.

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        Amortization of Deferred Financing Costs and Discount.    Amortization of deferred financing costs and discount increased during the year ended December 31, 2008, relative to 2007, due mainly to the $4.2 million write-off of financing costs related to a term loan that was repaid in April 2008. The remaining increase relates to the amortization of deferred financing costs associated with the revolving credit facility of our Partnership Credit Agreement and the issuance of Senior Notes in April 2008.

        Provision for Income Tax.    The total provision for income tax for the year ended December 31, 2008 was $68.8 million. Refer to Note 24 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for a discussion of the significant changes in the provision.

        The current provision for income tax was $15.0 million for the year ended December 31, 2008. Approximately $13.5 million is attributable to MarkWest Hydrocarbon, Inc. Of this amount, $18.8 million is attributable to MarkWest Hydrocarbon's ownership of Class A units, and the remaining benefit of $5.3 million is related to the Corporation's NGL marketing business. The remaining $1.5 million is related to taxes payable by the Partnership associated with the Texas Margin Tax and Michigan Business Taxes.

Liquidity and Capital Resources

        Our primary strategy is to expand our asset base through organic growth and expansion projects and selective third-party acquisitions that are accretive to our cash available for distribution per common unit. In 2009, we spent approximately $487.0 million on internal development and expansion opportunities, of which a significant portion was funded by our joint venture partners and by our divestiture of the SMR facility as discussed in the Alternative Financing section below.

        Our 2010 capital plan includes approximately $490 million to $540 million of capital expenditures for growth projects and approximately $10 million to $15 million for maintenance capital. Our share of growth capital expenditures is expected to be approximately $300 million to $350 million and the remainder will be funded through contributions from our joint venture partners and existing cash balances in the joint ventures. Growth capital includes expenditures made to expand the existing operating capacity, to increase the efficiency of our existing assets, and to facilitate an increase in volumes within our operations. Growth capital also includes costs associated with new well connections. Growth capital excludes expenditures for third-party acquisitions and equity investments. Maintenance capital includes capital expenditures made to maintain our operating capacity and asset base.

        Our primary sources of liquidity to meet operating expenses, pay distributions to our unitholders and fund capital expenditures are cash flows generated by our operations and access to debt and equity markets, both public and private. We will also consider the use of alternative financing strategies such as entering into additional joint venture arrangements and the sale of non-strategic assets.

        During 2009, we completed the following transactions that have improved our liquidity position:

•

Amended our Partnership Credit Agreement to increase our borrowing capacity under the revolving credit facility from $350.0 million to $435.6 million.

•

Received net proceeds of $113.8 million from a private placement of senior notes.

•

Received net proceeds of $178.6 million from two public offerings of common units.

•

Entered into a joint venture agreement with M&R to jointly fund our growth plan in the Marcellus Shale region. As of December 31, 2009, M&R has contributed $200.0 million to the joint venture, which net of transaction costs has provided additional liquidity of $194.5 million.

•

Entered into a joint venture agreement with ArcLight and received net proceeds of $60.7 million to finance a significant portion of the cost of the Arkoma Connector Pipeline.

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•

Sold the SMR for net proceeds of approximately $71.6 million.

•

Sold our 50% equity interest in Starfish for net proceeds of approximately $24.5 million, subject to post-closing adjustments for net working capital.

        As a result of these financing activities, which are discussed in further detail below, management believes that expenditures for our current capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partners for capital projects encompassed by the joint venture and our current borrowing capacity under the expanded revolving credit facility. However, it may be necessary to raise additional funds to finance our future capital requirements. Our access to capital markets can be impacted by factors outside our control, including economic conditions; however, we believe that our strong cash flows and balance sheet, renewal and expansion of our credit facility and our credit rating will provide us with adequate access to funding given our expected cash needs. Any new borrowing cost would be affected by market conditions and long-term debt ratings assigned by independent rating agencies. As of February 22, 2010, our debt ratings were B2 with a Stable outlook by Moody's Investors Service and B+ with a Stable outlook by Standard & Poor's. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

Debt Financing Activities

        Effective March 2, 2009, the revolving credit facility was amended in order to accommodate the MarkWest Liberty Midstream joint venture with M&R and the available credit facility was expanded to $435.6 million to provide additional liquidity. Under the terms of the amendment, the accordion feature was reset to $200.0 million of uncommitted funds. The term of the original credit agreement has been reduced by one year and is now due on February 20, 2012. Under the provisions of the Partnership Credit Agreement we are subject to a number of restrictions and covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. As of February 22, 2010, we had $10.1 million of borrowings outstanding and $37.5 million of letters of credit outstanding under the revolving credit facility, leaving approximately $388.0 million available for borrowing.

        On May 26, 2009, we completed a private placement of $150.0 million in aggregate principal amount of 6.875% senior unsecured notes due 2014 to qualified institutional buyers under Rule 144A. We received proceeds of approximately $113.8 million, after deducting initial purchasers' discounts and the expenses of the private placement. The proceeds were primarily used to repay borrowings under our revolving credit facility.

        As of December 31, 2009, we had four series of senior notes outstanding: $225.0 million aggregate principal issued in October 2004 and due November 2014 ("2014 Senior Notes"); $150.0 million aggregate principal issued in May 2009 and due November 2014 with terms substantially the same as the 2014 Senior Notes ("2014 Senior Notes—Mirror"); $275.0 million aggregate principal issued in July 2006 and due July 2016 ("2016 Senior Notes"); and $500.0 million aggregate principal issued in April and May 2008 and due April 2018 ("2018 Senior Notes" and all together with the 2014 Senior Notes, 2014 Senior Notes—Mirror, and 2016 Senior Notes, the "Senior Notes"). For further discussion of the Senior Notes see Note 19 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

        The indentures governing the Senior Notes limit our activity, including activity of our restricted subsidiaries. The indentures place limits on our ability to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of our restricted

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subsidiaries to pay dividends or distributions, make loans or transfer property to us; engage in transactions with our affiliates; sell assets, including equity interests of our subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.

        The Partnership Credit Agreement limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. The Partnership Credit Agreement prevents members of the participating bank group from requiring margin calls. As of February 22, 2010, approximately 95% of our derivative positions, measured volumetrically, are with members of the participating bank group and are not subject to margin deposit requirements. We believe this arrangement gives us additional liquidity as it allows us to enter into derivative instruments without utilizing cash for margin calls or requiring the use of letters of credit; however, there is no certainty that the members of our bank group will continue to participate and in such case, a portion of our available credit could be used for derivative instruments instead of future growth.

Equity Offerings

        On June 10, 2009, we completed a public offering of approximately 3.34 million newly issued common units, which included the exercise of the overallotment option by the underwriters, representing limited partner interests at a purchase price of $18.15 per common unit. Net proceeds of approximately $57.7 million were used to partially fund our 2009 capital expenditure requirements and the remainder was used to pay down borrowings under our revolving credit facility of the Partnership Credit Agreement.

        On August 18, 2009, we completed a public offering of approximately 6.03 million newly issued common units, which included the exercise of the overallotment option by the underwriters, representing limited partner interests at a purchase price of $20.95 per common unit. Net proceeds of approximately $120.9 million were used to partially fund our 2009 capital expenditure requirements and the remainder was used to pay down borrowings under our revolving credit facility of the Partnership Credit Agreement.

Alternative Financing Arrangements

        On February 27, 2009, we entered into a joint venture agreement in which M&R acquired a 40% interest in MarkWest Liberty Midstream (see Note 4 of the accompanying Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further details of the joint venture agreement). MarkWest Liberty Midstream operates our natural gas midstream business in and around the Marcellus Shale in western Pennsylvania and northern West Virginia. The 2009 capital expenditures related to projects included within MarkWest Liberty Midstream were approximately $181.5 million. In accordance with the joint venture agreement, M&R made contributions of $200.0 million to MarkWest Liberty Midstream in 2009, offsetting our total 2009 cash requirements.

        Effective November 1, 2009, we and M&R executed the Amended Liberty Agreement. Under the Amended Liberty Agreement, M&R will increase its participation in MarkWest Liberty Midstream by at least an additional $150.0 million. Additionally, we and M&R will maintain a 60%/40% respective ownership interest in MarkWest Liberty Midstream until January 1, 2011, at which time M&R's ownership interest will increase from 40% to 49%. We and M&R will jointly fund the capital requirements of MarkWest Liberty Midstream at agreed upon levels until our contributed capital is proportionate to our 51% ownership interest (the "Equalization Date"), which is expected to occur on or before December 31, 2012. Following the Equalization Date, M&R will have pre-emptive rights to maintain its ownership interest in MarkWest Liberty Midstream in a range of between 45% and 49%. MarkWest Liberty Midstream's capital plan for 2010 through 2012 has not been finalized, so the exact

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timing of the contributions by both parties is currently uncertain. If the Equalization Date has not occurred by December 31, 2012, M&R may elect that we contribute the amount of the shortfall, or may elect that we continue to fund 100% of MarkWest Liberty Midstream's capital expenditures until our total contributed capital is proportionate to our 51% ownership interest.

        On May 1, 2009, we entered into a joint venture with ArcLight (see Note 4 of the accompanying Notes to Consolidated Financial Statements in Item 8 of this Form 10-K for further details of the joint venture agreement). The joint venture entity, MarkWest Pioneer, operates a 50-mile FERC regulated pipeline that connects our gathering systems in the Woodford Shale to the Midcontinent Express Pipeline and the Gulf Crossing Pipeline. ArcLight acquired a 50% equity interest in MarkWest Pioneer for a total purchase price of $62.5 million. ArcLight contributed cash of $31.25 million at closing and an additional $31.25 million in July 2009, corresponding with the pipeline's commercial operations date. We retain a 50% equity interest and we were obligated to fund all capital expenditures necessary to complete construction of the Arkoma Connector Pipeline in excess of $125.0 million.

        On September 1, 2009, we completed the sale of the SMR currently being constructed at our Javelina gas processing and fractionation facility in Corpus Christi, Texas. Under the terms of the agreement, we received proceeds of $73.1 million and the purchaser will complete the construction of the SMR, which is expected to cost an additional $20 million. A related hydrogen supply agreement was executed under which we will receive all of the hydrogen produced by the SMR for the next 20 years in exchange for processing fees and the reimbursement of certain other expenses. We are deemed to have continuing involvement with the SMR as a result of certain provisions in the related agreements. Therefore, the transaction is treated as a financing arrangement under GAAP, not an asset sale. We used the proceeds from the transaction to pay down amounts outstanding under our revolving credit facility and for the continued development of other strategic projects.

        On December 31, 2009, we sold our 50% equity interest in Starfish and received proceeds of approximately $25.0 million. The purchase price is subject to post-closing adjustments to net working capital, which takes into account the cost of repairs performed prior to closing from damage caused by Hurricane Ike in 2008.

        In the future, we may raise additional capital through the issuance of debt and equity securities under our shelf registration statement or in private transactions.

Liquidity Risks and Uncertainties

        Our ability to pay distributions to our unitholders and to fund planned capital expenditures and make acquisitions will depend upon our future operating performance. That, in turn, will be affected by prevailing economic conditions in our industry, as well as financial, business and other factors, some of which are beyond our control. The global economic recession had a significant adverse impact on commodity prices during 2009. Although NGL and natural gas prices have improved somewhat in the latter part of 2009 compared to the end of 2008, our operating performance could continue to be negatively impacted if the improvements in commodity prices are not sustained.

        The prevailing uncertainty that exists in the financial markets has created an increased risk of counterparty default that could impact our liquidity in several ways. During 2010, we expect that we will be required to borrow additional amounts under our revolving credit facility. However, our ability to access these funds could be adversely impacted by the failure of one or more of the members of the participating bank group. Although management believes that the participating members are financially sound, an increased risk does exist. Also, because the participating members of our bank group are the counterparties to most of our derivative instruments, the failure of one of more members could significantly reduce the cash flow from operations related to the settlement of these positions. The cash flows generated by our operations could also be significantly reduced if any of our major customers defaulted. The creditworthiness of our trade customers is continuously monitored, and we believe that

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our current group of customers are sound and represent no abnormal credit risk. Additionally, our supply of gas is dependent on a few large producers in each of our operating segments. If any of these producers were forced to significantly curtail or cease production due to economic adversity, our cash flows from operations could be significantly reduced.

Cash Flow

        The following table summarizes cash inflows (outflows) (in thousands).

	Year ended December 31,
	2009			2008			Change
Net cash provided by operating activities	$	223,101		$	226,995		$	(3,894	)
Net cash used in investing activities		(461,753	)		(909,265	)		447,512
Net cash provided by financing activities		333,083			647,896			(314,813	)

        Net cash provided by operating activities decreased primarily due to a decrease of $27.9 million in operating income, excluding derivative gains and losses, in our operating segments. Operating income decreased in our Southwest and Gulf Coast segments, and was partially offset by an increase in Liberty, a new segment in 2009. Cash provided by operations for the year ended December 31, 2008 also included $40.3 million of inflows from the return of margin deposits which did not recur in 2009. These decreases were offset by an increase of $44.6 million in net cash received from the settlement of derivative positions and an increase in operating cash flows provided by working capital in 2009.

        Net cash used in investing activities decreased primarily due to cash paid as consideration in the Merger of $269.9 million in 2008. In 2008, we acquired PQ Assets for $41.3 million and there were no acquisitions in 2009. Cash contributed to equity investments in 2008 were higher by $28.8 million mainly due to the contribution to acquire Centrahoma. In addition, capital expenditures decreased by $88.7 million mainly in our Southwest segment offset by increases in our Liberty segment. Also, in 2009 we received proceeds of $25.0 million related to the sale of our equity interest in Starfish.

        Net cash provided by financing activities decreased primarily due to the $636.3 million decrease of net borrowings on long-term debt. This decrease was offset by $194.5 million in net contributions from M&R to MarkWest Liberty Midstream, $60.7 million in net proceeds from the sale of equity interest in the Arkoma joint venture, and $73.1 million in proceeds from the SMR Transaction. See Debt Financing Activities, Equity Offerings and Alternative Financing Arrangements above for a discussion of our 2009 financing activities.

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Total Contractual Cash Obligations

        A summary of our total contractual cash obligations as of December 31, 2009, is as follows (in thousands):

		Payment Due by Period
Type of obligation		Total Obligation		Due in 2010		Due in 2011-2012		Due in 2013-2014		Thereafter
Long-term debt		$	1,209,300	$	—	$	59,300	$	375,000	$	775,000
Interest expense on long-term debt(1)			649,825		96,020		189,445		181,516		182,844
Operating leases(2)			59,367		9,170		12,980		14,293		22,924
Purchase obligations(3)			16,723		16,723		—		—		—
Natural gas purchase obligations(4)			154,545		28,892		60,150		61,889		3,614
SMR Liability(5)			348,240		14,510		34,824		34,824		264,082
Other long-term liabilities reflected on the Consolidated Balance Sheets:
	Asset retirement obligation(6)		2,877		—		—		—		2,877
	Other(7)		7,566		1,636		2,667		1,280		1,983
Total contractual cash obligations		$	2,448,443	$	166,951	$	359,366	$	668,802	$	1,253,324

(1)

Assumes that our outstanding borrowings at December 31, 2009 remain outstanding until their respective maturity dates and we incur interest expense at 5.25% on the Partnership Credit Facility revolver, 6.875% on the 2014 Senior Notes and 2014 Senior Notes—Mirror, 8.5% on the 2016 Senior Notes and 8.75% on the 2018 Senior Notes.

(2)

Amounts relate primarily to compressor rentals and our office leases.

(3)

Represents purchase orders and contracts related to purchase of property, plant and equipment. Purchase obligations exclude current and long-term unrealized losses on derivative instruments included on the accompanying Consolidated Balance Sheets, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts are generally settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity.

(4)

Natural gas purchase obligations consist primarily of a purchase agreement with a producer in the Appalachia region. The contract provides for the purchase of keep-whole volumes at a specific price and is a component of a broader regional arrangement. The contract price is designed to share a portion of the frac spread with the producer and as a result, the amounts reflected for the obligation exceed the cost of purchasing the keep-whole volumes at a market price. The contract is considered an embedded derivative; see Note 7 of the accompanying Notes to Consolidated Financial Statements included in Item 8 for the fair value of the frac spread sharing component.

(5)

Represents amounts due under hydrogen supply agreement (see Note 6 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K).

(6)

Excludes accretion expense of $10.7 million. The total amount to be paid is approximately $13.6 million.

(7)

Primarily represents long-term portion of deferred revenue.

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Off-Balance Sheet Arrangements

        We do not engage in off-balance sheet financing activities.

Effects of Inflation

        Inflation did not have a material impact on our results of operations for the years ended December 31, 2009, 2008 or 2007. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire or replace property, plant and equipment. It may also increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and will continue to pass along increased costs to our customers in the form of higher fees.

Critical Accounting Policies and Estimates

        The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

        The policies and estimates discussed below are considered by management to be critical to an understanding of our financial statements, because their application requires the most significant judgments from management in estimating matters for financial reporting that are inherently uncertain. See Note 2 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for additional information on these policies and estimates, as well as a discussion of additional accounting policies and estimates.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Inventories
Inventories, which consist primarily of natural gas, propane, and other NGLs, are recorded at the lower of weighted-average cost or market value.	Due to the short-term volatility in commodity prices and differences based on geographic location, judgment is required in determining the market value of inventory. We estimate the market value based on the expected sales prices during the periods in which inventory will be sold.	As a result of the lower of cost or market analysis performed at December 31, 2009, no adjustment was required to record inventories at the lower of cost or market. If the actual sales prices are 10% lower than the expected prices used in our analysis, there would still be no required adjustment and no impact on the reported net income before taxes.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Intangible Assets
Intangible assets are comprised of customer contracts and relationships acquired in business combinations, recorded under the purchase method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets.	The fair value of customer contracts is generally calculated using the income approach. The key assumptions include contract renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, pricing volatility, and the discount rate.	If the actual results differ significantly from the assumptions used to determine the fair value and economic lives of intangible assets, then a significant impairment charge could be recorded (see Impairment of Long-Lived Assets below) or amortization expense could increase.
	Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. The estimated economic life is determined by assessing the life of the assets to which the contracts and relationships relate, likelihood of renewals, the projected reserves, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Impairment of Long-Lived Assets
Management evaluates our long-lived assets, including intangibles, for impairment when events or changes in circumstances warrant such a review. A long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group's carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group.	Management considers the volume of reserves behind the asset and future NGL product and natural gas prices to estimate cash flows for each asset group. The amount of additional reserves developed by future drilling activity depends, in part, on expected commodity prices. Projections of reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast.	During 2009 we wrote down the value of long-lived assets for Wirth Gathering Partnership to zero resulting in a $5.9 million impairment expense. As of December 31, 2009, there were no indicators of additional impairment for any of our asset groups. A significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset. A 10% decrease in the estimated future cash flows used in our impairment analysis would have indicated a potential impairment for one asset group with a total net book value of $51.8 million.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Impairment of Goodwill
Goodwill is the cost of an acquisition less the fair value of the net assets of the acquired business. We evaluate goodwill for impairment annually as of November 30, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.	Management determines the fair value of our reporting units using the income and market approaches. These approaches are also used when allocating the purchase price to acquired assets and liabilities. These types of analyses require us to make assumptions and estimates regarding industry and economic factors such as relevant commodity prices and production volumes. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations.	As a result of the goodwill impairment testing completed in 2009, we recorded no impairment expense. The fair value of each reporting unit with goodwill was significantly in excess of its carrying value.
	Management was also required to make certain assumptions when identifying the reporting units and determining the amount of goodwill allocated to each reporting unit. The method of allocating goodwill resulting from the Merger involved estimating the fair value of the reporting units and allocating the purchase price of the Merger to each reporting unit. Goodwill was then calculated for each reporting unit as the excess of the allocated purchase price over the estimated fair value of the net assets.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Impairment of Equity Investments
We evaluate our equity method investments for impairment whenever events or changes in circumstances indicate, in management's judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of an other-than-temporary loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred.	Our impairment loss calculations require management to apply judgment in estimating future cash flows and asset fair values, including forecasting useful lives of the assets, assessing the probability of differing estimated outcomes, and selecting the discount rate that reflects the risk inherent in future cash flows. We assess the fair value of our equity method investments using commonly accepted techniques, and may use more than one method, including, but not limited to, recent third party comparable sales and discounted cash flow models.	Management determined that there were no material events or changes in circumstances that would indicate an other-than-temporary decline in value of our investment in Centrahoma.
Accounting for Share-Based Compensation
Our long-term incentive plans permit the grant of restricted units, phantom units, unit options and substitute awards. As of December 31, 2009, only phantom units are issued and outstanding under these plans. Compensation expense is recognized over the vesting period or service period of the related awards. Compensation expense is only recognized for those awards for which vesting is probable. The vesting of performance-based awards is contingent upon us meeting specific financial targets in fiscal years 2009, 2010 and 2011.	We must exercise judgment and make several assumptions regarding the future profits and cash flows of the Partnership in order to estimate the number of performance-based units for which vesting is probable.	As of December 31, 2009, management expected none of the outstanding performance-based awards related to fiscal years 2009, 2010 and 2011 performance to vest and recorded no compensation expense accordingly. If management had concluded that vesting of all of the performance awards was probable, an additional $5.8 million of compensation expense would have been recognized during the year ended December 31, 2009.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Accounting for Risk Management Activities and Derivative Financial Instruments
Our derivative financial instruments are recorded at fair value in the accompanying Consolidated Balance Sheets. Changes in fair value and settlements are reflected in our earnings in the accompanying Consolidated Statements of Operations as gains and losses related to revenue, purchased product costs, facility expenses, interest income and/or miscellaneous income.	When available, quoted market prices or prices obtained through external sources are used to determine a financial instrument's fair value. The valuation of Level 2 financial instruments is based on quoted market prices for similar assets and liabilities in active markets and other inputs that are observable. However, for other financial instruments for which quoted market prices are not available, the fair value is based on inputs that are largely unobservable. These instruments are classified as Level 3 under the fair value hierarchy. The fair value of these instruments are determined based on pricing models developed primarily from historical and expected correlations with quoted market prices. All fair value measurements are appropriately adjusted for nonperformance risk.	If the assumptions used in the pricing models for our Level 2 and 3 financial instruments are inaccurate or if we had used an alternative valuation methodology, the estimated fair value may have been different, and we may be exposed to unrealized losses or gains that could be material. A 10% difference in our estimated fair value of Level 2 and 3 derivatives at December 31, 2009 would have affected net income by approximately $14.8 million for the year ended December 31, 2009.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Variable Interest Entities
We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity is a variable interest entity ("VIE"). Our interests in a VIE are referred to as variable interests. A variable interest can have the obligation to absorb expected losses and/or the right to receive the residual benefits of a VIE. When we conclude that we hold a variable interest in a VIE we must determine if we are the entity's primary beneficiary. A primary beneficiary absorbs a majority of the entity's expected losses or receives a majority of its residual returns, or both. We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any variable interests in a VIE that is not consolidated.	Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use qualitative and quantitative analysis to determine if an entity is a VIE. We evaluate the entity's need for continuing financial support; the equity holder's lack of the traditional characteristics of a controlling financial interest; and/or if an equity holders voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our variable interests in a VIE to determine whether we are the primary beneficiary. We use qualitative and quantitative analysis to determine if we absorb a majority of the VIE's expected losses and/or have the right to a majority of its residual returns. In circumstances where other variable interests are deemed to be our de-facto agents, we qualitatively determine if we are involved in substantially all of the VIE's activities, which would indicate we are the primary beneficiary. When reconsideration events occur, we evaluate changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions.	MarkWest Liberty Midstream and MarkWest Pioneer are VIEs and we are considered the primary beneficiary; we have a controlling financial interest in the Wirth Gathering Partnership and the Brightstar Partnership, which are less-than wholly-owned. All of these entities are consolidated subsidiaries. Changes in the design or nature of the activities of any of these entities, or our involvement with an entity may require us to reconsider our conclusions on the entity's status as a VIE and/or our status as the primary beneficiary. Such reconsideration could result in the deconsolidation of the affected subsidiary. The deconsolidation of a subsidiary would have a significant impact on our financial statements. We account for our ownership interest in Centrahoma under the equity method and have determined it is not a VIE. However, changes in the design or nature of the activities of the entity may require us to reconsider our conclusions. Such reconsideration would require the identification of the variable interests in the entity and a determination on which party is the entity's primary beneficiary. If Centrahoma were considered a VIE and we were determined to be the primary beneficiary, the change could cause us to consolidate the entity. The consolidation of an entity that is currently accounted for under the equity method could have a significant impact on our financial statements.

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Recent Accounting Pronouncements

        Refer to Note 2—Recent Accounting Pronouncements of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for information regarding recent accounting pronouncements.

ITEM 7A.    Quantitative and Qualitative Disclosures About Market Risk

        Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity price changes and, to a lesser extent, interest rate changes.

        Refer to Note 7 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for information and disclosures regarding our commodity price risk.

        The following table provides information on the derivative positions that we have entered into subsequent to December 31, 2009.

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)
2011		1,673	$	75.00	$	90.30

Interest Rate

        Our primary interest rate risk exposure results from the revolving portion of the Partnership Credit Agreement that has a borrowing capacity of $435.6 million. As of February 22, 2010, we have $10.1 million of borrowings outstanding on the revolving credit facility. The debt related to this agreement bears interest at variable rates that are tied to either the U.S. prime rate or LIBOR at the time of borrowing.

        We may make use of interest rate swap agreements in the future, to adjust the ratio of fixed and floating rates in our debt portfolio. In July 2009, we entered into fixed-to-variable interest rate swap agreements having a combined notional principal amount of $275.0 million. The hedges were intended to hedge against changes in fair value due to changes in the benchmark interest rate (one-month LIBOR). We hedged a portion of our senior notes that mature on November 1, 2014. All outstanding interest rate swaps were settled in January 2010.

Long-Term Debt	Interest Rate	Lending Limit		Due Date	Outstanding at December 31, 2009
Partnership Credit Agreement	Variable	$	435.6 million	February 2012	$	59.3 million
2014 Senior Notes	Fixed	$	225.0 million	November 2014	$	225.0 million
2014 Senior Notes—Mirror	Fixed	$	150.0 million	November 2014	$	150.0 million
2016 Senior Notes	Fixed	$	275.0 million	July 2016	$	275.0 million
2018 Senior Notes	Fixed	$	500.0 million	April 2018	$	500.0 million

        Based on our overall interest rate exposure at December 31, 2009, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our credit facility would change earnings by approximately $3.3 million over a 12-month period. Based on our overall interest rate exposure at February 22, 2010, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our credit facility would not have a material impact on our earnings over a 12-month period.

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ITEM 8.    Financial Statements and Supplementary Data

Index to Consolidated Financial Statements

Report of Deloitte & Touche LLP, Independent Registered Public Accounting Firm	87
Consolidated Balance Sheets at December 31, 2009 and 2008	88
Consolidated Statements of Operations for the years ended December 31, 2009, 2008 and 2007	89
Consolidated Statements of Changes in Partners' Capital and Comprehensive (Loss) Income for the years ended December 31, 2009, 2008 and 2007	90
Consolidated Statements of Cash Flows for the years ended December 31, 2009, 2008 and 2007	91
Notes to Consolidated Financial Statements for the years ended December 31, 2009, 2008 and 2007	92

        All omitted schedules have been omitted because they are not required or because the required information is contained in the financial statements or notes thereto.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of
MarkWest Energy GP, L.L.C.
Denver, Colorado

        We have audited the accompanying consolidated balance sheets of MarkWest Energy Partners, L.P. and subsidiaries (the "Partnership") as of December 31, 2009 and 2008, and the related consolidated statements of operations, changes in partners' capital and comprehensive income, and cash flows for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements based on our audits.

        We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

        In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of MarkWest Energy Partners, L.P. and subsidiaries as of December 31, 2009 and 2008, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated March 1, 2010 expressed an unqualified opinion on the Partnership's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
March 1, 2010

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MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

			December 31, 2009			December 31, 2008
ASSETS
Current assets:
	Cash and cash equivalents		$	97,752		$	3,321
	Receivables, net of allowances of $162 and $175, respectively			140,969			101,849
	Inventories			29,075			31,556
	Fair value of derivative instruments			8,821			126,949
	Deferred income taxes			12,228			—
	Other current assets			10,674			11,748
		Total current assets		299,519			275,423
Property, plant and equipment				2,154,644			1,650,692
Less: accumulated depreciation				(173,000	)		(81,167	)
		Total property, plant and equipment, net		1,981,644			1,569,525
Other long-term assets:
	Investment in unconsolidated affiliates			29,633			46,092
	Intangibles, net of accumulated amortization of $83,735 and $42,972, respectively			654,411			695,917
	Goodwill			9,421			9,421
	Deferred financing costs, net of accumulated amortization of $6,990 and $3,248, respectively			21,027			16,682
	Deferred contract cost, net of accumulated amortization of $1,638 and $1,326, respectively			1,612			1,924
	Fair value of derivative instruments			15,810			55,389
	Other long-term assets			1,660			2,681
		Total assets	$	3,014,737		$	2,673,054
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
	Accounts payable		$	87,832		$	72,837
	Accrued liabilities			137,687			111,034
	Deferred income taxes			—			2,682
	Fair value of derivative instruments			60,464			37,633
		Total current liabilities		285,983			224,186
Deferred income taxes				11,034			47,465
Fair value of derivative instruments				62,519			14,801
Long-term debt, net of discounts of $39,417 and $11,735, respectively				1,170,072			1,172,965
Other long-term liabilities				105,736			5,878
Commitments and contingencies (see Note 21)
Partners' Capital:
	MarkWest Energy Partners, L.P. partners' capital (66,275 and 56,640 units outstanding, respectively)			1,096,654			1,204,458
	Non-controlling interest in consolidated subsidiaries			282,739			3,301
		Total partners' capital		1,379,393			1,207,759
		Total liabilities and partners' capital	$	3,014,737		$	2,673,054

The accompanying notes are an integral part of these consolidated financial statements.

88

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

			Year ended December 31,
			2009			2008			2007
Revenue:
	Revenue		$	858,635		$	1,060,662		$	845,727
	Derivative (loss) gain			(120,352	)		277,828			(159,970	)
		Total revenue		738,283			1,338,490			685,757
Operating expenses:
	Purchased product costs			408,826			615,902			487,892
	Derivative loss related to purchased product costs			68,883			22,371			15,192
	Facility expenses			126,977			103,682			70,863
	Derivative (gain) loss related to facility expenses			(373	)		644			(14	)
	Selling, general and administrative expenses			63,728			68,975			72,484
	Depreciation			95,537			67,480			41,281
	Amortization of intangible assets			40,831			38,483			16,672
	Loss on disposal of property, plant and equipment			1,677			178			7,743
	Accretion of asset retirement obligations			198			129			114
	Impairment of goodwill and long-lived assets			5,855			36,351			356
		Total operating expenses		812,139			954,195			712,583
		(Loss) income from operations		(73,856	)		384,295			(26,826	)
Other income (expense):
	Earnings from unconsolidated affiliates			3,505			90			5,309
	Impairment of unconsolidated affiliate			—			(41,449	)		—
	Gain on sale of unconsolidated affiliate			6,801			—			—
	Interest income			349			3,769			4,547
	Interest expense			(87,419	)		(64,563	)		(39,435	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(9,718	)		(8,299	)		(2,983	)
	Derivative gain related to interest expense			2,509			—			—
	Miscellaneous income (expense), net			2,459			(241	)		233
		(Loss) income before provision for income tax		(155,370	)		273,602			(59,155	)
Provision for income tax (benefit) expense:
	Current			8,072			15,032			23,869
	Deferred			(50,088	)		53,798			(48,518	)
		Total provision for income tax		(42,016	)		68,830			(24,649	)
		Net (loss) income		(113,354	)		204,772			(34,506	)
Net (income) loss attributable to non-controlling interest				(5,314	)		3,301			(4,853	)
		Net (loss) income attributable to the Partnership	$	(118,668	)	$	208,073		$	(39,359	)
Net (loss) income attributable to the Partnership's common unitholders per common unit(1) (Note 25):
	Basic		$	(1.97	)	$	4.02		$	(1.72	)
	Diluted		$	(1.97	)	$	4.02		$	(1.72	)
Weighted average number of outstanding common units(1):
	Basic			60,957			51,013			22,854
	Diluted			60,957			51,016			22,854
Cash distribution declared per common unit(1)			$	2.560		$	2.059		$	0.703

(1)

All unit and per unit data where applicable has been adjusted to reflect the Exchange Ratio to give effect to the Merger (see Note 3).

The accompanying notes are an integral part of these consolidated financial statements.

89

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN
PARTNERS' CAPITAL AND COMPREHENSIVE (LOSS) INCOME

(in thousands)

		MarkWest Energy Partners, L.P. Unitholders
		Common Units(1)			Partners' Capital			Accumulated Other Comprehensive Income			Non-controlling Interest			Total
December 31, 2006			22,813		$	40,386		$	1,103		$	441,572		$	483,061
Stock option exercises			17			119			—			—			119
Restricted stock activity, net of registration costs			31			753			—			—			753
Gain in connection with issuance of units by MarkWest Energy Partners, L.P. (net of tax of $31.5 million)			—			52,367			—			—			52,367
APIC pool for excess tax benefits related to share-based compensation			—			335			—			—			335
Proceeds from Mark West Energy's private placement, net			—			—			—			224,951			224,951
Gain related to accounting for sales of stock by a subsidiary			—			—			—			(83,844	)		(83,844	)
Other			—			(71	)		—			967			896
Dividends paid			—			(16,067	)		—			—			(16,067	)
Distributions to non-controlling interest holders			—			—			—			(63,916	)		(63,916	)
Net (loss) income			—			(39,359	)		—			4,853			(34,506	)
Unrealized loss on marketable securities, net of tax of $110			—			—			(175	)		—			(175	)
Comprehensive loss															(34,681	)
December 31, 2007			22,861			38,463			928			524,583			563,974
Option exercises			98			375			—			—			375
Share-based compensation activity			14			11,560			—			—			11,560
Dividends paid			—			(4,338	)		—			—			(4,338	)
Distributions paid			—			(107,269	)		—			(19,651	)		(126,920	)
APIC pool for excess tax benefits related to share-based compensation			—			717			—			—			717
Acquisition of partially owned entity included as part of PQ Gathering Assets, L.L.C.			—			—			—			2,935			2,935
Other			—			—			—			1,032			1,032
Merger and Redemption:
	Redemption of MarkWest Hydrocarbon, Inc. common stock		(7,458	)		(240,513	)		—			—			(240,513	)
	Conversion of restricted stock to phantom units in connection with the Merger		(45	)		—			—			—			—
	Acquisition of General Partnership's non-controlling interest associated with the Merger		946			30,078			—			—			30,078
	Purchase of non-controlling interest of MarkWest Energy Partners, L.P.		34,474			1,095,917			—			(502,297	)		593,620
Issuance of units in public offering, net of offering costs			5,750			171,395			—			—			171,395
Net income (loss)			—			208,073			—			(3,301	)		204,772
Realized gain on marketable securities, net of tax of $558			—			—			(928	)		—			(928	)
Comprehensive income															203,844
December 31, 2008			56,640			1,204,458			—			3,301			1,207,759
Share-based compensation activity			275			5,204			—			—			5,204
Distributions paid			—			(155,307	)		—			(155	)		(155,462	)
Issuance of units in public offering, net of offering costs			9,360			178,565			—			—			178,565
Contributions to MarkWest Liberty Midstream joint venture, net			—			(5,464	)		—			200,000			194,536
Proceeds from sale of equity interest in joint venture, net			—			(1,846	)		—			62,500			60,654
Transfer to non-controlling interest from sale of equity interest in joint venture, net of tax			—			(10,288	)		—			11,779			1,491
Net (loss) income			—			(118,668	)		—			5,314			(113,354	)
December 31, 2009			66,275		$	1,096,654		$	—		$	282,739		$	1,379,393

(1)

All unit data where applicable has been adjusted to reflect the Exchange Ratio to give effect to the Merger (see Note 3).

The accompanying notes are an integral part of these consolidated financial statements.

90

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

				Year ended December 31,
				2009			2008			2007
Cash flows from operating activities:
Net (loss) income				$	(113,354	)	$	204,772		$	(34,506	)
	Adjustments to reconcile net (loss) income to net cash provided by operating activities (net of acquisitions):
	Depreciation				95,537			67,480			41,281
	Amortization of intangible assets				40,831			38,483			16,672
	Impairment of goodwill and long-lived assets				5,855			36,351			356
	Impairment of unconsolidated affiliate				—			41,449			—
	Inventory lower of cost or market adjustment				—			6,678			—
	Amortization of deferred financing costs and discount				9,718			8,299			2,983
	Accretion of asset retirement obligations				198			129			114
	Amortization of deferred contract costs				312			312			312
	Phantom unit compensation expense				7,448			11,348			2,080
	Participation Plan compensation expense				—			4,545			17,704
	Stock option compensation expense				—			—			(27	)
	Restricted stock compensation expense				—			75			780
	Equity in earnings of unconsolidated affiliates				(3,505	)		(90	)		(5,309	)
	Gain on sale of unconsolidated affiliate				(6,801	)		—			—
	Distributions from unconsolidated affiliates				—			445			10,840
	Unrealized loss (gain) on derivative instruments				227,920			(276,526	)		150,418
	Loss on disposal of property, plant and equipment				1,677			178			7,743
	Deferred income taxes				(50,088	)		53,798			(48,518	)
	Gain on sale of available for sale securities				—			(1,238	)		(668	)
	Trading securities transactions, net				512			3,162			(3,674	)
	Other				(2,740	)		181			(190	)
	Changes in operating assets and liabilities, net of working capital acquired:
		Receivables			(33,133	)		29,028			(29,761	)
		Inventories			6,245			(7,906	)		4,451
		Other current assets			1,074			39,430			(35,057	)
		Accounts payable and accrued liabilities			30,717			(34,072	)		34,051
		Other long-term assets			(2,808	)		(1,126	)		—
		Other long-term liabilities			7,486			1,810			1,162
			Net cash provided by operating activities		223,101			226,995			133,237
Cash flows from investing activities:
	Capital expenditures				(486,623	)		(575,298	)		(316,639	)
	Acquisitions				—			(41,300	)		29
	Equity investments				(405	)		(29,187	)		—
	Cash paid to acquire General Partnership's non-controlling interest				—			(21,484	)		—
	Cash paid in Merger for MarkWest Hydrocarbon, Inc. stock				—			(248,395	)		—
	Proceeds from sale of unconsolidated affiliate				25,000			—			—
	Proceeds from sale of available for sale securities				—			6,226			1,622
	Proceeds from disposal of property, plant and equipment				275			173			196
			Net cash flows used in investing activities		(461,753	)		(909,265	)		(314,792	)
Cash flows from financing activities:
	Proceeds from revolver				725,200			678,001			499,100
	Payments of revolver				(850,600	)		(548,801	)		(473,600	)
	Proceeds from long-term debt				117,000			498,732			—
	Payments for debt issuance costs, deferred financing costs and registration costs				(8,554	)		(21,204	)		(516	)
	Contributions to MarkWest Liberty Midstream joint venture, net				194,536			—			—
	Proceeds from sale of equity interest in joint venture, net				60,654			—			—
	Proceeds from SMR Transaction				73,129			—			—
	Proceeds from private placements, net				—			—			224,951
	Proceeds from public offering, net				178,565			171,395			—
	Exercise of stock options				—			375			119
	Cash paid for taxes related to net settlement of share-based payment awards				(1,385	)		(61	)		—
	APIC pool for excess tax benefits related to share-based compensation				—			717			335
	Payment of dividends and distributions				(155,462	)		(111,607	)		(16,067	)
	Distributions to MarkWest Energy unitholders prior to the Merger				—			(19,651	)		(63,916	)
			Net cash flows provided by financing activities		333,083			647,896			170,406
Net increase (decrease) in cash					94,431			(34,374	)		(11,149	)
Cash and cash equivalents at beginning of year					3,321			37,695			48,844
Cash and cash equivalents at end of year				$	97,752		$	3,321		$	37,695

The accompanying notes are an integral part of these consolidated financial statements.

91

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization

        MarkWest Energy Partners, L.P. ("MarkWest Energy Partners") was formed in January 2002, as a Delaware limited partnership. MarkWest Energy Partners and its majority-owned subsidiaries (collectively, the "Partnership") are 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. The Partnership has established a significant presence in the Southwest through strategic acquisitions and strong organic growth opportunities stemming from those acquisitions. The Partnership is also the largest processor of natural gas in the Appalachian Basin, one of the country's oldest natural gas producing regions. The Partnership also has a significant presence in the Marcellus Shale through a joint venture that is the largest gatherer and processor of natural gas in this emerging resource play. Finally, the Partnership owns a crude oil transportation pipeline in Michigan. The Partnership's principal executive office is located in Denver, Colorado.

        On February 21, 2008, MarkWest Energy Partners consummated the transactions contemplated by its plan of redemption and merger (the "Merger") with MarkWest Hydrocarbon, Inc. (the "Corporation" or "MarkWest Hydrocarbon") and MWEP, L.L.C., a wholly-owned subsidiary of the Partnership. A discussion of the Merger and its accounting impact on the Partnership is described in Note 3. The Merger was considered a downstream merger, whereby the Corporation was viewed as the surviving consolidated entity for accounting and financial purposes rather than the Partnership, which is the surviving consolidated entity for legal purposes. As such, the Merger was accounted for in the Corporation's consolidated financial statements as an acquisition of non-controlling interest using the purchase method of accounting. As a result, the historical and comparative consolidated financial statements of the surviving legal entity are those of the Corporation, the accounting acquirer, rather than those of the Partnership, the legal acquirer.

2. Summary of Significant Accounting Policies

Basis of Presentation

        The Partnership's consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Liberty Midstream & Resources, L.L.C. ("MarkWest Liberty Midstream") and MarkWest Pioneer, L.L.C. ("MarkWest Pioneer"), variable interest entities for which the Partnership has been determined to be the primary beneficiary, are included in the consolidated financial statements (see Note 4 for further discussion of MarkWest Liberty Midstream and MarkWest Pioneer). All significant intercompany investments, accounts and transactions have been eliminated. Investments in which the Partnership exercises significant influence but does not control, and is not the primary beneficiary, are accounted for using the equity method. The accompanying consolidated financial statements include the accounts of the Partnership, and have been prepared in accordance with GAAP.

Non-Controlling Interest in Consolidated Subsidiaries

        The Partnership owns a controlling operating interest in Wirth Gathering, a general partnership. The Partnership's equity interest was acquired as part of the acquisition of PQ Gathering Assets, L.L.C. ("PQ Assets", see Note 5). The interests in Wirth Gathering, MarkWest Liberty Midstream and MarkWest Pioneer that are not owned by the Partnership have been recorded as Non-controlling interest in consolidated subsidiaries in the accompanying Consolidated Balance Sheets. The amount recorded in 2009 relates to all three of these entities, the amount recorded in 2008 relates primarily to Wirth

92

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

Gathering and the amount recorded in 2007 relates to the non-controlling interest in the Partnership that no longer exists due to the Merger (see Note 3).

Use of Estimates

        The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Estimates affect, among other items, valuing identified intangible assets; determining the fair value of derivative instruments; valuing inventory, evaluating impairments of long-lived assets, goodwill and equity investments; establishing estimated useful lives for long-lived assets; recognition of share-based compensation expense; estimating revenues and expense accruals; valuing asset retirement obligations; and in determining liabilities, if any, for legal contingencies.

Cash and Cash Equivalents

        The Partnership considers investments in highly liquid financial instruments purchased with an original maturity of 90 days or less to be cash equivalents. Such investments include money market accounts.

Inventories

        Inventories are valued at the lower of weighted average cost or market. Inventories consisting primarily of crude oil and unprocessed natural gas are valued based on the cost of the raw material. Processed natural gas inventories include material, labor and overhead. Shipping and handling costs related to purchases of natural gas and NGLs are included in inventory.

Property, Plant and Equipment

        Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-lived assets are capitalized and amortized over the related asset's estimated useful life. Leasehold improvements are depreciated over the shorter of the useful life or lease term. Depreciation is provided, principally on the straight-line method, over the following estimated useful lives:

Asset Class	Range of Estimated Useful Lives
Buildings		20 - 25 years
Gas gathering facilities		20 - 25 years
Gas processing plants		20 - 25 years
Fractionation and storage facilities		20 - 25 years
Natural gas pipelines		20 - 25 years
Crude oil pipelines		20 - 25 years
NGL transportation facilities		20 - 25 years
Equipment and other		3 - 10 years

93

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

Asset Retirement Obligations

        An asset retirement obligation ("ARO") is a legal obligation associated with the retirement of tangible long-lived assets that generally result from the acquisition, construction, development or normal operation of the asset. AROs are recorded at fair value in the period in which they are incurred, if a reasonable estimate of fair value can be made, and added to the carrying amount of the associated asset. This additional carrying amount is then depreciated over the life of the asset. The liability is determined using a risk free interest rate, and increases due to the passage of time based on the time value of money until the obligation is settled. The Partnership recognizes a liability of a conditional ARO as soon as the fair value of the liability can be reasonably estimated. A conditional ARO is defined as an unconditional legal obligation to perform an asset retirement activity in which the timing and/or method of settlement are conditional on a future event that may or may not be within the control of the entity.

Regulation

        Certain assets and operations of the Partnership are subject to regulation by the FERC. The Partnership's accounting policies related to these assets conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the FERC.

Property, Plant and Equipment for FERC Regulated Assets

        Depreciation is generally computed over the asset's estimated useful life using the straight-line method. The composite weighted-average depreciation rates were 4% for 2009. When the Partnership retires its regulated property, plant and equipment, it charges the original cost plus the cost of retirement, less salvage value, to accumulated depreciation and amortization.

Allowance for Funds Used During Construction

        Allowance for funds used during construction ("AFUDC"), which represents the estimated debt and equity costs of capital funds necessary to finance the construction and expansion of regulated facilities, consists of an equity component and an interest expense component. The equity component is a non-cash item. AFUDC is capitalized as a component of Property, plant and equipment, with offsetting credits to the Consolidated Statements of Operations included in Miscellaneous income (expense), net for the equity component and Interest expense for the interest component. After construction is completed, the Partnership is permitted to recover these costs through inclusion in the rate base and in the depreciation provision. The total amount of AFUDC included in the Consolidated Statements of Operations was $5.0 million for the year ended December 31, 2009 (an equity component of $2.8 million and an interest expense component of $2.2 million). If the Partnership discontinued the application of GAAP related to regulated enterprises due to an increased level of competition and discounting in its market area, the Partnership would be required to write-off a portion of the recorded AFUDC.

Accounting for Sales of Real Estate

        The Partnership evaluates transactions involving the sale of assets to determine if they are, in-substance, the sale of real estate. Tangible assets may be considered real estate if the costs to

94

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

relocate them for use in a different location exceeds 10% of the asset's fair value. Financial assets, primarily in the form of ownership interests in an entity, may be in-substance real estate based on the significance of the real estate in the entity. Sales of real estate are not considered consummated if the Partnership maintains an interest in the asset after it is sold, or has certain other forms of continuing involvement. Significant judgment is required to determine if a transaction is a sale of real estate and if a transaction has been consummated. If a sale of real estate is not considered consummated, the Partnership cannot record the transaction as a sale and must account for the transaction under an alternative method of accounting such as a financing or leasing arrangement. During 2009, the Partnership entered into two transactions which were accounted for under the real estate guidance. The sale of the steam methane reformer ("SMR Transaction") was not considered a sale of real estate due to the Partnership's continuing involvement, and was accounted for as a financing arrangement. The Partnership's sale of equity interest in MarkWest Pioneer was considered the sale of in-substance real estate. See Notes 6 and 4, respectively, for a description of each transaction and its impact on the financial statements.

Investment in Unconsolidated Affiliates

        Equity investments in which the Partnership exercises significant influence, but does not control and is not the primary beneficiary, are accounted for using the equity method, and are reported in Investment in unconsolidated affiliates in the accompanying Consolidated Balance Sheets. Refer to Note 16 for further discussion of the Partnership's equity investments.

        The Partnership believes the equity method is an appropriate means for it to recognize increases or decreases measured by GAAP in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. It uses the following types of evidence of a loss in value to identify a loss in value of an investment that is other than a temporary decline. Examples of an other-than-temporary loss in value may be identified by:

•

The potential inability to recover the carrying amount of the investment;

•

The estimated fair value of an investment that is less than its carrying amount. Factors considered include the length of time in which the market has been less than cost and the intent and ability to retain the investment to sufficiently allow for any recovery; and

•

Other operational or external factors including economic trends and projected financial performance that cause management to believe the investment may be worth less than otherwise accounted for by using the equity method.

Intangible Assets

        The Partnership's intangible assets are comprised of customer contracts and relationships acquired in business combinations, recorded under the purchase method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets. Fair value is generally calculated as the present value of estimated future cash flows using a risk-adjusted discount rate. The key assumptions include probability of contract renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, pricing volatility, and the discount rate. Amortization of

95

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. The estimated economic life is determined by assessing the life of the assets to which the contracts and relationships relate, likelihood of renewals, the projected reserves, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

Goodwill

        Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Partnership evaluates goodwill for impairment annually as of November 30, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Impairment testing of goodwill consists of a two-step process. The first step involves comparing the fair value of the reporting unit, to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss.

Impairment of Long-Lived Assets

        The Partnership's policy is to evaluate whether there has been a permanent impairment in the value of long-lived assets when certain events indicate that the remaining balance may not be recoverable. The Partnership evaluates the carrying value of its property, plant and equipment on at least a segment level and at lower levels where the cash flows for specific assets can be identified and are largely independent from other asset groups. A long-lived asset group is considered impaired when the estimated undiscounted cash flows from such asset group are less than the asset group's carrying value. In that event, a loss is recognized to the extent that the carrying value exceeds the fair value of the long-lived asset group. Fair value is determined primarily using estimated discounted cash flows. Management considers the volume of reserves behind the asset and future NGL product and natural gas prices to estimate cash flows. The amount of additional reserves developed by future drilling activity depends, in part, on expected natural gas prices. Projections of reserves, drilling activity and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Any significant variance in any of these assumptions or factors could materially affect future cash flows, which could result in the impairment of an asset.

        For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value, less the cost to sell, to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is re-determined when related events or circumstances change.

Deferred Financing Costs

        Deferred financing costs are amortized over the estimated lives of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced, using the effective interest method.

96

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

Deferred Contract Costs

        A wholly-owned subsidiary of the Partnership entered into a series of agreements with a gas producer in September 2004, under which the Partnership processes natural gas under modified keep-whole arrangements. In connection with these agreements, the subsidiary paid $3.3 million of consideration to the producer in connection with these non-separable contracts, which are being amortized as additional cost of the gas purchased over the term of the contracts, October 1, 2004 through February 9, 2015. Amortization related to these contracts for the years ended December 31, 2009, 2008 and 2007 was $0.3 million for each year.

Deferred Income

        Deferred income represents prepayments received in revenue generating contracts. In certain cases, the Partnership received prepayments under fixed fee contracts to deliver NGLs at a future date. Deferred income is recognized as revenue upon delivery of the product. In other cases, the Partnership received prepayments related to the construction of gathering facilities to transport the producer's gas from certain delivery points. Deferred income is generally recognized into revenue over the term of the gathering contract. Deferred income is reported in Accrued liabilities and Other long-term liabilities in the accompanying Consolidated Balance Sheets.

Derivative Instruments

        Derivative instruments (including certain derivative instruments embedded in other contracts) are recorded at fair value and included in the consolidated balance sheet as assets or liabilities. The Partnership discloses the fair value of substantially all of its derivative instruments separate from other assets and liabilities under the caption Fair value of derivative instruments in the Consolidated Balance Sheet, inclusive of option premiums (net of amortization). The fair value of derivatives related to long-term debt is included as a component of Long-term debt in the Consolidated Balance Sheet.

        Changes in the fair value of derivative instruments are reported in the Statement of Operations in accounts related to the item economically hedged. During 2009, substantially all derivative instruments were marked to market through Revenue, Purchased product costs, Facility expenses, Interest expense, or Miscellaneous income (expense), net. Revenue gains and losses relate to contracts utilized to hedge the cash flow for the sale of a product and the amortization of associated option premiums. Option premiums are amortized over the effective term of the corresponding option contract. Purchased product costs gains and losses relate to contracts utilized to hedge costs, typically in a keep-whole arrangement. Facility expenses gains and losses relate to a contract utilized to hedge electricity costs. Interest expense gains relate to contracts to manage the interest rate risk associated with the fair value of its fixed rate borrowings. Miscellaneous income (expense), net relate to changes in the fair value of certain embedded put options (see Notes 7 and 19). Changes in risk management activities are reported in cash flow from operating activities on the accompanying Consolidated Statements of Cash Flows.

        During 2009 and 2008 the Partnership did not designate any hedges or designate any contracts as normal purchases and normal sales. During 2007, the Partnership did not designate any hedges but did designate certain contracts as normal purchases and normal sales.

97

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

Fair Value of Financial Instruments

        Management believes the carrying amount of financial instruments, including cash, accounts receivable, accounts payable, and accrued expenses approximates fair value because of the short-term maturity of these instruments. Management believes the carrying amount of the SMR Liability approximates fair value because there has not been a significant change in interest rates since the liability was established in September 2009 (see Note 6). The recorded value of the amounts outstanding under the Partnership's Credit Agreement approximate fair value due to the variable interest rate that reflects current market conditions. Derivative instruments are recorded at fair value, based on available market information (see Note 7). The following table shows the carrying value and related fair value of financial instruments that are not recorded in the financial statements at fair value as of December 31, 2009 (amounts in millions).

	Carrying Value		Fair Value
Long-term debt	$	1,170	$	1,212
SMR Liability		95		95
Total	$	1,265	$	1,307

Fair Value Measurement

        The Partnership adopted guidance related to fair value measurements, effective January 1, 2008, with portions deferred by the FASB as discussed in Recent Accounting Pronouncements. The guidance defines fair value, establishes a framework for measuring fair value, establishes a three-level valuation hierarchy, and expands the disclosures about fair value measurements.

        The valuation hierarchy is based upon the transparency of inputs to the valuation of an asset or liability as of the measurement date. The three levels are defined as follows:

•

Level 1—inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•

Level 2—inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

•

Level 3—inputs to the valuation methodology are unobservable and significant to the fair value measurement.

        A financial instrument's categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement.

        The determination to classify a financial instrument with Level 3 of the valuation hierarchy is based upon the significance of the unobservable inputs to the overall fair value measurement. However, Level 3 financial instruments typically include, in addition to the unobservable or Level 3 inputs, observable inputs (that is, inputs that are actively quoted and can be validated to external sources); accordingly, the gains and losses for Level 3 financial instruments include changes in fair value due in part to observable inputs that are part of the valuation methodology. Level 3 financial instruments include interest rate swaps, crude oil options, all NGL transactions and the embedded put options

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2. Summary of Significant Accounting Policies (Continued)

discussed in Notes 7 and 19, as they have significant unobservable inputs. Depending on the Level 3 financial instrument, significant unobservable inputs include volatilities associated with option contracts, commodity prices interpolated and extrapolated due to inactive markets, the embedded put options incorporate assumptions about the probability of specific events occurring in the future.

        The methods described above may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Partnership believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. For further discussion see Note 8.

Revenue Recognition

        The Partnership generates the majority of its revenues from natural gas gathering, transportation and processing; NGL transportation, fractionation, marketing and storage; and crude oil gathering and transportation. It enters into a variety of contract types. In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described below. The Partnership provides services under the following different types of arrangements:

•

Fee-based arrangements—Under fee-based arrangements, the Partnership receives 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 the Partnership earns from these arrangements is generally directly related to the volume of natural gas, NGLs or crude oil that flows through the Partnership's systems and facilities and is not directly dependent on commodity prices. In certain cases, the Partnership's arrangements provide for minimum annual payments, fixed demand charges, or fixed returns on gathering system expenditures.

•

Percent-of-proceeds arrangements—Under percent-of-proceeds arrangements, the Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices and remits to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, the Partnership will deliver an agreed-upon percentage of the residue gas and NGLs to the producer and sell the volumes the Partnership keeps to third parties at market prices.

•

Percent-of-index arrangements—Under percent-of-index arrangements, the Partnership will 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. The Partnership will then gather and deliver the natural gas to pipelines where the Partnership will resell the natural gas at the index price, or at a different percentage discount to the index price.

•

Keep-whole arrangements—Under keep-whole arrangements, the Partnership gathers natural gas from the producer, processes the natural gas and sells 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, the Partnership 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

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2. Summary of Significant Accounting Policies (Continued)

also have provisions that require the Partnership to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio or the NGL to gas ratio.

•

Settlement margin—Typically, the Partnership is allowed to retain a fixed percentage of the volume gathered to cover the compression fuel charges and deemed-line losses. To the extent the Partnership's gathering systems are operated more or less efficiently than specified per contract allowance, the Partnership is entitled to retain the benefit or loss for its own account.

        In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of the Partnership's contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements. Under all of the arrangements, revenue is recognized at the time the product is delivered and title is transferred. It is upon delivery and title transfer that the Partnership meets all four revenue recognition criteria, and it is at such time that the Partnership recognizes revenue.

        The Partnership's assessment of each of the four revenue recognition criteria as they relate to its revenue producing activities is as follows:

        Persuasive evidence of an arrangement exists.    The Partnership's customary practice is to enter into a written contract, executed by both the customer and the Partnership.

        Delivery.    Delivery is deemed to have occurred at the time the product is delivered and title is transferred, or in the case of fee-based arrangements, when the services are rendered.

        The fee is fixed or determinable.    The Partnership negotiates the fee for its services at the outset of its fee-based arrangements. In these arrangements, the fees are nonrefundable. The fees are generally due within ten days of delivery or services rendered. For other arrangements, the amount of revenue is determinable when the sale of the applicable product has been completed upon delivery and transfer of title. Proceeds from the sale of products are generally due in ten days.

        Collectibility is reasonably assured.    Collectibility is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates the customers' financial position (e.g. cash position and credit rating) and their ability to pay. If collectibility is not considered reasonably assured at the outset of an arrangement in accordance with the Partnership's credit review process, revenue is recognized when the fee is collected.

        The Partnership enters into revenue arrangements where it sells customer's gas and/or NGLs and depending on the nature of the arrangement acts as the principal or agent. Revenue from such sales is recognized gross where the Partnership acts as the Principal, as the Partnership takes title to the gas and/or NGLs, has physical inventory risk and does not earn a fixed amount. Revenue is recognized net when the Partnership earns a fixed amount and does not take ownership of the gas and/or NGLs.

        Amounts billed to customers for shipping and handling are included in Revenue. Shipping and handling costs associated with product sales are included in operating expenses. Taxes collected from customers and remitted to the appropriate taxing authority are excluded from revenue.

        Gas volumes received may be different from gas volumes delivered, resulting in gas imbalances. The Partnership records a receivable or payable for such imbalances based upon the contractual terms of the purchase agreements. The Partnership had an imbalance payable of $0.7 million and $0.2 million

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2. Summary of Significant Accounting Policies (Continued)

at December 31, 2009 and 2008, recorded in Accrued liabilities in the accompanying Consolidated Balance Sheets. The Partnership had an imbalance receivable of $0.3 million and $0.9 million at December 31, 2009 and 2008, respectively, recorded in Receivables, net in the accompanying Consolidated Balance Sheets. Changes in gas imbalances are recognized in Revenue or Purchased product costs in the accompanying Consolidated Statements of Operations.

Revenue and Expense Accruals

        The Partnership routinely makes accruals based on estimates for both revenues and expenses due to the timing of compiling billing information, receiving certain third party information and reconciling the Partnership's records with those of third parties. The delayed information from third parties includes, among other things, actual volumes purchased, transported or sold, adjustments to inventory and invoices for purchases, actual natural gas and NGL deliveries and other operating expenses. The Partnership makes accruals to reflect estimates for these items based on its internal records and information from third parties. Estimated accruals are reversed in the following month when actual information is received from third parties and the Partnership's internal records have been reconciled.

Incentive Compensation Plans

        The Partnership issues phantom units under certain share-based compensation plans as described further in Note 22. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. The phantom units are treated as equity awards. Compensation expense is measured for the phantom unit grants using the market price of MarkWest Energy Partners' common units on the date the units are granted. The fair value of the units awarded is amortized into earnings, reduced for an estimate of expected forfeitures, over the period of service corresponding with the vesting period. For certain plans the awards are accounted for as liability awards and the compensation expense is adjusted monthly for the change in the fair value of the unvested units granted.

        To satisfy common unit awards, the Partnership may issue new common units, acquire common units in the open market, or use common units already owned by the general partner.

Participation Plan

        The interests in the Partnership's General Partner sold by the Corporation to certain directors and employees were referred to as the Participation Plan. The Participation Plan was considered a compensatory arrangement and the General Partner interests were classified as liability awards. As a result, the Corporation was required to calculate the fair value of the General Partner interests at the end of each period. In conjunction with the Merger, all of the outstanding interests in the General Partner were acquired and the Participation Plan was terminated. Refer to Note 22 for further discussion of the impact of the Participation Plan on the financial statements.

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2. Summary of Significant Accounting Policies (Continued)

Income Taxes

        The Partnership is not a taxable entity for federal income tax purposes. As such, the Partnership does not directly pay federal income tax. The Partnership's taxable income or loss, which may vary substantially from the net income or loss reported in the Consolidated Statements of Operations, is includable in the federal income tax returns of each partner. The Partnership is, however, a taxable entity under certain state jurisdictions. The Corporation is a tax paying entity for both federal and state purposes.

        The Partnership and the Corporation account for income taxes under the asset and liability method. Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, capital loss carryforwards and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates applied to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to reflect the deferred tax assets at net realizable value as determined by management. Deferred tax balances that are expected to be settled within twelve months are classified as current, and all other deferred tax balance are classified as long term in the accompanying Consolidated Balance Sheets.

        The Corporation recognizes a tax expense or a tax benefit on its proportionate share of Partnership income or loss resulting from the Corporation's ownership of Class A units of the Partnership even though for financial reporting purposes said income or loss is eliminated in consolidation. The deferred income tax component relates to the change in the book to tax basis difference in the carrying amount of the investment in the Partnership which results primarily from its timing differences in the Corporation's proportionate share of the book income or loss as compared with the Corporation's proportionate share of the taxable income or loss of the Partnership.

        To account for uncertainty in income taxes recognized in financial statements, the Partnership prescribes a "more likely than not" recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The Partnership records penalties and interest related to income taxes as a component of income before tax as they become applicable. Penalties are recorded in Miscellaneous income (expense), net and interest is recorded in Interest expense in the accompanying Consolidated Statements of Operations.

Comprehensive Income (Loss)

        Comprehensive income (loss) includes net income and other comprehensive income (loss), which includes unrealized gains and losses on marketable securities that are classified as available for sale.

Earnings (Loss) Per Unit

        The Partnership's outstanding phantom units are considered to be participating securities, and therefore basic and diluted earnings per common unit are calculated pursuant to the two-class method described in the generally accepted accounting principles for earnings per share. In accordance with the two-class method, basic earnings per common unit is calculated by dividing net income attributable to

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2. Summary of Significant Accounting Policies (Continued)

the Partnership, after deducting amounts that are allocable to the outstanding phantom units, by the weighted-average number of common units outstanding during the period. The amount allocable to the phantom units is generally calculated as if all of the net income attributable to the Partnership were distributed, and not on the basis of actual cash distributions for the period. However, during periods in which a net loss attributable to the Partnership is reported or periods in which the total distributions exceed the reported net income attributable to the Partnership, the amount allocable to the phantom units is based on actual distributions to the phantom unit holders. Diluted earnings per unit is calculated by dividing net income attributable to the Partnership, after deducting amounts allocable to the outstanding phantom units, by the weighted-average number of potential common units outstanding during the period. Potential common units are excluded from the calculation of diluted earnings per unit during periods in which the Partnership incurs a net loss as the impact would be anti-dilutive.

Business Combinations

        Transactions in which the Partnership acquires control of a business are accounted for under the acquisition method. The identifiable assets, liabilities and any non-controlling interests are recorded at the estimated fair market values as of the acquisition date. The purchase price in excess of the fair value acquired is recorded as goodwill.

Accounting for Changes in Ownership Interests in Subsidiaries

        The Partnership's ownership interest in a consolidated subsidiary may change if it sells a portion of its interest, or if the subsidiary issues or re-purchases its own shares. If the transaction does not result in a change in control over the subsidiary and it is not deemed to be a sale of real estate, the transaction is accounted for as an equity transaction. If the transaction results in a change in control it would result in the deconsolidation of a subsidiary with a gain or loss recognized in the statement of operations. During 2009 the Partnership's ownership interest in Liberty Midstream changed in two separate transactions which were accounted for as equity transactions. See Note 4 for a description of the transactions and the impact to the financial statements.

Accounting for Sales of Stock by a Subsidiary

        Prior to the Merger, the Partnership issued common units in various transactions, which resulted in a dilution of the Corporation's percentage ownership in the Partnership. The Corporation accounted for the sale of the Partnership common units in accordance with guidance related to equity transactions. The guidance allows for the election of an accounting policy of recording such increase or decreases in a parent's investment either in income or in equity. The Corporation adopted a policy of recording such gains or losses directly to additional paid in capital. Due to the preference nature of the Partnership's common units, the Corporation was precluded from recording gains or losses until the subordinated units converted to common units. On August 15, 2007, the Partnership converted its remaining 1.2 million subordinated units to common units, in accordance with the provisions of the amended and restated partnership agreement. As a result, the Corporation recorded a $52.3 million gain to additional paid in capital, a decrease in non-controlling interest in consolidated subsidiary of $83.8 million and an increase to deferred tax liability of $31.5 million associated with gains from sales of common units by the Partnership in conjunction with, and subsequent to, the Partnership's May 24, 2002 initial public offering.

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2. Summary of Significant Accounting Policies (Continued)

Recent Accounting Pronouncements

        In September 2006, the FASB issued guidance regarding fair value measurements which was effective for the Partnership's financial statements as of January 1, 2008, except for certain provisions relating to non-financial assets and liabilities, which were effective January 1, 2009. The adoption as of January 1, 2008 had an effect of a $1.1 million decrease to fair value of derivative instruments liability, a decrease to Revenue—derivative loss of $0.4 million and an increase to derivative gain related to purchase product costs of $0.7 million. The provisions adopted as of January 1, 2009 did not have a material impact on the Partnership's financial statements.

        In December 2007, the FASB amended the guidance related to business combinations. The amended guidance provides for how the acquirer recognizes and measures the identifiable assets acquired, liabilities assumed any non-controlling interest in the acquiree. It also provides for how the acquirer recognizes and measures the goodwill acquired in the business combination or a gain from a bargain purchase and determines what information to disclose to enable users to evaluate the nature and financial effects of the business combination. The provisions of the amended guidance became effective for the Partnership as of January 1, 2009. The guidance did not affect business combinations completed prior to January 1, 2009.

        In December 2007, the FASB amended the guidance related to non-controlling interests in consolidated financial statements. This amended guidance provides that non-controlling interests in subsidiaries held by parties other than the parent be identified, labeled and presented in the statement of financial position within equity, but separate from the parent's equity. It also states that the amount of consolidated net income attributable to the parent and to the non-controlling interest be clearly identified on the consolidated statement of income and provides for consistency regarding changes in parent ownership including when a subsidiary is deconsolidated. Any retained non-controlling equity investment in the former subsidiary will be initially measured at fair value. Certain provisions of the amended guidance became effective for the Partnership as of January 1, 2009. The Partnership's financial statements were retrospectively adjusted for the presentation and disclosure requirements of the amended guidance.

        In April 2008, the FASB issued amended guidance related to the determination of the useful life of intangible assets. The guidance amends the factors that an entity should consider in developing renewal or extension assumptions used in determining the useful life of recognized intangible assets. In determining the useful life of an acquired intangible asset, an entity is no longer required to consider whether renewal of the intangible asset requires significant costs or material modifications to the related arrangement. The amended guidance also replaces the previous useful life assessment criteria with a requirement that an entity consider its own experience in renewing similar arrangements. If the entity has no relevant experience, it would consider market participant assumptions regarding renewal. The amended guidance became effective as of January 1, 2009 and applied only to intangible assets acquired after that date. Retroactive application to previously acquired intangible assets is prohibited. There will be no impact on the Partnership's financial statements unless the Partnership acquires intangible assets in the future.

        In June 2008, the FASB issued updated earnings per share guidance regarding determining whether instruments granted in share-based payment transactions are participating securities. The amended guidance states that unvested share-based payment awards that contain non-forfeitable rights to dividends or dividend equivalents (whether paid or unpaid) are participating securities and shall be

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2. Summary of Significant Accounting Policies (Continued)

included in the computation of earnings per unit pursuant to the two-class method. The amended guidance became effective for the Partnership beginning January 1, 2009. The adoption of the guidance did not have an impact on the net income reported in the Partnership's Consolidated Statements of Operations, however the reported earnings per unit is generally lower than the amount reported prior to adoption. The effect of the guidance is reflected for all years presented in the Partnership's Consolidated Statements of Operations.

        In November 2008, the FASB clarified the accounting for certain transactions and impairment considerations involving equity method investments which were affected by the FASB issuances of updated guidance related to business combinations and consolidations. The transition provisions require prospective application and are effective for the Partnership on January 1, 2009. The clarification did not have a material effect on the Partnership's consolidated financial statements.

        In May 2009, the FASB established guidance for the accounting and reporting of subsequent events, which are events occurring after the balance sheet date but before the financial statements are issued or available to be issued. The new principles describe the circumstances that would require the Partnership to recognize the impact of subsequent events in its financial statements, provides disclosure requirements for subsequent events, and defines the period through which subsequent events must be evaluated. The guidance became effective for the Partnership as of the period ended June 30, 2009, and did not have a material impact on the Partnership's financial statements upon adoption.

        In June 2009, the FASB amended the Variable Interest Entity ("VIE") subsections of the consolidation guidance. The amended guidance changes the criteria for determining if a VIE exists and whether or not a VIE should be consolidated. When this guidance is adopted, the Partnership must reconsider its previous VIE conclusions and what types of financial statement disclosures are appropriate. The amended guidance is effective for the Partnership on January 1, 2010. The amendment will not have a material effect on the Partnership's consolidated financial statements.

        In September 2009, the FASB amended the accounting guidance for revenue recognition for multiple-deliverable arrangements. The amended guidance establishes a hierarchy for determining the selling price of each individual deliverable and eliminates the residual value method of allocating the selling price. The amended guidance is effective prospectively for all revenue arrangements entered into or materially modified in fiscal years beginning after June 15, 2010. The amendment is not expected to have a material effect on the Partnership's consolidated financial statements.

        In January 2010, the FASB issued a clarification to the accounting for decreases in ownership interests in certain subsidiaries. The FASB clarified that the guidance for consolidations does not apply to transactions involving in-substance real estate or the conveyances of oil and gas mineral rights. The FASB indicated that the established guidance for transactions involving in-substance real estate or oil and gas mineral rights should be followed. The clarification also expands disclosures required upon the deconsolidation of a subsidiary. The guidance within this clarification is effective for the Partnership as of December 31, 2009, with retrospective application required to January 1, 2009. The Partnership has determined that its sale of equity interests in MarkWest Pioneer qualifies as a sale of in-substance real estate; however, the impact on the Partnership's consolidated financial statements was not material.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Redemption and Merger

        On February 21, 2008, the Partnership completed the transactions contemplated by its plan of redemption and merger with the Corporation and MWEP, L.L.C., a wholly-owned subsidiary of the Partnership. Under the Merger, the shareholders of the Corporation exchanged each share of Corporation common stock for consideration equal to 1.9051 Partnership common units. This Exchange Ratio was computed based on the stated consideration of 1.285 Partnership common units plus $20 in cash, or equivalent value. In accordance with the merger agreement, the equivalent value was based on a Partnership common unit price of $32.25, which equals the average market price of Partnership common units for the ten day period ending three days prior to the closing date. Therefore, the $20.00 in cash was equivalent to 0.6201 Partnership common units which results in a total Exchange Ratio of 1.9051 when combined with the other 1.285 units included in the stated consideration. Subject to proration, the shareholders elected to receive this consideration either entirely in cash in the redemption, entirely in Partnership common units in the Merger, or in any combination of cash and Partnership common units with equivalent value. The Corporation redeemed for $240.5 million in cash those shares of Corporation common stock electing to receive cash. Immediately after the redemption, the Partnership acquired the Corporation through a merger of MWEP, L.L.C. with and into the Corporation, pursuant to which all remaining shares of the Corporation's common stock were converted into approximately 15.5 million Partnership common units. As a result of the Merger, the Corporation is a wholly-owned subsidiary of the Partnership. In connection with the Merger, the incentive distribution rights in the Partnership, the 2% economic interest in the Partnership held by MarkWest Energy GP, L.L.C. (the "General Partner") and the Partnership common units owned by the Corporation were exchanged for Partnership Class A units. Contemporaneously with the closing of the transactions contemplated by the Merger, the Partnership separately acquired 100% of the Class B membership interests in the General Partner that had been held by current and former management and certain directors of the Corporation and the General Partner under the Participation Plan in exchange for approximately $21.5 million in cash and approximately 0.9 million common units valued at $30.1 million. Additionally, as a result of the Merger, the Partnership assumed the 2006 Hydrocarbon Stock Incentive Plan and the 1996 Hydrocarbon Stock Incentive Plan (see Note 22).

        Using the Exchange Ratio, the number of Corporation shares outstanding as of December 31, 2007 and activity through February 21, 2008 has been adjusted to the equivalent number of Partnership common units in the accompanying Consolidated Financial Statements. The following table illustrates these conversions (shares and units in thousands):

	Common Shares			Exchange Ratio		Common Units
Shares of Corporation Common Stock Outstanding at December 31, 2007		11,999.8			1.9051		22,861
Stock Option exercises in first quarter 2008, prior to Merger		51.5			1.9051		98
Conversion of Restricted Shares to Partnership Phantom units		(23.8	)		1.9051		(45	)
Shares eligible for redemption or conversion to Partnership Units		12,027.5					22,914
Common shares tendered for redemption in cash		(3,914.5	)		1.9051		(7,458	)
Common shares tendered for conversion to Partnership common units		8,113.0			1.9051		15,456

        Class A units represent limited partner interests in the Partnership and have identical rights and obligations of the Partnership common units except that Class A units (a) do not have the right to vote

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3. Redemption and Merger (Continued)

on, approve or disapprove, or otherwise consent to or not consent to any matter (including mergers, share exchanges and similar statutory authorizations) except as otherwise required by any non-waivable provision of law and (b) do not share in any cash and cash equivalents on hand, income, gains, losses, deductions and credits that are derived from or attributable to the Partnership's ownership of, or sale or disposition of, the shares of MarkWest Hydrocarbon common stock. The Class A units held by the Corporation and the General Partner are not treated as outstanding common units in the Consolidated Balance Sheets.

        The total fair value of the non-controlling interest acquired was the number of non-controlling interest units outstanding on the date the Merger closed valued at the then current per unit market price of the Partnership common units of $31.79. The following table shows the calculation of the purchase price of the Partnership ($ in thousands):

	Units		Dollars
Fair value of units held prior to Merger		34,473,647	$	1,095,917
Add: Direct costs of the Merger				7,882
			$	1,103,799

        Significant fair value estimates were required for the following assets and liabilities:

•

Property, plant, and equipment—The fair value estimates for property, plant and equipment were based primarily on the cost approach, which considers both historical cost and replacement cost. Additionally, management estimated the remaining useful lives of the property, plant and equipment to ensure that the useful lives used for depreciation subsequent to the Merger are reasonable and consistent with the Partnership's accounting policy.

•

Intangible assets—The fair value estimates for customer relationships were based on a version of the income approach. The income approach involves estimating future cash flows from existing customer relationships and making provisions for a fair return on other recognized contributory assets. Key assumptions in the valuation include contract renewals, economic incentives to retain customers, historic volumes, current and future capacity in the gathering system, pricing volatility and the discount rate. The estimated useful life of the intangible assets was determined by assessing the estimated useful life of the other assets to which the contracts and relationships relate, likelihood of renewals, projected reserves, competitive factors, regulatory or legal provisions, and maintenance and renewal costs.

•

Long-term debt—The fair value of the Partnership's Senior Notes was estimated using a high yield market price at which the debt was trading as of the date the Merger closed.

•

Deferred finance costs—The deferred finance costs of the Partnership had no fair market value as of the date the Merger closed. Therefore 85.7% of these costs, which is the percentage subject to revaluation under the purchase accounting method, were written-off.

•

The remaining purchase price in excess of the fair values of the assets and liabilities acquired was recorded as goodwill. The goodwill balance was then allocated to the Partnership's reporting units. The Partnership had eight reporting units: East Texas, Eastern Oklahoma, Western Oklahoma, Other Southwest, Javelina, Appalachia, Western Michigan, and Michigan Crude Pipeline. Goodwill was allocated to those reporting units that are expected to benefit from the

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3. Redemption and Merger (Continued)

business combination. One of the primary benefits of the Merger was to allow the Partnership to compete more effectively for future growth opportunities. Because there were no significant growth plans in place for Western Michigan and Michigan Crude Pipeline, no goodwill was allocated to these reporting units. For all other reporting units, goodwill was allocated in a manner consistent with the methodology used to determine total goodwill. Management estimated the fair value of the net assets of reporting unit, allocated a portion of the Merger purchase price to each reporting unit, and assigned goodwill to the extent that the allocated purchase price exceeded the fair value of the reporting unit. The methodology used to determine the fair value of the net assets of each reporting unit and the allocated purchase price to each reporting unit was applied consistently.

        The following table shows the final purchase price allocation as of February 21, 2008 (in thousands):

	Original Net Book Value			Fair Value			85.7% Proportional Step-Up of Fair Value			Average Depreciable Life
Property, plant and equipment	$	843,122		$	1,051,407		$	178,501			18
Intangible assets		324,326			780,343			390,807			18
Long-term debt		(581,642	)		(570,775	)		9,313			8
Deferred financing costs		12,815			—			(10,982	)		8
Goodwill								37,461
Total Adjustments								605,100
Deferred income taxes		n/a			n/a			(3,598	)
Non-controlling interest								502,297
Total Purchase Price							$	1,103,799

n/a—

Amounts represent the recognition of deferred tax liabilities related to temporary tax differences that are expected to reverse in future periods related to the proportional step-up of fair value due to the Merger. No deferred tax liabilities related to goodwill were recognized as goodwill is not deductible for tax purposes.

4. Variable Interest Entities

MarkWest Liberty Midstream

        On February 27, 2009, the Partnership entered into a joint venture with M&R MWE Liberty LLC ("M&R"), an affiliate of NGP Midstream & Resources, L.P. and its affiliated funds, which is a private equity firm focused on investments in selected areas of the energy infrastructure and natural resources sectors. The joint venture entity, MarkWest Liberty Midstream, operates in the natural gas midstream business in and around the Marcellus Shale in western Pennsylvania and northern West Virginia. The Partnership contributed its existing Marcellus Shale natural gas gathering and processing assets to MarkWest Liberty Midstream in exchange for a 60% ownership interest. The agreed-to value of the contributed assets was approximately $107.5 million. At closing, M&R contributed cash of $50.0 million in exchange for a 40% ownership interest. A wholly-owned subsidiary of the Partnership serves as the

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4. Variable Interest Entities (Continued)

operator of MarkWest Liberty Midstream and provides field operating and general and administrative services. A portion of the fee for providing these services is fixed.

        The Partnership has determined that MarkWest Liberty Midstream is a variable interest entity primarily due to the insufficiency of equity, as defined in generally accepted accounting principles for consolidation, at its inception as evidenced by the capital requirements outlined below. The Partnership is considered the primary beneficiary due mainly to its disproportionate share of profits and losses relative to the equal voting rights shared by both members. The Partnership assumes additional variability based on its compensation as the operator of MarkWest Liberty Midstream. The Partnership's maximum exposure to loss as a result of its involvement with MarkWest Liberty Midstream includes its equity investment, the additional capital contribution commitments and any operating expense in excess of its compensation as the operator of MarkWest Liberty Midstream. MarkWest Liberty Midstream will be funded entirely by the Partnership and M&R and has no debt.

        M&R contributed an additional $150.0 million during 2009 to fund the capital expenditures of MarkWest Liberty Midstream. MarkWest Liberty Midstream's capital expenditures exceed M&R's quarterly contributions during 2009. As a result, the Partnership contributed approximately $8.0 million to the entity during 2009. As M&R contributed the majority of capital associated with 2009 capital expenditures, the capital contributed to MarkWest Liberty Midstream is disproportionate to each party's respective ownership interest. Under the terms of the joint venture agreement, M&R received a special $3.4 million non-cash allocation of net income from MarkWest Liberty Midstream during 2009 because its capital contributed exceeded its ownership interest. The non-cash allocation is recorded in Net (income) loss attributable to non-controlling interest.

        Effective November 1, 2009, the Partnership and M&R executed the Amended Liberty Agreement pursuant to which M&R will increase its participation in MarkWest Liberty Midstream by at least an additional $150.0 million. Additionally, the Partnership and M&R will maintain a 60%/40% respective ownership interest in MarkWest Liberty Midstream until January 1, 2011, at which time M&R's ownership interest will increase from 40% to 49%. The Partnership and M&R will jointly fund the capital requirements of MarkWest Liberty Midstream at agreed upon levels until the Partnership's contributed capital is proportionate to its 51% ownership interest (the "Equalization Date"), which is expected to occur on or before December 31, 2012. MarkWest Liberty Midstream's capital plan for 2011 and 2012 has not been finalized and the exact timing of the member's contributions is currently uncertain. If the Equalization Date has not occurred by the end of 2012, M&R may require the Partnership to contribute the amount of the shortfall at December 31, 2012, or may allow the Partnership to continue to fund 100% of MarkWest Liberty Midstream's capital expenditures until its total contributed capital is proportionate to its ownership interest. Following the Equalization Date, M&R will have pre-emptive rights to maintain its ownership interest in MarkWest Liberty Midstream in a range of between 45% and 49% or have its ownership interest diluted to the extent that it elects not to fund its proportionate share. As a result of the execution of the Amended Liberty Agreement, the Partnership reconsidered the accounting treatment for MarkWest Liberty Midstream as a VIE and determined that the conclusions as discussed above remain unchanged.

MarkWest Pioneer

        MarkWest Pioneer is the owner and operator of the Arkoma Connector Pipeline, a 50-mile FERC regulated pipeline that was placed in service in July 2009 and provides approximately 638,000 Dth/d of

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4. Variable Interest Entities (Continued)

Woodford Shale takeaway capacity and interconnects with the Midcontinent Express Pipeline and the Gulf Crossing Pipeline.

        On May 1, 2009, the Partnership entered into a joint venture with Arkoma Pipeline Partners, LLC ("ArcLight"), an affiliate of ArcLight Capital Partners, LLC which is an investment firm focused on opportunities throughout the energy industry. ArcLight acquired a 50% equity interest in MarkWest Pioneer for a total purchase price of $62.5 million. The Partnership retained a 50% equity interest and was obligated to fund all capital expenditures necessary to complete construction of the Arkoma Connector Pipeline in excess of $125.0 million (the "Excess Capital Expenditures"). As a result of the Excess Capital Expenditures, the Partnership recorded a $10.3 million equity loss, net of a $1.5 million tax benefit, that is reflected as a transfer to non-controlling interest, and the Partnership's recorded ownership interest exceeds its stated ownership interest in MarkWest Pioneer by approximately $2.0 million. The difference between the Partnership's recorded ownership interest and its stated ownership interest is amortized based upon the respective useful lives of the assets to which the difference relates. A wholly-owned subsidiary of the Partnership serves as the operator of MarkWest Pioneer and provides field operating and general and administrative services for fixed fees.

        The Partnership has determined that MarkWest Pioneer is a VIE under generally accepted accounting principles for consolidation. This determination is based primarily on disproportionate economic interests as compared to voting interests. The Partnership has economic interests that do not match its 50% voting interest as it was obligated to fund the Excess Capital Expenditures.

Financial Statement Impact of VIEs

        As the primary beneficiary of MarkWest Liberty Midstream and MarkWest Pioneer, the Partnership consolidates the entities and recognizes non-controlling interests. The Partnership has not provided any financial support that it was not contractually obligated to provide. The Partnership

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Variable Interest Entities (Continued)

reflected the following amounts in its Consolidated Balance Sheet for MarkWest Liberty Midstream and MarkWest Pioneer (in thousands):

			As of December 31, 2009
			MarkWest Liberty Midstream		MarkWest Pioneer
ASSETS
	Cash and cash equivalents		$	18,168	$	3,774
	Accounts receivable			20,753		1,280
	Inventories			3,343		—
	Other current assets			225		102
	Property, plant and equipment, net of accumulated depreciation of $8,273 and $3,051, respectively			330,116		153,478
	Other long-term assets			314		—
		Total assets	$	372,919	$	158,634
LIABILITIES
	Accounts payable		$	2,713	$	32
	Accrued liabilities			43,136		1,479
	Other long-term liabilities			80		285
		Total liabilities	$	45,929	$	1,796

        The assets of MarkWest Liberty Midstream and MarkWest Pioneer are the property of the respective ventures and are not available to the Partnership for any other purpose, including collateral for its secured debt (see Note 19 and Note 27). The Partnership is required to reinvest all cash distributions from MarkWest Liberty Midstream until the Equalization Date has occurred. The liabilities of MarkWest Liberty Midstream and MarkWest Pioneer do not represent additional claims against the Partnership's general assets. The Partnership's Liberty segment includes the results of operations of MarkWest Liberty Midstream (see Note 26). The Partnership's Southwest segment includes the results of operations of MarkWest Pioneer (see Note 26). The cash flow information for MarkWest Liberty Midstream and MarkWest Pioneer comprise substantially all of the cash flow information of non-guarantors (see Note 27).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Variable Interest Entities (Continued)

        The following table shows the net loss attributable to the Partnership and transfers to the non-controlling interests for the year ended December 31, 2009 (in thousands).

			Year Ended December 31, 2009
Net loss attributable to the Partnership			$	(118,668	)
	Transfers to the non-controlling interests:
		Decrease in Partners' Capital for transaction costs related to sale of equity interest in MarkWest Liberty Midstream and MarkWest Pioneer		(7,310	)
		Decrease to Partners' Capital for transfer to non-controlling interest from sale of equity interest in MarkWest Pioneer(1)		(10,288	)
Net loss attributable to the Partnership and transfers to the non-controlling interests			$	(136,266	)

(1)

Decrease to Partners' Capital for transfer to non-controlling interest is determined based on the amount of Excess Capital Expenditures as estimated on the closing date. As of December 31, 2009, the decrease is shown net of tax benefit.

5. Business Combination

        On July 31, 2008, the Partnership acquired a 100% interest in PQ Assets from PetroQuest Energy, L.L.C. for $41.3 million. PQ Assets consisted of gathering systems located in the Woodford Shale area of Southeast Oklahoma. The acquisition also included a 50% managing partner interest in Wirth Gathering, a general partnership, which also owns a gathering system located in the Woodford Shale area. PQ Assets was renamed MarkWest McAlester, L.L.C. The transaction was accounted for under the purchase method, the results of operations from the business combination are included in the consolidated financial statements from the acquisition date. The following table summarizes the costs and allocation of the PQ Assets acquired (in thousands):

Allocation of acquisition costs:
Property, plant and equipment		$	26,698
Customer contracts and relationships(1)			16,872
Goodwill(2)			665
Non-controlling interest			(2,935	)
	Total	$	41,300

(1)

Customer contracts and relationships will be amortized over a ten-year life.

(2)

Goodwill was recorded in the Southwest segment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Divestitures

SMR Transaction

        On September 1, 2009, the Partnership completed the sale of the steam methane reformer ("SMR") currently being constructed at its Javelina gas processing and fractionation facility in Corpus Christi, Texas. Under the terms of the agreement, the Partnership received proceeds of $73.1 million and the purchaser will complete the construction of the SMR. The Partnership and the purchaser also executed a related hydrogen supply agreement under which the Partnership will receive all of the hydrogen produced by the SMR for the next 20 years in exchange for processing fees and the reimbursement of certain other expenses. The processing fee payments will begin when the SMR is capable of commencing operations, which is expected to occur in March 2010. The Partnership is deemed to have continuing involvement with the SMR as a result of certain provisions in the related agreements. Therefore, the transaction is treated as a financing arrangement under GAAP. The Partnership has continued to report an asset, and the related depreciation, for the total capitalized costs of constructing the SMR and has recorded a liability equal to the proceeds from the transaction plus the costs expected to be incurred by the buyer to complete construction ("SMR Liability"). The Partnership will impute interest on the SMR Liability at 9.35% annually, its incremental borrowing rate at the time of the transaction. Until the SMR is capable of commencing operations and the Partnership begins payment of the processing fee under the hydrogen supply agreement, the accrued interest on the SMR Liability will be capitalized. Each processing fee payment will have multiple elements: reduction of principal of the SMR Liability, interest expense associated with the SMR Liability, and facility expense related to the operation of the SMR. As of December 31, 2009, the following amounts related to the SMR are included in the accompanying Consolidated Balance Sheets (in thousands):

ASSETS
	Property, plant and equipment, net of accumulated depreciation of $0	$	103,522
LIABILITIES
	Accrued liabilities	$	1,434
	Other long-term liabilities		93,776

Other Divestitures

        Effective November 1, 2009, the Partnership sold its interest in Basin Pipeline, LLC ("Basin") for nominal consideration. Basin owns a natural gas pipeline in Manistee, Mason and Oceana Counties in Michigan. The Partnership ceased its operations in western Michigan, including Basin, in July 2009. The Partnership's loss on the disposal of Basin was near zero.

        Effective December 31, 2009, the Partnership sold its 50% equity interest in Starfish Pipeline Company, LLC ("Starfish") to Enbridge Offshore (Gas Transmission), L.L.C. for a base purchase price of $25.0 million. The purchase price is subject to post-closing adjustments to net working capital, which takes into account the cost of repairs performed prior to closing from damage caused by Hurricane Ike in 2008. The Partnership recorded a $6.8 million gain on the sale of its equity interest in Starfish. The calculated gain on sale was impacted by the impairment of $41.4 million recorded in 2008 (see Note 16).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Derivative Financial Instruments

Commodity Instruments

        The Partnership's primary risk management objective is to reduce downside volatility in its cash flows arising from changes in commodity prices related to future sales or purchases of natural gas, NGLs and crude oil. Swaps, options and fixed-price forward contracts may allow the Partnership to reduce downside volatility in its realized margins as realized losses or gains on the derivative instruments generally are offset by corresponding gains or losses in the Partnership's sales or purchases of physical product. While management largely expects realized derivative gains and losses to be offset by increases or decreases in the value of physical sales and purchases, the Partnership will experience volatility in reported earnings due to the recording of unrealized gains and losses on derivative positions that will have no offset. The Partnership's commodity derivative instruments are recorded at fair value in the Consolidated Balance Sheets. Accordingly, the volatility in any given period related to unrealized gains or losses reported in the Consolidated Statements of Operations can be significant to the overall financial results of the Partnership; however, management generally expects those gains and losses to be offset when they become realized. The Partnership does not have any trading derivative financial instruments.

        To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas. As a result of these transactions, the Partnership has mitigated a significant portion of its expected commodity price risk with agreements expiring at various times through the fourth quarter of 2012. The Partnership has a committee comprised of the senior management team that oversees all of the risk management activity and continually monitors the risk management program and expects to continue to adjust its derivative positions as conditions warrant.

        To manage its commodity price risk, the Partnership utilizes a combination of swaps, options and fixed-price forward contracts available on the OTC market. The Partnership enters into OTC derivatives with financial institutions and other energy company counterparties. Management conducts a standard credit review on counterparties and has agreements containing collateral requirements when deemed necessary. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements). Due to the timing of purchases and sales, direct exposure to price volatility may result because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Through marketing and derivative activities, direct price exposure may occur naturally or the Partnership may choose direct exposure when it is favorable as compared to the keep-whole risk.

        The use of derivative instruments may create exposure to the risk of financial loss in certain circumstances, including instances when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected, requiring market purchases to meet commitments, or (iii) OTC counterparties fail to purchase or deliver the contracted quantities of natural gas, NGLs or crude oil or otherwise fail to perform. To the extent that the Partnership engages in derivative activities, it may be prevented from realizing the benefits of favorable price changes in the physical market; however, it may be similarly insulated against unfavorable changes in such prices.

        The Partnership's Credit Agreement limits its ability to enter into transactions with parties that require margin calls under certain derivative instruments and prevents members of the participating

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Derivative Financial Instruments (Continued)

bank group from requiring margin calls. As of December 31, 2009 approximately 5% of the Partnership's derivative positions, measured volumetrically, are with non-bank group counterparties and are subject to margin deposit requirements under OTC agreements that it meets with letters of credit, if necessary. In the unlikely event that the Partnership were unable to meet these margin calls with letters of credit, it would be forced to terminate the corresponding contracts.

Interest Rate Contracts

        The Partnership borrows funds using a combination of fixed and variable rate debt. The Partnership may utilize interest rate swap contracts to manage the interest rate risk associated with the fair value of its fixed rate borrowings and to effectively convert a portion of the underlying cash flows related to its long-term fixed rate debt securities into variable rate cash flows in order to achieve its desired mix of fixed and variable rate debt. As a result, the Partnership's future cash flows from these agreements will vary with the market rate of interest.

Other Contracts—Embedded Derivatives Related to Long-Term Debt

        On May 26, 2009, the Partnership completed the private placement of senior notes with two contingent written put options as described in Note 19. The written put options are considered embedded derivatives and are not considered clearly and closely related to the indenture. When a hybrid contract contains more than one embedded derivative requiring separate accounting, the embedded derivatives must be aggregated and accounted for as one compound embedded derivative. The initial fair value of the compound embedded derivative in the indenture (the "Compound Derivative") was recorded as a component of Long-term debt in the Consolidated Balance Sheets with a corresponding increase in the recorded balance of the original issue discount related to the senior notes issued in May 2009.

Financial Statement Impact of Derivative Contracts

        See Note 2 for a description of how the Partnership values its derivative financial instruments and how the instruments impact its financial statements. The impact of the Partnership's derivative

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Derivative Financial Instruments (Continued)

instruments on its Consolidated Balance Sheets and Statements of Operations are summarized below (in thousands):

			Asset Derivatives				Liability Derivatives
Derivative contracts not designated as hedging instruments and their balance sheet location			Fair Value at December 31, 2009		Fair Value at December 31, 2008		Fair Value at December 31, 2009			Fair Value at December 31, 2008
Commodity Contracts
	Fair value of derivative instruments—current		$	8,312	$	126,949	$	(60,464	)	$	(37,633	)
	Fair value of derivative instruments—long-term			15,810		55,389		(62,519	)		(14,801	)
Interest Rate Contracts
	Fair value of derivative instruments—current			509		—		—			—
Other Contracts
	Long-term debt			—		—		(190	)		—
		Total	$	24,631	$	182,338	$	(123,173	)	$	(52,434	)

			Year ended December 31,
Derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in income			2009			2008			2007
Revenue: Derivative (loss) gain
	Realized gain (loss)		$	87,289		$	(15,704	)	$	(15,901	)
	Unrealized (loss) gain			(207,641	)		293,532			(144,069	)
		Total revenue: derivative (loss) gain		(120,352	)		277,828			(159,970	)
Derivative (loss) gain related to purchased product costs
	Realized (loss) gain			(53,052	)		7,368			(8,829	)
	Unrealized loss			(15,831	)		(29,739	)		(6,363	)
		Total derivative loss related to purchased product costs		(68,883	)		(22,371	)		(15,192	)
Derivative gain (loss) related to facility expenses
	Unrealized gain (loss)			373			(644	)		14
Derivative gain related to interest expense
	Realized gain			2,000			—			—
	Unrealized gain			509			—			—
		Total derivative gain related to interest expense		2,509			—			—
Miscellaneous income (expense), net
	Unrealized gain			336			—			—
		Total (loss) gain	$	(186,017	)	$	254,813		$	(175,148	)

        At December 31, 2009, the fair value of the Partnership's commodity derivative contracts is inclusive of premium payments of $7.7 million, net of amortization. For 2009, 2008 and 2007, the Realized (loss) gain—revenue includes amortization of premium payments of $5.7 million, $2.1 million and $1.0 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Derivative Financial Instruments (Continued)

Credit Risk Contingent Feature

        The Partnership has a contractual arrangement with one non-bank group counterparty that contains a credit risk contingent feature. The Partnership has OTC swap and put positions with this counterparty. This arrangement contains provisions that if the Partnership's credit rating for its long-term senior unsecured debt, as announced by Moody's Investors Service, Inc. and Standard & Poor's Corporation were to decline below B3 or B-, respectively, the Partnership would be required to post additional collateral in the amount of 15% of all outstanding transactions if the contract value of all outstanding transactions was in a net liability position. The Partnership has a standard master netting arrangement with this counterparty. The aggregate fair value of all derivative contracts with a credit risk related contingent feature that are in a liability position at December 31, 2009 is $(5.2) million; however, for all outstanding transactions with this counterparty, the Partnership has a net asset position of $1.7 million. If the credit risk contingent feature was triggered as of December 31, 2009, the Partnership would not be required to post additional collateral as collateral is not required when the net position is an asset. If the Partnership's net position became a liability and collateral was required to be posted, it would be accomplished through a letter of credit due to a restriction in the credit agreement which does not allow cash collateral.

Outstanding Derivative Contracts

        The following tables provide information on the volume of the Partnership's derivative activity for positions related to long liquids and keep-whole price risk and interest rate risk at December 31, 2009, including the weighted average prices ("WAVG"):

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2010 (Apr - Dec)		1,297	$	66.48	$	74.49	$	(3,678	)
2011		822		60.00		80.13		(3,399	)
2012		822		60.00		85.87		(3,328	)

WTI Crude Puts	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		Fair Value (in thousands)
2010		1,191	$	80.00	$	3,117
2011		1,818		80.00		6,872

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2010		2,783	$	67.88	$	(14,340	)
2011		535		68.20		(3,305	)
2012		529		70.30		(3,139	)

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2010		5,023	$	5.59	$	(25	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Derivative Financial Instruments (Continued)

IsoButane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		10,949	$	1.40	$	(802	)

Natural Gasoline Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		19,246	$	1.66	$	(828	)

Normal Butane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		16,532	$	1.36	$	(863	)

Propane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		56,435	$	1.10	$	(3,200	)

Interest Rate Swaps	Principal Notional Amount (in thousands)		WAVG LIBOR Spread			Fair Value (in thousands)
2014 (Settlement Dates May 1st & Nov 1st)	$	275,000		3.83	%	$	509

        The following tables provide information on the volume of the Partnership's taxable subsidiary's commodity derivative activity for positions related to keep-whole price risk at December 31, 2009, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012		648	$	70.00	$	91.85	$	(1,401	)

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2010		2,098	$	71.05	$	(8,959	)
2011		3,150		87.27		1,412
2012 (Jan)		2,142		91.50		261

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2010		12,810	$	8.83	$	(12,360	)
2011		15,429		8.79		(12,247	)
2012		4,225		7.08		(618	)

IsoButane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		14,224	$	1.44	$	(231	)

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7. Derivative Financial Instruments (Continued)

Natural Gasoline Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		27,080	$	1.66	$	(237	)

Normal Butane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		38,241	$	1.42	$	(437	)

Propane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2010		224,242	$	1.15	$	(2,927	)

        The Partnership has a commodity contract with a producer in the Appalachia region which creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The primary term of the commodity contract, a component of a broader regional arrangement, expired on December 31, 2009 but the producer exercised its right to extend the processing agreement and the commodity contract through the first quarter of 2015. The fair value of the commodity contract is marked based on an index price through Derivative loss related to purchased product costs. As of December 31, 2009, the estimated fair value of this contract was $(33.9) million.

        The Partnership has a commodity contract which gives it an option to fix a component of the utilities cost to an index price on electricity at one of its plant locations. The value of the derivative component of this contract is marked to market through Derivative (gain) loss related to facility expenses. As of December 31, 2009, the estimated fair value of this contract was $(0.3) million.

        During the first quarter of 2009, the Partnership settled a portion of its derivative positions covering 2009, 2010, and 2011 for $15.2 million of net realized gains. The settlement was completed prior to the contractual settlement to improve liquidity and to mitigate credit risk with certain counterparties, and as such does not represent trading activity. The settlement was recorded as $26.5 million of realized gains in Realized (loss) gain—revenue and $11.3 million loss is included in Derivative loss related to purchased product costs in the accompanying Consolidated Statements of Operations.

8. Fair Value

Fair Value Measurement

        Fair value measurements and disclosures relate primarily to the Partnership's derivative positions at December 31, 2009, see Note 2 for a description of the guidance and the fair value hierarchy.

Commodity Derivative Transactions

        The Partnership utilizes a combination of fixed-price forward contracts, fixed-for-floating price swaps and options available on the OTC market. The Partnership's derivative positions are valued using corroborated market data and internally developed models when observable market data is not available. Crude oil and natural gas swaps are considered Level 2 transactions as the pricing methodology include quoted prices for similar assets and liabilities and the Partnership can determine the prices are observable and do not contain Level 3 inputs that are significant to the measurement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Fair Value (Continued)

Level 3 financial instruments include interest rate swaps, crude oil options, all NGL transactions and the Compound Derivative as they have significant unobservable market parameters. Depending on the Level 3 financial instrument significant unobservable inputs include volatilities associated with option contracts, commodity prices interpolated and extrapolated due to inactive markets, and for the Compound Derivative assumptions about the probability of specific events occurring in the future. The methods described may produce a fair value calculation that may not be indicative of net realizable value or reflective of future fair values. Furthermore, while the Partnership believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at December 31, 2009. The following table presents the financial instruments carried at fair value as of December 31, 2009 and 2008, and by the valuation hierarchy (as described above, in thousands):

	Assets		Liabilities
As of December 31, 2009	Derivatives		Derivatives
Significant other observable inputs (Level 2)	$	9,920	$	(63,242	)
Significant unobservable inputs (Level 3)		14,711		(59,931	)
Total carrying value in Consolidated Balance Sheet	$	24,631	$	(123,173	)

	Assets
					Liabilities
	Trading Securities
As of December 31, 2008			Derivatives		Derivatives
Significant other observable inputs (Level 2)	$	—	$	106,826	$	(49,378	)
Significant unobservable inputs (Level 3)		512		75,512		(3,056	)
Total carrying value in Consolidated Balance Sheet	$	512	$	182,338	$	(52,434	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

8. Fair Value (Continued)

Changes in Level 3 Fair Value Measurements

        The tables below include a rollforward of the balance sheet amounts for the year ended December 31, 2009 and 2008 (including the change in fair value) for financial instruments classified by the Partnership within Level 3 of the valuation hierarchy (in thousands).

	December 31, 2009			December 31, 2008
	Derivatives (net)			Trading Securities			Derivatives (net)
Fair Value at Beginning of Period	$	72,456		$	3,674		$	(84,367	)
Total gain or loss (realized and unrealized) included in earnings(a)(b)		(88,537	)		(762	)		102,204
Purchases, sales, issuances and settlements (net)		(29,139	)		(2,400	)		54,619
Transfers in or out of Level 3 (net)		—			—			—
Fair Value at End of Period	$	(45,220	)	$	512		$	72,456
The amount of total gains or losses for the period included in earnings (or changes in net assets) attributable to the change in unrealized gains or losses relating to assets still held at December 31(a)	$	(68,948	)	$	(76	)	$	115,875

(a)

Gains and losses on derivative positions classified as Level 3 are recorded in Derivative (loss) gain related to revenue, purchased product costs, facility expenses and Miscellaneous income (expense), net.

(b)

Gains and losses on trading securities are realized and recorded in Miscellaneous income (expense), net.

Assets and liabilities measured at fair value on a nonrecurring basis

        Certain assets and liabilities are measured at fair value on a nonrecurring basis; that is, the instruments are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances. As of June 30, 2009, certain long-lived assets of Wirth Gathering Partnership ("Wirth"), a consolidated subsidiary, were required to be measured at fair value in conjunction with the Partnership's impairment evaluation for long-lived assets. Property, plant and equipment and intangible assets with a net book value of $5.2 million and $0.7 million, respectively, were written down to an estimated fair value of zero, resulting in an impairment charge of $5.9 million. The Partnership estimated the fair value of these assets based on an income approach using significant unobservable inputs (Level 3). See Note 15 for further discussion of the impairment. As of December 31, 2009, there were no other assets or liabilities to be measured at fair value on a nonrecurring basis.

9. Marketable Securities

        As of December 31, 2008, the Partnership held certain securities that were classified and accounted for as trading securities. The $0.5 million recorded value of these securities at December 31, 2008 consisted of an original cost basis of $1.2 million and an other-than-temporary impairment of

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9. Marketable Securities (Continued)

$0.7 million. Because the market mechanism normally used to liquidate the trading securities was no longer operating efficiently and it was not known if the market mechanism would become efficient within the next year, the balance of these securities is included in Other long-term assets as of December 31, 2008 in the accompanying Consolidated Balance Sheets. During the first quarter of 2009, the Partnership sold these securities for approximately $0.6 million and recognized a gain of less than $0.1 million. This gain is included in Miscellaneous income (expense), net in the accompanying Consolidated Statements of Operations.

10. Significant Customers and Concentration of Credit Risk

        For the years ended December 31, 2009, 2008, and 2007, revenues from one customer totaled $134.8 million, $234.0 million and $191.5 million, representing 15.7%, 22.1% and 22.6% of Revenue, respectively. Sales to this customer are made primarily from the Southwest segment. As of December 31, 2009, 2008 and 2007, the Partnership had $5.2 million, $6.5 million and $6.4 million of accounts receivable from this customer, respectively.

        For the years ended December 31, 2009, 2008 and 2007, revenues from another customer totaled $81.6 million, $87.6 million and $88.9 million, representing 9.5%, 8.3% and 10.5% of Revenue, respectively. Sales to this customer are made primarily from the Southwest segment. As of December 31, 2009, 2008 and 2007, the Partnership had $10.1 million, $2.4 million and $9.5 million of accounts receivable from this customer, respectively.

11. Receivables and Other Current Assets

        Receivables consist of the following (in thousands):

		December 31, 2009		December 31, 2008
Trade, net(1)		$	129,511	$	88,370
Other(2)			11,458		13,479
	Total receivables	$	140,969	$	101,849

(1)

Includes approximately $13.1 million of unbilled gathering fees under a long-term agreement. The total amount is expected to be billed and collected by December 31, 2010.

(2)

The 2009 balance relates primarily to amounts due from the settlement of derivative positions, and imbalances. The 2008 balance relates primarily to the settlement of derivative positions.

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11. Receivables and Other Current Assets (Continued)

        Other current assets consist of the following (in thousands):

		December 31, 2009		December 31, 2008
Prepaid fuel		$	4,269	$	1,114
Income tax receivable			4,362		8,416
Prepaid rents			515		—
Prepaid insurance			408		810
Prepaid other			1,120		1,408
	Total other current assets	$	10,674	$	11,748

12. Inventories

        Inventories consist of the following (in thousands):

		December 31, 2009		December 31, 2008
Natural gas and natural gas liquids		$	20,939	$	29,171
Spare parts			8,136		2,385
	Total inventories	$	29,075	$	31,556

        During the year ended December 31, 2008, the Partnership recognized an expense of $6.7 million to write down natural gas and NGL inventories to market value. The expense is included in Purchased product costs in the accompanying Consolidated Statements of Operations.

13. Property, Plant and Equipment

        Property, plant and equipment consist of the following (in thousands):

		December 31, 2009			December 31, 2008
Natural gas gathering facilities, pipelines and gas processing plants		$	1,720,817		$	1,206,584
Fractionation and storage facilities			67,839			24,498
Crude oil pipelines			16,810			16,104
NGL transportation facilities			14,286			10,888
Land, building, office equipment and other			131,735			87,842
Construction in progress			203,157			304,776
	Property, plant and equipment		2,154,644			1,650,692
Less: accumulated depreciation			(173,000	)		(81,167	)
	Total property, plant and equipment, net	$	1,981,644		$	1,569,525

        The Partnership capitalizes interest on major projects during construction. For the years ended December 31, 2009, 2008 and 2007, the Partnership capitalized interest, including deferred finance costs, of $12.2 million, $9.5 million and $3.3 million, respectively.

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14. Goodwill and Intangible Assets

        Goodwill.    Goodwill as of December 31, 2009 and 2008 is $9.4 million. All goodwill was acquired in 2008 as a result of the Merger and the acquisition of PQ Assets. The table below shows the gross amount of goodwill acquired and the cumulative impairment loss recognized as of December 31, 2009 (in millions).

	Southwest			Northeast		Gulf Coast			Total
Goodwill acquired	$	24.3		$	3.9	$	9.9		$	38.1
Cumulative impairment		(18.8	)				(9.9	)		(28.7	)
Ending balance	$	5.5		$	3.9	$	—		$	9.4

        Intangible Assets.    The Partnership's intangible assets as of December 31, 2009 and 2008 are comprised of customer contracts and relationships, as follows (in thousands):

		December 31, 2009							December 31, 2008
Description		Gross		Accumulated Amortization			Net		Gross		Accumulated Amortization			Net		Useful Life
Southwest		$	406,801	$	(47,147	)	$	359,654	$	407,544	$	(24,708	)	$	382,836	20 yrs
Northeast			68,573		(12,733	)		55,840		68,573		(5,876	)		62,697	10 yrs
Gulf Coast			262,772		(23,855	)		238,917		262,772		(12,388	)		250,384	25 yrs
	Total:	$	738,146	$	(83,735	)	$	654,411	$	738,889	$	(42,972	)	$	695,917

        Amortization expense related to intangible assets was $40.8 million, $38.5 million and $16.7 million for the years ended December 31, 2009, 2008 and 2007, respectively.

        Estimated future amortization expense related to the intangible assets at December 31, 2009, is as follows (in thousands):

Year ending December 31,
2010	$	40,772
2011		40,772
2012		40,772
2013		40,772
2014		40,772
Thereafter		450,551
	$	654,411

15. Impairment of Goodwill and Long-Lived Assets

        Goodwill.    The Partnership's policy is to evaluate goodwill for impairment annually as of November 30, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The evaluation performed as of November 30, 2009 did not indicate any impairment of goodwill.

        Due to the decline in the market prices of crude oil and other NGLs in December 2008, management significantly reduced the short- and medium-term forecasts for the net income and cash

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15. Impairment of Goodwill and Long-Lived Assets (Continued)

flow to be generated by the Partnership's reporting units. Management considered this significant change in the forecast and the continued decline in the trading price for its common units to be an indication of potential impairment, and therefore completed the goodwill impairment test as of November 30 and December 31, 2008. As a result of these analyses, the Partnership recorded impairment charges of $28.7 million to write-off the goodwill balance allocable to four of the Partnership's reporting units. Approximately $18.8 million and $9.9 million of the goodwill impairment related to the Southwest and Gulf Coast segments, respectively. The remaining goodwill balance of $9.4 million consists of $5.5 million allocated to the East Texas reporting unit in the Southwest segment and $3.9 million allocated to the Appalachia reporting unit in the Northeast segment. In completing the evaluation, management estimated the fair value of the Partnership's reporting units primarily using an income approach based on discounted future cash flows. Management also considered a market approach based on the Partnership's market capitalization as of December 31, 2008. Because management believes the market capitalization of the Partnership was adversely impacted by global economic factors and did not accurately represent the full underlying value of the Partnership's assets, the income approach was weighted more heavily in the analysis.

        Long-Lived Assets.    The Partnership's policy is to evaluate whether there has been an impairment in the value of long-lived assets when certain events have taken place that indicate that the remaining balance may not be recoverable. The Partnership evaluates the carrying value of its property, plant and equipment and intangibles on at least a segment level and at lower levels where cash flows for specific assets can be identified.

        An analysis completed during the second quarter of 2009 indicated that the future estimated operating cash flows could be at or below zero for Wirth, which operates a small natural gas gathering system included in the Partnership's Southwest segment. The Partnership owns a 50% interest in Wirth and consolidates its assets, liabilities, and results of operations in the accompanying Consolidated Financial Statements. Wirth's expected future cash flows were adversely impacted by a significant reduction to the primary producer's drilling plan disclosed in the second quarter of 2009, as well as increased operating expenses resulting from an agreement reached in May 2009 with the non-controlling partner. The Partnership used the income approach for determining the assets' fair value and recognized an impairment of long-lived assets of approximately $5.9 million for year ended December 31, 2009. After considering the impact of the non-controlling interest, the impairment increased the net loss attributable to the Partnership for the year ended December 31, 2009 by approximately $2.9 million, before provision for income tax.

        An analysis completed in 2008 indicated an impairment of the Partnership's gas-gathering assets in Manistee County, Michigan, which are part of the Partnership's Northeast segment, due to the decision to move the Fisk plant to Pennsylvania and to outsource the gas processing to a third party. The Partnership used the market approach to determine the assets' fair value and recognized an impairment of long-lived assets of $7.6 million for the year ended December 31, 2008.

        An analysis completed in 2007 determined that a system located in the Partnership's Southwest segment had future estimated cash inflows estimated to be near zero because the system was shut-in for a year, and as such the carrying amounts of the assets exceeded the estimated undiscounted cash flows. It was determined that an impairment of the system had occurred. Fair value of the long-lived assets was determined based on Management's opinion that the idle assets had no economic value.

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15. Impairment of Goodwill and Long-Lived Assets (Continued)

Therefore, an impairment of long-lived assets of $0.4 million was recognized for the year ended December 31, 2007.

16. Investment in Unconsolidated Affiliates

        The Partnership applies the equity method of accounting for its 40% non-operating interest in Centrahoma Processing LLC ("Centrahoma"). Differences between the Partnership's investment and its proportionate share of reported equity are amortized based upon the respective useful lives of the assets to which the differences relate.

        The table below shows the carrying value of the Partnership's equity investments (in thousands):

		December 31, 2009		December 31, 2008
Investment in Centrahoma		$	29,633	$	28,911
Investment in Starfish			—		17,181
	Total investment in unconsolidated affiliates	$	29,633	$	46,092

        On March 1, 2008, the Partnership acquired a 20% interest in Centrahoma for $11.6 million. On May 9, 2008, the Partnership exercised its option to acquire an additional 20% interest in Centrahoma for $12.0 million including a capital call. Centrahoma owns certain processing plants in the Arkoma Basin. In addition, the Partnership signed agreements to dedicate its processing rights in certain acreage in the Woodford Shale area to Centrahoma through March 1, 2018.

        The following table includes summarized balance sheet data for 100% of Centrahoma (in thousands):

	December 31, 2009		December 31, 2008
Current assets	$	14,280	$	9,192
Noncurrent assets		70,922		71,804
Current liabilities		11,925		8,728

        The following table includes summarized results of operations for the year ended December 31, 2009 and from inception on February 11, 2008 to December 31, 2008 for 100% of Centrahoma (in thousands):

	Year ended December 31, 2009			Inception to December 31, 2008
Revenue	$	9,585		$	6,648
Operating loss		(907	)		(718	)
Net loss		(907	)		(718	)
Partnership's share of net loss		(451	)		(277	)

        The Partnership applied the equity method of accounting for its 50% non-operating interest in Starfish, which was sold on December 31, 2009 for proceeds of approximately $25.0 million

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16. Investment in Unconsolidated Affiliates (Continued)

(see Note 6). The following table includes summarized balance sheet data as of December 31, 2008 for 100% of Starfish (in thousands):

	December 31, 2008
Current assets	$	15,009
Noncurrent assets		123,226
Current liabilities		14,015
Noncurrent liabilities		14,281

        The following table includes summarized results of operations for 100% of Starfish (in thousands):

	Year ended December 31,
	2009		2008		2007
Revenue	$	31,371	$	24,088	$	32,613
Operating income		6,691		1,125		11,959
Net income		7,788		950		12,118
Partnership's share of net income		3,956		367		5,309

        In September 2008, Hurricane Ike caused wind and water damage to oil and gas assets in the Gulf of Mexico and Gulf Coast regions, including damage to several onshore and offshore facilities of Starfish. Due to the damage in the region, the operations of Starfish were partially curtailed resulting in a decrease in the Partnership's Earnings from unconsolidated affiliates in the accompanying Consolidated Statements of Operations. The Partnership contributed $0.4 million and $5.0 million of additional capital to fund the repairs resulting from the hurricane for the years ended December 31, 2009 and 2008, respectively. The Partnership settled certain insurance claims related to damage and business interruption caused by Hurricane Ike in 2008. Total insurance proceeds of $0.8 million are included in Miscellaneous income (expense), net in the Consolidated Statements of Operations for the year ended December 31, 2009.

        During 2008, management determined that a combination of factors indicated that the fair value of the investment in Starfish may have declined below the carrying value. These factors included the increase in the investment balance due to the capital call associated with the damage repairs and a forecasted reduction in the expected future cash distributions from Starfish. The commodity price environment, damage to oil and gas assets in the region, and uncertainty of whether or not volumes would return to pre-hurricane levels, led to a downward revision of Starfish's short- and long-term financial forecast. As a result of these indicators, management completed an impairment evaluation as of December 31, 2008. Prior to completing the impairment evaluation, the recorded value of the investment in Starfish was $58.6 million. Using an income approach based on estimated discounted cash flows, management estimated that the fair value of the Partnership's investment in Starfish was approximately $17.2 million. Management believed that the downward revisions to the Starfish forecast were likely to be permanent. Therefore, the decline in value was considered to be other-than-temporary and an impairment charge of $41.4 million was recorded in the accompanying Consolidated Statements of Operations.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. Accrued Liabilities

        Accrued liabilities consist of the following (in thousands):

		December 31, 2009		December 31, 2008
Accrued property, plant and equipment		$	60,738	$	51,060
Product and operations			24,301		20,610
Interest			24,193		22,591
Short-term incentive, severance and vacation accruals			8,665		4,074
Taxes (other than income tax)			6,307		6,578
Deferred income			3,369		1,044
Accrued derivative settlements			2,616		—
Professional services			2,375		1,688
Phantom unit accrual			1,595		735
SMR Liability			1,434		—
Other			1,870		34
Deferred lease obligation			224		2,620
	Total accrued liabilities	$	137,687	$	111,034

18. Asset Retirement Obligation

        The Partnership's assets subject to asset retirement obligations are primarily certain gas-gathering pipelines and processing facilities, a crude oil pipeline and other related pipeline assets. The Partnership also has land leases that require the Partnership to return the land to its original condition upon termination of the lease. The Partnership reviews current laws and regulations governing obligations for asset retirements and leases, as well as the Partnership's leases and other agreements.

        The following is a reconciliation of the changes in the asset retirement obligation from January 1, 2008 to December 31, 2009 (in thousands):

		Year ended December 31,
		2009		2008
Beginning asset retirement obligation		$	1,773	$	1,635
	Liabilities incurred		906		9
	Accretion expense		198		129
Ending asset retirement obligation		$	2,877	$	1,773

        At December 31, 2009, 2008, and 2007, there were no assets legally restricted for purposes of settling asset retirement obligations. The asset retirement obligation has been recorded as part of Other long-term liabilities in the accompanying Consolidated Balance Sheets.

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19. Long-Term Debt

        Debt is summarized below (in thousands):

			December 31, 2009		December 31, 2008
Credit Facility
	Revolver facility, 5.25% and 2.51% interest, respectively, due February 2012		$	59,300	$	184,700
Senior Notes
	Senior Notes, 6.875% interest, net of discount of $8,089 and $9,676, respectively, issued October 2004 and due November 2014			216,911		215,324
	Senior Notes, 6.875% interest, net of discount of $29,515 and $0, respectively, issued May 2009 and due November 2014(1)			120,674		—
	Senior Notes, 8.5% interest, net of discount of $762 and $882, respectively, issued July 2006 and due July 2016			274,238		274,118
	Senior Notes, 8.75% interest, net of discount of $1,051 and $1,177, respectively, issued April and May 2008 and due April 2018			498,949		498,823
		Total long-term debt	$	1,170,072	$	1,172,965

(1)

Includes fair value of approximately $0.2 million of written put options as discussed below.

Credit Facility

        On February 20, 2008, the Partnership entered into a new credit agreement ("Partnership Credit Agreement"). The Partnership Credit Agreement originally provided for a maximum lending limit of $575.0 million through February 2013. The Partnership Credit Agreement included a senior secured revolving credit facility of $350.0 million (that under certain circumstances could be increased to $550.0 million) and a $225.0 million term loan, both of which could be repaid at any time without penalty. Initial borrowings under the revolving credit facility portion of Partnership Credit Agreement were used to finance other payments under the Merger and to repay amounts due on the old partnership credit facility revolver of $67.0 million. The Partnership retired the term loan in April 2008 using a portion of the proceeds from a private placement of Senior Notes completed on April 15, 2008. The Partnership recorded a charge of $4.2 million to write-off the deferred financing costs associated with the term loan, which is included in Amortization of deferred financing costs and discount in the accompanying Consolidated Statements of Operations. The credit facility is guaranteed and collateralized by substantially all of the Partnership's assets and those of its wholly-owned subsidiaries.

        On January 28, 2009, the Partnership entered into the first amendment to its Partnership Credit Agreement which became effective March 2, 2009. The amendment expands the Partnership's borrowing capacity under the revolving facility by $85.6 million from $350.0 million to $435.6 million. Pursuant to the amendment, the term of the original credit agreement has been reduced by one year and is now due on February 20, 2012. The accordion feature established under the original credit agreement was reset to $200.0 million of uncommitted funds. The borrowings under the revolving credit facility of the Partnership Credit Agreement continue to bear interest at a variable interest rate, plus basis points. The variable interest rate typically is based on LIBOR; however, in certain borrowing circumstances the rate would be based on the higher of a) the Federal Funds Rate plus 0.5%, and b) a rate set by the Partnership Credit Agreement's administrative agent, based on the U.S. prime rate. The

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19. Long-Term Debt (Continued)

basis points correspond to the ratio of the Partnership's Consolidated Funded Debt (as defined in the Partnership Credit Agreement) to Adjusted Consolidated EBITDA (as defined in the Partnership Credit Agreement). Under the original agreement, the basis points ranged from 50 to 125 for Base Rate loans, and 150 to 225 for LIBOR loans. Under the terms of the amendment, the basis points range from 150 to 225 for Base Rate loans and 250 to 325 for LIBOR loans. The amendment also established a floor of 2% for the LIBOR rate used to determine the interest rate on the LIBOR loans. The Partnership incurred and capitalized approximately $4.3 million of debt modification fees and other professional services as a result of the amendment. The amendment also resulted in the write-off of approximately $0.3 million of previously capitalized deferred finance costs during the first quarter of 2009, which is included in Amortization of deferred financing costs and discount in the accompanying Consolidated Statements of Operations.

        Under the provisions of the Partnership Credit Agreement, the Partnership is subject to a number of restrictions and covenants as defined by the agreement. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The credit facility is guaranteed and collateralized by substantially all of the Partnership's assets and those of its wholly-owned subsidiaries. As of December 31, 2009, the Partnership had $59.3 million of borrowings outstanding and $37.5 million of letters of credit outstanding under the revolving credit facility, leaving approximately $338.8 million available for borrowing. The Partnership pays a commitment fee of 0.375% annually on the unused portion of the revolving credit facility.

Senior Notes

        As of December 31, 2009, MarkWest Energy Partners, L.P. in conjunction with its wholly-owned subsidiary MarkWest Energy Finance Corporation (the "Issuers"), had four series of senior notes outstanding: $225.0 million aggregate principal issued in October 2004 and due in November 2014 (the "2014 Senior Notes"), $275.0 million aggregate principal issued in July 2006 and due in July 2016 (the "2016 Senior Notes"), $500.0 million aggregate principal issued in April and May 2008 and due in April 2018 (the "2018 Senior Notes"), and $150.0 million aggregate principal issued in May 2009 and due in November 2014 (the "2014 Senior Notes—Mirror" and all together with the 2014 Senior Notes, 2016 Senior Notes and 2018 Senior Notes, the "Senior Notes"). The estimated fair value of the Senior Notes was approximately $1,152.9 million and $627.1 million at December 31, 2009 and December 31, 2008, respectively, based on quoted market prices.

        2014 Senior Notes.    In October 2004, the Issuers completed a private placement, subsequently registered, of $225.0 million in senior notes at a fixed rate of 6.875%, payable semi-annually in arrears on May 1 and November 1, commencing May 1, 2005. The 2014 Senior Notes mature on November 1, 2014.

        2014 Senior Notes—Mirror.    In May 2009, the Issuers completed a private placement, subsequently registered, of $150.0 million in aggregate principal amount of 6.875% senior unsecured notes to qualified institutional buyers under Rule 144A. Although the terms of the 2014 Senior Notes—Mirror are substantially the same as the terms of the 2014 Senior Notes, the 2014 Senior Notes—Mirror were issued under a different indenture and are not part of the same series of notes. The 2014 Senior Notes—Mirror mature on November 1, 2014. The Partnership received proceeds of approximately $113.8 million, after deducting the initial purchasers' discounts and other expenses of the private placement. The proceeds were primarily used to repay borrowings under the Partnership's revolving

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19. Long-Term Debt (Continued)

credit facility. Interest on these senior notes is payable on each May 1 and November 1, and will accrue from May 26, 2009.

        The indenture for the senior notes issued in May 2009 contains the following two contingent written put options exercisable by the debt holders (see Note 7 for more information on the separate accounting for the written put options and Note 8 for more information on the determination of the fair value):

        Change in Control Put—In the event of a change in control of the Partnership, the debt holders have the option to put the notes at 101% of principal amount, plus any accrued interest.

        Asset Sale Offer Put—In the event the Partnership consummates an asset sale, as defined in the indenture, and fails to use the net proceeds in excess of $10.0 million to: (i) pay off indebtedness under the Credit Facility; (ii) to make capital expenditures; (iii) to acquire other long-term tangible assets or (iv) to invest the proceeds in any other approved investment, the Partnership must use the excess proceeds to offer to repurchase some portion of the senior notes at 100% of principal amount, plus any accrued interest.

        The written put options are considered embedded derivatives primarily due to the fact that they are contingently exercisable and the notes were issued at a substantial discount. Substantially similar contingent written put options are also in the indentures for the Partnership's previous senior note offerings, but they do not require separate accounting because their issuance in prior years was not at a substantial discount.

        2016 Senior Notes.    In July 2006, the Issuers completed a private placement, subsequently registered, of $200 million in aggregate principal amount of 8.5% senior notes due 2016 to qualified institutional buyers. The 2016 Senior Notes will mature on July 15, 2016, and interest is payable semi-annually in arrears on July 15 and January 15, commencing January 15, 2007. In October 2006 the Partnership offered $75.0 million in additional debt securities under this same indenture. The net proceeds from the private placements were approximately $191.2 million and $74.5 million, respectively, after deducting the initial purchasers' discounts and legal, accounting and other transaction expenses.

        2018 Senior Notes.    In April 2008, the Issuers completed a private placement, subsequently registered, of $400 million in aggregate principal amount of 8.75% senior notes to qualified institutional buyers under Rule 144A. The 2018 Notes mature on April 15, 2018, and interest is payable semi-annually in arrears on April 15 and October 15, commencing October 15, 2008. The Partnership received approximately $388.1 million, after deducting initial purchasers' discounts and the expenses of the offering. Also, on May 1, 2008, the Partnership completed the placement of an additional $100.0 million pursuant to the indenture to the 2018 Senior Notes. The Partnership received approximately $100.4 million, after including initial purchasers' premium and the estimated expenses of the offering. The notes issued in this offering and the notes issued on April 15, 2008, are treated as a single class of debt securities under this same indenture. The Partnership utilized approximately $275.0 million of the net proceeds from the offerings to repay the $225.0 million term loan portion of the Partnership Credit Agreement entered into on February 20, 2008 and to partially fund its 2008 capital expenditure requirements.

        The Issuers have no independent operating assets or operations. All wholly-owned subsidiaries, other than MarkWest Energy Finance Corporation, guarantee the Senior Notes, jointly and severally

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19. Long-Term Debt (Continued)

and fully and unconditionally. The Partnership's less than wholly-owned subsidiaries do not guarantee the Senior Notes (see Note 27 for required consolidating financial information). The notes are senior unsecured obligations equal in right of payment with all of the Partnership's existing and future senior debt. These notes are senior in right of payment to all of the Partnership's future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership's obligations in respect of the Partnership Credit Agreement.

        The indentures governing the Senior Notes limit the activity of the Partnership and its restricted subsidiaries. Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indentures pursuant to Rule 144A and Regulation S under the Securities Act of 1933. If at any time the Senior Notes are rated investment grade by both Moody's Investors Service, Inc. and Standard & Poor's Rating Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will be suspended during the period of time in which the foregoing requirements are met or will terminate entirely, in which case the Partnership and its subsidiaries will cease to be subject to such terminated covenants.

        The aggregate minimum principal payments on long-term debt are as follows, as of December 31, 2009, exclusive of any prepayments allowable under the Partnership's debt agreements (in thousands):

Year ending December 31,
2010	$	—
2011		—
2012		59,300
2013		—
2014		375,000
Thereafter		775,000
	$	1,209,300

20. Partners' Capital

        As described in Note 3, the Partnership acquired the Corporation through a merger of MWEP, L.L.C. with and into the Corporation, pursuant to which all remaining shares of the Corporation's common stock were converted into approximately 15.5 million Partnership common units. As of December 31, 2009, partners' capital consists of 66,275,477 common limited partner units. The Partnership Agreement stipulates the circumstances under which the Partnership is authorized to issue new capital, maintain capital accounts, and distribute cash.

        The Partnership Agreement contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.

Distributions of Available Cash

        The Partnership distributes all of its Available Cash (as defined) to unitholders of record within 45 days after the end of each quarter. Available Cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter, less reserves established by the general partner for future requirements, plus all cash for the quarter from working capital borrowings made after the end of the quarter. The general partner had the discretion to establish cash reserves

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20. Partners' Capital (Continued)

that are necessary or appropriate to (i) provide for the proper conduct of the Partnership's business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for any one or more of the next four quarters.

        The quarterly cash distributions and dividends applicable to 2009, 2008 and 2007, were as follows:

Quarter Ended	Record Date	Payment Date	Amount Per Unit
December 31, 2009	February 5, 2010	February 12, 2010	$	0.640
September 30, 2009	November 2, 2009	November 13, 2009	$	0.640
June 30, 2009	August 3, 2009	August 14, 2009	$	0.640
March 31, 2009	May 4, 2009	May 15, 2009	$	0.640
December 31, 2008	February 6, 2009	February 13, 2009	$	0.640
September 30, 2008	November 4, 2008	November 14, 2008	$	0.640
June 30, 2008	August 4, 2008	August 15, 2008	$	0.630
March 31, 2008	May 5, 2008	May 15, 2008	$	0.600
December 31, 2007	February 8, 2008	February 15, 2008	$	0.189
September 30, 2007	November 9, 2007	November 21, 2007	$	0.189
June 30, 2007	August 9, 2007	August 21, 2007	$	0.189
March 31, 2007	May 10, 2007	May 22, 2007	$	0.168

        Distributions for the quarter ended December 31, 2007 and all prior periods represent the Corporation's common stock dividends. The per unit amount has been adjusted to reflect the 1.9051 Exchange Ratio to give effect to the Merger on February 21, 2008.

Equity Offerings

        On August 18, 2009, the Partnership completed a public offering of approximately 6.03 million newly issued common units, which included the exercise of the overallotment option by the underwriters, representing limited partner interests at a purchase price of $20.95 per common unit. Net proceeds of approximately $120.9 million were used to partially fund the Partnership's 2009 capital expenditure requirements, and the remainder was used to pay down borrowings under its revolving credit facility of the Partnership Credit Agreement.

        On June 10, 2009, the Partnership completed a public offering of approximately 3.34 million newly issued common units, which included the exercise of the overallotment option by the underwriters, representing limited partner interests at a purchase price of $18.15 per common unit. Net proceeds of approximately $57.7 million were used to partially fund the Partnership's 2009 capital expenditure requirements, and the remainder was used to pay down borrowings under its revolving credit facility of the Partnership Credit Agreement.

        On April 14, 2008, the Partnership completed a public offering of 5.75 million newly issued common units, which included the exercise of the overallotment option by the underwriters, representing limited partner interests at a purchase price of $31.15 per common unit. Net proceeds of approximately $171.4 million were used to pay down borrowings under its revolving credit facility of the Partnership Credit Agreement, and the remainder was used to partially fund the Partnership's 2008 capital expenditure requirements.

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20. Partners' Capital (Continued)

        The following table summarizes the equity offerings that were completed in 2007 at the Partnership level prior to the Merger:

Date of offering	Units issued	Net proceeds
December 18, 2007	2.9 million	$	91.8 million
April 9, 2007	4.1 million	$	137.7 million

21. Commitments and Contingencies

Legal

        The Partnership is subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its business. The Partnership maintains insurance policies in amounts and with coverage and deductibles as it believes reasonable and prudent. However, the Partnership cannot assure that the insurance companies will promptly honor their policy obligations or that the coverage or levels of insurance will be adequate to protect the Partnership from all material expenses related to future claims for property loss or business interruption to the Partnership, or for third-party claims of personal and property damage, or that the coverages or levels of insurance it currently has will be available in the future at economical prices. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the consolidated financial statements.

        In June 2006, the Office of Pipeline Safety ("OPS") issued a Notice of Probable Violation and Proposed Civil Penalty ("NOPV") (CPF No. 2-2006-5001) to both MarkWest Hydrocarbon and Equitable Production Company ("Equitable"). The NOPV is associated with the pipeline leak and an ensuing explosion and fire that occurred on November 8, 2004 in Ivel, Kentucky on an NGL pipeline owned by Equitable and leased and operated by a subsidiary, MarkWest Energy Appalachia, L.L.C. The NOPV sets forth six counts of violations of applicable regulations, and a proposed civil penalty in the aggregate amount of $1.1 million. An administrative hearing on the matter, previously set for the last week of March 2007, was postponed to allow the administrative record to be produced and to allow OPS an opportunity to respond to MarkWest's and Equitable's motions to dismiss count one of the NOPV, which involves $0.8 million of the $1.1 million proposed penalty. This count arises out of alleged activity in 1982 and 1987, which predates MarkWest's leasing and operation of the pipeline. MarkWest believes it has viable and mitigating defenses to the remaining counts and will vigorously defend all applicable assertions of violations. The administrative hearing request was withdrawn by MarkWest and Equitable in October 2009, and the case will proceed to initial resolution on the briefs, exhibits and other documents filed or submitted by the parties in the matter.

        MarkWest Javelina Company, L.L.C. is a party to an action styled Esmerejilda G. Valasquez, et al. v. Occidental Chemical Corp., et al., Case No. A-060352-C, 128^th Judicial District, Orange County, Texas, original petition filed July 10, 2006; as refiled from previously dismissed petition captioned Jesus Villarreal v. Koch Refining Co. et al., Cause No. 05-01977-F, 214^th Judicial Dist. Ct., County of Nueces, Texas, originally filed April 27, 2005), which sets forth claims for wrongful death, personal injury or property damage, and nuisance type claims, allegedly incurred as a result of operations and emissions from MarkWest Javelina's gas processing plant and from various petroleum, petrochemical and metal processing and refining operations located in the area, which were also named as defendants in the

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21. Commitments and Contingencies (Continued)

action. The action has been and is being vigorously defended, and it appears at this time that this action should not have a material adverse impact on the Partnership's financial position or results of operations.

        In the ordinary course of business, the Partnership is a party to various other legal and regulatory actions. In the opinion of management, none of these actions, either individually or in the aggregate, will have a material adverse effect on the Partnership's financial condition, liquidity or results of operations.

Lease Obligations

        The Partnership has various non-cancelable operating lease agreements expiring at various times through fiscal year 2035. Annual rent expense under these operating leases was $18.6 million, $12.8 million and $10.3 million for the years ended December 31, 2009, 2008 and 2007, respectively. The minimum future lease payments under these operating leases as of December 31, 2009, are as follows (in thousands):

Year ending December 31,
2010	$	9,170
2011		6,383
2012		6,597
2013		7,116
2014		7,177
2015 and thereafter		22,924
	$	59,367

SMR Transaction

        On September 1, 2009, the Partnership entered into a hydrogen supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the hydrogen processed by the SMR (see Note 6 for further discussion of this agreement and the related SMR Transaction). The hydrogen received under this agreement will be sold to a refinery customer pursuant to a corresponding long-term agreement. The minimum amounts payable annually under the hydrogen

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21. Commitments and Contingencies (Continued)

supply agreement, excluding the potential impact of inflation adjustments per the agreement, are as follows (in thousands):

Year ending December 31,
2010	$	14,510
2011		17,412
2012		17,412
2013		17,412
2014		17,412
2015 and thereafter		264,082
Total minimum payments		348,240
Less: Services element		140,956
Less: Interest		112,074
Less: Current portion of SMR Liability		1,434
Long-term portion of SMR Liability	$	93,776

22. Incentive Compensation Plans

        As of December 31, 2009, the Partnership had three share-based compensation plans which are administered by the Compensation Committee of the General Partner's board of directors ("Compensation Committee").

Share-based compensation plan	Plan qualification under SFAS 123R	Further awards authorized for issuance under plan
2008 Long-Term Incentive Plan ("2008 LTIP")	Equity awards	Yes
2006 Hydrocarbon Stock Incentive Plan ("2006 Hydrocarbon Plan")	Equity awards	No
Long-Term Incentive Plan ("2002 LTIP")	Liability awards	No

        As of December 31, 2008, the Partnership had a fourth share-based compensation plan: the 1996 Hydrocarbon Stock Incentive Plan ("1996 Hydrocarbon Plan"). The 1996 Hydrocarbon Plan awards qualified as equity awards. The last awards issued under the 1996 Hydrocarbon Plan vested in 2009 and there were no further awards authorized for issuance; therefore, the 1996 Hydrocarbon Plan was no longer active as of December 31, 2009.

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22. Incentive Compensation Plans (Continued)

Compensation Expense

        Total compensation expense recorded for share-based pay arrangements was as follows (in thousands):

	Year ended December 31,
	2009		2008		2007
Phantom units	$	7,448	$	11,348	$	2,080
Distribution equivalent rights(1)		1,324		701		235
Restricted stock		—		75		780
Stock options		—		—		(27	)
General partner interests under Participation Plan		—		5,470		17,704
Total compensation expense	$	8,772	$	17,594	$	20,772

(1)

A distribution equivalent right is a right, granted in tandem with a specific phantom unit, to receive an amount in cash equal to, and at the same time as, the cash distributions made by the Partnership with respect to a unit during the period such phantom unit is outstanding. Payment of distribution equivalent rights associated with units that are expected to vest are recorded as capital distributions, however, payments associated with units that are not expected to vest are recorded as compensation expense.

        Compensation expense under the share-based compensation plans has been recorded as either Selling, general and administrative expenses or Facility expenses in the accompanying Consolidated Statements of Operations.

        As of December 31, 2009, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP and 2006 Hydrocarbon Plan was approximately $14.3 million, with a weighted average remaining vesting period of approximately 1.0 year. Total compensation expense not yet recognized related to unvested awards under the 2002 LTIP was approximately $0.4 million, with a weighted-average remaining vesting period of approximately 0.4 years. The actual compensation expense recognized for awards under the 2002 LTIP may differ as they qualify as liability awards, which are affected by changes in fair value.

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22. Incentive Compensation Plans (Continued)

Summary of Equity Awards

        Awards under the 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan qualify as equity awards. Accordingly, the fair value is measured at the grant date using the market price of the Partnership's common units. A phantom unit entitles an employee to receive a common unit upon vesting. The Partnership generally issues new common units upon vesting of phantom units. Compensation expense related to service-based awards is recognized over the requisite service period, reduced for an estimate of expected forfeitures. Phantom units generally vest equally over a three-year period. Compensation expense related to performance-based awards is recognized when probability of vesting is established, as discussed below. As part of a net settlement option, employees may elect to surrender a certain number of phantom units, and in exchange, the Partnership will assume the income tax withholding obligations related to the vesting. Phantom units surrendered for the payment of income tax withholdings will again become available for issuance under the plan from which the awards were initially granted, provided that further awards are authorized for issuance under the plan. The Partnership was required to pay approximately $1.1 million, $0.1 million and zero during the years ended December 31, 2009, 2008 and 2007, respectively, for income tax withholdings related to the vesting of equity awards. The Partnership received no proceeds from the issuance of phantom units, and none of the phantom units that vested were redeemed by the Partnership for cash.

2008 LTIP

        The 2008 LTIP was approved by unitholders on February 21, 2008. The 2008 LTIP provides 2.5 million common units for issuance to the Corporation's employees and affiliates as share-based payment awards. The 2008 LTIP was created to attract and retain highly qualified officers, directors, and other key individuals and to motivate them to serve the General Partner, the Partnership and their affiliates and to expend maximum effort to improve the business results and earnings of the Partnership and its affiliates. Awards authorized under the 2008 LTIP include unrestricted units, restricted units, phantom units, distribution equivalent rights, and performance awards to be granted in any combination.

        Phantom units containing performance vesting criteria ("Performance Units") have been granted to senior executives and other key employees under the 2008 LTIP. The Performance Units vest on a performance-based schedule generally over a three-year period, and vesting of these units occurs if the Partnership achieves established performance goals determined by the Compensation Committee. Management will conduct a quantitative analysis on an ongoing basis to assess the probability of meeting the established performance goals and will record compensation expense as required. As of December 31, 2009, there were 437,100 Performance Units outstanding with a grant date fair value of $10.6 million. Compensation expense recorded for the Performance Units expected to vest was approximately $0.5 million and $4.1 million for the years ended December 31, 2009 and 2008, respectively.

2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan

        On February 21, 2008, the 25,897 outstanding shares of restricted stock held by 43 employees and directors granted under the 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan were converted to 49,354 phantom units in connection with the Merger. The conversion qualified as a modification, requiring the Partnership to compare the grant date fair value of the original awards with the converted

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22. Incentive Compensation Plans (Continued)

awards. As a result of the comparison, the Partnership determined that the fair value of the awards had increased by $0.5 million. Approximately $0.4 million of the fair value was expensed in the first quarter of 2008; the remaining $0.1 million will be amortized as compensation expense over the remaining vesting period of less than one year. The converted phantom unit awards remain outstanding under the terms of the 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan until their respective settlement dates. There are no converted phantom units outstanding under the 1996 Hydrocarbon Plan as of December 31, 2009.

        The following is a summary of phantom unit activity under the 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan:

		Number of Units			Weighted-average Grant-date Fair Value
Unvested at January 1, 2008			—		$	—
	Granted(1)(2)		928,685			31.78
	Vested		(17,274	)		31.79
	Forfeited		(2,105	)		25.92
Unvested at December 31, 2008			909,306			31.80
	Granted(2)		442,035			8.64
	Vested(3)		(309,052	)		31.93
	Forfeited(4)		(65,048	)		20.96
Unvested at December 31, 2009			977,241			22.00

(1)

Includes 49,354 restricted shares converted to phantom units pursuant to the terms of the redemption and merger agreement.

(2)

Includes 463,500 and 154,500 Performance Units granted in 2008 and 2009, respectively.

(3)

Includes 144,550 Performance Units.

(4)

Includes 36,350 Performance Units.

	Year ended December 31,
	2009		2008		2007
	(in thousands)
Total grant-date fair value of phantom units granted during the period	$	3,819	$	29,516	$	822
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period	$	9,867	$	549	$	406

2002 LTIP

        As of December 31, 2009, there were 69,555 phantom units outstanding under the 2002 LTIP; no additional awards will be made under the plan. The phantom units awarded under the 2002 LTIP are classified as liability awards. Accordingly, the fair value of the outstanding awards is re-measured at the end of each reporting period using the market price of the Partnership's common units. The fair value

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22. Incentive Compensation Plans (Continued)

of the phantom units awarded is amortized into earnings as compensation expense over the vesting period, which is generally three years. A phantom unit entitles an employee to receive a common unit upon vesting, or at the discretion of the Compensation Committee, the cash equivalent to the value of a common unit. The Partnership generally issues new common units upon the vesting of phantom units. As part of a net settlement option, employees may elect to surrender a certain number of phantom units, and in exchange, the Partnership will assume the income tax withholding obligations related to the vesting. The Partnership received no proceeds (other than the contributions by the General Partner to maintain its 2% ownership interest prior to the Merger) for issuing phantom units and none of the phantom units that vested were redeemed by the Partnership for cash. The amounts paid by the Partnership for income tax withholdings related to the vesting of awards under the 2002 LTIP were $0.2 million for the year ended December 31, 2009 and near or at zero for the years ended December 31, 2008 and 2007.

        The following is a summary of phantom unit activity under the 2002 LTIP:

		Number of Units			Weighted-average Grant-date Fair Value
Unvested at January 1, 2007			125,200		$	24.14
	Granted		54,716			31.62
	Vested		(40,912	)		23.50
	Forfeited		(13,754	)		25.93
Unvested at December 31, 2007			125,250			27.42
	Granted		78,540			34.00
	Vested		(57,214	)		26.11
	Forfeited		(649	)		33.64
Unvested at December 31, 2008			145,927			31.45
	Granted		—			—
	Vested		(69,652	)		29.94
	Forfeited		(6,720	)		33.64
Unvested at December 31, 2009			69,555			32.75

	Year ended December 31,
	2009		2008		2007
	(in thousands)
Total grant-date fair value of phantom units granted during the period	$	—	$	2,670	$	1,730
Total fair value of phantom units vested during the period and total intrinsic value of phantom units settled during the period	$	920	$	1,943	$	1,281

Participation Plan

        The interests in the Partnership's General Partner sold by the Corporation to certain directors and employees were referred to as the Participation Plan. The Participation Plan was considered a compensatory arrangement and the General Partner interests were classified as liability awards. As a

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. Incentive Compensation Plans (Continued)

result, the Corporation was required to calculate the fair value of the General Partner interests at the end of each period. In conjunction with the Merger, all of the outstanding interests in the General Partner were acquired for a combination of 0.9 million common units with a fair value of approximately $30.1 million and approximately $21.5 million in cash.

Hydrocarbon Stock Options

        On or before February 21, 2008, the remaining 51,509 Hydrocarbon stock options outstanding were exercised or deemed exercised. The following summarizes the impact of the Corporation's stock options (in thousands):

	Year ended December 31,
	2008		2007
Options exercised, cashless		1		1
Shares issued, cashless		1		1
Options exercised, cash		50		13
Shares issued, cash		50		13

        A summary of the status of the Corporation's stock option plan as of December 31, 2008 and 2007 is presented below.

		Number of Shares			Weighted-average Exercise Price
Outstanding at January 1, 2007			65,635		$	7.48
	Exercised		(14,126	)		8.46
Outstanding at December 31, 2007			51,509			7.21
	Exercised		(51,509	)		7.21
Outstanding at December 31, 2008			—			—

        For the years ended December 31, 2008 and 2007, the Corporation received $0.4 million and $0.1 million, respectively, for the exercise of stock options. The intrinsic value of the options exercised during the years ended December 31, 2008 and 2007 was $2.9 million and $0.7 million, respectively. The fair value of the options vesting for the years ended December 31, 2008 and 2007 was zero.

APIC Pool

        The Partnership elected to adopt the simplified method to establish the beginning balance of the additional paid-in capital pool ("APIC Pool") related to the tax effects of employee share-based compensation, and to determine the subsequent impact on the APIC Pool and Consolidated Statements of Cash Flows of the tax effects of share-based compensation awards that were outstanding upon adoption. APIC is reported as common units in the accompanying Consolidated Balance Sheets as a result of the Merger.

        Cash flows resulting from tax deductions in excess of the cumulative compensation cost recognized for share-based compensation awards exercised are classified as financing cash flows. Previously, all tax benefits from awards had been reported as an operating activity. The Partnership recognized

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22. Incentive Compensation Plans (Continued)

$0.7 million and $0.3 million for the years ended December 31, 2008 and 2007, respectively, related to excess tax benefits realized from the exercise of share-based compensation awards.

23. Employee Benefit Plan

        All employees dedicated to, or otherwise principally supporting the Partnership are employees of MarkWest Hydrocarbon, and substantially all of these employees are participants in MarkWest Hydrocarbon's defined contribution benefit plan. The employer matching contribution expense related to this plan was $1.8 million, $1.6 million and $1.1 million for the years ended December 31, 2009, 2008 and 2007, respectively.

24. Income Tax

        The components of the provision for income tax (benefit) expense are as follows (in thousands):

		Year ended December 31,
		2009			2008		2007
Current income tax expense:
	Federal	$	6,525		$	12,947	$	22,386
	State		1,547			2,085		1,483
	Total current		8,072			15,032		23,869
Deferred income tax (benefit) expense:
	Federal		(43,409	)		50,129		(45,029	)
	State		(6,679	)		3,669		(3,489	)
	Total deferred		(50,088	)		53,798		(48,518	)
Provision for income tax (benefit) expense		$	(42,016	)	$	68,830	$	(24,649	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

24. Income Tax (Continued)

        A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate of 35% to the income before income taxes for the years ended December 31, 2009 and 2008 is as follows (in thousands):

Year ended December 31, 2009:

		Corporation			Partnership			Eliminations			Consolidated
Loss before provision for income tax		$	(112,506	)	$	(32,800	)	$	(10,064	)	$	(155,370	)
Federal Statutory Rate			35	%		0	%		0	%
Federal income tax at statutory rate			(39,377	)		—			—			(39,377	)
Permanent items			1			—			—			1
State income taxes net of federal benefit			(4,186	)		(1,439	)		—			(5,625	)
Current year change in valuation allowance			1,562			—			—			1,562
Tax rate changes			1,497			—			—			1,497
Provision on income from Class A units(1)			(525	)		—			—			(525	)
Write-off of deferred income tax assets			293			—			—			293
Other			158			—			—			158
	Provision for income tax benefit	$	(40,577	)	$	(1,439	)	$	—		$	(42,016	)
Effective tax rate												27.0	%

Year ended December 31, 2008:

		Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax		$	101,146		$	174,702		$	(2,246	)	$	273,602
Federal Statutory Rate			35	%		0	%		0	%
Federal income tax at statutory rate			35,401			—			—			35,401
Permanent items			(116	)		—			—			(116	)
State income taxes net of federal benefit			2,433			1,617			—			4,050
Current year change in valuation allowance			(120	)		—			—			(120	)
Provision on income from Class A units(1)			22,484			—			—			22,484
Write-off of deferred income tax assets(2)			7,471			—			—			7,471
Other			(340	)		—			—			(340	)
	Provision for income tax expense	$	67,213		$	1,617		$	—		$	68,830
Effective tax rate												25.2	%

(1)

The Corporation pays tax on its share of the Partnership's income or loss as a result of its ownership of Class A units as discussed in Note 2.

(2)

Represents the write-off of certain deferred tax assets that as an indirect result of the Merger will no longer be realized.

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24. Income Tax (Continued)

        A reconciliation of the actual income tax benefit and the amount computed by applying the federal statutory rate of 35% to the loss before provision for income tax for the year ended December 31, 2007 (before Merger) is as follows (in thousands):

Federal income tax at statutory rate		$	(22,404	)
Permanent items			12
State income taxes net of federal benefit—Corporation			(1,797	)
State income taxes—Energy			168
Current year change in valuation allowance			(387	)
Provision on income from Class A units			168
Other			(409	)
	Provision for income tax benefit	$	(24,649	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

24. Income Tax (Continued)

        The deferred tax assets and liabilities resulting from temporary book-tax differences are comprised of the following (in thousands):

		December 31,
		2009			2008
Current deferred tax assets
	Accruals and reserves	$	66		$	99
	Derivative instruments		12,172			—
	Current deferred tax assets		12,238			99
Current deferred tax liabilities
	Derivative instruments		10			2,781
	Current deferred tax liabilities		10			2,781
Current subtotal			12,228			(2,682	)
Long-term deferred tax assets
	Accruals and reserves		2			295
	Derivative instruments		15,585			—
	Uncertain tax positions liability		8			247
	Phantom unit compensation		1,165			840
	Capital loss carryforward		1,571			—
	State net operating loss carryforward		211			30
Long-term deferred tax assets			18,542			1,412
	Valuation allowance		(1,688	)		(30	)
Net long-term deferred tax assets			16,854			1,382
Long-term deferred tax liabilities
	Property, plant and equipment		3,344			5,187
	Phantom unit compensation		29			25
	Investment in consolidated subsidiaries		24,484			37,644
	Derivative instruments		31			5,991
Long-term deferred tax liabilities			27,888			48,847
Long-term subtotal			(11,034	)		(47,465	)
Net deferred tax asset (liability)		$	1,194		$	(50,147	)

        Significant judgment is required in evaluating tax positions and determining the Corporation's provision for income taxes. During the ordinary course of business, there are many transactions and calculations for which the ultimate tax determination is uncertain. The Corporation establishes reserves for uncertain tax positions based on estimates of whether, and the extent to which, additional taxes will be due. These reserves are established when the Corporation believes that certain positions might be challenged despite the Corporation's belief that its tax return positions are fully supportable. The Corporation adjusts these reserves in light of changing facts and circumstances, such as the outcome of tax audits. The provision for income taxes includes the impact of reserve provisions and changes to reserves that are considered appropriate.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

24. Income Tax (Continued)

        The reconciliation of the Corporation's accrual for uncertain tax positions is as follows (in thousands):

	Year ended December 31,
	2009			2008			2007
Tax contingencies—beginning of period	$	247		$	747		$	378
Changes to current period tax positions		(239	)		(500	)		369
Tax contingencies—end of period	$	8		$	247		$	747

As of December 31, 2009, changes to the Corporation's uncertain tax positions that are reasonably possible in the next twelve months are not material. As of December 31, 2009, the Corporation's accrued interest and penalties related to uncertain tax positions of on the Consolidated Balance Sheets are not material.

        As of December 31, 2009, the Corporation had state net operating loss carryforwards of approximately $2.7 million that expire between 2011 and 2026. The Corporation expects that future taxable income will likely be apportioned to states other than those in which the net operating loss was generated. As a result, the Corporation believes it is more likely than not that the state net operating losses will not be realized and has provided a 100% valuation allowance against this long-term deferred tax asset. As of December 31, 2009, the Corporation had a capital loss carryforward of approximately $4.1 million that expires in 2014. While the Corporation's consolidated Federal tax return and any significant state tax returns are not currently under examination, the tax years 2006 through 2008 remain open to examination by the major taxing jurisdictions to which the Corporation is subject.

25. Earnings (Loss) Per Common Unit

        All unit and per unit data has been adjusted to reflect the Exchange Ratio to give effect to the Merger (see Note 3). The following is a reconciliation of the Corporation common stock outstanding during 2007 adjusted to reflect comparable units as a result of the Merger (in thousands):

	Year ended December 31, 2007
	Adjusted for Merger		As previously reported
Weighted average common units and shares of common stock, respectively, outstanding during the period		22,854		11,996
Effect of dilutive instruments		—		—
Weighted average common units and shares of common stock, respectively, outstanding during the period including the effects of dilutive instruments		22,854		11,996

146

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

25. Earnings (Loss) Per Common Unit (Continued)

        The following table shows the computation of basic and diluted net (loss) income per common unit, for the years ended December 31, 2009, 2008 and 2007, respectively, and the weighted-average units used to compute diluted net income (loss) per common unit (in thousands, except per unit data):

		Year ended December 31,
		2009			2008		2007
Net (loss) income attributable to the Partnership		$	(118,668	)	$	208,073	$	(39,359	)
Less: Income allocable to phantom units			1,518			3,037		—
Net (loss) income available for common unitholders		$	(120,186	)	$	205,036	$	(39,359	)
Weighted average common units outstanding—basic			60,957			51,013		22,854
Effect of dilutive instruments(1)			—			3		—
Weighted average common units outstanding—diluted			60,957			51,016		22,854
Net (loss) income attributable to the Partnership's common unitholders per unit
	Basic	$	(1.97	)	$	4.02	$	(1.72	)
	Diluted	$	(1.97	)	$	4.02	$	(1.72	)

(1)

The dilutive instruments for the year ended December 31, 2008 include MarkWest Hydrocarbon stock options outstanding prior to the Merger. For the year ended December 31, 2007, 111 units were excluded from the calculation of diluted units since phantom units and potential common units from the exercises of stock options were anti-dilutive.

26. Segment Information

        The Partnership's chief operating decision maker is the chief executive officer ("CEO"). The CEO reviews the Partnership's discrete financial information on a geographic and operational basis, as the products and services are closely related within each geographic region and business operation. Accordingly, the CEO makes operating decisions, assesses financial performance and allocates resources on a geographical basis. The Partnership has four segments: Southwest, Northeast, Gulf Coast and Liberty. The Southwest segment provides gathering, processing, transportation, and storage services. The Northeast segment provides gathering, processing, transportation, fractionation and storage services. The Gulf Coast segment provides processing, transportation, fractionation and storage services. The Liberty segment provides gathering, processing, transportation and storage services. The Liberty segment is a new segment beginning in 2009 and consists primarily of the operations in the Marcellus Shale region of western Pennsylvania and northern West Virginia. Because the Liberty operations may grow to become a larger portion of the Partnership's business, management believes that transparency to the Liberty segment will provide useful information to investors. There were no operations in the Liberty segment in 2007.

        The Partnership prepares segment information in accordance with GAAP, except that certain items below (Loss) income from operations in the accompanying 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 segments. Management does not consider these

147

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

26. Segment Information (Continued)

items allocable to or controllable by any individual segment and therefore excludes these items when evaluating segment performance. The 2009 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 and capital expenditures for the reported segments for the years ended December 31, 2009, 2008 and 2007 (in thousands).

Year ended December 31, 2009:

			Southwest		Northeast		Liberty		Gulf Coast		Total
Revenue			$	492,369	$	260,529	$	47,968	$	57,769	$	858,635
Operating expenses:
	Purchased product costs			221,021		175,326		12,479		—		408,826
	Facility expenses			73,621		20,339		16,268		16,094		126,322
Total operating expenses before items not allocated to segments				294,642		195,665		28,747		16,094		535,148
Portion of operating income attributable to non-controlling interests				2,613		—		6,637		—		9,250
	Operating income before items not allocated to segments		$	195,114	$	64,864	$	12,584	$	41,675	$	314,237
	Capital expenditures		$	236,705	$	21,538	$	181,142	$	40,606	$	479,991
	Capital expenditures not allocated to segments											6,632
		Total capital expenditures									$	486,623

Year ended December 31, 2008:

			Southwest		Northeast		Liberty		Gulf Coast		Total
Revenue			$	652,365	$	313,921	$	2,334	$	92,042	$	1,060,662
Operating expenses:
	Purchased product costs			387,516		228,386		—		—		615,902
	Facility expenses			62,369		20,869		2,006		17,368		102,612
	Operating income before items not allocated to segments		$	202,480	$	64,666	$	328	$	74,674	$	342,148
	Capital expenditures		$	354,457	$	40,443	$	109,104	$	66,065	$	570,069
	Capital expenditures not allocated to segments											5,229
		Total capital expenditures									$	575,298

148

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

26. Segment Information (Continued)

Year ended December 31, 2007:

			Southwest		Northeast		Gulf Coast		Total
Revenue			$	503,461	$	265,152	$	77,114	$	845,727
Operating expenses:
	Purchased product costs			310,888		177,004		—		487,892
	Facility expenses			44,045		16,347		10,471		70,863
		Operating income before items not allocated to segments	$	148,528	$	71,801	$	66,643	$	286,972
	Capital expenditures		$	295,223	$	2,988	$	14,441	$	312,652
	Capital expenditures not allocated to segments									3,987
		Total capital expenditures							$	316,639

149

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

26. Segment Information (Continued)

        The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the three years ended December 31, 2009, 2008 and 2007 (in thousands):

			Year ended December 31,
			2009			2008			2007
Total segment revenue			$	858,635		$	1,060,662		$	845,727
Derivative (loss) gain not allocated to segments				(120,352	)		277,828			(159,970	)
		Total revenue	$	738,283		$	1,338,490		$	685,757
Operating income before items not allocated to segments			$	314,237		$	342,148		$	286,972
	Portion of operating income attributable to non-controlling interests			9,250			—			—
	Derivative (loss) gain not allocated to segments			(188,862	)		254,813			(175,148	)
	Compensation expense included in facility expenses not allocated to segments			(1,032	)		(1,070	)		—
	Facility expenses elimination			377			—			—
	Selling, general and administrative expenses			(63,728	)		(68,975	)		(72,484	)
	Depreciation			(95,537	)		(67,480	)		(41,281	)
	Amortization of intangible assets			(40,831	)		(38,483	)		(16,672	)
	Loss on disposal of property, plant and equipment			(1,677	)		(178	)		(7,743	)
	Accretion of asset retirement obligations			(198	)		(129	)		(114	)
	Impairment of goodwill and long-lived assets			(5,855	)		(36,351	)		(356	)
		(Loss) income from operations		(73,856	)		384,295			(26,826	)
	Earnings from unconsolidated affiliates			3,505			90			5,309
	Impairment of unconsolidated affiliate			—			(41,449	)		—
	Gain on sale of unconsolidated affiliate			6,801			—			—
	Interest income			349			3,769			4,547
	Interest expense			(87,419	)		(64,563	)		(39,435	)
	Amortization of deferred financing costs and discount (a component of interest expense)			(9,718	)		(8,299	)		(2,983	)
	Derivative gain related to interest expense			2,509			—			—
	Miscellaneous income (expense), net			2,459			(241	)		233
		(Loss) income before provision for income tax	$	(155,370	)	$	273,602		$	(59,155	)

150

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

26. Segment Information (Continued)

        The tables below present information about segment assets as of December 31, 2009, 2008 and 2007 (in thousands):

As of December 31, 2009:		Southwest		Northeast		Liberty		Gulf Coast		Total
Total segment assets		$	1,637,749	$	249,804	$	373,127	$	587,830	$	2,848,510
Assets not allocated to segments:
	Certain cash and cash equivalents										73,184
	Fair value of derivatives										24,631
	Investment in unconsolidated affiliates										29,633
	Other(1)										38,779
Total assets										$	3,014,737

(1)

Includes corporate fixed assets, deferred financing costs, income tax receivable and other corporate assets not allocated to segments.

As of December 31, 2008:		Southwest		Northeast		Liberty		Gulf Coast		Total
Total segment assets		$	1,487,205	$	233,403	$	127,785	$	548,503	$	2,396,896
Assets not allocated to segments:
	Certain cash and cash equivalents										137
	Fair value of derivatives										182,338
	Investment in unconsolidated affiliates										46,092
	Other(1)										47,591
Total assets										$	2,673,054

(1)

Includes corporate fixed assets, income tax receivable and other corporate assets not allocated to segments.

As of December 31, 2007:		Southwest		Northeast		Gulf Coast		Total
Total segment assets		$	780,640	$	186,911	$	392,937	$	1,360,488
Assets not allocated to segments:
	Certain cash and cash equivalents								40,623
	Fair value of derivatives								14,855
	Investment in unconsolidated affiliates								58,709
	Other(1)								50,020
Total assets								$	1,524,695

(1)

Includes corporate fixed assets, insurance receivable and other corporate assets not allocated to segments.

151

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

27. Supplemental Condensed Consolidating Financial Information

        MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of December 31, 2009, the Partnership's obligations under the outstanding Senior Notes (see Note 19) were fully and unconditionally guaranteed, jointly and severally, by all of its wholly-owned subsidiaries. Separate financial statements for each of the Partnership's guarantor subsidiaries are not provided because such information would not be material to its investors or lenders. As of February 2009, following the closing of the joint venture with M&R, and May 2009, following the closing of the joint venture with ArcLight (see Note 4), MarkWest Liberty Midstream and MarkWest Pioneer together with certain of the Partnership's other subsidiaries that do not guarantee the outstanding Senior Notes have significant assets and operations in aggregate. For the purpose of the following financial information, the Partnership's investments in its subsidiaries and the guarantor subsidiaries' investments in their subsidiaries are presented in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the subsidiaries operated as independent entities. The operations, cash flows, and financial position of the Co-Issuer, MarkWest Energy Finance Corporation, are not material and therefore have been included with the Parent's financial information. Comparative financial statements have not been provided because the non-guarantor subsidiaries as of December 31, 2008 and 2007 were minor subsidiaries individually and in the aggregate. Condensed consolidating financial information for

152

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

27. Supplemental Condensed Consolidating Financial Information (Continued)

MarkWest Energy Partners and its combined guarantor and combined non-guarantor subsidiaries as of December 31, 2009 and for the year ended December 31, 2009 is as follows (in thousands):

Condensed Consolidating Balance Sheet

			As of December 31, 2009
			Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
	Cash and cash equivalents		$	—	$	74,448	$	23,304	$	—		$	97,752
	Receivables and other current assets			870		165,421		26,655		—			192,946
	Intercompany receivables			1,543,169		2,091		88		(1,545,348	)		—
	Fair value of derivative instruments			246		8,575		—		—			8,821
		Total current assets		1,544,285		250,535		50,047		(1,545,348	)		299,519
	Total property, plant and equipment, net			3,307		1,499,233		484,788		(5,684	)		1,981,644
Other long-term assets:
	Investment in unconsolidated affiliates			—		29,633		—		—			29,633
	Investment in consolidated affiliates			529,846		203,895		—		(733,741	)		—
	Intangibles, net of accumulated amortization			—		653,797		614		—			654,411
	Fair value of derivative instruments			—		15,810		—		—			15,810
	Intercompany notes receivable			210,060		—		—		(210,060	)		—
	Other long-term assets			20,538		13,182		—		—			33,720
		Total assets	$	2,308,036	$	2,666,085	$	535,449	$	(2,494,833	)	$	3,014,737
LIABILITIES AND PARTNERS' CAPITAL
Current liabilities:
	Intercompany payables		$	1,195	$	1,543,257	$	896	$	(1,545,348	)	$	—
	Fair value of derivative instruments			—		60,464		—		—			60,464
	Other current liabilities			28,673		149,319		47,527		—			225,519
		Total current liabilities		29,868		1,753,040		48,423		(1,545,348	)		285,983
Deferred income taxes				2,694		8,340		—		—			11,034
Intercompany notes payable				—		210,060		—		(210,060	)		—
Fair value of derivative instruments				—		62,519		—		—			62,519
Long-term debt, net of discounts				1,170,072		—		—		—			1,170,072
Other long-term liabilities				3,064		102,280		392		—			105,736
Partners' Capital:
	MarkWest Energy Partners, L.P. partners' capital			1,102,338		529,846		486,634		(1,022,164	)		1,096,654
	Non-controlling interest in consolidated subsidiaries			—		—		—		282,739			282,739
		Total partners' capital		1,102,338		529,846		486,634		(739,425	)		1,379,393
		Total liabilities and partners' capital	$	2,308,036	$	2,666,085	$	535,449	$	(2,494,833	)	$	3,014,737

153

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

27. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statement of Operations

			Year ended December 31, 2009
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Total revenue			$	—		$	686,340		$	51,943	$	—		$	738,283
Operating expenses:
	Purchased product costs			—			465,152			12,557		—			477,709
	Facility expenses			—			110,147			16,834		(377	)		126,604
	Selling, general and administrative expenses			46,317			17,990			2,878		(3,457	)		63,728
	Depreciation and amortization			559			124,976			10,984		(151	)		136,368
	Other operating expenses			(161	)		2,019			17		—			1,875
	Impairment of long-lived assets			—			—			5,855		—			5,855
		Total operating expenses		46,715			720,284			49,125		(3,985	)		812,139
		(Loss) income from operations		(46,715	)		(33,944	)		2,818		3,985			(73,856	)
Earnings from unconsolidated affiliates				—			3,505			—		—			3,505
Earnings from consolidated affiliates				2,243			1,501			—		(3,744	)		—
Gain on sale of unconsolidated affiliate				—			6,801			—		—			6,801
Other (expense) income, net				(69,951	)		(16,197	)		3,997		(9,669	)		(91,820	)
		(Loss) income before provision for income tax		(114,423	)		(38,334	)		6,815		(9,428	)		(155,370	)
Provision for income tax benefit				(1,439	)		(40,577	)		—		—			(42,016	)
		Net (loss) income		(112,984	)		2,243			6,815		(9,428	)		(113,354	)
Net income attributable to non-controlling interest				—			—			—		(5,314	)		(5,314	)
		Net (loss) income attributable to the Partnership	$	(112,984	)	$	2,243		$	6,815	$	(14,742	)	$	(118,668	)

154

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

27. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Cash Flows

			Year ended December 31, 2009
			Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities			$	(98,853	)	$	322,540		$	5,249		$	(5,835	)	$	223,101
Cash flows from investing activities:
	Capital expenditures			(1,688	)		(209,485	)		(281,285	)		5,835			(486,623	)
	Equity investments			(52,358	)		(127,806	)		—			179,759			(405	)
	Distributions from consolidated affiliates			13,984			31,227			—			(45,211	)		—
	Collection of intercompany notes receivable			21,340			—			—			(21,340	)		—
	Proceeds from the sale of unconsolidated affiliate			—			25,000			—			—			25,000
	Proceeds from disposal of property, plant and equipment			—			275			—			—			275
	Proceeds from sale of equity interest in consolidated subsidiary			—			62,500			—			(62,500	)		—
		Net cash flows (used in) provided by investing activities		(18,722	)		(218,289	)		(281,285	)		56,543			(461,753	)
Cash flows from financing activities:
	Proceeds from revolver			725,200			—			—			—			725,200
	Payments of revolver			(850,600	)		—			—			—			(850,600	)
	Proceeds from long-term debt			117,000			—			—			—			117,000
	Payments of intercompany notes receivable, net			—			(21,340	)		—			21,340			—
	Payments for debt issuance costs, deferred financing costs and registration costs			(8,054	)		(500	)		—			—			(8,554	)
	Contributions to wholly-owned subsidiaries, net			—			52,358			—			(52,358	)		—
	Contributions to joint ventures, net			(5,464	)		—			327,401			(127,401	)		194,536
	Proceeds from sale of equity interest in joint venture, net			(1,846	)		—			—			62,500			60,654
	Proceeds from SMR Transaction			—			73,129			—			—			73,129
	Proceeds from public offerings, net			178,565			—			—			—			178,565
	Share-based payment activity			(1,385	)		—			—			—			(1,385	)
	Payment of distributions			(155,307	)		(13,984	)		(31,382	)		45,211			(155,462	)
	Intercompany advances, net			119,466			(119,466	)		—			—			—
		Net cash flows provided by (used in) financing activities		117,575			(29,803	)		296,019			(50,708	)		333,083
Net increase in cash				—			74,448			19,983			—			94,431
Cash and cash equivalents at beginning of year				—			—			3,321			—			3,321
Cash and cash equivalents at end of year			$	—		$	74,448		$	23,304		$	—		$	97,752

155

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

28. Supplemental Cash Flow Information

        The following table provides information regarding supplemental cash flow information (in thousands):

		Year ended December 31,
		2009		2008		2007
Supplemental disclosures of cash flow information:
	Cash paid for interest, net of amounts capitalized	$	85,817	$	55,428	$	39,714
	Cash paid for income taxes		4,609		19,243		24,317
Supplemental schedule of non-cash investing and financing activities:
	Accrued property, plant and equipment	$	60,738	$	51,060	$	17,302
	Interest capitalized on construction in progress		12,228		9,486		3,344
	Property, plant and equipment asset retirement obligation		906		9		253
	Merger step-up of fair value		—		605,100		—
	Issuance of common units for vesting of share-based payment awards		9,402		2,492		1,687

29. Valuation and Qualifying Accounts

        Activity in the allowance for doubtful accounts is as follows (in thousands):

	Year ended December 31,
	2009			2008			2007
Balance at beginning of period	$	175		$	194		$	156
Charged to costs and expenses		12			(15	)		61
Other charges(1)		(25	)		(4	)		(23	)
Balance at end of period	$	162		$	175		$	194

(1)

Bad debts written off (net of recoveries).

        Activity in the deferred tax assets valuation allowance is as follows (in thousands):

	Year ended December 31,
	2009			2008			2007
Balance at beginning of period	$	30		$	53		$	802
Charged to costs and expenses		1,667			—			—
Other charges(1)		(9	)		(23	)		(749	)
Balance at end of period	$	1,688		$	30		$	53

(1)

Utilization of state net operating loss carryforward.

156

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

30. Quarterly Results of Operations (Unaudited)

        The following summarizes the Partnership's quarterly results of operations for 2009 and 2008 (in thousands, except per unit data):

		Three months ended
		March 31			June 30			September 30		December 31
2009
Total revenue		$	191,671		$	101,765		$	217,691	$	227,156
(Loss) income from operations			(19,108	)		(67,450	)		35,654		(22,952	)
Net (loss) income			(29,669	)		(69,196	)		11,904		(26,393	)
Net (loss) income attributable to the Partnership			(29,649	)		(67,506	)		8,280		(29,793	)
Net (loss) income attributable to the Partnership's common unitholders per common unit(1):
	Basic	$	(0.53	)	$	(1.18	)	$	0.13	$	(0.46	)
	Diluted	$	(0.53	)	$	(1.18	)	$	0.13	$	(0.46	)

		Three months ended
		March 31(3)		June 30			September 30		December 31
2008(2)
Total revenue		$	238,792	$	(34,433	)	$	566,371	$	567,760
Income (loss) from operations			49,361		(213,684	)		253,686		294,932
Net income (loss)			15,758		(177,767	)		186,668		180,113
Net income (loss) attributable to the Partnership			19,151		(177,767	)		186,546		180,143
Net income (loss) attributable to the Partnership's common unitholders per common unit(1)(3):
	Basic	$	0.54	$	(3.20	)	$	3.24	$	3.13
	Diluted	$	0.54	$	(3.20	)	$	3.24	$	3.13

(1)

Basic and diluted net (loss) income per unit are computed independently for each of the quarters presented; therefore, the sum of the quarterly earnings per unit may not equal the total computed for the year.

(2)

Quarterly results of operations for 2008 have been modified for the retrospective application of changes to GAAP related to the presentation of non-controlling interest and the calculation of earnings per share.

(3)

All historical per unit data has been adjusted to reflect the Exchange Ratio to give effect of the Merger.

31. Subsequent Events

        During January 2010, the Partnership terminated all of its outstanding interest rate swap contracts and realized a $2.3 million gain. As a result of the termination, the entire fair value of the interest rate swaps is reflected as a current asset in the Consolidated Balance Sheet at December 31, 2009 (see Note 7).

157

ITEM 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

        None.

ITEM 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

        An evaluation was performed under the supervision and with the participation of the Partnership's management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the 1934 Act, as of December 31, 2009. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer concluded that, as of December 31, 2009, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the 1934 Act is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

Management's Report on Internal Control Over Financial Reporting

        Management of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) of the 1934 Act. Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2009 based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. As a result of this assessment, management concluded that, as of December 31, 2009, our internal control over financial reporting was effective in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Limitations on Controls

        Our disclosure controls and procedures and internal control over financial reporting are designed to provide reasonable assurance of achieving their objectives as specified above. Management does not expect, however, that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all error and fraud. Any control system, no matter how well designed and operated, is based upon certain assumptions and can provide only reasonable, not absolute, assurance that its objectives will be met. Further, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not occur or that all control issues and instances of fraud, if any, within the Company have been detected.

Changes in Internal Control Over Financial Reporting

        There were no changes in our internal control over financial reporting during the quarter ended December 31, 2009 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

        Deloitte & Touche has independently assessed the effectiveness of our internal control over financial reporting and its report is included below.

158

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors of
MarkWest Energy GP, L.L.C.
Denver, Colorado

        We have audited the internal control over financial reporting of MarkWest Energy Partners, L.P., and subsidiaries (the "Partnership") as of December 31, 2009, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.

        We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

        A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

        Because of its inherent limitations, internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of effectiveness of the internal control over financial reporting to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

        In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.

        We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2009, of the Partnership and our report dated March 1, 2010 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
March 1, 2010

159

ITEM 9B.    Other Information

        None.

PART III

ITEM 10.    Directors, Executive Officers and Corporate Governance

        Information required to be set forth in Item 10. Directors, Executive Officers and Corporate Governance, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2010 Annual Meeting of Unitholders expected to be filed no later than April 30, 2010.

ITEM 11.    Executive Compensation

        Information required to be set forth in Item 11. Executive Compensation, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2010 Annual Meeting of Unitholders expected to be filed no later than April 30, 2010.

ITEM 12.    Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

        Information required to be set forth in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2010 Annual Meeting of Unitholders expected to be filed no later than April 30, 2010.

ITEM 13.    Certain Relationships and Related Transactions, and Director Independence

        Information required to be set forth in Item 13. Certain Relationships and Related Transactions, and Director Independence, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2010 Annual Meeting of Unitholders expected to be filed no later than April 30, 2010.

ITEM 14.    Principal Accountant Fees and Services

        Information required to be set forth in Item 14. Principal Accountant Fees and Services, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2010 Annual Meeting of Unitholders expected to be filed no later than April 30, 2010.

PART IV

ITEM 15.    Exhibits and Financial Statement Schedules

(a)

The following documents are filed as part of this report:

(1)

Financial Statements

You should read the Index to Consolidated Financial Statements included in Item 8 of this Form 10-K for a list of all financial statements filed as part of this report, which is incorporated herein by reference.

(2)

Financial Statement Schedules

All omitted schedules have been omitted because they are not required or because the required information is contained in the financial statements or notes thereto.

(3)

Exhibits

160

Exhibit Number			Description
	2.1	(11)	Agreement and Plan of Redemption and Merger dated September 5, 2007 by and among MarkWest Hydrocarbon, Inc., MarkWest Energy Partners, L.P. and MWEP, L.L.C.
	3.1	(1)	Certificate of Limited Partnership of MarkWest Energy Partners, L.P.
	3.2	(1)	Certificate of Formation of MarkWest Energy Operating Company, L.L.C.
	3.3	(2)	Amended and Restated Limited Liability Company Agreement of MarkWest Energy Operating Company, L.L.C., dated as of May 24, 2002.
	3.4	(1)	Certificate of Formation of MarkWest Energy GP, L.L.C.
	3.5	(2)	Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of May 24, 2002.
	3.6	(17)	Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated as of February 21, 2008.
	3.7	(31)	Amendment No. 1 to Amended and Restated Limited Liability Company Agreement MarkWest Energy GP, L.L.C., dated as of December 31, 2004.
	3.8	(31)	Amendment No. 2 to Amended and Restated Limited Liability Company Agreement MarkWest Energy GP, L.L.C., dated as of January 19, 2005.
	3.9	(31)	Amendment No. 3 to Amended and Restated Limited Liability Company Agreement MarkWest Energy GP, L.L.C., dated as of February 21, 2008.
	3.10	(31)	Amendment No. 4 to Amended and Restated Limited Liability Company Agreement MarkWest Energy GP, L.L.C., dated as of March 31, 2008.
	4.1	(4)	Indenture dated as of October 25, 2004, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee.
	4.2	(4)	Form of 6.875% Series A Senior Notes due 2014 with attached notation of Guarantees (incorporated by Reference to Exhibits A and D of Exhibit 4.2 hereto)
	4.3	(23)	First Supplemental Indenture, dated as of February 2, 2005, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee.
	4.4	(24)	Second Supplemental Indenture, dated as of January 17, 2006, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and Wells Fargo Bank, National Association, as Trustee.
	4.5	(25)	Third Supplemental Indenture, dated as of March 6, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.6	(25)	Fourth Supplemental Indenture, dated as of April 25, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.7	(25)	Fifth Supplemental Indenture, dated as of August 4, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.

161

Exhibit Number			Description
	4.8	(25)	Sixth Supplemental Indenture, dated as of September 15, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.9	(6)	Registration Rights Agreement dated as of July 6, 2006 among MarkWest Energy Partners, L.P., with MarkWest Energy Finance Corporation as the Issuers, the Guarantors named therein, and each of RBC Capital Markets Corporation, J.P. Morgan Securities Inc., Wachovia Capital Markets, LLC, A.G. Edwards & Sons, Inc., Credit Suisse Securities (USA) LLC, Fortis Securities LLC, Mizuho International plc, Piper Jaffray & Co. and SG Americas Securities, LLC collectively as Initial Purchasers.
	4.10	(6)	Indenture dated as of July 6, 2006, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.11	(6)	Form of 8.5% Series A and Series B Senior Notes due 2016 with attached notation of Guarantees (incorporated by Reference to Exhibits A and D of Exhibit 4.13 hereto.
	4.12	(25)	First Supplemental Indenture, dated as of March 6, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.13	(25)	Second Supplemental Indenture, dated as of April 25, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.14	(25)	Third Supplemental Indenture, dated as of August 4, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.15	(25)	Fourth Supplemental Indenture, dated as of September 15, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.16	(7)	Registration Rights Agreement dated as of October 20, 2006 among MarkWest Energy Partners, L.P., with MarkWest Energy Finance Corporation as the Issuers, the Guarantors named therein, and RBC Capital Markets as the Initial Purchaser.
	4.17	(17)	Registration Rights Agreement dated as of February 21, 2008 by and among MarkWest Energy Partners, L.P., John M. Fox and MWHC Holding, Inc.
	4.18	(17)	Registration Rights Agreement dated as of February 21, 2008 by and among MarkWest Energy Partners, L.P. and the holders named therein.
	4.19	(19)	Indenture dated as of April 15, 2008 among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the several guarantors named therein, and Wells Fargo Bank, N.A., as trustee.
	4.20	(19)	Form of 83/4% Series A and Series B Senior Notes due 2018 with attached notation of Guarantees (incorporated by reference to Exhibits A and D of Exhibit 4.26 hereto).

162

Exhibit Number			Description
	4.21	(19)	Registration Rights Agreement dated as of April 15, 2008 among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, and the several guarantors named therein, and J.P. Morgan Securities Inc., RBC Capital Markets Corporation, Wachovia Capital Markets, LLC, Banc of America Securities LLC, Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Fortis Securities LLC and SunTrust Robinson Humphrey,  Inc.
	4.22	(20)	Registration Rights Agreement dated as of May 1, 2008 among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, and the several guarantors named therein, and J.P. Morgan Securities Inc., RBC Capital Markets Corporation, Wachovia Capital Markets, LLC, Banc of America Securities LLC, Credit Suisse Securities (USA) LLC, Deutsche Bank Securities Inc., Fortis Securities LLC and SunTrust Robinson Humphrey,  Inc.
	4.23	(25)	First Supplemental Indenture, dated as of April 25, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.24	(25)	Second Supplemental Indenture, dated as of August 4, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.25	(25)	Third Supplemental Indenture, dated as of September 15, 2008, among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Guarantors named therein, and Wells Fargo Bank, National Association, as Trustee.
	4.26	(26)	Indenture dated as of May 26, 2009 among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the several guarantors named therein, and Wells Fargo Bank, N.A., as trustee.
	4.27	(26)	Form of 6.875% Series A and Series B Senior Notes due 2014 with attached notation of Guarantees (incorporated by reference to Exhibits A and D of Exhibit 4.33 hereto)
	4.28	(26)	Registration Rights Agreement dated May 26, 2009 by and among MarkWest Energy Partners L.P., MarkWest Energy Finance Corporation, and the several guarantors listed therein, and J.P. Morgan Securities Inc., RBC Capital Markets Corporation, Wachovia Capital Markets, LLC, Deutsche Bank Securities Inc., and U.S. Bancorp Investments, Inc.
	4.29	(27)	Indenture Release of Subsidiary Guarantor dated as of May 1, 2009, among MarkWest Energy Partners, L.P., and Wells Fargo Bank, N.A.
	4.30	(28)	Indenture Release of Subsidiary Guarantor dated as of October 31, 2009, among MarkWest Energy Partners, L.P. and Wells Fargo Bank, N.A.
	4.31	(4)	Registration Rights Agreement dated October 25, 2004, among MarkWest Energy Partners L.P., MarkWest Energy Finance Corporation, the Guarantors named therein and the Initial Purchasers named therein.
	10.1	(2)	Contribution, Conveyance and Assumption Agreement dated as of May 24, 2002, by and among MarkWest Energy Partners, L.P.; MarkWest Energy Operating Company, L.L.C.; MarkWest Energy GP, L.L.C.; MarkWest Michigan, Inc.; MarkWest Energy Appalachia, L.L.C.; West Shore Processing Company, L.L.C.; Basin Pipeline, L.L.C.; and MarkWest Hydrocarbon, Inc.

163

Exhibit Number			Description
	10.2	(2)	MarkWest Energy Partners, L.P. Long-Term Incentive Plan.
	10.3	(2)	First Amendment to MarkWest Energy Partners, L.P. Long-Term Incentive Plan.
	10.4	(2)	Omnibus Agreement dated of May 24, 2002, among MarkWest Hydrocarbon, Inc.; MarkWest Energy GP, L.L.C.; MarkWest Energy Partners, L.P.; and MarkWest Energy Operating Company, L.L.C.
	10.5	(2)+	Fractionation, Storage and Loading Agreement dated as of May 24, 2002, between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
	10.6	(2)+	Gas Processing Agreement dated as of May 24, 2002, by and between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
	10.7	(2)+	Pipeline Liquids Transportation Agreement dated as of May 24, 2002, by and between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
	10.8	(2)	Natural Gas Liquids Purchase Agreement dated as of May 24, 2002, by and between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
	10.9	(3)	Services Agreement dated January 1, 2004 between MarkWest Energy GP, L.L.C. and MarkWest Hydrocarbon, Inc.
	10.10	(5)D	Executive Employment Agreement effective September 5, 2007 between MarkWest Hydrocarbon, Inc. and Frank Semple.
	10.11	(8)	Office Lease Agreement, dated April 19, 2006, by and between Park Central Property LLC, the landlord, and MarkWest Energy Partners, L.P., the tenant.
	10.12	(9)+	Construction, Operation and Gas Gathering Agreement dated as of September 21, 2006 between MarkWest Western Oklahoma Gas Company, L.L.C. and Newfield Exploration Mid-Continent Inc.
	10.13	(5)D	Form of Executive Employment Agreement effective September 5, 2007 between MarkWest Hydrocarbon, Inc. and Nancy K. Buese, C. Corwin Bromley, John C. Mollenkopf and Randy S. Nickerson.
	10.14	(10)	Form of Indemnification Agreement between MarkWest Energy Partners, L.P., MarkWest Energy GP, L.L.C., and each Non-employee Director and the following Officers of the Company: Frank Semple, President and Chief Executive Officer; Nancy Buese, Senior Vice President and Chief Financial Officer; Randy Nickerson, Senior Vice President and Chief Commercial Officer; John Mollenkopf, Senior Vice President and Chief Operations Officer; C. Corwin Bromley, Senior Vice President, General Counsel and Secretary; David Young, Senior Vice President of Corporate Services; Richard Ostberg, Vice President of Risk and Compliance, and Andrew Schroeder, Vice President and Treasurer dated as of January 26, 2007.
	10.15	(11)	Exchange Agreement dated September 5, 2007 by and among MarkWest Energy Partners, L.P., MarkWest Hydrocarbon, Inc., and MarkWest Energy, GP L.L.C.
	10.16	(11)	Voting Agreement dated September 5, 2007 by and among MarkWest Energy Partners, L.P. and the Fox Family Holders.
	10.17	(14)+	Hydrogen Supply Agreement dated September 28, 2007, by and between MarkWest Blackhawk, L.P. and CITGO Refining and Chemicals Company L.P.

164

Exhibit Number			Description
	10.18	(12)	Amended and Restated Class B Membership Interest Contribution Agreement dated October 26, 2007 by and among MarkWest Energy Partners, L.P. and John M. Fox, Donald C. Heppermann, Frank M. Semple, Nancy K. Buese, Randy S. Nickerson, John C. Mollenkopf, C. Corwin Bromley, Andrew L. Schroeder, Jan Kindrick, Cindy Kindrick, Kevin Kubat and Art Denney as the Sellers.
	10.19	(13)	Amended and Restated Form of Indemnification Agreement dated October 26, 2007 by and between MarkWest Energy Partners, L.P., MarkWest Energy GP, L.L.C., and each non-employee director and executive officer of the General Partner, including the following named executive officers: Frank Semple, President and Chief Executive Officer; Nancy Buese, Senior Vice President and Chief Financial Officer; Randy Nickerson, Senior Vice President and Chief Commercial Officer; John Mollenkopf, Senior Vice President and Chief Operations Officer; C. Corwin Bromley, Senior Vice President, General Counsel and Secretary and Andrew Schroeder, Vice President and Treasurer.
	10.20	(16)+	Gas Processing Agreement dated as of November 1, 2007, by and between MarkWest Javelina Company and CITGO Refining and Chemicals Company, L.P.
	10.21	(15)+	Amendment to Gas Processing Agreement dated as of December 11, 2007, by and between MarkWest Javelina Company and CITGO Refining and Chemicals Company, L.P.
	10.22	(15)	Omnibus Termination Agreement dated as of November 16, 2007, by and between MarkWest Energy Appalachia, L.L.C. and Equitable Production Company and Equitable Gathering LLC.
	10.23	(16)+	Natural Gas Liquids Transportation, Fractionation, and Marketing Agreement dated as of November 16, 2007, by and between MarkWest Energy Appalachia, L.L.C. and Equitable Gathering LLC.
	10.24	(15)	Assignment and Bill of Sale and Assumption Agreement dated as of November 16, 2007, by and between MarkWest Energy Appalachia, L.L.C. and Equitable Production Company and Equitable Gathering LLC.
	10.25	(15)	Second Amendment to the Gas Processing Agreement dated as of December 26, 2007, by and between MarkWest Energy Appalachia, L.L.C. and MarkWest Hydrocarbon, Inc.
	10.26	(17)	Credit Agreement dated as of February 20, 2008 among MarkWest Energy Partners, L.P., Royal Bank of Canada as Administrative Agent and Collateral Agent, JPMorgan Chase Bank, N.A. and Wachovia Bank, National Association, as Co-Syndication Agents, Fortis Capital Corp., SunTrust Bank and U.S. Bank National Association, as Documentation Agents, RBC Capital Markets, as Sole Lead Arrangers and Sole Book Running Manager, and the lenders party thereto.
	10.27	(18)	MarkWest Energy Partners, L.P. 2008 Long-Term Incentive Plan.

165

Exhibit Number			Description
	10.28	(21)	Form of Second Amended and Restated Indemnification Agreement dated April 24, 2008 by and among MarkWest Energy Partners, L.P., MarkWest Energy GP, L.L.C., and each director and officer of MarkWest Energy GP, L.L.C., including the following named executive officers: Frank Semple, President and Chief Executive Officer; Nancy Buese, Senior Vice President and Chief Financial Officer; Randy Nickerson, Senior Vice President and Chief Commercial Officer; John Mollenkopf, Senior Vice President and Chief Operations Officer; and C. Corwin Bromley, Senior Vice President, General Counsel and Secretary.
	10.29	(21)	1996 Stock Incentive Plan for MarkWest Hydrocarbon, Inc.
	10.30	(21)	2006 Stock Incentive Plan for MarkWest Hydrocarbon, Inc.
	10.31	(22)+	Stiles/Britt Ranch Gas Gathering and Processing Agreement dated effective as of June 12, 2008 and executed August 5, 2008 between Newfield Exploration Mid-Continent Inc. and MarkWest Oklahoma Gas Company, L.L.C.
	10.32	(25)+	Natural Gas Liquids Purchase Agreement dated August 25, 2006 between ONEOK Hydrocarbon, L.P. and MarkWest Western Oklahoma Gas Company, L.L.C., now known as MarkWest Oklahoma Gas Company, L.L.C.
	10.33	(25)+	Raw Product Purchase Agreement dated February 11, 2005 between MarkWest Energy East Texas Gas Company, L.P., now known as MarkWest Energy East Texas Gas Company, L.L.C., and Dynegy Liquids Marketing and Trade, now known as Targa Liquids Marketing and Trade.
	10.34	(25)+	Amendment to the Natural Gas Liquids Purchase Agreement effective as of November 1, 2008 by and between MarkWest Oklahoma Gas Company, L.L.C. and ONEOK Hydrocarbon, L.P.
	10.35	(29)	First Amendment to Credit Agreement entered into as of January 28, 2009, among MarkWest Energy Partners, L.P., the guarantors party thereto, Royal Bank of Canada, as Administrative Agent and Collateral Agent and as L/C Issuer, the Agents party thereto, and the lenders party thereto.
	10.36	(30)+	Contribution Agreement dated as of January 22, 2009 by and among MarkWest Liberty Gas Gathering, L.L.C., M&R MWE Liberty, LLC, and MarkWest Liberty Midstream & Resources, L.L.C.
	10.37	(30)+	Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources, L.L.C. dated as of February 27, 2009.
	10.38	(32)+	Letter Agreement dated August 10, 2009 between MarkWest Liberty Gas Gathering, L.L.C. and M&R MWE Liberty, LLC.
	10.39	*+	Second Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources, L.L.C. dated as of November 1, 2009.
	10.40	*	Amendment No. 1 to Second Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources, L.L.C. dated as of November 20, 2009.
	10.41	*+	Amendment to the Raw Product Purchase Agreement effective as of December 1, 2009 by and between Targa Liquids Marketing and Trade and MarkWest Energy East Texas Gas Company, L.L.C.

166

Exhibit Number			Description
	12.1	*	Computation of Ratio of Earnings to Fixed Charges
	21.1	*	List of subsidiaries
	23.1	*	Consent of Deloitte & Touche LLP
	31.1	*	Chief Executive Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act
	31.2	*	Chief Financial Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act
	32.1	*	Certification of Chief Executive Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	32.2	*	Certification of Chief Financial Officer of the General Partner pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(1)

Incorporated by reference to the Registration Statement (No. 33-81780) on Form S-1 filed January 31, 2002.

(2)

Incorporated by reference to the Current Report on Form 8-K filed June 7, 2002.

(3)

Incorporated by reference to the Annual Report on Form 10-K filed March 15, 2004.

(4)

Incorporated by reference to the Current Report on Form 8-K filed October 25, 2004.

(5)

Incorporated by reference to the Current Report on Form 8-K filed September 11, 2007.

(6)

Incorporated by reference to the Current Report on Form 8-K filed July 7, 2006.

(7)

Incorporated by reference to the Current Report on Form 8-K filed October 24, 2006.

(8)

Incorporated by reference to the Current Report on Form 8-K filed April 25, 2006.

(9)

Incorporated by reference to the Quarterly Report on Form 10-Q filed November 7, 2006.

(10)

Incorporated by reference to the Annual Report on Form 10-K filed March 7, 2007.

(11)

Incorporated by reference to the Current Report on Form 8-K filed September 6, 2007.

(12)

Incorporated by reference to the Current Report on Form 8-K filed November 13, 2007.

(13)

Incorporated by reference to the Current Report on Form 8-K filed November 1, 2007.

(14)

Incorporated by reference to the Quarterly Report on Form 10-Q filed November 8, 2007.

(15)

Incorporated by reference to the Annual Report on Form 10-K filed February 29, 2008.

(16)

Incorporated by reference to the Annual Report on Form 10-K/A filed May 8, 2008.

(17)

Incorporated by reference to the Current Report on Form 8-K filed February 21, 2008.

(18)

Incorporated by reference to the Form S-4/A Registration Statement filed December 21, 2007.

(19)

Incorporated by reference to the Current Report on Form 8-K filed April 15, 2008.

(20)

Incorporated by reference to the Current Report on Form 8-K filed May 1, 2008.

(21)

Incorporated by reference to the Quarterly Report on Form 10-Q filed August 11, 2008.

(22)

Incorporated by reference to the Quarterly Report on Form 10-Q filed November 10, 2008.

(23)

Incorporated by reference to the Form S-4 Registration Statement filed February 22, 2005.

167

(24)

Incorporated by reference to the Form S-4/A Registration Statement filed January 17, 2006.

(25)

Incorporated by reference to the Annual Report on Form 10-K filed March 2, 2009.

(26)

Incorporated by reference to the Current Report on Form 8-K filed May 27, 2009.

(27)

Incorporated by reference to the Quarterly Report on Form 10-Q filed August 10, 2009.

(28)

Incorporated by reference to the Registration Statement on Form S-3 filed January 13, 2010.

(29)

Incorporated by reference to the Quarterly Report on Form 10-Q filed May 11, 2009.

(30)

Incorporated by reference to the Quarterly Report on Form 10-Q/A filed October 16, 2009.

(31)

Incorporated by reference to the Form S-4 Registration Statement filed July 2, 2009.

(32)

Incorporated by reference to the Quarterly Report on Form 10-Q filed November 9, 2009.

+

Application has been made to the Securities and Exchange Commission for confidential treatment of certain provisions of these exhibits. Omitted material for which confidential treatment has been requested and has been filed separately with the Securities and Exchange Commission.

*

Filed herewith.

D

Identifies each management contract or compensatory plan or arrangement.

(b)

The following exhibits are filed as part of this report: See Item 15(a)(2) above.

(c)

The following financial statement schedules are filed as part of this report: None required.

168

SIGNATURES

        Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

	MarkWest Energy Partners, L.P.             (Registrant)
	By:	MarkWest Energy GP, L.L.C.,
	Its	General Partner
Date: March 1, 2010	By:	/s/ FRANK M. SEMPLE Frank M. Semple Chairman, President and Chief Executive Officer (Principal Executive Officer)

        Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities with MarkWest Energy GP, L.L.C., the General Partner of MarkWest Energy Partners, L.P., the Registrant, and on the dates indicated.

Date: March 1, 2010	By:	/s/ FRANK M. SEMPLE Frank M. Semple Chairman, President and Chief Executive Officer (Principal Executive Officer)
Date: March 1, 2010	By:	/s/ NANCY K. BUESE Nancy K. Buese Senior Vice President and Chief Financial Officer (Principal Financial Officer and Principal Accounting Officer)
Date: March 1, 2010	By:	/s/ DONALD D. WOLF Donald D. Wolf Lead Director
Date: March 1, 2010	By:	/s/ KEITH E. BAILEY Keith E. Bailey Director
Date: March 1, 2010	By:	/s/ MICHAEL L. BEATTY Michael L. Beatty Director

169

Date: March 1, 2010	By:	/s/ CHARLES K. DEMPSTER Charles K. Dempster Director
Date: March 1, 2010	By:	Anne E. Fox Mounsey Director
Date: March 1, 2010	By:	/s/ DONALD C. HEPPERMANN Donald C. Heppermann Director
Date: March 1, 2010	By:	/s/ WILLIAM A. KELLSTROM William A. Kellstrom Director
Date: March 1, 2010	By:	/s/ WILLIAM P. NICOLETTI William P. Nicoletti Director

170

EX-10.39

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Exhibit 10.39

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT FOR THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPERATELY FILED WITH THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH TWO ASTERISKS (**).

SECOND

AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT

of

MARKWEST LIBERTY MIDSTREAM & RESOURCES, L.L.C.

Dated as of November 1, 2009

TABLE OF CONTENTS

			Page
ARTICLE 1 DEFINED TERMS			1
	Section 1.1	Definitions	1
ARTICLE 2 FORMATION AND TERM			13
	Section 2.1	Formation	13
	Section 2.2	Name	13
	Section 2.3	Term	13
	Section 2.4	Registered Agent and Office	13
	Section 2.5	Principal Place of Business	13
	Section 2.6	Qualification in Other Jurisdictions	14
ARTICLE 3 PURPOSE AND POWERS OF THE COMPANY			14
	Section 3.1	Purpose	14
	Section 3.2	Powers of the Company	14
	Section 3.3	Projects, Restricted Projects, Exempted Projects and Out of Scope Projects	14
ARTICLE 4 CAPITAL CONTRIBUTIONS, MEMBER INTERESTS, CAPITAL ACCOUNTS AND FUTURE CAPITAL REQUIREMENTS			16
	Section 4.1	Capital Contributions	16
	Section 4.2	Capital Contribution Defaults	20
	Section 4.3	Member's Interest	20
	Section 4.4	Status of Capital Contributions	20
	Section 4.5	Capital Accounts	21
	Section 4.6	Capital Accounts Generally	21
	Section 4.7	Preferred Return	21
	Section 4.8	Investment Accounts	21
	Section 4.9	Equalization Target Date	22
ARTICLE 5 MEMBERS, MEETINGS AND AMENDMENTS			23
	Section 5.1	Powers of Members	23
	Section 5.2	No Resignation or Expulsion	23
	Section 5.3	Additional Members	23
	Section 5.4	Confidentiality Obligations of Members	24
	Section 5.5	Initial Budget	25
	Section 5.6	Incentive Interests to MWE Liberty Upon Transfer of NGPMR's Interest	25
	Section 5.7	Preemptive Rights	25
	Section 5.8	Registration Rights	26
ARTICLE 6 MANAGEMENT			26
	Section 6.1	Management Under Direction of the Board	26
	Section 6.2	Number, Tenure and Qualifications	27
	Section 6.3	Votes Per Manager; Quorum; Required Vote for Board Action; Meetings of the Board	28
	Section 6.4	Power to Bind Company	29
	Section 6.5	Liability for Certain Acts	29
	Section 6.6	Manager Has No Exclusive Duty to Company	30
	Section 6.7	Resignation and Withdrawal	30
	Section 6.8	Removal	30
	Section 6.9	Vacancies	30
	Section 6.10	Delegation of Authority; Officers	30

i

			Page
	Section 6.11	Designation of Operator	30
	Section 6.12	Approval of Members	32
	Section 6.13	Reliance by Third Parties	34
	Section 6.14	Fees and Expenses of the Managers	34
	Section 6.15	Budgets	34
ARTICLE 7 ASSIGNABILITY OF MEMBER INTERESTS			36
	Section 7.1	Prohibition on Assignment During Project Period	36
	Section 7.2	Transfers After the Project Period	36
	Section 7.3	Recognition of Assignment by Company or Other Members	39
	Section 7.4	Effective Date of Assignment	39
	Section 7.5	Limitations on Transfer	39
	Section 7.6	Transferee Not a Substitute Member	40
ARTICLE 8 DISTRIBUTIONS TO MEMBERS			40
	Section 8.1	Available Cash	40
	Section 8.2	Incentive Interest Percentage Distributions	41
	Section 8.3	Withholding	41
	Section 8.4	Limitations on Distribution	41
	Section 8.5	Tax Distributions	41
ARTICLE 9 ALLOCATIONS			42
	Section 9.1	Profits and Losses	42
	Section 9.2	Special Allocations	42
	Section 9.3	Curative Allocations	43
	Section 9.4	Income Tax Allocations	44
	Section 9.5	Allocation and Other Rules	44
ARTICLE 10 BOOKS AND RECORDS			45
	Section 10.1	Inspection Rights Pursuant to Law	45
	Section 10.2	Books and Records	45
	Section 10.3	Financial Statements and Reports	45
	Section 10.4	Accounting Method	46
	Section 10.5	Bank Accounts; Investments	46
ARTICLE 11 TAX MATTERS			46
	Section 11.1	Taxation of Company	46
	Section 11.2	Tax Returns	46
	Section 11.3	Member Tax Return Information	46
	Section 11.4	Tax Matters Representative	46
	Section 11.5	Right to Make Section 754 Election	47
	Section 11.6	Tax Elections	47
	Section 11.7	Tax Reimbursement	47
ARTICLE 12 LIABILITY, EXCULPATION AND INDEMNIFICATION			47
	Section 12.1	Liability	47
	Section 12.2	Exculpation	48
	Section 12.3	Indemnification	48
	Section 12.4	Expenses	48
	Section 12.5	Insurance	49
	Section 12.6	Certain Liabilities	49
	Section 12.7	Acts Performed Outside the Scope of the Company	49
	Section 12.8	Liability of Members to Company or Other Members	49

ii

			Page
	Section 12.9	Attorneys' Fees	49
	Section 12.10	Subordination of Other Rights to Indemnity	49
	Section 12.11	Survival of Indemnity Provisions	49
ARTICLE 13 DISSOLUTION, LIQUIDATION AND TERMINATION			50
	Section 13.1	No Dissolution	50
	Section 13.2	Events Causing Dissolution	50
	Section 13.3	Notice of Dissolution	50
	Section 13.4	Liquidation	50
	Section 13.5	Termination	51
	Section 13.6	Claims of the Members or Third Parties	51
	Section 13.7	Distributions In-Kind	51
ARTICLE 14 REPRESENTATIONS, WARRANTIES AND COVENANTS			52
	Section 14.1	Representations, Warranties and Covenants	52
ARTICLE 15 MISCELLANEOUS			53
	Section 15.1	Notices	53
	Section 15.2	Failure to Pursue Remedies	53
	Section 15.3	Cumulative Remedies	53
	Section 15.4	Binding Effect	53
	Section 15.5	Interpretation	54
	Section 15.6	Severability	54
	Section 15.7	Counterparts	54
	Section 15.8	Integration	54
	Section 15.9	Amendment or Restatement	54
	Section 15.10	Governing Law	54
	Section 15.11	Dealings in Good Faith	54
	Section 15.12	Partition of the Property	55
	Section 15.13	Third Party Beneficiaries	55
	Section 15.14	Tax Disclosure Authorization	55
	Section 15.15	Waivers and Consents	55
	Section 15.16	Deadlocks; Negotiations	55
	Section 15.17	Dispute Resolution	56
	Section 15.18	Transaction Expenses	58

EXHIBITS:
Exhibit A	Area of Mutual Interest
Exhibit B	Members and Capital Contributions
Exhibit C	Base Project
Exhibit D	Initial Budget
Exhibit E	Illustrative Example Calculation of Incentive Interests
Exhibit F	[Reserved]
Exhibit G	Capital Expenditures for Agreements
Exhibit H	Pre-Approved Affiliated Transactions
Exhibit I	[Reserved]
Exhibit J	[Reserved]
Exhibit K	[Reserved]

iii

SECOND

AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT

OF

MARKWEST LIBERTY MIDSTREAM & RESOURCES, L.L.C.

        THIS SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT of MarkWest Liberty Midstream & Resources, L.L.C., a Delaware limited liability company (the "Company"), is executed and agreed to as of November 1, 2009, by and among MarkWest Liberty Gas Gathering, L.L.C., a Delaware limited liability company ("MWE Liberty"), M&R MWE Liberty, LLC, a Delaware limited liability company ("NGPMR"), and such other Persons who may become Members of the Company from time to time pursuant hereto.

        WHEREAS, MWE Liberty, as the then sole member of the Company, entered into that certain Limited Liability Company Agreement (the "Original Agreement") of the Company, dated as of January 20, 2009;

        WHEREAS, pursuant to Section 11 of the Original Agreement, the Original Agreement was amended and restated in its entirety as set forth in that certain Amended and Restated Limited Liability Company Agreement (the "First Amended Agreement") of the Company, dated as of February 27, 2009, and in connection therewith MWE Liberty and NGPMR became the sole Members of the Company;

        WHEREAS, contemporaneously with the execution of the First Amended Agreement and in order to effect the contribution of the cash consideration comprising NGPMR's initial Capital Contribution and the assets comprising MWE Liberty's initial Capital Contribution, the Company, MWE Liberty and NGPMR entered into that certain Contribution Agreement, dated January 22, 2009 (the "Contribution Agreement"), pursuant to which MWE Liberty agreed to contribute, convey, assign and transfer to the Company all of MWE Liberty's right, title and interest in and to the assets referenced thereunder;

        WHEREAS, contemporaneously with the execution of the First Amended Agreement and in order to provide for the provision of certain services to the Company, the Company, MWE Liberty and MarkWest Hydrocarbon, Inc., a Delaware corporation ("MWE Hydrocarbon") entered into that certain Services Agreement, dated February 27, 2009, (the "Services Agreement");

        WHEREAS, pursuant to Section 15.9 of the First Amended Agreement, the Company and the Members desire to amend and restate the First Amended Agreement in its entirety to, among other things, revise the amount and timing of the additional Capital Contributions that certain of the Members have agreed to make to the Company;

        NOW THEREFORE, in consideration of the foregoing and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the First Amended Agreement is hereby amended and restated in its entirety to read as follows:

ARTICLE 1
DEFINED TERMS

        Section 1.1    Definitions.    

        Unless the context otherwise requires, the terms defined in this Article I shall, for the purposes of this Agreement, have the meanings herein specified.

        "AAA" shall have the meaning set forth in Section 6.15(e).

        "Accountants" shall have the meaning set forth in Section 4.1(a)(iii).

        "Act" means the Delaware Limited Liability Company Act, 6 Del. C. §§ 18-101 et seq., as it may be amended from time to time, and any successor statute thereto.

        "Additional Member" shall have the meaning set forth in Section 5.3(a).

        "Additional Projects" shall have the meaning set forth in Section 3.3(a).

        "Adjusted Capital Account" means the Capital Account maintained for each Member (a) increased by any amounts the Member is obligated to contribute or restore to the Company pursuant to the penultimate sentences of Treasury Regulations Sections 1.704-2(g)(1) and 1.704-2(i)(5), and (b) decreased by any amounts described in Treasury Regulations Sections 1.704-1(b)(2)(ii)(d)(4), (5), or (6) with respect to such Member.

        "Adjusted Capital Account Deficit" means a deficit balance in the Adjusted Capital Account of a Member.

        "Affiliate" means with respect to a Person, any other Person that, directly or indirectly, Controls, is Controlled by, or is under Common Control with, the specified Person.

        "Affiliate Contract" means any contract between the Company or any Subsidiary of the Company, on the one hand, and a Member or an Affiliate of a Member, on the other hand.

        "Affiliated Member Group" means (a) the MWE Liberty Group, (b) the NGPMR Group and (c) any other Member and transferee of Interests directly or indirectly (in the chain of title) from such Member that is an Affiliate of such transferee Member; provided, however, that once a Person is designated as a member of any Affiliated Member Group, such Person shall, as long as it owns any Interests, at all times be a member of such Affiliated Member Group and not a member of any other Affiliated Member Group, and provided, further, that for purposes of this clause (c) of this definition, an Affiliate shall not include a member of the MWE Liberty Group or the NGPMR Group.

        "Agreement" means this Second Amended and Restated Limited Liability Company Agreement, as amended, modified, supplemented or restated from time to time.

        "Annual Financial Statements" shall have the meaning set forth in Section 10.3(a).

        "Approved Budget" shall have the meaning set forth in Section 6.15(b).

        "Arbitration Panel" shall have the meaning set forth in Section 6.15(e).

        "Area of Mutual Interest" means the area ** identified ** as Exhibit A.

        "Assumed Tax Liability" shall have the meaning set forth in Section 8.5(a).

        "Available Cash" means, with respect to any period prior to the dissolution of the Company, all cash and cash equivalents of the Company on hand at the end of such period less the amount of any cash reserves established by the Operator to provide for the proper conduct of the business of the Company, including reserves for: future capital expenditures; current, future or contingent liabilities; anticipated future credit needs of the Company; and debt service and repayments; provided that such reserves shall not equal less than ** as authorized in the Approved Budget nor more than ** in the Approved Budget, without the approval of the Board and Requisite Member Approval.

        "Base Project" shall have the meaning set forth in Section 3.3(a).

        "Board" shall have the meaning set forth in Section 6.1.

        "Budget Rejection Notice" shall have the meaning set forth in Section 6.15(b).

        "Business Day" means any day that is not a Saturday, Sunday or other day on which commercial banks are required or authorized by law to be closed in the State of Texas or the State of Colorado.

        "Capital Account" means, with respect to any Member, the capital account maintained for such Member in accordance with the provisions of Section 4.5.

2

        "Capital Call" means a call or request for additional capital in writing (which may include electronic mail) by or on behalf of the Company, specifying the amount of capital requested to be contributed by each Member receiving such notice in accordance with the terms of this Agreement.

        "Capital Contribution" means, with respect to any Member, the aggregate amount of cash and the initial Gross Asset Value of any property other than cash contributed to the Company pursuant to Article 4 hereof by such Member. Any reference in this Agreement to a Capital Contribution of a Member shall include a Capital Contribution contributed by its predecessors in interest.

        "Cash Capital Contribution" means, with respect to any Member, the aggregate amount of cash contributed to the Company by such Member disregarding (A) any Investment Balance credit pursuant to Section 4.1(b)(iv) and (B) any accrued Preference Amount.

        "Certificate" means the Certificate of Formation of the Company filed on behalf of the Company with the office of the Secretary of State of the State of Delaware pursuant to the Act on January 20, 2009, and any and all amendments thereto and restatements thereof.

        "Claims" shall have the meaning set forth in Section 6.5.

        "Class A Interest" means an Interest in the Company which is classified on Exhibit B as a Class A Interest and which has the rights, powers and privileges enjoyed by a Member holding a Class A Percentage Interest (under the Act, the Certificate, this Agreement or otherwise) in its capacity as a Member, and all obligations, duties and liabilities imposed on such a Member (under the Act, the Certificate, this Agreement or otherwise) in its capacity as a Member.

        "Class A Manager" shall have the meaning set forth in Section 6.2.

        "Class A Member" means a Member who is designated on Exhibit B as a Class A Member, in its capacity as a holder of a Class A Percentage Interest.

        "Class A Percentage Interest" means, with respect to a Class A Member, the quotient (expressed as a percentage) obtained by dividing such Class A Member's Investment Balance by the aggregate Investment Balances of all Class A Members.

        "Class B Interest" means an Interest in the Company which is classified on Exhibit B as a Class B Interest and which has the rights, powers and privileges enjoyed by a Member holding a Class B Percentage Interest (under the Act, the Certificate, this Agreement or otherwise) in its capacity as a Member, and all obligations, duties and liabilities imposed on such a Member (under the Act, the Certificate, this Agreement or otherwise) in its capacity as a Member.

        "Class B Manager" shall have the meaning set forth in Section 6.2.

        "Class B Member" means a Member who is designated on Exhibit B as a Class B Member, in its capacity as a holder of a Class B Percentage Interest.

        "Class B Percentage Interest" means, with respect to a Class B Member, the quotient (expressed as a percentage) obtained by dividing such Class B Member's Investment Balance by the aggregate Investment Balances of all Class B Members.

        "Class B Seller" shall have the meaning set forth in Section 7.2(b).

        "Code" means the Internal Revenue Code of 1986, as amended from time to time, or any corresponding federal tax statute enacted after the date of this Agreement.

        "Company" shall have the meaning set forth in the preamble.

        "Company Minimum Gain" shall have the meaning assigned to the term "partnership minimum gain" in Treasury Regulations Sections 1.704-2(b)(2) and 1.704-2(d).

3

        "Company Nonrecourse Liability" shall have the meaning assigned to the term "nonrecourse liability" in Treasury Regulations Section 1.704-2(b)(3)

** shall have the meaning set forth in Section 4.9(b).

** shall have the meaning set forth in Section 4.9(c).

        "Confidential Information" shall mean all information provided or made available by or on behalf of the Company or its Representatives to a Member or its Representatives, including all information, data, reports, interpretations, contract terms and conditions, forecasts and records containing or otherwise reflecting information concerning the Company or its Affiliates, potential counterparties or customers or their Affiliates, potential projects, business plans or proposals, market or economic data, identities of actual or potential counterparties or customers, designs, concepts, trade secrets and other business, operational or technical information (irrespective of the form of communication of such information) and together with analyses, compilations, studies or other documents, whether prepared by or on behalf of a Member or its Representatives, which contain or otherwise reflect such information (irrespective of the form of communication of such information). "Confidential Information" also includes information of third parties, including such information as may be subject to any Third Party Confidentiality Agreements. Notwithstanding the foregoing, Confidential Information shall not include the following: (a) information which at the time of disclosure by or on behalf of the Company is publicly available or which later becomes publicly available through no act or omission of the disclosing Member or its Representatives; (b) information which a Member can demonstrate was in its possession on a non-confidential basis prior to disclosure by or on behalf of the Company hereunder; (c) information received by a Member from a third party who is not prohibited from transmitting the information by a contractual, legal or fiduciary obligation; or (d) information which a Member can demonstrate was independently developed by it or for it and which was not derived or obtained, in whole or in part, from Confidential Information or from the Company or its Representatives hereunder.

        "Contributing Class A Member" shall mean a Class A Member who makes a Quarterly Budgeted Funding Election in accordance with Sections 4.1(c) or (d).

        "Contributing Class B Member" shall mean a Class B Member who makes a Quarterly Budgeted Funding Election in accordance with Section 4.1(d).

        "Contribution Agreement" shall have the meaning set forth in the recitals.

        "Control," including the correlative terms "Controlling," "Controlled by" and "Under Common Control with" means possession, directly or indirectly (through one or more intermediaries), of the power to direct or cause the direction of the management or policies (whether through ownership of securities or any partnership or other ownership interest, by contract or otherwise) of a Person. For the purposes of this definition, ownership of more than 50% of the voting interests of any entity shall be conclusive evidence that Control exists.

        "Covered Person" means, in each case, whether or not a Person continues to have the applicable status referred to in the following list: a Member; a Manager; the Operator; any Affiliate of a Member or a Manager or of the Operator; any officers of the Company, whether or not such officers are employees of the Company; any officers, directors, members, managers, stockholders, partners, employees, representatives or agents of any Manager or Member or of the Operator, or of any of their respective Affiliates; any employee or agent of the Company or its Affiliates; and any Tax Matters Member of the Company.

        "CP Index" means the United States Department of Labor, Bureau of Labor Statistics Consumer Price Index—All Urban Consumers, U.S. City Average, Not Seasonally Adjusted, or, if such index is

4

discontinued, any successor or substitute index, which, in the Board's reasonable opinion, is most nearly equivalent to such index.

        "Debt" for any Person means, without duplication: (a) indebtedness of such Person for borrowed money, including obligations under letters of credit and agreements relating to the issuance of letters of credit or acceptance financing; (b) obligations of such Person evidenced by bonds, debentures, notes, or other similar instruments; (c) obligations of such Person to pay the deferred purchase price of property or services (including, without limitation, obligations that are non-recourse to the credit of such Person but are secured by the assets of such Person, but excluding trade accounts payable); (d) obligations of such Person under capital leases; and (e) obligations of such Person under guarantees in respect of indebtedness or obligations of others of the kinds referred to in clauses (a) through (d) above; provided that "Debt" shall not include the incurrence of trade debt in the ordinary course of business.

        "Default Rate" means a per annum rate of interest equal to the lower of ** and the maximum rate of interest then permitted by law.

        "Defaulting Member" shall have the meaning set forth in Section 4.2.

        "Depreciation" means, for each Fiscal Year or other period, an amount equal to the depreciation, amortization or other cost recovery deduction allowable for federal income tax purposes with respect to an asset for such Fiscal Year or other period and in a manner consistent with the methodologies employed by MWE or otherwise determined by the Board; provided, however, that if the Gross Asset Value of an asset differs from its adjusted basis for federal income tax purposes at the beginning of such Fiscal Year or other period, Depreciation for such Fiscal Year or other period shall equal to the amount of book basis recovered for such Fiscal Year or other period under the rules prescribed by Treasury Regulation Section 1.704-3(d)(2) and provided further, that if the federal income tax depreciation, amortization or other cost recovery deduction for such Fiscal Year or other period is zero, Depreciation shall be determined with reference to such beginning Gross Asset Value using any reasonable method selected by the Board.

        "Designated MWE Employees" has the meaning ascribed to such term in the Services Agreement.

        "Dispute" has the meaning set forth in Section 15.17(a).

        "Economic Risk of Loss" shall have the meaning assigned to that term in Treasury Regulation Section 1.752-2(a).

        "Effective Time" means 12:01 a.m. on January 1, 2009.

        "Election Period" shall have the meaning set forth in Section 5.7(b).

        "Electing Member" shall have the meaning set forth in Section 5.7(b).

        "Eligible Member" shall have the meaning set forth in Section 5.7(a).

        "Enforcement Activities" shall have the meaning set forth in Section 6.3(a).

        "Equalization Date" shall mean the first date after ** on which the quotient (expressed as a percentage) obtained by dividing the aggregate Investment Balances of all members of the MWE Liberty Group by the aggregate Investment Balances of all members of the MWE Liberty Group plus all members of the NGPMR Group is equal to or greater than 51%.

        "Equalization Target Date" shall have the meaning set forth in Section 4.9(a).

        "Exchange Act" means the Securities Exchange Act of 1934, and the rules and regulations promulgated thereunder, as amended and any successor statutes thereto.

        "Exempted Project" shall have the meaning set forth in Section 3.3(b).

5

        "Final Impasse" shall have the meaning set forth in Section 15.16(b).

        "First Amended Agreement" shall have the meaning set forth in recitals.

        "First Notice" shall have the meaning set forth in Section 5.7(b).

        "Fiscal Year" means (i) the period commencing at the Effective Time and ending on December 31, 2010 and (ii) any subsequent 12 month period commencing on January 1 and ending on December 31.

        "Fractionation and NGL Purchase Agreement" means that certain Fractionation and NGL Purchase Agreement, dated February 27, 2009, by and between MWE Hydrocarbon and the Company, as amended, restated and supplemented from time to time.

        "G&A Services" has the meaning ascribed to such term in the Services Agreement.

        "GAAP" means generally accepted accounting principles in the United States.

** means that certain ** by and between MarkWest Liberty Gas Gathering, L.L.C. and **, as amended, restated and supplemented from time to time.

        "Gross Asset Value" means, with respect to any asset, such asset's adjusted basis for federal income tax purposes, except as follows:

        (a)   the initial Gross Asset Value of any asset contributed by a Member to the Company shall be the gross fair market value of such asset, as agreed to by the contributing Member and the Board, except that MWE Liberty's initial Capital Contribution shall have the gross asset value determined in accordance with Section 4.1(a);

        (b)   the Gross Asset Value of all Company assets shall be adjusted to equal their respective gross fair market values, as determined by the Board, in connection with: (i) the acquisition of an additional interest in the Company by any new or existing Member in exchange for more than a de minimis Capital Contribution or in exchange for the performance of services to or for the benefit of the Company; (ii) the distribution by the Company to a Member of more than a de minimis amount of Company assets as consideration for an interest in the Company; and (iii) the liquidation of the Company within the meaning of Treasury Regulations Section 1.704-1(b)(2)(ii)(g) (other than pursuant to Section 708(b)(1)(B) of the Code) or any other event to the extent determined by the Board to be necessary to properly reflect the Gross Asset Values in accordance with the standards set forth in Treasury Regulations Section 1.704-1(b)(2)(iv)(q); provided, however, that adjustments pursuant to clause (i) and clause (ii) of this sentence shall be made only if the Board reasonably determines that such adjustments are necessary or appropriate to reflect the relative economic interests of the Members in the Company;

        (c)   the Gross Asset Value of any Company asset distributed to any Member shall be the gross fair market value of such asset on the date of distribution, as determined by the Board and the distributee Member; and

        (d)   the Gross Asset Values of Company assets shall be adjusted to reflect any adjustments to the adjusted basis of such assets pursuant to Code Section 734(b) or Code Section 743(b), but only to the extent that such adjustments are taken into account in determining Capital Accounts pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(m).

If the Gross Asset Value of an asset has been determined or adjusted pursuant to paragraph (a) or paragraph (b) above, such Gross Asset Value shall thereafter be adjusted by the Depreciation taken into account with respect to such asset for purposes of computing Profits and Losses.

        "Impasse" shall have the meaning set forth in Section 15.16(a).

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        "Impasse Notice" shall have the meaning set forth in Section 15.16(a).

        "Incentive Interest Transaction" shall have the meaning set forth in Section 5.6.

        "Indentures" has the meaning ascribed to such term in the Contribution Agreement.

        "Indemnitee" shall have the meaning set forth in Section 12.7.

        "Indemnitor" shall have the meaning set forth in Section 12.7.

        "Initial Budget" shall have the meaning set forth in Section 5.5.

        "Interest" means the interest of a Member in the Company, including both Class A Percentage Interests and Class B Percentage Interests, including rights to distributions (liquidating or otherwise), allocations, notices and information, rights to approve of or consent to certain matters (if applicable) and all other rights, benefits and privileges enjoyed by that Member (under the Act, the Certificate, this Agreement, or otherwise) in its capacity as a Member; and all obligations, duties and liabilities imposed on that Member (under the Act, the Certificate, this Agreement, or otherwise) in its capacity as a Member.

        "Investment Account" shall have the meaning set forth in Section 4.8.

        "Investment Balance" shall have the meaning set forth in Section 4.8.

        "Investment Threshold" shall have the meaning set forth in Section 4.1(c).

        "IPO Issuer" means (a) the Company or (b) an Affiliate of the Company which will be a successor to the Company and the issuer in a Qualified Public Offering.

        "Lien" means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset.

        "Liquidating Trustee" shall have the meaning set forth in Section 13.4(a).

        "Manager" shall have the meaning set forth in Section 6.1.

        "Member" means any Person (but not any Affiliate or entity in which such Person has an equity interest) executing this Agreement and any Person admitted as an Additional Member or a Substitute Member pursuant to the provisions of this Agreement, in such Person's capacity as a Member of the Company, and "Members" means two or more of such Persons, in their capacities as Members of the Company. Such terms do not include any Person or Persons who have ceased to be Members in the Company.

        "Member Nonrecourse Debt" has the meaning assigned to the term "partner nonrecourse debt" in Treasury Regulation Section 1.704-2(b)(4).

        "Member Nonrecourse Debt Minimum Gain" shall have the meaning assigned to the term "partner nonrecourse debt minimum gain" in Treasury Regulation Section 1.704-2(i)(2).

        "Member Nonrecourse Deductions" shall have the meaning assigned to the term "partner nonrecourse deductions" in Treasury Regulation Section 1.704-2(i)(1).

        "Minimum Gain" shall have the meaning assigned to that term in Treasury Regulation Section 1.704-2(d).

        "Minimum Price" shall have the meaning set forth in Section 7.2(b)(ii).

        "Monthly Reports" shall have the meaning set forth in Section 10.3(c).

        "MWE" means MarkWest Energy Partners, L.P., a Delaware limited partnership.

        "MWE Hydrocarbon" shall have the meaning set forth in the recitals.

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        "MWE Liberty" shall have the meaning set forth in the preamble.

        "MWE Liberty Group" means MWE Liberty and each transferee of Interests directly or indirectly (in the chain of title) from MWE Liberty that is an Affiliate of MWE Liberty; provided, however, that once a Person is designated as a member of the MWE Liberty Group such Person shall, as long as it owns any Interests, at all times be a member of the MWE Liberty Group and not a member of any other Affiliated Member Group; provided further, that for purposes of this definition, an Affiliate shall not include a member of any other Affiliated Member Group.

        "New Interests" shall have the meaning set forth in Section 5.7(a).

        "NGPMR" shall have the meaning set forth in the preamble.

        "NGPMR Covered Persons" has the meaning ascribed to such term in the Contribution Agreement.

        "NGPMR Exit Transaction" means ** involving the Company in which ** in which the ** prior to the ** of the Company ** or a ** of the Company**. For the avoidance of doubt, any **

        "NGPMR Group" means NGPMR and each transferee of Interests directly or indirectly (in chain of title) from NGPMR that is an Affiliate of NGPMR; provided, however, that once a Person is designated as a member of the NGPMR Group such Person shall, as long as it owns any Interests, at all times be a member of the NGPMR Group and not a member of any other Affiliated Member Group, and, provided further, that for purposes of this definition, an Affiliate shall not include a member of any other Affiliated Member Group.

        "NGPMR Portfolio Companies" shall have the meaning set forth in Section 3.3(c).

        "NGPMR Representatives" shall mean the members, managers and employees of NGPMR or any Affiliate thereof, together with all other persons serving as representatives of NGPMR, including those Persons who are serving as Managers at the request of NGPMR pursuant to this Agreement.

        "Non-Contributing Class A Member" shall mean a Class A Member who does not elect to make a Quarterly Budgeted Funding Election in accordance with Section 4.1(c).

        "Non-Contributing Class B Member" shall mean a Class B Member who does not elect to make a Quarterly Budgeted Funding Election in accordance with Section 4.1(d).

        "Nonrecourse Deductions" shall have the meaning assigned to that term in Treasury Regulation Section 1.704-2(b).

        "Operator" means the Person designated as the "Operator" of the Company in accordance with Section 6.11.

        "Original Agreement" shall have the meaning set forth in the recitals.

        "Out of Scope Project" means any project, activity, or business venture (a) outside the Area of Mutual Interest or (b) not within the scope of the Primary Business of the Company (whether inside or outside the Area of Mutual Interest).

        "Over-Allotment Amount" shall have the meaning set forth in Section 5.7(b).

        "Overfunded Capital" means, as of any determination date (a) on or prior to **, the difference (expressed as a dollar amount) between **, and (b) after **, the difference (expressed as a dollar amount) between **.

        "Partial NGPMR Exit Transaction" means ** after which the ** in the ** after which the **

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        "Percentage Interest" means:

        (a)   at any time on or prior to December 31, 2010:

          (i)  with respect to a Class A Member, the product (expressed as a percentage) of (1) 40% and (2) such Member's Class A Percentage Interest; and

         (ii)  with respect to a Class B Member, the product (expressed as a percentage) of (1) 60% and (2) such Member's Class B Percentage Interest.

        (b)   at any time after December 31, 2010, but prior to the earlier to occur of the Equalization Date and **:

          (i)  with respect to a Class A Member, the product (expressed as a percentage) of (1) 49% and (2) such Member's Class A Percentage Interest; and

         (ii)  with respect to a Class B Member, the product (expressed as a percentage) of (1) 51% and (2) such Member's Class B Percentage Interest.

        (c)   at any time on or after the earlier to occur of the Equalization Date and **, with respect to any Member (including any Class A Member or Class B Member), the quotient (expressed as a percentage) obtained by dividing the Investment Balance of such Member by the Investment Balances of all Members.

        "Permitted Liens" means (a) statutory liens for current taxes or assessments not yet due and delinquent or the validity of which is being contested in good faith by appropriate proceedings and for which adequate reserves have been established; (b) mechanics', carriers', workers', repairers' and other similar liens arising or incurred in the ordinary course of business; and (c) all applicable zoning ordinances and land use restrictions.

        "Permitted Transfers" shall have the meaning set forth in Section 7.1.

        "Personnel Services" has the meaning ascribed to such term in the Services Agreement.

        "Person" means any natural person, corporation, limited partnership, general partnership, limited liability company, joint stock company, joint venture, association, company, estate, trust, bank trust company, land trust, business trust, or other organization, whether or not a legal entity, custodian, trustee-executor, administrator, nominee or entity in a representative capacity and any government or agency or political subdivision thereof.

        "Preference Amount" means an amount calculated on the last day of each calendar quarter following the Effective Time and prior to the Equalization Date by determining the difference between (a) the amount of Overfunded Capital as of the last day of such quarter, multiplied by the Preference Rate and (b) the amount of all distributions made during such calendar quarter pursuant to Section 8.1(b)(i)(A). The Preference Amount for the prior calendar quarter shall be added to the Investment Balance as of the first day of the following calendar quarter.

        "Preference Rate" means a quarterly rate expressed as a percentage equal to ** per annum, divided by four.

        "Primary Business" shall have the meaning set forth in Section 3.1(a).

        "Profits" or "Losses" means, for each Fiscal Year, an amount equal to the Company's taxable income or loss for such Fiscal Year, determined in accordance with Section 703(a) of the Code (but including in taxable income or loss, for this purpose, all items of income, gain, loss or deduction

9

required to be stated separately pursuant to Section 703(a)(1) of the Code), with the following adjustments:

        (a)   any income of the Company exempt from federal income tax and not otherwise taken into account in computing Profits or Losses pursuant to this definition shall be added to such taxable income or loss;

        (b)   any expenditures of the Company described in Section 705(a)(2)(B) of the Code (or treated as expenditures described in Section 705(a)(2)(B) of the Code pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(i)) and not otherwise taken into account in computing Profits or Losses pursuant to this definition shall be subtracted from such taxable income or loss;

        (c)   in the event the Gross Asset Value of any Company asset is adjusted in accordance with paragraph (b) or paragraph (c) of the definition of "Gross Asset Value", the amount of such adjustment shall be taken into account as gain (if the adjustment increases the Gross Asset Value of the Company asset) or loss (if the adjustment decreases the Gross Asset Value of the Company asset) from the disposition of such asset for purposes of computing Profits or Losses;

        (d)   gain or loss resulting from any disposition of any Company asset with respect to which gain or loss is recognized for federal income tax purposes shall be computed by reference to the Gross Asset Value of the asset disposed of, notwithstanding that the adjusted tax basis of such asset differs from its Gross Asset Value;

        (e)   in lieu of the depreciation, amortization and other cost recovery deductions taken into account in computing such taxable income or loss, there shall be taken into account Depreciation for such Fiscal Year or other period, computed in accordance with the definition of "Depreciation";

        (f)    to the extent an adjustment to the adjusted tax basis of any asset pursuant to Code Section 734(b) is required, pursuant to Treasury Regulation Section 1.704-1(b)(2)(iv)(m)(4), to be taken into account in determining Capital Account balances as a result of a distribution other than in liquidation of a Member's interest in the Company, the amount of such adjustment shall be treated as an item of gain (if the adjustment increases the basis of the asset) or an item of loss (if the adjustment decreases such basis) from the disposition of such asset and shall be taken into account for purposes of computing Profits or Losses; and

        (g)   notwithstanding any other provisions of this definition, any items which are specially allocated pursuant to Section 9.2 or 9.3 shall not be taken into account in computing Profits or Losses.

        "Project Period" shall have the meaning set forth in Section 7.1.

        "Projects" shall have the meaning set forth in Section 3.3(a).

        "Property" means all of the assets and property now owned or hereafter acquired by the Company.

        "Proposed Budget" shall have the meaning set forth in Section 6.15(a).

        "Proposed Purchaser" shall have the meaning set forth in Section 5.7(a).

        "Prudent Industry Practices" means, at a particular time, any of the practices, methods and acts which, ** based upon the **, and the **, at such time, is ** operation and maintenance of the Company assets and shall include, without limitation, the practices, methods and acts engaged in or approved by ** at such time with respect to the assets of the same or similar types as the Company assets. Prudent Industry Practices are not intended to be limited to ** to the exclusion of all others, but rather is ** practices, methods and acts which ** at a ** as well as with the **. Prudent Industry Practices are intended to entail the **, in the **, use from time to time.

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        "Qualified Public Offering" means any underwritten initial public offering by the IPO Issuer of equity securities pursuant to an effective registration statement under the Securities Act and for which aggregate cash proceeds to be received by the IPO Issuer from such offering (without deducting underwriting discounts, expenses and commissions) are at least $50,000,000.

        "Qualifying Third Party Offer" shall have the meaning set forth in Section 7.2(a)(ii).

        "Quarterly Budgeted Funding Election" shall have the meaning set forth in Sections 4.1(c) and (d).

        "Quarterly Financial Statements" shall have the meaning set forth in Section 10.3(b).

        "Regulatory Allocations" shall have the meaning set forth in Section 9.3.

        "Remaining Members" shall have the meaning set forth in Section 7.2(a).

        "Representatives" means (a) with respect to the Company, any of: (i) the Company's Affiliates; and (ii) directors, officers, managers, employees, members, partners, agents and authorized representatives (including attorneys, accountants, consultants, bankers, lenders and financial advisors) of the Company and the Company's Affiliates and (b) with respect to a Member, any of: (i) such Member's Affiliates; (ii) directors, officers, managers, employees, members, stockholders, partners, agents and authorized representatives (including attorneys, accountants, consultants, bankers, lenders and financial advisors) of the Member and the Member's Affiliates; and (iii) Persons who are (or who are prospective) beneficial owners of equity interests in such Member.

        "Requisite Member Approval" means the approval of each Affiliated Member Group holding Interests with (i) an aggregate Percentage Interest equal to or exceeding ** or (ii) an **.

        "Restricted Project" has the meaning set forth in Section 3.3(b).

        "ROFO Interest" shall have the meaning set forth in Section 7.2(a).

        "ROFO Offer" shall have the meaning set forth in Section 7.2(a).

        "Rules" shall have the meaning set forth in Section 6.15(e).

        "Sale Proposal" shall have the meaning set forth in Section 7.2(b)(i).

        "Securities Act" means the Securities Act of 1933, and the rules and regulations promulgated thereunder, as amended and any successor statutes thereto.

        "Services Agreement" shall have the meaning set forth in the recitals.

        "Solicitation Notice" shall have the meaning set forth in Section 7.2(b)(ii).

        "Solicitation Period" shall have the meaning set forth in Section 7.2(a)(ii).

        "Solicitation Response" shall have the meaning set forth in Section 7.2(b)(ii).

        "Subsidiary" means, with respect to any Person, (a) any corporation, of which a majority of the total voting power of shares of stock entitled (without regard to the occurrence of any contingency) to vote generally in the election of directors thereof is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person or a combination thereof or (b) any limited liability company, partnership, association or other business entity, of which a majority of the partnership or other similar ownership interests thereof is at the time owned or controlled, directly or indirectly, by that Person or one or more Subsidiaries of that Person or a combination thereof. For purposes of this definition, a Person or Persons will be deemed to have a majority ownership interest in a limited liability company, partnership, association or other business entity if such Person or Persons will be allocated a majority of limited liability company, partnership,

11

association or other business entity gains or losses, or is or controls the managing member or general partner of such limited liability company, partnership, association or other business entity.

        "Substitute Member" means a Person who is admitted to the Company as a Member pursuant to Article 7, and then designated as a "Member" on an amended Exhibit B to this Agreement.

        "Tag-Along Members" shall have the meaning set forth in Section 7.2(b).

        "Tag-Along Notice" shall have the meaning set forth in Section 7.2(b)(i).

        "Tag-Along Notice Period" shall have the meaning set forth in Section 7.2(b)(i).

        "Tag-Along Rights" shall have the meaning set forth in Section 7.2(b).

        "Tax Distribution Date" shall have the meaning set forth in Section 8.5(a).

        "Tax Matters Member" shall have the meaning set forth in Section 11.4(a).

        "Third Party Confidentiality Agreements" means that certain ** among MWE Liberty, **, the **, that certain ** between ** and MWE Liberty, that certain ** between ** and MWE Liberty ** and that certain ** between ** and MWE Liberty ** or any other third party agreement entered into by or on behalf of the Company and delivered to a Member.

        "Third Party Offer" shall have the meaning set forth in Section 7.2(a)(ii).

        "** Payout" shall mean the dollar threshold, if any, at which the NGPMR Group has received a cumulative cash amount in respect of the NGPMR Group's Interests (whether as distributions from the Company or as cash payment in an Incentive Interest Transaction) equal to the ** as of the date of such cash payment ** where ** is equal to the ** determined as of the date of such cash payment or distribution.

        "** Payout Threshold" shall mean the receipt by the NGPMR Group of a cumulative cash amount in respect of the NGPMR Group's Interests (whether as distributions from the Company or as cash payment in an Incentive Interest Transaction) equal to the ** where ** is equal to the ** determined as of the date of such distribution or cash payment.

        "** Percentage" shall mean **.

**

        "Transaction Documents" shall have the meaning set forth in Section 5.1(b).

        "Transfer" means any direct or indirect transfer, assignment, sale, conveyance, license, lease, or partition of any Interest, and includes any "involuntary transfer" such as a sale of any part of the Interest therein in connection with any bankruptcy or similar insolvency proceedings, or any other disposition of any Interest. A Transfer shall not include any pledge, hypothecation or encumbrance of any Interest.

        "Transferring Member" shall have the meaning set forth in Section 7.2(a).

        "Treasury Regulations" means the income tax regulations, including temporary regulations, promulgated under the Code, as such regulations may be amended from time to time (including corresponding provisions of succeeding regulations).

        "True-Up Contribution" shall have the meaning set forth in Section 4.9(a).

        ** means that certain ** by and between MWE Liberty and ** as amended by Amendment No. 1 to ** by and between MWE Liberty and **.

        "Unrelated Information" shall have the meaning set forth in Section 10.2.

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        "Weighted Average Capital Contribution Factor" shall mean as of any date of calculation, a weighted average ** the amounts determined for each date on which NGPMR has made Capital Contributions (including without limitation the Capital Contributions funded on the date hereof) calculated as ** of the total ** years from the date of each Capital Contribution until the date of such calculation (with a partial year being expressed as a decimal determined by dividing the number of days which have passed since the most recent anniversary by 365). Solely for purposes of determining Capital Contributions under this definition, (i) ** shall be treated as a Capital Contribution made by the NGPMR Group as of the date **, and (ii) any other amounts ** shall be treated as Capital Contributions made by the NGPMR Group as of the date **.

ARTICLE 2
FORMATION AND TERM

        Section 2.1    Formation.    

        (a)   The Company was organized as a Delaware limited liability company under and pursuant to the Act by the filing of the Certificate by an authorized person and is being continued pursuant to the terms of this Agreement.

        (b)   The name and mailing address of each Member and the total amount which has been contributed to the capital of the Company through the date hereof is listed on Exhibit B. The Board shall cause Exhibit B to be updated, from time to time, as may be necessary to accurately reflect the information therein. Any amendment or revision to Exhibit B made in accordance with this Agreement shall not be deemed an amendment to this Agreement. Any reference in this Agreement to Exhibit B shall be deemed to be a reference to Exhibit B, as amended, revised and in effect from time to time.

        Section 2.2    Name.    

        The business and affairs of the Company shall be conducted under the name "MarkWest Liberty Midstream & Resources, L.L.C." and such name shall be used at all times in connection with the Company's business and affairs, except to the extent the Board agrees to the use by the Company of assumed names or other trade names or fictitious names. The Company's Managers or officers or the Operator shall execute such assumed or fictitious name certificates as may be desirable or required by law to be filed in connection with the business and affairs of the Company and shall cause such certificates to be filed in all appropriate public records.

        Section 2.3    Term.    

        The term of the Company commenced upon the effectiveness of the Certificate and shall continue perpetually, unless the Company is dissolved in accordance with the provisions of this Agreement.

        Section 2.4    Registered Agent and Office.

        The registered office of the Company required by the Act to be maintained in Delaware shall be the office of the initial registered agent named in the Certificate or such other office (which need not be a place of business of the Company) as the Board may designate in the manner provided by law. The registered agent of the Company in Delaware shall be the initial registered agent named in the Certificate or such other Person or Persons as the Board may designate in the manner provided by law.

        Section 2.5    Principal Place of Business.

        The principal place of business of the Company shall be 1515 Arapahoe Street, Tower 2, Suite 700, Denver, CO 80202. At any time, the Board may change the location of the Company's principal place of business. The Company may have such other places of business as the Board or the Operator may designate.

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        Section 2.6    Qualification in Other Jurisdictions.

        The Managers, the officers of the Company or the Operator shall cause the Company to be qualified, formed or registered under assumed or fictitious name statutes or similar laws in any jurisdiction in which the Company transacts business. The Managers, the officers of the Company or the Operator shall execute, deliver and file any certificates (and any amendments and/or restatements thereof) necessary or appropriate for the Company to qualify and continue to do business in a jurisdiction in which the Company may wish to conduct business. At the request of the Board or the Operator, each Member shall execute, acknowledge, swear to and deliver all certificates and other instruments conforming with this Agreement that are necessary or appropriate to qualify, continue and terminate the Company as a foreign limited liability company in all such jurisdictions in which the Company may conduct business, provided that no Member shall be required to file any general consent to service of process or to qualify as a foreign corporation, limited liability company, partnership or other entity in any jurisdiction in which it is not already so qualified.

ARTICLE 3
PURPOSE AND POWERS OF THE COMPANY

        Section 3.1    Purpose.    

        (a)   The purpose of the Company is to engage in the natural gas midstream business, including but not limited to natural gas gathering and processing, and the natural gas liquids processing, fractionation, transportation, storage and marketing businesses in the Area of Mutual Interest and to fulfill the obligations of the Company pursuant to any contract entered into by the Company or under which the Company has assumed obligations of any Person (the "Primary Business"), and to engage in any other business or activity that now or in the future may be necessary, incidental, proper, advisable or convenient to accomplish the foregoing purpose and that is not forbidden by the law of the jurisdiction in which the Company engages in such business or activity.

        (b)   In no event shall this Agreement be held or construed to imply the existence of a partnership (including a limited partnership) or joint venture among the Members and no Member shall be held or construed to be a partner or joint venturer of any other Member, for any purposes other than federal and state tax purposes. No Member shall have any power or authority under this Agreement to act as the agent or representative of the Company or any other Member with regard to any matter beyond the scope of this Company.

        Section 3.2    Powers of the Company.    

        The Company shall have all powers and privileges granted by the Act, any other law, or by this Agreement, including incidental powers thereto, to the extent that such powers and privileges are necessary, customary, convenient or incidental to the attainment of the Company's purpose.

        Section 3.3    Projects, Restricted Projects, Exempted Projects and Out of Scope Projects.    

        (a)   As part of the Primary Business, the Company shall use commercially reasonable efforts to pursue the acquisition, development, construction and operation of natural gas gathering and processing, and natural gas liquids fractionation, transportation, storage and marketing assets described on Exhibit C (such activities, the "Base Project"). From time to time, the Company may also pursue the acquisition, development, construction and operation of additional midstream assets in the Area of Mutual Interest in accordance with this Agreement (such activities, the "Additional Projects" and, collectively with the Base Project, the "Projects").

        (b)   No Class B Member (either directly or indirectly through one or more Affiliates) shall, own, operate, manage, control, engage in, participate in, invest in, finance, render services for,

14

assist others in, or otherwise carry out any Primary Business (a "Restricted Project") other than through the Company, without Requisite Member Approval, except as follows (any Restricted Project engaged in pursuant to one of the following exceptions is an "Exempted Project"):

          (i)  MWE Liberty or its Affiliates may engage in a Restricted Project outside the Company without Requisite Member Approval if the pursuit of such Restricted Project by the Company does not receive approval of the Board pursuant to Section 6.1 and Requisite Member Approval pursuant to Section 6.12, and the Company therefore is unable to pursue the Restricted Project;

         (ii)  MWE Hydrocarbon may perform its obligations under the Fractionation and NGL Purchase Agreement; and

        (iii)  A Class B Member or its Affiliates may ** as part of ** Restricted Projects, provided that ** such Class B Member ** the Company ** of ** as ** the Class B Member. In connection with ** the Company and the other Members **. Members holding Interests with an aggregate Percentage Interest ** Class B Member ** shall have the ** this Section 3.3(b)(iii) (which, for clarity purposes, shall not **). Such Members may, by written notice to the Company ** the Class B Member ** the Class B Member ** the Class B Member **. For the avoidance of doubt, ** the Restricted Project shall have ** prior to **. In the event that ** the Restricted Project, the ** the Class B Member ** the Class B Member or ** the Class B Member. ** Class B Member ** the Company.

        Each Member recognizes and affirms that in the event of breach by such Member of any of the provisions of this Section 3.3(b), money damages may be inadequate and the non-breaching Members may have no adequate remedy at law. Accordingly, each Member agrees that the non-breaching Members shall have the right, in addition to any other rights and remedies existing in their favor, to enforce their rights and each of the Members' obligations under this Section 3.3(b) not only by an action or actions for damages, but also by an action or actions for specific performance, injunctive and/or other equitable relief in order to enforce or prevent any violations (whether anticipatory, continuing or future) of the provisions of this Section 3.3(b).

        (c)   The Company and the Members recognize that: (i) NGPMR and its Affiliates own and will own substantial equity interests in other companies (existing and future) that participate in the energy industry ("NGPMR Portfolio Companies") and have in the past and will in the future enter into advisory service agreements with such NGPMR Portfolio Companies; (ii) the NGPMR Representatives who serve as Managers also serve as principals of other NGPMR Portfolio Companies; and (iii) at any time, other NGPMR Portfolio Companies may be in direct or indirect competition with the Company and/or its Subsidiaries. The Company and the Members acknowledge and agree that NGPMR, its Affiliates and NGPMR Representatives: (A) shall not be prohibited or otherwise restricted by their relationship with the Company and its Subsidiaries from engaging in the business of investing in NGPMR Portfolio Companies, entering into agreements to provide services to such NGPMR Portfolio Companies or acting as directors or advisors to, or other principals of, such NGPMR Portfolio Companies, regardless of whether such activities are in direct or indirect competition with the Company or the Primary Business, (B) shall not have any obligation to offer the Company or its Subsidiaries any business opportunity resulting from NGPMR and its Affiliates' ownership in the NGPMR Portfolio Companies, and (C) the Company and the Members hereby renounce any interest or expectancy in any such business opportunity pursued by NGPMR, its Affiliates, the NGPMR Representatives or another NGPMR Portfolio Company and waive any claim that any such business opportunity constitutes a corporate, partnership or other business opportunity of the Company or any of its Subsidiaries; provided, however, that nothing contained in this Section 3.3(c) is intended to limit the confidentiality obligations in Section 5.4 and NGPMR, its Affiliates, the NGPMR Portfolio Companies and the

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NGPMR Representatives are expressly prohibited from using any Confidential Information (i) to pursue any such business opportunity, (ii) in providing services to the NGPMR Portfolio Companies or (iii) in acting as directors or advisors to, or other principals of, such companies.

        (d)   No Member or its Affiliates shall have any obligation to communicate or offer any Out of Scope Projects to the Company or the other Members. The Members acknowledge and agree that each Member, and their respective Affiliates, may presently or in the future engage in and/or possess an interest in other business ventures of every nature and description, independently or with others, outside of the Area of Mutual Interest, whether or not such business ventures are within the scope of the Primary Business, or within the Area of Mutual Interest, so long as such ventures constitute Out of Scope Projects or Exempted Projects, and neither the Company nor any other Members shall have any right by virtue of this Agreement in and to any Out of Scope Projects or Exempted Projects, or to the income or profits derived therefrom.

ARTICLE 4
CAPITAL CONTRIBUTIONS, MEMBER INTERESTS,
CAPITAL ACCOUNTS AND FUTURE CAPITAL REQUIREMENTS

        Section 4.1    Capital Contributions.    

        (a)   Current Capital Contributions. On or prior to the date hereof, MWE Liberty and NGPMR have made the respective Capital Contributions to the Company in the amounts set forth on Exhibit B in exchange for the Percentage Interest and the type of Interest set forth on Exhibit B. The Members hereby acknowledge and agree that the Capital Contributions set forth on Exhibit B include the gross fair market value of MWE Liberty's initial Capital Contribution of $107,501,953, as such amount was finally determined in accordance with Section 4.1(a) of the First Amended Agreement.

        (b)   Additional Capital Contributions Prior to the Equalization Date.

          (i)  The Class A Members have collectively contributed Cash Capital Contributions through the date hereof in the amount listed on Exhibit B. The Class A Members hereby agree to make additional Cash Capital Contributions to the Company, on an as needed basis, until such time as the Class A Members have made aggregate Cash Capital Contributions of **. At each time when the Company requires additional capital pursuant to this Section 4.1(b)(i), the Board shall issue a Capital Call to the Class A Members and such Members shall contribute to the Company the amount of capital so required within ten Business Days after receipt of such Capital Call. Capital Calls issued pursuant to this Section 4.1(b)(i) shall not be made more frequently than 30 days following the prior Capital Call.

         (ii)  After the Class A Members have made aggregate Cash Capital Contributions equal to **, the Class A Members and the Class B Members hereby collectively agree to make additional Capital Contributions to the Company, on an as needed basis, such contributions to be made on a ** (Class A Members) and ** (Class B Members) relative basis, until such time as the Class A Members have made aggregate Cash Capital Contributions of **. At each time when the Company requires additional capital pursuant to this Section 4.1(b)(ii), the Board shall issue a Capital Call to the Class A Members and the Class B Members and such Members shall contribute to the Company the amount of capital so required within ten Business Days after receipt of such Capital Call. Capital Calls issued pursuant to this Section 4.1(b)(ii) shall not be made more frequently than 30 days following the prior Capital Call. At such time as the Class A Members have made aggregate Cash Capital Contributions of **, no Class A Member shall have any obligation to make additional Capital Contributions

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to the Company, unless such Class A Member elects to contribute capital pursuant to Sections 4.1(b)(iii), 4.1(c) or 4.1(d).

        (iii)  After the Class A Members have made aggregate Cash Capital Contributions equal to **, the Class B Members hereby agree to make additional Capital Contributions to the Company, on an as needed basis, until the occurrence of the Equalization Date. Prior to the occurrence of the Equalization Date, at each time when the Company requires additional capital pursuant to this Section 4.1(b)(iii), the Board shall issue a Capital Call to the Class A Members and the Class B Members. Concurrent with the issuance of each such Capital Call, the Class B Members shall make an initial election of the minimum percentage of such requested capital that the Class B Members desire to contribute to the Company. Such initial election shall be ** of the additional capital so requested by the Board and the ** of the Class B Members shall be included in the Capital Call. Within five Business Days after the receipt of such Capital Call, each Class A Member shall elect whether to contribute additional capital to the Company. Each Class A Member may elect to contribute an amount up to and including **. The election of each Class A Member shall be irrevocable and shall be made in writing (which may include electronic mail) to the Company. In the event any Class A Member fails to provide a written election within such five Business Day period, such Class A Member will be deemed to have elected not to participate in such Capital Call. Promptly following such five Business Day period, the Company shall provide written notice to the Class B Members of their respective obligation with respect to such Capital Call, giving effect to the elections of the Class A Members. Within 15 Business Days after receipt of such Capital Call, the electing Class A Members shall contribute to the Company the amount of capital elected to be contributed by such Class A Members pursuant to this Section 4.1(b)(iii), and the Class B Members shall contribute to the Company the remainder of the additional capital requested by the Board in such Capital Call. Capital Calls issued pursuant to this Section 4.1(b)(iii) shall not be made more frequently than 30 days following the prior Capital Call. Notwithstanding the foregoing, the Class A Members and the Class B Members shall not make any Capital Contributions pursuant to this Section 4.1(b)(iii) and the Company shall not issue any Capital Calls for any such Capital Contributions unless and until each of the Capital Contributions by the Class A Members and the Class B Members set forth in Sections 4.1(b)(i) and (ii) have been spent by the Company or committed to be spent in accordance with an Approved Budget.

        (iv)  The Class B Members hereby agree that, any distributions of Available Cash payable to a Class B Member pursuant to Section 8.1(a) prior to December 31, 2010 shall be distributed and automatically reinvested by each Class B Member as additional Capital Contributions without the issuance of any Capital Call. In accordance with Section 8.1(a), the Class A Members acknowledge and agree that they shall not receive any distributions of Available Cash prior to December 31, 2010; provided, however that the amount that each Class A Member would have received if Available Cash were distributed prior to December 31, 2010, shall increase the Investment Balance of such Class A Member on a dollar-for-dollar basis. Once December 31, 2010 has occurred, Available Cash shall be distributed in accordance with Section 8.1(b)(ii).

         (v)  It is the intent of the Members that Capital Calls will generally only be made for amounts required by the Company with respect to the 90 day period following the date the applicable Capital Contributions are to be made, and that Capital Calls will only be made for expenses approved or authorized in accordance with this Agreement.

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        (c)   Capital Contributions After the Equalization Date But Prior to Investment Threshold.

          (i)  If the Company requires additional capital to pursue any Project or in connection with the operation of the Primary Business after the Equalization Date but prior to the time that ** the Class A Members and Class B Members is ** (the "Investment Threshold"), then, with respect to funding for Projects or operations within the then current Approved Budget, the Class A Members shall elect (such election, a "Quarterly Budgeted Funding Election") on a quarterly basis whether to contribute additional capital that may be required to fund such Projects or operations for the upcoming calendar quarter. The Class A Members may elect to contribute an amount up to and including their then applicable respective Percentage Interests of the additional capital so requested by the Board. Such Quarterly Budgeted Funding Election shall be irrevocable, and shall be made in writing (which may include electronic mail) to the Company no less than 30 days prior to the commencement of the upcoming calendar quarter. If one or more Class A Members elect not to participate, or fail to make any election (which shall be deemed to be an election not to contribute), then such Non-Contributing Class A Member(s) shall have no obligation to contribute additional capital to fund Projects or operations within the then current Approved Budget for such upcoming calendar quarter. With respect to each Contributing Class A Member, at least ten days prior to the beginning of such calendar quarter, the Board shall issue to such Contributing Class A Member a Capital Call that identifies the amount of capital that the Company needs in connection with such Projects or operations for such quarter. Each Contributing Class A Member shall in accordance with such Class A Member's Quarterly Budgeted Funding Election contribute such requested capital to the Company within ten Business Days after the issuance of each such quarterly Capital Call.

         (ii)  After the Equalization Date but prior to the satisfaction of the Investment Threshold, the Class B Member(s) may contribute on a quarterly basis all additional capital (less any capital to be contributed by the Contributing Class A Members for such upcoming calendar quarter) required to fund Projects or operations within the then current Approved Budget for the upcoming calendar quarter, including any capital required to reduce any capital shortfall that may result from Non-Contributing Class A Member elections during such calendar quarter; provided, that the Class B Member(s) shall provide written notice to the other Members on a quarterly basis regarding their decision to fund additional capital and the amount of such Capital Contribution.

        (iii)  If elections to contribute capital by the Contributing Class A Members and the Class B Member(s) are less than the total amount of capital required by the Company pursuant to this Section 4.1(c), then the Company may seek to obtain the requested capital from third parties, which may include issuing additional Interests in the Company pursuant to and subject to Section 5.3 and Section 5.7, if applicable.

        (d)   Capital Contributions After the Equalization Date and Investment Threshold.

          (i)  If the Company requires additional capital to pursue any Project or in connection with the operation of the Primary Business after the Equalization Date and the satisfaction of the Investment Threshold, then, with respect to funding for Projects or operations within the then current Approved Budget, the Class B Members shall initially elect (such election, also a Quarterly Budgeted Funding Election) on a quarterly basis whether to contribute additional capital that may be required to fund such Projects or operations for the upcoming calendar quarter. Each Class B Member may elect to contribute up to a percentage of such additional capital so requested by the Board equal to the **. Such Quarterly Budgeted Funding Election shall be irrevocable, and shall be made in writing (which may include electronic mail) to the Company no less than 30 days prior to the commencement of the upcoming calendar quarter.

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If one or more Class B Members elect not to participate, or fail to make any election (which shall be deemed to be an election not to contribute), then such Non-Contributing Class B Member(s) shall have no obligation to contribute additional capital to fund Projects or operations within the then current Approved Budget for such upcoming calendar quarter. With respect to each Contributing Class B Member, at least ten days prior to the beginning of such calendar quarter, the Board shall issue to such Contributing Class B Member a Capital Call that identifies the amount of capital that the Company needs in connection with such Projects or operations for such quarter. Each Contributing Class B Member shall in accordance with such Class B Member's Quarterly Budgeted Funding Election and any further election pursuant to Section 4.1(d)(iii) contribute such requested capital to the Company within ten Business Days after the issuance of each such quarterly Capital Call.

         (ii)  After the Equalization Date and the satisfaction of the Investment Threshold, the Class A Member(s) may contribute on a quarterly basis additional capital in an amount up to and including their then applicable respective Percentage Interests of the additional capital ** required to fund Projects or operations within the then current Approved Budget for the upcoming calendar quarter. Twenty-five days prior to the commencement of the upcoming calendar quarter, the Company shall notify the Class A Members of any election by the Class B Members to contribute capital for such upcoming calendar quarter made in accordance with Section 4.1(d)(i). Within five days, the Class A Members shall elect whether to contribute additional capital required to fund such Projects or operations for the upcoming calendar quarter. Any such election shall state the percentage of such additional capital that such Class A Member desires to contribute. Such Quarterly Budgeted Funding Election shall be irrevocable, and shall be made in writing (which may include electronic mail) to the Company and the Class B Members. If one or more Class A Members elect not to participate, or fail to make any election (which shall be deemed to be an election not to contribute), then such Non-Contributing Class A Member(s) shall have no obligation to contribute additional capital to fund Projects or operations within the then current Approved Budget for such upcoming calendar quarter. With respect to each Contributing Class A Member, at least ten days prior to the beginning of such calendar quarter, the Board shall issue to such Contributing Class A Member a Capital Call that identifies the amount of capital that the Company needs in connection with such Projects or operations for such quarter. Each Contributing Class A Member shall in accordance with such Class A Member's Quarterly Budgeted Funding Election contribute such requested capital to the Company within ten Business Days after the issuance of such quarterly Capital Call.

        (iii)  Within fifteen days prior to the commencement of the upcoming calendar quarter, the Contributing Class B Members may elect to contribute additional capital to the Company to reduce any capital shortfall that may result from the Quarterly Budgeted Funding Elections made pursuant to Sections 4.1(d)(i) and (ii), but only if the Class B Members have elected to contribute an amount that is at least equal to the product of the Percentage Interests of all of the Class B Members and the aggregate amount of additional capital requested by the Board for the upcoming calendar quarter pursuant to Section 4.1(d)(i). Such an election (also a Quarterly Budgeted Funding Election) with respect to a capital shortfall shall be irrevocable, and shall be made in writing (which may include electronic mail) to the Company and the Class A Members.

        (iv)  If elections to contribute capital by the Contributing Class B Members and the Contributing Class A Member(s) pursuant to Sections 4.1(d)(i), (ii) and (iii) are less than the total amount of capital required by the Company pursuant to this Section 4.1(d), then the Company may seek to obtain the requested capital from third parties, which may include

19

issuing additional Interests in the Company pursuant to and subject to Section 5.3 and Section 5.7, if applicable.

        (e)   Percentage Interests Adjustment. For the avoidance of doubt, the Percentage Interests of the Members shall be subject to adjustment (upward and downward) pursuant to Sections 4.1(c) and (d), based upon the Members' respective Investment Balances giving effect to any additional Capital Contributions.

        Section 4.2    Capital Contribution Defaults.    

        If a Member fails to contribute any capital to the Company that is required to be so contributed pursuant to Section 4.1, such Member shall be considered in default (a "Defaulting Member"), but shall remain fully obligated to contribute such capital to the Company. The Company shall be entitled to pursue all remedies available at law or in equity against the Defaulting Member, including any one or more of the following:

        (a)   the Company may take all actions, including court proceedings, as the other Members may deem appropriate, to obtain payment by the Defaulting Member of the required amount of the Capital Contribution remaining unpaid, together with interest thereon at the Default Rate from the date that the required Capital Contribution was required to be contributed to the Company until the date it is so contributed, at the cost and expense of the Defaulting Member; and

        (b)   the non-defaulting Members may advance the portion of the Defaulting Member's Capital Contribution that is in default, in accordance with the non-defaulting Members' respective Percentage Interests, and, at the option of the non-defaulting Members, the non-defaulting Members making such advance may be deemed to have made a loan to the Defaulting Member in the amount of the Capital Contribution so advanced, which loan shall bear interest at the Default Rate from the date that such advance is made until the loan is repaid in full, and until such loan is repaid in full, the non-defaulting Members making such loan to the Defaulting Member shall be entitled to receive all distributions of Available Cash that would otherwise be payable to the Defaulting Member hereunder, in accordance with the non-defaulting Members' respective Percentage Interests.

        Section 4.3    Member's Interest.    

        A Member's Interest shall for all purposes be personal property. Title to the Company's assets, whether real, personal or mixed and whether tangible or intangible, shall be deemed to be owned by the Company as an entity, and no Member, Manager, Operator or officer of the Company shall have any ownership interest in such Company assets.

        Section 4.4    Status of Capital Contributions.    

        (a)   Except as otherwise provided in this Agreement, no Member, or the successor or assign of a Member, may demand a return of its Capital Contributions, in whole or in part. An unrepaid Capital Contribution is not a liability of the Company or of any Member.

        (b)   No Member or Affiliate of any Member shall receive any interest, return, compensation or drawing with respect to its Capital Contributions or its Capital Account, except as otherwise specifically provided in this Agreement.

        (c)   Except as otherwise provided in this Agreement, no Member shall be required to lend any funds or make any additional Capital Contributions to the Company. No Member shall have any personal liability for the repayment of any other Member's Capital Contribution or be required to contribute or lend any cash or property to the Company to enable the Company to repay any Member's Capital Contributions.

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        Section 4.5    Capital Accounts.    

        (a)   A separate Capital Account shall be established and maintained for each Member in accordance with the requirements of Treasury Regulations Section 1.704-1(b)(2)(iv). The original Capital Account established for any Member who acquires an Interest by virtue of an assignment in accordance with the terms of this Agreement shall be in the same amount as and shall replace the Capital Account of the assignor of such Interest. To the extent such Member acquires less than all of the Interest of the assignor of the Interest so acquired by such Member, the original Capital Account of such Member and its Capital Contributions shall be in proportion to the Interest it acquires, and the Capital Account of the assignor who retains an Interest shall be reduced in proportion to the Interest it retains.

        (b)   The Capital Account of each Member shall be maintained in accordance with the following provisions:

          (i)  to such Member's Capital Account there shall be credited such Member's Capital Contributions, such Member's distributive share of Profits, special allocations of income and gain, and the net amount of any Company liabilities that are assumed by such Member or that are secured by any Company assets distributed to such Member;

         (ii)  to such Member's Capital Account there shall be debited the amount of cash and the Gross Asset Value of any Company assets distributed to such Member pursuant to any provision of this Agreement, such Member's distributive share of Losses, special allocations of loss and deduction, and the net amount of any liabilities of such Member that are assumed by the Company or that are secured by any property contributed by such Member to the Company;

        (iii)  in determining the amount of any liability for purposes of this Section 4.5(b), there shall be taken into account Section 752(c) of the Code and any other applicable provisions of the Code and the Treasury Regulations; and

        (iv)  the Capital Accounts shall be increased or decreased upon a revaluation of Company property pursuant to clause (b) of the definition of Gross Asset Value in the manner prescribed in Treasury Regulation Section 1.704-1(b)(2)(iv)(f).

        Section 4.6    Capital Accounts Generally.    

        (a)   Except as otherwise provided in this Agreement, whenever it is necessary to determine the Capital Account of any Member for any purpose hereunder, the Capital Account of such Member shall be determined after giving effect to all adjustments provided for in Section 4.5 for the current Fiscal Year in respect of transactions effected prior to the date such determination is to be made.

        (b)   No Member shall be entitled to withdraw any part of its Capital Account, or to receive any distribution from the Company except as specifically provided in this Agreement.

        Section 4.7    Preferred Return.    

        For the avoidance of doubt, the Class A Interests shall accrue the Preference Amount until the Equalization Date, after which time the Preference Amount shall no longer accrue.

        Section 4.8    Investment Accounts.    

        The Company shall maintain an investment account (an "Investment Account") for each Member, the balance of which (the "Investment Balance") shall represent the sum of a Member's initial Capital Contribution, any additional Capital Contributions made by a Member pursuant to Sections 4.1(b), 4.1(c), 4.1(d) and 4.9, and with respect to each Class A Member, (i) the Preference Amount and

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(ii) the amount that is retained by the Company in accordance with Section 4.1(b)(iv) and which such Class A Member would have otherwise received if Available Cash were distributed prior to December 31, 2010. The Investment Balance for each Class A Member shall be reduced by any actual distributions to such member of Available Cash pursuant to Section 8.1(b)(i)(A) and Sections 13.4(a)(i)(A) and (B). For the avoidance of doubt, the Investment Balance of each Member as of the date hereof is set forth on Exhibit B. An assignee of all or any portion of an Interest shall succeed to a portion of the assignor Member's Investment Account in proportion to the Interest acquired.

        Section 4.9    Equalization Target Date.    

        (a)   All distributions of Available Cash received by the MWE Liberty Group after ** pursuant to any provision of this Agreement shall automatically be contributed to the Company as additional Capital Contributions until the Equalization Date occurs. If the Equalization Date has not occurred on or before December 31, 2012 (the "Equalization Target Date"), then the Class A Members holding at least a majority of the Class A Percentage Interests may elect by written notice to require MWE Liberty to make an additional cash Capital Contribution (the "True-Up Contribution") sufficient to result in the Equalization Date occurring within ** after the Equalization Target Date. MWE Liberty shall cause such True-Up Contribution to be made and the Equalization Date to occur within ** of the requesting notice of the requisite Class A Members. To the extent that the Company does not have commitments to spend the True-Up Contribution in accordance with the Approved Budget (and any amendments or modifications to such Approved Budget approved prior to the date of the True-up Contribution) in effect at the time MWE Liberty is required to make the True-Up Contribution, then, at the end of the first full fiscal quarter following the date of the True-Up Contribution, the Company shall distribute any amount of the True-Up Contribution not spent or committed to be spent in accordance with such Approved Budget, and any approved amendments thereto, to the Members in accordance with their Percentage Interests. For clarification purposes, it is the intent of the Members that the True-Up Contribution be an amount such that after payment of the True-Up Contribution is made by MWE Liberty, the Percentage Interest of the MWE Liberty Group is 51% and the Percentage Interest of the NGPMR Group is 49%.

        (b)   If MWE Liberty fails to make the True-Up Contribution in accordance with Section 4.9(a) above, then the Interests held by the MWE Liberty Group shall not be ** of the Company; provided, however, that the then controlling Members shall not ** to the MWE Liberty Group in any material respect ** of the MWE Liberty Group. Additionally, NGPMR shall have the ** subject to the provisions of ** to any Person, other than an Affiliate or partner of any member of the NGPMR Group or any NGPMR Portfolio Company, **, (B) all Members ** any Person, other than an Affiliate or partner of any member of the NGPMR Group or any NGPMR Portfolio Company, of all of ** or (C) the Company to ** other than an Affiliate or partner of any member of the NGPMR Group or any NGPMR Portfolio Company, **.

        (c)   Within five days after receipt of any notice of **, the Board shall notify each Member, in writing, ** shall identify the **, including the form of the ** and provide a copy of **. Each Member agrees that ** it will (i) take such action as may reasonably be required, including **, (ii) cause its designated Managers to take such action required, to **, (iii) provide for the execution of such agreements and such instruments and other actions reasonably necessary to provide, to the extent necessary, ** relating to such **, in each case only to the extent that **; provided that, no Affiliated Member Group shall be obligated in respect of any ** and referred to in the immediately preceding clause in such ** for an ** to such Affiliated Member Group in **. The Member proposing ** shall have the right in connection with ** (or in connection with the **) to require the Company to cooperate fully with ** by taking all customary and other actions reasonably requested by the Member **, including making the ** reasonably available **,

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establishing a ** in connection with such processes and making ** activities, in each case subject to **. The Company and each Member shall provide assistance with respect to these actions as reasonably requested by the Member **. In addition, once ** under this Section 4.9, the Board shall be entitled to take all steps reasonably necessary to carry out **, including **; provided, however, that the rights granted the Board in this sentence shall not permit the Board to **.

ARTICLE 5
MEMBERS, MEETINGS AND AMENDMENTS

        Section 5.1    Powers of Members.    

        (a)   Except for the right to consent to or approve certain matters as expressly provided in this Agreement, the Members in their capacity as Members shall not have any other power or authority to manage the business or affairs of the Company or to bind the Company or enter into agreements on behalf of the Company.

        (b)   To the fullest extent permitted by law and notwithstanding any provision of this Agreement or any other document executed in connection with this Agreement (a "Transaction Document") to the contrary, no Member in its capacity as a Member shall have any duty, fiduciary or otherwise, to the Company or any other Member in connection with the business and affairs of the Company or any consent or approval given or withheld pursuant to this Agreement or any other Transaction Document.

        (c)   Any matter requiring the consent or approval of the Members pursuant to this Agreement may be taken without a meeting, without prior notice and without a vote, by a consent in writing, setting forth such consent or approval, and signed by Members holding Interests not less than the requisite Interests necessary to consent to or approve such action; provided that at least one Class A Member shall be required to sign such consent or approval in order for such consent to be effective in the event that the Class A Members did not receive prior written notice of the action to be so taken. Prompt notice of such consent or approval shall be given by the Company to those Members who have not joined in such consent or approval.

        Section 5.2    No Resignation or Expulsion.    

        A Member may not take any action to resign, withdraw or retire as a Member voluntarily, and a Member may not be expelled or otherwise removed involuntarily as a Member, prior to the dissolution and winding up of the Company, other than as a result of a Permitted Transfer of all of such Member's Interests in accordance with Article 7 and each of the transferees of such Interests being admitted as a Substitute Member.

        Section 5.3    Additional Members.    

        (a)   After the Board makes a Capital Call pursuant to Section 4.1(c) or Section 4.1(d) that was not fully funded by the Members and subject to the preemptive rights set forth in Section 5.7 to the extent applicable, the Company is authorized to issue additional Interests and to admit any Person as an additional member of the Company (each, an "Additional Member" and collectively, the "Additional Members"). Upon receipt of requisite approval of the Board and the Members, the Company is authorized to issue additional Interests and to admit any Person as an additional member of the Company (each, an "Additional Member" and collectively, the "Additional Members"). Each such Person receiving additional Interests shall be admitted as an Additional Member at the time such Person (i) executes a counterpart signature page agreeing to be bound hereby and such other documents or instruments as may be required in the Board's reasonable judgment to effect the admission, and (ii) is designated as a Member (with a corresponding Percentage Interest) on an amended or supplemental Exhibit B. The Company may issue additional Interests or additional classes of membership interests to existing Members or to new or

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Additional Members in exchange for such Capital Contributions, including cash, property or services or any combination thereof.

        (b)   Additional Members shall not be entitled to any retroactive allocation of the Company's income, gains, losses, deductions, credits or other items; provided that, subject to the restrictions of Section 706(d) of the Code, Additional Members shall be entitled to their respective share of the Company's income, gains, losses, deductions, credits and other items arising under contracts entered into before the effective date of the admission of any Additional Members to the extent that such income, gains, losses, deductions, credits and other items arise after such effective date. To the extent consistent with Section 706(d) of the Code and Treasury Regulations promulgated thereunder, the Company's books may be closed at the time Additional Members are admitted (as though the Company's tax year had ended) or the Company may credit to the Additional Members pro rata allocations of the Company's income, gains, losses, deductions, credits and items for that portion of the Company's Fiscal Year after the effective date of the admission of the Additional Members.

        Section 5.4    Confidentiality Obligations of Members.    

        (a)   Each Member agrees that all Confidential Information shall be kept confidential by the Member, shall only be used for the purpose of reviewing and evaluating the performance of the Company and the Member's Interest therein, and shall not be disclosed in any manner, except to such of the Member's Representatives who have a need to know and who agree to be, or are otherwise, bound by the Member's obligations hereunder and except as otherwise expressly permitted in this Section 5.4. Each Member shall be responsible for any breach of this Section 5.4 by itself or any of its Representatives, and each Member covenants and agrees that it shall promptly notify the Company of any actual, potential or threatened breach of this Section 5.4 and shall, at its own expense, enforce, and assist the Company in its enforcement of, the provisions of this Section 5.4, including, to the extent reasonably necessary, seeking specific enforcement through court proceedings. Subject to Section 5.4(b), if a Member or any of its Representatives is requested or required by applicable law, rule or regulation, regulatory authority, subpoena, civil investigation, court order, demand or similar legal process to disclose any Confidential Information, the Member shall, to the maximum extent permitted by applicable law, provide the Company with prompt written notice thereof and will use reasonable efforts to resist disclosure, until an appropriate protective order or motion to quash may be sought or a waiver of compliance with this Section may be granted. If, in the absence of a protective order or the receipt of a waiver hereunder, such Member or any of its Representatives is, in the opinion of its legal counsel, legally required to disclose Confidential Information, then such Member or its Representatives may disclose only that portion of the Confidential Information legally required to be disclosed, without liability hereunder, provided that such Member or its Representatives uses reasonable efforts to obtain reliable assurance that confidential treatment will be accorded the Confidential Information. Each Member acknowledges and agrees that the Company and the other Members may be irreparably harmed by disclosure of the Confidential Information, that money damages would not be a sufficient remedy for any breach of this Section 5.4 by such Member or its Representatives and that, in addition to any other remedies available at law or in equity, specific performance and injunctive or other equitable remedies shall be available to the Company and the Members as a remedy for any such breach or threatened breach, without the requirement of posting bond or other security. The Company and the other Members shall be entitled to recover their costs and expenses, including attorneys' fees, incurred in connection with any successful action brought by them to enforce the terms of this Agreement. With respect to Confidential Information that is subject to confidentiality agreements under any Third Party Confidentiality Agreements, each Member covenants and agrees to, and shall cause its Representatives to, treat such Confidential Information confidentially in accordance with, and to comply with the terms of, the confidentiality

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provisions contained in those Third Party Confidentiality Agreements that have been disclosed to such Member, including, any provisions thereof that impose more stringent or additional obligations than those set forth herein (provided such has been disclosed to such Member). The obligations of a Member pursuant to this Section 5.4 shall continue following the time such Person ceases to be a Member, but thereafter such Person shall not have the right to enforce the provisions hereof. Notwithstanding anything set forth herein, all covenants made herein by a Member are for the sole benefit of the Company and the other Members and there shall be no third party beneficiaries of any of such covenants.

        (b)   Notwithstanding anything to the contrary in this Agreement, each Member may disclose any information about the Company, including any Confidential Information, without any liability to the Company or to any other Member or to their respective Affiliates and without any notice to any Member, to the extent that such disclosing Member believes that such disclosure is necessary or appropriate to satisfy its public disclosure obligations under the Securities Act, the Exchange Act, the rules of any stock exchange, or any similar public disclosure obligations.

        Section 5.5    Initial Budget.    

        By execution of this Agreement, the Members hereby approve and consent to the initial budget attached hereto as Exhibit D (the "Initial Budget") and acknowledge and agree that such Initial Budget shall be deemed to be an Approved Budget for all purposes of this Agreement.

        Section 5.6    Incentive Interests to MWE Liberty Upon Transfer of NGPMR's Interest.    

        In the event NGPMR receives cash from any NGPMR Exit Transaction or Partial NGPMR Exit Transaction (for the purposes of this section, such transaction an "Incentive Interest Transaction") that would result in ** Payout**, simultaneously with the consummation of any such transaction, NGPMR shall pay to MWE Liberty as a fee the following amount**, to the extent applicable:

**    Following ** Payout Threshold, if any, an amount equal to the ** of (i) the cash proceeds of all Incentive Interest Transactions plus cumulative cash distributions to NGPMR in respect of its Interest, **

**    

Exhibit E contains illustrative examples of the calculation and operation of amount** payable pursuant to Section 5.6** based upon hypothetical Incentive Interest Transactions. This Section 5.6 shall be interpreted and applied in a manner consistent with the examples set forth in Exhibit E. The obligations of NGPMR to make payment** to MWE Liberty pursuant to this Section 5.6 shall survive the closing of any NGPMR Exit Transaction or Partial NGPMR Exit Transaction and any liquidation, dissolution or winding up of the Company until such payment to MWE Liberty has been made.

        Section 5.7    Preemptive Rights.    

        (a)   After the Equalization Date, prior to the Company issuing any Interests or options or rights to acquire Interests (other than (i) any equity issuance associated with an acquisition previously approved by NGPMR, (ii) Interests issued in connection with any split, distribution or recapitalization of the Company, (iii) Interests issued in any initial public offering registration statement filed under the Securities Act, or (iv) in connection with any capital raising or financing efforts by the Company the purpose of which is to fund any activities of the Company which were the subject of a Capital Call made pursuant to Section 4.1(c) or Section 4.1(d) that was not fully funded by the Members; provided, however, that any Interests to be issued in such capital raising or financing efforts, and the pricing of such Interests, are equivalent to the terms of such Capital Call), whether through exchange, conversion or otherwise (the "New Interests"), to a proposed third party purchaser (the "Proposed Purchaser"), each Member who is not in default of this Agreement and which certifies to the Company's reasonable satisfaction that it is an "accredited

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investor" within the meaning of Rule 501 under the Securities Act (an "Eligible Member") shall have the right to purchase a portion of the New Interests in accordance with this Section 5.7.

        (b)   The Company shall give each Eligible Member prior written notice (the "First Notice") of any proposed issuance of New Interests, which shall set forth in reasonable detail the proposed terms and conditions thereof (as determined by the Board in good faith) and shall offer to each Eligible Member the opportunity to purchase its Percentage Interest (as of the date of such notice) of the New Interests, on the same terms and conditions and at the same time as the New Interests are proposed to be issued by the Company. If any Eligible Member desires to exercise its preemptive rights under this Section 5.7, it must deliver an irrevocable written notice within 30 days after the Eligible Member's receipt of the First Notice (the "Election Period") setting forth the dollar amount of the New Interests the Eligible Member (the "Electing Member") is electing to purchase, up to its Percentage Interest plus any additional amount of New Interests it desires to purchase in excess of its Percentage Interest (the "Over-Allotment Amount") if other Eligible Members do not exercise their preemptive rights hereunder. The right of each Electing Member to purchase New Interests in excess of its Percentage Interest shall be based on the relative Percentage Interests of the Electing Members desiring to purchase Over-Allotment Amounts.

        (c)   If the Eligible Members do not subscribe for all of the New Interests, the Company shall have the right, but not the obligation, to issue and sell the unsubscribed portion of the New Interests to the Proposed Purchaser at any time during the 90 days following the end of the Election Period, at the same price and pursuant to the terms and conditions set forth in the First Notice. The Board may, in its reasonable discretion, impose such other reasonable and customary terms and procedures such as setting a closing date and requiring customary closing deliveries in connection with any preemptive rights offering. In the event any Electing Member refuses to purchase the New Interests for which it subscribed pursuant to this Section 5.7, then in addition to any other rights the Company may have at law or in equity, such Electing Member and any transferee thereof shall not be considered an Eligible Member for any future rights granted under this Section 5.7 unless the Board expressly designates otherwise (which the Board may, in its sole discretion, do on an offer-by-offer basis or not at all) and shall be deemed a Defaulting Member under Section 4.2.

        Section 5.8    Registration Rights.    

        If the Board with Requisite Member Approval determines to effect a Qualified Public Offering, each of the Members shall be granted customary registration rights, including piggyback registration rights, with respect to such Qualified Public Offering.

ARTICLE 6
MANAGEMENT

        Section 6.1    Management Under Direction of the Board.    

        Except as otherwise expressly provided in this Agreement or required under the Act, the business and affairs of the Company shall be managed by a board of managers (the "Board" and each member of the Board, a "Manager"), and the Board shall have full and complete authority, power, and discretion to manage and control the business, affairs, and properties of the Company, to make all decisions regarding those matters and to perform any and all other acts or activities customary or incidental to the management of the Company's business. Without limiting the generality of the foregoing the approval of the Board shall be required for all matters not delegated by the Board to the Operator, the officers of the Company or to other authorized persons in accordance with Section 6.10,

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including approval of the following matters, which the Board shall not have the power to delegate to any Person, in each case except as otherwise approved in any Approved Budget:

        (a)   Proposed Budgets for the Company, other than the Initial Budget;

        (b)   distributions of Available Cash (including Tax Distributions);

        (c)   efforts by the Company to raise additional capital, including the issuance of additional Interests or any options to acquire Interests and the issuance of additional equity interests or options to acquire equity interests in the Company's subsidiaries;

        (d)   incurrence or guarantee of Debt by the Company in excess of $**;

        (e)   acquisitions or dispositions of assets by the Company in excess of $**;

        (f)    commencing or resolving litigation;

        (g)   election or removal of officers of the Company;

        (h)   material contracts to which the Company (or a subsidiary of the Company) is a party or by which it is bound; and

        (i)    the registration of any equity or debt securities of the Company or its subsidiaries under applicable United States federal or foreign securities laws or any public offering of equity or debt securities of the Company or its subsidiaries (including any Qualified Public Offering).

        Section 6.2    Number, Tenure and Qualifications.    

        (a)   Prior to the Equalization Date, the Board shall be comprised of six Managers, designated as follows:

          (i)  three Managers (each, a "Class A Manager") designated by Class A Members with an aggregate Class A Percentage Interest of at least 50%; and

         (ii)  three Managers (each, a "Class B Manager") designated by Class B Members with an aggregate Class B Percentage Interest of at least 50%.

        The initial Managers of the Company shall be: John T. Raymond, Jeffrey Rawls and Patrick Wade, who are the Class A Managers, and John Mollenkopf, Randy Nickerson and Frank Semple, who are the Class B Managers.

        (b)   On and after the Equalization Date, each Affiliated Member Group shall be entitled to designate the number of Managers determined by their Percentage Interests as follows:

          (i)  Each Affiliated Member Group with a Percentage Interest less than or equal to ** shall not be allowed to designate any Managers;

         (ii)  Each Affiliated Member Group with a Percentage Interest greater than ** but less than or equal to **, shall be allowed to designate one Manager;

        (iii)  Each Affiliated Member Group with a Percentage Interest greater than ** but less than ** shall be allowed to designate two Managers; and

        (iv)  Each Affiliated Member Group with a Percentage Interest equal to or greater than **, shall be allowed to designate three Managers.

        Any Manager designated in accordance with this section shall be immediately removed from the Board at any time that the Affiliated Member Group that designated such Manager ceases to own aggregate Percentage Interests that would permit such Affiliated Member Group to designate such Manager in accordance with the first sentence of this section. Notwithstanding the foregoing, so long as the Class A Members have **, such Class A Members shall be entitled to appoint no less than one

27

Manager to the Board and the size of the Board shall be, if necessary, increased by one to enable the Class A Members to make such appointment. The Board shall be comprised of the total number of Managers that all Affiliated Member Groups are entitled to so designate pursuant to the first sentence of this Section 6.2(b), plus any additional Manager whom the Class A Members are entitled to designate pursuant to the immediately preceding sentence. At any time that any Affiliated Member Group acquires aggregate Percentage Interests sufficient to permit such Affiliated Member Group to designate one or more additional Managers in accordance with the first sentence of this Section, then a new Manager position shall be created and such Affiliated Member Group shall be entitled to fill such the vacancy in such position in accordance with Section 6.9.

        (c)   A Manager need not be a resident of the State of Delaware. A Manager shall hold office until the Manager's successor shall be duly elected and shall qualify or until the earlier of such Manager's withdrawal, death, removal or resignation.

        Section 6.3    Votes Per Manager; Quorum; Required Vote for Board Action; Meetings of the Board.    

        (a)   Each Manager shall have one vote. Except as provided below, Managers comprising at least a majority of the total number of Managers entitled to be designated in accordance with Section 6.2 shall constitute a quorum for the transaction of business at a meeting of the Board. Except as otherwise expressly provided in this Agreement, any action or event shall be deemed approved by the Board of Managers comprising at least a majority of the total number of Managers then entitled to be designated at the time of such approval in accordance with Section 6.2 vote in favor of or approve such action or event at a meeting at which a quorum is present. Any actions by the Company in response to a breach of or default (or alleged breach or default) under an Affiliate Contract or other transaction with an Affiliate of a Member (such as a waiver of the breach or default, notice of breach or event of default or notice of termination for breach or default in accordance with the terms of the Affiliate Contract) or enforcement or exercise of any of the Company's rights or remedies in respect to such breach or default (or alleged breach or default) (collectively, "Enforcement Activities") shall be conducted by or under the direction of the Board, provided that any Manager designated by a Member that is a party to, or has an Affiliate (other than the Company) that is a party to, such Affiliate Contract or transaction ** at any meeting of the Board and ** of the Board; provided further that the foregoing proviso shall not apply to **, which shall be **.

        (b)   Except as otherwise required by applicable law, the Board may hold meetings in such place or places, within or outside of the State of Delaware, as the Board may determine from time to time. Business shall be conducted at such meetings in such order as the Board shall determine from time to time.

        (c)   Regular meetings of the Board shall be held at least quarterly and at such times and places as shall be designated from time to time by the Board. Notice of such regular meetings shall not be required if held at the times and places as previously determined by the Board and provided to each Manager. Special meetings of the Board may be called by any Manager upon at least 24 hours prior notice, which may be given via electronic mail, and which notice must include dial-in or other information so as to permit each Manager to participate in such meeting by telephone conference or other electronic means. Such notice must state the purpose of such meeting.

        (d)   Any action required or permitted to be taken at any meeting of the Board may be taken without a meeting if a consent in writing, setting forth the action so taken, shall be signed by a majority of the Managers then entitled to be designated in accordance with Section 6.2; provided that at least one Manager designated by the NGPMR Group (if there is such a Manager) and at least one Manager designated by the MWE Liberty Group (if there is such a Manager) shall be

28

required to sign such consent or approval, solely for purposes of providing an acknowledgement of receipt of notice of the action to be taken rather than approval or rejection thereof, in order for such consent or approval to be effective in the event that at least one Manager designated by the NGPMR Group (if there is such a Manager) or at least one Manager designated by the MWE Liberty Group (if there is such a Manager), as applicable, did not receive prior written notice of the action to be so taken.

        (e)   Members of the Board may participate in any meeting by means of conference telephone or similar communications equipment by means of which all persons participating in the meeting can hear each other and participation in such a meeting such constitute presence in person at such meeting, except as provided in clause (f).

        (f)    Attendance of a Manager at any meeting of the Board (including by telephone) shall constitute a waiver of notice of such meeting, except where such Manager attends the meeting for the express purpose of objecting to the transaction of any business on the ground that the meeting is not lawfully called or convened and notifies the other Managers at such meeting of such purpose.

        Section 6.4    Power to Bind Company.    

        Unless authorized to do so by this Agreement or by the Board, no Member of the Company shall have any power or authority to bind the Company in any way, to pledge the Company's credit or to render it liable pecuniarily for any purpose. However, a Person may act by a duly authorized attorney-in-fact executed in writing by the Board.

        Section 6.5    Liability for Certain Acts.    

        No Manager or officer of the Company (solely in such individual's capacity as a Manager or officer of the Company), nor any of their Affiliates or their respective successors or assigns, shall be liable to the Company or to any Member for any claims, losses, expenses, costs, obligations, liabilities, actions, suits, proceedings, judgments, or settlements (including attorneys' fees) (whether civil, criminal, administrative or investigative) (collectively, "Claims") arising or resulting from or relating to the performance of any of such Manager's or officer's obligations or duties under this Agreement in its capacity as Manager or officer, or otherwise attributable to any breach of duty owed by such Manager or officer (by virtue of being a Manager or officer) to the Company or the Members, except to the extent such Claims or breach of duty is based upon such person's fraud, bad faith or willful misconduct as established by a non-appealable court order, judgment, decree or decision by a court of competent jurisdiction. Without limiting the generality of the foregoing, the doing of any act or the failure to do any act by any Manager or officer, which shall not constitute fraud, bad faith or willful misconduct (as established by a non-appealable court order, judgment, decree or decision by a court of competent jurisdiction), the effect of which may cause or result in loss or damage to the Company, shall not subject any Manager or officer to any liability. Each Manager and officer shall be fully protected in relying in good faith upon the records of the Company and upon such information, opinions, reports or statements presented to the Company by any Person as to matters such Manager or officer reasonably believes are within such other Person's professional or expert competence, including information, opinions, reports or statements as to the value and amount of the assets, liabilities, profits, losses, or any other facts pertinent to the existence and amount of assets from which distributions to Members might properly be paid. The Managers do not, in any way, guarantee the return of the Members' Capital Contributions or a profit for the Members from the operations of the Company. No Manager shall be responsible to any Members because of a loss of their investments or a loss in operations, unless the loss shall have been the result of fraud, bad faith or willful misconduct established as set forth in this Section 6.5.

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        Section 6.6    Manager Has No Exclusive Duty to Company.    

        A Manager shall not be required to manage the Company as the Manager's sole and exclusive occupation, and a Manager may have other business interests and may engage in other investments, occupations and activities in addition to those relating to the Company. Neither the Company nor any Member shall have any right, by virtue of this Agreement, to share or participate in such other investments or activities of a Manager or to the income or proceeds derived therefrom.

        Section 6.7    Resignation and Withdrawal.    

        A Manager of the Company may resign from the position of Manager at any time by giving written notice to the Members of the Company. The resignation of a Manager shall take effect upon receipt of notice thereof or at such later time as shall be specified in such notice; and unless otherwise specified therein, the acceptance of such resignation shall not be necessary to make it effective. Upon the withdrawal of a Manager, such Manager shall be treated as having resigned as of the date of withdrawal and shall automatically cease to be a Manager as of the date of such withdrawal. Except in the case of resignation by reason of withdrawal, the resignation of a Manager who is also a Member pursuant to this Section 6.7 shall not affect such Manager's rights as a Member and shall not constitute a withdrawal of such Member.

        Section 6.8    Removal.    

        Subject to Section 6.2(b), a Manager may only be removed by the consent of the Member or Members then entitled to designate such Manager in accordance with Section 6.2. The removal of a Manager who is also a Member shall not affect such Manager's rights as a Member and shall not constitute a withdrawal of such Member.

        Section 6.9    Vacancies.    

        Any vacancy in the position of a Manager that is created by the withdrawal, death, resignation or removal of a Manager or by the creation of a new Manager position pursuant to Section 6.2(b) shall be filled only by consent of the Member or Members then entitled to designate such Manager in accordance with Section 6.2. A Manager elected to fill a vacancy shall hold office until a successor shall be elected and shall qualify, or until the Manager's earlier death, resignation, withdrawal or removal.

        Section 6.10    Delegation of Authority; Officers.    

        The Board shall have the power to elect, delegate authority to, and remove such officers, employees, agents and representatives of the Company as the Board may from time to time deem appropriate. Any delegation of authority to take any action must be approved in the same manner as would be required for the Board to approve such action directly. The salaries of all officers, employees and agents of the Company shall be fixed by the Board in accordance with the Approved Budget.

        Section 6.11    Designation of Operator.    

        (a)   The Company hereby designates MWE Liberty as the initial "Operator" of the Company. Subject to any required Board or Member approvals rights set forth in this Agreement, MWE Liberty shall be responsible for, shall make all decisions regarding and shall have full power and authority to manage the day-to-day operations of the Company's business, including, the development, construction and operation of the Company's facilities and business development activities and the oversight of G&A Services and Personnel Services provided to the Company by MWE Hydrocarbon pursuant to the Services Agreement, which includes the day-to-day management and supervision of all Designated MWE Employees. The appointment of MWE Liberty as the Operator shall be exclusive to MWE Liberty, except to the extent that MWE Liberty elects to cause such duties to be provided by third parties (and, in any case MWE Hydrocarbon and MWE Liberty remain fully responsible for compliance with the Services Agreement). MWE

30

Liberty shall have the power and authority to execute contracts, and to take such other actions, on behalf of the Company as may be necessary or appropriate to carry out the Company's business in accordance with the Approved Budget.

        (b)   For the avoidance of doubt, the power and authority granted to MWE Liberty as the Operator pursuant to Section 6.11(a) shall specifically include the ability to perform (or cause to be performed) the following services and activities (subject to compliance with any Board or Member approval rights with respect to such services and activities required pursuant to this Agreement):

          (i)  investigation, analysis and selection of acquisition and business development opportunities;

         (ii)  with respect to prospective acquisitions or dispositions by the Company, conducting negotiations with sellers and purchasers and their respective agents, representatives and advisors (including, without limitation, investment bankers);

        (iii)  administering the day-to-day operations of the Company and performing and supervising the performance of such other administrative functions necessary in the management of the Company as may be agreed upon by MWE Liberty as Operator and the Board, including the collection of revenues and the payment of the Company's debts and obligations and maintenance of appropriate computer services to perform such administrative functions;

        (iv)  monitoring the operating performance of the Company's assets and providing periodic reports with respect thereto to the Board, including comparative information with respect to such operating and performance and budgeted or projected operating results;

         (v)  assisting the Company to retain qualified accountants and legal counsel, as applicable, to assist in developing appropriate accounting procedures and compliance procedures;

        (vi)  causing the Company to qualify to do business in all applicable jurisdictions and to obtain and maintain all appropriate licenses;

       (vii)  negotiating, executing, amending and terminating the Company's agreements with unaffiliated third parties, managing and administering the Company's rights and obligations under all agreements with unaffiliated third parties to which the Company is a party or by which the Company is bound and monitoring compliance by the Company and by such unaffiliated third parties to such agreements with the terms and conditions thereof;

      (viii)  taking all necessary actions to enable the Company to make required tax filings and reports;

        (ix)  handling and resolving all claims, disputes or controversies (including, without limitation, all litigation, arbitration, settlement or other proceedings or negotiations) with unaffiliated third parties in which the Company may be involved or to which the Company may be subject arising out of the Company's day-to-day operations, subject to such limitations or parameters as may be imposed from time to time by the Board;

         (x)  purchasing, selling, leasing, operating and maintaining the Company's assets;

        (xi)  establishing and maintaining the Company's bank accounts and banking arrangements, and to the extent of funds available, reinvesting Company funds as MWE Liberty as Operator may deem appropriate and consistent with MWE Liberty's practices;

31

       (xii)  performing such other services as may be required from time to time for management and other activities relating to the assets of the Company as the Board shall reasonably request or MWE Liberty shall deem appropriate under the particular circumstances; and

      (xiii)  using commercially reasonable efforts to cause the Company to comply with all applicable laws.

        The Operator shall operate the Company and perform the services and activities referred to in clauses (i) through (xiii) above in accordance with Prudent Industry Practices.

        (c)   MWE Hydrocarbon shall receive the fees and reimbursement for its services as set forth in the Services Agreement. The Company and the Members hereby acknowledge and agree that the liability of Operator and MWE Hydrocarbon to the Company and the Members, and the Operator's obligation to satisfy any claim for indemnification in connection with any such liability, shall be limited in the manner and to the extent set forth in the Services Agreement, and the Members hereby consent to, approve, and agree to be bound by the terms thereof with regard to such limitations of the liability of the Operator and MWE Hydrocarbon to the Company and the Members, in the same manner and to the same extent as though such provisions were set forth herein. The Operator shall serve as the Operator until the termination of the Services Agreement. Upon the termination of the Services Agreement, the Board with the Requisite Member Approval may cause the Company to designate a new operator and enter into a new services agreement.

        (d)   MWE Liberty hereby agrees to notify NGPMR of any notice of default or other material notices received by MWE Liberty in connection with the agreements listed on Exhibit H.

        Section 6.12    Approval of Members.    

        The following matters shall require Requisite Member Approval (provided that an explicit approval of such matter in the Approved Budget or related Member resolution shall constitute a Requisite Member Approval if such approval is explicitly identified as a Requisite Member Approval):

        (a)   Prior to the Equalization Date to the extent not in accordance with Section 8.1, any distributions of Available Cash (including Tax Distributions);

        (b)   The approval of the Proposed Budgets for the Company, other than (i) the Initial Budget, which shall be deemed approved upon the execution of this Agreement and (ii) budget items associated with capital expenditures relating to the agreements set forth on Exhibit G; provided that the Company may not without the Requisite Member Approval (i) enter into any additional **, (ii) enter into any agreements or transactions referred to in ** or **, or (iii) extend the term of any of the agreements set forth on Exhibit G. In connection with any such approval, the Members having the authority to approve the Proposed Budget shall give the notice required by Section 6.15(d) below;

        (c)   Material deviations from Approved Budgets, including (i) with respect to any Approved Budget, any modification or amendment of any ** or other ** contained therein, the satisfaction of which results in the ** pursuant to such budget, (ii) with respect to the capital expenditure budget, changes of more than ** to the **, but excluding any items prior to the Equalization Date requiring aggregate capital expenditures of less than $** associated with a Project **, and excluding any items after the Equalization Date requiring aggregate capital expenditures of less than $** associated with a Project ** and (iii) with respect to the operating expenditure budget, increases of more than $** to the ** or increases of more than $** to the ** calculated on a **; provided that, in any case, a Project, operation, venture, agreement or activity that has received Requisite Member Approval shall automatically be incorporated within the Approved Budget and any changes or deviations required to incorporate such Project, operation, venture, agreement or

32

activity into the then current Approved Budget shall not require additional Requisite Member Approval; provided further that any additional changes or deviations associated with such Project, operation, venture, agreement or activity shall be subject to Requisite Member Approval to the extent they involve material deviations to the Approved Budget, as modified to include such new Project, operation, venture, agreement or activity, under this clause (c); provided, further, that changes in budget items listed in Section 6.15(a)(iii) through (vi) shall not be considered material deviations for purposes of this Section 6.12(c);

        (d)   Any material change in the Primary Business or in the Company's purpose;

        (e)   The incurrence of Debt and the granting of Liens on the Company's Property in an aggregate amount in excess of (A) $** prior to the Equalization Date and (B) $** after the Equalization Date, in each case excluding the Permitted Liens;

        (f)    Any interest rate protection agreement, foreign currency exchange agreement, commodity price protection agreement, or other interest, currency or commodity hedging arrangement entered into by the Company, including any forward sales, calls, puts, swaps and other derivative transactions, whether financially or physically settled; provided that transactions to be settled (i) within ** based on ** or (ii) ** based on the **, shall not require Requisite Member Approval;

        (g)   The acquisition or sale of any assets of the Company or its subsidiaries for consideration in excess of (i) $** prior to the Equalization Date and (ii) $** after the Equalization Date;

        (h)   Entry into, termination or renewal of, or material modification or amendment of, (i) any commercial contractual commitment reasonably expected to (A) result in expenditures or liabilities in excess of $**, which $** threshold shall be subject to increase by ** per year, (B) generate annual revenues in excess of $**, which $** threshold shall be subject to increase by ** per year, or (C) result in the commitment of more than ** of the capacity of any Company facility **, (ii) any joint venture, partnership or other similar arrangement involving the sharing of profits of the Company or any of its subsidiaries with any third-party, (iii) any contractual commitment that limits the freedom of the Company or any of its subsidiaries to compete within the Area of Mutual Interest, (iv) any contract for the lease of real property for ** and (v) settlement agreements or other agreements related to or proposing to resolve actual or threatened litigation, which involves (A) payment of greater than $** or (B) provides for restrictions or limitations on the Company's ability to operate in the form of an equitable remedy;

        (i)    The formation of any subsidiary of the Company;

        (j)    Transactions or agreements (including amendments, terminations and renewals thereof) between the Company on the one hand, and a Member or an Affiliate of a Member on the other hand, unless such transaction or agreements (including amendments, terminations and renewals thereof) (i) has been approved by the other Members that are not a party to, or Affiliates of a Party to, such transaction or agreement and whose consent is required pursuant to this Section or (ii) is identified on Exhibit H, all of which are hereby approved by the Members;

        (k)   The sale, exchange or other disposition of all, or substantially all, of the Company's assets in one transaction or a series of related transactions,

        (l)    Any merger into or with or consolidation with any other entity (i) in which the interests in the Company will be exchanged for a security with different rights, preferences or privileges or (ii) pursuant to which the Members will own less than 50% of the voting securities of the surviving entity;

        (m)  Any repurchase by the Company of Interests in the Company or any equity interests in any of its subsidiaries;

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        (n)   Prior to the Equalization Date, other than in accordance with the obligations of the Members pursuant to Section 4.1, any efforts by the Company to raise additional capital, including the issuance of additional Interests or options to acquire Interests or any equity interests or options to acquire equity interests in any of the Company's subsidiaries;

        (o)   The registration of any equity or debt securities of the Company or its subsidiaries under applicable United States federal or foreign securities laws or any public offering of equity or debt securities of the Company or its subsidiaries (including any Qualified Public Offering).

        (p)   Any declaration of bankruptcy, or the filing of a petition, or seeking protection, under any federal or state bankruptcy, insolvency or reorganization law;

        (q)   The dissolution of the Company or the voluntary liquidation of the Company's assets;

        (r)   Designating a new Operator of the Company;

        (s)   Approval of the maintenance of reserves less than the ** as authorized in the Approved Budget or more than the ** in the Approved Budget;

        (t)    Permit the Company to create any Debt in favor of any Person;

        (u)   Distributions in-kind of any assets of the Company pursuant to Section 13.7;

        (v)   Hiring any employees of the Company or accepting secondments of employees;

        (w)  After the ** in ** becomes operational, and thereafter to the extent there is available **, elections by the Company to ** to MWE Hydrocarbon under the Fractionation and NGL Purchase Agreement;

        (x)   Any action by the Company that would cause it to be ** under the **; and

        (y)   The entry into any agreement to effect any of the foregoing.

        Section 6.13    Reliance by Third Parties.    

        Any Person dealing with the Company, a Manager or the Operator may rely upon a certificate signed by a Manager or an appropriate officer as to:

        (a)   the identity of the Managers;

        (b)   the existence or non-existence of any fact or facts which constitute a condition precedent to acts by the Board or in any other manner germane to the affairs of the Company;

        (c)   the Persons who are authorized to execute and deliver any instrument or document of or on behalf of the Company; and

        (d)   any act or failure to act by the Company or as to any other matter whatsoever involving the Company or any Member.

        Section 6.14    Fees and Expenses of the Managers.    

        A Class A Manager shall receive an annual amount of $** for serving as a Manager. A Class B Manager shall not be entitled to any fees for serving as a Manager. A Manager shall be entitled to reimbursement for all reasonable out-of-pocket costs and expenses incurred by such Manager in the capacity as a Manager.

        Section 6.15    Budgets.    

        By ** of each calendar year following the Effective Time, the Operator shall prepare and submit the following budgets and forecasts for the upcoming year (to the extent such budgets or forecasts are

34

applicable to such upcoming year) to the Board for approval and to the appropriate Members for Requisite Member Approval in accordance with Section 6.12:

        (a)   (i) an operating expenditure oversight budget, which shall consist of the operating expenditure budget broken down by general categories of expenses for categories exceeding an aggregate **; (ii) a capital expenditure budget which shall include, to the extent applicable, maintenance capital expenditures and growth capital expenditures; (iii) a cost of goods sold budget or forecast; (iv) a volume budget or forecast; (v) a revenue budget or forecast; and (vi) a forecast of distributions or capital contributions (collectively, the "Proposed Budget").

        (b)   The Board and the Members with Requisite Member Approval Rights shall have 15 days to review and to either approve or to reject the Proposed Budget, in whole or in part. Any rejection of the Proposed Budget in whole or in part must be made in good faith, based on commercially reasonable standards and submitted in writing to the Board, the other Members with Requisite Member Approval rights and the Operator and must describe proposed modifications in reasonable detail (a "Budget Rejection Notice"). If a Budget Rejection Notice is not received within the requisite 15 day period, then the Proposed Budget will be deemed to be approved in all respects. If a Budget Rejection Notice is received within the requisite 15 day period, the Operator, the Board and the Members with Requisite Member Approval rights to approve the Proposed Budget will work together in good faith to promptly resolve the issues identified in a mutually agreeable manner and, if such dispute is not resolved prior to the commencement of the calendar year to which the Proposed Budget relates, the Approved Budget for the prior calendar year, increased by the percentage increase in the CP Index since the first day of the previous calendar year, shall be in effect until such dispute is resolved. If such dispute is not resolved by January 30^th of the calendar year to which the Proposed Budget relates, such dispute shall be submitted to arbitration pursuant to Section 6.15(e) below. The Proposed Budget as approved, or as deemed approved, by the Board and Requisite Member Approval in accordance with Section 6.12, and as modified in accordance with Section 6.15(c) below, is referred to herein as an "Approved Budget."

        (c)   Subject to the remaining provisions of this clause (c), the Operator shall update the Approved Budget from time to time to reflect amendments or modifications that the Operator deems necessary or appropriate, and shall promptly provide such updates to the Board; provided that any material deviations which require the consent of the Board or Requisite Member Approval in accordance with Section 6.12(c) shall not become part of the Approved Budget unless approved by the Board and Requisite Member Approval.

        (d)   Once a Proposed Budget or material deviations from an Approved Budget pursuant to Section 6.12(c) have been approved by the Board and have received Requisite Member Approval pursuant to Section 6.12, each Member that has the right to approve such Proposed Budget (or deviations from an Approved Budget) shall at the time of the approval, give notice to the Board of their intent to fund any budget item to the extent that such item would require the Board to make a Capital Call in order to fund such budget item.

        (e)   The binding arbitration shall be administered by the American Arbitration Association ("AAA") in accordance with its Commercial Arbitration Rules (the "Rules"). The "Arbitration Panel" shall consist of three members. The Class A Members and the Class B Members, acting by the vote of Members holding Class A Interests or Class B Interests with an aggregate Class A Percentage Interest or Class B Percentage Interest, respectively, equal to or exceeding 50% shall appoint one member of the Arbitration Panel. The third member of the Arbitration Panel shall be chosen by the appointed members and shall act as chairman of the Arbitration Panel. Should any arbitrator fail to be appointed in accordance with the foregoing, then such arbitrator shall be appointed by the AAA in accordance with the Rules. The arbitration shall be held in Houston,

35

Texas, and the proceeding shall be conducted and concluded as soon as reasonably practicable, based upon the schedule established by the Arbitration Panel, but in any event the decision of the Arbitration Panel shall be rendered within 90 days following the selection of the chairman of the Arbitration Panel. The decision of the Arbitration Panel shall be final and binding upon the Company and the Members. Judgment upon the award rendered by the Arbitration Panel may be entered in, and enforced by, any court of competent jurisdiction. Each class of Members shall bear its own expenses related to the arbitration, including its attorneys' fees and the fees and expenses of the arbitrator it appointed. Each class of Members shall pay 50% of the fees and expenses of the chairman of the Arbitration Panel.

ARTICLE 7
ASSIGNABILITY OF MEMBER INTERESTS

        Section 7.1    Prohibition on Assignment During Project Period.    

        Prior to ** (the "Project Period"), no Member may, directly or indirectly, Transfer its Interest or any portion thereof without the prior written consent of the other Members except for Permitted Transfers. For purposes of this Agreement, "Permitted Transfers" shall include the following: (a) a Member may Transfer all or a portion of its Interest to any of its Affiliates, (b) Interests held by any member of the MWE Liberty Group may be (i) Transferred, in whole or in part, in connection with any sale of all or substantially all of the assets of MWE, or (ii) indirectly Transferred by way of a sale of Control of MWE, or any merger of MWE with or into, or any consolidation of MWE into, any other entity and (c) Interests held by NGPMR may be transferred to the limited partners of NGPMR, if and to the extent required by the governance documents of NGPMR. In the event of a Transfer pursuant to the foregoing clause (c), the NGPMR Group shall designate a single representative to exercise all of the NGPMR Group's rights hereunder. If a Member Transfers an Interest during the Project Period in accordance with this Section 7.1, such Transfer shall entitle the assignee to become a Substitute Member and to exercise or receive the rights, powers or benefits of a Member if the assigning Member designates, in a written instrument delivered to the Board and the other Members, its assignee to become a Substitute Member and such assignee executes an instrument reasonably satisfactory to the Board, which shall include an acceptance and agreement by the Substitute Member to abide by all of the terms and conditions of this Agreement. A Member may not Transfer Interests in a Permitted Transfer if such Permitted Transfer has as a purpose the avoidance of the restrictions on Transfers in this Agreement (it being understood that the purpose of this sentence is to prohibit the Transfer of Interests to a transferee in a Permitted Transfer followed by a change in the relationship between the transferor and the transferee (or a change of Control of such transferor or transferee) after the Permitted Transfer with the result and effect that the transferor has indirectly Transferred Interests to a transferee in a Transfer which would not have been directly permitted as a Permitted Transfer under this Section 7.1 had such change in such relationship occurred prior to such Transfer).

        Section 7.2    Transfers After the Project Period.    

        After the Project Period, a Member may Transfer its Interest, or any portion thereof, without the consent of any other Member or the Board, provided that such Member complies with the requirements of this Section 7.2 in all instances except in connection with Permitted Transfers:

        (a)   In the event that a Member (the "Transferring Member") desires to Transfer, directly or indirectly, all or any portion of its Interest (the "ROFO Interest") and such Transfer is not a Permitted Transfer, then the Transferring Member shall give written notice thereof to the other Members (the "Remaining Members"). For a period of 30 days thereafter, all or a portion of the Remaining Members shall have the right, but not the obligation, to submit a written offer to purchase the ROFO Interest (with each offering Remaining Member to purchase its pro rata portion of the ROFO Interest as is determined in accordance with the respective Percentage

36

Interests of the Remaining Members, or such other portion as the Remaining Members may mutually agree upon) (the "ROFO Offer"), on such terms and conditions as the offering Remaining Members may determine and which terms and conditions shall be described in the ROFO Offer. Upon receipt of the ROFO Offer, the Transferring Member may elect in its sole discretion to accept or reject the ROFO Offer.

          (i)  In the event that the Transferring Member elects to accept the ROFO Offer, then the Transferring Member shall be bound to Transfer to the offering Remaining Members, and the offering Remaining Members shall be bound to purchase from the Transferring Member, the ROFO Interest on the terms and conditions set forth in the ROFO Offer (with such modifications as may be mutually agreed upon by the offering Remaining Members and the Transferring Member), and the closing of such Transfer of the ROFO Interest shall occur within 30 days of the Transferring Member's acceptance of the ROFO Offer or on such other date as may be set forth in the ROFO Offer (subject to extension to the extent necessary to pursue any required regulatory approvals, including to allow for the expiration or termination of all waiting periods under the Hart-Scott-Rodino Antitrust Improvements Act of 1976).

         (ii)  In the event that the Transferring Member rejects the ROFO Offer, then for a 60-day period after the date on which the Transferring Member rejects the ROFO Offer (the "Solicitation Period"), the Transferring Member may solicit an offer to purchase the ROFO Interest from one or more third parties as the Transferring Member may determine in its discretion. If the Transferring Member receives a third party offer (a "Third Party Offer") to purchase the ROFO Interest within the Solicitation Period, and the consideration payable for the ROFO Interest pursuant to such Third Party Offer exceeds the consideration payable for the ROFO Interest pursuant the ROFO Offer (such Third Party Offer is referred to as a "Qualifying Third Party Offer"), the Transferring Member may elect to Transfer the ROFO Interest to such third party in accordance with the Qualifying Third Party Offer within 30 days after the end of the Solicitation Period, subject to the Transferring Member's compliance with the provisions of Section 7.2(b). Any noncash consideration set forth in the ROFO Offer or a Third Party Offer shall be valued at its fair market value, as agreed by the Transferring Member and the offering Remaining Members, and failing such agreement, as determined by an independent third party appraiser selected by the Transferring Member and reasonably acceptable to the offering Remaining Members (the costs for which third party appraiser shall be shared equally by the Transferring Member, on the one hand, and the offering Remaining Members, on the other hand). The Transferring Member may not Transfer the ROFO Interest to any third party pursuant to a Third Party Offer that is not a Qualifying Third Party Offer without the offering Remaining Members' prior written consent, which may be withheld in their sole discretion. Such transferee shall become a Substitute Member if the Transferring Member designates, in a written instrument delivered to the Board and the other Members, the transferee to become a Substitute Member and such transferee executes an instrument reasonably satisfactory to the Board, which shall include an acceptance and agreement by the Substitute Member to abide by all of the terms and conditions of this Agreement. If such closing does not occur within the required 30-day period, then the ROFO Interest in question shall once again become subject to the restrictions of this Section 7.2, and the Transferring Member shall no longer be permitted to Transfer such ROFO Interest without again fully complying with the provisions of this Section 7.2

        (b)   Except for any Transfer to another Member and except for Permitted Transfers, each Class B Member hereby agrees, whether in one transaction or in a series of related transactions, not to Transfer for value, all or any portion of its Interest, directly or indirectly, without first complying with Section 7.2(a) and then permitting each of the Remaining Members (the "Tag-Along Members") to participate as sellers in such transaction (the "Tag-Along Rights"), such

37

that each Tag-Along Member shall be entitled to sell, on the same terms as the Class B Member proposing to sell its Interest (the "Class B Seller"), a portion of such Tag-Along Member's Interest, determined by multiplying the Interest that the purchaser is willing to acquire by the Percentage Interest of each such Tag-Along Member desiring to participate.

          (i)  Before accomplishing or entering into a binding contract for any Transfer for value of any Interest that would be covered by the Tag-Along Rights, the Class B Seller agrees to give each Tag-Along Member written notice (the "Tag-Along Notice") of any such proposed sale (the "Sale Proposal"). The Tag-Along Notice shall state that such Tag-Along Member shall be entitled to exercise its Tag-Along Rights. Each Tag-Along Member shall notify the Class B Seller in writing within 10 days after receipt of the Tag-Along Notice as to whether or not such Tag-Along Member wishes to exercise Tag-Along Rights and participate in the proposed Transfer (the "Tag-Along Notice Period"). Failure by any Tag-Along Member to respond within such period shall be deemed to be a declination of such Tag-Along Member's Tag-Along Rights with respect to such proposed transfer. The Class B Seller shall use its commercially reasonable efforts to obtain the agreement of the prospective transferee(s) to the participation of the Tag-Along Members in any contemplated Sale Proposal and to the inclusion of the Tag-Along Members' Interests in such transaction, and no Class B Seller shall transfer any portion of the Interest to any prospective transferee if such prospective transferee(s) declines to allow the participation of the Tag-Along Members or the inclusion of their Interests as contemplated herein. Each Tag-Along Member that elects to participate pursuant to this paragraph shall pay its pro rata share (based on the Interests to be Transferred) of the expenses incurred by the Class B Seller in connection with such Sale Proposal and shall be obligated to join on a pro rata basis (based on the Interests to be Transferred) in any indemnification or other obligations that Class B Seller agrees to provide in connection with such Sale Proposal (other than any such obligations that relate specifically to a particular Member such as indemnification with respect to representations and warranties given by a Member regarding such Member's title to and ownership of its Interest); provided that no Tag-Along Member shall be obligated in connection with such Sale Proposal to agree to indemnify or hold harmless the transferee with respect to an amount in excess of the net cash proceeds paid to such Tag-Along Member in connection with such Sale Proposal. If the Tag-Along Members decline, or are deemed to decline, their Tag-Along Rights for any proposed transfer, the Class B Seller may sell its offered Interest; provided, however, that (i) such Sale Proposal is consummated within 90 days after the end of the Tag-Along Notice Period and (ii) the terms of the actual transaction involve exactly the same consideration and other terms and conditions set forth in the Tag-Along Notice. Any transferee pursuant to the Sale Proposal shall become a Substitute Member if the Class B Seller designates, in a written instrument delivered to the Board and the other Members, the transferee to become a Substitute Member and such transferee executes an instrument reasonably satisfactory to the Board, which shall include an acceptance and agreement by the Substitute Member to abide by all of the terms and conditions of this Agreement. Failure to close the Sale Proposal within the required 90-day period shall again subject the offered Interest to the Tag-Along Rights set forth in this Section 7.2(b), whereupon the Class B Seller shall be required to give each Tag-Along Member a new written notice with respect to the proposed transfer, and each Tag-Along Member shall again have the right to exercise Tag-Along Rights in respect of such proposed transfer.

         (ii)  If a Class B Seller wishes to solicit Sale Proposals from third parties involving a Company Sale, it shall first notify the other Members of its desire to solicit a Company Sale ("Solicitation Notice"). The other Members shall notify the Class B Seller in writing within 10 days after receipt of the Solicitation Notice as to whether or not such Members wish to participate in a Company Sale and shall specify a minimum price ("Minimum Price") at which

38

such Members are willing to sell their Interest thereunder ("Solicitation Response"). If the Class B Seller obtains Solicitation Responses from all of the Members indicating each Member's desire to enter into a Company Sale and a Minimum Price with respect to each Member, then the Class B Seller may solicit offers for a Company Sale. If the Class B Seller obtains an offer within 90 days of its receipt of the Solicitation Responses for a Company Sale in excess of each of the Minimum Prices set forth in the Solicitation Responses, it may cause a Company Sale **. If the Class B Seller does not obtain an offer for a Company Sale in excess of the minimum prices set forth in the Solicitation Responses within 90 days of its receipt of the Solicitation Responses, then the Class B Seller may not pursue a Company Sale. For the avoidance of doubt, this Section 7.2(b)(ii) shall only apply to a Company Sale to be solicited by a Class B Member. Any sale of the Interest of a Class B Seller that is not a Company Sale shall remain subject to the provisions of Section 7.2(b)(i) above.

        (c)   The consideration or value allocated to the Members under this Section 7.2 shall be allocated among the Transferring Member and other Members (whether Tag-Along Members or otherwise) in accordance with their respective rights to distributions from the Company as if the Company had been liquidated pursuant to Section 13.4 and the Company had sold all of its Property for an Appraised Value using the implied valuation of such Property that may be derived from the sales process described in Section 7.2, provided, that, for purposes of determining whether the ** Payout, ** has been met, only the actual cash proceeds from the sale received by NGPMR shall be considered rather than the proceeds allocable to NGPMR from an implied valuation based upon a sale of all of the Company's Property and, except for such consideration, no Member will receive any payments of any nature whatsoever from the transferee in connection with or arising from such sale transaction.

        Section 7.3    Recognition of Assignment by Company or Other Members.    

        No Transfer of an Interest that is in violation of this Article 7 shall be valid or effective, and neither the Company nor the Board nor any Member shall recognize the same for any purpose of this Agreement, including the purpose of making distributions of Available Cash pursuant to this Agreement with respect to such Interest or part thereof. Neither the Company nor the Board shall incur any liability as a result of refusing to make any such distributions to the assignee of any such invalid assignment.

        Section 7.4    Effective Date of Assignment.    

        Any valid Transfer of a Member's Interest, or part thereof, pursuant to the provisions of this Article 7 shall be effective as of the later of (i) the date of Transfer set forth on the written instrument of Transfer, (ii) the date on which the Company has received the written instrument of Transfer and such other documents as may be required by the Company pursuant to this Agreement and such Transfer has been recorded on the books of the Company, and (iii) the date on which the requirements of this Article 7 have been satisfied. The Company shall, from the effective date of such Transfer, thereafter pay all further distributions on account of the Interest (or part thereof) so assigned to the assignee of such Interest, or part thereof. As between any Member and its assignee, Profits and Losses for the Fiscal Year of the Company in which such assignment occurs shall be apportioned for federal income tax purposes in accordance with any convention permitted under Section 706(d) of the Code and selected by the Board.

        Section 7.5    Limitations on Transfer.    

        No Transfer of an Interest may be effectuated unless in the opinion of counsel satisfactory to the Board, the Transfer (a) would comply with the Securities Act and applicable securities laws of any other jurisdiction; (b) would not cause the Company to be terminated for purposes of Code

39

Section 708; or (c) would not violate any other applicable laws, provided that the provisions of this Section 7.5 may be waived by the Board.

        Section 7.6    Transferee Not a Substitute Member.    

        In the event that a transferee is not designated, or does not become, a Substitute Member pursuant to this Article 7, then such transferee shall not be entitled to exercise or receive any of the rights, powers or benefits of a Member other than the right to receive distributions to which the assigning Member would be entitled.

ARTICLE 8
DISTRIBUTIONS TO MEMBERS

        Section 8.1    Available Cash.    

        Available Cash shall be determined by the Board on a quarterly basis within 30 days after the end of each calendar quarter. Subject to the remaining provisions of this Article 8 and any preferential or disproportionate distributions to the extent expressly provided for in this Agreement, and other than upon a liquidation of the Company pursuant to Section 13.4, the Company shall distribute such Available Cash within 45 days following the end of each calendar quarter to the Members of record, as follows.

        (a)   Following the end of each calendar quarter prior to December 31, 2010, all Available Cash shall be allocated for distribution among the Members in accordance with their respective Percentage Interests, and all Available Cash which is so allocated for distribution shall, (x) with respect to the Class A Members be retained by the Company for reinvestment without being distributed to such Class A Members, and (y) with respect to the Class B Members be distributed to such Class B Members and automatically reinvested (pursuant to Section 4.1(b)(iv)) in accordance with their Class B Percentage Interests. With respect to each Class A Member, the amount retained in accordance with clause (x) of the immediately preceding sentence shall increase the Investment Balance of such Class A Member on a dollar-for-dollar basis and, with respect to each Class B Member, the amount distributed and automatically invested and deemed contributed to the Company in accordance with clause (y) of the immediately preceding sentence shall increase the Investment Balance of such Class B Member on a dollar-for-dollar basis.

        (b)   Following the end of each calendar quarter ending on or after December 31, 2010, Available Cash shall be distributed to the Members as follows:

          (i)  If the Equalization Date has not yet occurred, then:

        (A)  First, 100% to the Class A Members in accordance with their Class A Percentage Interests, until the Preference Amount accruing for such calendar quarter is reduced to zero; and

        (B)  Thereafter, to the Members in accordance with their respective Percentage Interests.

         (ii)  If the Equalization Date has occurred, then to the Members in accordance with their respective Percentage Interests.

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        Section 8.2    Incentive Interest Percentage Distributions.    

        Notwithstanding the preceding provisions in Sections 8.1(a) and (b), any Available Cash remaining after a ** Payout** has occurred shall be distributed as follows:

**    Following the ** Payout, if any, (x) first calculated in accordance with their respective Percentage Interests, then (y) adjusted by reducing NGPMR's pro rata amount of Available Cash as determined in (x) by the ** and (z) increasing MWE Liberty's pro rata amount of Available Cash as determined in (x) by the amount determined in (y) **

**

Exhibit E contains illustrative examples of the determination of the amounts to be distributed to NGPMR and MWE Liberty pursuant to Section** 8.2** based on hypothetical distributions of Available Cash. This Section 8.2 shall be interpreted and applied in a manner consistent with the examples set forth in Exhibit E.

        Section 8.3    Withholding.    

        All amounts withheld pursuant to the Code or any provision of any foreign, state or local tax law or treaty with respect to any payment, distribution or allocation to the Company or the Members shall be treated as amounts distributed to the Members pursuant to this Article 8 for all purposes of this Agreement. The Board is authorized to withhold from distributions, or with respect to allocations, to the Members and to pay over to any federal, foreign, state or local government any amounts required to be so withheld pursuant to the Code or any provision of any other federal, foreign, state or local law or treaty and shall allocate such amounts to those Members with respect to which such amounts were withheld.

        Section 8.4    Limitations on Distribution.    

        Except as provided in this Agreement, no Member shall be entitled to any distribution of cash or other property from the Company. Notwithstanding any provision to the contrary contained in this Agreement, the Company shall not make a distribution to any Member on account of its Interest in the Company if such distribution would violate the Act or other applicable law.

        Section 8.5    Tax Distributions.    

        (a)   Each Member shall be entitled to receive, on the date which is two Business Days prior to each date on which estimated income tax payments are required to be made by an individual calendar year taxpayer and each due date for the income tax return of an individual calendar year taxpayer (each a "Tax Distribution Date"), cumulative cash distributions in an amount equal to such Member's Assumed Tax Liability, if any. The "Assumed Tax Liability" of each Member means an amount equal to (i) the cumulative amount of federal income taxes (including any applicable estimated taxes), determined taking into account the character of income and loss allocated to such Member as it affects the applicable tax rate, that the Board estimates would be due from such Member as of such Tax Distribution Date, assuming such Member were an individual that earned solely the items of income, gain, deduction, loss and/or credit allocated to such Member pursuant to Section 9.4 (after reflecting any adjustments thereto by reason of Code Sections 732(d), 734, or 743), reduced by (ii) all previous distributions made to such Member pursuant to this Article 8 (other than distributions distributed and reinvested pursuant to Section 8.1(a)).

        (b)   Distributions under this Section shall be treated as an advance distribution under and shall offset future distributions that such Member would otherwise be entitled to receive pursuant to Section 8.1 or, if not previously offset, Section 13.4.

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        (c)   If on a Tax Distribution Date there are not sufficient funds on hand to distribute to each Member the full amount of such Member's Assumed Tax Liability, distributions pursuant to this Section 8.5 shall be made to the Members to the extent of the available funds in proportion to each Member's Assumed Tax Liability.

ARTICLE 9
ALLOCATIONS

        Section 9.1    Profits and Losses.    

        (a)   After giving effect to the special allocations set forth in Section 9.2 and 9.3 and subject to the allocations contained in Section 13.4(b), all Profits and Losses from operations for each Fiscal Year (or part thereof) shall be allocated to the Class A Members and the Class B Members in accordance with their Percentage Interests; provided, no Losses shall be allocated to any Member to the extent that such Losses would result in a Member having an Adjusted Capital Account Deficit.

        Section 9.2    Special Allocations.    

        Notwithstanding anything in this Agreement to the contrary, the following special allocations shall be made:

        (a)   Nonrecourse Deductions. Nonrecourse Deductions for any taxable year shall be allocated to the Members in accordance with their Percentage Interests.

        (b)   Member Nonrecourse Deductions. Member Nonrecourse Deductions for any taxable year shall be allocated 100% to the Member that bears the Economic Risk of Loss with respect to the Member Nonrecourse Debt to which such Member Nonrecourse Deductions are attributable in accordance with Treasury Regulation Section 1.704-2(i). If more than one Member bears the Economic Risk of Loss with respect to a Member Nonrecourse Debt, Member Nonrecourse Deductions attributable thereto shall be allocated between or among such Members in accordance with the ratios in which they share such Economic Risk of Loss. This Section 9.2(b) is intended to comply with the provisions of Treasury Regulation Section 1.704-2(i) and shall be interpreted consistently therewith.

        (c)   Company Minimum Gain Chargeback. Notwithstanding any other provision of this Agreement, if there is a net decrease in Minimum Gain during any taxable year, each Member shall be allocated items of Company income and gain for such year (and, if necessary, subsequent taxable years) in the manner and amounts provided in Treasury Regulation Sections 1.704-2(f)(6), (g)(2) and (j)(2)(i). For purposes of this Section 9.2, each Member's Capital Account shall be determined, and the allocation of income or gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Article 9 with respect to such taxable year. This Section 9.2(c) is intended to comply with the partner minimum gain chargeback requirement in Treasury Regulation Section 1.704-2(f) and shall be interpreted consistently therewith.

        (d)   Member Nonrecourse Debt Minimum Gain Chargeback. Notwithstanding the other provisions of this Agreement (other than Section 9.2(c) above), if there is a net decrease in Member Nonrecourse Debt Minimum Gain during any taxable year, any Member with a share of Member Nonrecourse Debt Minimum Gain at the beginning of such taxable year shall be allocated items of Company income and gain for such year (and, if necessary, subsequent taxable years) in the manner and amounts provided in Treasury Regulation Section 1.704-2(i)(4) and (j)(2)(ii). For purposes of this Section 9.2, each Member's Adjusted Capital Account balance shall be determined, and the allocation of income and gain required hereunder shall be effected, prior to the application of any other allocations pursuant to this Article 9, other than Section 9.2(c) above, with respect to such taxable year. This Section 9.2(d) is intended to comply with the partner

42

nonrecourse debt minimum gain chargeback requirement in Treasury Regulation Section 1.704-2(i)(4) and shall be interpreted consistently therewith.

        (e)   Qualified Income Offset. Except as provided in Sections 9.2(c) and 9.2(d) above, in the event any Member unexpectedly receives an adjustment, allocation or distribution described in Treasury Regulation Sections 1.704-1(b)(2)(ii)(d)(4), (5) or (6), items of Company income and gain shall be allocated to such Member in an amount and manner sufficient to eliminate, to the extent required by such Treasury Regulation, the deficit balance, if any, in its Adjusted Capital Account created by such adjustment, allocation or distribution as quickly as possible unless such deficit balance is otherwise eliminated pursuant to Sections 9.2(c), 9.2(d) or 9.2(f). This Section 9.2(e) is intended to constitute a qualified income offset described in Treasury Regulation Section 1.704-1(b)(2)(ii)(d) and shall be interpreted consistently therewith.

        (f)    Priority Allocation.

          (i)  Items of Company gross income and gain shall be allocated to the Class A Members in accordance with their Class A Percentage Interests, until the aggregate amounts of such items allocated to the Class A Members for such Fiscal Year equals the amount distributed to the Class A Members pursuant to Section 8.1(b)(i)(A) for all Fiscal Years that have not been previously reflected by an allocation pursuant to this Section 9.2(f).

         (ii)  After giving effect to all preceding allocations in Section 9.2(f)(i), all or a portion of the remaining items of Company income or gain for the Fiscal Year, if any, shall be allocated to MWE Liberty in an amount equal to the cumulative cash distributed to MWE Liberty pursuant to Sections 8.2(a), 8.2(b) or 8.2(c) (to the extent of such distributions in excess of MWE Liberty's Percentage Interest), less the cumulative amount of income and gain previously allocated to MWE Liberty pursuant to this Section 9.2(f)(ii).

        (g)   Gross Income Allocation. In the event any Member has a deficit balance in its Adjusted Capital Account at the end of any taxable year, such Member shall be allocated items of Company gross income and gain in the amount of such excess as quickly as possible; provided, however, that an allocation pursuant to this Section 9.2(g) shall be made only if and to the extent that such Member would have a deficit balance in its Adjusted Capital Account after all other allocations provided in this Section 9.2 (other than Section 9.2(e)) have been tentatively made as if Section 9.2(e) and this Section 9.2(g) were not in this Agreement.

        Section 9.3    Curative Allocations.    

        The allocations set forth in Section 9.2 (other than Section 9.2(f)) (the "Regulatory Allocations") are intended to comply with certain requirements of the Treasury Regulations. It is the intent of the Members that, to the extent possible, all Regulatory Allocations shall be offset either with other Regulatory Allocations or with special allocations of other items of Company income, gain, loss or deduction pursuant to this Section 9.3. Therefore, notwithstanding any other provision of this Article 9 (other than the Regulatory Allocations), but subject to the Code and the Treasury Regulations, the Board shall make such offsetting special allocations of Company income, gain, loss or deduction in whatever manner it determines appropriate so that, after such offsetting allocations are made, each Member's Capital Account balance is, to the extent possible, equal to the Capital Account balance such Member would have had if the Regulatory Allocations were not part of this Agreement. In exercising its discretion under this Section 9.3, the Board shall take into account future Regulatory Allocations that, although not yet made, are likely to offset other Regulatory Allocations previously made.

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        Section 9.4    Income Tax Allocations.    

        (a)   Except as provided in this Section 9.4, each item of income, gain, loss and deduction of the Company for federal income tax purposes shall be allocated among the Members in the same manner as such items are allocated for book purposes under Sections 9.1, 9.2, 9.3 and 13.4(b).

        (b)   In accordance with Code Section 704(c) and the applicable Treasury Regulations thereunder, income, gain, loss and deduction with respect to any property contributed to the Company shall, solely for tax purposes, be allocated among the Members so as to take account of any variation between the adjusted basis of such property to the Company for federal income tax purposes and its Gross Asset Value at the time of its contribution to the Company. If the Gross Asset Value of any Company property is adjusted in accordance with clause (c) or (d) of the definition of Gross Asset Value, then subsequent allocations of income, gain, loss and deduction shall take into account any variation between the adjusted basis of such property for federal income tax purposes and its Gross Asset Value as provided in Code Section 704(c) and the related Treasury Regulations. For purposes of such allocations, the Company shall elect the remedial allocation method described in Treasury Regulation Section 1.704-3(d).

        (c)   All items of income, gain, loss, deduction and credit allocated to the Members in accordance with the provisions hereof and basis allocations recognized by the Company for federal income tax purposes shall be determined without regard to any election under Section 754 of the Code which may be made by the Company.

        (d)   If any deductions for depreciation or cost recovery are recaptured as ordinary income upon the Transfer of Company properties, the ordinary income character of the gain from such Transfer shall be allocated among the Members in the same ratio as the deductions giving rise to such ordinary character were allocated.

        Section 9.5    Allocation and Other Rules.    

        (a)   In the event Members are admitted to the Company pursuant to this Agreement on different dates, the Profits (or Losses) allocated to the Members for each Fiscal Year during which Members are so admitted shall be allocated among the Members in proportion to their Percentage Interests during such Fiscal Year in accordance with Section 706 of the Code, using any convention permitted by law and selected by the Board that takes into account the varying interests of the Members during such Fiscal Year.

        (b)   For purposes of determining the Profits, Losses or any other items allocable to any period, Profits, Losses and any such other items shall be determined on a daily, monthly or other basis, as determined by the Board using any method that is permissible under Section 706 of the Code and the Treasury Regulations thereunder.

        (c)   The Members are aware of the income tax consequences of the allocations made by this Article 9 and hereby agree to be bound by the provisions of this Article 9 in reporting their shares of Company income and loss for income tax purposes.

        (d)   Allocations made by the Board under Section 9.2 in reliance upon the advice of the Company's accountants shall be deemed to be made pursuant to any fiduciary obligation to the Company and the Members.

        (e)   If any Member makes a loan to the Company, or the Company makes a loan to any Member, and interest in excess of the amount actually payable is imputed under Code Sections 7872, 483, or 1271 through 1288 or corresponding provisions of subsequent federal income tax law, then any item of income or expense attributable to any such imputed interest shall be allocated solely to the Member who made or received the loan and shall be credited or charged to its Capital Account, as appropriate.

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ARTICLE 10
BOOKS AND RECORDS

        Section 10.1    Inspection Rights Pursuant to Law.    

        The Company shall have obligations to the Members as set forth in this Article 10 respecting books, records and financial statements of the Company.

        Section 10.2    Books and Records.    

        At all times during the continuance of the Company, the Company shall maintain at its principal place of business all records and materials the Company is required to maintain at such location under the Act. The Company shall keep proper and complete books of account adequate for its purposes. The books of account relating to the Company shall be open to inspection and copying by any of the Members or by their authorized representatives upon reasonable notice and at any reasonable time during business hours, at the Member's expense; provided, however, that the Members acknowledge and agree that, to the extent that the books of account include information relating to one or more Affiliates of the Operator (other than the Company) or any Out of Scope Projects or Exempted Projects (the "Unrelated Information"), then the Company and Operator shall be entitled either to redact, or limit access to, the books of account such that the Members shall not have access to Unrelated Information or to require such Member to designate an independent third party auditor to conduct such review, which auditor will be required to execute a confidentiality agreement with the Operator under which such auditor may examine the Unrelated Information but may not disclose the Unrelated Information to such Member.

        Section 10.3    Financial Statements and Reports.    

        The Operator shall prepare, on behalf of the Company and at the Company's expense, and shall submit to the Members the following statements, reports and notices:

        (a)   Annual financial statements of the Company, consisting of a profit and loss statement, balance sheet and statement of cash flows, as of the end of and for the prior Fiscal Year, which shall be prepared in accordance with generally accepted accounting principles consistently applied ("GAAP") and audited by the Operator's independent certified public accountants, which shall be a nationally recognized accounting firm (the "Annual Financial Statements"). The Annual Financial Statements shall be delivered to each Member within 75 days after the end of each Fiscal Year;

        (b)   Unaudited quarterly financial statements of the Company, consisting of a profit and loss statement, balance sheet and statement of cash flows, as of the end of and for the prior calendar quarter, which shall be prepared in accordance with GAAP except for normal year end adjustments and the absence of footnotes (the "Quarterly Financial Statements"). The Quarterly Financial Statements shall be delivered within 45 days after the end of each calendar quarter;

        (c)   Monthly financial and business reports, which shall consist of a profit and loss statement, balance sheet and statement of cash flows, as of the end of and for the prior calendar month, which shall be prepared in accordance with GAAP except for normal year end adjustments and the absence of footnotes (the "Monthly Reports"). The Monthly Reports shall be delivered within 30 days after the end of each calendar month;

        (d)   Copies of the Approved Budget in effect from time to time, within 30 days after the approval thereof in accordance with Section 6.15;

        (e)   Such other information as a Member may reasonably request to satisfy such Member's or its Affiliates' public disclosure obligations under the Exchange Act, the rules of any stock

45

exchange, or any similar public disclosure obligations; provided that public disclosure of any such information shall be subject to the provisions of Section 5.4.

        Section 10.4    Accounting Method.    

        For both financial and tax reporting purposes and for purposes of determining Profits and Losses, the books and records of the Company shall be kept on such method of accounting as determined by the Board and shall reflect all Company transactions and be appropriate and adequate for the Company's business.

        Section 10.5    Bank Accounts; Investments.    

        The Board shall establish one or more bank accounts in the name of the Company into which all Company funds shall be deposited. No other funds shall be deposited into these accounts.

ARTICLE 11
TAX MATTERS

        Section 11.1    Taxation of Company.    

        It is the intent of the Members that the Company shall be treated as a partnership for U.S. federal income tax purposes. Neither the Company nor any Member shall make an election for the Company to be excluded from the application of the provisions of subchapter K of chapter 1 of subtitle A of the Code or any similar provisions of applicable state law or to be classified as other than a partnership pursuant to Treasury Regulation Section 301.7701-3.

        Section 11.2    Tax Returns.    

        The Company shall cause the Operator to prepare, at the expense of the Company, for each Fiscal Year (or part thereof), federal tax returns in compliance with the provisions of the Code and any required state and local tax returns. Each Member shall furnish to the Company all pertinent information in its possession relating to the Company's operations that is necessary to enable the Company's tax returns to be timely prepared and filed. Not less than 60 days prior to the due date (as extended) of the Company's federal income tax return or any state income tax return, the return proposed by the Board to be filed by the Company shall be furnished to the Members for review. In addition, not more than 10 days after the date on which the Company files its federal income tax return or any state income tax return, a copy of the return so filed shall be furnished to the Members.

        Section 11.3    Member Tax Return Information.    

        The Company, at its expense, shall cause to be delivered to each Member within 60 calendar days after the end of the Company's taxable year an IRS Form K-1 or a good faith estimate of the amounts to be included on such IRS Form K-1 for such Member and such other information as shall be necessary (including a statement for that year of each Member's share of net income, net losses and other items allocated to such Member) for the preparation and timely filing by the Members of their federal, state and local income and other tax returns.

        Section 11.4    Tax Matters Representative.    

        (a)   The "tax matters partner" of the Company for purposes of Section 6231(a)(7) of the Code shall be MWE Liberty, so long as MWE Liberty or one of its Affiliates is a Member, and shall have the power to manage and control, on behalf of the Company, any administrative proceeding at the Company level with the Internal Revenue Service relating to the determination of any item of Company income, gain, loss, deduction or credit for federal income tax purposes. Any Member who is designated as the tax matters partner shall be referred to herein as the "Tax Matters Member."

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        (b)   The Tax Matters Member shall keep the Members informed as to the status of any audit of the Company's tax affairs, and shall take such action as may be necessary to cause any Member so requesting to become a "notice partner" within the meaning of Section 6231(a)(8) of the Code. Without first obtaining the approval of the Board and Requisite Member Approval, the Tax Matters Member shall not, with respect to Company tax matters: (i) enter into a settlement agreement with respect to any tax matter which purports to bind Members, (ii) intervene in any action pursuant to Code Section 6226(b)(5), (iii) enter into an agreement extending the period of limitations for making assessments on behalf of Members, or (iv) file a petition pursuant to Code Section 6226(a) or 6228. If an audit of any of the Company's tax returns shall occur, the Tax Matters Member shall not settle or otherwise compromise assertions of the auditing agent which may be adverse to any Member as compared to the position taken on the Company's tax returns without the prior written consent of each such affected Member.

        (c)   No Member shall file a request pursuant to Code Section 6227 for an administrative adjustment of Company items for any taxable year, or a petition under Code Sections 6226 or 6228 or other Code sections with respect to any item involving the Company, without first notifying other Members.

        Section 11.5    Right to Make Section 754 Election.    

        The Board, in its sole discretion, may make or revoke, on behalf of the Company, an election in accordance with Section 754 of the Code, so as to adjust the basis of Company property in the case of a distribution of property within the meaning of Section 734 of the Code, and in the case of a transfer of Interests within the meaning of Section 743 of the Code.

        Section 11.6    Tax Elections.    

        The Company shall have the right to make any U.S. federal income tax elections it deems appropriate and in the best interests of the Members.

        Section 11.7    Tax Reimbursement.    

        If Texas law requires the Company and any Member both to participate in the filing of a Texas margin tax combined group report, and if such Member pays the margin tax liability due in connection with such combined report, the parties agree that the Company shall promptly reimburse such Member for the margin tax paid on behalf of the Company as a combined group member. The margin tax paid on behalf of the Company shall be equal to the margin tax that the Company would have paid if it had computed its margin tax liability for the report period on a separate entity basis rather than as a member of the combined group. In such event, the parties agree that such Member shall be considered as paying such amount on behalf of the Company and the Company shall deduct for federal income tax purposes 100% of the Texas margin tax attributable to the Company; provided that in the event that such deduction may not be properly taken by the Company, the Company shall reimburse such Member for the after-tax cost of such payment of Texas margin tax paid on the Company's behalf.

ARTICLE 12
LIABILITY, EXCULPATION AND INDEMNIFICATION

        Section 12.1    Liability.    

        (a)   Except as otherwise provided by the Act, the debts, obligations and liabilities of the Company, whether arising in contract, tort or otherwise, shall be solely the debts, obligations and liabilities of the Company, and no Covered Person shall be obligated personally for any such debt, obligation or liability of the Company solely by reason of being a Covered Person.

        (b)   Except as otherwise expressly required by law, a Member, in its capacity as Member, shall have no liability in excess of (i) the amount of its Capital Contributions; (ii) its share of any assets

47

and undistributed profits of the Company; (iii) its obligation to make other payments expressly provided for in this Agreement; and (iv) the amount of any distributions wrongfully distributed to it.

        Section 12.2    Exculpation.    

        (a)   No Covered Person shall be liable to the Company or any other Covered Person for any loss, damage or claim incurred by reason of any act or omission performed or omitted by such Covered Person on behalf of the Company and in a manner reasonably believed to be within the scope of authority conferred on such Covered Person by this Agreement, except that a Covered Person shall be liable for any such loss, damage or claim incurred by reason of such Covered Person's fraud, bad faith or willful misconduct as established by a non-appealable court order, judgment, decree or decision.

        (b)   A Covered Person shall be fully protected in relying in good faith upon the records of the Company and upon such information, opinions, reports or statements presented to the Company by any Person as to matters the Covered Person reasonably believes are within such other Person's professional or expert competence and who has been selected with reasonable care by or on behalf of the Company, including information, opinions, reports or statements as to the value and amount of the assets, liabilities, Profits, Losses or Available Cash or any other facts pertinent to the existence and amount of assets from which distributions to Members might properly be paid.

        Section 12.3    Indemnification.    

        To the fullest extent permitted by applicable law, the Company shall indemnify and hold harmless each Covered Person from and against all Claims arising from or related to any act or omission performed or omitted by such Covered Person on behalf of the Company and in a manner reasonably believed to be within the scope of authority conferred on such Covered Person by this Agreement, except that no Covered Person shall be entitled to be indemnified in respect of any Claim by reason of such Covered Person's fraud, bad faith, or willful misconduct as established by a non-appealable court order, judgment, decree or decision. Any indemnity under this Section 12.3 shall be provided out of and to the extent of Company assets only (including the proceeds of any insurance policy obtained pursuant to Section 12.5), and no Covered Person shall have any personal liability on account thereof. Any amendment, modification or repeal of this Section 12.3 or any provision in this Section 12.3 shall be prospective only and shall not in any way affect the rights of any Covered Person under this Section 12.3 as in effect immediately prior to such amendment, modification or repeal with respect to matters occurring, in whole or in part, prior to such amendment, modification or repeal, regardless of when claims relating to such matters may arise or be asserted.

        Section 12.4    Expenses.    

        To the fullest extent permitted by applicable law, expenses (including legal fees) incurred by a Covered Person in defending any claim, demand, action, suit or proceeding shall, from time to time, be advanced by the Company prior to the final disposition of such claim, demand, action, suit or proceeding upon receipt by the Company of an undertaking by or on behalf of the Covered Person to repay such amount if it shall be determined that the Covered Person is not entitled to be indemnified as authorized in Section 12.3.

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        Section 12.5    Insurance.    

        The Company may purchase and maintain insurance, to the extent and in such amounts as the Board shall, in its sole discretion, deem reasonable, on behalf of Covered Persons and such other Persons as the Board shall determine, against any liability that may be asserted against or expenses that may be incurred by any such Person in connection with the activities of the Company or such indemnities, regardless of whether the Company would have the power to indemnify such Person against such liability under the provisions of this Agreement. The Board and the Company may enter into indemnity contracts with Covered Persons and such other Persons as the Board shall determine and adopt written procedures pursuant to which arrangements are made for the advancement of expenses and the funding of obligations under Section 12.4 and containing such other procedures regarding indemnification as are appropriate.

        Section 12.6    Certain Liabilities.    

        Each Member agrees to be liable for the Capital Contributions required to be made by such Member, and subject to the other provisions of this Agreement, in the event a Member becomes liable for any liabilities of the Company, the Members shall bear such liability in proportion to their then existing Percentage Interests.

        Section 12.7    Acts Performed Outside the Scope of the Company.    

        Each Member (each Member in such capacity, an "Indemnitor") shall indemnify, defend, save and hold harmless each other Member (an "Indemnitee") from any and all Claims that shall or may arise by virtue of any act or thing done or omitted to be done by the Indemnitor (directly or through agents or employees) outside the scope of, or in breach of, the terms of this Agreement; provided, however, that the Indemnitor shall be properly notified of the existence of the Claim, and shall be given reasonable opportunity to cure any act or omission causing liability, and participate in the defense thereof. The Indemnitee's failure to give such notice shall not affect the Indemnitor's obligations hereunder, except to the extent of any actual prejudice arising therefrom.

        Section 12.8    Liability of Members to Company or Other Members.    

        Unless otherwise provided in this Agreement, no Member shall be liable to any other Member or to the Company by reason of such Member's actions in connection with the Company, except in the event of a violation of any provision of this Agreement, fraud, bad faith or willful misconduct.

        Section 12.9    Attorneys' Fees.    

        All of the indemnities provided in this Agreement shall include reasonable attorneys' fees, including appellate attorneys' fees and court costs.

        Section 12.10    Subordination of Other Rights to Indemnity.    

        The interests of the Members in any proceeds of the Company by way of repayment of loans, return of any Capital Contributions, or any distributions from the Company, shall be subordinated to the right of Members to the indemnities provided by this Article 12.

        Section 12.11    Survival of Indemnity Provisions.    

        Except as otherwise specifically provided herein, all of the indemnity provisions contained in this Agreement shall survive a Member's ceasing to be a Member hereunder.

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ARTICLE 13
DISSOLUTION, LIQUIDATION AND TERMINATION

        Section 13.1    No Dissolution.    

        The Company shall not be dissolved by the admission of Additional Members or Substitute Members in accordance with the terms of this Agreement, or the withdrawal of a Member.

        Section 13.2    Events Causing Dissolution.    

        The Company shall be dissolved and its affairs shall be wound up upon the occurrence of any of the following events:

        (a)   the determination of the Members pursuant to Section 6.12(p);

        (b)   at such time as there are no Members;

        (c)   the entry of a decree of judicial dissolution under the Act; or

        (d)   the sale, exchange or disposition of all, or substantially all, of the Company's assets in one transaction or a series of related transactions.

        Section 13.3    Notice of Dissolution.    

        Upon the dissolution of the Company, the Board shall promptly notify the Members of such dissolution.

        Section 13.4    Liquidation.    

        (a)   Upon dissolution of the Company, the Board (in such capacity, the "Liquidating Trustee") shall carry out the winding up of the Company and shall immediately commence to wind up the Company's affairs; provided, however, that a reasonable time shall be allowed for the orderly liquidation of the assets of the Company and the satisfaction of liabilities to creditors so as to enable the Members to minimize the normal losses attendant upon a liquidation. The proceeds of liquidation shall be applied first to payment of all expenses and debts of the Company and setting up of such reserves as the Board reasonably deems necessary to wind up the Company's affairs and to provide for any contingent liabilities or obligations of the Company; provided that the unpaid principal of and interest on any loans made to the Company by Members (and their Affiliates) shall be distributed pro rata to the Members (and their Affiliates) who made such loans, in proportion to the total amount of principal and interest payable on such loans, such distributions being treated first as a payment of accrued interest on such loans and next as in payment of principal on such loans. Any remaining proceeds shall be distributed as follows:

          (i)  If the Equalization Date has not yet occurred, then:

        (A)  First, 100% to the Class A Members in accordance with their Class A Percentage Interests until the ** is reduced to zero;

        (B)  Next, 100% to the Class A Members in accordance with their Class A Percentage Interests until the ** is reduced to zero; and

        (C)  Thereafter, (1) if on or prior to **, ** to the holders of the Class A Membership Interests and ** to the holders of the Class B Membership Interests and (2) if after **, ** to the holders of the Class A Membership Interests and ** to the holders of the Class B Membership Interests.

         (ii)  If the Equalization Date has occurred, then to the Members in accordance with their respective Percentage Interests.

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        (b)   Incentive Interest Percentage Distributions. Notwithstanding the preceding provisions in Section 13.4(a), in the event a ** Payout** has occurred, Available Cash shall be distributed as follows:

        **    Following the ** Payout, if any, (x) first calculated in accordance with their respective Percentage Interests, then (y) adjusted by reducing NGPMR's pro rata amount of Available Cash as determined in (x) by the ** and (z) increasing MWE Liberty's pro rata amount of Available Cash as determined in (x) by the amount determined in (y) **

        **    

        (c)   The Profits and Losses arising from liquidation of the Company shall be allocated to the Members so that, to the maximum extent possible, each Member's Capital Account balance equals the amount of cash distributed to each such Member pursuant to Sections 13.4(a)(i) and (ii) and Section 13.4(b), to the extent applicable.

        Section 13.5    Termination.    

        The Company shall terminate when all of the assets of the Company, after payment of or due provision for all debts, liabilities and obligations of the Company, shall have been distributed to the Members in the manner provided for in this Article 13 and the Certificate shall have been canceled, or such other documents required under the Act to be executed and filed with the Secretary of State of the State of Delaware have been so executed and filed, in the manner required by the Act.

        Section 13.6    Claims of the Members or Third Parties.    

        The Members and former Members shall look solely to the Company's assets for the return of their Capital Contributions, and if the assets of the Company remaining after payment of or due provision for all debts, liabilities and obligations of the Company are insufficient to return such Capital Contributions, the Members and former Members shall have no recourse against the Company or any other Member; provided, however, that nothing contained herein shall be deemed to limit the rights of a Member under applicable law. In the event any Member has a deficit balance in its Capital Account at the time of the Company's dissolution, it shall not be required to restore such account to a positive balance or otherwise make any payments to the Company or its creditors or other third parties in respect of such deficiency.

        Section 13.7    Distributions In-Kind.    

        If any assets of the Company shall be distributed in kind, such assets shall be distributed to the Member(s) entitled thereto as tenants-in-common in the same proportions as such Member(s) would have been entitled to cash distributions if (i) such assets had been sold for cash by the Company at the fair market value of such property (taking the Gross Asset Value definition herein and Code Section 7701(g) into account) on the date of distribution; (ii) any unrealized income, gain, loss and deduction inherent in such property (that has not been reflected in the Capital Accounts previously) that would be realized by the Company from such sale were allocated among the Member(s) as Profits or Losses in accordance with this Agreement; and (iii) the cash proceeds were distributed to the Member(s) in accordance with this Article 13. The Capital Accounts of the Member(s) shall be increased by the amount of any unrealized income or gain inherent in such property or decreased by the amount of any loss or deduction inherent in such property that would be allocable to them, and shall be reduced by the fair market value of the assets distributed to them under the preceding sentence. Notwithstanding the foregoing, the Members shall have the right to assign their interest to such in-kind distribution to any Person.

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ARTICLE 14
REPRESENTATIONS, WARRANTIES AND COVENANTS

        Section 14.1    Representations, Warranties and Covenants.    

        Each Member hereby represents, warrants and covenants to the Company as follows:

        (a)   The Member understands that the purpose of the Company is to engage in the Primary Business. The Member has read and is familiar with, and has been given full and complete access to, information, financial or otherwise, regarding the Company and has utilized such access to the Member's satisfaction and has obtained any other relevant information the Member has sought. The Member has been given the opportunity to ask questions of, and receive answers from, the Company concerning the terms and conditions of, and other matters pertaining to, this investment.

        (b)   The Member has read this Agreement and understands that the Interests being acquired by the Member will be governed hereby. The Member agrees to be bound, in all respects, by the terms of this Agreement.

        (c)   The Member has sufficient knowledge and experience in financial and business matters in general, and investments in particular, to be capable of evaluating the merits and risks of the investment in the Interests. The Member is able to bear the economic risk of this investment, including a total loss of the investment. The Member has adequate means of providing for its currents needs and personal contingencies, has no need for liquidity in the investment in the Company and has no reason to anticipate any circumstances, financial or otherwise, which might cause or require any sale or distribution of the Interests. The Member's overall commitment to investments that are not readily marketable is not disproportionate to the Member's net worth and the investment in the Company will not cause the Member's overall commitment in such investments to become excessive. The Member can lose its entire investment in the Interests without producing a material adverse change in the Member's net worth.

        (d)   It is the Member's intention to acquire the Interest for its own account, for investment purposes, and not with a view to, or for, resale in connection with any distribution thereof. The Member understands that no federal or state agency has passed upon the Interests or made any findings or determination as to the fairness of this investment. The Member understands and acknowledges that the Interests have not been registered under the Securities Act or under state securities laws and that the sale of the Interests is being made pursuant to exemptions from registration that may depend upon the Member's investment intention. The Member also understands and acknowledges that the Interests may not be transferred unless they are registered under the Securities Act or an exemption from such registration is available thereunder and under applicable state securities laws and established to the Company's satisfaction. In addition, the Member acknowledges that the Interests are subject to additional restrictions on transferability in this Agreement that will make it difficult to Transfer or liquidate this investment. The Member acknowledges that the Company will rely on these representations and that the Company is not required to recognize any Transfer of an Interest if, in the opinion of counsel, such Transfer would result in a violation of any federal or state law, rule or regulation, regarding the offering or sale of securities. The Member further understands that any certificates representing the Interests may contain legends restricting the Transfer of the Interests.

        (e)   The Member has authorized the execution of this Agreement, and the person executing this Agreement on the Member's behalf has been duly authorized to do so.

        (f)    The Member understands and acknowledges that (i) the Company may need to raise additional capital from time to time in order to engage in the Primary Business and achieve any other objectives and goals that may be established for the Company by the Board, (ii) the

52

Company may raise additional capital by selling Interests to one or more Members or other Persons, (iii) the Member has no right to participate in any future offering, or to buy any additional Interests that may be issued, by the Company except to the extent set forth herein, and (iv) the Member's Percentage Interest in the Company may be diluted as a result of any such sale of additional Interests in the Company.

        (g)   The Member will indemnify and hold harmless the Company and its Managers, officers, Members and Affiliates, and any other Person who controls or is controlled by any of them, against any and all loss, liability, claim, damage and expense whatsoever, including reasonable attorney's fees, arising out of or based upon any false representation or warranty or any breach by the Member of any term or condition contained in this Article 14.

        (h)   All of the information provided to the Company by the Member and all of the Member's representations and warranties are true and correct as of the date of this Agreement. The Member's representations, warranties and covenants shall survive the delivery of the Member's Capital Contribution.

ARTICLE 15
MISCELLANEOUS

        Section 15.1    Notices.    

        All notices provided for in this Agreement shall be in writing, duly signed by the party giving such notice, and shall be delivered, telecopied, mailed by registered or certified mail, sent by recognized overnight delivery or courier service (e.g., Federal Express) or, to the extent permitted by this Agreement, sent via electronic mail, and shall be deemed to have been given upon delivery, if delivered personally or by facsimile or electronic mail, three days after mailing, if mailed, or one Business Day after delivery to the courier, if delivered by overnight courier service, as follows:

          (i)  if given to the Company, in care of the Board at the principal place of business of the Company set forth in Section 2.5 or at such other address as the Company may hereafter designate by 10 days' written notice to the Members.

         (ii)  if given to any Member, at such address designated on the signature page hereto or at such other address as such Member may hereafter designate by 10 days' written notice to the Company.

        Section 15.2    Failure to Pursue Remedies.    

        The failure of any party to seek redress for violation of, or to insist upon the strict performance of, any provision of this Agreement shall not prevent a subsequent act, which would have originally constituted a violation, from having the effect of an original violation.

        Section 15.3    Cumulative Remedies.    

        The rights and remedies provided by this Agreement are cumulative and the use of any one right or remedy by any party shall not preclude or waive its right to use any or all other remedies. Said rights and remedies are given in addition to any other rights the parties may have by law, statute, ordinance or otherwise.

        Section 15.4    Binding Effect.    

        This Agreement shall be binding upon and inure to the benefit of all of the parties and, to the extent permitted by this Agreement, their successors, legal representatives and assigns.

53

        Section 15.5    Interpretation.    

        Throughout this Agreement, nouns, pronouns and verbs shall be construed as masculine, feminine, neuter, singular or plural, whichever shall be applicable. All references herein to "Articles," "Sections" and "Paragraphs" shall refer to corresponding provisions of this Agreement.

        Section 15.6    Severability.    

        The invalidity or unenforceability of any particular provision of this Agreement shall not affect the other provisions hereof, and this Agreement shall be construed in all respects as if such invalid or unenforceable provision were omitted.

        Section 15.7    Counterparts.    

        This Agreement may be executed in any number of counterparts with the same effect as if all parties hereto had signed the same document. All counterparts shall be construed together and shall constitute one instrument.

        Section 15.8    Integration.    

        This Agreement constitutes the entire agreement among the parties hereto pertaining to the subject matter hereof and supersedes all prior agreements and understandings pertaining thereto.

        Section 15.9    Amendment or Restatement.    

        This Agreement (including any Exhibit or Schedule hereto) and the Certificate may be amended, modified or supplemented, and any provisions of this Agreement or the Certificate be waived, with a written instrument adopted, executed and agreed to by the Company and the Class B Members with an aggregate Class B Percentage Interest equal to or exceeding 50%; provided, however, that (a) this Agreement shall be deemed automatically amended from time to time without further consent of any party to reflect issuances and transfers of Interests made in compliance with this Agreement and (b) any amendment, modification, supplement or waiver to this Agreement or the Certificate that would adversely affect the rights, or increase the obligations, of any Member in any material respect shall not be effective without the consent of such affected Member. Except as required by law, no amendment, modification, supplement, discharge or waiver of or under this Agreement shall require the consent of any Person not a party to this Agreement.

        Section 15.10    Governing Law.    

        This Agreement and the rights of the parties hereunder shall be interpreted in accordance with the laws of the State of Delaware and all rights and remedies shall be governed by such laws without regard to principles of conflict of laws. The parties further agree that any legal action or proceeding with respect to this Agreement or any document relating hereto may be brought only in a federal or state court of competent jurisdiction in Houston, Texas. Each party hereby irrevocably waives any objection, including, without limitation, any objection to the laying of venue or based on the grounds of forum non-convenience, which it may now or hereafter have to the bringing of such action or proceeding in any such respective jurisdiction.

        Section 15.11    Dealings in Good Faith.    

        Except as otherwise expressly set forth herein, each party hereto agrees to act in good faith with respect to the other party in exercising its rights and discharging its obligations under this Agreement. Each party further agrees to use its reasonable efforts to ensure that the purposes of this Agreement are realized and to take all steps as are reasonable in order to implement the operational provisions of this Agreement.

54

        Section 15.12    Partition of the Property.    

        Each Member agrees that it shall have no right to partition the Property, or any portion thereof, and each Member agrees that it shall not make application to any court or authority having jurisdiction in the matter to commence or prosecute any action or proceeding for partition of the Property, or any portion thereof. Upon the breach of this Section by any Member, the other Members, in addition to all other rights and remedies in law and equity, shall be entitled to a decree or order dismissing application, action or proceeding.

        Section 15.13    Third Party Beneficiaries.    

        Except as expressly set forth in this Agreement, nothing in this Agreement is intended or shall be construed, to confer upon or give any Person other than the parties hereto, any rights, remedies, obligations or liabilities under or by reason of this Agreement, or result in their being deemed a third party beneficiary of this Agreement.

        Section 15.14    Tax Disclosure Authorization.    

        Notwithstanding anything herein to the contrary, the Members (and each Affiliate and Person acting on behalf of any Member) agree that each Member (and each employee, representative, and other agent of such Member) may disclose to any and all Persons, without limitation of any kind, the transaction's tax treatment and tax structure (as such terms are used in Sections 6011 and 6112 of the Code and the Treasury Regulations thereunder) contemplated by this Agreement and all materials of any kind (including opinions or other tax analyses) provided to such Member or such Person relating to such tax treatment and tax structure, except to the extent necessary to comply with any applicable federal or state securities laws.

        Section 15.15    Waivers and Consents.    

        A waiver or consent, express or implied, to or of any breach or default by any Person in the performance of its obligations hereunder is not a consent or waiver to or of any other breach or default in the performance by that Person of the same or any other obligation of such Person hereunder. Failure of a Person to assert the default or breach of any other Person hereunder shall not constitute a waiver thereof until the applicable statute of limitations period has run.

        Section 15.16    Deadlocks; Negotiations.    

        (a)   Deadlocks. If any matter or proposal requiring less than a unanimous vote of the Managers for approval thereof is (i) brought before the Managers and such matter or proposal is neither (A) approved of by the Managers sufficient to constitute approval of such matter or proposal or (B) disapproved of by the Managers sufficient to constitute rejection of such matter or proposal or (ii) would have been brought before the Board, but for the fact that a quorum was not present at three consecutive Board meetings called for a purpose which includes such matter or proposal, then any Manager, by written notice to the other Managers given within three Business Days after (1) the initial vote on such matter or proposal or (2) the third consecutive Board meeting at which a quorum was not present, as applicable, may call a meeting of the Board to reconsider such matter or proposal, such meeting to be held when, where and as reasonably specified in such notice, but not less than three Business Days nor more than seven Business Days after such vote. If such meeting is called and held as provided in the immediately preceding sentence and either (i) the matter or proposal is offered at such meeting again and is neither (A) approved of by the Managers sufficient to constitute approval of such matter or proposal or (B) disapproved of by the Managers sufficient to constitute rejection of such matter or proposal, (ii) the Managers are unable to otherwise agree on a course of action to address the matter or proposal which is the reason for the meeting, or (iii) a quorum is not present at such Board meeting, then any Manager may within three Business Days thereafter declare an impasse

55

("Impasse") by giving written notice to the other Managers and to the Chief Executive Officer (or the individual performing similar functions) of the parent company of each Member containing a brief description of the nature of the dispute subject to such Impasse (an "Impasse Notice"). Thereafter, such Impasse shall be subject to the provisions of Section 15.16(b) and, if applicable, binding arbitration, in accordance with Section 15.16(c). If no Manager calls such a meeting within the first three Business Days period provided in this Section or if an Impasse is not declared within the three Business Day period after the second meeting, then no Manager shall thereafter have any right to declare an Impasse regarding such matter or proposal and binding arbitration shall not be available regarding such matter or proposal.

        (b)   Impasse Negotiations. Within 20 Business Days after the receipt of an Impasse Notice, the Chief Executive Officer of each parent company of a Member (or the individual performing similar functions) shall meet in good faith effort to reach accords that will end the Impasse. If a decision is not made by common accord that ends the Impasse within 15 days after the date of such meeting, any Manager may declare a final Impasse ("Final Impasse") by written notice to the other Managers. Notwithstanding anything in this Agreement to the contrary, if any CEO refuses to meet with the other CEOs, any Manager may immediately invoke the provisions of Section 15.16(c).

        (c)   Submission to Arbitration. If within 10 Business Days following receipt of written notice of a Final Impasse, the matter or proposal subject to such Final Impasse is neither (A) approved of by the Managers sufficient to constitute approval of such matter or proposal or (B) disapproved of by the Managers sufficient to constitute rejection of such matter or proposal, then any Manager may subject the matter or proposal to binding arbitration pursuant to Section 15.17.

        Section 15.17    Dispute Resolution.    

        (a)   Agreement to Arbitrate. Any claim, counterclaim, demand, cause of action, dispute, or any other controversy arising out of or relating in any way to this Agreement or to the subject matter of this Agreement, including any dispute made subject to arbitration under Section 15.16(c) (each a "Dispute") shall be resolved by binding arbitration. A Dispute must be resolved through arbitration regardless of whether the Dispute involves claims that the Agreement is unlawful, unenforceable, void, or voidable or involves claims under statutory, civil or common law. The validity, construction and interpretation of this Agreement to arbitrate, and all other procedural aspects of the arbitration conducted pursuant hereto shall be decided by the arbitral tribunal.

        (b)   Rules and Applicable Law. Any arbitration under this Agreement shall be administered by the American Arbitration Association and conducted in accordance with the Commercial Arbitration Rules of the AAA in existence at the time of the arbitration. In resolving any Dispute, the arbitral tribunal shall apply the governing law as specified in Section 15.10 of this Agreement. THE ARBITRAL TRIBUNAL SHALL NOT BE EMPOWERED TO AWARD PUNITIVE, EXEMPLARY, TREBLE, MULTIPLE, SPECIAL, INDIRECT, INCIDENTAL OR CONSEQUENTIAL DAMAGES, INCLUDING DAMAGES FOR LOSS OF PROFITS, LOSS OF USE OR REVENUE OR LOSSES BY REASON OF COST OF CAPITAL, ARISING OUT OF OR RELATING TO THIS AGREEMENT OR ANY OTHER TRANSACTION DOCUMENT, OR THE BUSINESS OF THE COMPANY OR ANY OF ITS SUBSIDIARIES AND THE PARTIES WAIVE ANY RIGHT THEY MAY HAVE TO RECOVER SUCH DAMAGES FROM ONE ANOTHER. The arbitral tribunal shall not be empowered to declare any provision of this Agreement void or unenforceable. The arbitral tribunal shall not be empowered to decide any dispute ex aequo et bono or amiable compositeur.

        (c)   Location of the Proceeding. The arbitration shall be held in Houston, Texas.

56

        (d)   Selection of the Arbitral Tribunal. The Dispute shall be decided by a panel of three neutral arbitrators selected as follows. The claimant shall nominate an arbitrator at the time it serves its notice of arbitration. The respondent shall nominate an arbitrator within 15 days of the claimant's nomination of an arbitrator. In the event that there is more than one claimant or more than one respondent, then the claimants or respondents, as the case may be, shall collectively appoint one arbitrator. If a party or a group of parties does not appoint an arbitrator, then an arbitrator shall be appointed according to the Rules. The two arbitrators shall together agree upon a third arbitrator to chair the arbitration. If the two party-appointed arbitrators are unable to agree upon an arbitrator within 30 days of the respondent's appointment of an arbitrator, then the chairman shall be chosen according to the Rules.

        (e)   Interim Measures and Provisional Remedies. The arbitral tribunal is authorized to award interim measures, provisional remedies or injunctive relief, which may be enforced by the arbitral tribunal or by a court of law. In the event of an emergency or if one of the arbitrators is unavailable, then the chairman is authorized to award interim measures or injunctive relief, which may upon the request of a party be reviewed by the entire arbitral tribunal. The arbitral tribunal is authorized to direct the parties to request that any court vacate, modify or dismiss any temporary or preliminary relief issued by a court relating to a Dispute.

        (f)    Specific Performance. The parties agree that money damages alone shall not be an adequate remedy for any breach of this Agreement. Therefore, the parties agree that the arbitral tribunal is authorized to award specific performance and injunctive relief for any breach of this Agreement. The arbitral tribunal is authorized to award interim measures of specific performance while the arbitration is pending.

        (g)   Award. The award shall be final and binding on the parties and may be confirmed in, and judgment upon the award entered by, any court having jurisdiction over the parties. The award shall be required to be in writing, stating the award and the reasons therefor.

        (h)   Enforcement of Award by a Court and Challenge to an Award. Any arbitration award may be enforced by the state or federal courts sitting in the state of Delaware or any other court of competent subject matter jurisdiction where the party against whom the award is sought to be enforced keeps or maintains assets. Any party seeking to challenge an award must bring the action in the state or federal courts sitting in the state of Delaware. The parties agree to waive any objections they may have to personal jurisdiction, venue, or forum non-conveniens for any action brought to enforce or to challenge an award in one of the courts set forth above. The parties agree that service of process may be accomplished according to the procedures of Section 15.1 or by any other means authorized by law. The parties agree to waive any objection they may have to service of process if accomplished according to the procedures of Section 15.1.

        (i)    Costs and Attorneys Fees. The arbitral tribunal is authorized to award costs of the arbitration in its award and to allocate costs between the parties, including (A) the fees and expenses of the arbitrators; (B) the costs of assistance required by the tribunal, including its experts; (C) the fees and expenses of the administrator; (D) the reasonable costs for legal representation of a successful party, including attorneys fees, expert witness fees, out of pocket costs and other expenses; and (E) any such costs incurred in connection with an application for interim or emergency measures.

        (j)    Interest. The award shall include pre-judgment interest at a rate to be determined by the arbitral tribunal from the date of the breach or default. Interest shall accrue until the date the award is paid in full.

57

        (k)   Payment of the Award. The award (including any interim award) shall be paid within 30 days of the issuance of the award in immediately available funds, free and clear of any liens, taxes or other deductions. The award shall be paid in United States dollars.

        (l)    Severability. If any provision of this arbitration provision is found by a court to be unenforceable or unlawful, then it shall be severed from the agreement and the remaining terms shall be enforced as written.

        (m)  Confidentiality. Any arbitration (including a settlement resulting from an award, documents exchanged or produced during an arbitration proceeding, and memorials, briefs or other documents prepared for the arbitration) shall be Confidential Information subject to the provisions of Section 5.4. A breach of this confidentiality provision shall not void any settlement or award.

        Section 15.18    Transaction Expenses.    

        **    Class A Members and the Class B Members ** out-of-pocket fees, costs and expenses incurred in connection with the transactions related to this Agreement **.

[Signature Page Follows]

58

        IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above written.

MWE LIBERTY:
MARKWEST LIBERTY GAS GATHERING, L.L.C., a Delaware limited liability company
By:	/s/ Frank M. Semple
Name:	Frank M. Semple
Title:	President and CEO
Address for notice: 1515 Arapahoe Street Tower 2, Suite 700 Denver, CO 80202-2126 Attention: Senior Vice President and Chief Operations Officer
NGPMR:
M&R MWE LIBERTY, LLC
By:	/s/ John T. Raymond
Name:	John T. Raymond
Title:	CEO & Managing Partner
Address for notice: 1401 McKinney, Suite 1025 Houston, TX 77010 Attention: Jeffrey C. Rawls
with a copy to:
Locke Lord Bissell & Liddell, LLP 600 Travis Street, Suite 3400 Houston, Texas 77002 Fax (713) 229-2518 Attention: H. William Swanstrom

Signature Page

EXHIBIT A

AREA OF MUTUAL INTEREST

        The areas described on the attached Area of Mutual Interest Map.

A-1

**

A-2

EXHIBIT B

MEMBERS AND CAPITAL CONTRIBUTIONS(1)

Member Name and Address	Aggregate Capital Contributions		Cash Capital Contributions		Type of Membership Interest		Percentage Interest		Investment Balance
M&R MWE Liberty, LLC	$	**	$	**		Class A		40%	$	**
1401 McKinney, Suite 1025
Houston, TX 77010
Attention: Jeffrey C. Rawls
Facsimile: (713) 579-5017
Email: jrawls@ngpmr.com
with a copy to:
Locke Lord Bissell & Liddell, LLP
600 Travis Street, Suite 3400
Houston, Texas 77002
Fax (713) 229-2518
Attention: H. William Swanstrom
MarkWest Liberty Gas Gathering, L.L.C.	$	**	$	**		Class B		60%	$	**
1515 Arapahoe Street, Tower 2
Suite 700
Denver, CO 80202
Attention: Senior Vice President and Chief Operations Officer
Facsimile: (303) 925-9305
Email: jmollenkopf@markwest.com
with a copy to:
MarkWest Liberty Gas Gathering, L.L.C.
1515 Arapahoe Street, Tower 2
Suite 700
Denver, CO 80202
Attention: Senior Vice President, General Counsel and Secretary
Facsimile: (303) 925-9308
Email: cbromley@markwest.com

(1)

Aggregate Capital Contributions, Cash Capital Contributions and Investment Balances determined as of October 1, 2009.

B-1

EXHIBIT C

BASE PROJECT

1.

Natural Gas Processing Plant Construction and Operation

**

2.

Natural Gas Pipeline Construction and Operation

**

3.

Miscellaneous Natural Gas Processing Infrastructure Construction and Operation

**

C-1

EXHIBIT D

INITIAL BUDGET

(See attached)

**

[2 pages have been omitted and filed separately with the Securities and Exchange Commission pursuant to the request for confidential treatment.]

D-1

EXHIBIT E

ILLUSTRATIVE EXAMPLE CALCULATION OF INCENTIVE INTERESTS

**

[6 pages have been omitted and filed separately with the Securities and Exchange Commission pursuant to the request for confidential treatment.]

E-1

EXHIBIT G

CAPITAL EXPENDITURES FOR AGREEMENTS

**

G-1

EXHIBIT H

PRE-APPROVED AFFILIATED TRANSACTIONS

1.

Services Agreement

2.

Fractionation and NGL Purchase Agreement

3.

The execution of the Company's acknowledgment of the pledge by MWE Liberty of its Class B Interest in the Company to the Royal Bank of Canada pursuant to that certain Credit Agreement, dated as of February 20, 2008, among MWE, certain subsidiary guarantors, Royal Bank of Canada, as Administrative Agent and Collateral Agent, and the other lenders party thereto.

H-1

QuickLinks

Exhibit 10.39

ARTICLE 1 DEFINED TERMS
ARTICLE 2 FORMATION AND TERM
ARTICLE 3 PURPOSE AND POWERS OF THE COMPANY
ARTICLE 4 CAPITAL CONTRIBUTIONS, MEMBER INTERESTS, CAPITAL ACCOUNTS AND FUTURE CAPITAL REQUIREMENTS
ARTICLE 5 MEMBERS, MEETINGS AND AMENDMENTS
ARTICLE 6 MANAGEMENT
ARTICLE 7 ASSIGNABILITY OF MEMBER INTERESTS
ARTICLE 8 DISTRIBUTIONS TO MEMBERS
ARTICLE 9 ALLOCATIONS
ARTICLE 10 BOOKS AND RECORDS
ARTICLE 11 TAX MATTERS
ARTICLE 12 LIABILITY, EXCULPATION AND INDEMNIFICATION
ARTICLE 13 DISSOLUTION, LIQUIDATION AND TERMINATION
ARTICLE 14 REPRESENTATIONS, WARRANTIES AND COVENANTS
ARTICLE 15 MISCELLANEOUS
EXHIBIT B MEMBERS AND CAPITAL CONTRIBUTIONS(1)

EX-10.40

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Exhibit 10.40

AMENDMENT NO. 1 TO
SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY
AGREEMENT OF MARKWEST LIBERTY MIDSTREAM & RESOURCES, L.L.C.

        This AMENDMENT NO. 1 TO SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT (the "Amendment") of MarkWest Liberty Midstream & Resources, L.L.C. (the "Company") is dated as of November 20, 2009 among MarkWest Liberty Gas Gathering, L.L.C., a Delaware limited liability company ("MWE Liberty"), M&R MWE Liberty, LLC, a Delaware limited liability company ("NGPMR"), and the Company.

RECITALS

        A.    MWE Liberty and NGPMR constitute all of the Members of the Company and are parties to that certain Second Amended and Restated Limited Liability Company Agreement of the Company dated as of November 1, 2009 (as amended or restated, the "Agreement").

        B.    NGPMR holds all of the Class A Interests and is the sole Class A Member of the Company and MWE Liberty holds all of the Class B Interests and is the sole Class B Member of the Company.

        C.    Pursuant to Section 15.9 of the Agreement, MWE Liberty, NGPMR and the Company desire to amend the Agreement to modify the period of time in which the Members must contribute capital to the Company after a Capital Call has been issued pursuant to the Agreement in the manner set forth in this Amendment.

        C.    Capitalized terms used but not defined in this Amendment shall have the meaning ascribed to them in the Agreement.

AGREEMENT

        NOW THEREFORE, in consideration of the premises and the mutual covenants and agreements contained herein, and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereby agree as follows:

        1.     Section 4.1(b)(i) of the Agreement is hereby amended by deleting the third sentence thereof in its entirety and replacing it with the following:

"At each time when the Company requires additional capital pursuant to this Section 4.1(b)(i), the Board shall issue a Capital Call to the Class A Members, and such Members shall contribute to the Company the amount of capital so required within fifteen (15) Business Days after receipt of such Capital Call."

        2.     Section 4.1(b)(ii) of the Agreement is hereby amended by deleting the second sentence thereof in its entirety and replacing it with the following:

"At each time when the Company requires additional capital pursuant to this Section 4.1(b)(ii), the Board shall issue a Capital Call to the Class A Members and the Class B Members, and such Members shall contribute to the Company the amount of capital so required within fifteen (15) Business Days after receipt of such Capital Call."

        3.     Section 4.1(c)(i) of the Agreement is hereby amended by deleting the last sentence thereof in its entirety and replacing it with the following:

"Each Contributing Class A Member shall in accordance with such Class A Member's Quarterly Budgeted Funding Election contribute such requested capital to the Company within fifteen (15) Business Days after the issuance of each such quarterly Capital Call."

        4.     Section 4.1(d)(i) of the Agreement is hereby amended by deleting the last sentence thereof in its entirety and replacing it with the following:

"Each Contributing Class B Member shall in accordance with such Class B Member's Quarterly Budgeted Funding Election and any further election pursuant to Section 4.1(d)(iii) contribute such requested capital to the Company within fifteen (15) Business Days after the issuance of each such quarterly Capital Call."

        5.     Section 4.1(d)(ii) of the Agreement is hereby amended by deleting the last sentence thereof in its entirety and replacing it with the following:

"Each Contributing Class A Member shall in accordance with such Class A Member's Quarterly Budgeted Funding Election contribute such requested capital to the Company within fifteen (15) Business Days after the issuance of such quarterly Capital Call."

        6.     Except as expressly modified by this Amendment, all terms of the Agreement remain in full force and effect. In the event of a conflict between this Amendment and the Agreement, the terms of this Amendment shall control.

        7.     This Amendment may be executed in any number of counterparts, and each of such counterparts shall together constitute but one and the same Amendment. Executed counterparts may be delivered by facsimile or PDF and shall be considered an original.

[signature page follows]

        IN WITNESS WHEREOF, the parties hereto have executed this Amendment No. 1 to the Second Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources, L.L.C. as of the date first above written.

MARKWEST LIBERTY GAS GATHERING, L.L.C.
By:	/s/ Frank M. Semple
Name:	Frank M. Semple
Title:	President and CEO
MARKWEST LIBERTY MIDSTREAM & RESOURCES, L.L.C.
By:	/s/ Frank M. Semple
Name:	Frank M. Semple
Title:	President and CEO
M&R MWE LIBERTY, LLC
By:	/s/ John T. Raymond
Name:	John T. Raymond
Title:	Managing Partner & CEO

QuickLinks

Exhibit 10.40

AMENDMENT NO. 1 TO SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF MARKWEST LIBERTY MIDSTREAM & RESOURCES, L.L.C.
RECITALS
AGREEMENT

EX-10.41

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Exhibit 10.41

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT FOR THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPERATELY FILED WITH THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH TWO ASTERISKS (**).

AMENDMENT TO
RAW PRODUCT PURCHASE AGREEMENT

This Amendment to the Raw Product Purchase Agreement (the "Amendment") is made and entered into effective as of December 1, 2009 (the "Effective Date") by and between Targa Liquids Marketing and Trade ("Targa"), successor-in-interest to Dynegy Liquids Marketing and Trade, and MarkWest Energy East Texas Gas Company, L.L.C. ("MarkWest"), successor-in-interest to MarkWest Energy East Texas Gas Company, L.P. Targa and MarkWest may be referred to collectively as the "Parties" or singularly as a "Party".

RECITALS:

        WHEREAS, the Parties entered into that certain Raw Product Purchase Agreement (the "Agreement") dated February 11, 2005, with an effective start date on December 1, 2005; and

        WHEREAS, the Parties wish to amend certain provisions of the Agreement.

        NOW THEREFORE, in consideration of the premises and other good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the Parties agree as follows:

        1.     Paragraph 1 ("Term") of the first page of the Agreement shall be amended by deleting that paragraph in its entirety and replacing it with the following:

1.

Term: Targa will purchase and MarkWest will sell ** barrels per day ("bpd") of "on-spec" NGL Raw Product that MarkWest delivers to the West Texas LPG Pipeline, during a period of ten years commencing December 1, 2005 (the "Primary Term"), and shall continue the purchase and sale of such Raw Product from year to year thereafter unless and until canceled by either Party hereto at the end of the Primary Term or any yearly anniversary thereafter by either Party giving notice to the other Party not less than ninety (90) days prior to the end of the Primary Term or subsequent yearly period, as applicable, of its intent to cancel this Agreement.

        2.     "Approx. Volume" in Paragraph 2 of the first page of the Agreement shall be revised to read "** barrels per day."

        3.     "Attachment A—Volumes, Pricing and Special Terms" shall be amended effective as of December 1, 2009, by deleting paragraphs A, B, and C in their entirety and replacing paragraphs A and B with the following (paragraph C will be deleted and not replaced):

A.

Delivery Obligations & Volume:

1.

MarkWest agrees to sell and deliver to Targa and Targa agrees to purchase and accept, subject to Attachment B, Sections 9 and 10, Raw Product (as such term is defined in Attachment B) delivered by MarkWest to the West Texas LPG Pipeline.



2.

The daily volume of Raw Product to be purchased and accepted hereunder shall be an amount ** barrels per day ("bpd") (calculated as a monthly average). The ** bpd shall be **. Deliveries of Raw Product shall be on a ratable basis.



3.

MarkWest and Targa agree that the Pricing provisions contained in paragraph B of this Attachment A shall be based upon the implementation of ** as defined in Section A.2 above.

4.

If MarkWest fails to deliver ** in any calendar year, but adjusted for a partial year in 2015, MarkWest shall ** March 1 of the following year ** as follows:

**

There will be **.

a.

It is understood and agreed that in addition to meeting the product specifications referenced in Section 9 of Attachment B (Quality and Testing), such Raw Product sold to Targa under this Agreement shall contain no concentrations of any substance or contaminants that would make the natural gas liquid products fractionated from such Raw Product stream commercially unacceptable in general industry application. The Parties shall use commercially reasonable efforts to nominate, deliver and receive, as applicable, Raw Product on a generally ratable basis each day during the term hereof. However, the Parties recognize that variations between the volumes that are nominated, taken and/or delivered may occur.



B.

Pricing:

For the Raw Product delivered hereunder, Targa shall pay to MarkWest a purchase price ("Price") equal to the applicable OPIS Monthly Index (as defined in Subsection B.1 below) for each gallon of each NGL Component (as such term is defined in Attachment B and as reported on end-of-the-month report from WTPL) contained therein less (i) Transportation Costs (as defined in Subsection B.2 below) and (ii) Fractionation Costs (as defined in Subsection B.3 below).

1.

OPIS Monthly Index means the monthly average of the daily high and low prices per gallon, for the month of delivery, as quoted by the Oil Price Information Service ("OPIS") for ** under ** using (i) the ** for the propane, isobutane, normal butane, and natural gasoline NGL Components; and (ii) the ** for the ethane NGL Component. Should any of the indices referenced herein be discontinued, the Parties shall mutually agree upon a comparable successor index and/or publication.



2.

Transportation Costs shall mean the total transportation costs incurred by Targa or its designee ** from the ** to **; including, without limitation, ** in connection with such transportation, including charges imposed for **, and charges assessed by **. Targa or its designee shall be the shipper on WTPL and will therefore ** as well as **.

2

3.

Fractionation Costs shall be calculated on a monthly basis in cents per gallon using the following formula**:

**

Where:

Gas Price =	The ** as published in the first issue INSIDE F.E.R.C.'s GAS MARKET REPORT, for natural gas for the month in which the Fractionation Fee is being computed in dollars per million British thermal units ($/mmBtu)
Elec =	The combined average cost of purchased electricity, in cents per kilowatt hour, at ** during the preceding month
CPIU =	The latest available Consumer Price Index, all Urban Consumers ("CPIU), U.S. city average, All Items, 1982-84 = 100 (Unadjusted) as published by the United States Bureau of Labor Statistics (the "BLS") or any successor agency thereto ("CPI-Index"). The CPIU Index shall be taken from the data published by the BLS either electronically at its then current internet site or as same is published in hardcopy form.

        4.     "Attachment A—Volumes, Pricing and Special Terms" shall be further amended effective December 1, 2009, by adding the following sentence to the end of paragraph F ("Adequate Assurance"):

Notwithstanding the foregoing, MarkWest shall not be deemed to have reasonable grounds for insecurity unless a material adverse change takes place with respect to Targa or Targa's guarantor's creditworthiness after December 1, 2009. In the event that MarkWest requests Adequate Assurance ** in the form of a letter of credit, then Targa shall provide such letter of credit **.

        5.     "Attachment B—General Terms and Conditions" shall be amended by deleting paragraph D in Section 1 and replacing it with the following:

D.

"Raw Product" shall mean a mixture of liquid hydrocarbons subject to the specifications contained in Attachment B, Section 9.

6.

"Attachment B—General Terms and Conditions" shall be amended by adding the following definition to Section 1 ("Definitions"):

G.

"Plant" shall mean MarkWest's East Texas Carthage processing facilities in their entirety as now or in the future changed, modified, supplemented, replaced, expanded, etc.

        7.     "Attachment B—General Terms and Conditions" shall be amended by adding a second paragraph to Section 17 as follows:

Notwithstanding anything contained in this Agreement to the contrary, ** in the event there is an enactment of, or change in, any law or regulation after January 1, 2010 that results in a governmental authority requiring either Party to hold or acquire emission allowances or their equivalent related to the carbon dioxide content or emissions or the greenhouse gas content or emissions (collectively "New GHG Laws") attributable to ** natural gas liquids ("NGLs") sold by MarkWest to Targa and/or the transportation, fractionation and/or storage of such ** NGLs, then the Parties agree to meet and negotiate in good faith to determine an equitable allocation of the new requirements to acquire such emission allowances or their equivalent **. If the Parties, after reasonable efforts and negotiating in good faith to arrive at an equitable allocation of any new requirements to acquire such emission allowances or their equivalents **, fail to reach an agreement for such allowances or their equivalents within sixty (60) days after the initial meeting,

3

then either Party shall have the right to terminate its obligations and rights **, including to sell and deliver or to purchase and receive ** under this Agreement, at any time thereafter upon not less than thirty (30) days written notice to the other Party, provided, however, that such termination date shall not occur or be effective prior to the date that the obligation to incur the costs to acquire such emission allowances or their equivalents under such New GHG Laws, takes effect and is imposed upon the Party electing to terminate their obligations **.

8.

The Parties further agree that:

1.

All pricing for fractionation fees on invoices submitted by Targa prior to the Effective Date of this Amendment shall be accepted as accurate and final and neither Party shall dispute the terms therein.



2.

During the Term of the Agreement, ** with the terms and conditions of ** as set forth in **, in order to continue to receive the ** for ** under the terms of this Agreement. In connection therewith, Targa, **, is required to deliver a ** to execute the ** under the Program for the term of this Agreement. In addition, ** under the Program and, provided that ** the terms and conditions of the Program **.



3.

If a Party elects to terminate its rights and obligations ** pursuant to paragraph 7 of this Amendment, then the Agreement shall be deemed to be amended upon the termination effective date, to delete or eliminate all provisions and rights or obligations regarding or applicable **, including, but not limited to, modifying ** the Parties' obligations to sell and deliver and to purchase and receive Raw Product under the Agreement **.

9.

Except as amended herein, all other provisions of the Agreement shall remain in full force and effect.

        IN WITNESS WHEREOF, the Parties have each caused their duly authorized representative to execute this Amendment effective as of the Effective Date.

Targa Liquids Marketing and Trade		MarkWest Energy East Texas Gas Company, L.L.C.
By:	/s/ Michael A. Heim	By:	/s/ John Mollenkopf
Name:	Michael A. Heim	Name:	John Mollenkopf
Title:	Executive Vice President and COO	Title:	Senior Vice President and COO

4

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Exhibit 10.41

EX-12.1

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Exhibit 12.1

MarkWest Energy Partners, L.P.
Calculation of Earnings to Fixed Charges
(Dollar amounts in thousands)

		Year ended December 31,
		2005			2006			2007			2008			2009
Total fixed charges		$	34,080		$	54,153		$	49,191		$	86,559		$	112,981
Earnings:
Earnings from continuing operations before income taxes		$	(8,515	)	$	74,498		$	(59,155	)	$	273,602		$	(155,370	)
Add:
	Fixed charges		34,080			54,153			49,191			86,559			112,981
	Amortization of capitalized interest		195			255			478			1,110			1,444
	Cash distributions from equity method investments		2,441			—			10,840			445			—
	Income (loss) from equity method investments		2,153			(5,316	)		(5,309	)		(90	)		(3,505	)
Subtract:
	Interest capitalized		(2,133	)		(900	)		(3,344	)		(9,486	)		(12,228	)
Total earnings		$	28,221		$	122,690		$	(7,299	)	$	352,140		$	(56,678	)
Ratio			0.83			2.27			(0.15	)		4.07			(0.50	)

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Exhibit 12.1

MarkWest Energy Partners, L.P. Calculation of Earnings to Fixed Charges (Dollar amounts in thousands)

EX-21.1

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Exhibit 21.1

Entity	State of Incorporation
Bright Star Partnership	Texas
Centrahoma Processing LLC	Delaware
MarkWest Blackhawk, L.L.C.	Texas
MarkWest Energy Appalachia, L.L.C.	Delaware
MarkWest Energy East Texas Gas Company, L.L.C.	Delaware
MarkWest Energy Finance Corporation	Delaware
MarkWest Energy GP, L.L.C.	Delaware
MarkWest Energy Operating Company, L.L.C.	Delaware
MarkWest Gas Marketing, L.L.C.	Texas
MarkWest Gas Services, L.L.C.	Texas
MarkWest Hydrocarbon, Inc.	Delaware
MarkWest Javelina Company, L.L.C.	Texas
MarkWest Javelina Pipeline Company, L.L.C.	Texas
MarkWest Liberty Gas Gathering, L.L.C.	Delaware
MarkWest Liberty Midstream & Resources, L.L.C.	Delaware
MarkWest Marketing, L.L.C.	Delaware
MarkWest McAlester, L.L.C.	Oklahoma
MarkWest Michigan Pipeline Company, L.L.C.	Michigan
MarkWest New Mexico, L.L.C.	Texas
MarkWest Oklahoma Gas Company, L.L.C.	Oklahoma
MarkWest Pinnacle, L.L.C.	Texas
MarkWest Pioneer, L.L.C.	Delaware
MarkWest Pipeline Company, L.L.C.	Texas
MarkWest PNG Utility, L.L.C.	Texas
MarkWest Power Tex, L.L.C.	Texas
MarkWest Texas PNG Utility, L.L.C.	Texas
Mason Pipeline Limited Liability Company	Michigan
Matrex, L.L.C.	Michigan
West Shore Processing Company, L.L.C.	Michigan
Wirth Gathering, a general partnership	Oklahoma

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Exhibit 21.1

EX-23.1

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Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

        We consent to the incorporation by reference in Registration Statement Nos. 333-142358, 333-149742, 333-157883 and 333-164323 on Form S-3 and Registration Statement Nos. 333-91120, 333-151159, 333-151162 and 333-151164 on Form S-8 of our reports dated March 1, 2010, relating to the consolidated financial statements of MarkWest Energy Partners, L.P. and subsidiaries (the "Partnership"), and the effectiveness of the Partnership's internal control over financial reporting, appearing in this Annual Report on Form 10-K of MarkWest Energy Partners, L.P. for the year ended December 31, 2009.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
March 1, 2010

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Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

EX-31.1

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Exhibit 31.1

CERTIFICATION

I, Frank M. Semple, certify that:

1.

I have reviewed this annual report on Form 10-K of MarkWest Energy Partners, L.P.

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report.

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f), for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 1, 2010 By: /s/ FRANK M. SEMPLE Frank M. Semple
Chairman, President and Chief Executive Officer
(Principal Executive Officer)

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Exhibit 31.1

CERTIFICATION

EX-31.2

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Exhibit 31.2

CERTIFICATION

I, Nancy K. Buese, certify that:

1.

I have reviewed this annual report on Form 10-K of MarkWest Energy Partners, L.P.

2.

Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report.

3.

Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report.

4.

The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f), for the registrant and have:

a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)

Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)

Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5.

The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent function):

a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: March 1, 2010 By: /s/ NANCY K. BUESE Nancy K. Buese
Senior Vice President & Chief Financial Officer
(Principal Financial Officer and
Principal Accounting Officer)

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Exhibit 31.2

CERTIFICATION

EX-32.1

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Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the Annual Report of MarkWest Energy Partners, L.P. (the "Partnership"), on Form 10-K for the period ending December 31, 2009, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Frank M. Semple, Chief Executive Officer of the General Partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and



(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

Date: March 1, 2010 By: /s/ FRANK M. SEMPLE Frank M. Semple
Chairman, President and Chief Executive Officer
(Principal Executive Officer)

        This certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document. This certification shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to liability under that section. This certification shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent this Exhibit 32.1 is expressly and specifically incorporated by reference in any such filing.

        A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

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Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

EX-32.2

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Exhibit 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the Annual Report of MarkWest Energy Partners, L.P. (the "Partnership") on Form 10-K for the period ending December 31, 2009, as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Nancy K. Buese, Chief Financial Officer of the General Partner of the Partnership, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to §906 of the Sarbanes-Oxley Act of 2002, that:

(1)

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and



(2)

The information contained in the Report fairly presents, in all material respects, the financial condition and result of operations of the Partnership.

Date: March 1, 2010 By: /s/ NANCY K. BUESE Nancy K. Buese
Senior Vice President & Chief Financial Officer
(Principal Financial Officer and Principal
Accounting Officer)

        This certification is being furnished solely pursuant to 18 U.S.C. Section 1350 and is not being filed as part of the Report or as a separate disclosure document. This certification shall not be deemed "filed" for purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), or otherwise subject to liability under that section. This certification shall not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act except to the extent this Exhibit 32.2 is expressly and specifically incorporated by reference in any such filing.

        A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

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Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002