10-K

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ITEM 8. Financial Statements and Supplementary Data
Table of Contents

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, 2011
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 1, Suite 1600, Denver, CO 80202-2137
(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 to 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 ý    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. o

         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, 2011 was approximately $3.6 billion. As of February 17, 2012, the number of the registrant's common units and Class B units outstanding were 95,908,615 and 19,954,389, respectively.

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 2012, 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	33
Item 1B.	Unresolved Staff Comments	53
Item 2.	Properties	54
Item 3.	Legal Proceedings	58
Item 4.	Mine Safety Disclosures	58
PART II
Item 5.	Market for Registrant's Common Units, Related Unitholder Matters and Issuer Purchases of Equity Securities	59
Item 6.	Selected Financial Data	61
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	64
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	87
Item 8.	Financial Statements and Supplementary Data	93
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	161
Item 9A.	Controls and Procedures	161
Item 9B.	Other Information	163
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	163
Item 11.	Executive Compensation	163
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	163
Item 13.	Certain Relationships and Related Transactions, and Director Independence	163
Item 14.	Principal Accountant Fees and Services	163
PART IV
Item 15.	Exhibits and Financial Statement Schedules	163
SIGNATURES		171

        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, 2011. References to "MarkWest Hydrocarbon" or the "Corporation" are intended to mean MarkWest Hydrocarbon, Inc., a wholly-owned taxable subsidiary of the Partnership. References to "General Partner" are intended to mean MarkWest Energy GP, L.L.C., the general partner 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	Barrel
Bbl/d	Barrels per day
Bcf/d	Billion cubic feet per day
Btu	One British thermal unit, an energy measurement
Dth/d	Dekatherms per day
EBITDA (a non-GAAP financial measure)	Earnings Before Interest, Taxes, Depreciation and Amortization
EPA	Environmental Protection Agency
ERCOT	Electric Reliability Council of Texas
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
GAAP	Accounting principles generally accepted in the United States of America
Gal	Gallon
Gal/d	Gallons per day
IFRS	International Financial Reporting Standards
LIBOR	London Interbank Offered Rate
Mcf	One thousand cubic feet of natural gas
Mcf/d	One thousand cubic feet of natural gas per day
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)	Segment 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
SMR	Steam methane reformer, operated by a third party and located at the Javelina gas processing and fractionation facility in Corpus Christi, Texas
TSR Performance Units	Phantom units containing performance vesting criteria related to the Partnership's total shareholder return
VIE	Variable interest entity
WTI	West Texas Intermediate

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Forward-Looking Statements

        Certain statements and information included in this Annual Report on Form 10-K may constitute "forward-looking statements." The words "could," "may," "predict," "should," "expect," "hope," "continue," "potential," "plan," "intend," "anticipate," "project," "believe," "estimate" and similar expressions are intended to identify forward-looking statements, which are generally not historical in nature. These forward-looking statements are based on current expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. While management believes that these forward-looking statements are reasonable as and when made, there can be no assurance that future developments affecting us will be those that we anticipate. All comments concerning our expectations for future revenues and operating results are based on our forecasts for our existing operations and do not include the potential impact of any future acquisitions. Our forward-looking statements involve significant risks and uncertainties (some of which are beyond our control) and assumptions that could cause actual results to differ materially from our historical experience and our present expectations or projections. Important factors that could cause actual results to differ materially from those in the forward-looking statements include those described in (i) Item 1A. Risk Factors of this Form 10-K and elsewhere in this report, (ii) our reports and registration statements filed from time to time with the SEC and (iii) other announcements we make from time to time. Investors are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. We undertake no obligation to publicly update or revise any forward-looking statements after the date they are made, whether as a result of new information, future events or otherwise.

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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 the following operating segments: Southwest, Northeast, Liberty and Gulf Coast. Maps detailing the individual assets can be found on our Internet website, www.markwest.com. For more information on these segments, see Our Operating Segments discussion below.

        The following table summarizes the operating performance for each segment for the year ended December 31, 2011 (amounts in thousands). For further discussion of our segments and a reconciliation to our consolidated statement of operations, see Note 24 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

	Southwest		Northeast		Liberty		Gulf Coast		Total
Revenue	$	935,513	$	268,884	$	248,949	$	96,473	$	1,549,819
Purchased product costs		506,911		91,612		83,847		—		682,370
Net operating margin(1)		428,602		177,272		165,102		96,473		867,449
Facility expenses		82,761		27,126		34,913		38,436		183,236
Portion of operating income attributable to non-controlling interests		5,431		—		63,731		—		69,162
Operating income before items not allocated to segments	$	340,410	$	150,146	$	66,458	$	58,037	$	615,051

(1)

Net operating margin is a non-GAAP financial measure. For a reconciliation of net operating margin to income from operations, the most comparable GAAP financial measure, see Non-GAAP Measures discussion below.

Organizational Structure

        We are a master limited partnership with outstanding common units, Class A units and Class B units.

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Our common units are publicly traded on the New York Stock Exchange under the symbol "MWE.".

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All of our Class A units are owned by MarkWest Hydrocarbon and our General Partner, which are our wholly-owned subsidiaries. The unregistered 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 Class A units share, on a pro-rata basis, in the income or loss of the Partnership except for those items described in (ii) above. The ownership structure, whereby our Class A units are held by

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MarkWest Hydrocarbon and the General Partner, was adopted upon the merger of the Partnership and MarkWest Hydrocarbon in February 2008 (the "Merger").

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All of our Class B units were issued to and are held by M&R MWE Liberty, LLC ("M&R"), an affiliate of The Energy and Minerals Group ("EMG") as part of our December 31, 2011 acquisition of the non-controlling interest in MarkWest Liberty Midstream & Resources, L.L.C. ("MarkWest Liberty Midstream"). See Recent Developments below for further discussion. The unregistered Class B units will convert to common units on a one-for-one basis (the "Converted Units") in five equal installments beginning on July 1, 2013 and each of the first four anniversaries of such date. Class B units (i) are not entitled to participate in any distributions of available cash prior to their conversion and (ii) 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) other than those matters that disproportionately and adversely affect the rights and preferences of the Class B units. Upon conversion of the Class B units, the right of M&R and certain of its affiliates to vote as a common unitholder of the Partnership will be limited to a maximum of 5% of the Partnership's outstanding common units. Once converted, M&R and certain of its affiliates will have the right to participate in underwritten offerings of our Partnership in an amount up to 20% of the total number of common units offered and will have comparable 20% participation and sale rights if the Partnership adopts a continuous equity or similar program in the future. M&R also has limited rights to distribute an aggregate of 2,500,000 common units to its members and their limited partners beginning in 2016, and M&R and certain of its affiliates will have the right to demand that we conduct up to three underwritten offerings beginning in 2017, but restricted to no more than one offering in any twelve-month period. Except as described above, M&R is not permitted to transfer its Class B units or Converted Units without the prior written consent of the General Partner's board of directors (the "Board").

        The following table provides the aggregate number of units and relative ownership interests of the Class A and B units and common units as of February 17, 2012 (units in millions):

	Units		%
Common units		95.9		69.2	%
Class A units		22.6		16.3	%
Class B units		20.0		14.5	%
Total units		138.5		100	%

        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. The ownership percentages as of February 17, 2012 in the graphic depicted below reflect the Partnership structure

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from the basis of the consolidated financial statements with the Class A units eliminated in consolidation. All Class B units are owned by the public.

        The primary benefit of our organizational structure is the absence of incentive distribution rights, which prior to our Merger, 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 absence 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

Acquisition of Non-controlling Interest in MarkWest Liberty Midstream

        Effective December 31, 2011, we acquired the 49% interest in MarkWest Liberty Midstream held by M&R for consideration of approximately $994 million of cash and the issuance of approximately 19,954,000 unregistered Class B units valued at approximately $753 million. We also incurred approximately $4 million in third-party transaction costs. As a result, we own 100% of MarkWest Liberty Midstream as of December 31, 2011. Please refer to the Organizational Structure for a description of the Class B units and refer to Note 4 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of the accounting treatment of the acquisition.

Utica Shale Joint Venture

        Effective January 1, 2012, we and EMG Utica, LLC ("EMG Utica"), an affiliate of EMG, executed agreements to form a Utica Shale midstream joint venture (the "Utica Joint Venture") operated through MarkWest Utica EMG, L.L.C. ("MarkWest Utica EMG") to develop significant natural gas processing and NGL fractionation, transportation and marketing infrastructure in Eastern Ohio beginning in 2012. Under the terms of the agreements, EMG Utica is obligated to fund the initial capital expenditures of MarkWest Utica EMG, up to the first $500 million.

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        The first phase of the Utica development plan includes two new processing complexes and 100,000 Bbl/d of fractionation, storage and marketing capacity. The initial processing plant in Harrison County is expected to have a capacity of 200 MMcf/d and begin initial operations in mid-2013. MarkWest is finalizing the design capacity and the location of the second processing complex, which is also expected to begin operations in 2013. Both processing complexes are expected be connected via an NGL gathering system to the fractionation facilities in Harrison County that are anticipated to be operational in 2013.

Common Unit Offerings

        On December 19, 2011, we completed a public offering of 10.0 million newly issued common units representing limited partner interests. On January 13, 2012, we issued an additional 0.7 million units pursuant to the underwriters' exercise of their option to purchase additional common units. The total net proceeds of the offering, including the exercise of the underwriters' option, were approximately $559 million and were primarily used to partially fund the cash consideration for the acquisition of the 49% non-controlling interest in MarkWest Liberty Midstream. We completed additional public offerings earlier in 2011 and, in total, issued 23.2 million common units receiving net proceeds of approximately $1.1 billion. Refer to Note 17 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of the accounting treatment of the common unit offering.

Credit Facility

        On December 29, 2011, we amended our revolving credit facility as provided under the Amended and Restated Revolving Credit Agreement dated July 1, 2010, as amended ("Credit Facility") to increase the borrowing capacity to $900 million, and to reset the uncommitted accordion feature of $250 million, providing us with the additional financial flexibility to continue to execute our growth strategy. Earlier in 2011, we had amended the Credit Facility to reduce the interest rates and extend the maturity date to September 2016. See Note 16 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further details of our Credit Facility.

Senior Notes Offerings and Tender Offers

        During 2011, we completed a public offering for $500 million in aggregate principal amount of 6.5% senior notes due in August 2021 ("2021 Senior Notes") and a public offering for $700 million in aggregate principal amount of 6.25% senior notes due in June 2022 ("2022 Senior Notes"). A portion of the $1.2 billion combined net proceeds from these offerings was used to repurchase $275 million aggregate principal amount of our 8.5% senior notes due in July 2016 and approximately $419 million aggregate principal amount of our 8.75% senior notes due in April 2018, with the remainder used to provide additional capital for general partnership purposes and to fund our capital expenditures. As a result of these refinancing activities, we have significantly reduced the interest rates and extended the terms of our long-term financing. See Note 16 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for more details of these senior notes transactions and discussion of the accounting impacts.

Expansion of Marcellus Shale Operations

        During the third quarter of 2011, we began operations of our fractionation facility at our Houston, Pennsylvania processing complex ("Houston Complex") with a design capacity of 60,000 barrels per day. This was a significant milestone in our continued development of our fully integrated midstream services in the Marcellus Shale.

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        In January 2012, we announced the 400 MMcf/d expansion of our processing facilities in Majorsville, West Virginia ("Majorsville Complex"), which would bring the total cryogenic processing capacity at the Majorsville Complex to 670 MMcf/d. The expansion of the Majorsville Complex includes two, 200 MMcf/d processing trains that are expected to begin operations in 2013 and will be supported by long-term agreements with CONSOL Energy, Noble Energy and Range Resources.

        In February 2012, we announced plans to expand the capacity of our processing facilities in Sherwood, West Virginia ("Sherwood Complex") with an additional 200 MMcf/d cryogenic processing plant that is expected to be completed in 2013. The expansion plans are based, in part, on a producer customer's decision to support the additional capacity under a long-term processing agreement. The producer customer has publicly stated its intent to move forward with the project but must make its final decision on whether to proceed with the additional plant at the Sherwood Complex by July 1, 2012.

        See Our Operating Segments below for additional discussion of our existing operations and planned expansion in Liberty and other segments.

Business Strategy

        Our primary business strategy is to provide top-tier midstream services by developing and operating high-quality, strategically located assets in the liquids-rich areas of the emerging resource plays in the United States. We plan to accomplish this through the following:

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Developing long-term integrated relationships with our producer customers.  As a top-rated midstream service provider, we develop long-term, integrated relationships with key producer customers as evidenced by our relationships with the primary producers in the Woodford Shale, the Haynesville Shale, the Granite Wash, the Marcellus Shale and the Huron/Berea Shale. We intend to continue to develop relationships that are characterized by joint planning for the development of the emerging resource plays, such as the Utica Shale, and our commitment to grow to meet the specific needs of our customers.

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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 2011, we spent approximately $551 million of total capital to develop midstream infrastructure in the Marcellus Shale and to expand several of our gathering and processing operations in our Southwest segment, including the Western Oklahoma gas processing plant.

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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 longer includes incentive distribution rights, positions us to compete more effectively for future acquisitions. For example, during 2011, we completed the Langley Acquisition for approximately $231 million to acquire natural gas processing and NGL pipeline assets located in Kentucky and West Virginia for processing gas produced in the Huron/Berea Shale and transporting NGLs to our Siloam fractionation facility. In addition, we acquired the non-controlling 49% interest in MarkWest Liberty Midstream for consideration of $994 million in cash and approximately 19,954,000 unregistered Class B units valued at approximately $753 million. Please refer to Note 4 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of the acquisition of non-controlling interest.

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Maintaining our financial flexibility.  Our goal is to maintain a capital structure with approximately equal amounts of debt and equity financing on a long-term prospective basis. During 2011, we

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raised approximately $2.3 billion by strategically accessing the debt and equity markets to fund our planned expansion projects and to effectively refinance a significant portion of our senior notes to realize lower interest rates and to extend the maturity dates. See Note 16 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of the recent transactions related to our senior notes. We also entered into amendments to our Credit Facility to expand the borrowing capacity from $705 million to $900 million and to extend the term to September 2016. As of December 31, 2011, we and our wholly-owned subsidiaries had approximately $117 million of cash and cash equivalents and we had approximately $815 million available for borrowing under our Credit Facility. We believe that our Credit Facility, our ability to issue additional partnership units and long-term debt and our strong relationships with our existing joint venture partners will provide us with the financial flexibility to facilitate the execution of our business strategy.

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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 estimate that fee-based contracts will account for greater than 50% of our net operating margin in 2013. 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 6 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of our commodity risk management policy.

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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 many of our facilities, which enables us to increase throughput with minimal incremental costs.

        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, Marcellus Shale and Huron/Berea Shale, five emerging resource plays that are expected to be a significant source of domestic natural gas and NGL production. Additionally, we have recently announced plans for the development of operations in the Utica Shale. The following table summarizes the magnitude of the growth projects and acquisitions, including equity investments. The amounts include the portion of our growth projects funded by contributions from our joint venture partners.

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

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Leading position in the liquids-rich areas of the northeast United States.  Since our inception, we have been the largest processor and fractionator in the northeast United States and we continue

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to strengthen our position in this critical growth area that is driven by the development of the Marcellus, Huron/Berea, and Utica shale formations. Currently, our Northeast and Liberty segments have combined processing capacity in excess of 1.1 Bcf/d and combined fractionation capacity of nearly 85,000 barrels per day, as well as an integrated NGL pipeline, storage and marketing infrastructure. Our processing and fractionation capacity is supported by strategic long-term agreements that include significant acreage dedications from key producers. We believe our significant presence and asset base provide us with a competitive advantage in capturing and contracting for new supplies of natural gas as the production from these shale formations continues to be developed, particularly in the liquids-rich area of the region as evidenced by the recently announced development plans for the Utica Shale.

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Strategic and growing position with high-quality assets in the Southwest and the Gulf Coast.  Our acquisitions and internal growth projects since inception 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 expanded this strategy through our agreement with Newfield Exploration Mid-Continent Inc. ("Newfield") by building the largest gathering system to date in the Woodford Shale in southeast Oklahoma. We have continued this strategy through the current development of our gathering system in the Granite Wash area under a similar arrangement with Newfield. All of our major acquisitions and growth projects in this region have been characterized by several common critical success factors that include:

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an existing strong competitive position;

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

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ample opportunities for long-term continued organic growth;

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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 or with direct access to the Cotton Valley, Pettit and Travis Peak reservoirs as well as the Haynesville and Bossier Shales. 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 that is currently being developed as mentioned above. Additionally, as described 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.

Our Gulf Coast assets provide high quality processing and fractionation service to six strategically located gulf coast refineries that we believe will continue to play a key role in supporting the long-term U.S. demand for refined petroleum products.

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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 43% of our current gathering volumes are under contract for longer than 4 years as of December 31, 2011. Approximately 59% 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 6 years. Approximately 93% of our throughput in the Woodford gathering system is subject to contracts with remaining terms of more than 5 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 9 and 17 years. In Appalachia, our natural gas processing and NGL fractionation and exchange contracts with remaining terms of

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more than 4 years account for approximately 77% of our volumes, with 60% of volumes subject to contracts with terms of at least 10 years. In the Gulf Coast segment, approximately 74% of our volumes are under contract for more than 7 years. In the Liberty segment, all of our current gathering and processing agreements with significant dedicated acreage have remaining terms of at least 9 years.

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Experienced management with operational, technical and acquisition expertise.  Each member of our executive management team, whose interests are aligned with those of our common unitholders, 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 midstream infrastructure facilities. 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 13 acquisitions as of December 31, 2011, including the acquisition of the non-controlling interest in MarkWest Liberty Midstream effective December 31, 2011.

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, natural gas processing and NGL fractionation processes:

        The natural gas production process begins with the drilling of wells into gas-bearing rock formations. The gathering process begins when a producing 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.

        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.

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        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 and treated. Natural gas processing and treating involves the separation of raw natural gas into pipeline-quality natural gas, principally methane, and a mixed NGL stream, as well as the removal of 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 gas industry discussion above, the natural gas delivered to our Javelina processing plant is a product of the crude oil refining process. The following diagram illustrates the significant gas processing and fractionation processes at the Javelina facility:

        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.

        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.

        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 currently recovered from the natural gas stream in our Northeast and Liberty segments. However, we are developing projects that would allow us to recover ethane and provide our producer customers with access to markets for the ethane produced in the Liberty

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segment, which are expected to begin operations in mid-2013. See Our Operating Segments—Liberty Segment below in this Item 1 for further discussion of our ethane solution.

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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 mainly 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 primarily used by refiners to enhance the octane content of motor gasoline.

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

        The other primary products produced and sold from our Javelina facility are discussed below.

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Ethylene is primarily used in the production of a wide range of plastics and other chemical products.

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Propylene is primarily used in manufacturing plastics, synthetic fibers and foams. It is also used in the manufacture of polypropylene, which has a variety of end-uses including packaging film, carpet and upholstery fibers and plastic parts for appliances, automobiles, houseware and medical products.

Our Operating Segments

        We conduct our operations in the following operating segments: Southwest, Northeast, Liberty and Gulf Coast. Our assets and operations in each of these segments are described below. In addition, we include a description of the initial planned development of the Utica segment.

Southwest Segment

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East Texas.  We own a system in East Texas that 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. For natural gas that is processed in this area, we purchase the NGLs from the producers primarily under percent-of-proceeds arrangements or we transport volumes for a fee.

Approximately 77% of our natural gas volumes in the East Texas System result from contracts with 6 producers in 2011. 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 19.4% of our consolidated revenue in 2011. The initial term of the Targa agreement expires in December 2015.

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Oklahoma.  We own a natural gas gathering system in the Woodford Shale play in the Arkoma Basin of southeast Oklahoma. The liquids-rich natural gas gathered in the Woodford system is processed through Centrahoma Processing LLC ("Centrahoma"), our equity investment, or other third-party processors. In addition, we own the Foss Lake natural gas gathering system and the Western Oklahoma natural gas processing complex, all located in Roger Mills, Beckham, 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 a gathering system in the Granite Wash formation in Wheeler County in the Texas panhandle that

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is connected to our Western Oklahoma processing complex. We completed the expansion of the Western Oklahoma natural gas processing plant in October 2011, which increased our processing capacity at the Western Oklahoma complex by 75 MMcf/d to a total of 235 MMcf/d. The gathering and processing expansions are supported by long-term agreements with producer customers.

Approximately 70% of our Oklahoma volumes result from contracts with 3 producers in 2011. We sell substantially all of the NGLs produced in the Western Oklahoma processing complex to ONEOK Hydrocarbon L.P. ("ONEOK") under a long-term contract. Such sales represent approximately 13.2% of our consolidated revenue in 2011. The initial term of the ONEOK agreement expires in October 2021.

Through our joint venture, MarkWest Pioneer, we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline that interconnects with the Midcontinent Express Pipeline and Gulf Crossing Pipeline at Bennington, Oklahoma and is designed to provide approximately 638,000 Dth/d of Woodford Shale takeaway capacity. We plan to complete an additional interconnect with the NGPL Pipeline in Bennington, Oklahoma in April 2012. 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 Shale. 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. Our Hobbs, New Mexico natural gas pipeline is subject to regulation by FERC.

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

Northeast Segment

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Kentucky and southern West Virginia.  Our Northeast segment assets include the Kenova, Boldman, Cobb, Kermit and Langley (acquired in the first quarter of 2011) natural gas processing plants, an NGL pipeline and the Siloam NGL fractionation plant. In connection with the acquisition of the Langley processing plants, related facilities, and partially completed Ranger pipeline, we completed the construction of the Ranger Pipeline to extend our existing NGL pipeline and connect the Langley Processing Facilities to our Siloam fractionation facility. We also plan to complete an additional cryogenic natural gas processing plant with a capacity of 150 MMcf/d by the fourth quarter of 2012. In addition, we have two caverns for storing propane at our Siloam facility and additional propane storage capacity under a long-term firm-capacity agreement with a third party. The Northeast segment operations include fractionation and marketing services on behalf of the Liberty segment through the end of the third quarter 2011. Including our presence in the Marcellus shale (see Liberty Segment below), we are the largest processor and fractionator of natural gas in the Northeast, with fully integrated processing, fractionation, storage and marketing operations.

•

Michigan.  We own and operate a FERC-regulated crude oil pipeline in Michigan ("Michigan Crude Pipeline") providing transportation service for three shippers.

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The Northeast Segment has one customer that accounts for a significant portion of its segment revenue, but this customer does not account for a significant portion of our consolidated revenue.

Liberty Segment

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Marcellus Shale.  We provide extensive natural gas midstream services in southwestern Pennsylvania and northern West Virginia through MarkWest Liberty Midstream. With gathering capacity of 325 MMcf/d and current processing capacity of 625 MMcf/d, we are the largest processor of natural gas in the Marcellus Shale, with fully integrated gathering, processing, fractionation, storage and marketing operations that are critical to the liquids-rich gas development in the northeast United States.

The processing and fractionation facilities currently operating and under construction in our Liberty segment include the following:

        Processing    

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355 MMcf/d of current cryogenic processing capacity at our Houston Complex, which includes a 200 MMcf/d cryogenic plant that began operations in the second quarter of 2011.

•

270 MMcf/d of current cryogenic processing capacity at our Majorsville Complex, which includes a 135 MMcf/d cryogenic plant that began operations in the second quarter of 2011.

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400 MMcf/d expansion of our Majorsville Complex, expected to commence operation in 2013, bringing our total cryogenic processing capacity at Majorsville to 670 MMcf/d. The Majorsville expansion includes two, 200 MMcf/d processing trains that are and will be supported by long-term agreements with CONSOL Energy, Noble Energy and Range Resources.

•

320 MMcf/d cryogenic processing capacity under construction in Mobley, West Virginia ("Mobley Complex") where cryogenic plants with capacity of 120 MMcf/d and 200 MMcf/d are expected to be completed in the first and second half of 2012, respectively.

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200 MMcf/d cryogenic processing capacity under construction at our Sherwood Complex that is expected to be completed in the second half of 2012. We recently announced plans to expand the capacity at our Sherwood Complex with an additional 200 MMcf/d cryogenic processing plant that is expected to be completed in 2013. The expansion plans are based, in part, on a producer customer's decision to support the additional capacity under a long-term processing agreement. The producer customer has publicly stated its intent to move forward with the project but must make its final decision on whether to proceed with the additional plant at the Sherwood Complex by July 1, 2012.

        By the end of 2013, MarkWest Liberty Midstream is expected to have between 1.5 Bcf/d and 1.7 Bcf/d of cryogenic processing capacity that is supported by long-term agreements with our producer customers. NGLs produced at the Majorsville Complex are delivered through an NGL pipeline ("Majorsville Pipeline") to the Houston Complex for exchange for fractionated products. We also plan to complete an NGL pipeline connecting each of the planned processing facilities to the Majorsville Pipeline allowing for fractionation at the Houston Complex. By the end of 2012, MarkWest Liberty Midstream expects to have approximately 100 miles of NGL transportation pipeline.

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Fractionation and Market Outlets

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Existing fractionation facility at our Houston Complex with a design capacity of 60,000 Bbl/d that was placed into service in the third quarter of 2011. Prior to the completion of the Houston fractionation facility, only propane was recovered at our Houston Complex and further fractionation of the remaining portion of the NGL stream produced at the Liberty processing plants was performed at the Siloam NGL fractionation plant in our Northeast segment.

•

Existing interconnect with a key interstate pipeline providing a market outlet for the propane produced from this region.

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Existing extension of our Majorsville Pipeline to receive NGLs produced at a third-party's Fort Beeler processing plant. This project allows certain producers to benefit from our integrated NGL fractionation and marketing operations.

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Railcar loading facility under construction at our Houston Complex that is expected to be completed in the first half of 2012.

        We continue to evaluate additional projects to expand our gathering, processing, fractionation and marketing operations in the Marcellus Shale.

Ethane Recovery and Associated Market Outlets

        Due to the increased production of natural gas from the liquids-rich area of the Marcellus Shale, natural gas processors must begin to recover a significant amount of ethane from the raw NGL stream to continue to meet the pipeline gas quality specifications for residue gas. We have been developing a solution that will have the capability to recover and fractionate the required ethane, be scalable to recover and fractionate additional ethane at the option of our producer customers and provide access to attractive ethane markets in North America and Europe. The primary components of our ethane recovery solution consist of the following:

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75,000 Bbl/d de-ethanization facilities under construction at our Houston and Majorsville Complexes that are expected to be completed by mid-2013.

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A third de-ethanization facility is planned that would increase production capacity of purity ethane to 115,000 Bbl/d by 2014.

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A joint pipeline project with Sunoco Logistics, L.P. ("Sunoco") that is currently under construction to deliver Marcellus ethane to Sarnia, Ontario, Canada markets ("Mariner West"). Mariner West will utilize new and existing pipelines and is anticipated to have an initial capacity to transport up to 50,000 Bbl/d of ethane by mid-2013 with the ability to expand to support higher volumes as needed. Sunoco completed an open season for Mariner West and received binding commitments from shippers that would enable the project to proceed as designed.

•

An additional joint project with Sunoco is under consideration ("Mariner East"). Mariner East, a pipeline and marine project, is intended to deliver Marcellus purity ethane to the Gulf Coast and international markets. Mariner East is anticipated to have initial capacity to transport up to 50,000 Bbl/d of ethane.

        We continue to evaluate additional projects that would support a comprehensive ethane solution for producers in the Marcellus Shale.

The majority of the volumes currently processed in the Liberty segment result from contracts with three producers. The resulting NGLs are sold to numerous customers in the northeast United States. There

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is one individual customer that we consider to be significant to the Liberty segment revenue but not to our consolidated revenue.

Utica Segment

        Effective January 1, 2012, MarkWest and EMG formed MarkWest Utica EMG, a joint venture focused on the development of significant natural gas processing and NGL fractionation, transportation and marketing infrastructure to serve producers' drilling programs in the Utica shale in eastern Ohio. The first phase of the Utica development plan includes two new processing complexes and a 100,000 Bbl/d fractionation, storage, and marketing facility. The initial processing complex will be in Harrison County ("Harrison Complex"), and is expected to begin initial operations in mid-2013. MarkWest is finalizing the design capacity and the location of the second processing complex, which is also expected to begin operations in 2013.

        Both processing complexes are expected to be connected via an NGL pipeline system to the fractionation facilities at the Harrison Complex that is expected to be operational in 2013. Creating a large network of processing complexes connected through an extensive NGL gathering system has been critical to the full development of the Marcellus, and the announced Ohio facilities represent the first major step in providing Utica producers with the same benefits. Additionally, the Harrison Complex fractionation facilities, which would be able to market NGLs by truck, rail and pipeline, is expected to be connected to our extensive processing and NGL pipeline network in our Liberty segment and provide for the integrated operation of the two largest fractionation complexes in the Northeastern United States.

        The Utica Segment did not have any assets, liabilities, equity or operations as of, or for the year ending, December 31, 2011. As such, it is not considered a reportable segment as described in Note 24 of the accompanying Notes to the 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 that treats and processes off-gas from six local refineries operated by three different refinery customers. We have a product supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the product processed by the SMR (see Note 5 of the accompanying Notes to Consolidated Financial Statements for further discussion of this agreement and the related SMR Transaction). The product received under this agreement is 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 Non-GAAP Measures discussion below) generated by our assets, by segment, for the year ended December 31, 2011:

	Southwest			Northeast			Liberty			Gulf Coast			Total
Revenue		60	%		17	%		16	%		7	%		100	%
Net operating margin		49	%		20	%		19	%		12	%		100	%

        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.

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Equity Investment in Unconsolidated Affiliate

        We own a 40% non-operating membership interest in Centrahoma, a joint venture with Cardinal Midstream, LLC ("Cardinal") that is accounted for using the equity method. Centrahoma owns certain processing plants in the Arkoma Basin and Cardinal operates an additional processing plant that is not owned by Centrahoma but is located adjacent to and operates in conjunction with the Centrahoma plants. We have signed long-term agreements to dedicate the processing rights for our natural gas gathering system in the Woodford Shale to Centrahoma and to Cardinal's independently owned processing facility. 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 financial measure, see Non-GAAP Measures below for discussion and reconciliation of net operating margin) from natural gas gathering, transportation and processing; NGL transportation, fractionation, exchange, 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 types of arrangements:

•

Fee-based arrangements:  Under fee-based arrangements, we receive a fee or fees for one or more of the following services: gathering, processing and transportation of natural gas; transportation, fractionation, exchange, marketing 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 (i) a percentage discount to a specified index price, (ii) a specified index price less a fixed amount or (iii) 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 (i) and (iii) 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 for the producer, process the natural gas and sell the resulting condensate and NGLs to third parties at market prices. Because the extraction of NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for

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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 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 may influence our long-term financial results.

Non-GAAP Measures

        In evaluating the Partnership's financial performance, management utilizes the segment performance measures, segment revenues and operating income before items not allocated to segments. These financial measures are presented in Note 24 to the accompanying condensed consolidated financial statements and are considered non-GAAP financial measures when presented outside of the notes to the condensed consolidated financial statements. The use of these measures allows investors to understand how management evaluates financial performance to make operating decisions and allocate resources. See Note 24 to the accompanying condensed consolidated financial statements for the reconciliations of segment revenue and operating income before items not allocated to segments to the respective most comparable GAAP measure.

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

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

	Year ended December 31,
	2011			2010			2009
Segment revenue	$	1,549,819		$	1,241,563		$	858,635
Purchased product costs		(682,370	)		(578,627	)		(408,826	)
Net operating margin		867,449			662,936			449,809
Facility expenses		(173,598	)		(151,449	)		(126,977	)
Derivative loss		(75,515	)		(80,350	)		(188,862	)
Revenue deferral adjustment		(15,385	)		—			—
Selling, general and administrative expenses		(81,229	)		(75,258	)		(63,728	)
Depreciation		(149,954	)		(123,198	)		(95,537	)
Amortization of intangible assets		(43,617	)		(40,833	)		(40,831	)
Loss on disposal of property, plant and equipment		(8,797	)		(3,149	)		(1,677	)
Accretion of asset retirement obligations		(1,190	)		(237	)		(198	)
Impairment of goodwill and long-lived assets		—			—			(5,855	)
Income (loss) from operations	$	318,164		$	188,462		$	(73,856	)

        The following table does not give effect to our active commodity risk management program. For further discussion of how we have reduced the downside volatility to the portion of our net operating margin that is not fee-based, see Note 6 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K. For the year ended December 31, 2011, 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		21	%		38	%		4	%		37	%		100	%
Net operating margin(4)		38	%		29	%		0	%		33	%		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.

(4)

We manage our business by taking into account the partial offset of short natural gas positions by long positions primarily in our Southwest segment. The calculated percentages for the net operating margin for percent-of-proceeds, percent-of-index and keep-whole contracts reflect the partial offset of our natural gas positions.

Competition

        In each of our operating segments, we face competition for natural gas gathering and crude oil transportation and in obtaining natural gas supplies for our processing and related services; 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,

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proximity to supply and industry marketing centers and cost efficiency and reliability of service. Competition for customers to purchase our natural gas and NGLs is based primarily on price, delivery capabilities, flexibility and maintenance of high-quality customer relationships.

        Our competitors include:

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a large number of natural gas midstream providers, of varying financial resources and experience, 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

        Some of our competitors operate as master limited partnerships and may 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 contracted 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 the Southwest segment, our major gathering systems are relatively new, are located primarily in the heart of shale plays with significant growth opportunities 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 more than 20 years as the largest processor and fractionator in the region and our existing presence in the Appalachian Basin provide a significant competitive advantage. In the Liberty segment, our early entrance in the liquids-rich corridor of 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 and the development of the Utica Shale. In our Gulf Coast segment, the strategic location of our assets and the long-term nature of our contracts provide a significant competitive advantage.

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 our Northeast segment operations, 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. These seasonal factors also impact our Liberty segment; however, the expected growth and expansion in our Liberty segment may counteract this seasonality impact.

Regulatory Matters

        Our operations are subject to extensive regulations. The failure to comply with applicable laws and regulations or to obtain, maintain and comply with requisite permits and authorizations can result in substantial penalties and other costs to the Partnership. The regulatory burden on our operations increases our 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

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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.

        FERC-Regulated Natural Gas Pipelines.    Our natural gas pipeline operations are subject to federal, state and local regulatory authorities. Specifically, our Hobbs, New Mexico natural gas pipeline and our Arkoma Connector natural gas pipeline in Oklahoma are subject to regulation by FERC, and it is possible that we may construct additional gas pipelines in the future that may be subject to such regulation. Federal regulation extends to various matters including:

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rates and rate structures;

•

return on equity;

•

recovery of costs;

•

the services that our regulated assets are permitted to perform;

•

the acquisition, construction, expansion, operation and disposition of assets;

•

Affiliate interactions; and

•

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 FERC regulated natural gas facilities from unduly preferring, or unduly discriminating against, any person with respect to pipeline rates or terms and conditions of service or other matters. 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 be assured that FERC will continue to pursue its approach of pro-competitive 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 EPAct"). Under the 2005 EPAct, 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 EPAct 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 EPAct. This order makes it unlawful for gas pipelines and storage companies that provide interstate services to: (i) directly or indirectly, to use or employ any device, scheme or artifice to defraud 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; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC's enforcement authority.

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        Standards of Conduct.    On October 16, 2008, FERC issued new standards of conduct for transmission providers (Order 717) to regulate the manner in which interstate natural gas pipelines may interact with their marketing affiliates based on an employee separation approach. A "Transmission Provider" includes an interstate natural gas pipeline that provides open access transportation pursuant to FERC's regulations. Under these rules, a Transmission Provider's transmission function employees (including the transmission function employees of any of its affiliates) must function independently from the Transmission Provider's marketing function employees (including the marketing function employees of any of its affiliates). FERC issued Order 717-A, an order on rehearing and clarification of Order 717, on October 15, 2009. FERC further clarified Order 717-A in a rehearing order, Order 717-B, on November 16, 2009, in Order 717-C, on April 16, 2010, and in Order 717-D, on April 8, 2011. However, Orders 717-B, 717-C, and 717-D did not substantively alter the rules promulgated under Orders 717 and 717-A.

        Market Transparency Rulemakings.    In 2007, FERC issued Order 704, whereby 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 requires most, if not all of our natural gas pipelines to report annual volumes of relevant transactions to FERC.

        Intrastate Natural Gas Pipeline Regulation.    Some of 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 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.

        Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, FERC and the courts. We cannot predict the ultimate impact of these or the above regulatory changes to our natural gas operations. We do not believe that we would be affected by any such FERC action materially differently than other midstream natural gas companies with whom we compete.

        Natural Gas Gathering Pipeline Regulation.    Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC if the primary function of the facilities is gathering natural gas. 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. We cannot provide assurance, however, that FERC will not at some point assert that transportation on these facilities 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.

        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 and regulations. Ratable take statutes and regulations generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes and regulations 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

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source of supply. Although state regulation is typically less onerous than at FERC, these statutes and regulations 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 or regulated as a public utility. Our gathering operations also may be or become subject to safety and operational regulations and permitting relating to the design, siting, 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.

        NGL Gathering Pipelines.    Several of our NGL gathering pipelines carry NGLs across state lines; however, we do not operate these pipelines as common carrier pipelines or hold them out for service to the public because there are no third-party shippers on the pipelines and we do not expect third-party shippers to seek to use these NGL pipelines. Accordingly, we believe these pipelines would meet the qualifications for a waiver from FERC's applicable regulatory requirements. We cannot, however, provide assurance that FERC will not, at some point, either at the request of other entities or on its own initiative, assert that some or all of such transportation is within its jurisdiction or that such an assertion would not adversely affect our results of operations. In the event FERC were to determine that these NGL pipelines would not qualify for a waiver from FERC's applicable regulatory requirements, we would likely be required to file a tariff with FERC, provide a cost justification for the transportation charge and provide service to all potential shippers without undue discrimination. We also may elect to construct one or more common carrier NGL product pipelines to transport NGL products for third-party shippers across state lines or otherwise in interstate commerce, in which event we would be required to comply with FERC requirements for such common carrier pipelines, including the filing of a tariff. Our NGL pipelines are subject to safety regulation by the Department of Transportation under 49 C.F.R. Part 195 for operators of hazardous liquid pipelines. Our NGL gathering pipelines and operations may also be or become subject to state public utility or related jurisdiciton which could impose additional safety and operational regulations relating to the design, siting, installation, testing, construction, operation, replacement and management of NGL gathering facilities.

        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.

        Common Carrier Crude 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

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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 these pipelines to keep tariffs on file with FERC that set forth the rates the pipeline charges for providing transportation services and 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. FERC retains cost-of-service ratemaking, market-based rates and settlement rates as alternatives to the indexing approach.

        On February 24, 2009, we filed to increase our rates on the Michigan Crude Pipeline, 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 and denied a request for rehearing. We filed an appeal of FERC's decision at the Court of Appeals for the District of Columbia Circuit. On July 1, 2011, the Court denied our petition for review of the FERC's decision.

        On July 30, 2010, we made a cost-of-service filing at FERC to increase our rates for transportation on the Michigan Crude Pipeline. Several parties protested this filing and on August 31, 2010, FERC accepted the filing, effective September 1, 2010, subject to refund. FERC also established a hearing to investigate the issues raised by the protestors, but ordered the hearing to be held in abeyance pending the result of settlement discussions between the parties. On July 25, 2011, the parties submitted an offer of settlement to FERC in this proceeding and on December 16, 2011, FERC issued an order accepting that settlement. MarkWest began charging the settlement rates effective August 1, 2011 and expects to pay refunds related to the initial filing once the FERC's December 2011 order becomes final and is no longer subject to appeal.

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 environmentally sensitive areas such as wetlands or areas inhabited by endangered species, requiring us to incur 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. We cannot assure, 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 trend in environmental law is to place more restrictions and limitations on activities that may be perceived to affect the environment. Thus there can be no assurance as to the amount or timing of future expenditures for compliance with environmental laws and regulations, permits and permitting

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requirements, or remediation pursuant to such laws and regulations, 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. Such revised or additional environmental requirements may also result in material delays in the construction or expansion of our facilities, which may materially impact our ability to meet our construction obligations with our producer customers.

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 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. 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 off-site treatment 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 defined as hazardous substances under CERCLA or similar state statutes, we do not believe that we have any current material liability for cleanup costs under such laws, or for third party claims or personal injury or property damage. 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. Under the authority of the EPA, most states administer some or all of the provisions of the RCRA, sometimes in conjunction with their own, more stringent requirements. 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 transportation, storage, treatment and/or 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 nonhazardous 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 Third Parties.

        The prior third-party owner or operator of our Cobb, Boldman, Kenova, and Majorsville facilities, who is also the prior owner and current operator of the Kermit facility, has been, or is currently involved in, investigatory or remedial activities with respect to the real property underlying these facilities. 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 third-party owner/operator with the Kentucky Natural Resources and Environmental Protection Cabinet in October 1994. The third party 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 third party has agreed to perform all the required response actions at its expense in a manner that minimizes interference with our use of the properties. We understand that to date, all actions required under these agreements have been or are being performed 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.

        In addition, the prior third-party owner and/or operator of certain facilities on the real property on which our rail facility is being constructed near Houston, Pennsylvania has been, or is currently involved in, investigatory or remedial activities related to acid mine drainage ("AMD") with respect to the real property underlying these facilities. These investigatory and remedial obligations arise out of an arrangement entered into between the Pennsylvania Department of Environmental Protection and the third party, which has accepted liability and responsibility for, and indemnifies us against, any environmental liabilities associated with the AMD that are not exacerbated by us in connection with our operations. In addition, the third party has agreed to perform all of the required response actions at its expense in a manner that minimizes interference with our use of the property. We understand that to date, all actions required under these agreements have been or are being performed 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 Discharges.

        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 addition, 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 federal, state and local agencies with regard to the application of those laws and regulations to our facilities, including the permitting process and categories of applicable permits for stormwater or other discharges, stream crossings and wetland disturbances that may be required for the construction or operation of certain of our facilities in the various states. We believe that we are in substantial compliance with the Clean Water Act and analogous state laws. However, new permitting requirements or reinterpretations of existing requirements may be implemented that could materially increase our operating costs or materially delay the construction or expansion of our facilities.

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Hydraulic Fracturing.

        Hydraulic fracturing is an important and common practice that is used to stimulate production of natural gas and/or oil from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand and additives under pressure into the formation to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act, as amended ("SDWA") over certain hydraulic fracturing activities involving the use of diesel fuel. In addition, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have already adopted laws and/or regulation that require disclosure of the chemicals used in hydraulic fracturing and many states are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on natural gas drilling activities. In the event that new or more stringent federal, state or local legal restrictions relating to natural gas drilling activities or to the hydraulic fracturing process are adopted in areas where our producer customers operate, those customers could incur potentially significant added costs to comply with such requirements and experience delays or curtailment in the pursuit of production or development activities, which could reduce demand for our gathering, transportation and processing services and/or our NGL fractionation services.

        In addition, certain governmental reviews are either underway or being proposed that focus on potential environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the U.S. House of Representatives has conducted an investigation of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014. Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities and plans to propose these standards by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms, which events could delay or curtail production of natural gas, and thus reduce demand for our midstream services.

Air Emissions.

        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 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, utilize specific equipment or technologies to control emissions, or aggregate two or more of our facilities into one application for permitting purposes. Amendments, expansions or re-interpretations of the Clean Air Act or comparable state laws may cause us to incur capital expenditures for installation of air pollution control equipment and to encounter construction or operational delays while applying for, or awaiting the review, processing and issuance of new or amended permits. For example, on July 28, 2011, the EPA proposed a range of new regulations that would establish new air emission controls for oil and natural gas production and natural gas processing, including, among other things, new leak detection requirements for natural gas processing plants. The EPA is under a court order to finalize these proposed regulations by April 3, 2012. We have been in discussions with various state agencies in the areas in which we operate with respect to their guidance,

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policies, rules and regulations regarding the permitting process, source determination, categories of applicable permits and control technology that may be required for the construction or operation of certain of our facilities. We believe that our operations are in substantial compliance with applicable air permitting and control technology requirements.

Climate Change.

        As a consequence to an EPA administrative conclusion that emissions of carbon dioxide, methane and other greenhouse gases, or GHGs, into the ambient air endangers public health and welfare, the EPA has adopted regulations that require a reduction in emissions of GHGs from motor vehicles and also trigger construction and operating permit review for GHG emissions from certain large stationary sources. The EPA has published its final rule to address the permitting of GHG emissions from stationary sources under the Prevention of Significant Deterioration ("PSD") and Title V permitting programs, pursuant to which these permitting programs have been "tailored" to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, the EPA adopted rules requiring the monitoring and reporting of greenhouse gas emissions from specified greenhouse gas emission sources in the United States, including, among others, certain onshore and offshore oil and natural gas production and onshore oil and natural gas processing, fractionation, transmission, storage and distribution facilities, which may include certain of our operations. As a result of these requirements—all of which are currently subject to judicial review in the Court of Appeals for the District of Columbia—we may be required to incur potentially significant added costs to comply with the new regulatory requirements or added capital expenditures for air pollution control equipment, or we experience delays or possible curtailment of construction or projects in connection with maintaining or in applying or obtaining preconstruction and operating permits and we may encounter limitations to the design capacities or size of facilities as a result of the requirements and consequences of the EPA GHG regulations.

        In addition to the EPA regulations, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise limits emissions of GHGs from our equipment and operations could require us to incur potentially significant added costs to comply with the new regulatory requirements or to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas. It is not possible at this time to predict the full or final 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 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. Finally, for a variety of reasons, natural and/or anthropogenic, climate changes could occur and have significant physical effects, such as increased frequency and severity of storms, droughts and floods and other climatic events; if such effects were to occur, they could have an adverse effect on our operations, 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

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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 were also required to develop a written security plan for our Javelina plant and train our employees accordingly. In March 2010, we received a response from the DHS approving our Security Vulnerability Assessment and requesting that we develop and submit a Site Security Plan for the Javelina plant. We submitted the Site Security Plan to the DHS for review in June 2010. 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 Site Security Plan. 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.

Endangered Species Act Considerations.

        The federal Endangered Species Act ("ESA") restricts activities that may affect endangered or threatened species or their habitats. If endangered species are located in areas where we propose to construct new gathering or transportation pipelines or processing or fractionation facilities, such work could be prohibited or delayed or expensive mitigation may be required. Additionally, construction and operational activities could result in inadvertent impact to habitats of listed species and could result in alleged takings under the ESA, exposing the Partnership to civil or criminal enforcement actions and fines or penalties. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia on September 9, 2011, the U.S. Fish and Wildlife Service is required to make a determination on listing of more than 250 species as endangered or threatened under the ESA over the next six years, through the agency's 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where we conduct operations or plan to construct pipelines or facilities could cause us to incur increased costs arising from species protection measures or could result in limitations on our customer's exploration and production activities, which could have an adverse impact on demand for our midstream operations.

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, these laws are subject to further amendment, with the potential for more

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onerous obligations and stringent standards being imposed on pipeline owners and operators. For example, on January 3, 2012, President Obama signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 ("2011 Pipeline Safety Act"), which requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act directs the Secretary of Transportation to promulgate rules or standards relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use and leak detection system installation. The 2011 Pipeline Safety Act also directs owners and operators of interstate and intrastate gas transmission pipelines to verify their records confirming the maximum allowable pressure of pipelines in certain class locations and high consequence areas, requires promulgation of regulations for conducting tests to confirm the material strength of pipe operating above 30% of specified minimum yield strength in high consequence areas and increases the maximum penalty for violation of pipeline safety regulations from $1 million to $2 million. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could be significant and have a material adverse effect on our results of operations or financial position.

        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 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 has adopted rules that amend the pipeline safety regulations to extend regulatory coverage to certain rural onshore hazardous liquid gathering lines and low stress pipelines, including those pipelines located in 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. For instance, in August 2011, PHMSA published an advance notice of proposed rulemaking in which the agency is seeking public comment on a number of changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, (i) revising the definitions of "high consequence areas" and "gathering lines"; (ii) strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed; (iii) strengthening requirements on the types of gas transmission pipeline integrity assessment methods that may be selected for use by operators; (iv) imposing gas transmission integrity management requirements on onshore gas gathering lines; (v) requiring the submission of annual, incident and safety-related conditions reports by operators of all gathering lines; and (vi) enhancing the current requirements for internal corrosion control of gathering lines.

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

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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, we employ approximately 683 individuals to operate our facilities and provide general and administrative services. We have no employees represented by unions.

Available Information

        Our principal executive office is located at 1515 Arapahoe Street, Tower 1, Suite 1600, Denver, Colorado 80202-2137. 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 on or 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.

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 flow, 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:

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

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

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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;

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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;

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

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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 any future downturn in our business or the economy in general, conduct operations or otherwise take advantage of business opportunities that may arise.

        Our obligations under our Credit Facility are secured by substantially all of our assets and guaranteed by all of our wholly-owned subsidiaries other than MarkWest Liberty Midstream, but including our operating company (please read Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources). Our Credit Facility and our indentures contain 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. 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.

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. Also, tightening of the capital markets could adversely impact our ability to execute our long-term organic growth projects and meet our obligations to our producer customers and limit our ability to otherwise take advantage of business opportunities or react to changing economic and business conditions. These factors could have a material adverse effect on our revenues, income from operations, cash flows and our quarterly distribution on the common units.

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 may fluctuate from quarter to quarter based on, among other things:

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

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

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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;

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the level of our operating costs; and

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prevailing economic conditions.

        In addition, the actual amount of cash available for distribution may 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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restrictions contained in our joint venture 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

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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 and may not make cash distributions during periods when we record net income.

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 2010 ranged from a high of $6.01 per MMBtu to a low of $3.29 per MMBtu. In 2011, the same index ranged from a high of $4.85 per MMBtu to a low of $2.99 per MMBtu. Also as an example, the composite of the weighted monthly average NGLs price at our Appalachian facilities based on our average NGLs composition in 2010 ranged from a high of approximately $1.55 per gallon to a low of approximately $1.11 per gallon. In 2011, the same composite ranged from a high of approximately $2.18 per gallon to a low of approximately $1.51 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;

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seasonality;

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the condition of the U.S. economy;

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•

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

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government regulation, legislation and policies.

        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 NGL 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.

        Additionally, due to the timing of purchases and sales of natural gas and NGLs, direct exposure to changes in market prices of either gas or NGLs can be created because there is no longer an offsetting purchase or sale that remains exposed to market pricing. Direct exposure may occur naturally as result of our production processes or we may create exposure through purchases of NGLs or natural gas. Given that we have derivative positions, adverse movement in prices to the positions we have taken may 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 expect to 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

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imperfect and our risk management 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 is involved. For further information about our risk management policies and procedures, please read Note 6 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K.

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 enactment of the Dodd-Frank Act and promulgation of regulations thereunder, could have an adverse impact on our ability to manage risks associated with our business.

        Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the OTC derivatives market and entities, such as us, that participate in that market. The new legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), was signed into law on July 21, 2010 and requires the Commodities Futures Trading Commission (the "CFTC"), the SEC and other regulators to promulgate rules and regulations implementing the new legislation. The agencies have taken administrative action to defer the effectiveness of the Dodd-Frank Act as they continue to work on finalizing rules. The CFTC has also proposed a phased implementation in which entities such as the Partnership will have a further deferred compliance date. Among the regulations the CFTC has finalized are regulations to set aggregate federal position limits for futures and option contracts for crude oil, natural gas, heating oil and gasoline and for swaps that are their economic equivalents. Certain bona fide hedging transactions or positions would be exempt from these position limits. This regulation will be effective for "spot months" 60 days after the definition of the term "Swap" is finalized and for "all months" after the CFTC obtains approximately one year's data for swap open interest in such contracts. While it is not possible at this time to predict when the CFTC and the SEC will finalize or make these regulations effective, the agencies have issued estimated timeframes which indicate that significant elements of the regulations will be addressed in the first half of 2012. The financial reform regulations may also require us to comply with margin requirements and with certain clearing and trade-execution requirements in connection with our derivative activities either through direct regulation of us or indirectly through regulation of our derivative counterparties, although the specifics of those provisions are uncertain at this time. The financial reform legislation also requires the counterparties to our derivative instruments to spin off some of their derivatives activities to a separate entity, which may not be as creditworthy as the current counterparty. The new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the legislation and regulations, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material, adverse effect on our income from operations, cash flows and quarterly distribution to common unitholders.

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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, treating facilities 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.

        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, drilling costs per Mcf, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulations and the availability and cost of capital. 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 2011, we saw decreases in the prices of natural gas, leading some producers to announce significant reductions to their drilling plans specifically in dry gas areas. If sustained over the long-term, low gas prices could lead to a material reduction in volumes in certain areas of our operations.

        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 facilities would decline, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions.

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.

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

        One of the ways we intend to grow our business is through the construction of, or additions to, our existing, gathering, treating, processing, and fractionation facilities. The construction of gathering, processing, fractionation 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, and stringent, lengthy and occasionally unreasonable or impractical federal, state and local permitting, consent, or authorizations requirements, which may cause us to incur additional capital expenditures for meeting certain conditions or requirements or which may delay, interfere with or impair our construction activities. As a result, new facilities may not be

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constructed as scheduled or as originally designed, which may require redesign and additional equipment, relocations of facilities or rerouting of pipelines, which in turn could subject us to additional capital costs, additional expenses or penalties and may adversely affect our operations and cash flows available for distribution to unitholders. In addition, the coordination and monitoring of this diverse group of projects requires skilled and experienced labor. If we undertake these projects, we may not be able to complete them on schedule, or at all, or at the budgeted cost. In addition, certain agreements with our producer customers contain substantial financial penalties and/or give the producer the right to repurchase certain assets and terminate their contracts with us if construction deadlines are not achieved. Any such penalty or contract termination could have a material adverse effect on our income from operations, cash flows and quarterly distribution to common unitholders. 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 may occur over an extended period of time, and we may not receive any material increases in revenues until after completion of the project, if at all. Our ability to successfully manage these projects depends on obtaining skilled labor, project managers and engineers.

        Furthermore, we may have only limited natural gas or NGL supplies committed to these facilities prior to their construction. Moreover, we may construct facilities to capture anticipated future growth in production or satisfy anticipated market demand in a region in which anticipated production growth or market demand does not materialize, the facilities may not operate as planned or may not be used at all. 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 or NGLs 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, or if third parties do not renew or extend their contracts with us or if third parties suspend or terminate their contracts with us, our financial results would suffer.

We are exposed to the credit risks of our key customers and derivative counterparties, and any material nonpayment or nonperformance by our key customers or derivative counterparties 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, which risks may increase during periods of economic uncertainty. 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. In addition, our risk management 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 risk management policies and procedures are not properly followed. Any material nonpayment or nonperformance by our key

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customers or our derivative counterparties could reduce our ability to make distributions to our unitholders.

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, 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 our unitholders.

        Some of our gas, NGL and crude oil transmission operations are or may in the future be, subject to siting, public necessity, rate and service regulations by FERC or various state regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas, NGLs 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. We also own or are constructing pipelines that are carrying or are expected to carry NGLs owned by us across state lines. We currently are, and expect in the future to be, the only shipper on these pipelines and do not operate, and do not expect in the future to operate, these pipelines as a common carrier or hold them out for service to the public. We do not expect third-party entities to seek to utilize our NGL pipelines; therefore, we believe these pipelines would meet the qualifications for a waiver from FERC's applicable regulatory requirements. However, we cannot provide assurance that FERC will not at some point assert that some or all of such transportation is within its jurisdiction. If FERC were successful with any such assertion, FERC's rate-making methodologies may subject us to potentially burdensome and expensive operational, reporting and other requirements. We may also elect to construct in the future NGL common carrier pipelines to carry NGLs of third parties across state lines or otherwise in interstate commerce, and in such event we would be required to comply with FERC rate, operational, reporting and other requirements which may increase our cost of operations.

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        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 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, which could limit the rates that we may charge and increase our costs of operation. 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, NGL and crude oil 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 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 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 may 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 other property rights, or the cost of renewing existing rights-of-way or property rights 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 and the expansion of our gathering, processing and fractionation assets may require us to obtain new rights-of-way or other property rights prior to constructing new plants, pipelines and other transportation facilities. We may be unable to obtain such rights-of-way or other property rights to connect new natural gas supplies to our existing gathering lines, to connect our existing or future 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 other property rights or to renew existing rights-of-way or property rights. If the cost of obtaining new or renewing existing rights-of-way or other property rights increases, it may adversely affect our operations and cash flows available for distribution to unitholders.

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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 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 and current operator of our Kermit facility. 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.

        In addition, Consol Coal is the previous owner and/or operator of certain facilities on the real property on which our rail facility is being constructed near Houston, Pennsylvania, and has been or is currently involved in, investigatory or remedial activities related to AMD with respect to the real property underlying these facilities. Consol Coal has accepted liability and responsibility for, and has agreed to indemnify us against, any environmental liabilities associated with the AMD that are not exacerbated by us in connection with our operations.

        Our results of operation and our ability to make cash distributions to our unitholders could be adversely affected if in the future either Columbia Gas or Consol Coal fails to perform under the indemnification provisions of which we are the beneficiary.

Our business is subject to laws and regulations with respect to environmental, occupational, safety, nuisance, zoning, land use 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, occupational, safety, nuisance, zoning, land use, 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 CERCLA, RCRA, 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, and new, amended or re-interpreted permitting requirements and processes, might adversely affect our products and activities, and existing laws, regulations and policies could be reinterpreted or modified to impose additional requirements, delays or constraints on our construction of facilities or on our operations. For example, certain requirements under amendments, expansions or re-interpretations of existing laws may include more stringent permitting requirements if two or more of our facilities are aggregated into one application for permitting purposes or the use of certain types of pollution-control equipment for emissions purposes that may increase our costs. Federal, state and local agencies also could impose additional safety requirements, any of which could affect our profitability. Local governments may adopt more stringent

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local permitting and zoning ordinances that impose additional requirements, delays or constraints on our activities to construct and operate our facilities, require the relocation of our facilities or increase our costs to construct and operate our facilities, including the construction of sound mitigation 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, environmental remediation and restoration costs, and governmental fines and penalties. 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 some or all of 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.

        As a consequence to an EPA administrative conclusion that GHGs present an endangerment to public health and the environment, the EPA has adopted regulations that require a reduction in emissions of GHGs from motor vehicles and also trigger PSD and Title V permit requirements for GHG emissions from certain large stationary sources when the motor vehicle standards took effect on January 2, 2011. The EPA rules have tailored the PSD and Title V permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. Also, the EPA adopted rules regulating the monitoring and reporting of greenhouse gas emissions from specified large greenhouse gas emission sources in the United States, including, among others, certain natural onshore and offshore oil and natural gas production and onshore oil and natural gas processing, fractionation, transmission, storage and distribution facilities. In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, and almost one-half of the states have already taken legal measures to reduce emissions of GHGs, primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. As a result of these requirements—all of which are currently subject to judicial review in the Court of Appeals for the District of Columbia—or the adoption of any new legislation or regulations that requires additional reporting, monitoring or recordkeeping of GHGs, or otherwise limits emissions of GHGs from our equipment and operations, could adversely affect our operations and materially restrict or delay our ability to obtain air permits for new or modified facilities, could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil and natural gas we process or fractionate. For more information regarding greenhouse gas emission and regulation, please read Item 1. Business—Environmental Matters—Air and Greenhouse Gases. Finally, for a variety of reasons, natural and/or anthropogenic, climate changes could occur which could 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, which in turn could adversely affect our cash available for distribution to our unitholders.

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.

        Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations such as shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater

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quality, legislation has been introduced before Congress to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. Also, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices, with the EPA commencing a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with initial results expected to be available by late 2012 and final results by 2014 and, more recently, announcing the proposed development of effluent limitations for the treatment and discharge of wastewater resulting from hydraulic fracturing activities by 2014. Other governmental agencies, including the U.S. Department of Energy and the U.S. Department of the Interior, are evaluating various other aspects of hydraulic fracturing. Moreover, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a committee of the United States House of Representatives has conducted an investigation of hydraulic fracturing practices. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements 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 of natural gas that we gather and process and NGLs that we gather and fractionate which could adversely impact our earnings, profitability and cash flows.

The amount of gas we process, gather and transmit, or the NGLs and crude oil we gather and transport, may be reduced if the pipelines to which we deliver the natural gas, NGLs or crude oil cannot, or will not, accept the gas, NGLs 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 may 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 and fractionation facilities. Likewise, if the pipelines into which we deliver NGLs or crude oil are interrupted, we may be limited in, or prevented from conducting, our crude oil or NGL 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 (i) the volumes of natural gas we process, gather and transmit, (ii) the throughput of NGLs through our transportation, fractionation and storage facilities and (iii) 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, various means of transportation and marketing services. 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, or to market the natural gas or NGL's, would adversely affect our operations and cash flows available for distribution to our unitholders.

        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 or facilities;

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•

restrictions imposed by governmental authorities or court proceedings;

•

labor difficulties that result in a work stoppage or slowdown;

•

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 NGL pipelines and fractionation facilities; and

•

inadequate storage capacity or market access to support production volumes.

        In addition, the construction and operation of certain of our facilities in our Northeast and Liberty segments may be impacted by subsurface mining operations. One or more third parties may have previously engaged in, or may in the future engage in, subsurface mining operations near or under our facilities, which could cause subsidence or other damage to our facilities. In such event, our operations at such facilities may be impaired or interrupted, and we may not be able to recover the costs incurred to repair our facilities from such third parties.

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.

Alternative financing strategies may not be successful.

        Periodically, we may consider the use of alternative financing strategies such as joint venture arrangements and the sale of non-strategic assets. Joint venture arrangements 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.

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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 vehicles and construction and farm equipment;

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leakage of crude oil, natural gas, NGLs and other hydrocarbons into the environment, including groundwater;

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fires and explosions; and

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other hazards and conditions, including those associated with various hazardous pollutant emissions, high-sulfur content, or sour gas, and proximity to businesses, homes, or other populated areas, 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.

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, field 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.

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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 (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts with them, (ii) unable to obtain financing for these acquisitions on economically acceptable terms, or (iii) outbid by competitors, then our future growth and ability to increase distributions may 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 may 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;

•

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;

•

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;

•

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 may consider in determining the application of these funds and other resources.

We have partial ownership interests in a number of joint venture legal entities, including Pioneer, MarkWest Utica EMG, Bright Star, 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 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

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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;

•

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;

•

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

•

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.

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 proposed implementation of, or convergence with, IFRS, could change our current application of GAAP. Changes in the application of GAAP and the costs of implementing such changes could result 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.

        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.

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Risks Related to Our Partnership Structure

We may issue additional common units without unitholder approval, which would dilute current unitholder 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:

•

the unitholders' proportionate ownership interest will decrease;

•

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

•

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

•

the market price of the common units may decline; and

•

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 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 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 would 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.

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        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 have considered substantive changes to the existing U.S. tax laws that would have affected certain publicly traded partnerships. Although the proposed legislation would not affect our tax treatment as a partnership, we are unable to predict whether any of these changes or other proposals, will be reintroduced or will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

        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 may be reduced to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation or other fees 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 or fees imposed 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, use, property, ad valorem and other forms of taxation or permit, impact, throughput and miscellaneous other fees. Imposition of any such taxes or fees may substantially reduce the cash available for distribution to our unitholders. For example, the state of Texas has instituted an income-based tax that results in an entity level tax for us. We are required to pay a Texas franchise tax of 1.0% of our gross margin that is apportioned to Texas in the prior year. The imposition of entity level taxes on us by any other state may 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

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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 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 a unitholder sells common 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, 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 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.

        To maintain the uniformity of the economic and tax characteristics of our common units, we have adopted 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.

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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 U.S. Treasury Department 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. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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, the unitholder 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, the unitholder 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 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 lending 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 and Class B 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 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, the Class A unitholders and Class B 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.

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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 technically 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. The IRS has recently announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership may be permitted to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

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.

53

ITEM 2.    Properties

        The following tables set forth certain information relating to our gas processing facilities, fractionation facilities, natural gas gathering systems, NGL pipelines, natural gas pipeline and crude oil pipeline as of and for the year ended December 31, 2011.

Gas Processing Facilities:

					Year ended December 31, 2011
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		228,300		82	%		654,000
Oklahoma:
Western Oklahoma processing plants(1)	Custer County, OK	2000		235,000		175,500		75	%		485,500
Northeast
Appalachia:
Kenova processing plant(2)	Wayne County, WV	1996		160,000		99,200		62	%		195,900
Boldman processing plant(2)	Pike County, KY	1991		70,000		41,600		59	%		47,300
Cobb processing plant	Kanawha County, WV	2005		65,000		31,900		49	%		74,300
Kermit processing plant(2)(3)	Mingo County, WV	2001		32,000		N/A		N/A			N/A
Langley processing plant(4)	Langley, KY	2000		175,000		133,200		76	%		357,000
Liberty
Marcellus Shale:
Houston processing plants(5)	Washington County, PA	2009		355,000		176,300		50	%		395,400
Majorsville processing plant(6)	Marshall County, WV	2010		270,000		147,600		55	%		300,600
Gulf Coast
Javelina processing plant(7)	Corpus Christi, TX	1989		142,000		113,300		80	%		892,300

(1)

A 75 MMcf/d cryogenic plant began operations in the fourth quarter of 2011, increasing the processing capacity.

(2)

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.

(3)

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.

(4)

The Langley processing plant was acquired February 1, 2011 (see Note 3 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K). The volume reported is the average daily rate for the days of operation.

(5)

A 200 MMcf/d cryogenic plant began operations in the second quarter of 2011, increasing the processing capacity.

(6)

A 135 MMcf/d cryogenic plant began operations in the second quarter of 2011, increasing the processing capacity.

(7)

Also includes fractionation capacity of 29,000 Bbl/d.

54

Fractionation Facilities:

					Year ended December 31, 2011
Facility	Location	Year of Initial Construction	Design Throughput Capacity		NGL Throughput		Utilization of Design Capacity
			(Bbl/d)		(Bbl/d)
Northeast
Appalachia:
Siloam fractionation plant	South Shore, KY	1957		24,000		20,300		85	%
Liberty
Marcellus Shale:
Houston(8)	Washington County, PA	2009		60,000		11,800		20	%

(8)

The fractionation facility at our Houston Complex was placed into service during the third quarter of 2011. Prior to the completion of the Houston fractionation facility, only propane was recovered and further fractionation of the remaining portion of the NGL stream was performed at the Siloam fractionation plant.

        Our Siloam facility has both above ground, pressurized NGL storage facilities, with usable capacity of two million gallons, and underground storage facilities, with usable capacity of ten 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 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. Our Houston facility has above ground NGL storage with a usable capacity of 3.8 million gallons and eight automated truck loading and unloading slots. We also have an additional 50 million gallons of NGL storage capacity that can be utilized by our Northeast and Liberty segments under a firm capacity agreement with a third party that expires 2018.

55

Natural Gas Gathering Systems:

					Year ended December 31, 2011
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		423,600		85	%
Oklahoma:
Western Oklahoma gathering system	Wheeler County, TX and Roger Mills, Ellis, Custer and Beckham Counties, OK	1998		405,000		237,900		59	%
Southeast Oklahoma gathering system	Hughes, Pittsburg and Coal Counties, OK	2006		550,000		511,900		93	%
Other Southwest:
Other Southwest gathering systems(9)	Various	Various		121,500		29,900		25	%
Liberty
Marcellus Shale:
Gas gathering system	Washington County, PA	2008		325,000		245,700		76	%

(9)

Excludes lateral pipelines where revenue is not based on throughput.

NGL Pipelines:

						Year ended December 31, 2011
Pipeline	Location	Year of Initial Construction		Design Throughput Capacity		NGL Throughput		Utilization of Design Capacity
				(Bbl/d)		(Bbl/d)
Northeast
Appalachia:
Langley to Siloam(10)	Langley, KY to South Shore, KY		1957		19,000		12,600		66	%
Southwest
East Texas:
East Texas liquid line	Panola County, TX		2005		25,000		15,600		62	%
Liberty
Marcellus Shale:
Majorsville to Houston	Washington County, PA		2010		43,400		7,200		17	%
Fort Beeler to Majorsville(11)	Marshall County, WV to Washington County, PA		2011		45,000		1,700		4	%

(10)

NGLs transported through the Langley to Ranger and Ranger to Kenova pipelines are combined with NGLs recovered at the Kenova facility. The volume reported for the Langley to Siloam pipeline represents the combined NGL stream.

(11)

The Fort Beeler to Majorsville pipeline was placed into service during the fourth quarter of 2011. The volume reported is the average daily rate for the days of operation.

56

Natural Gas Pipeline:

						Year ended December 31, 2011
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(12)	Coal County, OK to Bryan County, OK		2009		638,000		271,400		43	%

(12)

The Arkoma Connector Pipeline is a joint venture with Arkoma Pipeline Partners, LLC ("ArcLight"), an affiliate of ArcLight Capital Partners, LLC. One of our wholly-owned subsidiaries serves as the operator (see Note 4 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K).

Crude Oil Pipeline:

						Year ended December 31, 2011
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		10,300		17	%

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. Certain of our facilities, including our Siloam and Houston fractionation plants and several of our processing plants, 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

57

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, other than MarkWest Liberty Midstream, as collateral for borrowings under our Credit Facility.

ITEM 3.    Legal Proceedings

        We are subject to a variety of risks and disputes, and are a party to various legal and regulatory proceedings in the normal course of our business. We maintain insurance policies in amounts and with coverage and deductibles as we believe reasonable and prudent. However, we cannot be assured 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 and that none of these actions, either individually or in the aggregate, will have a material adverse effect on our financial condition, liquidity or results of operation.

        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 of the Partnership, 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. In March 2011, MarkWest received an order assessing a penalty solely against Equitable for count one of the NOPV in the amount of $0.5 million and assessing a penalty jointly and severally against MarkWest and Equitable for four of the other counts in the NOPV in the amount of $0.2 million. In March 2011, the parties filed separate petitions for reconsideration. In January 2012, the Agency issued an order that dismissed the penalty assessed solely against Equitable but retained the $0.2 million penalty assessed jointly and severally against MarkWest and Equitable. MarkWest did not appeal the Agency's decision and paid the entire penalty.

ITEM 4.    Mine Safety Disclosures

        Not applicable.

58

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 2011 and 2010:

	Unit Price
					Distributions Per Common Unit
Quarter Ended	High		Low				Declaration Date	Record Date	Payment Date
December 31, 2011	$	56.82	$	42.18	$	0.76	January 26, 2012	February 6, 2012	February 14, 2012
September 30, 2011.		50.06		39.00		0.73	October 18, 2011	November 7, 2011	November 14, 2011
June 30, 2011		51.70		42.80		0.70	July 21, 2011	August 1, 2011	August 12, 2011
March 31, 2011		48.50		40.80		0.67	April 21, 2011	May 2, 2011	May 13, 2011
December 31, 2010		43.51		35.70		0.65	January 27, 2011	February 7, 2011	February 14, 2011
September 30, 2010.		37.00		31.50		0.64	October 27, 2010	November 8, 2010	November 12, 2010
June 30, 2010		33.45		20.96		0.64	July 22, 2010	August 2, 2010	August 13, 2010
March 31, 2010		32.00		26.05		0.64	April 22, 2010	May 3, 2010	May 14, 2010
December 31, 2009		29.94		22.20		0.64	January 26, 2010	February 5, 2010	February 12, 2010

        As of February 17, 2012, there were approximately 177 holders of record of our common units.

Distributions of Available Cash

        Within 45 days after the end of each quarter, we distribute all of our "Available Cash" to unitholders of record on the applicable record date. We make distributions of "Available Cash" to all common and Class A unitholders, pro rata and we make distributions of Hydrocarbon Available Cash (as defined in our amended and restated partnership agreement) pro rata to common unitholders. Class B unitholders do not receive cash distributions. 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 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.

        Our ability to distribute available cash is contractually restricted by the terms of our credit agreement. Our credit agreement contains covenants requiring us to maintain certain financial ratios

59

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 agreement. 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 our creditors. We will distribute any remaining proceeds to the unitholders, which will include the holders of Class B units that convert upon liquidation, 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.

Securities Authorized for Issuance under Equity Compensation Plans

        The following table provides information as of December 31, 2011, regarding our common units that may be issued upon conversion of outstanding phantom units granted under all of our existing equity compensation plans that have been approved by security holders. There are no active plans that have not been approved by security holders.

	Number of securities to be issued upon exercise of outstanding options, warrants and rights(1)		Weighted average exercise price of outstanding options, warrants and rights(2)		Number of securities remaining available for future issuance under equity compensation plans
Equity compensation plans approved by security holders:
2008 Long-Term Incentive Plan		935,509	$	—		858,438

(1)

Includes 282,000 units that vest if we achieve various performance or market-based targets determined by the Compensation Committee of the Board. 141,000 of these performance based units vested in January 2012 and 141,000 units were forfeited.

(2)

Phantom units are granted with no exercise price.

Recent Sales of Unregistered Units

        The Partnership issued approximately 19,954,000 Class B Units to EMG as part of our acquisition of the non-controlling interest in MarkWest Liberty Midstream which was effective December 31, 2011. See Note 4 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of the acquisition of non-controlling interest.

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

        None.

60

ITEM 6.    Selected Financial Data

        The following table sets forth selected consolidated historical financial and operating data for MarkWest Energy Partners (dollars in thousands, except per unit amounts). 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,
	2011			2010			2009			2008			2007
Statement of Operations:
Revenue:
Revenue	$	1,534,434		$	1,241,563		$	858,635		$	1,060,662		$	845,727
Derivative (loss) gain(1)		(29,035	)		(53,932	)		(120,352	)		277,828			(159,970	)
Total revenue		1,505,399			1,187,631			738,283			1,338,490			685,757
Operating expenses:
Purchased product costs		682,370			578,627			408,826			615,902			487,892
Derivative loss related to purchased product costs(1)		52,960			27,713			68,883			22,371			15,192
Facility expenses		173,598			151,449			126,977			103,682			70,863
Derivative (gain) loss related to facility expenses(1)		(6,480	)		(1,295	)		(373	)		644			(14	)
Selling, general and administrative expenses		81,229			75,258			63,728			68,975			72,484
Depreciation		149,954			123,198			95,537			67,480			41,281
Amortization of intangible assets		43,617			40,833			40,831			38,483			16,672
Loss on disposal of property, plant and equipment		8,797			3,149			1,677			178			7,743
Accretion of asset retirement obligations		1,190			237			198			129			114
Impairment of goodwill and long-lived assets		—			—			5,855			36,351			356
Total operating expenses		1,187,235			999,169			812,139			954,195			712,583
Income (loss) from operations		318,164			188,462			(73,856	)		384,295			(26,826	)
Other income (expense):
(Loss) earnings from unconsolidated affiliates		(1,095	)		1,562			3,505			90			5,309
Impairment of unconsolidated affiliate		—			—			—			(41,449	)		—
Gain on sale of unconsolidated affiliate		—			—			6,801			—			—
Interest income		422			1,670			349			3,769			4,547
Interest expense		(113,631	)		(103,873	)		(87,419	)		(64,563	)		(39,435	)
Amortization of deferred financing costs and discount (a component of interest expense)		(5,114	)		(10,264	)		(9,718	)		(8,299	)		(2,983	)
Derivative gain related to interest expense(1)		—			1,871			2,509			—			—
Loss on redemption of debt		(78,996	)		(46,326	)		—			—			—
Miscellaneous income (expense), net(1)		144			1,189			2,459			(241	)		233
Income (loss) before provision for income tax		119,894			34,291			(155,370	)		273,602			(59,155	)
Provision for income tax expense (benefit):
Current		17,578			7,655			8,072			15,032			23,869
Deferred		(3,929	)		(4,466	)		(50,088	)		53,798			(48,518	)
Total provision for income tax		13,649			3,189			(42,016	)		68,830			(24,649	)
Net income (loss)		106,245			31,102			(113,354	)		204,772			(34,506	)
Net (income) loss attributable to non-controlling Interest		(45,550	)		(30,635	)		(5,314	)		3,301			(4,853	)
Net income (loss) attributable to the Partnership	$	60,695		$	467		$	(118,668	)	$	208,073		$	(39,359	)
Net income (loss) attributable to the Partnership's common unitholders per common unit(2)(3):
Basic	$	0.75		$	(0.01	)	$	(1.97	)	$	4.02		$	(1.72	)
Diluted	$	0.75		$	(0.01	)	$	(1.97	)	$	4.02		$	(1.72	)
Cash distribution declared per common unit(3)	$	2.750		$	2.560		$	2.560		$	2.059		$	0.703

61

	Year ended December 31,
	2011			2010			2009			2008			2007
Balance Sheet Data (at December 31):
Working capital	$	4,234		$	(43,296	)	$	13,536		$	51,237		$	21,932
Property, plant and equipment, net		2,864,307			2,319,024			1,981,644			1,569,525			830,809
Total assets		4,070,425			3,333,362			3,014,737			2,673,054			1,524,695
Total long-term debt		1,846,062			1,273,434			1,170,072			1,172,965			552,695
Total equity		1,502,067			1,458,566			1,309,553			1,148,155			563,974
Cash Flow Data:
Net cash flow provided by (used in):
Operating activities	$	414,698		$	312,328		$	223,101		$	226,995		$	133,237
Investing activities		(776,553	)		(485,936	)		(461,753	)		(909,265	)		(314,792	)
Financing activities		411,421			143,306			333,083			647,896			170,406
Other Financial Data:
Maintenance capital expenditures(4)	$	16,067		$	10,286		$	7,483		$	7,161		$	4,140
Growth capital expenditures(4)		535,214			448,382			479,140			568,137			312,499
Total capital expenditures	$	551,281		$	458,668		$	486,623		$	575,298		$	316,639

(1)

As discussed further in Note 6 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. 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,
	2011			2010			2009			2008			2007
Realized (loss) gain—revenue	$	(48,093	)	$	(33,560	)	$	87,289		$	(15,704	)	$	(15,901	)
Unrealized gain (loss)—revenue		19,058			(20,372	)		(207,641	)		293,532			(144,069	)
Realized (loss) gain—purchased product costs		(27,711	)		(21,909	)		(53,052	)		7,368			(8,829	)
Unrealized loss—purchased product costs		(25,249	)		(5,804	)		(15,831	)		(29,739	)		(6,363	)
Unrealized gain (loss)—facility expenses		6,480			1,295			373			(644	)		14
Realized gain—interest expense		—			2,380			2,000			—			—
Unrealized (loss) gain—interest expense		—			(509	)		509			—			—
Unrealized gain—miscellaneous income (expense), net		—			190			336			—			—
Total derivative (loss) gain	$	(75,515	)	$	(78,289	)	$	(186,017	)	$	254,813		$	(175,148	)

(2)

For the calculation of Net (loss) income attributable to the Partnership's common unitholders per common unit, see Note 23 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

(3)

All per unit data, where applicable, has been adjusted to give effect to the Merger.

(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 investment.

62

Operating Data

	Year ended December 31,
	2011		2010		2009		2008		2007
Southwest
East Texas gathering systems throughput (Mcf/d)		423,600		430,300		454,400		442,900		413,700
East Texas natural gas processed (Mcf/d)		228,300		233,100		246,600		189,300		175,400
East Texas NGL sales (gallons, in thousands)		238,700		245,800		245,800		193,500		179,600
Western Oklahoma gathering system throughput (Mcf/d)(1)		237,900		191,100		185,600		193,500		116,500
Western Oklahoma natural gas processed (Mcf/d)		175,500		134,700		148,000		105,300		104,000
Western Oklahoma NGL sales (gallons, in thousands)		177,200		134,100		126,900		79,400		87,500
Southeast Oklahoma gathering systems throughput (Mcf/d)		511,900		521,400		416,800		318,700		114,000
Southeast Oklahoma natural gas processed (Mcf/d)(2)		103,400		81,600		39,400		46,300		6,300
Southeast Oklahoma NGL sales (gallons, in thousands)		125,100		102,300		48,400		31,000		900
Arkoma Connector Pipeline throughput (Mcf/d)(3)		307,300		375,900		277,300		N/A		N/A
Other Southwest gathering system throughput (Mcf/d)(4)		29,900		39,500		57,600		69,400		67,400
Northeast(5)
Natural gas processed (Mcf/d)		305,900		188,700		194,600		202,200		200,200
NGLs fractionated (Bbl/d)(6)		20,300		20,700		18,300		12,400		10,800
Keep-whole sales (gallons, in thousands)		113,800		136,700		145,500		140,800		126,200
Percent-of-proceeds sales (gallons, in thousands)		130,300		120,300		99,900		54,000		43,800
Total NGL sales (gallons, in thousands)(7)		244,100		257,000		245,400		194,800		170,000
Crude oil transported for a fee (Bbl/d)		10,300		12,800		12,300		13,300		14,000
Liberty(8)
Natural gas processed (Mcf/d)		323,900		215,700		51,800		18,700		N/A
Gathering system throughput (Mcf/d)		245,700		142,200		53,500		18,700		N/A
NGLs fractionated (Bbl/d)(9)		11,800		4,200		1,100		N/A		N/A
NGL sales (gallons, in thousands)(10)		241,200		119,900		34,400		N/A		N/A
Gulf Coast
Refinery off-gas processed (Mcf/d)		113,300		118,600		120,200		122,900		114,500
Liquids fractionated (Bbl/d)		21,200		22,500		23,200		24,400		25,000
NGL sales (gallons excluding hydrogen, in thousands)		325,700		345,500		356,300		376,000		382,800

(1)

Includes natural gas gathered in Western Oklahoma and from the Granite Wash formation in the Texas Panhandle as management considers this one integrated area of operations.

(2)

The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma, our equity investment, or other third-party processors.

(3)

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

(4)

Excludes lateral pipelines where revenue is not based on throughput.

(5)

Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported are the average daily rates for the days of operation.

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(6)

Amount includes 3,900 barrels per day, 4,000 barrels per day and 1,500 barrels per day fractionated on behalf of Liberty for 2011, 2010 and 2009, respectively. Beginning in the fourth quarter of 2011, Siloam no longer fractionates NGLs on behalf of Liberty due to the operation of Liberty's fractionation facility that began in September 2011.

(7)

Represents sales at the Siloam fractionator. The total sales exclude approximately 59,200,000 gallons, 60,900,000 gallons, and 23,300,000 gallons sold by the Northeast on behalf of Liberty for 2011, 2010 and 2009, respectively. These volumes are included as part of NGLs sold at Liberty.

(8)

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

(9)

Amount includes all NGLs that were produced at the Liberty processing facilities and fractionated into purity products at our Liberty fractionation facility. Through August 2011, only propane was recovered at our Liberty facilities. In September 2011, Liberty's fractionation facility commenced operations and Liberty now has full fractionation capabilities.

(10)

Includes sale of all purity products fractionated at the Liberty facilities and sale of all unfractionated NGLs. Also includes the sale of purity products fractionated and sold at the Siloam facilities on behalf of Liberty.

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 Financial Data and our consolidated financial statements and accompanying notes included elsewhere in this report. Statements that are not historical facts are forward-looking statements. We use words such as "could," "may," "predict," "should," "expect," "hope," "continue," "potential," "plan," "intend," "anticipate," "project," "believe," "estimate" and similar expressions to identify forward-looking statements. These statements are based on current expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. Forward-looking statements are not guarantees and actual results could differ materially from those expressed or implied in the forward-looking statements as a result of a number of factors. We do not update publicly any forward-looking statement with new information or future events. Undue reliance should not be placed on forward-looking statements as many of these factors are beyond our ability to control or predict.

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 and fractionator in the Appalachian region.

Significant Financial and Other Highlights

        Significant financial and other highlights for the year ended December 31, 2011 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 increased approximately $143 million, or 30%, for the year ended December 31, 2011 compared to the same period in 2010. The increase is primarily due to higher commodity prices in 2011, expanding operations in the Liberty segment and increased volumes processed in the Southwest segment. The increase in segment income was partially offset by a $20 million decrease in net cash flow from the settlement of commodity derivative positions.

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•

We acquired the remaining 49% interest in MarkWest Liberty Midstream effective December 31, 2011 for approximately $998 million of cash, including transaction costs, and the issuance of approximately 19,954,000 unregistered Class B units valued at approximately $753 million.

•

We increased the borrowing capacity under our Credit Facility from $705 million to $900 million.

•

We received net proceeds of approximately $1.2 billion from public offerings of senior notes and redeemed $419 million aggregate principal amount of our 8.75% 2018 Senior Notes and $275 million aggregate principal amount of our 8.5% 2016 Senior Notes.

•

We received net proceeds of approximately $1.1 billion from public offerings of common units.

•

We entered into a new Utica Shale midstream joint venture to develop natural gas processing and NGL fractionation, transportation and marketing infrastructure in eastern Ohio beginning in 2012.

Impact of Business Combination on Comparability of Financial Results

        In reviewing our historical results of operations, investors should consider the impact of our business combinations, which fundamentally affect the comparability of our results of operations over the periods discussed.

        One business combination occurred in 2011 and is included in the results of operations from the acquisition date. The Langley Processing Facilities and Ranger Pipeline acquisition closed on February 1, 2011 for consideration of $230.7 million. As a result, eleven months of activity for the Langley Processing Facilities and Ranger Pipeline is reflected in the accompanying Consolidated Statements of Operations for the year ended December 31, 2011. The revenue and income before provision for income tax were approximately $21.8 million and $6.8 million, respectively, for the year ended December 31, 2011.

Results of Operations

Segment Reporting

        We classify our business in the following reportable segments: Southwest, Northeast, Liberty and Gulf Coast. We capture information in MD&A by geographical segment. Items below Income (loss) 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 segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests.

Year Ended December 31, 2011 Compared to Year Ended December 31, 2010

        The tables below present financial information, as evaluated by management, for the reported segments for the years ended December 31, 2011 and 2010. The information includes net operating margin, a non-GAAP financial measure. For a reconciliation of net operating margin to Income (loss) from operations, the most comparable GAAP financial measure, see Our Contracts discussion in Item 1. Business.

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Southwest

	Year ended December 31,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	935,513	$	665,768	$	269,745			41	%
Purchased product costs		506,911		308,960		197,951			64	%
Net operating margin		428,602		356,808		71,794			20	%
Facility expenses		82,761		81,772		989			1	%
Portion of operating income attributable to non-controlling interests		5,431		6,440		(1,009	)		(16	)%
Operating income before items not allocated to segments	$	340,410	$	268,596	$	71,814			27	%

        Segment Revenue.    Segment revenue increased primarily due to higher commodity prices for all areas of the segment, higher condensate revenue and an overall increase in the volume of natural gas processed and NGLs produced in Oklahoma, due in part to the expansion of the processing facilities.

        Purchased Product Costs.    Purchased product costs increased primarily due to higher commodity prices and an increase in the volume of natural gas processed and NGLs produced in Oklahoma.

Northeast

	Year ended December 31,
	2011		2010		$ Change			% Change
	(in thousands)
Segment revenue	$	268,884	$	384,724	$	(115,840	)		(30	)%
Purchased product costs		91,612		252,827		(161,215	)		(64	)%
Net operating margin		177,272		131,897		45,375			34	%
Facility expenses		27,126		19,513		7,613			39	%
Operating income before items not allocated to segments	$	150,146	$	112,384	$	37,762			34	%

        Segment Revenue.    Segment revenue decreased primarily due to a contract change related to the Langley Acquisition. Subsequent to the Langley Acquisition, we continue to market the NGLs related to natural gas processed at the Langley Processing Facilities; however we are acting as an agent and therefore record revenue net of purchase product costs. Prior to the contract change, we were acting as the principal. Segment revenue also decreased due to a decrease in volumes processed under keep-whole terms primarily due to the required repairs of a significant third-party transmission pipeline feeding our Kenova plant. The repairs of the transmission pipeline were completed in the fourth quarter of 2011, after which volumes returned to normal levels.

        Purchased Product Costs.    Purchased product costs decreased due to the contract change related to the Langley Acquisition discussed in the Segment Revenue section above. In addition, purchased product costs decreased as a percentage of revenue due to an increase in the spread between NGL and natural gas prices.

        Facility Expenses.    Facility expenses increased primarily due to the Langley Acquisition on February 1, 2011.

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Liberty

	Year ended December 31,
	2011		2010		$ Change		% Change
	(in thousands)
Segment revenue	$	248,949	$	105,911	$	143,038		135	%
Purchased product costs		83,847		16,840		67,007		398	%
Net operating margin		165,102		89,071		76,031		85	%
Facility expenses		34,913		24,028		10,885		45	%
Portion of operating income attributable to non-controlling interests		63,731		26,126		37,605		144	%
Operating income before items not allocated to segments	$	66,458	$	38,917	$	27,541		71	%

        Segment Revenue.    Segment revenue increased due to ongoing expansion of the Liberty operations and higher NGL prices. Segment revenue increased approximately $43.7 million related to gathering and processing fees and approximately $89.0 million related to NGL product sales.

        Purchased Product Costs.    Purchased product costs increased primarily due to the purchase and sale of propane from certain producers at market prices less a discount, which began in the second half of 2010.

        Facility Expenses.    Facility expenses increased due to costs related to the expansion of Liberty operations. The increase in costs related to expansion were partially offset by a reduction in compressor rental expense as compressors were purchased in the first quarter of 2010 and by environmental and remediation costs incurred in 2010 that did not recur in 2011.

        Portion of Operating Income Attributable to Non-controlling Interests.    Portion of operating income attributable to non-controlling interests represents M&R's interest in net operating income of MarkWest Liberty Midstream. The increase is the result of ongoing expansion of the Liberty operations, as well as M&R's interest increasing from 40% to 49% effective January 1, 2011. Due to our acquisition of M&R's interest effective December 31, 2011, going forward there will be no operating income allocated to non-controlling interest.

Gulf Coast

	Year ended December 31,
	2011		2010		$ Change		% Change
	(in thousands)
Segment revenue	$	96,473	$	85,160	$	11,313		13	%
Purchased product costs		—		—		—		N/A
Net operating margin		96,473		85,160		11,313		13	%
Facility expenses		38,436		33,337		5,099		15	%
Operating income before items not allocated to segments	$	58,037	$	51,823	$	6,214		12	%

        Segment Revenue.    Segment revenue increased primarily due to increases in commodity prices and the revenues earned from the SMR which did not begin until March 2010. The increases were partially offset by a decrease in volumes due to increased maintenance activities of our refinery customers.

        Facility Expenses.    Facility expenses increased primarily due to operating expenses of the SMR which began in March 2010.

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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, 2011 and 2010. 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,
	2011			2010			$ Change			% Change
	(in thousands)
Total segment revenue	$	1,549,819		$	1,241,563		$	308,256			25	%
Derivative loss not allocated to segments		(29,035	)		(53,932	)		24,897			(46	)%
Revenue deferral adjustment		(15,385	)		—			(15,385	)		N/A
Total revenue	$	1,505,399		$	1,187,631		$	317,768			27	%
Operating income before items not allocated to segments	$	615,051		$	471,720		$	143,331			30	%
Portion of operating income attributable to non-controlling interests		69,162			32,566			36,596			112	%
Derivative loss not allocated to segments		(75,515	)		(80,350	)		4,835			(6	)%
Revenue deferral adjustment		(15,385	)		—			(15,385	)		N/A
Compensation expense included in facility expenses not allocated to segments		(1,781	)		(1,890	)		109			(6	)%
Facility expenses adjustments		11,419			9,091			2,328			26	%
Selling, general and administrative expenses		(81,229	)		(75,258	)		(5,971	)		8	%
Depreciation		(149,954	)		(123,198	)		(26,756	)		22	%
Amortization of intangible assets		(43,617	)		(40,833	)		(2,784	)		7	%
Loss on disposal of property, plant and equipment		(8,797	)		(3,149	)		(5,648	)		179	%
Accretion of asset retirement obligations		(1,190	)		(237	)		(953	)		402	%
Income from operations		318,164			188,462			129,702			69	%
(Loss) earnings from unconsolidated affiliates		(1,095	)		1,562			(2,657	)		(170	)%
Interest income		422			1,670			(1,248	)		(75	)%
Interest expense		(113,631	)		(103,873	)		(9,758	)		9	%
Amortization of deferred financing costs and discount (a component of interest expense)		(5,114	)		(10,264	)		5,150			(50	)%
Derivative gain related to interest expense		—			1,871			(1,871	)		(100	)%
Loss on redemption of debt		(78,996	)		(46,326	)		(32,670	)		71	%
Miscellaneous income, net		144			1,189			(1,045	)		(88	)%
Income before provision for income tax	$	119,894		$	34,291		$	85,603			250	%

        Derivative Loss Not Allocated to Segments.    Unrealized gain from the change in fair value of our derivative instruments was $0.3 million in 2011 compared to an unrealized loss of $24.9 million in 2010. Realized loss from the settlement of our derivative instruments was $75.8 million in 2011 compared to $55.5 million in 2010. The total change of $4.8 million is due mainly to volatility in commodity prices when comparing prices in 2011 with prices in 2010.

        Revenue Deferral Adjustment.    Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we expect to perform a similar level of service for the entire term;

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therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore the impact of the revenue deferrals is excluded for segment reporting purposes. For the year ended December 31, 2011, approximately $7.2 million and $8.2 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. There were no revenue deferral adjustments in 2010 or 2009. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

        Facility Expenses Adjustments.    Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR, which is included in facility expenses for the purposes of evaluating the performance of the Gulf Coast segment. The increase is due to a full year of interest expense related to the SMR in 2011 compared to approximately nine months of SMR interest expense in 2010.

        Selling, General and Administrative.    Selling, general and administrative expenses increased primarily due to higher labor, benefits and professional services necessary to support the overall growth of our operations.

        Depreciation.    Depreciation increased due to additional projects completed and placed into service during 2010 and 2011, as well as the Langley Acquisition.

        Loss on Disposal of Property, Plant and Equipment.    Loss relates to disposals of miscellaneous equipment, primarily in the Northeast segment.

        Interest Expense.    Interest expense increased primarily due to increased borrowings under our Credit Facility and a net increase in our borrowings resulting from our senior notes offerings and related redemptions in order to fund our capital plan. Interest expense also increased approximately $1.8 million related to payments of the liability associated with the SMR Transaction that began in March 2010.

        Amortization of Deferred Financing Costs and Discount.    Amortization of deferred financing costs and discount decreased primarily due to the write-off of the unamortized discount associated with our 6.875% senior notes due 2014 ("2014 Senior Notes"), which were redeemed in the fourth quarter of 2010. The decrease was partially offset by the amortization of deferred financing costs related to notes issued in the fourth quarter of 2010 and 2011.

        Loss on Redemption of Debt.    Loss on redemption of debt relates to the redemption of approximately $275 million of our 2016 Senior Notes and approximately $419 million of our 2018 Senior Notes. Approximately $7.6 million relates to the non-cash write-off of the unamortized discount and deferred finance costs associated with these senior notes and approximately $71.4 million relates to the payment of the related call and tender premiums. See Note 16 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further details.

        Derivative Gain Related to Interest Expense.    Derivative gain related to interest expense reflects changes in the fair value of interest rate swaps which we used to manage the interest rate risk associated with the fair value of our fixed rate borrowings. The interest rate swaps effectively converted 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 6 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 for the year ended December 31, 2011 was $13.7 million. Refer to Note 22 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.

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        MarkWest Hydrocarbon pays tax based on enacted and applicable corporate and state tax rates on its pro-rata share of income and deductions allocated to the Class A units by the Partnership.

        The current provision for income tax was $17.6 million for the year ended December 31, 2011. Approximately $16.0 million is attributable to MarkWest Hydrocarbon, Inc. Of this amount, $8.5 million is attributable to MarkWest Hydrocarbon's ownership of Class A units, and the remaining expense of $7.5 million is related to the Corporation's NGL marketing business. The remaining $1.6 million is related to taxes payable by the Partnership associated with the Texas Margin tax and Michigan Business Taxes. We expect the current provision for income tax to increase in 2012 due to expected increases in net income from MarkWest Hydrocarbon's NGL sales as well as additional income allocated to MarkWest Hydrocarbon as a result of its ownership of Class A units due to increases in earnings and additional income expected to be allocated by the Partnership in accordance with the Internal Revenue Code.

        If the Partnership was to cause the Class A units to be disposed of (through sale or otherwise) or retired as a class of units, MarkWest Hydrocarbon would pay income taxes on the recognized gain to the full extent of the proceeds received or implied as received in excess of its tax basis. We currently do not have a plan to dispose of Class A units. During 2011, the Partnership determined it had understated its deferred tax liability related to its investment in consolidated subsidiaries for timing differences created as a result of items charged or credited directly to equity. We recorded a deferred tax liability of $90.8 million, of which $77.5 million related to prior years. See Note 22 to the consolidated financial statements.

Year Ended December 31, 2010 Compared to Year Ended December 31, 2009

        The tables below present financial information, as evaluated by management, for the reported segments for the years ended December 31, 2010 and 2009. The information includes net operating margin, a non-GAAP financial measure. For a reconciliation of net operating margin to Income (loss) from operations, the most comparable GAAP financial measure, see Our Contracts discussion in Item 1. Business.

Southwest

	Year ended December 31,
	2010		2009		$ Change		% Change
	(in thousands)
Segment revenue	$	665,768	$	492,369	$	173,399		35	%
Purchased product costs		308,960		221,021		87,939		40	%
Net operating margin		356,808		271,348		85,460		31	%
Facility expenses		81,772		73,621		8,151		11	%
Portion of operating income attributable to non-controlling interests		6,440		2,613		3,827		146	%
Operating income before items not allocated to segments	$	268,596	$	195,114	$	73,482		38	%

        Segment Revenue.    Segment revenue increased primarily due to higher NGL prices. Segment revenue from NGL and condensate sales increased approximately $149.3 million across the segment, partially offset by a $2.5 million decrease in revenue from natural gas sales. An increase in volumes from a large producer in our Woodford Shale operations also contributed to the increase in product sales. Gathering, treating, and compression fee revenue also increased $23.6 million due to a full year of the Arkoma Connector Pipeline operations that began in mid-July 2009 and higher volumes in the

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Woodford Shale and Stiles Ranch. The increase in segment revenue was partially offset by a decrease in gathered volumes in the Foss Lake, East Texas and Other Southwest areas and a change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas. The decline in gathered volumes in these conventional natural gas formations may continue until natural gas prices improve.

        Purchased Product Costs.    Purchased product costs increased primarily due to higher commodity prices and increased volumes in certain areas, which was partially offset by a decrease in plant inlet volumes in the Foss Lake, East Texas and Other Southwest areas and a change from a gas purchase contract to a gas gathering contract with a significant producer in the Other Southwest areas.

        Facility Expenses.    Facility expenses increased primarily due to higher operating expenses in Southeast Oklahoma resulting from the commencement of operations of the Arkoma Connector Pipeline in mid-July 2009 and the increased volumes primarily in the Woodford Shale and Stiles Ranch gathering systems. The increase was partially offset by a reduction in repairs and maintenance expense related to environmental costs in 2009 in East Texas that did not recur in 2010.

        Portion of Operating Income Attributable to Non-controlling Interests.    Portion of operating income attributable to non-controlling interests represents our partners' share in net operating income of MarkWest Pioneer and Wirth Gathering Partnership. The increase resulted from the Arkoma Connector Pipeline being placed in service in mid-July 2009.

Northeast

	Year ended December 31,
	2010		2009		$ Change			% Change
	(in thousands)
Segment revenue	$	384,724	$	260,529	$	124,195			48	%
Purchased product costs		252,827		175,326		77,501			44	%
Net operating margin		131,897		85,203		46,694			55	%
Facility expenses		19,513		20,339		(826	)		(4	)%
Operating income before items not allocated to segments	$	112,384	$	64,864	$	47,520			73	%

        Segment Revenue.    Segment revenue increased primarily due to higher commodity prices realized on NGL sales, as well as an increase in volumes from a significant customer under a percent-of-proceeds arrangement. The segment revenue increases were partially offset by a decrease in volumes processed under keep-whole terms primarily due to the required repairs of a significant transmission pipeline feeding our Kenova plant. The transmission pipeline is scheduled to be repaired in mid 2011 after which we expect volumes to return to normal levels.

        Purchased Product Costs.    Purchased product costs increased due to higher prices for the natural gas that is purchased to satisfy the keep-whole arrangements, as well as the overall increase in volumes.

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Liberty

	Year ended December 31,
	2010		2009		$ Change		% Change
	(in thousands)
Segment revenue	$	105,911	$	47,968	$	57,943		121	%
Purchased product costs		16,840		12,479		4,361		35	%
Net operating margin		89,071		35,489		53,582		151	%
Facility expenses		24,028		16,268		7,760		48	%
Portion of operating income attributable to non-controlling interests		26,126		6,637		19,489		294	%
Operating income before items not allocated to segments	$	38,917	$	12,584	$	26,333		209	%

        Segment Revenue.    Segment revenue increased due to ongoing expansion of the Liberty operations and higher NGL prices. Segment revenue increased approximately $35.8 million related to gathering fees and gathering system lease income and approximately $24.6 million related to NGL product sales.

        Purchased Product Costs.    Purchased product costs increased primarily due to the purchase of product from certain producers. During 2010, the Liberty segment purchased stored NGLs from producers monthly, whereas prior to this arrangement the Liberty segment did not purchase any NGLs and acted solely as the producers' agent providing processing, storage and marketing services. The increase was partially offset by the purchased product costs incurred in 2009 related to an interim plant that ceased operations in January 2010.

        Facility Expenses.    Facility expenses increased primarily due to the ongoing expansion of the Liberty operations, which includes the start-up of the Majorsville processing plant in the third quarter of 2010. The increase in facility expenses was partially offset by a decrease in compressor rental expense as we have purchased certain compressors that had been leased.

        Portion of Operating Income Attributable to Non-controlling Interests.    Portion of operating income attributable to non-controlling interests represents M&R's 40% interest in net operating income of MarkWest Liberty Midstream. The increase is the result of the formation of the joint venture on February 27, 2009 and the ongoing expansion of the Liberty operations.

Gulf Coast

	Year ended December 31,
	2010		2009		$ Change		% Change
	(in thousands)
Segment revenue	$	85,160	$	57,769	$	27,391		47	%
Purchased product costs		—		—		—		N/A
Net operating margin		85,160		57,769		27,391		47	%
Facility expenses		33,337		16,094		17,243		107	%
Operating income before items not allocated to segments	$	51,823	$	41,675	$	10,148		24	%

        Segment Revenue.    Segment revenue increased primarily due to $15.3 million related to the SMR and higher commodity prices. See Note 5 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of the SMR.

        Facility Expenses.    Facility expenses increased primarily due to $14.7 million of SMR operating expenses and increased utilities and chemicals expense.

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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, 2010 and 2009. 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,
	2010			2009			$ Change			% Change
	(in thousands)
Total segment revenue	$	1,241,563		$	858,635		$	382,928			45	%
Derivative loss not allocated to segments		(53,932	)		(120,352	)		66,420			(55	)%
Total revenue	$	1,187,631		$	738,283		$	449,348			61	%
Operating income before items not allocated to segments	$	471,720		$	314,237		$	157,483			50	%
Portion of operating income attributable to non-controlling interests		32,566			9,250			23,316			252	%
Derivative loss not allocated to segments		(80,350	)		(188,862	)		108,512			(57	)%
Compensation expense included in facility expenses not allocated to segments		(1,890	)		(1,032	)		(858	)		83	%
Facility expenses adjustments		9,091			377			8,714			2,311	%
Selling, general and administrative expenses		(75,258	)		(63,728	)		(11,530	)		18	%
Depreciation		(123,198	)		(95,537	)		(27,661	)		29	%
Amortization of intangible assets		(40,833	)		(40,831	)		(2	)		0	%
Loss on disposal of property, plant and equipment		(3,149	)		(1,677	)		(1,472	)		88	%
Accretion of asset retirement obligations		(237	)		(198	)		(39	)		20	%
Impairment of long-lived assets		—			(5,855	)		5,855			(100	)%
Income (loss) from operations		188,462			(73,856	)		262,318			(355	)%
Earnings from unconsolidated affiliates		1,562			3,505			(1,943	)		(55	)%
Gain on sale of unconsolidated affiliate		—			6,801			(6,801	)		(100	)%
Interest income		1,670			349			1,321			379	%
Interest expense		(103,873	)		(87,419	)		(16,454	)		19	%
Amortization of deferred financing costs and discount (a component of interest expense)		(10,264	)		(9,718	)		(546	)		6	%
Derivative gain related to interest expense		1,871			2,509			(638	)		(25	)%
Loss on redemption of debt		(46,326	)		—			(46,326	)		N/A
Miscellaneous income, net		1,189			2,459			(1,270	)		(52	)%
Income (loss) before provision for income tax	$	34,291		$	(155,370	)	$	189,661			(122	)%

        Derivative Loss Not Allocated to Segments.    Unrealized loss from the mark-to-market of our derivative instruments was $24.9 million in 2010 compared to $223.1 million in 2009. Realized loss from the settlement of our derivative instruments was $55.5 million in 2010 compared to realized gain of $34.2 million in 2009. The total change of $108.5 million is due mainly to volatility in commodity prices when comparing prices in 2010 with 2009. Realized gains in 2009 also include net gains of $15.2 million due to the early settlement of certain positions as discussed in Note 6 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

        Facility Expenses Adjustments.    Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR

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which is included in facility expenses for the purposes of evaluating the performance of the Gulf Coast segment.

        Selling, General and Administrative Expenses.    Selling, general and administrative expenses increased primarily due to higher share-based compensation expense related to the January 2010 unrestricted unit grant, as well as increases in headcount, short-term incentive compensation, insurance and corporate office rent. These increases were partially offset by a decrease in professional services expense.

        Depreciation.    Depreciation increased due to depreciation on additional projects completed during 2010 and 2009.

        Impairment of 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.

        Gain on Sale of Unconsolidated Affiliate.    During the year ended December 31, 2009, we sold our equity investment in Starfish. See Note 5 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion.

        Interest Expense.    Interest expense increased primarily due to additional borrowings in May 2009 and the net increase in our borrowings resulting from our 2020 Senior Notes offering and related redemption of our 2014 Senior Notes. Interest expense of $7.1 million related to the SMR also contributed to the increase.

        Loss on Redemption of Debt.    Loss on redemption of debt relates to the redemption of $375 million of our 2014 Senior Notes in the fourth quarter of 2010. Approximately $36.6 million relates to the non-cash write-off of the unamortized discount and deferred finance costs associated with these senior notes and approximately $9.7 million relates to the payment of the related call and tender premiums. See Note 16 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further details.

        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 used to manage the interest rate risk associated with the fair value of our fixed rate borrowings. The interest rate swaps effectively converted 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 6 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further details.

Liquidity and Capital Resources

        Our primary strategy is to expand our asset base through organic growth projects and acquisitions that are accretive to our cash available for distribution per common unit.

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        Our 2011 capital expenditures and our 2012 capital plan are summarized in the table below (in millions):

	2012 Full Year Plan						Actual
							Year ended December 31, 2011
	Low			High
Consolidated growth capital	$	1,050		$	1,500		$	535
Liberty joint venture partner's share of growth capital		—			—			(130	)
Utica joint venture partner's estimated share of growth capital		(150	)		(200	)		—
Partnership share of growth capital		900			1,300			405
Langley Acquisition		—			—			231
Partnership share of growth capital and acquisition		900			1,300			636
Consolidated maintenance capital	$	20		$	20		$	16

        In addition to the capital expenditures in the above table, we spent approximately $998 million of cash, including transaction costs, and issued approximately 19,954,000 Class B units with a value of approximately $753 million for the purchase of the 49% interest in MarkWest Liberty Midstream from EMG.

        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, our Credit Facility and access to debt and equity markets, both public and private. We may also consider the use of alternative financing strategies such as entering into additional joint venture arrangements.

        Management believes that expenditures for our currently planned capital projects will be funded with cash flows from operations, current cash balances, contributions by our joint venture partners, our current borrowing capacity under the Credit Facility, additional long-term borrowings and proceeds from equity offerings. 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, 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 17, 2012, our credit ratings were Ba2 with a Stable outlook by Moody's Investors Service, BB with a Stable outlook by Standard & Poor's, which both reflect upgrades during 2011, and BB with a Stable outlook by Fitch Ratings. 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.

Credit Facility

        On December 29, 2011, we amended our Credit Facility to increase the borrowing capacity to $900 million and to reset the uncommitted accordion feature to $250 million, providing us with the additional financial flexibility to continue to execute our growth strategy. Earlier in 2011, we had amended the Credit Facility to reduce the interest rates and extend the maturity date to September 2016. See Note 16 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further details of our Credit Facility.

        As of February 17, 2012, we had no borrowings outstanding and $22.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $877.7 million available for borrowing.

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Senior Notes Offerings and Tender Offers

        During 2011, we completed a public offering for $500 million in aggregate principal amount of 6.5% senior notes due in August 2021 ("2021 Senior Notes") and a public offering for $700 million in aggregate principal amount of 6.25% senior notes due in June 2022 ("2022 Senior Notes"). A portion of the $1.2 billion combined net proceeds from these offerings was used to repurchase $275 million aggregate principal amount of 8.5% senior notes due in July 2016 and approximately $419 million aggregate principal amount of 8.75% senior notes due in April 2018, with the remainder used to provide additional capital for general partnership purposes.

        As of December 31, 2011, we had four series of senior notes outstanding: $81 million in aggregate principal issued in April and May 2008 and due April 2018; $500 million in aggregate principal issued in November 2010 and due November 2020; $500 million in aggregate principal issued in February and March 2011 and due August 2021; and $700 million aggregate principal issued in October 2011 and due June 2022 (altogether "Senior Notes"). For further discussion of the Senior Notes and the accounting impacts, see Note 16 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.The Credit Facility and indentures governing the Senior Notes limit the activity of the Partnership and its restricted subsidiaries. The Credit Facility and indentures place limits on the ability of the Partnership and its restricted subsidiaries 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 the Partnership's restricted subsidiaries to pay dividends or distributions, make loans or transfer property to the Partnership; engage in transactions with the Partnership's affiliates; sell assets, including equity interests of the Partnership's 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 Credit Facility limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. Under the Credit Facility, neither we nor the bank can require margin calls for outstanding derivative positions. As of February 17, 2012, all of our derivative positions 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.

Equity Offerings

        On December 19, 2011, we completed a public offering of 10.0 million newly issued common units representing limited partner interests. On January 13, 2012, we issued an additional 0.7 million units pursuant to the underwriters' exercise of their option to purchase additional common units. The total net proceeds, including the exercise of the underwriters' option, were approximately $559 million and were used to partially fund the cash consideration for the acquisition of the 49% non-controlling interest in MarkWest Liberty Midstream. We completed three additional public offerings earlier in 2011. In total, we issued 23.2 million common units and received net proceeds of approximately $1.1 billion. Refer to Note 17 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of the accounting treatment of the common unit offerings.

Utica Shale Joint Venture

        Effective January 1, 2012, we and EMG Utica, LLC executed agreements to form the Utica Joint Venture, operated through MarkWest Utica EMG, to develop significant natural gas processing and NGL fractionation, transportation and marketing infrastructure in Eastern Ohio beginning in 2012.

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        Under the terms of the agreements, we will make an initial contribution to MarkWest Utica EMG in a nominal amount in exchange for a 60% membership interest in MarkWest Utica EMG, and EMG Utica will make an initial contribution in a nominal amount and will agree to contribute to MarkWest Utica EMG $350 million in cash on an as needed basis (the "Initial EMG Contribution") in exchange for a 40% membership interest in MarkWest Utica EMG. Following the funding of the Initial EMG Contribution, either (i) EMG Utica will fund, as needed, all capital required to develop projects within the Utica Joint Venture until such time as EMG Utica's total investment balance reaches $500 million (the "Minimum EMG Investment") or (ii) following the Initial EMG Contribution but prior to the first capital call requiring funds in excess of the Initial EMG Contribution, we will have the one time right to elect to fund 60% of all capital required to develop projects within the Utica Joint Venture until such time as EMG Utica's total investment balance equals the Minimum EMG Investment and EMG Utica will be required to fund the remaining 40% of all such capital. Once EMG Utica has funded capital equal to the Minimum EMG Investment, we will be required to fund, as needed, 100% of all capital required to develop projects within the Utica Joint Venture until such time as the total investment balances of us and EMG Utica are in the ratio of 60% and 40%, respectively (such time being referred to as the "First Equalization Date").

        Following the First Equalization Date, we shall have the right to elect to continue to fund up to 100% of any additional capital required until such time as the investment balances of us and EMG Utica are in the ratio of 70% and 30%, respectively (such time being referred to as the "Second Equalization Date"). To the extent we do not fully exercise such right at any time prior to the Second Equalization Date, EMG Utica shall have the right, but not the obligation, to contribute such additional capital that is requested and that is not contributed by us. After the Second Equalization Date, EMG Utica shall have the right, but not the obligation, to maintain a 30% interest in MarkWest Utica EMG by funding 30% of any additional required capital.

Liquidity Risks and Uncertainties

        Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions depends upon our future operating performance. That, in turn, may be affected by prevailing economic conditions in our industry, as well as financial, business and other factors, some of which are beyond our control. Although NGL prices increased throughout 2010 and 2011, our operating performance could be negatively impacted if the increases in NGL prices are not sustained. Natural gas prices remained at low levels during 2010 and decreased further during the second half of 2011. Although low natural gas prices, combined with high and increasing NGL prices increase our earnings under keep-whole contracts in the short term, our long-term earnings could be adversely impacted, particularly from areas dependant on dry gas volumes, if the low natural gas prices do not increase resulting in decreased drilling and production from producers. Additionally, legislation currently being written and new legislation recently enacted by Congress could limit our ability to execute our hedging strategy, which would increase our exposure to adverse changes in commodity prices.

Cash Flow

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

	Year ended December 31,
	2011			2010			Change
Net cash provided by operating activities	$	414,698		$	312,328		$	102,370
Net cash used in investing activities		(776,553	)		(485,936	)		(290,617	)
Net cash provided by financing activities		411,421			143,306			268,115

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        Net cash provided by operating activities increased primarily due to a $143.3 million increase in operating income, excluding derivative gains and losses, in our operating segments and an increase in operating cash flows resulting from changes in working capital, which was partially offset by a $20.3 million decrease in net cash flow from the settlement of commodity derivative positions.

        Net cash used in investing activities increased primarily due to the $230.7 million Langley Acquisition.

        Net cash provided by financing activities increased primarily due to:

•

$953.2 million increase in proceeds from public equity offerings, and

•

$505.4 million increase in net borrowings.

        These increases were partially offset by:

•

$997.6 million used to acquire EMG's interest in MarkWest Liberty Midstream,

•

$31.9 million decrease in cash contributions received from our joint venture partners,

•

$60.7 million increase in distributions to non-controlling interest holders due to the increased cash flow from MarkWest Liberty Midstream,

•

$61.6 million increase in premiums paid for the redemption of our 2016 Senior Notes and 2018 Senior Notes, and

•

$37.3 million increase in distributions to common unitholders due to additional units outstanding and growth in the per unit distribution.

Total Contractual Cash Obligations

        A summary of our total contractual cash obligations as of December 31, 2011, is as follows (in thousands):

	Payment Due by Period
Type of obligation	Total Obligation		Due in 2012		Due in 2013 - 2014		Due in 2015 - 2016		Thereafter
Long-term debt	$	1,847,112	$	—	$	—	$	66,000	$	1,781,112
Interest payments on long-term debt(1)		1,131,969		119,737		239,475		238,815		533,942
Operating leases and long-term storage agreement(2)		59,383		10,299		16,481		14,940		17,663
Purchase obligations(3)		192,382		180,971		11,411		—		—
Natural gas purchase obligations(4)		351,987		26,470		53,735		65,526		206,256
SMR Liability(5)		317,089		17,412		34,824		34,824		230,029
Other long-term liabilities reflected on the Consolidated Balance Sheets:
Asset retirement obligation(6)		6,818		—		—		—		6,818
Total contractual cash obligations	$	3,906,740	$	354,889	$	355,926	$	420,105	$	2,775,820

(1)

Assumes that our outstanding borrowing at December 31, 2011 remain outstanding until their respective maturity dates and we incur interest at 4.0% on the Credit Facility, 8.75% on the 2018 Senior Notes, 6.75% on the 2020 Senior Notes, 6.5% on the 2021 Senior Notes and 6.25% on the 2022 Senior Notes.

(2)

Amounts relate primarily to a long-term propane storage agreement and our office and vehicle 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

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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 Northeast segment. 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 6 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 a product supply agreement (see Note 18 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K).

(6)

Excludes estimated accretion expense of $18.5 million. The total amount to be paid is approximately $25.3 million.

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, 2011, 2010 or 2009. 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 expect to 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

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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
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 discounted future cash flows. The key assumptions include contract renewals, historical volumes, current and future capacity of the gathering system, pricing volatility and the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. We consider alternative methods of amortization when the intangibles assets are initially recorded, however have previously determined that alternative amortization methods do not create material differences in amortization expense each year and therefore concluded straight-lining methodology to be appropriate. 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.	If the actual results differ significantly from the assumptions used to determine the fair value and economic lives of intangible assets, the carrying value of the intangible asset may be over/understated resulting in an over/understatement of amortization expense as the over/understatement of the intangible assets would create an under/overstatement of other assets (i.e. goodwill).

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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 certain events have taken place that indicate that the carrying value may not be recoverable from the expected undiscounted future cash flows. Qualitative and quantitative information is reviewed in order to determine if a triggering event has occurred or an impairment indicator exists. If we determine that a triggering event has occurred we would complete a full impairment analysis. If we determine that the carrying value of an asset group is not recoverable, a loss is recorded for the difference between the fair value and the carrying value. We evaluate our 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.	Management considers the volume of reserves dedicated to be processed by 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.	As of December 31, 2011, there were no indicators of impairment for any of our asset groups. A significant variance in any of the assumptions or factors used to estimate future cash flows could result in the impairment of an asset. A 10% decrease in the estimated future cash flows used in our impairment analysis would indicate a potential impairment for asset groups with a total carrying value of approximately $60 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 identifiable 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. The first step of the evaluation is a qualitative analysis to determine if it is "more likely than not" that the carrying value of a reporting unit with goodwill exceeds its fair value. The additional quantitative steps in the goodwill impairment test are only performed if we determine that it is more likely than not that the carrying value is greater than the fair value.	If a quantitative analysis is deemed to be required, 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. For the current year qualitative analysis, we analyzed the changes in the assumptions above in light of current economic conditions to determine if it was more likely than not that impairment exists. We looked at factors that include changes in the forecasted operating income and volumes for the two reporting units with goodwill, changes in the commodity price environment, changes in our per unit market value and changes in the our peers market value, and changes in industry EBITDA multiples. Management is 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 acquisitions involved estimating the fair value of the reporting units and allocating the purchase price for each acquisition to each reporting unit. Goodwill is then calculated for each reporting unit as the excess of the allocated purchase price over the estimated fair value of the net assets.	As a result of the goodwill impairment testing completed in 2011, we recorded no impairment expense. There were no indicators that it was more likely than not that the carrying value of a reporting unit exceed its fair value, based on the qualitative analysis performed.

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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 investment in Centrahoma 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 assessment requires us to apply judgment in estimating future cash flows from Centrahoma. The primary estimates include the expected volumes to be processed by Centrahoma, the terms of the related processing agreements, and future commodity prices. We determined that there were no material events or changes in circumstances that would indicate an other-than-temporary loss in value has occurred. Our impairment assessment requires us to apply judgment in estimating future cash flows. The primary estimates include the expected volumes to be processed by Centrahoma, the terms of the related processing agreements, and future commodity prices.	Based on the current forecasts, our ownership in Centrahoma will generate cash flows with a present value in excess of the current carrying value of the investment. 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 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 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 such as option volatilities and NGL prices that are interpolated and extrapolated due to inactive markets. These instruments are classified as Level 3 under the fair value hierarchy. 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, 2011 would have affected net income before provision for income tax by approximately $18.1 million for the year ended December 31, 2011.

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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Accounting for Significant Embedded Derivative Instruments
We have a Gas Purchase Agreement with Equitable ("EQT"), in which we are required to purchase natural gas based on a complex formula designed to share some of the frac-spread with EQT, through December 31, 2022. This contract has been identified as an embedded derivative and requires a complex valuation based on significant judgment. The agreement has a primary term that expires on December 31, 2022 and contains two successive term-extending options under which EQT can extend the purchase agreement an additional five years. Such options are part of the embedded feature and thus are required to be considered in the valuation of the embedded derivative. We are required to make a significant judgment about the probability that the options would be exercised when determining the value of the extension options.	We carry the EQT embedded derivative at fair value with changes in fair value recognized in income each period. The valuation requires significant judgment when forming the assumptions used. Third-party forward curves for certain commodity prices utilized in the valuation do not extend through the term of the arrangement. Thus, pricing is required to be extrapolated for those periods. We utilize multiple cash flow techniques to extrapolate NGL pricing. Due to the illiquidity of future markets, we do not believe one method is more indicative of fair value than the other methods. The fair value is also appropriately adjusted for nonperformance risk each period. We evaluated various factors in order to determine the probability that the term-extending options would be exercised by EQT such as estimates of future gas reserves in the region, the competitive environment in which the contract operates, the commodity price environment, and EQT's business strategy. We have asserted that the probability that EQT will exercise their option to extend the agreement is 0% as of December 31, 2011 based on the high degree of uncertainty.	The EQT Embedded Derivative is an instrument that is not exchange-traded. The valuation of the instrument is complex and requires significant judgment. The inputs used in the valuation model require specialized knowledge, as NGL price curves do not exist for the entire term of the arrangement. The valuation is sensitive to NGL and natural gas future price curves. Holding the natural gas curves constant, a 10% increase (decrease) in NGL price curves causes a 30% increase (decrease) in the liability as of December 31, 2011. Holding the NGL curves constant, a 10% increase (decrease) in the natural gas curves causes a 10% decrease (increase) in the liability as of December 31, 2011. The determination of the fair value of the option to extend is based on our judgment about the probability of EQT exercising the extension. If it were determined that the probability of exercise was not 0% as of December 31, 2011, the liability would be understated.

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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 VIE. Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership or other pecuniary interests in an entity that change with changes in the fair value of the VIE's assets. When we conclude that we hold an interest in a VIE we must determine if we are the entity's primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. This controlling financial interest is evidenced by both (a) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses that could potentially be significant to the VIE or the right to receive benefits that could potentially be significant to the VIE. We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any 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 primarily qualitative 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 a controlling financial interest; and/or if an equity holder's voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE. We continually monitor our interests in legal entities for 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 Pioneer is a VIE and we are considered the primary beneficiary. We have a controlling interest in the Wirth Gathering Partnership and the Bright Star Partnership, which are less-than wholly-owned but are consolidated under the voting interest model. 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 requires significant judgment and understanding of the organization. This 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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Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions
Acquisitions—Purchase Price Allocation
We allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities is recorded as goodwill. For significant acquisitions, we engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets such as customer relationships, trade names and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, after the acquisition closing date through the end of the measurement period of up to one year as we finalize valuations for the assets acquired and liabilities assumed.	Purchase price allocation methodology requires management to make assumptions and apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities primarily using a market approach, income approach, or cost approach, as appropriate. Key inputs into the fair value determinations include estimates and assumptions related to future volumes, commodity prices, operating costs, replacement costs and construction costs, as well as an estimate of the expected term and profits of the related customer contract or contracts.	If estimates or assumptions used to complete the purchase price allocation and estimate the fair value of acquired assets and liabilities significantly differed from assumptions made, the allocation of purchase price between goodwill, intangibles and property plant and equipment could significantly differ. Such a difference would impact future earnings through depreciation and amortization expense. In addition, if forecasts supporting the valuation of the intangibles or goodwill are not achieved, impairments could arise.

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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 and nonperformance by our customers and counterparties.

Commodity Price Risk

        NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of natural gas and NGL transportation, NGL fractionation capacity and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at our or third-party processing plants, purchasing and selling, or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of drilling activity, such prices also affect profitability. To protect ourselves financially against adverse price movements and to maintain more stable and predictable earnings so that we can meet our cash distribution objectives, debt service and capital expenditures, we execute a strategy governed by the risk management policy approved by the Board. We have a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts our strategy as conditions warrant. We enter into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps, options and fixed price forward contracts traded on the OTC market. The risk management policy does not allow speculative derivative contracts.

        To mitigate our cash flow exposure to fluctuations in the price of NGLs, we have entered into derivative financial instruments relating to the future price of NGLs and crude oil. Generally we manage our NGL price risk using crude oil as NGL financial markets lack adequate liquidity and historically there has been a strong relationship between changes in NGL and crude oil prices. The pricing relationship between NGLs and crude oil may vary in certain periods because crude oil pricing is generally based on worldwide demand and the level of production of major crude oil exporting countries while NGL prices are correlated to North America supply and petrochemical demand. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, we incur increased risk and additional gains or losses. We enter into NGL derivative contracts when adequate market liquidity exists.

        To mitigate our cash flow exposure to fluctuations in the price of natural gas, we primarily utilize derivative financial instruments relating to the future price of natural gas. and take into account the partial offset of our long and short gas positions resulting from normal operating activities.

        As a result of our current derivative positions, we have mitigated a portion of our expected commodity price risk through the fourth quarter of 2014. We would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event we have derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

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        We enter into derivative contracts primarily with financial institutions that are participating members of the Credit Facility as collateral is not posted by us as the participating members have a collateral position in substantially all of our wholly-owned assets other than MarkWest Liberty Midstream. All of our financial derivative positions are currently with participating bank group members. Management conducts a standard credit review on counterparties. For all participating bank group members, collateral requirements do not exist when a derivative contract favors us. We use standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).

Outstanding Derivative Contracts

        The following tables provide information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at December 31, 2011, including the weighted-average prices ("WAVG"):

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012		2,634	$	75.65	$	97.22	$	(7,557	)
2013		3,714		88.08		107.45		2,114
2014		734		95.36		114.81		2,359

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2012		6,555	$	87.21	$	(33,561	)
2013		4,665		92.70		(5,080	)
2014		746		99.89		1,751

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2012		14,377	$	4.41	$	(6,941	)
2013		980		5.13		(469	)

Propane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Jan - Mar)		140,047	$	1.42	$	1,571

IsoButane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Jan - Mar)		25,051	$	1.85	$	(547	)

Normal Butane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Jan - Mar)		40,083	$	1.79	$	(272	)

Natural Gasoline Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Jan - Mar)		92,847	$	2.29	$	632

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        The following tables provide information on the volume of our taxable subsidiary's commodity derivative activity for positions related to keep-whole price risk at December 31, 2011, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)		Fair Value (in thousands)
2012		1,122	$	78.49	$	101.71	$	(2,261	)

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)		Fair Value (in thousands)
2012(1)		1,083	$	87.11	$	(7,946	)
2013		1,304		94.32		(638	)

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)		Fair Value (in thousands)
2012		14,419	$	6.02	$	(14,435	)
2013		9,793		5.34		(4,956	)
2014		4,249		5.69		(2,023	)

Propane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Jan - Mar)		152,569	$	1.46	$	1,113
2013 (Jan - Mar, Oct - Dec)		36,885		1.29		(190	)
2014 (Jan - Mar, Oct - Dec)		87,837		1.25		(522	)

IsoButane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Jan - Mar)		8,282	$	1.82	$	(254	)
2013		3,081		1.70		(102	)
2014		3,885		1.67		(91	)

Normal Butane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Jan - Mar)		22,944	$	1.75	$	(342	)
2013		8,512		1.61		(225	)
2014		10,711		1.61		(115	)

Natural Gasoline Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Jan - Mar)		14,969	$	2.28	$	33
2013		5,600		2.26		327
2014		7,106		2.32		683

(1)

During the second quarter of 2011, we effectively converted our swap hedges related to our first quarter 2012 NGL exposure from crude proxy hedges to direct NGL product hedges by purchasing crude swaps to offset the existing crude swap positions. The volume of offsetting crude swaps outstanding as of December 31, 2011 was 277,095 barrels for Q1 2012. The outstanding positions were being used to manage price risk on NGL products. To continue to manage price risk on NGL products, we sold NGL product swaps through the first quarter of 2012.

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        The following table provides information on the volume of MarkWest Liberty Midstream's commodity derivative activity positions related to long liquids price risk at December 31, 2011, including the WAVG:

Propane Swaps	Volumes (Gal/d)		WAVG Price (Per Gal)		Fair Value (in thousands)
2012 (Jan - Mar)		49,010	$	1.54	$	684

        The following table provides information on the derivative positions related to long liquids and keep-whole price risk that we have entered into subsequent to December 31, 2011, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)
2012		638	$	90.00	$	108.82

WTI Crude Swaps	Volumes (Bbl/d)		WAVG Price (Per Bbl)
2013		796	$	98.46
2014		1,027	$	95.03

Natural Gas Swaps	Volumes (MMBtu/d)		WAVG Price (Per MMBtu)
2012		2,767	$	2.72
2013 (Jan - Sep)		634	$	3.70

        The following tables provide information on the derivative positions of MarkWest Liberty Midstream related to long liquids price risk that we have entered into subsequent to December 31, 2011, including the WAVG:

WTI Crude Collars	Volumes (Bbl/d)		WAVG Floor (Per Bbl)		WAVG Cap (Per Bbl)
2012 (Apr - Dec)		682	$	90.00	$	108.99
2013		494		92.00		108.67

        We have a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative loss related to purchased product costs. In February 2011, we executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. As of December 31, 2011, the estimated fair value of this contract was a liability of $114.9 million and the recorded value was a liability of $61.4 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and,

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therefore, not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of December 31, 2011 (in thousands):

Fair value of commodity contract	$	114,928
Inception value for period from April 1, 2015 to December 31, 2022		(53,507	)
Derivative liability as of December 31, 2011	$	61,421

        We have a commodity contract that gives us an option to fix a component of the utilities cost to an index price on electricity at one of our plant locations through the fourth quarter of 2014. The changes in the fair value of the derivative component of this contract is recognized as Derivative (gain) loss related to facility expenses. As of December 31, 2011, the estimated fair value of this contract was an asset of $7.5 million.

Interest Rate Risk

        Our primary interest rate risk exposure results from our Credit Facility which has a borrowing capacity of $900 million. As of February 17, 2012, we have no borrowings outstanding on the 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 million. The swaps were intended to mitigate the effects of changes in fair value due to changes in the benchmark interest rate (one-month LIBOR). We managed the fair value risk on a portion of our 2014 Senior Notes that were redeemed in the fourth quarter of 2010. All outstanding interest rate swaps were settled in January 2010.

Long-Term Debt	Interest Rate	Lending Limit		Due Date	Outstanding at December 31, 2011
Credit Facility	Variable	$	900 million	September 2016	$	66 million
2018 Senior Notes	Fixed	$	81 million	April 2018	$	81 million
2020 Senior Notes	Fixed	$	500 million	November 2020	$	500 million
2021 Senior Notes	Fixed	$	500 million	August 2021	$	500 million
2022 Senior Notes	Fixed	$	700 million	June 2022	$	700 million

        Based on our overall interest rate exposure at December 31, 2011, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our Credit Facility would change earnings by approximately $0.7 million over a 12-month period. Based on our overall interest rate exposure at February 17, 2012, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our Credit Facility would not change earnings.

Credit Risk

        We are subject to risk of loss resulting from nonpayment or nonperformance by the counterparties to our derivative contracts. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value at the reporting date. These outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted.

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        We are subject to risk of loss resulting from nonpayment by our customers to whom we provide midstream services or sell natural gas or NGLs. Our credit exposure related to these customers is represented by the value of our trade receivables. Where exposed to credit risk, we analyze the customer's financial condition prior to entering into a transaction or agreement, establish credit terms and monitor the appropriateness of these terms on an ongoing basis. In the event of a customer default, we may sustain a loss and our cash receipts could be negatively impacted.

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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	94
Consolidated Balance Sheets at December 31, 2011 and 2010	95
Consolidated Statements of Operations for the years ended December 31, 2011, 2010 and 2009	96
Consolidated Statements of Changes in Equity and Comprehensive Income for the years ended December 31, 2011, 2010 and 2009	97
Consolidated Statements of Cash Flows for the years ended December 31, 2011, 2010 and 2009	98
Notes to Consolidated Financial Statements for the years ended December 31, 2011, 2010 and 2009	99

        All 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, 2011 and 2010, and the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these 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, 2011 and 2010, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, 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, 2011, 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 February 28, 2012 expressed an unqualified opinion on the Partnership's internal control over financial reporting.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
February 28, 2012

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MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED BALANCE SHEETS

(in thousands)

	December 31, 2011			December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents ($2,684 and $2,913, respectively)	$	117,016		$	67,450
Restricted cash		26,193			—
Receivables, net ($1,569 and $43,783, respectively)		226,561			179,209
Inventories ($0 and $8,431)		41,006			23,432
Fair value of derivative instruments		8,698			4,345
Deferred income taxes		14,885			16,090
Other current assets ($169 and $272, respectively)		11,748			8,020
Total current assets		446,107			298,546
Property, plant and equipment ($156,808 and $849,986, respectively)		3,302,369			2,613,027
Less: accumulated depreciation ($15,551 and $38,169, respectively)		(438,062	)		(294,003	)
Total property, plant and equipment, net		2,864,307			2,319,024
Other long-term assets:
Restricted cash ($0 and $28,001)		—			28,001
Investment in unconsolidated affiliate		27,853			28,688
Intangibles, net of accumulated amortization of $168,168 and $124,568, respectively		603,767			613,578
Goodwill		67,918			9,421
Deferred financing costs, net of accumulated amortization of $13,194 and $11,445, respectively		41,798			32,901
Deferred contract cost, net of accumulated amortization of $2,262 and $1,950, respectively		988			1,300
Fair value of derivative instruments		16,092			417
Other long-term assets ($102 and $383, respectively)		1,595			1,486
Total assets	$	4,070,425		$	3,333,362
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($96 and $5,945, respectively)	$	179,871		$	122,473
Accrued liabilities ($1,144 and $64,713, respectively)		171,451			153,869
Deferred income taxes		—			11
Fair value of derivative instruments		90,551			65,489
Total current liabilities		441,873			341,842
Deferred income taxes		93,664			87,881
Fair value of derivative instruments		65,403			66,290
Long-term debt, net of discounts of $1,050 and $1,566, respectively		1,846,062			1,273,434
Other long-term liabilities ($73 and $154, respectively)		121,356			105,349
Commitments and contingencies (see Note 18)
Equity:
Common units (94,940 and 71,440 common units issued and outstanding, respectively)		679,309			993,049
Class B units (19,954 and 0 units issued and outstanding, respectively)		752,531			—
Non-controlling interest in consolidated subsidiaries		70,227			465,517
Total equity		1,502,067			1,458,566
Total liabilities and equity	$	4,070,425		$	3,333,362

Asset and liability amounts in parentheses represent the portion of the consolidated balance attributable to variable interest entities.

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

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MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

	Year ended December 31,
	2011			2010			2009
Revenue:
Revenue	$	1,534,434		$	1,241,563		$	858,635
Derivative loss		(29,035	)		(53,932	)		(120,352	)
Total revenue		1,505,399			1,187,631			738,283
Operating expenses:
Purchased product costs		682,370			578,627			408,826
Derivative loss related to purchased product costs		52,960			27,713			68,883
Facility expenses		173,598			151,449			126,977
Derivative gain related to facility expenses		(6,480	)		(1,295	)		(373	)
Selling, general and administrative expenses		81,229			75,258			63,728
Depreciation		149,954			123,198			95,537
Amortization of intangible assets		43,617			40,833			40,831
Loss on disposal of property, plant and equipment		8,797			3,149			1,677
Accretion of asset retirement obligations		1,190			237			198
Impairment of goodwill and long-lived assets		—			—			5,855
Total operating expenses		1,187,235			999,169			812,139
Income (loss) from operations		318,164			188,462			(73,856	)
Other income (expense):
(Loss) earnings from unconsolidated affiliates		(1,095	)		1,562			3,505
Gain on sale of unconsolidated affiliate		—			—			6,801
Interest income		422			1,670			349
Interest expense		(113,631	)		(103,873	)		(87,419	)
Amortization of deferred financing costs and discount (a component of interest expense)		(5,114	)		(10,264	)		(9,718	)
Derivative gain related to interest expense		—			1,871			2,509
Loss on redemption of debt		(78,996	)		(46,326	)		—
Miscellaneous income, net		144			1,189			2,459
Income (loss) before provision for income tax		119,894			34,291			(155,370	)
Provision for income tax expense (benefit):
Current		17,578			7,655			8,072
Deferred		(3,929	)		(4,466	)		(50,088	)
Total provision for income tax		13,649			3,189			(42,016	)
Net income (loss)		106,245			31,102			(113,354	)
Net income attributable to non-controlling interest		(45,550	)		(30,635	)		(5,314	)
Net income (loss) attributable to the Partnership	$	60,695		$	467		$	(118,668	)
Net income (loss) attributable to the Partnership's common unitholders per common unit (Note 23):
Basic	$	0.75		$	(0.01	)	$	(1.97	)
Diluted	$	0.75		$	(0.01	)	$	(1.97	)
Weighted average number of outstanding common units:
Basic		78,466			70,128			60,957
Diluted		78,619			70,128			60,957
Cash distribution declared per common unit	$	2.75		$	2.56		$	2.56

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

96

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in thousands)

	Common Units					Class B Units
										Non- controlling Interest
	Units		Amount			Units		Amount					Total
December 31, 2008		56,640	$	1,144,854			—	$	—	$	3,301		$	1,148,155
Share-based compensation activity		275		5,204			—		—		—			5,204
Distributions paid		—		(155,307	)		—		—		(155	)		(155,462	)
Issuance of units in public offerings, 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
Deferred income tax impact from changes in equity		—		(10,236	)		—		—		—			(10,236	)
Net (loss) income		—		(118,668	)		—		—		5,314			(113,354	)
December 31, 2009		66,275		1,026,814			—		—		282,739			1,309,553
Share-based compensation activity		278		12,087			—		—		—			12,087
Excess tax benefits related to share-based compensation		—		98			—		—		—			98
Distributions paid		—		(181,058	)		—		—		(6,150	)		(187,208	)
Issuance of units in public offering, net of offering costs		4,887		142,255			—		—		—			142,255
Contributions to MarkWest Liberty Midstream joint venture,		—		—			—		—		158,293			158,293
Deferred income tax impact from changes in equity		—		(7,614	)		—		—		—			(7,614	)
Net income		—		467			—		—		30,635			31,102
December 31, 2010		71,440		993,049			—		—		465,517			1,458,566
Share-based compensation activity		275		8,083			—		—		—			8,083
Excess tax benefits related to share-based compensation		—		1,084			—		—		—			1,084
Distributions paid		—		(218,398	)		—		—		(66,887	)		(285,285	)
Issuance of units in public offerings, net of offering costs		23,225		1,095,488			—		—		—			1,095,488
Issuance of Class B units		—		—			19,954		752,531		—			752,531
Contributions to MarkWest Liberty Midstream joint venture		—		—			—		—		126,392			126,392
Purchase of non-controlling interest of MarkWest Liberty M&R, net of tax benefit		—		(1,198,465	)		—		—		(500,345	)		(1,698,810	)
Deferred income tax impact from changes in equity		—		(62,227	)		—		—		—			(62,227	)
Net income		—		60,695			—		—		45,550			106,245
December 31, 2011		94,940	$	679,309			19,954	$	752,531	$	70,227		$	1,502,067

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

97

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,
	2011			2010			2009
Cash flows from operating activities:
Net income (loss)	$	106,245		$	31,102		$	(113,354	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities (net of acquisitions):
Depreciation		149,954			123,198			95,537
Amortization of intangible assets		43,617			40,833			40,831
Impairment of goodwill and long-lived assets		—			—			5,855
Loss on redemption of debt		78,996			46,326			—
Amortization of deferred financing costs and discount		5,114			10,264			9,718
Accretion of asset retirement obligations		1,190			237			198
Amortization of deferred contract cost		312			312			312
Phantom unit compensation expense		13,479			15,319			7,448
Loss (earnings) of unconsolidated affiliates		1,095			(1,562	)		(3,505	)
Gain on sale of unconsolidated affiliate		—			—			(6,801	)
Contribution to unconsolidated affiliate		(560	)		—			—
Distributions from unconsolidated affiliate		300			2,508			—
Unrealized loss on derivative instruments		4,147			28,475			227,920
Loss on disposal of property, plant and equipment		8,797			3,149			1,677
Deferred income taxes		(3,929	)		(4,466	)		(50,088	)
Other		1,626			—			(2,228	)
Changes in operating assets and liabilities, net of working capital acquired:
Receivables		(45,463	)		(37,090	)		(33,133	)
Inventories		(16,025	)		5,710			6,245
Other current assets		(3,728	)		2,654			1,074
Accounts payable and accrued liabilities		54,745			45,361			30,717
Other long-term assets		(307	)		174			(2,808	)
Other long-term liabilities		15,093			(176	)		7,486
Net cash provided by operating activities		414,698			312,328			223,101
Cash flows from investing activities:
Restricted cash		2,006			(28,001	)		—
Capital expenditures		(551,281	)		(458,668	)		(486,623	)
Acquisition of business		(230,728	)		—			—
Equity investments		—			—			(405	)
Proceeds from sale of unconsolidated affiliate		—			—			25,000
Proceeds from disposal of property, plant and equipment		3,450			733			275
Net cash flows used in investing activities		(776,553	)		(485,936	)		(461,753	)
Cash flows from financing activities:
Proceeds from revolving credit facility		1,182,200			494,404			725,200
Payments of revolving credit facility		(1,116,200	)		(553,704	)		(850,600	)
Proceeds from long-term debt		1,199,000			500,000			117,000
Payments of long-term debt		(693,888	)		(375,000	)		—
Payments of premiums on redemption of long-term debt		(71,377	)		(9,732	)		—
Payments for debt issuance costs, deferred financing costs and registration costs		(20,163	)		(20,912	)		(8,554	)
Acquisition of non-controlling interest, including transaction costs		(997,601	)		—			—
Contributions to MarkWest Liberty Midstream joint venture, net		126,392			158,293			194,536
Proceeds from sale of equity interest in joint venture, net		—			—			60,654
Payments of SMR Liability		(1,875	)		(1,354	)		—
Proceeds from SMR Transaction		—			—			73,129
Proceeds from public equity offerings, net		1,095,488			142,255			178,565
Cash paid for taxes related to net settlement of share-based payment awards		(6,354	)		(3,834	)		(1,385	)
Excess tax benefits related to share-based compensation		1,084			98			—
Payment of distributions to common unitholders		(218,398	)		(181,058	)		(155,307	)
Payment of distributions to non-controlling interest		(66,887	)		(6,150	)		(155	)
Net cash flows provided by financing activities		411,421			143,306			333,083
Net increase (decrease) in cash and cash equivalents		49,566			(30,302	)		94,431
Cash and cash equivalents at beginning of year		67,450			97,752			3,321
Cash and cash equivalents at end of year	$	117,016		$	67,450		$	97,752

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

98

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. Organization and Basis of Presentation

        MarkWest Energy Partners, L.P. ("MarkWest Energy Partners") was formed in January 2002 as a Delaware limited partnership. In February 2008, MarkWest Energy Partners completed its Merger with MarkWest Hydrocarbon, Inc. (the "Corporation" or "MarkWest Hydrocarbon") and MWEP, L.L.C, whereby MarkWest Hydrocarbon became a wholly-owned subsidiary of MarkWest Energy Partners. 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 and fractionator of natural gas in the Appalachian Basin and continues to expand this position through the growth of its operations in the Marcellus Shale. Finally, the Partnership owns a crude oil transportation pipeline in Michigan. The Partnership's principal executive office is located in Denver, Colorado.

        The Partnership's consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Liberty Midstream and MarkWest Pioneer, variable interest entities for which the Partnership has been determined to be the primary beneficiary, are included in the consolidated financial statements. Effective December 31, 2011, the Partnership acquired the remaining 49% interest of MarkWest Liberty Midstream. As a result, as of December 31, 2011, MarkWest Liberty Midstream is not a variable interest entity but is consolidated as a wholly-owned subsidiary (see Note 4 for further discussion of MarkWest Pioneer and MarkWest Liberty Midstream). For non-wholly-owned subsidiaries, the interests owned by third parties have been recorded as Non-controlling interest in consolidated subsidiaries in the accompanying Consolidated Balance Sheets. All significant intercompany investments, accounts and transactions have been eliminated. Investments in which the Partnership exercises significant influence but does not control, or 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.

2. Summary of Significant Accounting Policies

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.

99

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

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.

Restricted Cash

        Restricted cash includes cash and investments that must be held in escrow until certain capital projects are completed and the third party releases the restriction. Restricted cash balances for which the restrictions will not be released within a period of twelve months are classified as a long-term asset in the Consolidated Balance Sheets.

Inventories

        Inventories, which consist primarily of natural gas, propane, other NGLs and spare parts and supplies, are valued at the lower of weighted-average cost or market. 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 a period of 20 to 25 years for all assets, with the exception of miscellaneous equipment and vehicles, which are depreciated over a period of three to ten years.

        The Partnership evaluates transactions involving the sale of property, plant and equipment to determine if they are, in-substance, the sale of real estate. Tangible assets may be considered real estate if the costs to 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. The Partnership's 2009 sale of the SMR, which was considered in-substance real estate, was not considered a sale 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 in 2009 was considered the sale of in-substance real estate. See Note 5 and Note 4, respectively, for a description of each transaction and its impact on the financial statements.

100

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.

Investment in Unconsolidated Affiliate

        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 affiliate in the accompanying Consolidated Balance Sheets.

        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.

Intangibles

        The Partnership's intangibles are comprised of customer contracts and relationships acquired in business combinations and 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 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

101

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

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. The Partnership first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. If a two-step process goodwill impairment test is required, 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 an 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 group.

        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 contractual term of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced, using the effective interest method.

102

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

Deferred Contract Cost

        The Partnership may pay consideration to a producer upon entering a long-term arrangement to provide midstream services to the producer. In such cases, the amount of consideration paid is recorded as Deferred contract cost, net of accumulated amortization on the accompanying Consolidated Balance Sheets and is amortized over the term of the arrangement.

Derivative Instruments

        Derivative instruments (including derivative instruments embedded in other contracts) are recorded at fair value and included in the consolidated balance sheet as assets or liabilities. Assets and liabilities related to derivative instruments with the same counterparty are not netted in the consolidated balance sheet. The Partnership discloses the fair value of 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). Changes in the fair value of derivative instruments are reported in the Statement of Operations in accounts related to the item whose value or cash flows are being managed. 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 manage 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 manage costs, typically in a keep-whole arrangement. Facility expenses gains and losses relate to a contract utilized to manage 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 Note 6). Changes in risk management activities are reported as an adjustment to net income in computing cash flow from operating activities on the accompanying Consolidated Statements of Cash Flows.

        During 2011, 2010 and 2009, the Partnership did not designate any hedges or designate any contracts as normal purchases and normal sales.

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. The recorded value of the amounts outstanding under the Credit Facility approximates fair value due to the variable interest rate that approximates current market rates. Derivative instruments are recorded at fair value, based on available market information (see Note 6). 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, 2011 and 2010 (in thousands):

	December 31, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	1,846,062	$	1,880,710	$	1,273,434	$	1,333,875
SMR Liability		93,909		119,887		95,784		125,600

103

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

        The fair value of the long-term debt is estimated based on recent market quotes. The fair value of the SMR Liability is estimated using a discounted cash flow approach based on the contractual cash flows and the Partnership's unsecured borrowing rate.

Fair Value Measurement

        Financial assets and liabilities recorded at fair value in the Consolidated Balance Sheet are categorized based upon a fair value hierarchy established by GAAP, which classifies the inputs used to measure fair value into the following levels:

•

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 derivatives, the embedded derivatives in commodity contracts and the embedded put options discussed in Note 6 and Note 16 as they have significant unobservable inputs.

        The methods and assumptions described above may produce a fair value that may not be realized in future periods upon settlement. 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 7.

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. 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 exchange and storage of NGLs; and gathering and transportation of crude oil. The revenue the Partnership earns from these arrangements is generally directly

104

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

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 or fixed demand charges.

•

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 delivers an agreed-upon percentage of the residue gas and NGLs to the producer and sell the volumes the Partnership keeps to third parties.

•

Percent-of-index arrangements—Under percent-of-index arrangements, the Partnership purchases 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 then gathers and delivers the natural gas to pipelines where the Partnership resells 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 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. 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 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. For other arrangements,

105

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

2. Summary of Significant Accounting Policies (Continued)

the amount of revenue is determinable when the sale of the applicable product has been completed upon delivery and transfer of title.

        Collectability is reasonably assured.    Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates a customer's financial position (e.g. cash position and credit rating) and its ability to pay. If collectability 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 customers' 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 acts as an agent and earns a fixed amount and does not take ownership of the gas and/or NGLs.

        Amounts billed to customers for shipping and handling, including fuel costs, 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.

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 adjusted 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 its share-based compensation plans as described further in Note 20. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. Phantom units are treated as equity awards and compensation expense is measured for these phantom unit grants based on the fair value of the units on the grant date, as defined by GAAP. 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.

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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 balances are classified as long-term in the accompanying Consolidated Balance Sheets. All changes in the tax bases of assets and liabilities are allocated among continued operations and items charged or credited directly to equity.

        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 Class A units were issued to the Corporation as part of the Merger and represent limited partner interests with the same rights as common units except that the Class A units do not have voting rights, except as required by law. Class A units are not treated as outstanding common units in the Consolidated Balance Sheet as they are eliminated in the consolidation of the Corporation. The deferred income tax component relates to the change in the temporary 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.

Earnings (Loss) Per Unit

        The Partnership's outstanding phantom units are considered to be participating securities and the Class B units are considered to be a separate class of common units that do not participate in cash distributions. 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 the Partnership, after deducting amounts that are allocable to the outstanding phantom units and Class B units, by the weighted average number of common units outstanding during the period. The amount allocable to the phantom units and Class B 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, no earnings are allocable to Class B units as they do not

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2. Summary of Significant Accounting Policies (Continued)

participate in cash distributions. 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 and Class B units is based on actual distributions to the phantom units and Class B unitholders. Diluted earnings per unit is calculated by dividing net income attributable to the Partnership, after deducting amounts allocable to the outstanding phantom units and Class B 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 net income attributable to the Partnership, after deducting amounts that are allocable to the outstanding phantom units and Class B units, is a 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 acquires additional interest or if the subsidiary issues or repurchases its own shares. If the transaction does not result in a change in control over the subsidiary, the transaction is accounted for as an equity transaction. If a sale 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. If the purchase of additional interest occurs which changes the acquirer's ownership interest from non-controlling to controlling, the acquirer's preexisting interest in the acquiree is remeasured to its fair value, with a resulting gain or loss recorded in earnings upon consummation of the business combination. Once an entity has control of a subsidiary, its acquisitions of some or all of the noncontrolling interests in that subsidiary are accounted for as equity transactions and are not considered to be a business combination. See Note 4 for a description of the transactions that resulted in a change in the Partnership's ownership interest in a subsidiary and the impact of these transactions to the financial statements.

Recent Accounting Pronouncements

        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 for the Partnership prospectively for all revenue arrangements entered into or materially modified on or after January 1, 2011. The amendment did not have a material effect on the Partnership's consolidated financial statements.

        In May 2011, the FASB amended the accounting guidance for fair value measurement and disclosure. The amended guidance was intended to converge the fair value measurement and disclosure requirements under GAAP and IFRS. The amendment primarily clarifies the application of the existing guidance and provides for increased disclosures, particularly related to Level 3 fair value measurements. The amended

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2. Summary of Significant Accounting Policies (Continued)

guidance is effective for the Partnership prospectively as of January 1, 2012. Except for the additional disclosures, the adoption of the amended guidance is not expected to have a material effect on the Partnership's consolidated financial statements.

        In September 2011, the FASB amended the accounting guidance for goodwill impairment testing. The amended guidance provides an entity with an option to first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership elected early adoption for the period ended December 31, 2011 and the adoption did not have a material effect on the Partnership's consolidated financial statements.

        In December 2011, the FASB amended the accounting guidance for balance sheet offsetting for financial assets and financial liabilities. The amended guidance was intended to help investors and other financial statement users to better assess the effect or potential effect of offsetting arrangements on a company's financial position and provides for increased disclosures. The amended guidance is effective for the Partnership prospectively as of January 1, 2013. Except for the additional disclosures, the adoption of the amended guidance is not expected to have a material effect on the Partnership's consolidated financial statements.

3. Business Combination

        On February 1, 2011, the Partnership acquired natural gas processing and NGL pipeline assets from EQT for a cash purchase price of approximately $230.7 million. The assets acquired include natural gas processing facilities located near Langley, Kentucky, consisting of a cryogenic natural gas processing plant with a capacity of approximately 100 MMcf/d and a refrigeration natural gas processing plant with a capacity of approximately 75 MMcf/d, the partially constructed Ranger pipeline that extends through parts of Kentucky and West Virginia, and certain other related assets. The acquired assets do not include certain residue gas compression and transportation facilities at the same location as the Langley Processing Facilities. This acquisition is referred to as the Langley Acquisition. In connection with the Langley Acquisition, the Partnership completed the construction of the Ranger Pipeline to connect the Langley Processing Facilities to the Partnership's existing pipeline that transports NGLs to its Siloam fractionation facility in South Shore, Kentucky.

        Concurrently with the closing of the Langley Acquisition, the Partnership entered into a long-term agreement to process certain natural gas owned or controlled by EQT at the Langley Processing Facilities. The processing agreement requires the Partnership to install an additional cryogenic natural gas processing plant with a capacity of at least 60 MMcf/d in 2012. The Partnership exchanges the NGLs produced at the Langley Processing Facilities for fractionated products from its Siloam facility and markets the fractionated products on behalf of EQT in accordance with a long-term NGL exchange and marketing agreement. As a result of the acquisition, the Partnership has significantly expanded its midstream operations in the liquids-rich gas areas of the Appalachian Basin.

        The Langley Acquisition is accounted for as a business combination. The total purchase price is allocated to the identifiable assets acquired and liabilities assumed based on the estimated fair values at the acquisition date. The remaining purchase price in excess of the fair value of the identifiable assets and liabilities is recorded as goodwill. The acquired assets and the related results of operations are included in the Partnership's Northeast segment.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

3. Business Combination (Continued)

        The following table summarizes the purchase price allocation for the Langley Acquisition (in thousands):

Property, plant and equipment	$	136,525
Goodwill		58,497
Intangible asset		33,900
Inventory		1,806
Total	$	230,728

        The goodwill recognized from the Langley Acquisition results primarily from the Partnership's ability to continue to grow its business in the liquids-rich gas areas of the Appalachian Basin and access additional markets in a competitive environment as a result of securing the processing rights for a large area of dedicated acreage and acquiring expanded midstream infrastructure in the acquisition. All of the goodwill is deductible for tax purposes.

        The intangible asset consists of an identifiable customer contract. The acquired intangible will be amortized on a straight-line basis over the estimated remaining customer contract useful life of approximately twelve years.

        The results of operations from the Langley Acquisition are included in the consolidated financial statements from the acquisition date. Revenue and income before provision for income tax related to the Langley Acquisition were approximately $21.8 million and $6.8 million, respectively, for the year ended December 31, 2011.

        Pro forma financial results that give effect to the Langley Acquisition are not presented as it is impracticable to obtain the necessary information. EQT did not operate the acquired assets as a stand-alone business and, therefore, historical financial information that is consistent with the operations under the current agreements is not available.

4. Variable Interest Entities

MarkWest Liberty Midstream

        On February 27, 2009, the Partnership entered into a joint venture with M&R, an affiliate of The Energy & Minerals Group 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. Under the original joint venture agreement, MarkWest Liberty Midstream was owned 60% by the Partnership and 40% by M&R. Upon closing, the Partnership contributed its existing Marcellus Shale natural gas gathering and processing assets with an agreed to value of $107.5 million and M&R contributed cash of $50.0 million to MarkWest Liberty Midstream. M&R also committed to fund the next $150 million of MarkWest Liberty Midstream's capital requirements after which time the Partnership agreed to fund the future capital requirements until each member's contributed capital was proportionate to its ownership interest ("Equalization"). Effective November 1, 2009, the Partnership and M&R executed the Second Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources L.L.C. pursuant to which M&R increased its participation in MarkWest Liberty Midstream.

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4. Variable Interest Entities (Continued)

The Partnership and M&R agreed to maintain a 60%/40% respective ownership interest in MarkWest Liberty Midstream until January 1, 2011, at which time M&R's ownership interest increased from 40% to 49%. In addition to its initial contribution of assets at closing, the Partnership contributed an additional $252.4 million, $171.1 million, and $8.0 million during 2011, 2010, and 2009 respectively. In addition to its $50 million contribution at closing, M&R contributed $126.4 million, $158.3 million, and $150.0 million during 2011, 2010 and 2009, respectively.

        The cumulative capital contributed by M&R exceeded its ownership interest until the third quarter of 2011. Under the terms of the joint venture agreement, M&R received a special $1.3 million, $11.4 million, and $3.4 million allocation of net income from MarkWest Liberty Midstream during the years ended December 31, 2011, 2010 and 2009, respectively, due to its excess contributions. The allocation is recorded in Net income attributable to non-controlling interest in the Consolidated Statements of Operations.

        The Partnership determined that MarkWest Liberty Midstream was a VIE until December 31, 2011, primarily due to the Partnership's disproportionate economic interests as compared to its voting interests in the entity. Additionally, MarkWest Liberty Midstream had insufficient equity at risk, as evidenced by the additional capital funding requirements discussed above. Although voting interests were shared equally between the respective members of MarkWest Liberty Midstream until December 31, 2011, the Partnership had concluded that it was the primary beneficiary based on its affiliate's role as the operator. The Partnership believes that its role as the operator along with its equity interests gave it the power to direct the activities that most significantly affected the economic performance of MarkWest Liberty Midstream. As the primary beneficiary of a VIE, the Partnership consolidated MarkWest Liberty Midstream for all periods presented in the accompanying financial statements.

        Effective December 31, 2011, the Partnership acquired M&R's 49% non-controlling interest of MarkWest Liberty Midstream for total consideration of approximately $1,746.5 million, which includes cash of $994.0 million and approximately 19,954,000 Class B units valued at approximately $752.5 million (see Note 17 for discussion of Class B units). The Partnership paid transaction fees of approximately $3.6 million related to this transaction. As a result of the transaction, MarkWest Liberty Midstream is a wholly-owned subsidiary of the Partnership and is no longer a VIE. However, the Partnership continues to consolidate MarkWest Liberty Midstream.

        In accordance with GAAP, a change in the Partnership's ownership interest in a subsidiary while it retains a controlling interest is recorded as an equity transaction. As such, the fair value of the consideration paid in excess of the $500.3 million carrying amount of the non-controlling interest acquired and the related transaction costs of approximately $3.6 million are recognized as a reduction of equity attributable to the Partnership's common units. See table below in this Note 4 for a summary of the impact on equity attributable to the Partnership's common units as of December 31, 2011.

        As the accompanying Consolidated Statements of Operations include the historical results of MarkWest Liberty Midstream, pro forma results of operations are not presented for this acquisition of non-controlling interest. The primary impact of the transaction on the financial statements is that none of MarkWest Liberty Midstream's net income will be allocable to a non-controlling interest in future periods as 100% of MarkWest Liberty Midstream's net income will be attributable to the Partnership. During the years ended December 31, 2011, 2010 and 2009, the portion of MarkWest Liberty

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4. Variable Interest Entities (Continued)

Midstream's net income attributable to non-controlling interest was $44.0 million, $27.9 million and $6.3 million, respectively.

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 mid-July 2009. The Arkoma Connector Pipeline is designed to provide approximately 638,000 Dth/d of Arkoma Basin takeaway capacity and interconnects with the Midcontinent Express Pipeline and the Gulf Crossing Pipeline. In 2009, the Partnership sold a 50% interest in MarkWest Pioneer to ArcLight Capital Partners, LLC. Under the terms of the sale, the Partnership was required to fund all of the capital expenditures required to complete construction of the Arkoma Connector Pipeline in excess of $125 million, and as a result the Partnership has made capital contributions to MarkWest Pioneer in excess of its stated ownership and voting interests. A wholly-owned subsidiary of the Partnership serves as the operator and provides field operating and general and administrative services for fixed fees. The Partnership has determined that MarkWest Pioneer is a VIE primarily due to the Partnership's disproportionate economic interests as compared to its voting interests. Although voting interests are shared equally between the respective members of MarkWest Pioneer, the Partnership has concluded that it is the primary beneficiary based on its role as the operator. The Partnership believes that its role as the operator along with its equity interests give it the power to direct the activities that most significantly affect the economic performance of MarkWest Pioneer.

Financial Statement Impact of VIEs

        As of December 31, 2011, MarkWest Pioneer is the only VIE included in the Partnership's consolidated financial statements. The assets and liabilities attributable to MarkWest Pioneer as of December 31, 2011 are disclosed parenthetically on the accompanying Consolidated Balance Sheets. As of December 31, 2010, MarkWest Pioneer and MarkWest Liberty Midstream were both consolidated

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Variable Interest Entities (Continued)

VIEs. The following table shows the assets and liabilities attributable to VIEs reflected in the Consolidated Balance Sheets as of December 31, 2010 (in thousands):

	MarkWest Liberty Midstream		MarkWest Pioneer		Total
ASSETS
Cash and cash equivalents	$	—	$	2,913	$	2,913
Receivables, net		42,181		1,602		43,783
Inventories		8,431		—		8,431
Other current assets		271		1		272
Property, plant and equipment, net of accumulated depreciation of $28,869 and $9,300, respectively		664,778		147,039		811,817
Restricted cash		28,001		—		28,001
Other long-term assets		281		102		383
Total assets	$	743,943	$	151,657	$	895,600
LIABILITIES
Accounts payable	$	5,945	$	—	$	5,945
Accrued liabilities		63,450		1,263		64,713
Other long-term liabilities		86		68		154
Total liabilities	$	69,481	$	1,331	$	70,812

        The assets of MarkWest Pioneer are not available to the Partnership for any other purpose, including collateral for its secured debt (see Note 16 and Note 25). MarkWest Pioneer's asset balances can only be used to settle it own obligations and not those of the Partnership or any other subsidiaries of the Partnership. The liabilities of MarkWest Pioneer do not represent additional claims against the Partnership's general assets and the creditors or beneficial interest holders of MarkWest Pioneer do not have recourse to the general credit of the Partnership. The Partnership's maximum exposure to loss as a result of its involvement with the MarkWest Pioneer includes its equity investment and any operating expense incurred by the subsidiary operator in excess of its subsidiary's compensation for the performance of those services.

        For the years ended December 31, 2011, 2010 and 2009, the results of operations and cash flow information of MarkWest Liberty Midstream and MarkWest Pioneer comprise substantially all of the results of operations and cash flow information of the non-guarantor subsidiaries (see Note 25). Individually, the results of operations and cash flow of MarkWest Pioneer, the remaining VIE, are not material to the Partnership. The Partnership did not provide any financial support to the MarkWest Liberty Midstream or MarkWest Pioneer that it was not contractually obligated to provide during the years ended December 31, 2011, 2010 and 2009.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

4. Variable Interest Entities (Continued)

        As discussed above, the Partnership's ownership interest in MarkWest Liberty Midstream and MarkWest Pioneer changed as a result of transactions completed in 2009 and 2011.The following table summarizes the effect of these changes of ownership interest on the equity attributable to the Partnership's common units (in thousands):

	Year ended December 31,
	2011			2010		2009
Net income (loss) attributable to the Partnership	$	60,695		$	467	$	(118,668	)
Transfers to the non-controlling interests:
Decrease in common unit equity for 2011 acquisition of equity interest in MarkWest Liberty Midstream, net of $51,321 income tax benefit		(1,194,865	)		—		—
Decrease in common unit equity for transaction costs related to 2011 acquisition of equity interest in MarkWest Liberty Midstream		(3,600	)		—		—
Decrease in common unit equity for transfer to non- controlling interest from 2009 sale of equity interest in MarkWest Pioneer, net of $1,491 income tax benefit		—			—		(10,288	)
Decrease in common unit equity for transaction costs related to 2009 sales of equity interests in MarkWest Liberty Midstream and MarkWest Pioneer		—			—		(7,310	)
Net (loss) income attributable to the Partnership and transfers to the non-controlling interest	$	(1,137,770	)	$	467	$	(136,266	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

5. Divestitures

SMR Transaction

        On September 1, 2009, the Partnership completed the sale of the steam methane reformer ("SMR Transaction") the Partnership began constructing 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 completed the construction of the SMR. The Partnership and the purchaser also executed a related product supply agreement under which the Partnership will receive all of the product produced by the SMR through 2030 in exchange for processing fees and the reimbursement of certain other expenses. The processing fee payments began when the SMR commenced operations 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 estimated costs incurred by the buyer to complete construction ("SMR Liability"). The Partnership imputes interest on the SMR Liability at 9.35% annually, its incremental borrowing rate at transaction consummation. The accrued interest on the SMR Liability was capitalized until the SMR commenced operations and the Partnership began payment of the processing fee under the product supply agreement. Each processing fee payment has 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, 2011 and 2010, the following amounts related to the SMR are included in the accompanying Consolidated Balance Sheets (in thousands):

	December 31, 2011		December 31, 2010
ASSETS
Property, plant and equipment, net of accumulated depreciation of $9,658 and $4,390, respectively	$	95,705	$	100,973
LIABILITIES
Accrued liabilities	$	2,058	$	1,875
Other long-term liabilities		91,851		93,909

Sale of Starfish

        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 purchase price of $25.0 million. The Partnership recorded a $6.8 million gain on the sale of its equity interest in Starfish.

6. Derivative Financial Instruments

Commodity Contracts

        NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership's control. The Partnership's profitability is directly affected by prevailing commodity prices primarily as a result of processing or

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Derivative Financial Instruments (Continued)

conditioning at its or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of drilling activity, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable cash flows so the Partnership can meet its cash distribution objectives, debt service requirements and fund its capital expenditures, the Partnership executes a strategy governed by the risk management policy approved by the Board. The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps, options and fixed price forward contracts traded on the OTC market. The risk management policy does not allow for trading derivative contracts.

        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. Generally the Partnership manages its NGL price risk using crude oil as NGL financial markets lack adequate liquidity and historically there has been a strong relationship between changes in NGL and crude oil prices. The pricing relationship between NGLs and crude oil may vary in certain periods due to various market conditions. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the Partnership incurs increased risk and additional gains or losses. The Partnership enters into NGL derivative contracts when adequate market liquidity exists.

        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 and takes into account the partial offset of its long and short gas positions resulting from normal operating activities.

        As a result of its derivative positions outstanding on December 31, 2011, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2014. The Partnership would be exposed to additional commodity risk in certain situations that include, but are not limited to, when producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions will be terminated.

        The Partnership enters into derivative contracts primarily with financial institutions that are participating members of the amended and restated credit agreement as collateral is not posted by the Partnership as the participating members have a collateral position in substantially all the wholly-owned assets of the Partnership other than MarkWest Liberty Midstream. All of the Partnership's financial derivative positions are currently with participating bank group members. Management conducts a standard credit review on counterparties and the Partnership has agreements containing collateral requirements. For all participating bank group members, collateral requirements do not exist when a derivative contract favors the Partnership. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).

        The Partnership records derivative contracts at fair value in the Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation which may

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6. Derivative Financial Instruments (Continued)

cause volatility in the Statement of Operations as the Partnership recognizes in current earnings all unrealized gains and losses from the changes in the fair value of its derivatives.

Embedded Derivative in Debt Contract

        On May 26, 2009, the Partnership completed the private placement of senior notes with contingent written put options as described in Note 16. The written put options were considered embedded derivatives and were not considered clearly and closely related to the indenture governing the notes. When a hybrid contract contains multiple embedded derivatives requiring separate accounting, the embedded derivatives must be aggregated and accounted for as a compound embedded derivative. These senior notes were redeemed in the fourth quarter of 2010 and the put options no longer exist as of December 31, 2010.

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.

        During the first quarter of 2010, the Partnership terminated all of its outstanding interest rate swap contracts. The financial statement impact is disclosed in the tables below.

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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6. Derivative Financial Instruments (Continued)

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

	Assets				Liabilities
Derivative contracts not designated as hedging instruments and their balance sheet location	Fair Value at December 31, 2011		Fair Value at December 31, 2010		Fair Value at December 31, 2011			Fair Value at December 31, 2010
Commodity contracts(1)
Fair value of derivative instruments—current	$	8,698	$	4,345	$	(90,551	)	$	(65,489	)
Fair value of derivative instruments—long-term		16,092		417		(65,403	)		(66,290	)
Total	$	24,790	$	4,762	$	(155,954	)	$	(131,779	)

(1)

Includes Embedded Derivatives in Commodity Contracts as discussed below.

	Year ended December 31,
Derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in income	2011			2010			2009
Revenue: Derivative loss
Realized (loss) gain	$	(48,093	)	$	(33,560	)	$	87,289
Unrealized gain (loss)		19,058			(20,372	)		(207,641	)
Total revenue: derivative loss		(29,035	)		(53,932	)		(120,352	)
Derivative loss related to purchased product costs
Realized loss		(27,711	)		(21,909	)		(53,052	)
Unrealized loss		(25,249	)		(5,804	)		(15,831	)
Total derivative loss related to purchase product costs		(52,960	)		(27,713	)		(68,883	)
Derivative gain related to facility expenses
Unrealized gain		6,480			1,295			373
Derivative gain related to interest expense
Realized gain		—			2,380			2,000
Unrealized (loss) gain		—			(509	)		509
Total derivative gain related to interest expense		—			1,871			2,509
Miscellaneous income, net
Unrealized gain		—			190			336
Total loss	$	(75,515	)	$	(78,289	)	$	(186,017	)

        At December 31, 2011 and 2010, the fair value of the Partnership's commodity derivative contracts is inclusive of premium payments of zero and $4.4 million, net of amortization, respectively. For 2011, 2010 and 2009, the Realized (loss) gain—revenue includes amortization of premium payments of $4.4 million, $3.3 million and $5.7 million, respectively.

        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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

6. Derivative Financial Instruments (Continued)

counterparties, and as such does not represent trading activity. The settlement was recorded as $26.5 million of realized gains in Revenue: Derivative loss and $11.3 million of loss included in Derivative loss related to purchased product costs in the accompanying Consolidated Statements of Operations.

Volume of Derivative Activity

        As of December 31, 2011, the Partnership had the following outstanding commodity contracts that were executed to manage the cash flow risk associated with future sales of NGLs or future purchases of natural gas.

Derivative contracts not designated as hedging instruments	Position	Notional Quantity (net)
Crude Oil (bbl)	Short		8,244,902
Natural Gas (MMBtu)	Long		16,021,887
NGLs (gal)	Short		86,563,841

Embedded Derivatives in Commodity Contracts

        The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative loss related to purchased product costs. In February 2011, the Partnership executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer's option to extend the agreement for successive five year terms through December 31, 2032. As of December 31, 2011, the estimated fair value of this contract was a liability of $114.9 million and the recorded value was a liability of $61.4 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and, therefore, not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of December 31, 2011 (in thousands).

Fair value of commodity contract	$	114,928
Inception value for period from April 1, 2015 to December 31, 2022.		(53,507	)
Derivative liability as of December 31, 2011	$	61,421

        The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at its plant location in the Gulf Coast segment through the fourth quarter of 2014. Changes in the fair value of the derivative component of this contract are recognized as Derivative gain related to facility expenses. As of December 31, 2011 and 2010, the estimated fair value of this contract was an asset of $7.5 million and $1.0 million, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Fair Value

Fair Value Measurement

        Fair value measurements and disclosures relate primarily to the Partnership's derivative positions discussed in Note 6. See Note 2 for a description of the guidance and the fair value hierarchy.

        The derivative contracts are measured at fair value on a recurring basis and classified within Level 2 and Level 3 of the valuation hierarchy. The Level 2 and Level 3 measurements are obtained using a market approach. LIBOR rates are an observable input for the measurement of all derivative contracts. The measurements for all commodity contracts contain observable inputs in the form of forward prices based on WTI crude oil prices; Columbia Appalachia, Henry Hub, PEPL and Houston Ship Channel natural gas prices; Mont Belvieu and Conway NGL prices; and ERCOT electricity prices. Level 2 instruments include crude oil and natural gas swap contracts. The valuations are based on the appropriate commodity prices and contain no significant unobservable inputs. Level 3 instruments include crude oil options, all NGL transactions, embedded derivatives in commodity contracts and the embedded put options. The significant unobservable inputs for crude oil options, NGL transactions and embedded derivatives in commodity contracts include option volatilities and commodity prices interpolated and extrapolated due to inactive markets. The significant unobservable inputs for the embedded put options are option volatilities and management's assumptions about the probability of specific events occurring in the future. The following table presents the financial instruments carried at fair value as of December 31, 2011 and 2010, and by the valuation hierarchy (in thousands):

As of December 31, 2011	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	5,063	$	(79,358	)
Significant unobservable inputs (Level 3)
Commodity contracts		12,210		(15,175	)
Embedded derivatives in commodity contracts		7,517		(61,421	)
Total carrying value in Consolidated Balance Sheet	$	24,790	$	(155,954	)

As of December 31, 2010	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	52	$	(77,776	)
Significant unobservable inputs (Level 3)
Commodity contracts		3,674		(18,031	)
Embedded derivatives in commodity contracts		1,036		(35,972	)
Total carrying value in Consolidated Balance Sheet	$	4,762	$	(131,779	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Fair Value (Continued)

Changes in Level 3 Fair Value Measurements

        The tables below include a rollforward of the balance sheet amounts for the years ended December 31, 2011 and 2010 (including the change in fair value) for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands):

	Year Ended December 31, 2011
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(14,357	)	$	(34,936	)
Total gain or loss (realized and unrealized) included in earnings(1)		3,182			(30,827	)
Settlements		8,210			11,859
Fair value at end of period	$	(2,965	)	$	(53,904	)
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at end of period	$	6,241		$	(29,556	)

	Year Ended December 31, 2010
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Interest Rate Contracts			Embedded Derivative in Debt Contract
Fair value at beginning of period	$	(11,340	)	$	(34,199	)	$	509		$	(190	)
Total gain or loss (realized and unrealized) included in earnings(1)		(11,093	)		(11,792	)		1,871			190
Purchases, sales, issuances and settlements (net)		8,076			11,055			(2,380	)		—
Fair value at end of period	$	(14,357	)	$	(34,936	)	$	—		$	—
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at December 31(1)	$	(13,101	)	$	(9,329	)	$	—		$	—

(1)

Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Derivative (loss) gain related to revenue. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Purchased product costs, Derivative loss related to purchased product costs and Derivative gain related to facility expenses. Gains on Embedded Derivative in Debt Contract are recorded in Miscellaneous income (expense), net. Gains and losses on Interest Rate Contracts are recorded in Derivative gain related to interest expense.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

7. Fair Value (Continued)

Assets and liabilities measured at fair value on a nonrecurring basis

        Certain assets and liabilities are remeasured 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. During 2009, certain long-lived assets of Wirth Gathering, 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 in 2009. The Partnership estimated the fair value of these assets based on an income approach using significant unobservable inputs (Level 3). See Note 13 for further discussion of the 2009 impairment. During the three years ended December 31, 2011, there were no other assets or liabilities to be measured at fair value on a nonrecurring basis.

8. Significant Customers and Concentration of Credit Risk

        For the years ended December 31, 2011, 2010 and 2009, revenues from a single customer totaled $297.8 million, $198.6 million and $134.8 million, representing 19.4%, 16.0% and 15.7% of Revenue, respectively. Revenues from this customer are for NGL sales made primarily in the Southwest segment. As of December 31, 2011 and 2010, the Partnership had $8.0 million and $5.1 million of accounts receivable from this customer, respectively.

        For the years ended December 31, 2011, 2010 and 2009, revenues from another customer totaled $203.3 million, $115.0 million and $81.6 million, representing 13.2%, 9.3% and 9.5% of Revenue, respectively. Revenues from this customer are for NGL sales made primarily from the Southwest segment. As of December 31, 2011 and 2010, the Partnership had $21.9 million and $13.1 million of accounts receivable from this customer, respectively.

9. Receivables

        Receivables consist of the following (in thousands):

	December 31, 2011		December 31, 2010
Trade, net	$	221,343	$	174,216
Other		5,218		4,993
Total receivables	$	226,561	$	179,209

10. Inventories

        Inventories consist of the following (in thousands):

	December 31, 2011		December 31, 2010
NGLs	$	32,352	$	15,930
Spare parts, materials and supplies		8,654		7,502
Total inventories	$	41,006	$	23,432

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

11. Property, Plant and Equipment

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

	December 31, 2011			December 31, 2010
Natural gas gathering and NGL transportation pipelines and facilities	$	2,039,524		$	1,625,170
Processing plants		660,928			584,886
Fractionation and storage facilities		120,474			81,317
Crude oil pipelines		16,678			16,810
Land, building, office equipment and other		185,462			155,437
Construction in progress		279,303			149,407
Property, plant and equipment		3,302,369			2,613,027
Less: accumulated depreciation		(438,062	)		(294,003	)
Total property, plant and equipment, net	$	2,864,307		$	2,319,024

12. Goodwill and Intangible Assets

        Goodwill.    The table below shows the gross amount of goodwill acquired and the cumulative impairment loss recognized as of December 31, 2011 (in thousands). There was no activity related to goodwill during 2009 or 2010.

	Southwest			Northeast		Gulf Coast			Total
Gross goodwill as of December 31, 2010	$	24,324		$	3,948	$	9,854		$	38,126
Acquisition(1)		—			58,497		—			58,497
Gross Goodwill as of December 31, 2011		24,324			62,445		9,854			96,623
Cumulative impairment(2)		(18,851	)		—		(9,854	)		(28,705	)
Balance as of December 31, 2011	$	5,473		$	62,445	$	—		$	67,918

(1)

Represents goodwill associated with the Langley Acquisition (see Note 3).

(2)

All impairments recorded in the fourth quarter of 2008.

        Intangible Assets.    The Partnership's intangible assets as of December 31, 2011 and 2010 are comprised of customer contracts and relationships, as follows (in thousands):

	December 31, 2011							December 31, 2010
Description	Gross		Accumulated Amortization			Net		Gross		Accumulated Amortization			Net		Useful Life
Southwest	$	406,690	$	(92,340	)	$	314,350	$	406,801	$	(69,655	)	$	337,146	10 - 20 yrs
Northeast		102,473		(29,037	)		73,436		68,573		(19,590	)		48,983	12 yrs
Gulf Coast		262,772		(46,791	)		215,981		262,772		(35,323	)		227,449	20 - 25 yrs
Total	$	771,935	$	(168,168	)	$	603,767	$	738,146	$	(124,568	)	$	613,578

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

12. Goodwill and Intangible Assets (Continued)

        Estimated future amortization expense related to the intangible assets at December 31, 2011 is as follows (in thousands):

Year ending December 31,
2012	$	43,940
2013		43,940
2014		43,940
2015		43,940
2016		43,940
Thereafter		384,067
	$	603,767

13. Impairment of 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 a segment level and at lower levels where cash flows for specific assets can be identified.

        An analysis completed during 2009 indicated that the future estimated operating cash flows could be at or below zero for Wirth Gathering. Wirth Gathering'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 expense.

14. Accrued Liabilities and Other Long-Term Liabilities

        Accrued liabilities as of December 31, 2011 and 2010 consist of the following (in thousands):

	December 31, 2011		December 31, 2010
Accrued property, plant and equipment	$	87,098	$	65,908
Interest		27,458		26,607
Product and operations		22,969		31,241
Employee compensation		12,600		9,167
Taxes (other than income tax)		9,914		8,670
Other		11,412		12,276
Total accrued liabilities	$	171,451	$	153,869

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

14. Accrued Liabilities and Other Long-Term Liabilities (Continued)

        Other long-term liabilities as of December 31, 2011 and 2010 consist of the following (in thousands):

	December 31, 2011		December 31, 2010
SMR Liability (see Note 5)	$	91,851	$	93,909
Deferred revenue		19,383		4,018
Asset retirement obligation		6,818		4,029
Other		3,304		3,393
Total other long-term liabilities	$	121,356	$	105,349

15. 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, 2010 to December 31, 2011 (in thousands):

	December 31, 2011		December 31, 2010
Beginning asset retirement obligation	$	4,029	$	2,877
Liabilities incurred		1,599		915
Accretion expense		1,190		237
Ending asset retirement obligation	$	6,818	$	4,029

        At December 31, 2011, 2010 and 2009, 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.

        In addition to recorded asset retirement obligations, the Partnership has other asset retirement obligations related to certain gathering, processing and other assets as a result of environmental and other legal requirements. The Partnership is not required to perform such work until it permanently ceases operations of the respective assets. Because the Partnership considers the operational life of these assets to be indeterminable, an associated asset retirement obligation cannot be calculated and is not recorded.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Long-Term Debt

        Debt is summarized below (in thousands):

	December 31, 2011		December 31, 2010
Credit Facility
Revolving credit facility, 4.0% interest due September 2016	$	66,000	$	—
Senior Notes
2016 Senior Notes, 8.5% interest, net of discount of $0 and $642, respectively, issued July 2006 and due July 2016		—		274,358
2018 Senior Notes, 8.75% interest, net of discount of $129 and $924, respectively, issued April and May 2008 and due April 2018		80,983		499,076
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020		500,000		500,000
2021 Senior Notes, 6.5% interest, net of discount of $921, issued February and March 2011 and due August 2021		499,079		—
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022		700,000		—
Total long-term debt	$	1,846,062	$	1,273,434

Credit Facility

        The Partnership's Credit Facility has a current lending capacity of $900 million and provides for an uncommitted accordion feature whereby the Credit Facility may be increased from time to time by the Partnership upon the satisfaction of certain requirements by up to an aggregate of $250 million. The Credit Facility matures on September 7, 2016. The Partnership incurred approximately $2.1 million, $11.2 million, and $4.4 million of deferred financing costs associated with modifications of the Credit Facility during the years ended December 31, 2011, 2010 and 2009, respectively.

        The borrowings under the Credit Facility bear interest at a variable interest rate, plus basis points. The variable interest rate is based either on the London interbank market rate ("LIBO Rate Loans"), or the higher of (a) the prime rate set by the Facility's administrative agent, (b) the Federal Funds Rate plus 0.50% and (c) the rate for LIBO Rate Loans for a one month interest period plus 1% ("Alternate Base Rate Loans"). The basis points correspond to the Partnership's Total Leverage Ratio (which is the ratio of the Partnership's consolidated funded debt to the Partnership's adjusted consolidated EBITDA), ranging from 0.75% to 1.75% for Alternate Base Rate Loans and from 1.75% to 2.75% for LIBO Rate Loans. The Partnership may utilize up to $150 million of the Credit Facility for the issuance of letters of credit and $10 million for shorter-term swingline loans.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Long-Term Debt (Continued)

        Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants. Significant financial covenants under the Credit Facility include the Interest Coverage Ratio (as defined in the Credit Facility), which must be greater than 2.75 to 1.0, and the Total Leverage Ratio (as defined in the Credit Facility), which must be less than 5.25 to 1.0. As of December 31, 2011, the Partnership was in compliance with these covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by the Partnership's wholly-owned subsidiaries other than MarkWest Liberty Midstream and collateralized by substantially all of the Partnership's assets and those of its wholly-owned subsidiaries other than MarkWest Liberty Midstream. As of December 31, 2011, the Partnership had $66.0 million of borrowings outstanding and $19.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $814.7 million available for borrowing.

Senior Notes

        As of December 31, 2011, MarkWest Energy Partners, L.P. in conjunction with its wholly-owned subsidiary MarkWest Energy Finance Corporation (the "Issuers"), had the following series of senior notes outstanding: $81.1 million aggregate principal issued in April and May 2008 and due in April 2018; $500.0 million aggregate principal issued in November 2010 and due in November 2020; $500.0 million aggregate principal issued in February and March 2011, due August 2021; and $700.0 million of Senior aggregate principal issued in November 2011, due June 2022.

        2014 Senior Notes.    In October 2004, the Issuers completed a private placement, subsequently registered, of $225 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. In May 2009, the Issuers completed an additional private placement, subsequently registered, of $150 million in aggregate principal amount of 6.875% senior unsecured notes to qualified institutional buyers under Rule 144A under an indenture substantially similar to the indenture relating to the notes issued in October 2004. The 2014 Senior Notes were redeemed in the fourth quarter of 2010.

        2016 Senior Notes.    In July and October 2006, the Issuers completed a private placement, subsequently registered, of $275 million in aggregate principal amount of 8.5% senior unsecured notes due 2016 ("2016 Senior Notes") to qualified institutional buyers. The 2016 Senior Notes were redeemed in the first and third quarters of 2011.

        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 unsecured notes to qualified institutional buyers under Rule 144A. The 2018 Senior Notes mature on April 15, 2018, and interest is payable semi-annually in arrears on April 15 and October 15, commencing October 15, 2008. In May 2008, the Partnership completed the placement of an additional $100 million pursuant to the indenture to the 2018 Senior Notes. The notes issued in the April 2008 and May 2008 offerings are treated a single class of debt under this same indenture. The Partnership received combined proceeds of approximately $488.5 million, after including initial purchasers' premium and deducting the underwriting fees and the other expenses of the offering. Approximately $253.3 million and $165.6 million of the 2018 Senior Notes were redeemed in the fourth quarter and first quarter of 2011, respectfully.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Long-Term Debt (Continued)

        2020 Senior Notes.    In November 2010, the Issuers completed a public offering of $500 million in aggregate principal amount of 6.75% senior unsecured notes. The 2020 Senior Notes mature on November 1, 2020, and interest is payable semi-annually in arrears on May 1 and November 1, commencing May 1, 2011. The Partnership received proceeds of approximately $490.3 million after deducting the underwriting fees and the other third-party expenses associated with the offering.

        2021 Senior Notes.    On February 24, 2011, the Issuers completed a public offering of $300 million in aggregate principal amount of 6.5% senior unsecured notes, which were issued at par. On March 10, 2011, the Issuers completed a follow-on public offering of an additional $200 million in aggregate principal amount of 2021 Senior Notes, which were issued at 99.5% of par and are treated as a single class of debt securities under the same indenture as the 2021 Senior Notes issued on February 24, 2011. The 2021 Senior Notes mature on August 15, 2021, and interest is payable semi-annually in arrears on February 15 and August 15, commencing August 15, 2011. The Partnership received aggregate net proceeds of approximately $492 million from the 2021 Senior Notes offerings after deducting the underwriting fees and other third-party expenses associated with the offerings.

        2022 Senior Notes.    On November 3, 2011, the Issuers completed a public offering of $700 million in aggregate principal amount of 6.25% senior unsecured notes due June 2022. Interest on the 2022 Notes is payable semi-annually in arrears on June 15 and December 15, commencing June 15, 2012. The Partnership received aggregate net proceeds of approximately $688 million from the 2022 Senior Notes offerings, after deducting the underwriting fees and other third-party expenses.

        The proceeds from the issuance of the 2021 and 2022 Senior Notes were used to redeem $275 million of 2016 Senior Notes and $419 million of 2018 Senior Notes and to provide additional working capital for general partnership purposes. The proceeds from the issuance of the 2020 Senior Notes were used to redeem the 2014 Senior Notes, repay the Credit Facility and to provide additional working capital for general partnership purposes.

        The Partnership recorded a total pre-tax loss of approximately $79.0 million during 2011 related to the redemption of the 2016 Senior Notes and 2018 Senior Notes. The pre-tax loss consisted of approximately $7.6 million related to the non-cash write-off of the unamortized discount and deferred finance costs and approximately $71.4 million related to the payment of tender premiums and third party expenses. The loss is recorded in Loss on redemption of debt in the accompanying Consolidated Statements of Operations.

        The Partnership recorded a total pre-tax loss of approximately $46.3 million in the fourth quarter of 2010 related to the redemption of the senior notes issued in October 2004 and May 2009. The pre-tax loss consisted of approximately $36.6 million related to the non-cash write-off of the unamortized discount and deferred finance costs and approximately $9.7 million related to the payment of premiums. The loss is recorded in Loss on redemption of debt in the accompanying Consolidated Statements of Operations.

        The Issuers have no independent operating assets or operations. All wholly-owned subsidiaries, other than MarkWest Energy Finance Corporation and MarkWest Liberty Midstream, guarantee the Senior Notes, jointly and severally and fully and unconditionally. The Partnership's less than wholly-owned subsidiaries do not guarantee the Senior Notes (see Note 25 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

16. Long-Term Debt (Continued)

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 Credit Facility.

        The indentures governing the Senior Notes limit the activity of the Partnership and the restricted subsidiaries identified in the indentures. 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 terminate, in which case the Partnership and its subsidiaries will cease to be subject to such terminated covenants.

        As of December 31, 2011, there are no minimum principal payments on Senior Notes due during the next five years. The full $1,781 million principal amounts for Senior Notes are due between 2018 and 2022. The $66 million of borrowings outstanding under the Credit Facility as of December 31, 2011 is due in 2016.

17. Equity

        The Partnership Agreement stipulates the circumstances under which the Partnership is authorized to issue new capital, maintain capital accounts and distribute cash and 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 has the discretion to establish cash reserves 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 up to the next four quarters.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

17. Equity (Continued)

        The quarterly cash distributions applicable to 2011, 2010 and 2009 were as follows:

Quarter Ended	Distribution Per Common Unit		Declaration Date		Record Date		Payment Date
December 31, 2011	$	0.76		January 26, 2012		February 6, 2012		February 14, 2012
September 30, 2011	$	0.73		October 18, 2011		November 7, 2011		November 14, 2011
June 30, 2011	$	0.70		July 21, 2011		August 1, 2011		August 12, 2011
March 31, 2011	$	0.67		April 21, 2011		May 2, 2011		May 13, 2011
December 31, 2010	$	0.65		January 27, 2011		February 7, 2011		February 14, 2011
September 30, 2010	$	0.64		October 27, 2010		November 8, 2010		November 12, 2010
June 30, 2010	$	0.64		July 22, 2010		August 2, 2010		August 13, 2010
March 31, 2010	$	0.64		April 22, 2010		May 3, 2010		May 14, 2010
December 31, 2009	$	0.64		January 26, 2010		February 5, 2010		February 12, 2010
September 30, 2009	$	0.64		October 22, 2009		November 2, 2009		November 13, 2009
June 30, 2009	$	0.64		July 23, 2009		August 3, 2009		August 14, 2009
March 31, 2009	$	0.64		April 23, 2009		May 4, 2009		May 15, 2009

Equity Offerings

        On June 10, 2009, the Partnership completed a public offering of approximately 3.34 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option. Net proceeds after deducting underwriters' fees and other third-party expenses were approximately $57.7 million.

        On August 18, 2009, the Partnership completed a public offering of approximately 6.03 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option. Net proceeds after deducting underwriters' fees and other third-party expenses were approximately $120.9 million.

        On April 6, 2010, the Partnership completed a public offering of approximately 4.9 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option. Net proceeds after deducting underwriters' fees and other third-party expenses were approximately $142.3 million.

        On January 14, 2011, the Partnership completed a public offering of approximately 3.45 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriter's over-allotment option. Net proceeds after deducting underwriter's fees and other third-party expenses were approximately $138.2 million and were used to partially fund the ongoing capital expenditure program, including a portion of the costs associated with the Langley Acquisition.

        On July 13, 2011, the Partnership completed a public offering of approximately 4.0 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option. Net proceeds after deducting underwriters' fees and other third-party expenses were approximately $185.1 million.

        On October 13, 2011, the Partnership completed a public offering of approximately 5.75 million newly issued common units representing limited partner interests, which includes the full exercise of the

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17. Equity (Continued)

underwriters' over-allotment option. Net proceeds after deducting underwriters' fees and other third-party expenses were approximately $251 million.

        On December 19, 2011, we completed a public offering of 10.0 million newly issued common units representing limited partner interests. Total net proceeds of approximately $521 million were used to partially fund the cash consideration to acquire the remaining 49% interest in MarkWest Liberty Midstream. On January 13, 2012, we issued an additional 0.7 million units to cover the exercise of the underwriters' over-allotment option. Total net proceeds of approximately $38 million were used to fund our growth capital program.

        Net proceeds from equity offerings, unless specifically identified otherwise, were used to repay borrowings under the Credit Facility and to provide working capital for general partnership purposes.

Class B Units Issuance

        The Partnership issued approximately 19,954,000 Class B units to M&R as part of our acquisition of the non-controlling interest in MarkWest Liberty Midstream which was effective December 31, 2011. See Note 4 for further discussion of the acquisition. The Class B units will convert to common units on a one-for-one basis in five equal installments beginning on July 1, 2013 and each of the first four anniversaries of such date. Class B units (i) are not entitled to participate in any distributions of available cash prior to their conversion and (ii) 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) other than those matters that disproportionately and adversely affect the rights and preferences of the Class B units. Upon conversion of the Class B units, M&R's right to vote as a common unitholder of the Partnership will be limited to a maximum of 5% of the Partnership's outstanding Common Units. Once converted, M&R has the right to participate in underwritten offerings undertaken by the Partnership up to 20% of the total number of common units offered. M&R also has limited rights to distribute an aggregate of 2,500,000 common units to its members and their limited partners beginning in 2016, and EMG Liberty and certain of its affiliates will have the right to demand that we conduct up to three underwritten offerings beginning in 2017, but restricted to no more than one offering in any twelve-month period. Except as described above, M&R is not permitted to transfer its Class B units or Converted Units without the prior written consent of the Board.

18. 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

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18. Commitments and Contingencies (Continued)

financial statements and that none of these actions, either individually or in the aggregate, will have a material adverse effect on our financial condition, liquidity or results of operation.

        In June 2006, the Pipeline and Hazardous Materials Safety Administration 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 of the Partnership, 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. In March 2011, MarkWest received an order assessing a penalty solely against Equitable for count one of the NOPV in the amount of $0.5 million and assessing a penalty jointly and severally against MarkWest and Equitable for four of the other counts in the NOPV in the amount of $0.2 million. In March 2011, the parties filed separate petitions for reconsideration. In January 2012, the Agency issued an order that dismissed the penalty assessed solely against Equitable but retained the $0.2 million penalty assessed jointly and severally against MarkWest and Equitable. MarkWest did not appeal the Agency's decision and paid the entire penalty.

Contract Contingencies

        Certain natural gas processing arrangements in our Liberty and Northeast segments require the Partnership to construct new natural gas processing plants and NGL pipelines and contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. The Partnership has experienced a couple of months' delays in the construction of one processing facility in our Liberty Segment due to inabilities or delays in obtaining requisite permits, as well as due to extreme weather events. The requisite permits have subsequently been issued and construction has re-commenced. Delay charges could be up to $1.0 million for each month (pro-rated for partial months) that the Partnership does not achieve certain intermediate and final completion construction milestones, other than delays due to force majeure. The Partnership currently estimates the construction completion dates of the processing plant will occur approximately two months after the milestone dates specified in the applicable agreement, but the Partnership has made a force majeure claim as the delays were a direct result of permit delays and weather which are force majeure events under the applicable contract. The customer has reserved its rights to dispute the claim, but the Partnership's management believes it has a convincing legal position and believes that it is unlikely that its force majeure claim would not prevail if contested.

Lease and Other Contractual Obligations

        The Partnership has various non-cancellable operating lease agreements and a long-term propane storage agreement expiring at various times through fiscal year 2040. Annual expense under these agreements was $15.0 million, $18.4 million and $18.6 million for the years ended December 31, 2011,

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18. Commitments and Contingencies (Continued)

2010 and 2009, respectively. The minimum future payments under these agreements as of December 31, 2011 are as follows (in thousands):

Year ending December 31,
2012	$	10,299
2013		8,688
2014		7,793
2015		7,606
2016		7,334
2017 and thereafter		17,663
	$	59,383

SMR Transaction

        On September 1, 2009, the Partnership entered into a product supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the product processed by the SMR (see Note 5 for further discussion of this agreement and the related SMR Transaction). The product received under this agreement is sold to a refinery customer pursuant to a corresponding long-term agreement. The minimum amounts payable annually under the product supply agreement, excluding the potential impact of inflation adjustments per the agreement, are as follows (in thousands):

Year ending December 31,
2012	$	17,412
2013		17,412
2014		17,412
2015		17,412
2016		17,412
2017 and thereafter		230,029
Total minimum payments		317,089
Less: Services element		121,295
Less: Interest		101,885
Total SMR liability		93,909
Less: Current portion of SMR Liability		2,058
Long-term portion of SMR Liability	$	91,851

19. Lease Operations

        Based on the terms of certain natural gas gathering, transportation, and processing agreements, the Partnership is considered to be the lessor under several implicit operating lease arrangements in accordance with GAAP. The Partnership's primary implicit lease operations relate to a natural gas gathering agreement in the Liberty segment for which it earns a fixed-fee for providing gathering services to a single producer using a dedicated gathering system. As the gathering system is expanded the fixed-fee charged to the producer is adjusted to include the additional gathering assets in the lease.

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19. Lease Operations (Continued)

The primary term of the natural gas gathering arrangement expires in 2024 and will continue thereafter on a year to year basis until terminated by either party. Another significant implicit lease relates to natural gas processing agreement in the Northeast segment for which the Partnership earns a minimum monthly fee for providing processing services to a single producer using a dedicated processing plant. The primary term of the natural gas processing agreement expires in 2022 and may be extended at the option of the producer for up to two successive five year terms.

        The Partnership's revenue from its implicit lease arrangements, excluding executory costs, totaled approximately $67.4 million, $32.2 million and $14.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. The Partnership's implicit lease arrangements do not contain any significant contingent rental provisions. The following is a schedule of minimum future rentals on the non-cancellable operating leases as of December 31, 2011 (in thousands):

Year ending December 31,
2012	$	61,081
2013		61,081
2014		61,081
2015		59,794
2016		59,794
2017 and thereafter		352,760
Total minimum future rentals	$	655,591

        The following schedule provides an analysis of the Partnership's investment in assets held for operating lease by major classes as of December 31, 2011 and 2010 (in thousands):

	December 31, 2011			December 31, 2010
Natural gas gathering and NGL transportation pipelines and facilities	$	479,567		$	264,669
Construction in progress		38,386			60,170
Property, plant and equipment		517,953			324,839
Less: accumulated depreciation		(46,006	)		(21,742	)
Total property, plant and equipment, net	$	471,947		$	303,097

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. Incentive Compensation Plans

        The following table summarizes the share-based compensation plans administered by the Compensation Committee of the Board ("Compensation Committee") that were active during the periods presented in the accompanying Consolidated Statements of Operations:

Share-based compensation plan	Award Classification	Further awards authorized for issuance under plan as of December 31, 2011	Awards outstanding under the plan as of December 31, 2011	Final Year of Activity
2008 Long-Term Incentive Plan ("2008 LTIP")	Equity	Yes	Yes		N/A
2006 Hydrocarbon Stock Incentive Plan ("2006 Hydrocarbon Plan")	Equity	No	No		2010
Long-Term Incentive Plan ("2002 LTIP")	Liability	No	No		2011
1996 Hydrocarbon Stock Incentive Plan ("1996 Hydrocarbon Plan")	Equity	No	No		2009

Compensation Expense

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

	Year ended December 31,
	2011		2010		2009
Phantom units	$	13,479	$	15,319	$	7,448
Distribution equivalent rights(1)		446		1,465		1,324
Total compensation expense	$	13,925	$	16,784	$	8,772

(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, 2011, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP was approximately $12.1 million, with a weighted average remaining vesting period of approximately 0.8 years. Total compensation expense not yet recognized includes approximately $0.2 million related to the TSR Performance Units (see discussion of TSR Performance Units below).

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20. Incentive Compensation Plans (Continued)

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.

        TSR Performance Units.    In April 2010, the Board granted 282,000 performance phantom units ("TSR Performance Units") under the 2008 LTIP to senior executives and other key employees. The TSR Performance Units are classified as equity awards and do not contain distribution equivalent rights. The TSR Performance Units were scheduled to vest in equal installments on January 31, 2011 and January 31, 2012, subject to the Partnership's relative total unitholder return (unit price appreciation and distribution performance) over the three-year calendar period prior to the scheduled vesting date compared to the total unitholder return of a defined group of peer companies over the same period ("Market Criteria"). Zero TSR Performance Units vest if the Partnership's relative ranking is less than the 40^th percentile; 50% of the TSR Performance Units vest if the Partnership's relative ranking is in the 40^th to 60^th percentile; 75% of the TSR Performance Units vest if the Partnership's relative ranking is in the 60^th to 80^th percentile; and 100% of the TSR Performance Units vest if the Partnership's relative ranking is in the 80^th to 100^th percentile. Additionally, the Board can increase or decrease the number of units to vest by up to 25% of the number of units that would otherwise vest based on the Performance Criteria. In January 2011 and 2012, 141,000 TSR performance vested based on the Market Criteria and the Board exercised its discretion to issue and immediately vest an additional 35,250 units.

        The effect of vesting conditions is that 75% of the TSR Performance Units vested based solely on the Partnership's actual performance with regards to the Market Criteria. The remaining 25% of the TSR Performance Units vested based on a combination of the Market Criteria and the Performance Criteria. Compensation expense related to the TSR Performance Units that vested solely based on the Market Criteria was recognized over the requisite service period based on the fair value of the units as of the grant date. However, a grant date, as defined by GAAP, was not established for the TSR Performance Units that vest based on a combination of the Market Criteria and Performance Criteria until the Board exercised its discretion because the Performance Criteria prevents a mutual understanding of the key terms of the award. Therefore, compensation expense related to this portion of the TSR Performance Units was recognized over the requisite service period based on the fair value of the units as of each reporting date. The requisite service period for all TSR Performance Units began in April 2010 when the Board approved the awards. TSR Compensation expense recognized related to TSR Performance Units was approximately $4.8 million and $4.5 million for the years ended December 31, 2011 and 2010, respectively.

        The fair value of the TSR Performance Units was measured at each appropriate measurement date using a Monte Carlo simulation model that estimated the most likely outcome based on the terms of the award. The key inputs in the model include the market price of the Partnership's common units as of the valuation date, the historical volatility of the market price of the Partnership's common units, the

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20. Incentive Compensation Plans (Continued)

historical volatility of the market price of the common units or common stock of the peer companies, and the correlation between changes in the market price of the Partnership's common units and those of the peer companies.

        Unrestricted Units.    In January 2010, the Board granted 166,000 unrestricted units to senior executives and other key employees under the 2008 LTIP. The unrestricted units vested immediately and the Partnership recognized approximately $4.8 million of expense related to these units.

        Performance Units.    Phantom units containing performance vesting criteria ("Performance Units") were granted to senior executives and other key employees under the 2008 LTIP in 2008 and 2009. The Performance Units vest on a performance-based schedule over a three-year period, and vesting of these units occurs if the Partnership achieves established financial performance goals determined by the Compensation Committee. Management conducts an analysis on an ongoing basis to assess the probability of meeting the established performance goals and records compensation expense as required. As of December 31, 2011, there are 141,000 Performance Units outstanding with a grant date fair value of $1.2 million. The outstanding Performance Units did not vest. Compensation expense recorded for the Performance Units expected to vest was zero for the years ended December 31, 2011 and 2010, and approximately $0.5 million year ended December 31, 2009.

2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan

        On February 21, 2008, the 25,897 outstanding shares of restricted stock granted under the 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan were converted to 49,354 phantom units in connection with the Merger. The converted phantom unit awards remained outstanding under the terms of the 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan until their respective settlement dates. The last converted phantom units outstanding under the 2006 Hydrocarbon Plan or the 1996 Hydrocarbon Plan vested on January 31, 2010 and 2009, respectively.

Summary of Equity Awards

        Awards under the 2008 LTIP, and historically the 2006 Hydrocarbon Plan and the 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. Phantom unit awards generally vest in equal tranches over a three-year period. For service-based awards, compensation expense related to each tranche is recognized over its requisite service period, reduced for an estimate of expected forfeitures. 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 assumes 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 $6.0 million, $3.4 million, and $1.1 million during the years ended December 31, 2011, 2010 and 2009, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

20. Incentive Compensation Plans (Continued)

        The following is a summary of all phantom unit activity under the 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan for the years ended December 31, 2011, 2010 and 2009:

	Number of Units			Weighted-average Grant-date Fair Value(1)
Unvested at January 1, 2009		909,306		$	31.80
Granted		442,035			8.64
Vested		(309,052	)		31.93
Forfeited		(65,048	)		20.96
Unvested at December 31, 2009		977,241			22.00
Granted (includes 282,000 TSR units)		736,688			30.25
Vested		(363,502	)		26.85
Forfeited		(21,267	)		19.28
Unvested at December 31, 2010 (includes 282,000 TSR units)		1,329,160			25.29
Granted (includes 35,250 TSR units)		309,629			42.75
Vested (includes 176,250 TSR units)		(396,934	)		27.04
Forfeited		(306,346	)		31.66
Unvested at December 31, 2011 (includes 141,000 TSR units)(2)		935,509			28.50

(1)

The calculation of the weighted average grant-date fair value for units granted during the year ended December 31, 2010 and unvested as of December 2010 and December 2011 is recalculated to include the fair value as of December 31, 2011 for 35,250 TSR Performance Units. A grant date, as defined by GAAP, has not been established for these units.

(2)

Includes 141,000 Performance Units that did not vest and were forfeited in January 2012.

        The total fair value and intrinsic value of the phantom units vested under the 2008 LTIP was $10.7 million, $9.8 million, and $9.9 million during the years ended December 31, 2011, 2010, and 2009, respectively. The total fair value and intrinsic value of the TSR Performance Units vested during the year ended December 31, 2011 was $4.9 million.

2002 LTIP

        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 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 assumes the income tax withholding obligations related to the vesting. The Partnership

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20. Incentive Compensation Plans (Continued)

received no proceeds 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 $0.4 million, $0.4 million and $0.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

        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, 2009		145,927		$	31.45
Vested		(69,652	)		29.94
Forfeited		(6,720	)		33.64
Unvested at December 31, 2009		69,555			32.75
Vested		(44,942	)		32.15
Forfeited		(968	)		34.00
Unvested at December 31, 2010		23,645			33.83
Vested		(23,645	)		33.83
Unvested at December 31, 2011		—			—

        The total fair value and intrinsic value of the phantom units vested under the 2002 LTIP was $1.0 million, $1.3 million, and $0.9 million during the years ended December 31, 2011, 2010, and 2009, respectively.

Tax effects of share-based compensation

        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. Additional paid-in capital 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 and are included as Excess tax benefits related to share-based compensation in the accompanying Consolidated Statements of Cash Flows.

21. 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 $2.7 million, $2.3 million and $1.8 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. Income Tax

        As discussed in Note 2, all changes in the tax bases of assets and liabilities are allocated among continued operations and items charged or credited directly to equity. During the fourth quarter of 2011, the Partnership determined it had understated its deferred tax liability related to its investment in consolidated subsidiaries for timing differences created as a result of items charged or credited directly to equity. The Partnership evaluated the materiality of the error from a qualitative and quantitative perspective and concluded that the error was not material to any prior period.

        In the accompanying Consolidated Balance Sheet as of December 31, 2010, the correction of the error discussed above results in an increase in long-term deferred tax liabilities and a corresponding decrease in equity of $77.5 million as compared to the amounts previously reported. In the accompanying Consolidated Statement of Changes in Equity, the correction resulted in a cumulative decrease in the balances associated with common units and total equity of $77.5 million, $69.8 million, and $59.6 million as of December 31, 2010, 2009, and 2008, respectively. This cumulative adjustment gives effect to the Deferred tax impact of equity transactions, which was previously not reported, of $7.6 million and $10.2 million for the years ended December 31, 2010 and 2009, respectively.

        The components of the provision for income tax expense (benefit) are as follows (in thousands):

	Year ended December 31,
	2011			2010			2009
Current income tax expense:
Federal	$	15,039		$	5,850		$	6,525
State		2,539			1,805			1,547
Total current		17,578			7,655			8,072
Deferred income tax (benefit) expense:
Federal		(4,732	)		(3,870	)		(43,409	)
State		803			(596	)		(6,679	)
Total deferred		(3,929	)		(4,466	)		(50,088	)
Provision for income tax	$	13,649		$	3,189		$	(42,016	)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. 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, 2011, 2010 and 2009 is as follows (in thousands):

Year ended December 31, 2011:

	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax.	$	3,813		$	124,087		$	(8,006	)	$	119,894
Federal statutory rate		35	%		0	%		0	%
Federal income tax at statutory rate		1,335			—			—			1,335
Permanent items		36			—			—			36
State income taxes net of federal benefit		102			2,742			—			2,844
Current year change in valuation allowance		(64	)		—			—			(64	)
Prior period adjustments and tax rate changes		163			—			—			163
Provision on income from Class A units(1)		9,323			—			—			9,323
Other		12			—			—			12
Provision for income tax	$	10,907		$	2,742		$	—		$	13,649

Year ended December 31, 2010:

	Corporation			Partnership			Eliminations			Consolidated
(Loss) income before provision for income tax	$	(8,120	)	$	47,761		$	(5,350	)	$	34,291
Federal statutory rate		35	%		0	%		0	%
Federal income tax at statutory rate		(2,842	)		—			—			(2,842	)
Permanent items		20			—			—			20
State income taxes net of federal benefit		(272	)		1,299			—			1,027
Current year change in valuation allowance		(1,022	)		—			—			(1,022	)
Prior period adjustments and tax rate changes		70			—			—			70
Provision on income from Class A units(1)		5,753			—			—			5,753
Other		183			—			—			183
Provision for income tax	$	1,890		$	1,299		$	—		$	3,189

141

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. Income Tax (Continued)

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	$	(40,577	)	$	(1,439	)	$	—		$	(42,016	)

(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. This amount includes intra period allocations to continued operations and excludes allocations to equity.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. Income Tax (Continued)

        The deferred tax assets and liabilities resulting from temporary book-tax differences are comprised of the following (in thousands):

	December 31,
	2011			2010
Current deferred tax assets:
Accruals and reserves	$	78		$	64
Derivative instruments		14,807			16,031
Current deferred tax assets		14,885			16,095
Current deferred tax liabilities:
Derivative instruments		—			16
Current deferred tax liabilities		—			16
Current subtotal		14,885			16,079
Long-term deferred tax assets:
Accruals and reserves		48			34
Derivative instruments		20,301			14,241
Phantom unit compensation		2,103			1,684
Capital loss carryforward		971			975
State net operating loss carryforward		101			156
Long-term deferred tax assets		23,524			17,090
Valuation allowance		(977	)		(1,036	)
Net long-term deferred tax assets		22,547			16,054
Long-term deferred tax liabilities:
Property, plant and equipment and intangibles		2,123			3,529
Phantom unit compensation		—			31
Investment in affiliated groups		114,088			100,345
Derivative instruments		—			30
Long-term deferred tax liabilities		116,211			103,935
Long-term subtotal		(93,664	)		(87,881	)
Net deferred tax liability	$	(78,779	)	$	(71,802	)

        Significant judgment is required in evaluating tax positions and determining the Corporation's provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. However, the Corporation did not have any material uncertain tax positions for the years ended December 31, 2011, 2010 or 2009. As of December 31, 2011, the Corporation had state net operating loss carryforwards of approximately $0.1 million that expire between 2024 and 2027. 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

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MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

22. Income Tax (Continued)

December 31, 2011, the Corporation had a capital loss carryforward of approximately $1.0 million that expires in 2014. The Corporation does not anticipate utilizing this carryforward and has provided a 100% valuation allowance against this long-term deferred tax asset. While the Corporation's consolidated federal tax return and any significant state tax returns are not currently under examination, the tax years 2007 through 2010 remain open to examination by the major taxing jurisdictions to which the Corporation is subject.

23. Earnings (Loss) Per Common Unit

        The following table shows the computation of basic and diluted net (loss) income per common unit, for the years ended December 31, 2011, 2010 and 2009, respectively, and the weighted average units used to compute diluted net (loss) income per common unit (in thousands, except per unit data):

	Year ended December 31,
	2011(2)		2010			2009
Net income (loss) attributable to the Partnership	$	60,695	$	467		$	(118,668	)
Less: Income allocable to phantom units		1,749		1,308			1,518
Income (loss) available for common unitholders	$	58,946	$	(841	)	$	(120,186	)
Weighted average common units outstanding—basic		78,466		70,128			60,957
Effect of dilutive instruments(1)		153		—			—
Weighted average common units outstanding—diluted		78,619		70,128			60,957
Net income (loss) attributable to the Partnership's common unitholders per common unit:
Basic	$	0.75	$	(0.01	)	$	(1.97	)
Diluted	$	0.75	$	(0.01	)	$	(1.97	)

(1)

For the years ended December 31, 2011 and 2010, dilutive instruments include TSR Phantom Units and are based on the number of units, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period. For the year ended December 31, 2010, 195 units were excluded from the calculation of diluted units because the impact was anti-dilutive. See Note 20 for further discussion of TSR Phantom Units.

(2)

The Class B units had no impact to the earnings per unit calculation as they were issued on December 31, 2011 and as such were not outstanding for any portion of the fiscal year and were not allocated any of the Net income (loss) attributable to the Partnership.

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MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

24. 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 the following segments: Southwest, Northeast, Liberty and Gulf Coast. The Southwest segment provides gathering, processing, transportation and storage services. The Northeast segment provides gathering, processing, transportation, fractionation and storage services. The Liberty segment provides gathering, processing, transportation, fractionation and storage services. The Gulf Coast segment provides processing, transportation, fractionation and storage services.

        The Partnership prepares segment information in accordance with GAAP. Certain items below Income (loss) from operations in the accompanying Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any gains (losses) from derivative instruments are not allocated to individual segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. 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, 2011, 2010 and 2009 (in thousands).

Year ended December 31, 2011:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	935,513	$	268,884	$	248,949	$	96,473	$	1,549,819
Purchased product costs		506,911		91,612		83,847		—		682,370
Net operating margin		428,602		177,272		165,102		96,473		867,449
Facility expenses		82,761		27,126		34,913		38,436		183,236
Portion of operating income attributable to non-controlling interests		5,431		—		63,731		—		69,162
Operating income before items not allocated to segments	$	340,410	$	150,146	$	66,458	$	58,037	$	615,051
Capital expenditures	$	103,968	$	51,280	$	388,850	$	2,093	$	546,191
Capital expenditures not allocated to segment										5,090
Total capital expenditures									$	551,281

145

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

24. Segment Information (Continued)

Year ended December 31, 2010:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	665,768	$	384,724	$	105,911	$	85,160	$	1,241,563
Purchased product costs		308,960		252,827		16,840		—		578,627
Net operating margin		356,808		131,897		89,071		85,160		662,936
Facility expenses		81,772		19,513		24,028		33,337		158,650
Portion of operating income attributable to non-controlling interests		6,440		—		26,126		—		32,566
Operating income before items not allocated to segments	$	268,596	$	112,384	$	38,917	$	51,823	$	471,720
Capital expenditures	$	114,109	$	2,179	$	332,793	$	3,947	$	453,028
Capital expenditures not allocated to segments										5,640
Total capital expenditures									$	458,668

Year ended December 31, 2009:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	492,369	$	260,529	$	47,968	$	57,769	$	858,635
Purchased product costs		221,021		175,326		12,479		—		408,826
Net operating margin		271,348		85,203		35,489		57,769		449,809
Facility expenses		73,621		20,339		16,268		16,094		126,322
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

146

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

24. 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, 2011, 2010 and 2009 (in thousands):

	Year ended December 31,
	2011			2010			2009
Total segment revenue	$	1,549,819		$	1,241,563		$	858,635
Derivative loss not allocated to segments		(29,035	)		(53,932	)		(120,352	)
Revenue deferral adjustment(1)		(15,385	)		—			—
Total revenue	$	1,505,399		$	1,187,631		$	738,283
Operating income before items not allocated to segments	$	615,051		$	471,720		$	314,237
Portion of operating income attributable to non-controlling interests		69,162			32,566			9,250
Derivative loss not allocated to segments		(75,515	)		(80,350	)		(188,862	)
Revenue deferral adjustment(1)		(15,385	)		—			—
Compensation expense included in facility expenses not allocated to segments		(1,781	)		(1,890	)		(1,032	)
Facility expenses adjustments(2)		11,419			9,091			377
Selling, general and administrative expenses		(81,229	)		(75,258	)		(63,728	)
Depreciation		(149,954	)		(123,198	)		(95,537	)
Amortization of intangible assets		(43,617	)		(40,833	)		(40,831	)
Loss on disposal of property, plant and equipment		(8,797	)		(3,149	)		(1,677	)
Accretion of asset retirement obligations		(1,190	)		(237	)		(198	)
Impairment of goodwill and long-lived assets		—			—			(5,855	)
Income (loss) from operations		318,164			188,462			(73,856	)
(Loss) earnings from unconsolidated affiliates		(1,095	)		1,562			3,505
Gain on sale of unconsolidated affiliate		—			—			6,801
Interest income		422			1,670			349
Interest expense		(113,631	)		(103,873	)		(87,419	)
Amortization of deferred financing costs and discount (a component of interest expense)		(5,114	)		(10,264	)		(9,718	)
Derivative gain related to interest expense		—			1,871			2,509
Loss on redemption of debt		(78,996	)		(46,326	)		—
Miscellaneous income, net		144			1,189			2,459
Income (loss) before provision for income tax	$	119,894		$	34,291		$	(155,370	)

(1)

Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership expects to perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and, therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the year ended December 31, 2011, approximately $7.2 million and

147

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

24. Segment Information (Continued)

$8.2 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts is expected to decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

(2)

Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR, which is included in facility expenses for the purposes of evaluating the performance of the Gulf Coast segment. The increase is due to a full year of interest expense related to the SMR in 2011 compared to approximately nine months of SMR interest expense in 2010.

        The tables below present information about segment assets as of December 31, 2011, 2010, and 2009 (in thousands):

	December 31, 2011		December 31, 2010		December 31, 2009
Southwest	$	1,701,919	$	1,646,607	$	1,637,749
Northeast		533,591		244,219		249,804
Liberty		1,114,654		743,943		373,127
Gulf Coast		553,043		573,456		587,830
Total segment assets		3,903,207		3,208,225		2,848,510
Assets not allocated to segments:
Certain cash and cash equivalents		66,212		49,776		73,184
Fair value of derivatives		24,790		4,762		24,631
Investment in unconsolidated affiliate		27,853		28,688		29,633
Other(1)		48,363		41,911		38,779
Total assets	$	4,070,425	$	3,333,362	$	3,014,737

(1)

As of December 31, 2011, includes corporate fixed assets, deferred financing costs, income tax receivable, deferred tax asset and other corporate assets not allocated to segments. As of December 31, 2010 and 2009, includes corporate fixed assets, deferred financing costs, income tax receivable, receivables and other corporate assets not allocated to segments.

25. Supplemental Condensed Consolidating Financial Information

        MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of December 31, 2011, the Partnership's obligations under the outstanding Senior Notes (see Note 16) were fully, jointly and severally guaranteed, by all of its wholly-owned subsidiaries other than MarkWest Liberty Midstream. The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the guarantee under the indentures. 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

148

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

25. Supplemental Condensed Consolidating Financial Information (Continued)

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. Condensed consolidating financial information for MarkWest Energy Partners and its combined guarantor and combined non-guarantor subsidiaries as of

149

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

25. Supplemental Condensed Consolidating Financial Information (Continued)

December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 is as follows (in thousands):

Condensed Consolidating Balance Sheets

	As of December 31, 2011
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	22	$	99,580	$	17,414	$	—		$	117,016
Restricted cash		—		—		26,193		—			26,193
Receivables and other current assets		7,097		232,010		55,098		(5	)		294,200
Intercompany receivables		19,981		40,519		22,193		(82,693	)		—
Fair value of derivative instruments		—		8,015		683		—			8,698
Total current assets		27,100		380,124		121,581		(82,698	)		446,107
Total property, plant and equipment, net		4,012		1,714,857		1,163,226		(17,788	)		2,864,307
Other long-term assets:
Investment in unconsolidated affiliate		—		27,853		—		—			27,853
Investment in consolidated affiliates		3,071,124		1,097,350		—		(4,168,474	)		—
Intangibles, net of accumulated amortization		—		603,224		543		—			603,767
Fair value of derivative instruments		—		16,092		—		—			16,092
Intercompany notes receivable		235,700		—		—		(235,700	)		—
Other long-term assets		41,492		70,434		373		—			112,299
Total assets(1)	$	3,379,428	$	3,909,934	$	1,285,723	$	(4,504,660	)	$	4,070,425
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	40,503	$	40,374	$	1,816	$	(82,693	)	$	—
Fair value of derivative instruments		—		90,551		—		—			90,551
Other current liabilities		38,775		219,622		92,930		(5	)		351,322
Total current liabilities		79,278		350,547		94,746		(82,698	)		441,873
Deferred income taxes		1,228		92,436		—		—			93,664
Intercompany notes payable		—		212,700		23,000		(235,700	)		—
Fair value of derivative instruments		—		65,403		—		—			65,403
Long-term debt, net of discounts		1,846,062		—		—		—			1,846,062
Other long-term liabilities		3,232		117,724		400		—			121,356
Equity:
Common Units		697,097		3,071,124		1,167,577		(4,256,489	)		679,309
Class B Units		752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries		—		—		—		70,227			70,227
Total equity		1,449,628		3,071,124		1,167,577		(4,186,262	)		1,502,067
Total liabilities and equity	$	3,379,428	$	3,909,934	$	1,285,723	$	(4,504,660	)	$	4,070,425

(1)

In accordance with the December 2011 amendment to the Partnership's Credit Facility, certain assets in the Liberty segment included in Total property, plant, and equipment, net are expected to be contributed from a non-guarantor subsidiary to a guarantor subsidiary by April 2012. The contributed assets would include only the natural gas processing facilities at the Partnership's Houston Complex and any other equipment related solely to these processing facilities.

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MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

25. Supplemental Condensed Consolidating Financial Information (Continued)

	As of December 31, 2010
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	63,850	$	3,600	$	—		$	67,450
Receivables and other current assets		1,708		172,209		52,834		—			226,751
Intercompany receivables		1,440,302		1,099		7,635		(1,449,036	)		—
Fair value of derivative instruments		—		4,345		—		—			4,345
Total current assets		1,442,010		241,503		64,069		(1,449,036	)		298,546
Total property, plant and equipment, net		4,623		1,512,763		812,898		(11,260	)		2,319,024
Other long-term assets:
Restricted cash		—		—		28,001		—			28,001
Investment in unconsolidated affiliate		—		28,688		—		—			28,688
Investment in consolidated affiliates		639,219		368,864		—		(1,008,083	)		—
Intangibles, net of accumulated amortization		—		613,000		578		—			613,578
Fair value of derivative instruments		—		417		—		—			417
Intercompany notes receivable		197,710		—		—		(197,710	)		—
Other long-term assets		32,587		12,139		382		—			45,108
Total assets	$	2,316,149	$	2,777,374	$	905,928	$	(2,666,089	)	$	3,333,362
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	672	$	1,447,799	$	565	$	(1,449,036	)	$	—
Fair value of derivative instruments		—		65,489		—		—			65,489
Other current liabilities		31,882		173,667		70,804		—			276,353
Total current liabilities		32,554		1,686,955		71,369		(1,449,036	)		341,842
Deferred income taxes		2,533		85,348		—		—			87,881
Intercompany notes payable		—		197,710		—		(197,710	)		—
Fair value of derivative instruments		—		66,290		—		—			66,290
Long-term debt, net of discounts		1,273,434		—		—		—			1,273,434
Other long-term liabilities		3,319		101,852		178		—			105,349
Equity:
Common Units		1,004,309		639,219		834,381		(1,484,860	)		993,049
Non-controlling interest in consolidated subsidiaries		—		—		—		465,517			465,517
Total equity		1,004,309		639,219		834,381		(1,019,343	)		1,458,566
Total liabilities and equity	$	2,316,149	$	2,777,374	$	905,928	$	(2,666,089	)	$	3,333,362

151

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

25. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Operations

	Year ended December 31, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	1,240,004		$	265,395		$	—		$	1,505,399
Operating expenses:
Purchased product costs		—			651,132			84,198			—			735,330
Facility expenses		—			128,612			39,171			(665	)		167,118
Selling, general and administrative expenses		46,903			31,015			9,011			(5,700	)		81,229
Depreciation and amortization		719			151,362			42,198			(708	)		193,571
Other operating expenses		673			9,030			284			—			9,987
Total operating expenses		48,295			971,151			174,862			(7,073	)		1,187,235
(Loss) income from operations		(48,295	)		268,853			90,533			7,073			318,164
Earnings from consolidated affiliates		288,870			44,425			—			(333,295	)		—
Loss on redemption of debt		(78,996	)		—			—			—			(78,996	)
Other expense, net		(91,612	)		(13,501	)		(558	)		(13,603	)		(119,274	)
Income before provision for income tax		69,967			299,777			89,975			(339,825	)		119,894
Provision for income tax expense		2,742			10,907			—			—			13,649
Net income		67,225			288,870			89,975			(339,825	)		106,245
Net income attributable to non-controlling interest		—			—			—			(45,550	)		(45,550	)
Net income attributable to the Partnership	$	67,225		$	288,870		$	89,975		$	(385,375	)	$	60,695

152

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

25. Supplemental Condensed Consolidating Financial Information (Continued)

	Year ended December 31, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Total revenue	$	—		$	1,063,621		$	124,010	$	—		$	1,187,631
Operating expenses:
Purchased product costs		—			589,403			16,937		—			606,340
Facility expenses		—			122,240			28,566		(652	)		150,154
Selling, general and administrative expenses		46,549			27,339			6,317		(4,947	)		75,258
Depreciation and amortization		594			136,781			27,054		(398	)		164,031
Other operating expenses		753			2,342			291		—			3,386
Total operating expenses		47,896			878,105			79,165		(5,997	)		999,169
(Loss) income from operations		(47,896	)		185,516			44,845		5,997			188,462
Earnings from consolidated affiliates		183,557			15,963			—		(199,520	)		—
Loss on redemption of debt		(46,326	)		—			—		—			(46,326	)
Other (expense) income, net		(82,000	)		(16,032	)		1,753		(11,566	)		(107,845	)
Income before provision for income tax		7,335			185,447			46,598		(205,089	)		34,291
Provision for income tax expense		1,299			1,890			—		—			3,189
Net income		6,036			183,557			46,598		(205,089	)		31,102
Net income attributable to non-controlling interest		—			—			—		(30,635	)		(30,635	)
Net income attributable to the Partnership	$	6,036		$	183,557		$	46,598	$	(235,724	)	$	467

153

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

25. Supplemental Condensed Consolidating Financial Information (Continued)

	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 consolidated affiliates		2,243			1,501			—		(3,744	)		—
Gain on sale of unconsolidated affiliate		—			6,801			—		—			6,801
Other (expense) income, net		(69,951	)		(12,692	)		3,997		(9,669	)		(88,315	)
(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)

25. Supplemental Condensed Consolidating Financial Information (Continued)

Condensed Consolidating Statements of Cash Flows

	Year ended December 31, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(126,782	)	$	410,762		$	137,961		$	(7,243	)	$	414,698
Cash flows from investing activities:
Restricted cash		—			—			2,006			—			2,006
Capital expenditures		(789	)		(162,517	)		(399,992	)		12,017			(551,281	)
Acquisitions		—			(230,728	)		—			—			(230,728	)
Equity investments		(47,295	)		(252,367	)		—			299,662			—
Distributions from consolidated affiliates		50,718			68,651			—			(119,369	)		—
Investment in intercompany notes, net		(37,990	)		—			—			37,990			—
Proceeds from disposal of property, plant and equipment		—			606			7,617			(4,773	)		3,450
Net cash flows used in investing activities		(35,356	)		(576,355	)		(390,369	)		225,527			(776,553	)
Cash flows from financing activities:
Proceeds from revolving credit facility		1,182,200			—			—			—			1,182,200
Payments of revolving credit facility		(1,116,200	)		—			—			—			(1,116,200	)
Proceeds from long-term debt		1,199,000			—			—			—			1,199,000
Payments of long-term debt		(693,888	)		—			—			—			(693,888	)
Payments of premiums on redemption of long-term debt		(71,377	)		—			—			—			(71,377	)
Proceeds from intercompany notes, net		—			14,990			23,000			(37,990	)		—
Payments for debt issuance costs, deferred financing costs and registration costs		(20,163	)		—			—			—			(20,163	)
Acquisition of non-controlling interest, including transaction costs		(997,601	)		—			—			—			(997,601	)
Contributions from parent, net		—			47,295			—			(47,295	)		—
Contributions to joint ventures, net		—			—			378,759			(252,367	)		126,392
Payments of SMR Liability		—			(1,875	)		—			—			(1,875	)
Proceeds from public equity offerings, net		1,095,488			—			—			—			1,095,488
Share-based payment activity		(6,354	)		1,084			—			—			(5,270	)
Payment of distributions		(218,398	)		(50,718	)		(135,537	)		119,368			(285,285	)
Intercompany advances, net		(190,547	)		190,547			—			—			—
Net cash flows provided by financing activities		162,160			201,323			266,222			(218,284	)		411,421
Net increase in cash		22			35,730			13,814			—			49,566
Cash and cash equivalents at beginning of year		—			63,850			3,600			—			67,450
Cash and cash equivalents at end of period	$	22		$	99,580		$	17,414		$	—		$	117,016

155

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

25. Supplemental Condensed Consolidating Financial Information (Continued)

	Year ended December 31, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(102,042	)	$	373,483		$	46,852		$	(5,965	)	$	312,328
Cash flows from investing activities:
Restricted cash		—			—			(28,001	)		—			(28,001	)
Capital expenditures		(1,924	)		(123,005	)		(347,231	)		13,492			(458,668	)
Equity investments		(44,346	)		(171,252	)		—			215,598			—
Distributions from consolidated affiliates		41,167			22,246			—			(63,413	)		—
Collection of intercompany notes, net		12,350			—			—			(12,350	)		—
Proceeds from disposal of property, plant and equipment		—			733			7,527			(7,527	)		733
Net cash flows provided by (used in) investing activities		7,247			(271,278	)		(367,705	)		145,800			(485,936	)
Cash flows from financing activities:
Proceeds from revolving credit facility		494,404			—			—			—			494,404
Payments of revolving credit facility		(553,704	)		—			—			—			(553,704	)
Proceeds from long-term debt		500,000			—			—			—			500,000
Payments of long-term debt		(375,000	)		—			—			—			(375,000	)
Payments of premiums on redemption of long-term debt		(9,732	)		—			—			—			(9,732	)
Payments of intercompany notes, net		—			(12,350	)		—			12,350			—
Payments for debt issuance costs, deferred financing costs and registration costs		(20,912	)		—			—			—			(20,912	)
Contributions from parent, net		—			44,346			—			(44,346	)		—
Contributions to joint ventures, net		—			—			329,545			(171,252	)		158,293
Payments of SMR Liability		—			(1,354	)		—			—			(1,354	)
Proceeds from public equity offering, net		142,255			—			—			—			142,255
Share-based payment activity		(3,834	)		98			—			—			(3,736	)
Payment of distributions		(181,058	)		(41,167	)		(28,396	)		63,413			(187,208	)
Intercompany advances, net		102,376			(102,376	)		—			—			—
Net cash flows provided by (used in) financing activities		94,795			(112,803	)		301,149			(139,835	)		143,306
Net decrease in cash		—			(10,598	)		(19,704	)		—			(30,302	)
Cash and cash equivalents at beginning of year		—			74,448			23,304			—			97,752
Cash and cash equivalents at end of period	$	—		$	63,850		$	3,600		$	—		$	67,450

156

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

25. Supplemental Condensed Consolidating Financial Information (Continued)

	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, net		21,340			—			—			(21,340	)		—
Proceeds from 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 investing activities		(18,722	)		(218,289	)		(281,285	)		56,543			(461,753	)
Cash flows from financing activities:
Proceeds from revolving credit facility		725,200			—			—			—			725,200
Payments of revolving credit facility		(850,600	)		—			—			—			(850,600	)
Proceeds from long-term debt		117,000			—			—			—			117,000
Payments of intercompany notes, net		—			(21,340	)		—			21,340			—
Payments for debt issuance costs, deferred financing costs and registration costs		(8,054	)		(500	)		—			—			(8,554	)
Contributions from parent, 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 period	$	—		$	74,448		$	23,304		$	—		$	97,752

157

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

26. Supplemental Cash Flow Information

        The following table provides information regarding supplemental cash flow information (in thousands):

	Year ended December 31,
	2011		2010		2009
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	112,780	$	101,459	$	85,817
Cash paid for income taxes, net of refunds		10,115		8,683		4,609
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	87,098	$	65,908	$	60,738
Interest capitalized on construction in progress		1,121		2,766		12,228
Issuance of common units for vesting of share-based payment awards		5,412		7,238		9,402
Issuance of Class B units for acquisition of non-controlling interest		752,531		—		—

27. Valuation and Qualifying Accounts

        Activity in the Partnership's allowance for doubtful accounts and deferred tax asset valuation allowance is as follows (in thousands):

	Year ended December 31,
	2011			2010			2009
Allowance for Doubtful Accounts
Balance at beginning of period	$	162		$	162		$	175
Charged to costs and expenses		—			134			12
Other charges(1)		(2	)		(134	)		(25	)
Balance at end of period	$	160		$	162		$	162
Deferred Tax Asset Valuation Allowance
Balance at beginning of period	$	1,036		$	1,688		$	30
Charged to costs and expenses		(59	)		(652	)		1,667
Other charges		—			—			(9	)
Balance at end of period	$	977		$	1,036		$	1,688

(1)

Bad debts written-off (net of recoveries).

158

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

28. Quarterly Results of Operations (Unaudited)

        The following summarizes the Partnership's quarterly results of operations for 2011 and 2010 (in thousands, except per unit data):

	Three months ended
	March 31(1)			June 30		September 30		December 31(2)
2011
Total revenue	$	263,221		$	400,439	$	507,826	$	333,913
(Loss) income from operations		(15,294	)		133,214		207,801		(7,557	)
Net (loss) income		(74,671	)		89,205		153,454		(61,743	)
Net (loss) income attributable to the Partnership		(84,029	)		78,497		140,312		(74,085	)
Net (loss) income attributable to the Partnership's common unitholders per common unit(4):
Basic	$	(1.13	)	$	1.03	$	1.77	$	(0.87	)
Diluted	$	(1.13	)	$	1.03	$	1.77	$	(0.87	)

	Three months ended
	March 31		June 30		September 30			December 31(3)
2010
Total revenue	$	308,379	$	323,850	$	255,411		$	299,991
Income from operations		53,573		109,071		646			25,172
Net income (loss)		26,004		66,968		(18,676	)		(43,194	)
Net income (loss) attributable to the Partnership		21,510		60,217		(27,151	)		(54,109	)
Net income (loss) attributable to the Partnership's common unitholders per common unit(4):
Basic	$	0.32	$	0.84	$	(0.39	)	$	(0.76	)
Diluted	$	0.32	$	0.84	$	(0.39	)	$	(0.76	)

(1)

During the first quarter of 2011, the Partnership recorded a loss on redemption of debt of approximately $43.3 million related to the repurchase of the 2016 Senior Notes and a portion of 2018 Senior Notes. See Note 16 for further details.

(2)

During the fourth quarter of 2011, the Partnership recorded a loss on redemption of debt of approximately $35.5 million related to the repurchase of a portion of the 2018 Senior Notes. See Note 16 for further details.

(3)

During the fourth quarter of 2010, the Partnership recorded a loss on redemption of debt of approximately $46.3 million related to the redemption of the 2014 Senior Notes. See Note 16 for further details.

(4)

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.

159

MARKWEST ENERGY PARTNERS, L.P.

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)

29. Subsequent Events

Utica Shale Joint Venture

        Effective January 1, 2012, the Partnership and EMG Utica entered into the Utica Joint Venture to develop significant natural gas processing and NGL fractionation, transportation and marketing infrastructure in the Utica Shale in eastern Ohio beginning in 2012. Under the terms of the Utica Joint Venture, EMG will fund a majority of the initial capital expenditures required to develop the Utica midstream infrastructure. The Partnership has a 60% ownership in the Utica Joint Venture. A wholly-owned subsidiary of the Partnership serves as the operator of MarkWest Utica EMG and provides field operating and general and administrative services. A portion of the fee for providing these services is fixed.

160

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, 2011. Based on this evaluation, the Partnership's management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of December 31, 2011, 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, 2011 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, 2011, 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 Partnership 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, 2011 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.

161

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, 2011 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 the inherent limitations of 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 the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the 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, 2011, 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, 2011 of the Partnership and our report dated February 28, 2012 expressed an unqualified opinion on those financial statements.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
February 28, 2012

162

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 2011 Annual Meeting of Unitholders expected to be filed no later than April 29, 2012.

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 2012 Annual Meeting of Unitholders expected to be filed no later than April 29, 2012.

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 2011 Annual Meeting of Unitholders expected to be filed no later than April 29, 2012.

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 2011 Annual Meeting of Unitholders expected to be filed no later than April 29, 2012.

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 2012 Annual Meeting of Unitholders expected to be filed no later than April 29, 2012.

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 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

163

Exhibit Number			Description
	2.1	(6)	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	(10)	Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated as of February 21, 2008.
	3.7	(20)	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	(20)	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	(20)	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	(20)	Amendment No. 4 to Amended and Restated Limited Liability Company Agreement MarkWest Energy GP, L.L.C., dated as of March 31, 2008.
	3.11	(27)	Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated December 29, 2011.
	4.1	(12)	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.
	4.2	(12)	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 4.1 hereto).
	4.3	(12)	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.
	4.4	(13)	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.
	4.5	(16)	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.

164

Exhibit Number			Description
	4.6	(16)	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.
	4.7	(16)	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.
	4.8	(17)	Indenture Release of Subsidiary Guarantor dated as of May 1, 2009, among MarkWest Energy Partners, L.P., and Wells Fargo Bank, N.A.
	4.9	(18)	Indenture Release of Subsidiary Guarantor dated as of October 31, 2009, among MarkWest Energy Partners, L.P. and Wells Fargo Bank, N.A.
	4.10	(28)	Fourth Supplemental Indenture dated as of March 10, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
	4.11	(32)	Fifth Supplemental Indenture dated as of October 21, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
	4.12	(34)	Sixth Supplemental Indenture, dated as of November 10, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
	4.13	(22)	Indenture, dated as of November 2, 2010, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
	4.14	(22)	First Supplemental Indenture, dated as of November 2, 2010, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
	4.15	(22)	Form of 63/4% Senior Notes due 2020 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.14 hereto).
	4.16	(26)	Second Supplemental Indenture, dated as of February 24, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
	4.17	(26)	Form of 6.5% Senior Notes due 2021 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.16 hereto).
	4.18	(28)	Third Supplemental Indenture dated as of March 10, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
	4.19	(32)	Fourth Supplemental Indenture dated as of October 21, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
	4.20	(33)	Fifth Supplemental Indenture, dated as of November 3, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.

165

Exhibit Number			Description
	4.21	(33)	Form of 6.25% Senior Notes due 2022 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.20 hereto).
	4.22	*	Sixth Supplemental Indenture, dated as of December 27, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee.
	4.23	*	Registration Rights Agreement dated December 29, 2011 between MarkWest Energy Partners, L.P. and M&R MWE Liberty, LLC.
	10.1	(24)	Amended and Restated Revolving Credit Agreement dated as of July 1, 2010 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as successor Administrative Agent, Issuing Bank and Swingline Linder, Royal Bank of Canada, as prior administrative agent, RBC Capital Markets, as Syndication Agent, BNP Paribas, Morgan Stanley Bank and U.S. Bank National Association, as Documentation Agents, and the lenders party thereto.
	10.2	(25)	Joinder Agreement dated as of July 29, 2010 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, individually and as Administrative Agent, Issuing Bank and Swingline Lender and Goldman Sachs Bank USA.
	10.3	(29)	Joinder Agreement dated as of June 15, 2011 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, individually and as Administrative Agent, Issuing Bank and Swingline Lender and Citibank, N.A.
	10.4	(31)	First Amendment to Amended and Restated Credit Agreement dated as of September 7, 2011 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto.
	10.5	(27)	Second Amendment to Amended and Restated Credit Agreement dated as of December 29, 2011, among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto.
	10.6	(3)	Services Agreement dated January 1, 2004 between MarkWest Energy GP, L.L.C. and MarkWest Hydrocarbon, Inc.
	10.7	(5)+	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.
	10.8	(7)+	Hydrogen Supply Agreement dated September 28, 2007, by and between MarkWest Blackhawk, L.P. and CITGO Refining and Chemicals Company L.P.
	10.9	(9)+	Gas Processing Agreement dated as of November 1, 2007, by and between MarkWest Javelina Company and CITGO Refining and Chemicals Company, L.P.
	10.10	(8)+	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.
	10.11	(15)+	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.
	10.12	(16)+	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.

166

Exhibit Number			Description
	10.13	(16)+	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.
	10.14	(16)+	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.
	10.15	(23)+	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.
	10.16	(19)+	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.
	10.17	(19)+	Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources, L.L.C. dated as of February 27, 2009.
	10.18	(21)+	Letter Agreement dated August 10, 2009 between MarkWest Liberty Gas Gathering, L.L.C. and M&R MWE Liberty, LLC.
	10.19	(23)+	Second Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources, L.L.C. dated as of November 1, 2009.
	10.20	(23)	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.
	10.21	(6)	Exchange Agreement dated September 5, 2007 by and among MarkWest Energy Partners, L.P., MarkWest Hydrocarbon, Inc., and MarkWest Energy, GP L.L.C.
	10.22	(14)	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.
	10.23	(2)	MarkWest Energy Partners, L.P. Long-Term Incentive Plan.
	10.24	(2)	First Amendment to MarkWest Energy Partners, L.P. Long-Term Incentive Plan.
	10.25	(14)	1996 Stock Incentive Plan for MarkWest Hydrocarbon, Inc.
	10.26	(14)	2006 Stock Incentive Plan for MarkWest Hydrocarbon, Inc.
	10.27	(11)	MarkWest Energy Partners, L.P. 2008 Long-Term Incentive Plan.
	10.28	(4)D	Executive Employment Agreement effective September 5, 2007 between MarkWest Hydrocarbon, Inc. and Frank Semple.

167

Exhibit Number			Description
	10.29	(4)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.
	10.30	(30)+	Amendment No. 2 to Second Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources, L.L.C. dated as of April 28, 2011.
	10.31	(28)+	Purchase and Sale Agreement dated as of January 3, 2011 by and between EQT Gathering, LLC and MarkWest Energy Appalachia, L.L.C.
	10.32	(28)+	Letter Agreement dated February 1, 2011 between EQT Gathering, LLC and MarkWest Energy Appalachia, L.L.C.
	10.33	*+	Amendment No. 3 to Second Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources, L.L.C. dated as of December 19, 2011, among MarkWest Liberty Midstream & Resources, L.L.C., MarkWest Liberty Gas Gathering, L.L.C. and M&R MWE Liberty, LLC.
	10.34	*+	Contribution Agreement dated December 29, 2011 among M&R MWE Liberty, LLC, MarkWest Energy Partners, L.P. and MarkWest Liberty Gas Gathering L.L.C.
	10.35	*+	Limited Liability Company Agreement of MarkWest Utica EMG, L.L.C., dated December 29, 2011 and effective January 1, 2012, between MarkWest Utica Operating Company, L.L.C. and EMG Utica, LLC.
	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.
	101	*	The following financial information from the annual report on Form 10-K of MarkWest Energy Partners, L.P. for the year ended December 31, 2010, formatted in XBRL (eXtensible Business Reporting Language): (i) Consolidated Balance Sheets, (ii) Consolidated Statements of Operations, (iii) Consolidated Statements of Changes in Equity and Comprehensive Income, (iv) Consolidated Statements of Cash Flows, and (v) Notes to Consolidated Financial Statements, tagged as blocks of text.

(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.

168

(4)

Incorporated by reference to the Current Report on Form 8-K filed September 11, 2007.

(5)

Incorporated by reference to the Quarterly Report on Form 10-Q filed November 7, 2006.

(6)

Incorporated by reference to the Current Report on Form 8-K filed September 6, 2007.

(7)

Incorporated by reference to the Quarterly Report on Form 10-Q filed November 8, 2007.

(8)

Incorporated by reference to the Annual Report on Form 10-K filed February 29, 2008.

(9)

Incorporated by reference to the Annual Report on Form 10-K/A filed May 8, 2008.

(10)

Incorporated by reference to the Current Report on Form 8-K filed February 21, 2008.

(11)

Incorporated by reference to the Form S-4/A Registration Statement filed December 21, 2007.

(12)

Incorporated by reference to the Current Report on Form 8-K filed April 15, 2008.

(13)

Incorporated by reference to the Current Report on Form 8-K filed May 1, 2008.

(14)

Incorporated by reference to the Quarterly Report on Form 10-Q filed August 11, 2008.

(15)

Incorporated by reference to the Quarterly Report on Form 10-Q filed November 10, 2008.

(16)

Incorporated by reference to the Annual Report on Form 10-K filed March 2, 2009.

(17)

Incorporated by reference to the Quarterly Report on Form 10-Q filed August 10, 2009.

(18)

Incorporated by reference to the Registration Statement on Form S-3 filed January 13, 2010.

(19)

Incorporated by reference to the Quarterly Report on Form 10-Q/A filed October 16, 2009.

(20)

Incorporated by reference to the Form S-4 Registration Statement filed July 2, 2009.

(21)

Incorporated by reference to the Quarterly Report on Form 10-Q filed November 9, 2009.

(22)

Incorporated by reference to the Current Report on Form 8-K filed November 3, 2010.

(23)

Incorporated by reference to the Annual Report on Form 10-K filed March 1, 2010.

(24)

Incorporated by reference to the Current Report on Form 8-K filed July 7, 2010.

(25)

Incorporated by reference to the Current Report on Form 8-K filed August 4, 2010.

(26)

Incorporated by reference to the Current Report on Form 8-K filed February 24, 2011.

(27)

Incorporated by reference to the Current Report on Form 8-K filed December 30, 2011.

(28)

Incorporated by reference to the Quarterly Report on Form 10-Q filed May 9, 2011.

(29)

Incorporated by reference to the Current Report on Form 8-K filed June 17, 2011.

(30)

Incorporated by reference to the Quarterly Report on Form 10-Q filed August 8, 2011.

(31)

Incorporated by reference to the Current Report on Form 8-K filed September 13, 2011.

(32)

Incorporated by reference to the Quarterly Report on Form 10-Q filed November 7, 2011.

(33)

Incorporated by reference to the Current Report on Form 8-K filed November 7, 2011.

(34)

Incorporated by reference to the Current Report on Form 8-K filed November 15, 2011.

+

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.

169

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.

170

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: February 28, 2012	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: February 28, 2012	By:	/s/ FRANK M. SEMPLE Frank M. Semple Chairman, President and Chief Executive Officer (Principal Executive Officer)
Date: February 28, 2012	By:	/s/ NANCY K. BUESE Nancy K. Buese Senior Vice President and Chief Financial Officer (Principal Financial Officer)
Date: February 28, 2012	By:	/s/ PAULA L. ROSSON Paula L. Rosson Vice President and Chief Accounting Officer (Principal Accounting Officer)
Date: February 28, 2012	By:	/s/ DONALD D. WOLF Donald D. Wolf Lead Director
Date: February 28, 2012	By:	/s/ KEITH E. BAILEY Keith E. Bailey Director

171

Date: February 28, 2012	By:	/s/ MICHAEL L. BEATTY Michael L. Beatty Director
Date: February 28, 2012	By:	/s/ CHARLES K. DEMPSTER Charles K. Dempster Director
Date: February 28, 2012	By:	/s/ ANNE E. FOX MOUNSEY Anne E. Fox Mounsey Director
Date: February 28, 2012	By:	/s/ DONALD C. HEPPERMANN Donald C. Heppermann Director
Date: February 28, 2012	By:	/s/ WILLIAM A. KELLSTROM William A. Kellstrom Director
Date: February 28, 2012	By:	/s/ WILLIAM P. NICOLETTI William P. Nicoletti Director
Date: February 28, 2012	By:	/s/ RANDALL J. LARSON Randall J. Larson Director

172

EX-4.22

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Exhibit 4.22

SIXTH SUPPLEMENTAL INDENTURE

        This SIXTH SUPPLEMENTAL INDENTURE (this "Supplemental Indenture"), dated as of December 27, 2011, is among MarkWest Energy Partners, L.P., a Delaware limited partnership (the "Partnership"), MarkWest Energy Finance Corporation, a Delaware corporation ("MarkWest Finance" and, together with the Partnership, the "Issuers"), each of the other parties identified on the signature page hereto (the "Subsidiary Guarantors") and Wells Fargo Bank, National Association, a national banking association, as Trustee.

RECITALS

        WHEREAS, the Issuers, the Subsidiary Guarantors and the Trustee are parties to (i) an Indenture, dated as of November 2, 2010 (as amended and supplemented by the first supplemental indenture, the third supplemental indenture and the fourth supplemental indenture thereto, the "2020 Notes Indenture"), pursuant to which the Issuers have issued $500,000,000 in principal amount of 6³/4% Senior Notes due 2020 (the "2020 Notes"), (ii) an Indenture, dated as of November 2, 2010 (as amended and supplemented by the second supplemental indenture, the third supplemental indenture and the fourth supplemental indenture thereto, the "2021 Notes Indenture"), pursuant to which the Issuers have issued $500,000,000 in principal amount of 6.5% Senior Notes due 2021 (the "2021 Notes") and (iii) an Indenture, dated as of November 2, 2010 (as amended and supplemented by the fifth supplemental indenture thereto, the "2022 Notes Indenture" and together with the 2020 Notes Indenture and the 2021 Notes Indenture, the "Indentures"), pursuant to which the Issuers have issued $700,000,000 in principal amount of 6.25% Senior Notes due 2022 (the "2022 Notes" and together with the 2020 Notes and the 2021 Notes, the "Notes");

        WHEREAS, Section 10.01(a) of each of the Indentures provides that the Issuers, the Subsidiary Guarantors and the Trustee may amend or supplement the Indentures in order to cure any ambiguity, defect or inconsistency, without the consent of the Holders of the Notes;

        WHEREAS, clause (c) of the definition of "Non-Recourse Debt" in Section 2.01 of each Indenture refers to an exception contemplated by clause (o) of the definition of "Permitted Liens" allowing recourse by lenders in certain circumstances to the stock or assets of the Partnership or any of its Restricted Subsidiaries;

        WHEREAS, such clause (o) contemplates no such exception and relates solely to certain Liens incurred in the ordinary course of business of the Partnership or any of its Restricted Subsidiaries, while the preceding clause (n) relates to Liens on and pledges of the Equity Interests of any Unrestricted Subsidiary or any Joint Venture owned by the Partnership or any of its Restricted Subsidiaries to the extent securing Non-Recourse Debt or other Indebtedness of such Unrestricted Subsidiary or Joint Venture;

        WHEREAS, such clause (o) of the definition of "Permitted Liens" is manifestly inconsistent with the reference to it in clause (c) of the definition of "Non-Recourse Debt," such reference being manifestly to, and consistent only with, the preceding clause (n) of the definition of "Permitted Liens"; and

        WHEREAS, all acts and things prescribed by the Indentures, by law and by the Certificate of Incorporation and the Bylaws (or comparable constituent documents) of the Issuers, of the Subsidiary Guarantors and of the Trustee necessary to make this Supplemental Indenture a valid instrument legally binding on the Issuers, the Subsidiary Guarantors and the Trustee, in accordance with its terms, have been duly done and performed;

        NOW, THEREFORE, to comply with the provisions of the Indentures and in consideration of the above premises, the Issuers, the Subsidiary Guarantors and the Trustee covenant and agree for the equal and proportionate benefit of the respective Holders of the Notes as follows:

ARTICLE 1

        This Supplemental Indenture is supplemental to the Indentures and does and shall be deemed to form a part of, and shall be construed in connection with and as part of, the Indentures for any and all purposes.

        This Supplemental Indenture shall become effective immediately upon its execution and delivery by each of the Issuers, the Subsidiary Guarantors and the Trustee.

ARTICLE II

        Clause (c) in the definition of "Non-Recourse Debt" in Section 2.01 of each Indenture is hereby amended by substituting the words "clause (n)" for the words "clause (o)" in the final line thereof.

ARTICLE III

        Except as specifically modified herein, the Indentures and the Notes are in all respects ratified and confirmed (mutatis mutandis) and shall remain in full force and effect in accordance with their terms with all capitalized terms used herein without definition having the same respective meanings ascribed to them as in the Indentures.

        The Trustee accepts the amendments of the Indentures effected by this Supplemental Indenture and agrees to execute the trust created by the Indentures as hereby amended, but on the terms and conditions set forth in the Indentures, including the terms and provisions defining and limiting the liabilities and responsibilities of the Trustee, which terms and provisions shall in like manner define and limit its liabilities and responsibilities in the performance of the trust created by the Indentures as hereby amended, and without limiting the generality of the foregoing, the Trustee shall not be responsible in any manner whatsoever for or with respect to any of the recitals or statements contained herein, all of which recitals or statements are made solely by the Issuers and the Subsidiary Guarantors, and the Trustee makes no representation with respect to any such matters. Additionally, the Trustee makes no representations as to the validity or sufficiency of this Supplemental Indenture.

        THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

        The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of such executed copies together shall represent the same agreement.

        [NEXT PAGE IS SIGNATURE PAGE]

Sixth Supplemental Indenture

2

        IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed, all as of the date first written above.

MARKWEST ENERGY FINANCE CORPORATION
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer
MARKWEST ENERGY PARTNERS, L.P.
By:	MarkWest Energy GP, L.L.C., its General Partner
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer
MARKWEST HYDROCARBON, INC.
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer
MARKWEST ENERGY GP, L.L.C.
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer

Signature Page to Sixth Supplemental Indenture

3

MASON PIPELINE LIMITED LIABILITY COMPANY
By:	MarkWest Hydrocarbon, Inc., its Sole Member
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer
MARKWEST ENERGY OPERATING COMPANY, L.L.C.
By:	MarkWest Energy Partners, L.P., its Managing Member
By:	MarkWest Energy GP, L.L.C., its General Partner
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer

Signature Page to Sixth Supplemental Indenture

4

MARKWEST BLACKHAWK, L.L.C.
MARKWEST ENERGY APPALACHIA, L.L.C.
MARKWEST ENERGY EAST TEXAS GAS COMPANY, L.L.C.
MARKWEST GAS MARKETING, L.L.C.
MARKWEST GAS SERVICES, L.L.C.
MARKWEST JAVELINA COMPANY, L.L.C.
MARKWEST JAVELINA PIPELINE COMPANY, L.L.C.
MARKWEST LIBERTY GAS GATHERING, L.L.C.
MARKWEST MARKETING, L.L.C.
MARKWEST MOUNTAINEER PIPELINE COPMANY, L.L.C.
MARKWEST NEW MEXICO, L.L.C.
MARKWEST PINNACLE, L.L.C.
MARKWEST PIPELINE COMPANY, L.L.C.
MARKWEST PNG UTILITY, L.L.C.
MARKWEST POWER TEX, L.L.C.
MARKWEST TEXAS PNG UTILITY, L.L.C.
By:	MarkWest Energy Operating Company, L.L.C., its Sole Member
By:	MarkWest Energy Partners, L.P., its Managing Member
By:	MarkWest Energy GP, L.L.C., its General Partner
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer

Signature Page to Sixth Supplemental Indenture

5

MARKWEST MICHIGAN PIPELINE COMPANY, L.L.C. MARKWEST OKLAHOMA GAS COMPANY, L.L.C.
By:	MarkWest Energy Operating Company, L.L.C., its Managing Member
By:	MarkWest Energy Partners, L.P., its Managing Member
By:	MarkWest Energy GP, L.L.C., its General Partner
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer
MATREX, L.L.C.
By:	West Shore Processing Company L.L.C., its Sole Member and Manager
By:	MarkWest Energy Operating Company, L.L.C., its Sole Member and Manager
By:	MarkWest Energy Partners, L.P., its Managing Member
By:	MarkWest Energy GP, L.L.C., its General Partner
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer

Signature Page to Sixth Supplemental Indenture

6

MARKWEST MCALESTER, L.L.C.
By:	MarkWest Oklahoma Gas Company, L.L.C., its Sole Member
By:	MarkWest Energy Operating Company, L.L.C., its Managing Member
By:	MarkWest Energy Partners, L.P., its Managing Member
By:	MarkWest Energy GP, L.L.C., its General Partner
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer
MARKWEST RANGER PIPELINE COMPANY, L.L.C
By:	MarkWest Energy Appalachia, L.L.C., its Sole Member
By:	MarkWest Energy Operating Company, L.L.C., its Sole Member
By:	MarkWest Energy Partners, L.P., its Managing Member
By:	MarkWest Energy GP, L.L.C., its General Partner
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer

Signature Page to Sixth Supplemental Indenture

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WEST SHORE PROCESSING COMPANY L.L.C.
By:	MarkWest Energy Operating Company, L.L.C., its Sole Member and Manager
By:	MarkWest Energy Partners, L.P., its Managing Member
By:	MarkWest Energy GP, L.L.C., its General Partner
By:	/s/ Nancy Buese
Name:	Nancy Buese
Title:	Senior Vice President and Chief Financial Officer

Signature Page to Sixth Supplemental Indenture

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WELLS FARGO BANK, NATIONAL ASSOCIATION, as Trustee
By:	/s/ Patrick Giordano
Name:	Patrick Giordano
Title:	Vice President

Signature Page to Sixth Supplemental Indenture

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QuickLinks

Exhibit 4.22

SIXTH SUPPLEMENTAL INDENTURE
RECITALS
ARTICLE 1
ARTICLE II
ARTICLE III

EX-4.23

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Exhibit 4.23

Execution Version

REGISTRATION RIGHTS AGREEMENT

between

MARKWEST ENERGY PARTNERS, L.P.

and

M&R MWE LIBERTY, LLC

dated

December 29, 2011

TABLE OF CONTENTS

	ARTICLE I DEFINITIONS
Section 1.01	Definitions	1
	ARTICLE II REGISTRATION RIGHTS
Section 2.01	Shelf Registration	4
Section 2.02	Piggyback Rights	5
Section 2.03	Underwritten Offering	7
Section 2.04	Continuous Equity Programs	8
Section 2.05	Sale Procedures	8
Section 2.06	Cooperation by Holders	11
Section 2.07	Restrictions on Sale by Holders of Registrable Securities	11
Section 2.08	Expenses	11
Section 2.09	Indemnification	11
Section 2.10	Limitations on Subsequent Registration Rights	13
Section 2.11	Transfer or Assignment of Registration Rights	13
	ARTICLE III MISCELLANEOUS
Section 3.01	Communications	14
Section 3.02	Successors and Assigns	15
Section 3.03	Interpretations	15
Section 3.04	Confidentiality	15
Section 3.05	Recapitalization, Exchanges, Etc. Affecting the Registrable Securities	16
Section 3.06	Specific Performance	16
Section 3.07	Counterparts	16
Section 3.08	Applicable Law, Submission to Jurisdiction	16
Section 3.09	Waiver of Jury Trial	17
Section 3.10	Severability of Provisions	17
Section 3.11	Entire Agreement	17
Section 3.12	Amendment	17
Section 3.13	No Presumption	17
Section 3.14	Obligations Limited to Parties to this Agreement	17

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REGISTRATION RIGHTS AGREEMENT

        This REGISTRATION RIGHTS AGREEMENT, dated December 29, 2011, (this "Agreement"), is entered into by and between MARKWEST ENERGY PARTNERS, L.P., a Delaware limited partnership ("MWE") and M&R MWE Liberty, LLC, a Delaware limited liability company (the "Acquirer").

        WHEREAS, this Agreement is made in connection with the closing of the transactions contemplated by that certain Contribution Agreement, of even date herewith by and among MWE, MarkWest Liberty Gas Gathering, L.L.C., a Delaware limited liability company and the Acquirer (the "Contribution Agreement"); and

        WHEREAS, MWE has agreed to provide the registration and other rights set forth in this Agreement for the benefit of the Acquirer pursuant to the Contribution Agreement.

        NOW THEREFORE, in consideration of the mutual covenants and agreements set forth herein and for good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged by each party hereto, the parties hereby agree as follows:

ARTICLE I
DEFINITIONS

        Section 1.01    Definitions.    As used in this Agreement, the following terms have the meanings indicated:

        "Acquirer" is defined in the introductory paragraph of this Agreement.

        "Acquirer Group Member" means the Acquirer or any Person that is directly or indirectly Controlled by the Acquirer and / or to whom Converted Units or Class B Units are Disposed of in a Disposition made in compliance with the transfer restrictions applicable to the Acquirer set forth in Sections 4.6(e) and 4.6(f) of, and elsewhere in, the MWE Partnership Agreement.

        "Affiliate" means with respect to any Person, any Person that, directly or indirectly, Controls, is Controlled by, or is under a common Control with, such Person. With respect to any natural person, the term "Affiliate" shall also mean (a) the spouse or children (including those by adoption) and siblings of such Person; and any trust whose primary beneficiary is such Person, such Person's spouse, such Person's siblings and/or one or more of such Person's lineal descendants, (b) the legal representative or guardian of such Person or of any such immediate family member in the event such Person or any such immediate family member becomes mentally incompetent and (c) any Person controlled by or under the common control with any one or more of such Person and the Persons described in clauses (a) or (b) of this definition.

        "Agreement" is defined in the introductory paragraph of this Agreement.

        "Business Day" means Monday through Friday of each week, except that a legal holiday recognized as such by the government of the United States of America or the States of Colorado or Texas shall not be regarded as a Business Day.

        "Class B Unit" means a Class B Unit representing a limited partner interests in MWE, having the terms set forth therefore in the MWE Partnership Agreement.

        "Commission" means the United States Securities and Exchange Commission.

        "Common Unit" means a Common Unit representing a limited partner interest in MWE, having the terms set forth therefore in the MWE Partnership Agreement.

        "Confidential Information" is defined in Section 3.04.

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        "Continuous Equity Program" means any continuous equity program, "at-the-market" program, "dribble out" program or similar continuous equity transaction program under which MWE engages one or more investment banks or other broker-dealers to act as distribution agents in continuous registered offerings of Common Units to the public.

        "Contribution Agreement" is defined in the recitals of this Agreement.

        "Control," including the correlative terms "Controlling," and "Controlled by" means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

        "Converted Unit" means a Common Unit issuable upon the conversion of a Class B Unit that is issued to the Acquirer pursuant to the Contribution Agreement at the closing of the transactions contemplated thereby.

        "Disposition," including the correlative term "Disposed of," means any transaction by which the holder of a Common Unit or a Class B Unit directly or indirectly assigns such Common Unit or Class B Unit to another Person, and includes a sale, assignment, gift, pledge, encumbrance, hypothecation, mortgage, exchange or any other disposition by operation of law or otherwise.

        "Effective Date" means, with respect to a particular Shelf Registration Statement, the date of effectiveness of such Shelf Registration Statement.

        "Effectiveness Period" is defined in Section 2.01(a).

        "Exchange Act" means the Securities Exchange Act of 1934, as amended, supplemented or restated from time to time and any successor to such statute.

        "Governmental Authority" means any executive, legislative, judicial, regulatory or administrative agency, body, commission, department, board, court, tribunal, arbitrating body or authority of the United States or any foreign country, or any state, local or other governmental subdivision thereof.

        "Holder" means a record holder of Registrable Securities.

        "Included Registrable Securities" is defined in Section 2.02(a).

        "Launch Date" is defined in Section 2.02(a).

        "Law" means any law, statute, code, ordinance, order, rule, rule of common law, regulation, judgment, decree, injunction, franchise, permit, certificate, license or authorization of any Governmental Authority.

        "Losses" is defined in Section 2.09(a).

        "Managing Underwriter" means, with respect to any Underwritten Offering, the book running lead manager of such Underwritten Offering.

"Maximum Underwritten Offering Amount" means, with respect to any Underwritten Offering Request that Holders of Registrable Securities desire to make pursuant to Section 2.03, a number of Registrable Securities equal to 25 times the average daily trading volume for Common Units on the principal National Securities Exchange on which Common Units are then listed or admitted to trading for Common Units for the 30 consecutive trading days ending on the close of trading on the last trading day preceding the date of such desired Underwritten Offering Request.

"Minimum Underwritten Offering Amount" means, with respect to any Underwritten Offering Request that Holders of Registrable Securities desire to make pursuant to Section 2.03, a number of Registrable Securities equal to 10 times the average daily trading volume for Common Units on the principal National Securities Exchange on which Common Units are then listed or admitted to trading

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for Common Units for the 30 consecutive trading days ending on the close of trading on the last trading day preceding the date of such desired Underwritten Offering Request.

        "MWE" is defined in the introductory paragraph.

        "MWE Partnership Agreement" means the Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated effective as of February 21, 2008, as amended by Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated as of even date with this Agreement.

        "National Securities Exchange" means an exchange registered with the Commission under Section 6(a) of the Exchange Act, or the NASDAQ Stock Market or any successor thereto.

        "Opt-Out Notice" is defined in Section 2.02(a).

        "Other Holders" is defined in Section 2.02(c).

        "Person" means an individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity.

        "Piggyback Offering" is defined in Section 2.02(a).

        "Pricing Date" is defined in Section 2.02(a).

        "Registrable Securities" means each Converted Unit, in all cases only until the earliest to occur of the following: (a) when a registration statement covering such Converted Unit becomes or has been declared effective by the Commission and such Converted Unit has been Disposed of pursuant to such registration statement; (b) when such Converted Unit (or the Class B Unit to which such Converted Unit relates) is held by MWE or one of its subsidiaries; (c) when such Converted Unit (or the Class B Unit to which such Converted Unit relates) is Disposed of to a Person other than an Acquirer Group Member, whether such Disposition is made pursuant to Rule 144 (or any similar provision then in force) under the Securities Act or otherwise (provided that this definition does not, for the avoidance of doubt, modify the transfer restrictions applicable to the Acquirer and its Affiliates set forth in Sections 4.6(e) and 4.6(f) of, and elsewhere in, the MWE Partnership Agreement); and (d) when such Converted Unit, if previously Disposed of to an Acquirer Group Member, becomes directly or indirectly beneficially owned by a Person who, at any time, is not an Acquirer Group Member (as a result of a change of control of the Acquirer Group Member to whom such Converted Unit was previously Disposed or otherwise).

        "Registration Expenses" is defined in Section 2.08(a).

        "Securities Act" means the Securities Act of 1933, as amended, supplemented or restated from time to time and any successor to such statute.

        "Selling Expenses" is defined in Section 2.08(a).

        "Selling Holder" means a Holder who is selling Registrable Securities under a registration statement pursuant to the terms of this Agreement.

        "Selling Holder Documentation" is defined in Section 2.02(a).

        "Shelf Registration Statement" means a registration statement under the Securities Act to permit the public resale of Registrable Securities from time to time as permitted by Rule 415 of the Securities Act (or any similar provision then in force under the Securities Act).

        "Underwritten Offering" means an offering (including an offering pursuant to a Shelf Registration Statement) in which Common Units are sold to an underwriter on a firm commitment basis for

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reoffering to the public. For purposes of this Agreement, an offering or sale pursuant to a Continuous Equity Program shall not be considered an Underwritten Offering.

        "Underwritten Offering Request" is defined in Section 2.03(a).

ARTICLE II
REGISTRATION RIGHTS

        Section 2.01    Shelf Registration.

        (a)    Shelf Registration.    MWE shall use its commercially reasonable best efforts to (i) prepare and file one Shelf Registration Statement under the Securities Act covering the Registrable Securities and (ii) cause such Shelf Registration Statement to become effective no later than July 1, 2013. To the extent that such Shelf Registration Statement does not become effective on or prior to July 1, 2013, other than at the fault of a Selling Holder, without the prior written consent of the Holders of a majority of the Registrable Securities, MWE will not sell equity securities for its own account in an Underwritten Offering until such Shelf Registration Statement is effective. The Shelf Registration Statement filed pursuant to this Section 2.01(a) shall be on such appropriate registration form of the Commission as shall be selected by MWE; provided, however, that if a prospectus supplement will be used in connection with the marketing of an Underwritten Offering from such Shelf Registration Statement and the Managing Underwriter at any time shall notify MWE in writing that, in the reasonable judgment of such Managing Underwriter, inclusion of detailed information to be used in such prospectus supplement is of material importance to the success of the Underwritten Offering of such Registrable Securities, MWE shall use its commercially reasonable efforts to include such information in the prospectus supplement. MWE will use its commercially reasonable efforts to cause the Shelf Registration Statement filed pursuant to this Section 2.01(a) to be continuously effective under the Securities Act until the earliest date on which any of the following occurs: (i) all Registrable Securities covered by such Shelf Registration Statement have been distributed in the manner set forth and as contemplated in such Shelf Registration Statement, (ii) there are no longer any Registrable Securities covered by such Shelf Registration Statement outstanding and (iii) July 1, 2019 (the "Effectiveness Period"). The Shelf Registration Statement filed pursuant to this Section 2.01(a) when it becomes or is declared effective (including the documents incorporated therein by reference) will comply as to form in all material respects with all applicable requirements of the Securities Act and the Exchange Act and will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading (and, in the case of any prospectus contained in such Shelf Registration Statement, in the light of the circumstances under which a statement is made). As soon as practicable following the Effective Date of the Shelf Registration Statement filed pursuant to this Section 2.01(a), but in any event within three Business Days of such date, MWE will notify the Selling Holders of the effectiveness of such Shelf Registration Statement.

        (b)    Maximum Shelf Registration Rights; Delay Rights.

          (i)  Notwithstanding anything to the contrary contained in this Agreement, MWE shall not be obligated to file or effect more than one Shelf Registration Statement (including any post-effective amendments to such Shelf Registration Statement filed for the primary purpose of including Selling Holders or adding Converted Units to such Shelf Registration Statement) pursuant to Section 2.01(a).

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         (ii)  Notwithstanding anything to the contrary contained in this Agreement, MWE may, upon written notice to any Selling Holder whose Registrable Securities are included in the Shelf Registration Statement filed pursuant to Section 2.01(a), suspend such Selling Holder's use of any prospectus that is a part of such Shelf Registration Statement (in which event the Selling Holder shall discontinue sales of the Registrable Securities pursuant to the Shelf Registration Statement) if (A) MWE is pursuing an acquisition, merger, reorganization, disposition or other similar transaction and MWE determines in good faith that MWE's ability to pursue or consummate such a transaction would be materially and adversely affected by any required disclosure of such transaction in the Shelf Registration Statement or (B) MWE has experienced some other material non-public event the disclosure of which at such time, in the good faith judgment of MWE, would materially and adversely affect MWE; provided, however, that in no event shall the Selling Holders be suspended from selling Registrable Securities pursuant to the Shelf Registration Statement for a period that exceeds an aggregate of 60 days in any 180 day period or 90 days (exclusive of days covered by any lock-up agreement executed by a Selling Holder in connection with any Underwritten Offering by MWE or a Selling Holder) in any 365 day period. Upon disclosure of such information or the termination of the conditions described above, MWE shall provide prompt notice to the Selling Holders whose Registrable Securities are included in the Shelf Registration Statement, and shall promptly terminate any suspension of sales it has put into effect and shall take such other actions necessary or appropriate to permit registered sales of Registrable Securities as contemplated in this Agreement.

        Section 2.02    Piggyback Rights.

        (a)    Underwritten Offering Piggyback Rights.    If at any time during the Effectiveness Period MWE proposes to file (i) a prospectus supplement to an effective shelf registration statement, other than the Shelf Registration Statement contemplated by Section 2.01(a), or (ii) a registration statement (other than: (A) a shelf registration statement; (B) a registration relating solely to employee benefit plans; (C) a registration relating solely to a Rule 145 transaction; or (D) a registration on any registration form which does not permit secondary sales), in either case, for the sale of Common Units in an Underwritten Offering for its own account, then, as soon as practicable but not less than two Business Days prior to the date such Underwritten Offering is expected to be launched (the "Launch Date") (1) MWE shall notify the Holders of the pendency of the Underwritten Offering and such notice shall offer the Holders the opportunity to include in such Underwritten Offering such number of Registrable Securities (the "Included Registrable Securities") as each such Holder may request in writing (a "Piggyback Offering") and (2) if the Holders propose to include Included Registrable Securities in the Underwritten Offering, then the Managing Underwriter of the Underwritten Offering shall, no later than the two Business Days prior to the expected Launch Date, provide to the Selling Holders all of the documentation customarily required for the inclusion of Registrable Securities in the Underwritten Offering, including, without limitation, a custody agreement and power-of-attorney, Selling Holders' customary representations and warranties, and a form of legal opinion required to be delivered by counsel to the Selling Holders (in form and substance reasonably acceptable to counsel for the Selling Holders) at the closing of an Underwritten Offering and any over-allotment option closing (collectively, the "Selling Holder Documentation"). To include Registrable Securities in an Underwritten Offering, each Selling Holder shall, subject to receipt of notice of the Underwritten Offering and Selling Holder Documentation within the time periods set forth above: (A) complete its review and return the Selling Holder Documentation, with such revisions as have been agreed to by MWE (such agreement not to be unreasonably withheld) and the Selling Holder, at least one Business Day prior to the expected Launch Date; (B) place the Registrable Securities eligible for inclusion in an Underwritten Offering into the custody of MWE's transfer agent at least one Business Day prior to the expected Launch Date; (C) agree to participate following reasonable notice in any due diligence calls arranged by the Managing Underwriter of an Underwritten Offering on the expected Launch Date, the pricing date of an Underwritten Offering (the "Pricing Date") or in advance of the closing of an Underwritten Offering

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and any over-allotment option closing; and (D) unconditionally waive any right to withdraw any Registrable Securities placed into the custody of MWE's transfer agent for inclusion in an Underwritten Offering within one Business Day of the expected Launch Date, whether on the basis of the offering price, underwriter discount, or for any other reason. Notwithstanding the foregoing, if MWE has been advised by the Managing Underwriter that the inclusion of Registrable Securities for sale for the benefit of the Holders will have an adverse effect on the price, timing or distribution of the Common Units, then the amount of Registrable Securities to be offered for the accounts of participating Holders shall be determined based on the provisions of Section 2.02(c). If, at any time after giving written notice of its intention to undertake an Underwritten Offering and prior to the closing of such Underwritten Offering, MWE shall determine for any reason not to undertake or to delay such Underwritten Offering, MWE shall give written notice of such determination to the Selling Holders and, (i) in the case of a determination not to undertake such Underwritten Offering, shall be relieved of its obligation to sell any Registrable Securities held by the Selling Holders in connection with such terminated Underwritten Offering, and (ii) in the case of a determination to delay such Underwritten Offering, shall be permitted to delay offering any Registrable Securities held by the Selling Holders for the same period as the delay of the Underwritten Offering and, so long as (A) such delay is not longer than 10 days and (B) the number of Common Units intended to be included in the resumed Underwritten Offering by MWE is no more than 20% lower or higher than the number of Common Units that were intended to be included by MWE in such Underwritten Offering prior to the delay, shall not be required to offer any non-Selling Holders the opportunity to include Registrable Securities in such delayed Underwritten Offering once it is resumed. Any Selling Holder shall have the right to withdraw such Selling Holder's request for inclusion of such Selling Holder's Registrable Securities in such Underwritten Offering by giving written notice to MWE of such withdrawal at least one Business Day prior to the Launch Date. Notwithstanding the foregoing, any Holder may deliver written notice (an "Opt-Out Notice") to MWE requesting that such Holder not receive notice from MWE of any proposed Underwritten Offering; provided, however, that such Holder may later revoke any such Opt-Out Notice in writing. For the avoidance of doubt, if a Holder elects to include Registrable Securities in a Piggyback Offering, such included Registrable Securities shall be allocated to the primary offering of Common Units and to any over-allotment option requested by the Managing Underwriter in the same relative proportions as are the Common Units intended to be included in such Piggyback Offering by MWE. In the event that following the Launch Date, MWE determines to increase the number of units offered in any Underwritten Offering, MWE shall provide written notice to the Selling Holders and such Selling Holders shall have the right to increase the number of Registrable Securities offered by such Selling Holders to the extent covered by the Selling Holder Documentation and subject to the limitations set forth in Section 2.02(b). In the event of any such upsize, the Selling Holders will promptly (and in a manner that does not unreasonably or materially delay or impair MWE's primary marketing efforts in relation to the anticipated timing of pricing the Underwritten Offering) notify MWE in writing of their intention to participate in the upsized Underwritten Offering.

        (b)    Limitation on Piggyback Rights.    Notwithstanding anything to the contrary contained in this Agreement, if, in connection with an Underwritten Offering contemplated by Section 2.02(a), the total amount of Registrable Securities that Holders propose to include in such Underwritten Offering would exceed 20% of the total number of Common Units intended to be included in such Underwritten Offering by MWE, then, subject to the limitations set forth in Section 2.02(c) , such Holders shall only be entitled to register in such Underwritten Offering a number of Registrable Securities equal to 20% of the total number of Common Units intended to be included in such Underwritten Offering by MWE (including an equal percentage in any over-allotment option requested by the Managing Underwriter), with such number to be allocated (i) pro-rata among such Holders based on the percentage determined by dividing (A) the number of Registrable Securities proposed to be sold by each such Holder in such Underwritten Offering by (B) the aggregate number of Registrable Securities proposed to be sold by all

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Holders in such Underwritten Offering or (ii) in such other proportions as such Holders may specify in a written notice delivered to MWE at least one Business Day prior to the Launch Date.

        (c)    Priority of Piggyback Rights.    Notwithstanding anything to the contrary contained in this Agreement, in connection with an Underwritten Offering contemplated by Section 2.02(a), if the Managing Underwriter or Managing Underwriters of such Underwritten Offering advises MWE that the total amount of Common Units that the Selling Holders and any other Persons intend to include in such Underwritten Offering exceeds the number that can be sold in such Underwritten Offering without being likely to have an adverse effect on the price, timing or distribution of the Common Units offered or the market for the Common Units, then the Common Units to be included in such Underwritten Offering shall include the number of Common Units that such Managing Underwriter or Managing Underwriters advises MWE can be sold without having such adverse effect, with such number to be allocated (i) first, pro-rata among MWE and the Selling Holders, based, for MWE and each such Selling Holder, on the percentage derived by dividing (A) the number of Common Units proposed to be sold by MWE or such Selling Holder in such Underwritten Offering (subject to the limitations set forth in Section 2.02(b)); by (B) the aggregate number of Common Units proposed to be sold by MWE and all Selling Holders in the Underwritten Offering (subject to the limitations set forth in Section 2.02(b)) and (ii) second, pro rata among any other Persons who have been or are granted registration rights on or after the date of this Agreement who have requested participation in the Underwritten Offering (the "Other Holders") based, for each such Other Holder, (i) on the percentage derived by dividing (A) the number of Common Units proposed to be sold by such Other Holders in such Underwritten Offering; by (B) the aggregate number of Common Units proposed to be sold by all Other Holders in the Underwritten Offering or (ii) on such other manner as such Other Holders may agree.

        Section 2.03    Underwritten Offering.

        (a)    Request for Underwritten Offering.    From and after January 1, 2017, in the event that Holders of at least a majority of the Registrable Securities elect to Dispose of Registrable Securities under a Shelf Registration Statement pursuant to an Underwritten Offering, MWE shall, at the request of such Selling Holders (such request, the "Underwritten Offering Request"), enter into an underwriting agreement in customary form with the Managing Underwriter or Managing Underwriters, which shall include, among other provisions, indemnities to the effect and to the extent provided in Section 2.09, and shall take all such other reasonable actions as are requested by the Managing Underwriter to expedite or facilitate the Disposition of the Registrable Securities; provided, however, that (i) MWE shall not be required to effect more than three Underwritten Offerings pursuant to this Section 2.03; (ii) the Holders shall be limited to one Underwritten Offering Request in any consecutive 365-day period; (iii) MWE shall not be required to effect either of the first two Underwritten Offerings requested pursuant to this Section 2.03 if the Holders do not request to register at least the Minimum Underwritten Offering Amount in such Underwritten Offering and (iv) the Holders shall not be permitted to request to register more than the Maximum Underwitten Offering Amount in any single Underwritten Offering Request.

        (b)    General Procedures.    In connection with any Underwritten Offering, MWE shall be entitled to select the Managing Underwriter or Managing Underwriters. In connection with an Underwritten Offering contemplated by this Agreement in which a Selling Holder participates, each Selling Holder and MWE shall be obligated to enter into an underwriting agreement with the Managing Underwriter or Managing Underwriters that contains such representations, covenants, indemnities and other rights and obligations as are customary in underwriting agreements for firm commitment offerings of equity securities. No Selling Holder may participate in an Underwritten Offering unless such Selling Holder agrees to sell its Registrable Securities on the basis provided in such underwriting agreement and completes and executes all questionnaires, powers-of-attorney, indemnities and other documents reasonably required under the terms of such underwriting agreement. Each Selling Holder may, at its

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option, require that any or all of the representations and warranties by, and the other agreements on the part of, MWE to and for the benefit of such underwriters also be made to and for such Selling Holder's benefit and that any or all of the conditions precedent to the obligations of such underwriters under such underwriting agreement also be conditions precedent to its obligations. No Selling Holder shall be required to make any representations or warranties to or agreements with MWE or the underwriters other than representations, warranties or agreements regarding such Selling Holder and its ownership of the securities being registered on its behalf and its intended method of distribution and any other representation required by Law. If any Selling Holder disapproves of the terms of an Underwritten Offering, such Selling Holder may elect to withdraw therefrom by notice to MWE and the Managing Underwriter; provided, however, that such withdrawal must be made at least one Business Day prior to the pricing of such Underwritten Offering to be effective. No such withdrawal or abandonment shall affect MWE's obligation to pay Registration Expenses. In the event that all Selling Holders holding Registrable Securities subject to such Underwritten Offering, specifically not including any securities to be sold by MWE or other Persons in such Underwritten Offering, withdraw from such Underwritten Offering, such Underwritten Offering shall not be counted for purposes of the Underwritten Offering limitations set forth in Section 2.03(a)(i) or (ii).

        Section 2.04    Continuous Equity Programs.    If at any time during the Effectiveness Period MWE has in place or has imminent plans to implement a Continuous Equity Program, MWE shall provide prompt notice of the existence or planned implementation of such Continuous Equity Program to the Acquirer and, if notified by the Acquirer in writing, shall cooperate with the Acquirer to provide the Acquirer the opportunity to, at the election of MWE, either: (a) enter into commercially reasonable arrangements to include, on behalf of the Acquirer in such Continuous Equity Program Registrable Securities equal to 20% of the total number of Common Units included or intended to be included in such Continuous Equity Program by MWE; or (b) enter into commercially reasonable alternative arrangements that would permit the Acquirer to resell Registrable Securities equal to 20% of the total number of Common Units included or intended to be included in such Continuous Equity Program by MWE to the public from time to time, pursuant to Rule 144 or such other method of distribution as may be agreed between MWE and the Acquirer. If the Acquirer participates in a Continuous Equity Program in accordance with this Section 2.04, the Acquirer and MWE shall enter into an equity distribution agreement with the distribution agent or distribution agents that contain such representations, covenants, indemnities and other rights and obligations as are customary in equity distribution agreements for continuous equity transaction programs. The Acquirer will not be permitted to participate in a Continuous Equity Program unless the Acquirer agrees to sell the applicable Registrable Securities on the basis provided in such equity distribution agreement and completes and executes all questionnaires, powers-of-attorney, indemnities and other documents reasonably required under the terms of such equity distribution agreement. The Acquirer shall not be required to make any representations or warranties to or agreements with MWE or the distribution agents other than representations, warranties or agreements regarding the Acquirer and its ownership of the securities to be subject to such equity distribution agreement and its intended method of distribution and any other representations required by Law. Each Holder shall keep any information relating to any such Continuous Equity Program confidential and shall not disseminate or in any way disclose such information

        Section 2.05    Sale Procedures.    In connection with its obligations under this Article II, MWE will, as expeditiously as possible:

        (a)   prepare and file with the Commission such amendments and supplements to the Shelf Registration Statement filed pursuant to Section 2.01(a) and the prospectus used in connection therewith as may be necessary to keep such Shelf Registration Statement effective for the Effectiveness Period and as may be necessary to comply with the provisions of the Securities Act with respect to the Disposition of all securities covered by such Shelf Registration Statement;

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        (b)   furnish to each Selling Holder (i) as far in advance as reasonably practicable before filing the Shelf Registration Statement to be filed pursuant to Section 2.01(a) or any other registration statement contemplated by this Agreement or any supplement or amendment thereto, upon request, copies of reasonably complete drafts of all such documents proposed to be filed (including exhibits and each document incorporated by reference therein to the extent then required by the rules and regulations of the Commission, which shall be deemed provided if such exhibits and documents are available on the Commission's website), and provide each such Selling Holder the opportunity to object to any information pertaining to such Selling Holder and its plan of distribution that is contained therein and make the corrections reasonably requested by such Selling Holder with respect to such information prior to filing such Shelf Registration Statement or such other registration statement and the prospectus included therein or any supplement or amendment thereto, and (ii) an electronic copy of such Shelf Registration Statement or such other registration statement and the prospectus included therein and any supplements and amendments thereto as such Selling Holder may reasonably request in order to facilitate the public sale or other Disposition of the Registrable Securities covered by such Shelf Registration Statement or other registration statement;

        (c)   if applicable, use its commercially reasonable efforts to register or qualify the Registrable Securities covered by the Shelf Registration Statement filed pursuant to Section 2.01(a) or any other registration statement contemplated by this Agreement under the securities or "blue sky" laws of such jurisdictions as the Selling Holders or, in the case of an Underwritten Offering, the Managing Underwriter, shall reasonably request; provided, however, that MWE shall not be required to qualify generally to transact business in any jurisdiction where it is not then required to so qualify or to take any action which would subject it to general service of process in any such jurisdiction where it is not then so subject;

        (d)   promptly notify each Selling Holder and each underwriter of Registrable Securities, at any time when a prospectus relating thereto is required to be delivered under the Securities Act, of (i) the filing of the Shelf Registration Statement filed pursuant to Section 2.01(a) or any other registration statement contemplated by this Agreement or any prospectus or prospectus supplement to be used in connection therewith, or any amendment or supplement thereto, and, with respect to such Shelf Registration Statement or any other registration statement or any post-effective amendment thereto, when the same has become effective; and (ii) the receipt of any written comments from the Commission with respect to any filing referred to in clause (i) and any written request by the Commission for amendments or supplements to such Shelf Registration Statement or any other registration statement or any prospectus or prospectus supplement thereto;

        (e)   immediately notify each Selling Holder and each underwriter of Registrable Securities, at any time when a prospectus relating thereto is required to be delivered under the Securities Act, of (i) the happening of any event as a result of which the prospectus or prospectus supplement contained in the Shelf Registration Statement filed pursuant to Section 2.01(a) or any other registration statement contemplated by this Agreement, as then in effect, or any supplemental amendment thereto, includes an untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make the statements therein not misleading in light of the circumstances then existing; (ii) the issuance or threat of issuance by the Commission of any stop order suspending the effectiveness of such Shelf Registration Statement or any other registration statement contemplated by this Agreement, or the initiation of any proceedings for that purpose; or (iii) the receipt by MWE of any notification with respect to the suspension of the qualification of any Registrable Securities for sale under the applicable securities or blue sky laws of any jurisdiction. Following the provision of such notice, MWE agrees to as promptly as practicable amend or supplement the prospectus or prospectus supplement or take other appropriate action so that the prospectus or prospectus supplement does not include an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances

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then existing and to take such other action as is necessary to remove a stop order, suspension, threat thereof or proceedings related thereto;

        (f)    upon request and subject to appropriate confidentiality obligations, furnish to each Selling Holder copies of all material correspondence with the Commission or any other governmental agency or self-regulatory body or other body having jurisdiction (including any domestic or foreign securities exchange) relating to such offering of Registrable Securities;

        (g)   in the case of an Underwritten Offering, furnish upon request, (i) an opinion letter of counsel for MWE dated the date of the closing under the underwriting agreement, including a standard "10b-5" letter and (ii) a "cold comfort" letter dated the Pricing Date of such Underwritten Offering and a letter of like kind dated the date of the closing under the underwriting agreement, in each case, signed by the independent public accountants who have certified MWE's financial statements included or incorporated by reference into the applicable registration statement, and each of the opinion and the "cold comfort" letter shall be in customary form and covering substantially the same matters with respect to such registration statement (and the prospectus included therein and any supplement thereto) and as are customarily covered in opinion letters of issuer's counsel and in accountants' letters delivered to the underwriters in underwritten offerings of equity securities;

        (h)   otherwise use its commercially reasonable efforts to comply with all applicable rules and regulations of the Commission, and make available to its security holders, as soon as reasonably practicable, an earnings statement, which earnings statement shall satisfy the provisions of Section 11(a) of the Securities Act and Rule 158 promulgated thereunder;

        (i)    make available to the appropriate representatives of the Managing Underwriter and Selling Holders access to such information and MWE personnel as is reasonable and customary to enable such parties to establish a due diligence defense under the Securities Act; provided, however, that MWE need not disclose any non-public information to any such representative unless and until such representative has entered into a confidentiality agreement with MWE reasonably satisfactory to MWE;

        (j)    cause all Registrable Securities registered pursuant to this Agreement to be listed on each National Securities Exchange, if any, on which similar securities issued by MWE are then listed;

        (k)   use its commercially reasonable efforts to cause the Registrable Securities to be registered with or approved by such other Governmental Authorities as may be necessary by virtue of the business and operations of MWE to enable the Selling Holders to consummate the Disposition of such Registrable Securities, subject to the last clause of Section 2.05(c);

        (l)    provide a transfer agent and registrar for Registrable Securities covered by the registration statement in respect of any registration of any Registrable Securities not later than the effective date of such registration statement; and

        (m)  take such other actions as are reasonably requested by the Selling Holders or the underwriters, if any, to expedite or facilitate the Disposition of such Registrable Securities. and

        Each Selling Holder, upon receipt of notice from MWE of the happening of any event of the kind described in subsection (e) of this Section 2.05, shall forthwith discontinue Disposition of the Registrable Securities until such Selling Holder's receipt of the copies of the supplemented or amended prospectus contemplated by subsection (e) of this Section 2.05 or until it is advised in writing by MWE that the use of the prospectus may be resumed, and has received copies of any additional or supplemental filings incorporated by reference in the prospectus, and, if so directed by MWE, such Selling Holder will deliver, or will request the Managing Underwriter or Managing Underwriters, if any, to deliver to MWE all copies in their possession or control, other than permanent file copies then in such Selling Holder's possession, of the prospectus and any prospectus supplement covering such Registrable Securities current at the time of receipt of such notice.

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        Section 2.06    Cooperation by Holders.    MWE shall have no obligation to include Registrable Securities of a Holder in a Shelf Registration Statement or in an Underwritten Offering or otherwise under Article II if such Selling Holder has failed to timely furnish such information that, in the reasonable opinion of counsel to MWE, is reasonably required for such registration statement or prospectus supplement, as applicable, to comply with the Securities Act.

        Section 2.07    Restrictions on Sale by Holders of Registrable Securities.    During the Effectiveness Period, each Holder of Registrable Securities who is included in the Shelf Registration Statement filed pursuant to Section 2.01(a) agrees not to effect any Disposition of Common Units during the 90 calendar day period beginning on the date that a prospectus supplement or other prospectus (including any free writing prospectus) is filed with the Commission with respect to an Underwritten Offering of equity securities of MWE; provided that the duration of the foregoing restrictions shall be no longer than the duration of the shortest restriction generally imposed by the underwriters on the officers, directors or any other unitholder of MWE on whom a restriction is imposed in connection with such public offering.

        Section 2.08    Expenses.

        (a)    Certain Definitions.    "Registration Expenses" means all expenses incident to MWE's performance under or compliance with this Agreement to effect the registration of Registrable Securities in the Shelf Registration Statement pursuant to Section 2.01(a), a Piggyback Offering pursuant to Section 2.02, an Underwritten Offering pursuant to Section 2.03, or any Continuous Equity Program or other arrangement contemplated by Section 2.04, and the Disposition of such securities pursuant thereto, including, without limitation, all customary registration, filing, securities exchange listing and securities exchange fees, all customary registration, filing, qualification and other fees and expenses of complying with securities or "blue sky" laws, fees of the Financial Industry Regulatory Authority, Inc., fees of transfer agents and registrars, all word processing, duplicating and printing expenses, the fees and disbursements of counsel to MWE and independent public accountants for MWE, including the expenses of any special audits or "cold comfort" letters required by or incident to such performance and compliance, and reasonable fees and expenses of one counsel for the Holders in such registration as a group (which counsel shall be selected by the Holders of a majority of the Registrable Securities included in such registration). "Selling Expenses" means all underwriting fees, discounts and selling commissions (and similar fees or arrangements associated with) and transfer taxes allocable to the sale of the Registrable Securities.

        (b)    Expenses.    MWE will pay all reasonable Registration Expenses as determined in good faith, including, in the case of an Underwritten Offering or a Piggyback Offering, whether or not any sale is made pursuant to the related registration statement. Except as otherwise provided in Section 2.08(a) or Section 2.09, MWE shall not be responsible for legal fees incurred by Holders in connection with the exercise of such Holders' rights and obligations under this Agreement, or for any Selling Expenses. Each Selling Holder shall pay all Selling Expenses in connection with any sale of its Registrable Securities.

        Section 2.09    Indemnification.    

        (a)    By MWE.    In the event of a registration of any Registrable Securities under the Securities Act pursuant to this Agreement, MWE will indemnify and hold harmless each Selling Holder, its directors, officers, employees, agents and managers, and each underwriter, pursuant to the applicable underwriting agreement with such underwriter, of Registrable Securities thereunder and each Person, if any, who controls such Selling Holder or underwriter within the meaning of the Securities Act and the Exchange Act, and its directors, officers, employees, agents and managers, against any losses, claims, damages, expenses or liabilities (including reasonable attorneys' fees and expenses) (collectively, "Losses"), joint or several, to which such Selling Holder or underwriter or controlling Person may become subject under the Securities Act, the Exchange Act or otherwise, insofar as such Losses (or

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actions or proceedings, whether commenced or threatened, in respect thereof) arise out of or are based upon any untrue statement or alleged untrue statement of any material fact (in the case of any prospectus, in the light of the circumstances under which such statement is made) contained in the Shelf Registration Statement filed pursuant to Section 2.01(a) or any other registration statement contemplated by this Agreement, any preliminary prospectus or final prospectus contained therein, or any free writing prospectus related thereto, or any amendment or supplement thereof, or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein (in the case of a prospectus, in the light of the circumstances under which they were made) not misleading, and will reimburse each such Selling Holder, its directors and officers, each such underwriter and each such controlling Person for any legal or other expenses reasonably incurred by them in connection with investigating or defending any such Loss or actions or proceedings; provided, however, that MWE will not be liable in any such case if and to the extent that any such Loss arises out of or is based upon an untrue statement or alleged untrue statement or omission or alleged omission so made in conformity with information furnished by such Selling Holder, such underwriter or such controlling Person in writing specifically for use in the Shelf Registration Statement or such other registration statement, free writing prospectus or prospectus supplement, as applicable. Such indemnity shall remain in full force and effect regardless of any investigation made by such Selling Holder or any such director, officer, employee, agent, manager or controlling Person, and shall survive the transfer of such securities by such Selling Holder.

        (b)    By Each Selling Holder.    Each Selling Holder agrees to indemnify and hold harmless MWE, its directors, officers, employees and agents and each Person, if any, who controls MWE within the meaning of the Securities Act or of the Exchange Act to the same extent as the foregoing indemnity from MWE to the Selling Holders, but only with respect to information regarding such Selling Holder furnished in writing by or on behalf of such Selling Holder expressly for inclusion in the Shelf Registration Statement filed pursuant to Section 2.01(a) or any other registration statement contemplated by this Agreement, any preliminary prospectus or final prospectus contained therein, or any free writing prospectus related thereto, or any amendment or supplement thereof; provided, however, that the liability of each Selling Holder shall not be greater in amount than the dollar amount of the proceeds (net of Selling Expenses) received by such Selling Holder from the sale of the Registrable Securities giving rise to such indemnification. Such indemnity shall remain in full force and effect regardless of any investigation made by or on behalf of MWE or any such director, officer, employee, agent, manager or controlling Person, and shall survive the transfer of such securities by such Selling Holder.

        (c)    Notice.    Promptly after any indemnified party has received notice of any indemnifiable claim hereunder, or the commencement of any action, suit or proceeding by a third person, which the indemnified party believes in good faith is an indemnifiable claim under this Agreement, the indemnified party shall give the indemnifying party written notice of such claim but failure to so notify the indemnifying party will not relieve the indemnifying party from any liability it may have to such indemnified party hereunder except to the extent that the indemnifying party is materially prejudiced by such failure. Such notice shall state the nature and the basis of such claim to the extent then known. The indemnifying party shall be entitled to participate in and, to the extent it shall wish, to assume and undertake the defense thereof with counsel reasonably satisfactory to such indemnified party and, after notice from the indemnifying party to such indemnified party of its election so to assume and undertake the defense thereof, the indemnifying party shall not be liable to such indemnified party under this Section 2.09 for any legal expenses subsequently incurred by such indemnified party in connection with the defense thereof other than reasonable costs of investigation and of liaison with counsel so selected; provided, however, that, (i) if the indemnifying party has failed to assume the defense and employ counsel or (ii) if the defendants in any such action include both the indemnified party and the indemnifying party and counsel to the indemnified party shall have concluded that there may be reasonable defenses available to the indemnified party that are different from or additional to

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those available to the indemnifying party, or if the interests of the indemnified party reasonably may be deemed to conflict with the interests of the indemnifying party, then the indemnified party shall have the right to select a separate counsel and to assume such legal defense and otherwise to participate in the defense of such action, with the reasonable out-of-pocket expenses and fees of such separate counsel and other reasonable out-of-pocket expenses related to such participation to be reimbursed by the indemnifying party as incurred. Notwithstanding any other provision of this Agreement, the indemnifying party shall not settle any indemnified claim without the consent of the indemnified party, unless the settlement thereof imposes no liability or obligation on, and includes a complete release from liability of, and does not contain any admission of wrongdoing by, the indemnified party.

        (d)    Contribution.    If the indemnification provided for in this Section 2.09 is held by a court or government agency of competent jurisdiction to be unavailable to any indemnified party or is insufficient to hold them harmless in respect of any Losses, then each such indemnifying party, in lieu of indemnifying such indemnified party, shall contribute to the amount paid or payable by such indemnified party as a result of such Loss in such proportion as is appropriate to reflect the relative fault of the indemnifying party on the one hand and of such indemnified party on the other in connection with the statements or omissions which resulted in such Losses, as well as any other relevant equitable considerations; provided, however, that in no event shall a Selling Holder be required to contribute an aggregate amount in excess of the dollar amount of proceeds (net of Selling Expenses) received by such Selling Holder from the sale of Registrable Securities giving rise to such indemnification. The relative fault of the indemnifying party on the one hand and the indemnified party on the other shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact has been made by, or relates to, information supplied by such party, and the parties' relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission. The parties hereto agree that it would not be just and equitable if contributions pursuant to this paragraph were to be determined by pro rata allocation or by any other method of allocation which does not take account of the equitable considerations referred to herein. The amount paid by an indemnified party as a result of the Losses referred to in the first sentence of this paragraph shall be deemed to include any legal and other expenses reasonably incurred by such indemnified party in connection with investigating or defending any Loss that is the subject of this paragraph. No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any Person who is not guilty of such fraudulent misrepresentation.

        (e)    Other Indemnification.    The provisions of this Section 2.09 shall be in addition to any other rights to indemnification or contribution that an indemnified party may have pursuant to Law, equity, contract or otherwise.

        Section 2.10    Limitations on Subsequent Registration Rights.    From and after the date of this Agreement, MWE shall not, without the prior written consent of the Holders of a majority of the Registrable Securities then outstanding, enter into any agreement with any holder or prospective holder of any securities of the Company that contains priority rights that contravene the priority rights of the Holders under Section 2.02(c); provided that this limitation shall not apply to any additional Person who becomes a party to this Agreement in accordance with Section 2.11. This Section 2.10 does not limit or restrict any outstanding agreements providing for registration rights between MWE and any other Person(s) entered into prior to the date of this Agreement.

        Section 2.11    Transfer or Assignment of Registration Rights.    The rights to cause MWE to register Registrable Securities granted to the Acquirer by MWE under this Article II may be transferred or assigned by a Holder to a transferee or assignee; provided, that the transferee or assignee is an Acquirer Group Member. The transferor shall give written notice to MWE at least ten Business Days prior to any said transfer or assignment, setting forth the information required under Section 3.01 for each such transferee and identifying the securities with respect to which such registration rights are

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being transferred or assigned, and each such transferee shall agree in writing to be subject to all of the terms and conditions of this Agreement.

ARTICLE III
MISCELLANEOUS

        Section 3.01    Communications; Holder Representative.    

        (a)   All notices and demands provided for hereunder shall be in writing and shall be given by hand delivery, electronic mail, facsimile, registered or certified mail, return receipt requested, regular mail, or air courier guaranteeing overnight delivery to the following addresses:

(i)    If to the Acquirer:

c/o M&R MWE Liberty, LLC
811 Main Street, Suite 4200
Houston, Texas 77002
Attention: Holder Representative

Facsimile: (713) 579-5010

Electronic mail: jraymond@emgtx.com
                           jrawls@emgtx.com
                           pwade@emgtx.com

with a copy (which shall not constitute notice) to:

Locke Lord LLP
600 Travis Street, Suite 2800
Houston, Texas 77002
Attention: H. William Swanstrom

Electronic mail: bswanstrom@lockelord.com

(ii)    If to MWE:

MarkWest Energy Partners, L.P.
1515 Arapahoe Street
Tower 1, Suite 1600
Denver, Colorado 80202-2126
Attention:    Senior Vice President and Chief Financial Officer
                    Senior Vice President and General Counsel

Facsimile: (303) 925-9305

Electronic mail:    nbuese@markwest.com
                              cbromley@markwest.com

or, if to a transferee of the Acquirer, to the transferee at the addresses provided pursuant to Section 2.10. All notices and communications shall be deemed to have been duly given: (i) at the time delivered by hand, if personally delivered; (ii) when notice is sent to the recipient provided that confirmation of receipt is obtained by sender orally, by facsimile or by electronic mail if sent by electronic mail; (iii) upon confirmation of delivery, if sent by facsimile; (iv) upon actual receipt if sent by registered or certified mail, return receipt requested, or regular mail, if mailed; and (v) upon actual receipt when delivered to an air courier guaranteeing overnight delivery.

        (b)   John T. Raymond is hereby appointed by the Acquirer and by any Person who may become a Holder from time to time (and their respective successors and assigns) as agent and attorney-in-fact

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with full power of substitution (the "Holder Representative") for the Acquirer and each such other Holder as the party authorized to: (i) to elect to exercise, or not exercise, any and all rights of the Acquirer and any such Holder arising under this Agreement, including those relating to the exercise of rights in respect of Underwritten Offerings under Article II; (ii) consent to and execute any amendment, waiver or consent of or under this Agreement; and (iii) give and receive notices, demands and other communications to or from the Acquirer or any such other Holder relating to the this Agreement and the transactions contemplated by this Agreement, in each case without having to seek or obtain the consent of the Acquirer or any such other Holder. The Holders may at any time remove and replace the Holder Representative by providing written notice thereof, executed by the Holders of at least a majority of the Registrable Securities to MWE.

        (c)   Notwithstanding anything to the contrary in this Agreement, wherever any notice, demand or other communication to the Acquirer, any other Holder or any group of Holders, or any Selling Holder or group of Selling Holders (including any such notice, demand or other communication under Article II) is provided for in this Agreement, such notice, demand or other communication shall be deemed duly given if delivered to the Holder Representative. MWE shall be entitled to act in full reliance and shall be protected from acting in reliance upon any notice, demand or other communication from the Holder Representative on behalf of the Acquirer, any other Holder or any group of Holders, or any Selling Holder or group of Selling Holders.

        Section 3.02    Successors and Assigns.    This Agreement shall inure to the benefit of and be binding upon the successors and assigns of each of the parties, including subsequent Holders of Registrable Securities to the extent permitted herein.

        Section 3.03    Interpretations.    In this Agreement, unless a clear contrary intention appears: (a) the singular includes the plural and vice versa; (b) reference to a Person includes such Person's successors and assigns but, in the case of a party, to this Agreement only if such successors and assigns are permitted by this Agreement, and reference to a Person in a particular capacity excludes such Person in any other capacity; (c) reference to any gender includes each other gender; (d) references to any Section, Article, subsection and other subdivision refer to the corresponding Sections, Articles, subsections and other subdivisions of this Agreement unless expressly provided otherwise; (e) references in any Section or Article or definition to any clause means such clause of such Section, Article or definition; (f) "hereunder," "hereof," "hereto" and words of similar import are references to this Agreement as a whole and not to any particular provision of this Agreement; (g) the word "or" is not exclusive, and the word "including" (in its various forms) means "including without limitation"; (h) references to "days" are to calendar days; and (i) all references to money refer to the lawful currency of the United States. The table of contents and Article and Section titles and headings in this Agreement are inserted for convenience of reference only and are not intended to be a part of, or to affect the meaning or interpretation of, this Agreement. Whenever any determination, consent or approval is to be made or given by MWE under this Agreement, such action shall be in the MWE's sole discretion unless otherwise specified.

        Section 3.04    Confidentiality.    The Acquirer agrees that all information that is not generally available to the public that is disclosed to the Acquirer pursuant to this Agreement, including any information regarding the expected price, timing or distribution of the Common Units expected be offered or the market for the Common Units in any Underwritten Offering ("Confidential Information"), shall be kept confidential by the Acquirer unless such Confidential Information (a) is known or becomes known to the public in general (other than as a result of a breach of this Section 3.04 by the Acquirer or any Person to whom Acquirer discloses such Confidential Information) or (b) is or has been made known or disclosed to the Acquirer by a third party without a breach of any obligation of confidentiality such third party may have to MWE; provided, however, that the Acquirer may disclose Confidential Information (i) to its attorneys, accountants, consultants and other professionals to the extent necessary to obtain their services in connection with monitoring its

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investment in MWE and who agree to abide by, or are otherwise bound by obligations of confidentiality sufficient to ensure compliance with, this Section 3.04; provided further that the Holder Representative shall use commercially reasonable efforts to limit broad disclosure of such information prior to any election of Holders to exercise rights to include Registered Securities in any Underwritten Offering or to participate in any Continuous Equity Program or other alternative arrangement under Section 2.04; (ii) to any prospective purchaser of any Registrable Securities from the Acquirer, if such Holder agrees in writing to become subject to the terms and conditions of the Section 3.04; (iii) to any existing or prospective Affiliate, partner, member, or wholly-owned subsidiary of the Acquirer in the ordinary course of business and who have a need to know, provided that the Acquirer informs such Person that such information is confidential and directs such Person to maintain the confidentiality of such information and such Person agrees to abide by, or is otherwise bound by obligations of confidentiality sufficient to ensure compliance with, this Section 3.04; or (iv) as may otherwise be required by Law, subpoena, civil investigation, court order, demand or similar legal process, provided that the Acquirer promptly notifies MWE in writing of such disclosure and takes reasonable steps to minimize the extent of such required disclosure. The Acquirer shall be responsible for any breach of the terms and conditions of this Section 3.04 by any Person described in clause (i), (ii) or (iii) of the preceding sentence.

        Section 3.05    Recapitalization, Exchanges, Etc. Affecting the Registrable Securities.    The provisions of this Agreement shall apply to the fullest extent set forth herein with respect to any and all limited partner interests of MWE or equity securities of any successor or assignee of MWE (whether by merger, consolidation, sale of assets or otherwise) that may be issued in respect of, in exchange for or in substitution of, the Registrable Securities, and shall be appropriately adjusted for combinations, splits, recapitalizations and the like occurring after the date of this Agreement.

        Section 3.06    Specific Performance.    Damages in the event of breach of this Agreement by a party hereto may be difficult, if not impossible, to ascertain, and it is therefore agreed that each such Person, in addition to and without limiting any other remedy or right it may have, will have the right to an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach, and enforcing specifically the terms and provisions hereof, and each of the parties hereto hereby waives any and all defenses it may have on the ground of lack of jurisdiction or competence of the court to grant such an injunction or other equitable relief. The existence of this right will not preclude any such Person from pursuing any other rights and remedies at law or in equity which such Person may have.

        Section 3.07    Counterparts.    This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which counterparts, when so executed and delivered, shall be deemed to be an original and all of which counterparts, taken together, shall constitute but one and the same Agreement.

        Section 3.08    Applicable Law, Submission to Jurisdiction.    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, BUT NOT LIMITED TO, 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.

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        Section 3.09    Waiver of Jury Trial.    THE PARTIES TO THIS AGREEMENT EACH HEREBY KNOWINGLY, VOLUNTARILY, INTENTIONALLY, AND IRREVOCABLY WAIVE, AND AGREE TO CAUSE THEIR AFFILIATES TO WAIVE, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY RIGHT TO TRIAL BY JURY OF ANY CLAIM, DEMAND, ACTION OR CAUSE OF ACTION (i) ARISING UNDER THIS AGREEMENT OR (ii) IN ANY WAY CONNECTED WITH OR RELATED OR INCIDENTAL TO THE DEALINGS OF THE PARTIES HERETO IN RESPECT OF THIS AGREEMENT OR ANY OF THE TRANSACTIONS RELATED HERETO, IN EACH CASE WHETHER NOW EXISTING OR HEREAFTER ARISING, AND WHETHER IN CONTRACT, TORT, EQUITY OR OTHERWISE. THE PARTIES TO THIS AGREEMENT EACH HEREBY AGREES AND CONSENTS THAT ANY SUCH CLAIM, DEMAND, ACTION OR CAUSE OF ACTION SHALL BE DECIDED BY COURT TRIAL WITHOUT A JURY AND THAT THE PARTIES TO THIS AGREEMENT MAY FILE AN ORIGINAL COUNTERPART OF A COPY OF THIS AGREEMENT WITH ANY COURT AS WRITTEN EVIDENCE OF THE CONSENT OF THE PARTIES HERETO TO THE WAIVER OF THEIR RIGHT TO TRIAL BY JURY.

        Section 3.10    Severability of Provisions.    Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof or affecting or impairing the validity or enforceability of such provision in any other jurisdiction.

        Section 3.11    Entire Agreement.    This Agreement is intended by the parties as a final expression of their agreement and intended to be a complete and exclusive statement of the agreement and understanding of the parties hereto in respect of the subject matter contained herein. There are no restrictions, promises, warranties or undertakings, other than those set forth or referred to herein with respect to the rights granted by MWE set forth herein. This Agreement supersedes all prior agreements and understandings between the parties with respect to such subject matter.

        Section 3.12    Amendment.    This Agreement may be amended only by means of a written amendment signed by MWE and the Holders of a majority of the then outstanding Registrable Securities; provided, however, that no such amendment shall disproportionately and adversely affect the rights of any Holder hereunder without the consent of such Holder.

        Section 3.13    No Presumption.    In the event any claim is made by a party relating to any conflict, omission, or ambiguity in this Agreement, no presumption or burden of proof or persuasion shall be implied by virtue of the fact that this Agreement was prepared by or at the request of a particular party or its counsel.

        Section 3.14    Obligations Limited to Parties to this Agreement.    Each of the parties hereto covenants, agrees and acknowledges that no Person other than the Acquirer, its permitted assignees and MWE shall have any obligation hereunder and that, notwithstanding that one or more of MWE and the Acquirer may be a corporation, partnership, limited liability company or other entity, no recourse under this Agreement or under any documents or instruments delivered in connection herewith or therewith shall be had against any former, current or future director, officer, employee, agent, general or limited partner, manager, member, stockholder or Affiliate of any of MWE, the Acquirer or their respective permitted assignees, or any former, current or future director, officer, employee, agent, general or limited partner, manager, member, stockholder or Affiliate of any of the foregoing, whether by the enforcement of any assessment or by any legal or equitable proceeding, or by virtue of any applicable Law, it being expressly agreed and acknowledged that no personal liability whatsoever shall attach to, be imposed on or otherwise by incurred by any former, current or future director, officer, employee, agent, general or limited partner, manager, member, stockholder or Affiliate of any of MWE, the Acquirer or any of their respective assignees, or any former, current or future director, officer, employee, agent, general or limited partner, manager, member, stockholder or Affiliate of any of the foregoing, as such, for any obligations of MWE, the Acquirer or their respective permitted assignees under this Agreement or any documents or instruments delivered in connection herewith or therewith or for any claim based on, in respect of or by reason of such obligation or its creation, except in each case for any assignee of a Holder.

[Signature Page Follows]

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        IN WITNESS WHEREOF, the parties hereto execute this Agreement, effective as of the date first above written.

MARKWEST ENERGY PARTNERS, L.P.
By:	MarkWest Energy GP, L.L.C., its general partner
By:	/s/ Frank M. Semple
Name:	Frank M. Semple
Title:	President and CEO

SIGNATURE PAGE TO
REGISTRATION RIGHTS AGREEMENT

M&R MWE LIBERTY, LLC
By:	/s/ John T. Raymond
Name:	John T. Raymond
Title:	CEO & Managing Partner

SIGNATURE PAGE TO
REGISTRATION RIGHTS AGREEMENT

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TABLE OF CONTENTS
REGISTRATION RIGHTS AGREEMENT
ARTICLE I DEFINITIONS
ARTICLE II REGISTRATION RIGHTS
ARTICLE III MISCELLANEOUS

EX-10.33

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Exhibit 10.33

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 NO. 3 TO
SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY
AGREEMENT OF MARKWEST LIBERTY MIDSTREAM & RESOURCES, L.L.C.

        This Amendment No. 3 dated December 19, 2011 (this "Amendment") to the Second Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources, L.L.C., dated as of November 1, 2009, as amended by that certain Amendment No. 1, dated as of November 20, 2009, and that certain Amendment No. 2, dated as of April 28, 2011 (as so amended and as further amended from time to time, the "Agreement"), is made and entered into by the Company and the undersigned Members of the Company, and hereby amends the Agreement as set forth herein. Capitalized terms not otherwise defined herein shall have the meaning in the Agreement.

        WHEREAS, the Members have never intended for a Transfer of Interests from the NGPMR Group to the MWE Liberty Group to be considered an NGPMR Exit Transaction or a Partial NGPMR Exit Transaction; and

        WHEREAS, pursuant to that unanimous written consent of the Managers and Members dated the date hereof, the Board and the Members have consented to this Amendment; and

        WHEREAS, the undersigned are the sole Members of the Company and pursuant to Section 15.9 of the Agreement, the Members and the Company desire to amend the Agreement to modify the Agreement in the manner set forth in this Amendment;

        NOW THEREFORE, in consideration of the mutual promises made herein, the parties, intending to be legally bound, hereby agree as follows:

        1.     Section 5.6 of the Agreement is hereby amended by deleting the first paragraph thereof and replacing it with the following:

        "In the event NGPMR receives cash from any NGPMR Exit Transaction or Partial NGPMR Exit Transaction, in each case other than such a transaction that consists of a Transfer of Interests by the NGPMR Group to the MWE Liberty Group (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:"

        2.     Section 7.2 of the Agreement is hereby amended to add Section 7.2(a)(iii) as follows:

        "(iii)  For the avoidance of doubt, for purposes of this Section 7.2(a), if any member of the NGPMR Group is a Transferring Member, a Third Party Offer to such member of the NGPMR Group for a ROFO Interest will not constitute a Qualifying Third Party Offer if the consideration that would be received by such member of the NGPMR Group for such ROFO Interest pursuant to such Third Party Offer, net of any amount** that would be required to be paid to MWE Liberty pursuant to Section 5.6 as a result of the Transfer of such ROFO Interest to the third party making such Third Party Offer, does not exceed the consideration payable to such member of the NGPMR Group for such ROFO Interest pursuant to any ROFO Offer made by any member or members of the MWE Liberty Group."

        3.     Except as hereby expressly modified by this Amendment, all terms of the Agreement remain in full force and effect. This Amendment shall bind and benefit the Company and its Members and their respective heirs, beneficiaries, administrators, executors, receivers, trustees, successors and assigns.

        4.     The Members agree that the actions of the Board, Members and officers previously taken in connection with the actions, elections and transactions of the Company and contemplated to be taken under this Amendment and the Consent are in all respects, authorized, approved, ratified and confirmed as the acts and deeds of the Company.

        5.     This Amendment may be executed in any number of counterparts, including by electronic transmission, with each such counterpart constituting an original and all of such counterparts constituting but one and the same instrument.

[SIGNATURE PAGE FOLLOWS]

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        IN WITNESS WHEREOF, the Company and the Members have executed this Amendment as of the date first written above pursuant to and in accordance with Section 15.9 of the Agreement.

COMPANY:
MARKWEST LIBERTY MIDSTREAM & RESOURCES, L.L.C., a Delaware limited liability company
By:	/s/ Frank M. Semple
Name:	Frank M. Semple
Title:	President and CEO
MEMBERS:
MARKWEST LIBERTY GAS GATHERING, L.L.C., a Delaware limited liability company		M&R MWE LIBERTY, LLC, a Delaware limited liability company
By:	/s/ Frank M. Semple	By:	/s/ John T. Raymond
Name:	Frank M. Semple	Name:	John T. Raymond
Title:	President and CEO	Title:	Managing Partner & CEO

SIGNATURE PAGE TO
AMENDMENT NO. 3 TO
SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY
AGREEMENT OF MARKWEST LIBERTY MIDSTREAM & RESOURCES, L.L.C.

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Exhibit 10.33

AMENDMENT NO. 3 TO SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT OF MARKWEST LIBERTY MIDSTREAM & RESOURCES, L.L.C.

EX-10.34

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Exhibit 10.34

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 (**).

Execution Version

CONTRIBUTION AGREEMENT

BY AND AMONG

M&R MWE LIBERTY, LLC,

MARKWEST ENERGY PARTNERS, L.P.

and

MARKWEST LIBERTY GAS GATHERING, L.L.C.

dated

December 29, 2011

TABLE OF CONTENTS

		Page
ARTICLE I DEFINITIONS AND INTERPRETATIONS			1
1.1.	Definitions		1
1.2.	Interpretations		1
ARTICLE II CONTRIBUTION OF THE CONTRIBUTED INTEREST; CLOSING			2
2.1.	Contribution of the Contributed Interest		2
2.2.	Contribution Consideration		2
2.3.	Time and Place of Closing; Effective Time		2
2.4.	Deliveries and Actions at Closing		2
ARTICLE III REPRESENTATIONS AND WARRANTIES OF THE CONTRIBUTOR			3
3.1.	Organization; Qualification		3
3.2.	Authority; Enforceability		3
3.3.	Non-Contravention		4
3.4.	Governmental Approvals		4
3.5.	Representations as to Contributed Interest		4
3.6.	Matters Relating to Transactions		5
3.7.	Brokers' Fee		5
ARTICLE IV REPRESENTATIONS AND WARRANTIES OF THE ACQUIRER PARTIES			6
4.1.	Organization; Qualification		6
4.2.	Authority; Enforceability		6
4.3.	Non-Contravention		6
4.4.	Governmental Approvals		7
4.5.	Capitalization		7
4.6.	Representations as to Unit Consideration		8
4.7.	MWE SEC Filings		8
4.8.	Matters Relating to Transactions		8
4.9.	Litigation		9
4.10.	Brokers' Fee		9
ARTICLE V COVENANTS OF THE PARTIES			9
5.1.	Certain Legends		9
5.2.	Expenses		10
5.3.	Further Assurances		10
5.4.	Public Statements		10
5.5.	Confidentiality		11
5.6.	Agreements Relating to MWE Partnership Agreement		11
5.7.	Tax Matters		11
5.8.	Agreements and Waivers Relating to Contributed Interest		13
ARTICLE VI SURVIVAL; RELATED MATTERS			13
6.1.	Survival		13
6.2.	Calculation of Losses		14
6.3.	Waiver of Certain Losses		14
6.4.	No Reliance		15
ARTICLE VII GENERAL PROVISIONS			15
7.1.	Notices		15
7.2.	Binding Effect		16
7.3.	Third Party Rights		16

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		Page
7.4.	Waiver of Compliance		16
7.5.	Applicable Law		16
7.6.	Waiver of Jury Trial		16
7.7.	Severability		17
7.8.	Amendment or Modification		17
7.9.	Assignment		17
7.10.	Waiver of Transfer Restrictions in Company LLC Agreement		17
7.11.	Counterparts		17
7.12.	No Recourse Against Non-Parties		17
7.13.	Representation by Counsel		17
7.14.	Entire Agreement; Supersedure		17

Exhibits

        Exhibit A—Definitions

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CONTRIBUTION AGREEMENT

        This CONTRIBUTION AGREEMENT (this "Agreement"), dated December 29, 2011, is made and entered into by and among M&R MWE Liberty, LLC, a Delaware limited liability company (the "Contributor"), on the one hand, and MarkWest Energy Partners, L.P., a Delaware limited partnership ("MWE") and MarkWest Liberty Gas Gathering, L.L.C., a Delaware limited liability company (the "Acquirer"), on the other hand. Each of the Acquirer and MWE is sometimes referred to individually in this Agreement as a "Acquirer Party," and such Parties are sometimes collectively referred to in this Agreement as the "Acquirer Parties."

        Each of the parties to this Agreement is sometimes referred to individually in this Agreement as a "Party" and all of the parties to this Agreement are sometimes collectively referred to in this Agreement as the "Parties."

R E C I T A L S

        WHEREAS, reference is hereby made to that certain Second Amended and Restated Limited Liability Company Agreement, dated as of November 1, 2009, as amended by that certain Amendment No. 1, dated as of November 20, 2009, as further amended by that certain Amendment No. 2, dated as of April 28, 2011 and as further amended by that certain Amendment No. 3, dated as of December 19, 2011 (as so amended, the "Company LLC Agreement"), of MarkWest Liberty Midstream & Resources, L.L.C., a Delaware limited liability company (the "Company"), by and among the Company, the Contributor and the Acquirer;

        WHEREAS, the Contributor owns 100% of the Class A Interests in the Company (the "Contributed Interest"); and

        WHEREAS, subject to the terms and conditions of this Agreement, the Contributor desires to contribute to the Acquirer, and the Acquirer desires to accept the contribution of, the Contributed Interest in exchange for a transfer of cash in the amount set forth in this Agreement and the issuance of certain limited partnership interests of MWE to the Contributor.

A G R E E M E N T S

        NOW, THEREFORE, in consideration of the representations, warranties, agreements and covenants contained in this Agreement, and other good and valuable consideration, the receipt and legal sufficiency of which are hereby acknowledged, the Parties undertake and agree as follows:

ARTICLE I
DEFINITIONS AND INTERPRETATIONS

        1.1.Definitions.    Capitalized terms used in this Agreement but not defined in the body of this Agreement shall have the respective meanings ascribed to such terms in Exhibit A. Capitalized terms defined in the body of this Agreement are listed in Exhibit A by location of the definitions of such terms in the body of this Agreement.

        1.2.Interpretations.    In this Agreement, unless a clear contrary intention appears: (a) the singular includes the plural and vice versa; (b) reference to a Person includes such Person's successors and assigns but, in the case of a Party, only if such successors and assigns are permitted by this Agreement, and reference to a Person in a particular capacity excludes such Person in any other capacity; (c) reference to any gender includes each other gender; (d) references to any Exhibit, Schedule, Section, Article, subsection and other subdivision refer to the corresponding Exhibits, Schedules, Sections, Articles, subsections and other subdivisions of this Agreement unless expressly provided otherwise; (e) references in any Section or Article or definition to any clause means such clause of such Section, Article or definition; (f) "hereunder," "hereof," "hereto" and words of similar import are

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references to this Agreement as a whole and not to any particular provision of this Agreement; (g) the word "or" is not exclusive, and the word "including" (in its various forms) means "including without limitation"; (h) references to "days" are to calendar days; (i) all references to money refer to the lawful currency of the United States and (j) references to the "date of this Agreement" or the "date hereof" shall mean December 29, 2011. The Table of Contents and the Article and Section titles and headings in this Agreement are inserted for convenience of reference only and are not intended to be a part of, or to affect the meaning or interpretation of, this Agreement.

ARTICLE II
CONTRIBUTION OF THE CONTRIBUTED INTEREST; CLOSING

        2.1.Contribution of the Contributed Interest.    Upon the terms contained in this Agreement, at the Closing the Contributor shall contribute, assign, transfer and deliver to MWE, and MWE, through its subsidiary, the Acquirer, shall acquire and accept from the Contributor, the Contributed Interest.

        2.2.Contribution Consideration.    The total consideration (the "Contribution Consideration") to be delivered by the Acquirer, or by MWE on behalf of the Acquirer, to the Contributor in exchange for the contribution, assignment, transfer and delivery of the Contributed Interest shall be as follows:

        (a)   cash in the aggregate amount of $994,000,000 (the "Cash Consideration"), consisting of the Cash Sale Consideration and the Cash Distribution Consideration; and

        (b)   the Unit Consideration.

        2.3.Time and Place of Closing; Effective Time.    The closing of the contribution, assignment, transfer and delivery of the Contributed Interest to the Acquirer and the other transactions contemplated by this Agreement (the "Closing") will take place at the offices of Vinson & Elkins L.L.P., 1001 Fannin Street, Suite 2500, Houston, Texas 77002 on December 29, 2011. The Parties acknowledge and agree that the Closing shall be effective on December 29, 2011 for all purposes other than the purposes specified in Section 5.7(d), for which purposes the Closing will be deemed effective as of 11:59 p.m., Denver, Colorado time, on December 31, 2011.

        2.4.Deliveries and Actions at Closing.    

        (a)    Deliveries and Actions of Acquirer Parties.    The Acquirer Parties will execute and deliver, or cause to be executed and delivered, to the Contributor, each of the following documents, where the execution or delivery of documents is contemplated, and will take or cause to be taken the following actions, where the taking of actions is contemplated:

        (i)    Cash Consideration.    Transfer of the Cash Consideration to the Contributor by wire transfer of immediately available funds to an account designated by the Contributor;

        (ii)    Unit Consideration.    The Unit Consideration issued and delivered to the Contributor by one or more certificates representing the MWE Class B Units comprising the Unit Consideration.

        (iii)    Amendment No. 1 to MWE Partnership Agreement.    A copy of Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., in the form mutually agreed by the Parties (the "MWE Partnership Agreement Amendment"), duly executed by the MWE GP and MarkWest Hydrocarbon, Inc., a Delaware corporation;

        (iv)    Registration Rights Agreement.    A counterpart of a registration rights agreement, in the form mutually agreed by the Parties (the "Registration Rights Agreement"), duly executed by MWE; and

        (v)    Assignment of Interests.    A counterpart of an assignment in the form mutually agreed by the Parties (the "Assignment of Interests"), evidencing the assignment, transfer and delivery to

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MWE, through its subsidiary, the Acquirer, of the Contributed Interest, duly executed by the Acquirer Parties.

        (b)    Deliveries and Actions of the Contributor.    At the Closing, the Contributor will execute and deliver, or cause to be executed and delivered, to the Acquirer Parties, each of the following documents, where the execution or delivery of documents is contemplated, and will take or cause to be taken the following actions, where the taking of actions is contemplated:

        (i)    FIRPTA Certificates.    A certificate of the Contributor, or its tax regarded owner if the Contributor is a disregarded entity, in the form specified in Treasury Regulation Section 1.1445-2(b)(2)(iv) that the Contributor is not a "foreign person" within the meaning of Section 1445 of the Code;

        (ii)    Registration Rights Agreement.    A counterpart of the Registration Rights Agreement, duly executed by the Contributor;

        (iii)    Assignment of Interests.    A counterpart of the Assignment of Interests, duly executed by the Contributor;

        (iv)    Evidence of Release of Liens.    Written evidence, in form reasonably satisfactory to the Acquirer Parties, of the release of any Liens on the Interests; and

        (v)    Resignations.    The written resignations of John T. Raymond, Jeffrey Rawls and Patrick Wade as Managers of the Company, in each case in form and substance reasonably satisfactory to the Acquirer Parties and effective prior to or concurrently with the Closing.

ARTICLE III
REPRESENTATIONS AND WARRANTIES OF THE CONTRIBUTOR

        The Contributor hereby represents and warrants to the Acquirer Parties as follows:

        3.1.Organization; Qualification.    The Contributor is a legal entity duly formed, validly existing and in good standing under the laws of the State of Delaware and has all requisite organizational power and authority to own, lease and operate its properties and to carry on its business as it is now being conducted, and is duly qualified, registered or licensed to do business as a foreign entity and is in good standing in each jurisdiction in which the property owned, leased or operated by such Person or the nature of the business conducted by such Person makes such qualification necessary, except where the failure to be so duly qualified, registered or licensed and in good standing would not reasonably be expected to prevent or materially delay the consummation of the transactions contemplated by the Transaction Documents to which the Contributor is a party or to materially impair the Contributor's ability to perform its obligations under the Transaction Documents to which it is a party.

        3.2.Authority; Enforceability.    

        (a)   The Contributor has the requisite power and authority to execute and deliver the Transaction Documents to which it is a party, and to consummate the transactions contemplated thereby. The execution and delivery by the Contributor of the Transaction Documents to which the Contributor is a party, and the consummation by the Contributor of the transactions contemplated thereby, have been duly and validly authorized by the Contributor, and no other limited liability company proceedings on the part of the Contributor are necessary to authorize the Transaction Documents to which it is a party or to consummate the transactions contemplated by the Transaction Documents to which it is a party.

        (b)   The Transaction Documents to which the Contributor is a party have been duly executed and delivered by the Contributor, and, assuming the due authorization, execution and delivery by the other parties thereto (other than the Contributor), each Transaction Document to which the Contributor is a party constitutes the valid and binding agreement of the Contributor, enforceable against the

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Contributor in accordance with its terms, except as such enforceability may be limited by applicable bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and similar Laws relating to or affecting creditors' rights generally and subject, as to enforceability, to legal principles of general applicability governing the availability of equitable remedies, including principles of commercial reasonableness, good faith and fair dealing (regardless of whether such enforceability is considered in a proceeding in equity or at law) (collectively, "Creditors' Rights").

        3.3.Non-Contravention.    The execution, delivery and performance of the Transaction Documents to which the Contributor is a party by the Contributor and the consummation by the Contributor of the transactions contemplated thereby does not and will not: (a) result in any breach of any provision of the Organizational Documents of the Contributor; (b) except with respect to the Contributor Credit Agreement, which shall be fully repaid and terminated at or prior to the Closing, constitute a default (or an event that with notice or passage of time or both would give rise to a default) under, or give rise to any right of termination, cancellation, amendment or acceleration (with or without the giving of notice, or the passage of time or both) under any of the terms, conditions or provisions of any Contract to which the Contributor is a party or by which any property or asset of the Contributor is bound or affected; or (c) violate any Law to which the Contributor is subject or by which any of the Contributor's properties or assets is bound, except, in the cases of clauses (b) and (c), for such defaults or rights of termination, cancellation, amendment, or acceleration or violations as would not reasonably be expected to prevent or materially delay the consummation of the transactions contemplated by the Transaction Documents to which the Contributor is a party or to materially impair the Contributor's ability to perform its obligations under the Transaction Documents to which it is a party.

        3.4.Governmental Approvals.    No declaration, filing or registration with, or notice to, or authorization, consent or approval of, any Governmental Authority is necessary for the consummation by the Contributor of the transactions contemplated by the Transaction Documents to which it is a party, other than such declarations, filings, registrations, notices, authorizations, consents or approvals that have been obtained or made or that would in the ordinary course be made or obtained after the Closing, or which, if not obtained or made, would not reasonably be expected to prevent or materially delay the consummation of the transactions contemplated by the Transaction Documents to which the Contributor is a party or to materially impair the Contributor's ability to perform its obligations under the Transaction Documents to which it is a party.

        3.5.Representations as to Contributed Interest.    

        (a)   The Contributed Interest constitutes all of the equity interests of the Company owned beneficially or of record by the Contributor or its Affiliates.

        (b)   The Contributor is the sole record and beneficial owner of, and has good and valid title to, the Contributed Interest, free and clear of all Liens other than (i) the Lien evidenced by the Contributor Credit Agreement, which Lien shall be extinguished upon the full repayment and termination of the Contributor Credit Agreement at or prior to the Closing, (ii) any transfer restrictions imposed by federal and state securities laws and (iii) any transfer restrictions contained in the Organizational Documents of the Company.

        (c)   At the Closing, the Contributor will assign, convey, transfer and deliver to MWE, through the Acquirer, good and valid title to the Contributed Interest, free and clear of all Liens other than (i) any transfer restrictions imposed by federal and state securities laws, (ii) any transfer restrictions contained in the Organizational Documents of the Company and (iii) any Liens on the Contributed Interest as a result of actions by the Acquirer Parties or their Affiliates.

        (d)   Neither the Contributor nor any of its Affiliates is a party to any agreements, arrangements or commitments obligating the Contributor to grant, deliver or sell, or cause to be granted, delivered or sold, the Contributed Interest, by sale, lease, license or otherwise, other than this Agreement.

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        (e)   Except as set forth in the Company LLC Agreement, there are no voting trusts, proxies or other agreements or understandings to which the Contributor is bound with respect to the voting of the Contributed Interest.

        3.6.Matters Relating to Transactions.    

        (a)   The Contributor has such knowledge and experience in financial and business matters so as to be capable of evaluating the merits and risks of its investment in the Unit Consideration and is capable of bearing the economic risk of such investment. The Contributor is an "accredited investor" as that term is defined in Rule 501 of Regulation D (without regard to Rule 501(a)(4)) promulgated under the Securities Act. The Contributor is acquiring the Unit Consideration for investment for its own account and not with a view toward or for sale in connection with any distribution thereof, or with any present intention of distributing or selling the Unit Consideration. The Contributor is not a party to any Contract with any Person to sell, transfer or grant participations to such Person or to any third Person, with respect to the Unit Consideration. The Contributor acknowledges and understands that (i) the acquisition of the Unit Consideration has not been registered under the Securities Act in reliance on an exemption therefrom and (ii) that the Unit Consideration will be characterized as "restricted securities" under state and federal securities laws. The Contributor agrees that the Unit Consideration may not be sold, transferred, offered for sale, pledged, hypothecated or otherwise disposed of except (i) pursuant to an effective registration statement under the Securities Act or pursuant to an available exemption from the registration requirements of the Securities Act, and in compliance with other applicable state and federal securities laws and (ii) in compliance with all transfer restrictions in the MWE Partnership Agreement, including the transfer restrictions applicable to the Contributor set forth in Sections 4.6(e) and 4.6(f) of the MWE Partnership Agreement.

        (b)   The Contributor has had an opportunity to ask questions and receive answers from the Acquirer Parties regarding the terms and conditions of the contribution of the Contributed Interest and the offering of the Unit Consideration pursuant to this Agreement and the business, properties, prospects, and financial condition of the Company and MWE. The foregoing, however, does not modify the representations and warranties of the Acquirer Parties in Article IV and such representations and warranties constitute the sole and exclusive representations and warranties of the Acquirer Parties to the Contributor in connection with the transactions contemplated by this Agreement.

        (c)   The Contributor has all right, power and authority necessary to enter into the MWE Partnership Agreement at the Closing upon its receipt of the Unit Consideration.

        3.7.Brokers' Fee.    Except for the fee payable to Citigroup Global Markets Group, Inc., which shall be paid by the Contributor, no broker, investment banker, financial advisor or other Person is entitled to any broker's, finder's, financial advisor's or other similar fee or commission in connection with the transactions contemplated by this Agreement based upon arrangements made by or on behalf of the Contributor.

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ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF THE ACQUIRER PARTIES

        The Acquirer Parties hereby jointly and severally represent and warrant to the Contributor as follows:

        4.1.Organization; Qualification.    

        (a)   Each Acquirer Party is a legal entity duly formed, validly existing and in good standing under the laws of Delaware and has all requisite organizational power and authority to own, lease and operate its properties and to carry on its business as it is now being conducted, and is duly qualified, registered or licensed to do business as a foreign entity and is in good standing in each jurisdiction in which the property owned, leased or operated by it or the nature of its business makes such qualification necessary, except where the failure to be so duly qualified, registered or licensed and in good standing would not reasonably be expected to have an MWE Material Adverse Effect or to prevent or materially delay the consummation of the transactions contemplated by the Transaction Documents to which it is a party or to materially impair its ability to perform its obligations under the Transaction Documents to which it is a party.

        (b)   MWE is properly treated as a partnership for U.S. federal income tax purposes. MWE would not be treated as an investment company (within the meaning of Code Section 351) if it were incorporated.

        (c)   Acquirer is disregarded as an entity separate from its owner for U.S. federal income tax purposes within the meaning of Treasury Regulation Section 301.7701-3(b). Acquirer has not elected to be classified as an association, taxable as a corporation, within the meaning of Treasury Regulation Section 301.7701.3(a), and will not make any such election that would be contrary to the treatment agreed upon by the Parties in Section 5.7(b).

        4.2.Authority; Enforceability.    

        (a)   Each Acquirer Party has the requisite power and authority to execute and deliver the Transaction Documents to which it is a party, and to consummate the transactions contemplated thereby. The execution and delivery by each Acquirer Party of the Transaction Documents to which it is a party, and the consummation by it of the transactions contemplated thereby, have been duly and validly authorized by such Acquirer Party, and no other limited liability company or limited partnership proceedings, as applicable, on the part of such Acquirer Party are necessary to authorize the Transaction Documents to which it is a party or to consummate the transactions contemplated by the Transaction Documents to which it is a party.

        (b)   The Transaction Documents to which each Acquirer Party is a party have been duly executed and delivered by such Acquirer Party, and, assuming the due authorization, execution and delivery by the other parties thereto, each Transaction Document to which such Acquirer Party is a party constitutes the valid and binding agreement of such Acquirer Party, enforceable against such Acquirer Party in accordance with its terms, except as such enforceability may be limited by Creditors' Rights.

        4.3.Non-Contravention.    

        (a)   The execution, delivery and performance of the Transaction Documents to which each Acquirer Party is a party by such Acquirer Party and the consummation by each Acquirer Party of the transactions contemplated thereby does not and will not: (a) result in any breach of any provision of the Organizational Documents of each Acquirer Party; (b) constitute a default (or an event that with notice or passage of time or both would give rise to a default) under, or give rise to any right of termination, cancellation, amendment or acceleration (with or without the giving of notice, or the passage of time or both) under any of the terms, conditions or provisions of any Contract to which such Acquirer Party is a party or by which any property or asset of such Acquirer Party is bound or

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affected; or (c) violate any Law to which either Acquirer Party is subject or by which any of such Acquirer Party's properties or assets is bound, except, in the cases of clauses (b) and (c), for such defaults or rights of termination, cancellation, amendment, or acceleration or violations as would not reasonably be expected to have an MWE Material Adverse Effect or to prevent or materially delay the consummation of the transactions contemplated by the Transaction Documents to which each Acquirer Party is a party or to materially impair such Acquirer Party's ability to perform its obligations under the Transaction Documents to which it is a party.

        (b)   Except for such consents as have been obtained at or prior to the Closing, no consents are required under the MWE Credit Agreements or MWE Indentures to permit the consummation of the Transactions.

        4.4.Governmental Approvals.    No declaration, filing or registration with, or notice to, or authorization, consent or approval of, any Governmental Authority is necessary for the consummation by either Acquirer Party of the transactions contemplated by the Transaction Documents to which it is a party, other than such declarations, filings, registrations, notices, authorizations, consents or approvals which, if not obtained or made, would not reasonably be expected to have an MWE Material Adverse Effect or to prevent or materially delay the consummation of the transactions contemplated by the Transaction Documents to which either Acquirer Party is a party or to materially impair either Acquirer Party's ability to perform its obligations under the Transaction Documents to which it is a party.

        4.5.Capitalization.    

        (a)   As of the date of this Agreement, 94,939,558 MWE Common Units are issued and outstanding and 22,640,000 MWE Class A Units are issued and outstanding. Such Common Units and Class A Units represent the only limited partnership interests of MWE outstanding as of the date of this Agreement.

        (b)   All of the limited partner interests in MWE are duly authorized and validly issued in accordance with the Organizational Documents of MWE, and are fully paid (to the extent required under the Organizational Documents of MWE) and nonassessable (except as nonassessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) and were not issued in violation of any preemptive rights, rights of first refusal or other similar rights of any Person.

        (c)   Except as set forth in the Organizational Documents of MWE, there are no preemptive rights, conversion rights, redemption rights or other similar rights that obligate MWE to issue or sell any equity interests in MWE or any securities or obligations convertible or exchangeable into or exercisable for, or giving any Person a right to subscribe for or acquire, any equity interests in MWE, and no securities or obligations evidencing such rights are authorized, issued or outstanding.

        (d)   Except as set forth in the Organizational Documents of MWE or in the Transaction Documents, or as described in the MWE SEC Filings (including, for purposes of this Section 4.5, the exhibits to or filed with such MWE SEC Filings), or as otherwise issued pursuant to MWE's equity incentive plans, there are no options, warrants, stock appreciation rights, or similar agreements or arrangements that obligate MWE to issue or sell any equity interests of MWE or any securities or obligations convertible or exchangeable into or exercisable for, or giving any Person a right to subscribe for or acquire, any equity interests in MWE, and no securities or obligations evidencing such rights are authorized, issued or outstanding.

        (e)   MWE does not have any outstanding bonds, debentures, notes or other obligations the holders of which have the right to vote (or convertible into or exercisable for securities having the right to vote) with the holders of equity interests in MWE on any matter.

        (f)    MarkWest Energy GP, L.LC., a Delaware limited liability company ("MWE GP") is the sole general partner of MWE with a 0.0% General Partner Interest (as defined in the MWE Partnership

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Agreement) in MWE (the "MWE GP Interest"). The MWE GP Interest has been duly authorized and validly issued in accordance with the MWE Partnership Agreement and has not been issued in violation of any preemptive rights, rights of first refusal or other similar rights of any Person.

        4.6.Representations as to Unit Consideration.    

        (a)   The issuance of the MWE Class B Units comprising the Unit Consideration and the MWE Common Units issuable upon conversion of such MWE Class B Units has been duly authorized in accordance with the Organizational Documents of MWE. The MWE Class B Units comprising the Unit Consideration, when issued and delivered to the Contributor in accordance with the terms of this Agreement, and the MWE Common Units issuable upon conversion of such MWE Class B Units, when issued upon conversion of such MWE Class B Units, in each case will be validly issued, fully paid (to the extent required under the Organizational Documents of MWE), nonassessable (except to the extent nonassessability may be affected by Sections 17-303, 17-607 and 17-804 of the Delaware LP Act) and free and clear of all Liens other than (i) any transfer restrictions imposed by federal and state securities laws, and (ii) any transfer restrictions contained in the Organizational Documents of MWE.

        (b)   Upon issuance and delivery of the Unit Consideration, the MWE Class B Units comprising the Unit Consideration shall have those rights, preferences, privileges and restrictions governing the MWE Class B Units, as applicable, as set forth in the MWE Partnership Agreement. Further, the MWE Common Units issuable upon conversion of such MWE Class B Units shall have those rights, preferences, privileges and restrictions governing the MWE Common Units, as applicable, as set forth in the MWE Partnership Agreement.

        (c)   Upon issuance and delivery of the Unit Consideration, the Contributor will be duly admitted to MWE as an additional limited partner.

        4.7.MWE SEC Filings.    MWE has filed with the SEC: (a) its Annual Report on Form 10-K for the fiscal year ended December 31, 2010; (b) such Quarterly Reports on Form 10-Q since December 31, 2010 as are required to be filed pursuant to the Exchange Act; (c) such Current Reports on Form 8-K since December 31, 2010 as are required to be filed pursuant to the Exchange Act; (d) all proxy statements relating to all meetings of MWE's unitholders (whether annual or special) since December 31, 2010; and (e) all other reports required to be filed by MWE with the SEC after December 31, 2010 pursuant to Section 13(a) of the Exchange Act (each such document, excluding any exhibits thereto, an "MWE SEC Filing"). Each MWE SEC Filing, at the time such report was filed with or furnished to the SEC complied in all material respects with the Securities Act and the Exchange Act. No MWE SEC Filing, at the time such report was filed with or furnished to the SEC, contained any untrue statement of a material fact or omitted to state any material fact required to be stated therein in order to make the statements contained therein, in light of the circumstances under which they were made, not misleading. The financial statements of MWE included in the MWE SEC Filings complied as to form in all material respects with published rules and regulations of the SEC with respect thereto, were prepared in accordance with GAAP applied on a consistent basis throughout the periods indicated (except as may be indicated in the notes thereto or, in the case of unaudited financial statements, as permitted under Form 10-Q or Form 8-K under the Exchange Act) and fairly presented in all material respects the consolidated financial position of MWE and its consolidated subsidiaries as of the respective dates thereof and the consolidated results of MWE's operations and cash flows for the periods indicated (subject, in the case of unaudited statements, to normal and recurring year end audit adjustments).

        4.8.Matters Relating to Transactions.    

        (a)   The Acquirer Parties have such knowledge and experience in financial and business matters so as to be capable of evaluating the merits and risks of its investment in the Contributed Interest and are capable of bearing the economic risk of such investment. Each Acquirer Party is an "accredited

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investor" as that term is defined in Rule 501 of Regulation D (without regard to Rule 501(a)(4)) promulgated under the Securities Act. MWE, through its subsidiary, the Acquirer, is acquiring the Contributed Interest for investment for its own account and not with a view toward or for sale in connection with any distribution thereof, or with any present intention of distributing or selling the Contributed Interest. Neither Acquirer Party has any Contract or arrangement with any Person to sell, transfer or grant participations to such Person or to any third Person, with respect to the Contributed Interest. Each Acquirer Party acknowledges and understands that (i) the acquisition of the Contributed Interest has not been registered under the Securities Act in reliance on an exemption therefrom and (ii) that the Contributed Interest will be characterized as "restricted securities" under state and federal securities laws.

        (b)   Each Acquirer Party has had an opportunity to ask questions and receive answers from the Contributor regarding the terms and conditions of the contribution of the Contributed Interest. The foregoing, however, does not modify the representations and warranties of the Contributor Parties in Article III and such representations and warranties constitute the sole and exclusive representations and warranties of the Contributor to the Acquirer Parties in connection with the transactions contemplated by this Agreement

        4.9.Litigation.    As of the date of this Agreement, except as described in the MWE SEC Filings, there are no pending or, to the knowledge of the Acquirer Parties, threatened legal or governmental proceedings to which any Acquirer Party is or, to the knowledge of the Acquirer Parties, is threatened to be a party to that would reasonably be expected to have an MWE Material Adverse Effect or to prevent or materially delay the consummation of the transactions contemplated by the Transaction Documents to which any Acquirer Party is a party or to materially impair any Acquirer Party's ability to perform its obligations under the Transaction Documents to which it is a party.

        4.10.Brokers' Fee.    Except for the fee payable to Morgan Stanley & Co. LLC, which shall be paid by the Acquirer Parties, no broker, investment banker, financial advisor or other Person is entitled to any broker's, finder's, financial advisor's or other similar fee or commission in connection with the transactions contemplated by this Agreement based upon arrangements made by or on behalf of the Acquirer Parties.

ARTICLE V
COVENANTS OF THE PARTIES

        5.1.Certain Legends.    

        (a)   The Contributor agrees that, so long as the restrictions described in the following legends are applicable, each certificate representing, and each ownership statement issued under a book-entry system maintained with respect to, all or any portion of the MWE Class B Units comprising the Unit Consideration and the MWE Common Units issuable upon the conversion of such MWE Class B Units shall bear the following legends:

THIS SECURITY HAS NOT BEEN REGISTERED UNDER THE SECURITIES ACT OF 1933, AS AMENDED. IT MAY NOT BE SOLD, OFFERED FOR SALE, PLEDGED OR HYPOTHECATED IN THE ABSENCE OF A REGISTRATION STATEMENT IN EFFECT WITH RESPECT TO THE SECURITIES UNDER SUCH ACT OR AN OPINION OF COUNSEL SATISFACTORY TO MARKWEST ENERGY PARTNERS, L.P. THAT SUCH REGISTRATION IS NOT REQUIRED.

THIS SECURITY IS SUBJECT TO RESTRICTIONS ON TRANSFER SET FORTH IN SECTIONS 4.6(E) AND 4.6(F) OF AND ELSEWHERE IN THE THIRD AMENDED AND RESTATED AGREEMENT OF LIMITED PARTNERSHIP OF MARKWEST ENERGY PARTNERS, L.P., AS AMENDED BY AMENDMENT NO. 1 THERETO, AND AS FURTHER

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AMENDED, SUPPLEMENTED OR RESTATED FROM TIME TO TIME (THE "PARTNERSHIP AGREEMENT") AND THE VOTING RESTRICTIONS SET FORTH IN SECTION 5.7(D) OF THE PARTNERSHIP AGREEMENT AND IN THE DEFINITION OF THE DEFINED TERM "OUTSTANDING" IN THE PARTNERSHIP AGREEMENT.

THE HOLDER OF THIS SECURITY ACKNOWLEDGES FOR THE BENEFIT OF MARKWEST ENERGY PARTNERS, L.P. THAT THIS SECURITY MAY NOT BE SOLD, OFFERED, RESOLD, PLEDGED OR OTHERWISE TRANSFERRED IF SUCH TRANSFER WOULD (A) VIOLATE THE THEN APPLICABLE FEDERAL OR STATE SECURITIES LAWS OR RULES AND REGULATIONS OF THE SECURITIES AND EXCHANGE COMMISSION, ANY STATE SECURITIES COMMISSION OR ANY OTHER GOVERNMENTAL AUTHORITY WITH JURISDICTION OVER SUCH TRANSFER, (B) TERMINATE THE EXISTENCE OR QUALIFICATION OF MARKWEST ENERGY PARTNERS L.P. UNDER THE LAWS OF THE STATE OF DELAWARE, OR (C) CAUSE MARKWEST ENERGY PARTNERS, L.P. TO BE TREATED AS AN ASSOCIATION TAXABLE AS A CORPORATION OR OTHERWISE TO BE TAXED AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES (TO THE EXTENT NOT ALREADY SO TREATED OR TAXED). MARKWEST ENERGY GP, L.L.C., THE GENERAL PARTNER OF MARKWEST ENERGY PARTNERS, L.P., MAY IMPOSE ADDITIONAL RESTRICTIONS ON THE TRANSFER OF THIS SECURITY IF IT RECEIVES AN OPINION OF COUNSEL THAT SUCH RESTRICTIONS ARE NECESSARY TO AVOID A SIGNIFICANT RISK OF MARKWEST ENERGY PARTNERS, L.P. BECOMING TAXABLE AS A CORPORATION OR OTHERWISE BECOMING TAXABLE AS AN ENTITY FOR FEDERAL INCOME TAX PURPOSES.

        (b)   The Contributor agrees that, so long as the restrictions described in the following legends are applicable, in addition to the legends set forth in Section 5.1(a) each certificate representing, and each ownership statement issued under a book-entry system maintained with respect to, all or any portion of the MWE Class B Units comprising the Unit Consideration shall bear the following legend:

THIS SECURITY IS SUBJECT TO THE RIGHTS SET FORTH IN SECTION 6.2 OF THAT CERTAIN CONTRIBUTION AGREEMENT, DATED DECEMBER 29, 2011, BY AND AMONG M&R MWE LIBERTY, LLC, MARKWEST ENERGY PARTNERS, L.P. AND MARKWEST LIBERTY GAS GATHERING, L.L.C.

        5.2.Expenses.    All costs and expenses incurred by the Contributor in connection with the Transactions shall be paid by the Contributor and all costs and expenses incurred by the Acquirer Parties in connection with the Transactions shall be paid by the Acquirer Parties; provided, however, that if any action at law or equity is necessary to enforce or interpret the terms of the Transaction Documents, the prevailing Party shall be entitled to reasonable attorneys' fees and expenses in addition to any other relief to which such Party may be entitled.

        5.3.Further Assurances.    Subject to the terms and conditions of this Agreement, each of the Parties shall use all commercially reasonable efforts to take, or cause to be taken, all action, and to do, or cause to be done, all things necessary, proper or advisable under applicable Law to consummate and effectuate the transactions contemplated by this Agreement.

        5.4.Public Statements.    The Parties shall consult with each other prior to issuing any public announcement, statement or other disclosure with respect to the Transactions and none of the Contributor and their respective Affiliates on one hand nor the Acquirer Parties and their respective Affiliates on the other shall issue any such public announcement, statement or other disclosure without having first notified the Contributor on one hand or the Acquirer Parties on the other; provided, however, that MWE and its Affiliates may make any public disclosure without first so consulting with or notifying the Contributor if MWE or any such Affiliate reasonably believes that it is required to do so by Law or by any stock exchange listing requirement or trading agreement concerning the publicly traded securities of MWE.

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        5.5.Confidentiality.    The Contributor acknowledges and agrees that the obligations set forth in Section 5.4 of the Company LLC Agreement shall continue in full effect following the Closing, but that the Contributor shall not have the right to enforce the provisions thereof except with respect to disclosure of any Confidential Information of the Contributor or its Affiliates.

        5.6.Agreements Relating to MWE Partnership Agreement.    The Contributor acknowledges and agrees that at the Closing the Contributor shall: (a) become a Limited Partner (as such term is defined in the MWE Partnership Agreement) and comply with and be bound by the MWE Partnership Agreement, including the restrictions on transfer applicable to the Contributor set forth in Sections 4.6(e) and 4.6(f) thereof and the voting restrictions applicable to the Contributor set forth in Section 5.7(d) thereof and in the definition of the defined term "Outstanding" in the MWE Partnership Agreement, and shall be deemed to have executed the MWE Partnership Agreement; (b) be deemed to have granted the powers of attorney provided for in the Partnership Agreement; and (c) be deemed to have made the waivers and given the consents and approvals contained in the MWE Partnership Agreement.

        5.7.    Tax Matters.

        (a)    Tax Responsibilities.    Except as otherwise provided in this Agreement, each Party shall bear all taxes imposed on it as a result of the transactions contemplated by this Agreement. Each Party shall timely file, to the extent required by or permissible under applicable Law, all tax returns and other documentation with respect to any such taxes.

        (b)    Tax Treatment.    The Parties intend to treat the transactions contemplated by Article II as an "assets-over" partnership merger within the meaning of Treasury Regulations Section 1.708-1(c)(3)(i), whereby (i) first, the Contributor is treated as selling a portion of the Contributed Interest to MWE in exchange for the Cash Sale Consideration in accordance with Treasury Regulations Section 1.708-1(c)(4) (and the Contributor hereby agrees to treat the transfer of such portion of the Contributed Interest to MWE as a sale for all tax purposes), (ii) second, the Company is treated as contributing to MWE pursuant to Section 721 of the Code an undivided interest in each of the Company's assets in exchange for the Unit Consideration and the Cash Distribution Consideration, with the Cash Distribution Consideration being treated as a reimbursement of a portion of the Company's preformation capital expenditures pursuant to Treasury Regulations Section 1.707-4(d), and (iii) third, the Company is treated as liquidating, distributing (A) the Cash Contribution Consideration and the Unit Consideration to the Contributor and (B) the remainder of the Company's underlying assets to MWE. The Parties agree to report consistent with this Section 5.7(b) on all relevant tax returns, except as otherwise required by a determination, as defined in Section 1313 of the Code.

        (c)    Agreement to Cooperate.    Except as provided herein, each Party shall use commercially reasonable efforts to cooperate fully with the other Parties, as and to the extent reasonably requested by any other Party, in connection with the filing of tax returns and any proceeding with respect to taxes. If upon audit of the Company's federal income tax return for the period ending December 31, 2011, the Internal Revenue Service proposes to treat the receipt of all or a portion of the Cash Distribution Consideration as proceeds from the sale of assets by the Company to MWE, any income or gain resulting from the proposed adjustment will be allocated for all tax purposes to the Contributor. Acquirer, as the tax matters partner of the Company, will contest any proposed adjustment with respect to the treatment of the receipt of the Cash Distribution Consideration at the direction of the Contributor; provided that the Contributor shall be liable for and shall pay all of the direct out-of-pocket costs incurred by the Acquirer Parties in contesting such claims. The parties covenant to make such adjustments to the Company's post contribution tax returns (and any related information returns of its members) as are necessary to reflect any adjustments to the treatment of the transactions as contemplated herein.

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        (d)    Tax and Accounting Effective Time.    The Parties agree that, for administrative convenience, the transactions contemplated by this Agreement will be deemed to be effective for all tax and accounting purposes as of 11:59 p.m. on December 31, 2011. The Parties intend that Contributor shall be treated as the tax owner of the Contributed Interest until such time, and that all items of Company income, gain, loss and deduction with respect to the Contributed Interest for the tax period ending December 31, 2011 shall be allocated to the Contributor.

        (e)    MWE Allocations.    The Parties acknowledge that MWE will apply the principles of Treasury Regulation Section 1.704-3(d) to address the difference between the fair market value and the adjusted tax basis of the portion of the Company assets deemed contributed to MWE.

        (f)    Allocation of Consideration.    Acquirer Parties shall, within 90 days following the Closing, prepare and deliver to Contributor for its review and approval a purchase price allocation among the Company's assets consistent with the principles of Sections 704(b) and 1060 of the Code and the Treasury Regulations promulgated thereunder (the "Allocation") and the Contributor shall have 10 days following delivery of the Allocation to object to the Allocation. If the Contributor objects to the Allocation and the Parties cannot come to a mutually agreeable resolution regarding such objection, the Parties shall select a mutually agreeable third-party public accounting firm to resolve such objection and any other disputes relating to the Allocation. Upon agreement of the Parties or determination of the third-party public accounting firm with respect to the Allocation, the Parties agree (A) to file all tax returns consistently with the Allocation, and (B) that neither Party or any of their respective Affiliates or direct or indirect owners shall take a position on any tax return, or before any Governmental Authority in connection with the examination of a tax return or in any judicial proceeding, that is in any manner inconsistent with the terms of the Allocation, except as required by a determination, as defined in Section 1313 of the Code. If, any taxing authority makes or proposes an allocation different from the Allocation, the Parties shall cooperate with each other in good faith to contest such taxing authority's allocation (or proposed allocation), provided, however, that, after consultation with the Party (or Parties) adversely affected by such allocation (or proposed allocation), the other Party (or Parties) hereto may file such protective claims or tax returns as may be reasonably required to protect its (or their) interests.

        (g)    Tax Returns.    Acquirer shall be responsible for filing the Company's tax returns for the year ended December 31, 2011, including an election for the Company under Section 754 of the Code, if applicable. Acquirer shall provide a copy of each such tax return at least sixty (60) days before the due date for such tax return along with a computation of the allocations of tax, if any, to Contributor in accordance with the Company LLC Agreement as in effect immediately before the closing of the transactions contemplated by this Agreement. Prior to the filing of such tax returns, Acquirer shall make any revisions or adjustments reasonably requested by Contributor. The Parties shall each provide the other with all information reasonably necessary to prepare such tax returns.

        (h)    Changes and Amendments to Tax Matters.    With respect to the Company's tax year ended December 31, 2011 or any prior tax year, without Contributor's prior written consent (not to be unreasonably withheld), Acquirer Partners and their Affiliates will not, on behalf of or with respect to the Company or its assets, and will not cause the Company to, (i) make any material tax elections (except elections consistent with past practices), (ii) amend any tax returns or settle or compromise any federal, state, local or foreign tax liability, or (iii) enter into any agreement or preliminary settlement concerning taxes or file any waiver extending the statutory period for assessment or reassessment of taxes or any other waiver of restrictions on assessment or collection of any taxes.

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        5.8.    Agreements and Waivers Relating to Contributed Interest.

        (a)   The Contributor acknowledges and agrees, for and on behalf of itself and its respective Affiliates, that:

          (i)  after the Closing, the Contributed Interest may increase in value and the Contributor and its Affiliates will not receive or realize any benefit from such increase in value or any increase in the value of the Company or its successors generally, other than indirectly through an increase in the value of the MWE Class B Units, including that, for the avoidance of doubt, the Contributor shall not be entitled to share in any distributions made by the Company after the Closing, including any distribution of Available Cash associated with the fourth quarter of 2011;

         (ii)  there are inherent uncertainties in valuing illiquid securities like the Contributed Interest such that a third-party valuation of the Contributed Interest could have resulted in a materially higher or lower valuation than that attributable to the Contribution Consideration received by the Contributor under this Agreement;

        (iii)  the Company may engage in transactions with MWE or its Affiliates, joint ventures with third parties, and other future transactions, any or all of which may result in an increase in the value of the Contributed Interest and the Acquirer Parties and their officers, directors, employees and Affiliates may possess material non-public information relating to the foregoing or other matters that is not known to the Contributor and may impact the value of the Contributed Interest; and

        (iv)  in light of the foregoing, the Contributor understands, based on its experience, the disadvantage to which the Contributor is subject due to the disparity of information between the Contributor and the Acquirer Parties and, notwithstanding this, the Contributor has deemed it appropriate to engage in the Transaction based on its own independent review and consultations with such investment, legal, tax, accounting and other advisers as it deemed necessary, without reliance on any representation or warranty of, or advice from, the Acquirer Parties, other than the representations and warranties of the Acquirer Parties in Article IV, which representations and warranties constitute the sole and exclusive representations and warranties of the Acquirer Parties in connection with the transactions contemplated by this Agreement.

        (b)   After the Closing, the Contributor hereby releases and discharges each Acquirer Party, its Affiliates, directors, officers, partners, members, equityholders and employees (former or present) and their respective successors, heirs and assigns, from any and all Claims and Losses, known or unknown, that have accrued or may accrue and that arise out of or relate to the matters described in this Section 5.8.

        (c)   The Acquirer Parties acknowledge and agree, for and on behalf of themselves and their respective Affiliates, that the Contributor shall not be responsible or liable for any capital contributions to the Company that were due and payable or will become due and payable, prior to, on, or after the date of this Agreement pursuant to Article IV of the Company LLC Agreement or otherwise.

        (d)   The Contributor hereby consents, on behalf of itself and on behalf of the Class A Managers designated by the Contributor, to **, and the Company and the Contributor acknowledge and agree that the Contributor shall have no rights or obligations in respect of **.

ARTICLE VI
SURVIVAL; RELATED MATTERS

        6.1.    Survival.

        (a)   The representations and warranties of the Contributor under this Agreement shall survive the execution and delivery of this Agreement and shall continue in full force and effect until **; provided

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that the representations and warranties of the Contributor in Sections 3.1, 3.2, 3.5, 3.6 and 3.7 shall survive until ** (the date on which a particular representation or warranty of the Contributor under this Agreement expires, the "Contributor Expiration Date").

        (b)   The representations and warranties of the Acquirer Parties under this Agreement shall survive the execution and delivery of this Agreement and shall continue in full force and effect ** (the "Acquirer Expiration Date"); provided that the representations and warranties of the Acquirer Parties in Sections 4.1, 4.2, 4.5, 4.6, 4.8 and 4.10 shall survive **.

        (c)   Each Party's covenants and agreements contained in this Agreement shall survive the execution and delivery of this Agreement and shall continue in full force and effect until fully discharged.

        (d)   No Claim for a breach of any Party's respective representations or warranties contained in this Agreement (other than representations or warranties of the Acquirer Parties that survive indefinitely pursuant to Section 6.1(b)) shall be brought after the applicable Contributor Expiration Date with respect to such a Claim against the Contributor, or the Acquirer Expiration Date, with respect to such a Claim against the Acquirer Parties. Notwithstanding the foregoing, if such a Claim is brought before the applicable Contributor Expiration Date, with respect to such a claim against the Contributor, or the Acquirer Expiration Date, with respect to such a Claim against the Acquirer Parties, then (notwithstanding the occurrence of such expiration date) the representation or warranty giving rise to such Claim will survive until the final resolution of such Claim and the satisfaction of any obligations relating thereto.

        6.2.    Calculation of Losses.    In calculating the amount of any Losses incurred, arising out of or relating to any Claim for any breach of any representation or warranty of a Party contained in this Agreement or any breach of any of the covenants or agreements of any Party contained in this Agreement, the amount of such Losses shall be determined without duplication of any other Loss for which a Claim has been made or could be made that arises out of or relates to the breach of any other representation, warranty, covenant, or agreement of any Party contained in this Agreement and shall be computed net of (a) payments actually recovered by the Party making such Claim under any insurance policy with respect to such Losses and (b) any prior or subsequent actual recovery by the Party making such Claim from any Person with respect to such Losses. To the extent that the Contributor is adjudged liable or agrees in writing to take responsibility for Losses resulting from a breach of any representation, warranty, covenant or agreement of the Contributor contained in this Agreement, the Contributor shall have the right to satisfy and discharge any Losses by **. If the Contributor is adjudged liable for Losses resulting from a breach of any representation, warranty, covenant or agreement of the Contributor contained in this Agreement **, but does not pay such amount, or cause an amount equal to such Losses to be paid, to the Party incurring such Losses within 20 days of the date of such final adjudication, then MWE or its successor shall **; provided, however, that, in the event MWE or its successor **. In no event shall the Contributor's aggregate liability for Losses hereunder exceed **. For the avoidance of doubt, **. For purposes of this Agreement, ** In all events, the **

        6.3.    Waiver of Certain Losses.    NOTWITHSTANDING ANY OTHER PROVISION OF THIS AGREEMENT, IN NO EVENT SHALL ANY PARTY BE LIABLE TO ANY OTHER PARTY OR ANY OF ITS DIRECTORS, MANAGERS, OFFICERS, EMPLOYEES, CONSULTANTS, AGENTS, GENERAL OR LIMITED PARTNERS, MEMBERS, STOCKHOLDERS OR AFFILIATES (COLLECTIVELY, "COVERED PERSONS") FOR EXEMPLARY, PUNITIVE, REMOTE, CONSEQUENTIAL, SPECIAL OR LOST PROFITS LOSSES OF ANY KIND OR NATURE, REGARDLESS OF THE FORM OF ACTION THROUGH WHICH SUCH LOSSES ARE SOUGHT, PROVIDED, HOWEVER, THIS SECTION 6.3 SHALL NOT LIMIT THE RIGHT OF A PARTY OR ANY OF ITS COVERED PERSONS TO RECOVER ANY LOSSES, INCLUDING

14

EXEMPLARY, PUNITIVE, REMOTE, CONSEQUENTIAL, INCIDENTAL OR SPECIAL DAMAGES, TO THE EXTENT SUCH LOSSES ARE A COMPONENT OF ANY CLAIM BY A THIRD PARTY AGAINST SUCH PARTY OR ANY OF ITS COVERED PERSONS IN RESPECT OF WHICH SUCH PARTY OR COVERED PERSON IS OTHERWISE FINALLY DETERMINED TO BE ENTITLED TO RECOVER FROM ANOTHER PARTY.

        6.4.    No Reliance.    THE REPRESENTATIONS AND WARRANTIES OF THE CONTRIBUTOR CONTAINED IN ARTICLE III CONSTITUTE THE SOLE AND EXCLUSIVE REPRESENTATIONS AND WARRANTIES OF THE CONTRIBUTOR TO THE ACQUIRER PARTIES IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. THE REPRESENTATIONS OF THE ACQUIRER PARTIES CONTAINED IN ARTICLE IV CONSTITUTE THE SOLE AND EXCLUSIVE REPRESENTATIONS AND WARRANTIES OF THE ACQUIRER PARTIES TO THE CONTRIBUTOR IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT. EXCEPT FOR SUCH REPRESENTATIONS AND WARRANTIES, NEITHER ANY PARTY OR ANY OTHER PERSON MAKES ANY OTHER EXPRESS OR IMPLIED REPRESENTATION OR WARRANTY WITH RESPECT TO SUCH PARTY OR THE TRANSACTIONS CONTEMPLATED BY THIS AGREEMENT, AND EACH PARTY DISCLAIMS ANY OTHER REPRESENTATIONS OR WARRANTIES, WHETHER MADE BY SUCH PARTY OR ANY OF ITS COVERED PERSONS. EXCEPT FOR SUCH REPRESENTATIONS AND WARRANTIES, EACH PARTY DISCLAIMS ALL LIABILITY AND RESPONSIBILITY FOR ANY REPRESENTATION, WARRANTY, PROJECTION, FORECAST, STATEMENT, OR INFORMATION MADE, COMMUNICATED, OR FURNISHED (ORALLY OR IN WRITING) TO ANY OTHER PARTY OR ITS COVERED PERSONS (INCLUDING OPINIONS, INFORMATION, PROJECTIONS, OR ADVICE THAT MAY HAVE BEEN OR MAY BE PROVIDED TO ANY PARTY OR ANY OFFICER, DIRECTOR, EMPLOYEE, AGENT OR REPRESENTATIVE OF SUCH PARTY OR ANY OF ITS AFFILIATES).

ARTICLE VII
GENERAL PROVISIONS

        7.1.    Notices.    Any notice, demand or communication required or permitted under this Agreement shall be in writing and delivered personally or by reputable overnight delivery service or other courier, and shall be deemed to have been duly given as of the date and time reflected on the delivery receipt, addressed as follows:

If to either Acquirer Party:

c/o MarkWest Energy Partners, L.P.
1515 Arapahoe Street
Tower 1, Suite 1600
Denver, Colorado 80202-2126
Attention: General Counsel

with a copy (which shall not constitute notice) to:

Vinson & Elkins LLP
1001 Fannin Street, Suite 2600
Houston, Texas 77002
Attention: Alan Beck

15

If to the Contributor:

M&R MWE Liberty, LLC
811 Main Street, Suite 4200
Houston, Texas 77002
Attention: John T. Raymond

with a copy (which shall not constitute notice) to:

Locke Lord LLP
600 Travis Street, Suite 3400
Houston, Texas 77002
Attention: H. William Swanstrom

A Party may change its address for the purpose of notices hereunder by giving notice to the other Party specifying such changed address in the manner specified in this Section 7.1.

        7.2.    Binding Effect.    This Agreement will be binding upon, and will inure to the benefit of, the Parties and their respective successors, permitted assigns and legal representatives.

        7.3.    Third Party Rights.    The provisions of this Agreement are intended to bind the Parties as to each other and are not intended to and do not create rights in any other Person or confer upon any other Person (other than the express beneficiaries of the waiver set forth in Section 6.5) any benefits, rights or remedies and no Person is or is intended to be a third party beneficiary of any of the provisions of this Agreement.

        7.4.    Waiver of Compliance.    Any failure of any of the Parties to comply with any obligation, covenant, agreement or condition in this Agreement may be waived by the Party or Parties entitled to the benefits thereof only by a written instrument signed by the Party or Parties granting such waiver, but such waiver or failure to insist upon strict compliance with such obligation, covenant, agreement or condition shall not operate as a waiver of, or estoppel with respect to, any subsequent or other failure.

        7.5.    Applicable 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, BUT NOT LIMITED TO, 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.

        7.6.    Waiver of Jury Trial.    THE PARTIES EACH HEREBY KNOWINGLY, VOLUNTARILY, INTENTIONALLY, AND IRREVOCABLY WAIVE, AND AGREE TO CAUSE THEIR AFFILIATES TO WAIVE, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY RIGHT TO TRIAL BY JURY OF ANY CLAIM, DEMAND, ACTION OR CAUSE OF ACTION (A) ARISING UNDER THIS AGREEMENT OR (B) IN ANY WAY CONNECTED WITH OR RELATED OR INCIDENTAL TO THE DEALINGS OF THE PARTIES IN RESPECT OF THIS AGREEMENT OR ANY OF THE TRANSACTIONS, IN EACH CASE WHETHER NOW EXISTING OR HEREAFTER ARISING, AND WHETHER IN CONTRACT, TORT, EQUITY OR OTHERWISE. THE PARTIES EACH HEREBY AGREES AND CONSENTS THAT ANY SUCH CLAIM, DEMAND, ACTION OR CAUSE OF ACTION SHALL BE DECIDED BY COURT TRIAL

16

WITHOUT A JURY AND THAT THE PARTIES MAY FILE AN ORIGINAL COUNTERPART OF A COPY OF THIS AGREEMENT WITH ANY COURT AS WRITTEN EVIDENCE OF THE CONSENT OF THE PARTIES TO THE WAIVER OF THEIR RIGHT TO TRIAL BY JURY.

        7.7.    Severability.    If any of the provisions of this Agreement are held by any court of competent jurisdiction to contravene, or to be invalid under, the laws of any political body having jurisdiction over the subject matter hereof, such contravention or invalidity shall not invalidate the entire Agreement. Instead, this Agreement shall be construed as if it did not contain the particular provision or provisions held to be invalid and an equitable adjustment shall be made and necessary provision added so as to give effect to the intention of the Parties as expressed in this Agreement at the time of execution of this Agreement.

        7.8.    Amendment or Modification.    This Agreement may be amended, modified or supplemented from time to time only by a written agreement executed by all the Parties.

        7.9.    Assignment.    No Party shall have the right to assign its rights or obligations under this Agreement without the prior written consent of the other Parties.

        7.10.    Waiver of Transfer Restrictions in Company LLC Agreement.    The Parties hereby waive the transfer restrictions and requirements set forth in Article 7 of the Company LLC Agreement such that no prior written consent of MWE is required to consummate the Transactions and no legal opinion of counsel pursuant to Section 7.5 of the Company LLC Agreement will be required to consummate the Transactions.

        7.11.    Counterparts.    This Agreement may be executed in any number of counterparts with the same effect as if all Parties had signed the same document. All counterparts shall be construed together and shall constitute one and the same instrument. Execution and delivery of this Agreement by exchange of facsimile or other electronically transmitted counterparts bearing the signature of a Party shall be equally as effective as delivery of a manually executed counterpart by such Party.

        7.12.    No Recourse Against Non-Parties.    For the avoidance of doubt, the provisions of this Agreement shall not give rise to any right of recourse against any former, current or future director, officer, employee, agent, general or limited partner, manager, member, or stockholder of any Party.

        7.13.    Representation by Counsel.    Each of the Parties agrees that it has been represented by independent counsel of its choice during the negotiation and execution of this Agreement and the instruments referenced in this Agreement, and that it has executed the same upon the advice of such independent counsel. Each Party and its counsel cooperated in the drafting and preparation of this Agreement and the instruments referenced in this Agreement, and any and all drafts relating thereto shall be deemed the work product of the Parties and may not be construed against any Party by reason of its preparation. Therefore, the Parties waive the application of any Law providing that ambiguities in an agreement or other instrument will be construed against the Party drafting such agreement or other instrument.

        7.14.    Entire Agreement; Supersedure.    This Agreement and the instruments referenced in this Agreement, together with any other written agreements executed by the Parties in connection with the transactions contemplated by this Agreement, supersede all previous understandings or agreements among the Parties, whether oral or written, with respect to their subject matter and contain the entire understanding of the Parties with respect to the subject matter hereof and thereof. No understanding, representation, promise or agreement, whether oral or written, is intended to be or shall be included in or form part of this Agreement unless it is contained in a written amendment hereto executed by the Parties after the date of this Agreement.

17

        IN WITNESS WHEREOF, each of the Parties has caused this Agreement to be executed by its respective duly authorized officer 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 ENERGY PARTNERS, L.P.,
By:	MarkWest Energy GP, L.L.C., its general partner
By:	/s/ Frank M. Semple
Name:	Frank M. Semple
Title:	President and CEO

SIGNATURE PAGE TO
CONTRIBUTION AGREEMENT

M&R MWE LIBERTY, LLC
By:	/s/ John T. Raymond
Name:	John T. Raymond
Title:	CEO & Managing Partner

SIGNATURE PAGE TO
CONTRIBUTION AGREEMENT

EXHIBIT A

        "Acquirer" is defined in the preamble to this Agreement.

        "Acquirer Party" and "Acquirer Parties" is defined in the preamble to this Agreement.

        "Affiliate" means with respect to any Person, any Person that, directly or indirectly, controls, is controlled by, or is under a common control with, such Person. The term "control" (including the terms "controlled by" and "under common control with") as used in this definition means the possession, directly or indirectly, of the power to direct or cause the direction of management and policies of a Person, whether through the ownership of voting securities, by contract, or otherwise. With respect to any natural person, the term "Affiliate" shall also mean (a) the spouse or children (including those by adoption) and siblings of such Person; and any trust whose primary beneficiary is such Person, such Person's spouse, such Person's siblings and/or one or more of such Person's lineal descendants, (b) the legal representative or guardian of such Person or of any such immediate family member in the event such Person or any such immediate family member becomes mentally incompetent and (c) any Person controlled by or under the common control with any one or more of such Person and the Persons described in clauses (a) or (b) of this definition.

        "Agreement" is defined in the preamble to this Agreement.

        "Acquirer Expiration Date" is defined in Section 6.1(b).

        "Allocation" is defined in Section 5.7(f).

        "Assignment of Interests" is defined in Section 2.4(a)(v).

        "Available Cash" has the meaning ascribed to such term in the Company LLC Agreement.

        "Cash Consideration" is defined in Section 2.2(a).

        "Cash Distribution Consideration" is the amount of the Cash Consideration that the Parties determine may be treated, in connection with the deemed contribution in accordance with Section 5.7(b)(ii), as a reimbursement of the Company's pre-formation capital expenditures pursuant to Treasury Regulation Section 1.707-4(d) in a manner that would allow for the satisfaction of Section 6662(d)(2)(B)(i) of the Internal Revenue Code..

        "Cash Sale Consideration" is the amount of the Cash Consideration in excess of the Cash Distribution Consideration.

        "Claim" means any and all claims, causes of action, demands, lawsuits, suits, information requests, proceedings, governmental investigations or audits and administrative orders.

        "Class A Interest" has the meaning ascribed to such term in the Company LLC Agreement.

        "Class B-1 Unit" has the meaning ascribed to such term in the MWE Partnership Agreement.

        "Class B-2 Unit" has the meaning ascribed to such term in the MWE Partnership Agreement.

        "Class B-3 Unit" has the meaning ascribed to such term in the MWE Partnership Agreement.

        "Class B-4 Unit" has the meaning ascribed to such term in the MWE Partnership Agreement.

        "Class B-5 Unit" has the meaning ascribed to such term in the MWE Partnership Agreement.

        "Closing" is defined in Section 2.3.

        "Code" means the Internal Revenue Code of 1986, as amended.

        "Company" is defined in the recitals to this Agreement.

        "Company LLC Agreement" is defined in the recitals to this Agreement.

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        "Confidential Information" is defined in Section 1.1 of the Company LLC Agreement.

        "Contract" means any contract, agreement, lease, license, note, evidence of indebtedness, mortgage, security agreement, understanding, instrument or other legally binding arrangement, whether oral or written.

        "Contribution Consideration" is defined in Section 2.2.

        "Contributed Interest" is defined in the recitals to this Agreement.

        "Contributor" is defined in the preamble to this Agreement.

        "Contributor Credit Agreement" means that certain Credit Agreement, dated as of April 28, 2011, by and among the Contributor, Citibank N.A., National Banking Association as administrative agent and certain lenders thereto, as amended by that First Amendment to the Credit Agreement dated as of August 11, 2011.

        "Contributor Expiration Date" is defined in Section 6.1(a).

        "Converted Common Unit" has the meaning ascribed to such term in the MWE Partnership Agreement.

        "Covered Persons" is defined in Section 6.3.

        "Creditors' Rights" is defined in Section 3.2(b).

        "Delaware LP Act" means the Delaware Revised Uniform Limited Partnership Act, as amended from time to time.

        "Equivalent Securities" has the meaning ascribed to such term in the MWE Partnership Agreement.

        "Exchange Act" means the Securities Exchange Act of 1934, as amended, and the rules and regulations promulgated thereunder.

        "GAAP" means generally accepted accounting principles in the United States of America.

        "Governmental Authority" means any executive, legislative, judicial, regulatory or administrative agency, body, commission, department, board, court, tribunal, arbitrating body or authority of the United States or any foreign country, or any state, local or other governmental subdivision thereof.

        "Law" means any law, statute, code, ordinance, order, rule, rule of common law, regulation, judgment, decree, injunction, franchise, permit, certificate, license or authorization of any Governmental Authority.

        "Lien" means, with respect to any property or asset, any lien, pledge, condemnation award, claim, restriction, charge, preferential purchase right, security interest, mortgage or encumbrance of any nature whatsoever.

**

        "Losses" means all debts, liabilities, obligations, losses, damages, interest (including prejudgment interest), penalties, fines, reasonable legal fees, disbursements and costs of investigations, deficiencies, levies, duties and imposts.

        "MWE" is defined in the preamble to this Agreement.

        "MWE Class A Units" means Class A Units representing limited partner interests in MWE, having the terms set forth therefore in the MWE Partnership Agreement.

        "MWE Class B Units" means Class B Units representing limited partner interests in MWE, having the terms set forth therefore in the MWE Partnership Agreement.

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        "MWE Common Units" means Common Units representing limited partner interests in MWE, having the terms set forth therefore in the MWE Partnership Agreement.

        "MWE Class B Unit Value" is defined in Section 6.2.

        "MWE Credit Agreements" means any and all credit agreements to which either of the Acquirer Parties is a party including that certain Amended and Restated Credit Agreement dated July 1, 2010 by and among MWE, Wells Fargo Bank, National Association as administrative agent and collateral agent, and certain lenders thereto, as amended by that First Amendment to the Amended and Restated Credit Agreement dated September 7, 2011, and as further amended or restated from time to time.

        "MWE GP" is defined in Section 4.5(f).

        "MWE GP Interest" is defined in Section 4.5(f).

        "MWE Indentures" means any and all indentures to which either of the Acquirer Parties is a party including the indentures, as supplemented, governing the MWE 8.75% Senior Notes Due 2018, MWE 6.75% Senior Notes Due 2020, MWE 6.5% Senior Notes Due 2021 and MWE 6.25% Senior Notes Due 2022 and any additional series of senior notes of MWE which are outstanding as of the Closing.

        "MWE Material Adverse Effect" means any effect, event, development or change which, individually or in the aggregate with all effects, events, developments or changes, is or is reasonably likely to become materially adverse to the business, assets, liabilities, properties, operations or financial condition of MWE, taken as a whole; provided, however, that, an MWE Material Adverse Effect shall not be deemed to have occurred as a result of any of the following changes, events or developments (either alone or in combination): (a) any change in general economic, political or business conditions (including any effects on the economy arising as a result of acts of terrorism) that affect MWE, except any such changes that affect MWE in a disproportionate manner compared to similarly situated participants in the industries in which MWE operates; (b) any change in oil or natural gas commodity prices; (c) any change affecting the natural gas transportation or gathering industries, except any such changes that affect MWE in a disproportionate manner compared to similarly situated participants in such industries; (d) any change in accounting requirements or principles imposed by GAAP or any change in Law after the date of this Agreement, except any such changes that affect MWE in a disproportionate manner compared to similarly situated participants in the industries in which MWE operates; or (e) any change resulting from the execution of this Agreement or the announcement of the transactions contemplated hereby or from MWE's ownership of the Contributed Interest from and after the Closing; or (f) any change resulting from compliance by the Acquirer Parties with the terms of the Transaction Documents or from any action by the Acquirer Parties expressly permitted by this Agreement.

        "MWE Partnership Agreement" means the Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated effective as of February 21, 2008, as amended by Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated as of even date herewith, as further amended, supplemented and restated from time to time.

        "MWE Partnership Agreement Amendment" is defined in Section 2.4(a)(iii).

        "MWE SEC Filing" is defined in Section 4.7.

        "National Securities Exchange" means an exchange registered with the SEC under Section 6(a) of the Exchange Act, or the NASDAQ Stock Market or any successor thereto.

        "Organizational Documents" means, with respect to any Person, the articles of incorporation, certificate of incorporation, certificate of formation, certificate of limited partnership, bylaws, limited liability company agreement, operating agreement, partnership agreement, stockholders' agreement and

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all other similar documents, instruments or certificates executed, adopted or filed in connection with the creation, formation or organization of such Person, including any amendments thereto (including, in the case of the Company, the Company LLC Agreement and, in the case of MWE, the MWE Partnership Agreement).

        "Party" and "Parties" are defined in the preamble of this 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 Governmental Authority.

        "Registration Rights Agreement" is defined in Section 2.4(a)(iv).

        "SEC" means the United States Securities and Exchange Commission.

        "Securities Act" means the Securities Act of 1933, as amended, and the rules and regulations promulgated thereunder.

        "Trading Day" means, with respect to MWE Common Units or any other security, a day on which the principal National Securities Exchange on which such securities are then listed or admitted to trading is open for the transaction of business.

        "Transactions" means the Transactions contemplated by the Transaction Documents.

        "Transaction Documents" means this Agreement, the MWE Partnership Agreement Amendment, the Assignment of Interests and the Registration Rights Agreement.

        "Treasury Regulations" means the regulations (including temporary regulations) promulgated by the United States Department of the Treasury pursuant to and in respect of provisions of the Code. All references herein to sections of the Treasury Regulations shall include any corresponding provision or provisions of succeeding, similar or substitute, temporary or final Treasury Regulations.

        "Unit Consideration" means 19,954,389 MWE Class B Units.

**

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Exhibit 10.34

TABLE OF CONTENTS
CONTRIBUTION AGREEMENT
R E C I T A L S
A G R E E M E N T S
ARTICLE I DEFINITIONS AND INTERPRETATIONS
ARTICLE II CONTRIBUTION OF THE CONTRIBUTED INTEREST; CLOSING
ARTICLE III REPRESENTATIONS AND WARRANTIES OF THE CONTRIBUTOR
ARTICLE IV REPRESENTATIONS AND WARRANTIES OF THE ACQUIRER PARTIES
ARTICLE V COVENANTS OF THE PARTIES
ARTICLE VI SURVIVAL; RELATED MATTERS
ARTICLE VII GENERAL PROVISIONS
EXHIBIT A

EX-10.35

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Exhibit 10.35

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 (**).

Execution Version

LIMITED LIABILITY COMPANY AGREEMENT

of

MARKWEST UTICA EMG, L.L.C.

Dated December 29, 2011
to be effective as of January 1, 2012

TABLE OF CONTENTS

		Page
ARTICLE 1 DEFINED TERMS			1
Section 1.1	Definitions		1
ARTICLE 2 FORMATION AND TERM			11
Section 2.1	Formation		11
Section 2.2	Name		11
Section 2.3	Term		12
Section 2.4	Registered Agent and Office		12
Section 2.5	Principal Place of Business		12
Section 2.6	Qualification in Other Jurisdictions		12
ARTICLE 3 PURPOSE AND POWERS OF THE COMPANY			12
Section 3.1	Purpose		12
Section 3.2	Powers of the Company		13
Section 3.3	Projects, Restricted Projects, Exempted Projects and Out of Scope Projects		13
ARTICLE 4 CAPITAL CONTRIBUTIONS, MEMBER INTERESTS, CAPITAL ACCOUNTS AND FUTURE CAPITAL REQUIREMENTS			14
Section 4.1	Capital Contributions		14
Section 4.2	Capital Contribution Defaults		17
Section 4.3	Member's Interest		17
Section 4.4	Status of Capital Contributions		17
Section 4.5	Capital Accounts		18
Section 4.6	Capital Accounts Generally		18
Section 4.7	Investment Accounts		18
ARTICLE 5 MEMBERS, MEETINGS AND AMENDMENTS			19
Section 5.1	Powers of Members		19
Section 5.2	No Resignation or Expulsion		19
Section 5.3	Additional Members		19
Section 5.4	Confidentiality Obligations of Members		20
Section 5.5	Initial Budget		21
Section 5.6	Preemptive Rights		21
Section 5.7	Registration Rights		22
ARTICLE 6 MANAGEMENT			22
Section 6.1	Management Under Direction of the Board		22
Section 6.2	Number, Tenure and Qualifications		22
Section 6.3	Votes Per Manager; Quorum; Required Vote for Board Action; Meetings of the Board		23
Section 6.4	Power to Bind Company		24
Section 6.5	Liability for Certain Acts		24
Section 6.6	Manager Has No Exclusive Duty to Company		25
Section 6.7	Resignation and Withdrawal		25
Section 6.8	Removal		25
Section 6.9	Vacancies		25
Section 6.10	Delegation of Authority; Officers		26
Section 6.11	Designation of Operator		26
Section 6.12	Approval of Members		27
Section 6.13	**		30

i

		Page
Section 6.14	Reliance by Third Parties		30
Section 6.15	Fees and Expenses of the Managers		30
Section 6.16	Budgets		30
ARTICLE 7 ASSIGNABILITY OF MEMBER INTERESTS			31
Section 7.1	Prohibition on Assignment During Project Period		31
Section 7.2	Transfers After the Project Period		32
Section 7.3	Recognition of Assignment by Company or Other Members		35
Section 7.4	Effective Date of Assignment		35
Section 7.5	Limitations on Transfer		36
Section 7.6	Transferee Not a Substitute Member		36
ARTICLE 8 DISTRIBUTIONS TO MEMBERS			36
Section 8.1	Available Cash		36
Section 8.2	Withholding		36
Section 8.3	Limitations on Distribution		37
Section 8.4	Tax Distributions		37
ARTICLE 9 ALLOCATIONS			37
Section 9.1	Profits and Losses		37
Section 9.2	Special Allocations		37
Section 9.3	Curative Allocations		38
Section 9.4	Income Tax Allocations		39
Section 9.5	Allocation and Other Rules		39
ARTICLE 10 BOOKS AND RECORDS			40
Section 10.1	Inspection Rights Pursuant to Law		40
Section 10.2	Books and Records		40
Section 10.3	Financial Statements and Reports		40
Section 10.4	Accounting Method		41
Section 10.5	Bank Accounts; Investments		41
ARTICLE 11 TAX MATTERS			41
Section 11.1	Taxation of Company		41
Section 11.2	Tax Returns		41
Section 11.3	Member Tax Return Information		41
Section 11.4	Tax Matters Representative		42
Section 11.5	Right to Make Section 754 Election		42
Section 11.6	Tax Elections		42
Section 11.7	Tax Reimbursement		42
ARTICLE 12 LIABILITY, EXCULPATION AND INDEMNIFICATION			43
Section 12.1	Liability		43
Section 12.2	Exculpation		43
Section 12.3	Indemnification		43
Section 12.4	Expenses		43
Section 12.5	Insurance		44
Section 12.6	Certain Liabilities		44
Section 12.7	Acts Performed Outside the Scope of the Company		44
Section 12.8	Liability of Members to Company or Other Members		44
Section 12.9	Attorneys' Fees		44
Section 12.10	Subordination of Other Rights to Indemnity		44
Section 12.11	Survival of Indemnity Provisions		44

ii

		Page
ARTICLE 13 DISSOLUTION, LIQUIDATION AND TERMINATION			45
Section 13.1	No Dissolution		45
Section 13.2	Events Causing Dissolution		45
Section 13.3	Notice of Dissolution		45
Section 13.4	Liquidation		45
Section 13.5	Termination		46
Section 13.6	Claims of the Members or Third Parties		46
Section 13.7	Distributions In-Kind		46
ARTICLE 14 REPRESENTATIONS, WARRANTIES AND COVENANTS			47
Section 14.1	Representations, Warranties and Covenants		47
ARTICLE 15 MISCELLANEOUS			48
Section 15.1	Notices		48
Section 15.2	Failure to Pursue Remedies		48
Section 15.3	Cumulative Remedies		48
Section 15.4	Binding Effect		48
Section 15.5	Interpretation		49
Section 15.6	Severability		49
Section 15.7	Counterparts		49
Section 15.8	Integration		49
Section 15.9	Amendment or Restatement		49
Section 15.10	Governing Law		49
Section 15.11	Dealings in Good Faith		49
Section 15.12	Partition of the Property		50
Section 15.13	Third Party Beneficiaries		50
Section 15.14	Tax Disclosure Authorization		50
Section 15.15	Waivers and Consents		50
EXHIBITS:
Exhibit A	Area of Mutual Interest
Exhibit B	Members and Capital Contributions
Exhibit C	Base Project
Exhibit D	Initial Budget
Exhibit E	Pre-Approved Affiliated Transactions
Exhibit F	**

iii

LIMITED LIABILITY COMPANY AGREEMENT

OF

MARKWEST UTICA EMG, L.L.C.

        THIS LIMITED LIABILITY COMPANY AGREEMENT ("Agreement") of MarkWest Utica EMG, L.L.C., a Delaware limited liability company (the "Company"), is entered into as of December 29, 2011, to be effective as of January 1, 2012, by and among MarkWest Utica Operating Company, L.L.C., a Delaware limited liability company ("MWE Operating Company"), EMG Utica, LLC, a Delaware limited liability company ("EMG"), and such other Persons who may become Members of the Company from time to time pursuant hereto.

        WHEREAS, in order to initially capitalize the Company, on or before January 1, 2012, the Members shall make the Initial Capital Contributions and from time to time thereafter, certain of the Members shall make additional Capital Contributions in accordance with Article 4;

        WHEREAS, contemporaneously with the execution of this Agreement and in order to provide for the provision of certain services to the Company, the Company, MWE Operating Company and MarkWest Hydrocarbon, Inc., a Delaware corporation ("MWE Hydrocarbon") shall enter into a Services Agreement (the "Services Agreement"), pursuant to which MWE Hydrocarbon shall provide certain services, or cause such services to be provided, to the Company; and

        WHEREAS, the Company and the Members desire to enter into this Agreement to reflect the agreement of the Company and the Members as set forth herein;

        NOW THEREFORE, in consideration of the foregoing and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto agree 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 6.16(d).

        "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 Class A Contributions" shall have the meaning set forth in Section 4.1(b)(i).

        "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 Operating Company Group, (b) the EMG 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 Operating Company Group or the EMG Group.

        "Agreement" means this 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 6.16(b).

        "Arbitration Panel" shall have the meaning set forth in Section 6.16(d).

        "Area of Mutual Interest" means the area within ** the State of Ohio listed on Exhibit A.

        "Assumed Tax Liability" shall have the meaning set forth in Section 8.4(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 6.16(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.

        "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.

        "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 December 22, 2011, 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

2

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(a)(i).

        "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(a)(ii).

        "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).

        "Company Nonrecourse Liability" shall have the meaning assigned to the term "nonrecourse liability" in Treasury Regulations Section 1.704-2(b)(3)

"Company Sale" means (i) any disposition to any Person of all or substantially all of the Property of the Company, (ii) a Transfer to any Person of all of the outstanding Interests of the Company or (iii) a merger, combination or consolidation of the Company with or into any Person.

        "Company Sale Notice" shall have the meaning set forth in Section 7.2(b)(iii).

        "Company Sale Offer" shall have the meaning set forth in Section 7.2(b)(ii).

        "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 currently or in the future be

3

subject to confidentiality agreements between the Company and third parties. 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.

        "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 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

4

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.

        "Economic Risk of Loss" shall have the meaning assigned to that term in Treasury Regulation Section 1.752-2(a).

        "Election Period" shall have the meaning set forth in Section 5.6(b).

        "Electing Member" shall have the meaning set forth in Section 5.6(b).

        "Eligible Member" shall have the meaning set forth in Section 5.6(a).

        "EMG" shall have the meaning set forth in the preamble.

        "EMG Group" means EMG and each transferee of Interests directly or indirectly (in chain of title) from EMG that is an Affiliate of EMG; provided, however, that once a Person is designated as a member of the EMG Group such Person shall, as long as it owns any Interests, at all times be a member of the EMG 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.

        "EMG Portfolio Companies" shall have the meaning set forth in Section 3.3(d).

        "EMG Representatives" shall mean the members, managers and employees of EMG or any Affiliate thereof, together with all other persons serving as representatives of EMG, including those Persons who are serving as Managers at the request of EMG pursuant to this Agreement.

        "Enforcement Activities" shall have the meaning set forth in Section 6.3(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).

        "First Equalization Date" shall mean the first date on which the quotient (expressed as a percentage) obtained by dividing the aggregate Investment Balances of all members of the MWE Operating Company Group by the aggregate Investment Balances of all members of the MWE Operating Company Group plus all members of the EMG Group is equal to or greater than 60%.

        "First Notice" shall have the meaning set forth in Section 5.6(b).

        "Fiscal Year" means (i) the period commencing January 1, 2012 and ending on December 31, 2012 and (ii) any subsequent 12 month period commencing on January 1 and ending on December 31.

        "G&A Services" has the meaning ascribed to such term in the Services Agreement.

        "GAAP" means generally accepted accounting principles in the United States.

        "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;

        (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

5

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.

**

        "Indemnitee" shall have the meaning set forth in Section 12.7.

        "Indemnitor" shall have the meaning set forth in Section 12.7.

        "Indentures" means (a) that certain Indenture, dated as of November 2, 2010 (as amended and supplemented by the first supplemental indenture, the third supplemental indenture, and the fourth supplemental indenture, thereto), by and among MWE, MarkWest Energy Finance Corporation, a Delaware corporation, the Subsidiary Guarantors (as defined therein), and Wells Fargo Bank, National Association, a national banking association, as trustee, (b) that certain Indenture, dated as of November 2, 2010 (as amended and supplemented by the second supplemental indenture, the third supplemental indenture, and the fourth supplemental indenture, thereto), by and among MWE, MarkWest Energy Finance Corporation, a Delaware corporation, the Subsidiary Guarantors (as defined therein), and Wells Fargo Bank, National Association, a national banking association, as trustee, and (c) that certain Indenture, dated as of November 2, 2010 (as amended and supplemented by the fifth supplemental indenture, thereto), by and among MWE, MarkWest Energy Finance Corporation, a Delaware corporation, the Subsidiary Guarantors (as defined therein), and Wells Fargo Bank, National Association, a national banking association, as trustee, and in each case as further amended and supplemented.

        "Initial Budget" shall have the meaning set forth in Section 5.5.

        "Initial Capital Contribution" shall have the meaning set forth in Section 4.1(a).

        "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 4.7

        "Investment Balance" shall have the meaning set forth in Section 4.7

6

        "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).

        "Liquidation Amounts" shall have the meaning set forth in Section 13.4(b).

        "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 Class A Investment" shall have the meaning set forth in Section 4.1(b)(ii).

        "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.

        "MWE Liberty" means MarkWest Liberty Midstream & Resources, L.L.C., a Delaware limited liability company.

        "MWE Operating Company" shall have the meaning set forth in the preamble.

        "MWE Operating Company Group" means MWE Operating Company and each transferee of Interests directly or indirectly (in the chain of title) from MWE Operating Company that is an Affiliate of MWE Operating Company; provided, however, that once a Person is designated as a member of the MWE Operating Company Group such Person shall, as long as it owns any Interests, at all times be a member of the MWE Operating Company 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 5.6(a).

        "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.

7

        "Out of Scope Project" means (a) any project, activity, or business venture outside the Area of Mutual Interest, (b) any project, activity, or business venture not within the scope of the Primary Business of the Company (whether inside or outside the Area of Mutual Interest), (c) any project, activity, or business venture involving assets that are wholly or partially inside the Area of Mutual Interest if the primary purpose of such project, activity or business venture does not relate to natural gas or natural gas liquids gathered from within the Area of Mutual Interest, or (d) MWE Liberty's interests in the Base Project and any expansions thereof that are paid for by MWE Liberty.

        "Over-Allotment Amount" shall have the meaning set forth in Section 5.6(b).

**

        "Percentage Interest" means:

        (a)   at any time prior to the earlier to occur of the First Equalization Date and the Trigger Date:

          (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 on or after the earlier to occur of the First Equalization Date and the Trigger Date, 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.

        "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 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

8

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 6.16(a).

        "Proposed Purchaser" shall have the meaning set forth in Section 5.6(a).

        "Prudent Industry Practices" means, at a particular time, any of the practices, methods and acts which, in the exercise of reasonable judgment based upon the circumstances existing, and the information available, at such time, is reasonably expected to result in the proper operation and maintenance of the Company assets and shall include, without limitation, the practices, methods and acts engaged in or approved by a significant portion of, or otherwise commonly used in, the industry 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 optimum practices, methods or acts, to the exclusion of all others, but rather is a spectrum of possible practices, methods and acts which could have been expected to accomplish the desired result at a commercially reasonable cost and consistent with reliability, safety, timeliness and all applicable laws as well as with the Approved Budget. Prudent Industry Practices are intended to entail the same standards as a Person would, in the commercially reasonable prudent management of its own properties, use from time to time.

        "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 $50,000,000.00.

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        "Qualifying Third Party Offer" shall have the meaning set forth in Section 7.2(a)(ii).

        "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 an aggregate Percentage Interest equal to or exceeding **.

        "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 6.16(d).

        "Sale Proposal" shall have the meaning set forth in Section 7.2(b)(i).

        "Second Equalization Date" shall mean the first date on which the quotient (expressed as a percentage) obtained by dividing the aggregate Investment Balances of all members of the MWE Operating Company Group by the aggregate Investment Balances of all members of the MWE Operating Company Group plus all members of the EMG Group is equal to or greater than 70%.

        "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, 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.

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        "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 Distributions" means distributions made to Members pursuant to Section 8.4.

        "Tax Distribution Date" shall have the meaning set forth in Section 8.4(a).

        "Tax Matters Member" shall have the meaning set forth in Section 11.4(a).

        "Third Party Offer" shall have the meaning set forth in Section 7.2(a)(ii).

        "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).

        "Trigger Date" shall mean December 31, 2016.

        "Unrelated Information" shall have the meaning set forth in Section 10.2.

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 shall be contributed to the capital of the Company through the January 1, 2012 effective date 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 Utica EMG, 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.

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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 1, Suite 1600, 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.

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.

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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 the natural gas liquids processing, 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, 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 Operating Company 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 (solely due to the lack of approval by the Class A Managers and/or Class A Members, as applicable), and the Company therefore is unable to pursue the Restricted Project; and

         (ii)  A Class B Member or its Affiliates may ** as part of ** Restricted Projects; provided, that ** such Class B Member ** the Company ** the Class B Member. In connection with ** the Company and the other Members **. Members holding Interests with an aggregate Percentage Interest ** shall have the ** this Section 3.3(b)(ii) (which, for clarity purposes, shall not **). Such Members may, by written notice to the Company ** Class B Member ** the Class B Member ** 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 ** of 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)   Notwithstanding anything to the contrary in this Agreement, in the event that Class B Member(s) (either directly or indirectly through one or more Affiliates) elects to pursue for its own account any Exempted Project pursuant to Section 3.3(b), or any Member(s) elects to pursue an Out of Scope Project, then, to the extent reasonably requested by such Member(s), the Company and the other Members hereby agree to reasonably amend this Agreement or to enter into other reasonable and customary commercial and other agreements such that such Member(s) or their respective Affiliates shall be entitled to receive the benefits attributable to such Exempted Project or Out of Scope Project or to otherwise pursue the Exempted Project or Out of Scope Project.

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        (d)   The Company and the Members recognize that: (i) EMG and its Affiliates own and will own substantial equity interests in other companies (existing and future) that participate in the energy industry ("EMG Portfolio Companies") and have in the past and will in the future enter into advisory service agreements with such EMG Portfolio Companies; (ii) the EMG Representatives who serve as Managers also serve as principals of other EMG Portfolio Companies; and (iii) at any time, other EMG 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 EMG, its Affiliates and EMG 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 EMG Portfolio Companies, entering into agreements to provide services to such EMG Portfolio Companies or acting as directors or advisors to, or other principals of, such EMG 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 EMG and its Affiliates' ownership in the EMG Portfolio Companies, and (C) the Company and the Members hereby renounce any interest or expectancy in any such business opportunity pursued by EMG, its Affiliates, the EMG Representatives or another EMG 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(d) is intended to limit the confidentiality obligations in Section 5.4 and EMG, its Affiliates, the EMG Portfolio Companies and the EMG Representatives are expressly prohibited from using any Confidential Information (i) to pursue any such business opportunity, (ii) in providing services to the EMG Portfolio Companies or (iii) in acting as directors or advisors to, or other principals of, such companies.

        (e)   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)    Initial Capital Contributions.    On or prior to January 1, 2012, MWE Operating Company and EMG shall have made the respective Capital Contributions (each, an "Initial Capital Contribution") to the Company in the amounts set forth on Exhibit B in exchange for the initial Percentage Interest and the type of Interest set forth on Exhibit B.

        (b)    Additional Capital Contributions Prior to the First Equalization Date.    

          (i)  The Class A Members hereby collectively agree to make from time to time additional cash Capital Contributions to the Company, on an as needed basis and as consistent with the applicable Approved Budget, until such time as the Class A Members have an aggregate Investment Balance of $350,000,000.00 (such Capital Contributions, the "Additional Class A Contributions"). Such Capital Contributions shall be made upon receipt by each Class A Member of a Capital Call properly made by the Board to such Class A Members for such amount. The

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Class A Members shall contribute to the Company the amount of capital so requested in accordance with their respective Class A Percentage Interests, within fifteen Business Days after receipt of such Capital Call.

         (ii)  Following the funding of the Additional Class A Contributions, the Class A Members hereby collectively agree to make from time to time additional cash Capital Contributions to the Company, on an as needed basis and as consistent with the applicable Approved Budget (to the extent such cash Capital Contributions are not funded by the Class B Members pursuant to Section 4.1(b)(iii)), until such time as the Class A Members have an aggregate Investment Balance of at least $500,000,000.00 (such Investment Balance, the "Minimum Class A Investment"). Such Capital Contributions shall be made upon receipt by each Class A Member of a Capital Call properly made by the Board to such Class A Members for such amount. The Class A Members shall contribute to the Company the amount of capital so requested in accordance with their respective Class A Percentage Interests, within fifteen Business Days after receipt of such Capital Call. Upon the first to occur of (1) the contribution of the Class A Member's Initial Capital Contribution, each of the Additional Class A Contributions, and the cash Capital Contributions required pursuant to this Section 4.1(b)(ii), or (2) the occurrence of the Trigger Date (provided that the Class A Members have not defaulted on any obligation to contribute additional capital to the Company prior to the Trigger Date pursuant to a valid request made pursuant to Section 4.1(b)(i) or 4.1(b)(ii) which such obligation was due prior to and remains uncured as of the Trigger Date), the Class A Members shall thereafter have no obligation to contribute any additional capital to the Company.

        (iii)  Following the funding of the Additional Class A Contributions by the Class A Members pursuant to Section 4.1(b)(i), the Class B Members may elect to fund 60% of all additional cash Capital Contributions required by the Company and consistent with the applicable Approved Budget until such time as the Class A Members' Investment Balance equals the Minimum Class A Investment. Such election (1) will be a one-time election to fund 60% of all Capital Calls after the Additional Class A Contributions have been funded and until the Class A Members have made Capital Contributions equal to the Minimum Class A Investment and (2) will be made by the Class B Members in connection with the first Capital Call properly made by the Board pursuant to Section 4.1(b)(ii) that includes notice to the Class B Members that the Additional Class A Investments have been fully funded by the Class A Members. If the Class B Members make such election, then such Capital Contributions shall be made upon receipt by each Class B Member of a Capital Call properly made by the Board and the Class B Members shall contribute to the Company the amount of capital so requested as set forth in this Section 4.1(b)(iii) and in accordance with their respective Class B Percentage Interests, within fifteen Business Days after receipt of such Capital Call.

        (iv)  Following the funding of the Minimum Class A Investment by the Class A Members pursuant to Sections 4.1(b)(i) and 4.1(b)(ii), the Class B Members hereby agree to make from time to time additional cash Capital Contributions to the Company, on an as needed basis and is consistent with the applicable Approved Budget, until the occurrence of the First Equalization Date. Prior to the occurrence of the First Equalization Date, at each time when the Company requires additional capital, the Board shall issue a Capital Call to the Class B Members, and the Class B Members shall contribute to the Company the amount of capital so requested, in accordance with their respective Class B Percentage Interests, within fifteen Business Days after receipt of such Capital Call. Following the First Equalization Date, the Class B Members shall thereafter have no obligation to contribute any additional capital to the Company.

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        (c)    Capital Contributions After the First Equalization Date But Prior to the Second Equalization Date.    

          (i)  After the First Equalization Date but prior to the Second Equalization Date, the Class B Member(s) will have the right, but not the obligation, to make all additional cash Capital Contributions required by the Company and consistent with the applicable Approved Budget.

         (ii)  If the Company requires additional capital after the First Equalization Date but prior to the Second Equalization Date, and the Class B Member(s) elects not to contribute all additional capital so required, then, the Class A Members may elect to contribute additional capital that is not contributed by the Class B Member(s), up to an aggregate amount of capital equal to the total amount of capital requested, less the amount of additional capital contributed by the Class B Member(s) in connection with such request. Upon any such election by the Class A Members, the amount to be contributed by the Class A Members shall be contributed to the Company by the Class A Members pro rata in accordance with their respective Class A Percentage Interests.

        (iii)  With respect to additional capital required under this Section 4.1(c), the Class A Member(s) and Class B Member(s) will use commercially reasonable efforts to cooperate in making and communicating funding elections to permit the continued orderly conduct of the Company's business. The Member(s) electing to fund additional capital pursuant to this Section 4.1(c) shall contribute to the Company the amount of capital so elected within fifteen Business Days after receipt of a Capital Call properly made by the Board.

        For the avoidance of doubt, the Percentage Interests of the Members shall be subject to adjustment (upward and downward) pursuant to this Section 4.1(c), based upon the Members' respective Investment Balances giving effect to such additional Capital Contributions. If elections to contribute capital by the Members are less than the total amount of capital required by the Company consistent with the applicable Approved Budget 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 Sections 5.3 and subject to Section 5.6, if applicable.

        (d)    Capital Contributions After the Second Equalization Date.    

          (i)  If the Company requires additional capital consistent with the applicable Approved Budget after the Second Equalization Date, then, the Class A Member(s) and the Class B Member(s) will have the right, but not the obligation, to make additional cash Capital Contributions in accordance with their respective Percentage Interests. If the Class A Member(s) do not elect to make their proportionate share of such additional cash Capital Contributions, or elect to contribute less than the amount set forth in the first sentence of this Section 4.1(d)(i), the Class B Member(s) may elect to contribute such additional capital not contributed by the Class A Member(s).

         (ii)  With respect to additional capital required under this Section 4.1(d), the Class A Member(s) and Class B Member(s) will use commercially reasonable efforts to cooperate in making and communicating funding elections to permit the continued orderly conduct of the Company's business. The Member(s) electing to fund additional capital pursuant to this Section 4.1(d) shall contribute to the Company the amount of capital so elected within fifteen Business Days after receipt of a Capital Call properly made by the Board.

        For the avoidance of doubt, the Percentage Interests of the Members shall be subject to adjustment (upward and downward) pursuant to this Section 4.1(d), based upon the Members' respective Investment Balances giving effect to such additional Capital Contributions. If elections to contribute capital by the Members are less than the total amount of capital required by the Company consistent with the applicable Approved Budget pursuant to this Section 4.1(d), then the Company may

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seek to obtain the requested capital from third parties, which may include issuing additional Interests in the Company pursuant to Sections 5.3 and subject to Section 5.6, if applicable.

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; Capital Calls.    

        (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.

        (d)   The Company and the Board will use commercially reasonable efforts to not initiate Capital Calls more frequently than once per calendar month; provided that the Members acknowledge that more frequent Capital Calls may be required in the case of events outside of the ordinary course of business, including in response to emergencies or similar situations.

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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    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 and any additional Capital Contributions made by a Member pursuant to Sections 4.1(b), 4.1(c) and 4.1(d). 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.

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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 (which prior written notice may be given by electronic mail). 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 Sections 4.1(c) or 4.1(d) that was not fully funded by the Members and subject to the preemptive rights set forth in Section 5.6 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 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

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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, in addition to complying with the confidentiality obligations set forth herein, 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 provisions contained in those third party confidentiality agreements that have been disclosed and delivered to such Member, including, any provisions thereof that impose more stringent or additional obligations than those set forth herein (provided such has been disclosed and delivered 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.

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        (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. The Members acknowledge that **.

Section 5.6    Preemptive Rights.    

        (a)   Subject to the Class A Member(s) or Class B Member(s) obligation or right to contribute additional capital as set forth in Section 4.1, 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 EMG, (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 Sections 4.1(c) or 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 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 5.6.

        (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 5.6, 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

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subscribed pursuant to this Section 5.6, 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 5.6 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 5.7    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, 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)   subject to Section 6.12(j), incurrence or guarantee of Debt by the Company in excess of $**;

        (e)   subject to Section 6.12(j), acquisitions or dispositions of assets by the Company in excess of (i) $** prior to the First Equalization Date and (ii) $** after the First Equalization Date;

        (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 First Equalization Date, the Board shall be comprised of five Managers, designated as follows:

          (i)  two Managers (each, a "Class A Manager") designated by Class A Members with an aggregate Class A Percentage Interest of at least 50%; and

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         (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 and Jeffrey C. Rawls, 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 First 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 or equal to **, shall be allowed to designate two Managers;

        (iv)  Each Affiliated Member Group with a Percentage Interest greater than ** but less than or equal to **, shall be allowed to designate three Managers;

         (v)  Each Affiliated Member Group with a Percentage Interest greater than ** but less than or equal to **, shall be allowed to designate four Managers; and

        (vi)  Each Affiliated Member Group with a Percentage Interest greater than **, shall be allowed to designate five 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 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

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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 ** the Board.

        (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 EMG Group (if there is such a Manager) and at least one Manager designated by the MWE Operating Company Group (if there is such a Manager) shall be 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 EMG Group (if there is such a Manager) or at least one Manager designated by the MWE Operating Company Group (if there is such a Manager), as applicable, did not receive prior written notice of the action to be so taken (which prior written notice may be given by email).

        (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,

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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.

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.

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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 Operating Company as the initial "Operator" of the Company. Subject to any required Board or Member approvals rights set forth in this Agreement, MWE Operating Company 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 Operating Company as the Operator shall be exclusive to MWE Operating Company, except to the extent that MWE Operating Company elects to cause such duties to be provided by third parties (and, in any case MWE Hydrocarbon and MWE Operating Company remain fully responsible for compliance with the Services Agreement). MWE Operating Company shall have the power and authority to execute contracts, and to take such other actions, and to direct the officers of the Company to do the foregoing, 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 Operating Company 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 Operating Company 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

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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 Operating Company as Operator may deem appropriate and consistent with MWE Operating Company's practices;

       (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 Operating Company 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)   As of the date hereof, the Operator and the Company shall execute the Services Agreement with MWE Hydrocarbon, which is hereby approved by the Members. 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 Operating Company hereby agrees to notify EMG of any notice of default or other material notices received by MWE Operating Company in connection with the agreements listed on Exhibit E.

Section 6.12    Approval of Members.    

        The following matters shall require Requisite Member Approval (provided that, in addition to other exceptions described in this Section 6.12, 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 First Equalization Date to the extent not in accordance with Section 8.1, any distributions of Available Cash (including Tax Distributions);

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        (b)   The approval of the Proposed Budgets for the Company, other than the Initial Budget, which shall be deemed approved upon the execution of this Agreement;

        (c)   Material deviations from Approved Budgets, including (i) with respect to any Approved Budget, any modification or amendment of ** pursuant to such budget, (ii) with respect to the capital expenditure budget, **, but excluding any items, other than as provided in Section 6.12(j), requiring aggregate capital expenditures of ** associated with a Project ** and (iii) with respect to the operating expenditure budget, ** or **; 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 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 6.16(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)   Subject to Section 6.12(j), the incurrence of Debt and the granting of Liens on the Company's Property in an aggregate amount in excess of $**, excluding the Permitted Liens; provided, that, with respect to this Section 6.12(e), no Requisite Member Approval is required if (x) the applicable Debt and/or granting of Liens on the Company's Property is associated with an Approved Budget and (y) the terms of such Debt and/or Liens are materially consistent with the terms contained in any Approved Budget;

        (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 ** shall not require Requisite Member Approval; provided further, that, with respect to this Section 6.12(f), if Requisite Member Approval has been obtained to preapprove transactions or agreements identified in this Section 6.12(f) meeting certain requirements, then no additional Requisite Member Approval shall be required to enter into such transactions or agreements that satisfy such requirements;

        (g)   Subject to Section 6.12(j), the acquisition or sale of any assets of the Company or its subsidiaries for consideration in excess of (i) $** prior to the First Equalization Date and (ii) $** after the First Equalization Date; provided, that, with respect to this Section 6.12(g), no Requisite Member Approval is required if (x) the applicable acquisition or sale is associated with an Approved Budget and (y) the terms of such acquisition or sale are materially consistent with the terms contained in any Approved Budget.

        (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 **, (B) generate annual revenues in excess of $**, which **, 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 greater than ** 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; provided, that, with respect to Section 6.12(h)(i), no Requisite Member

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Approval is required if (x) the applicable commercial contract is associated with an Approved Budget and (y) the terms of such commercial contract are materially consistent with the economic terms contained in any Approved Budget;

        (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 agreement (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 E, all of which are hereby approved by the Members or (iii) is entered into in the ordinary course of business on terms comparable to arm's length transactions between unrelated third parties for **;

        (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;

        (n)   Prior to the First Equalization Date, other than in accordance with the obligations or rights 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 ** as authorized in the Approved Budget or more than ** in the Approved Budget;

        (t)    Permitting 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)  Any action by the Company that would cause it to be **; and

        (x)   The entry into any agreement to effect any of the foregoing.

        Notwithstanding anything to the contrary in this Agreement, MWE Operating Company shall have the unilateral right, without the approval of the Company, any other Member or any other Person, to either (i) contribute capital to the Company for the purpose of causing the Company to satisfy any payment obligation under any instrument of indebtedness or other agreement or (ii) directly pay any such amount on behalf of the Company in satisfaction of any such obligation; provided that MWE would not receive any additional equity interests, increases in its Investment Balance or other similar credit for such a contribution or payment.

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Section 6.13**

        **

Section 6.14    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 6.15    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 6.16    Budgets.

        By ** of each calendar year (beginning with calendar year 2012), the Operator shall prepare and submit the following budgets and forecasts for the upcoming year (to the extent such budgets or forecasts are 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 **; (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 until ** 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 by such date, then the Proposed Budget will be deemed to be approved in all respects. If a Budget Rejection Notice is received by such date, 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. If the Proposed Budget is not approved, or in the event of a dispute 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 the Proposed Budget is approved or any such dispute is resolved. In the event of a dispute, if such dispute is not resolved by February 15th of the calendar year to which the Proposed Budget relates, such dispute shall be submitted to arbitration pursuant to Section 6.16(d) below. The Proposed Budget as

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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 6.16(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) or otherwise shall not become part of the Approved Budget unless approved by the Board and Requisite Member Approval.

        (d)   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, 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 Operating Company 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 EMG may be transferred to the limited partners of EMG, if and to the extent required by the governance documents of EMG. In the event of a Transfer pursuant to the foregoing clause (c), the EMG Group shall designate a single representative to exercise all of the EMG 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

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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 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 Sections 7.2(a)(iii) and 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).

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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

        (iii)  Prior to the Transferring Member electing to Transfer the ROFO Interest to a third party in accordance with a Qualifying Third Party Offer pursuant to Section 7.2(a)(ii), the Transferring Member must comply with this Section 7.2(a)(iii). Prior to accepting a Qualifying Third Party Offer pursuant to Section 7.2(a)(ii), the Transferring Member shall give written notice thereof to the other Members. For a period of 15 days thereafter, the Remaining Members shall have the right, but not the obligation, 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 Interests of the Remaining Members, or such other portion as the Remaining Members may mutually agree upon) at ** the price proposed in the Qualifying Third Party Offer, and otherwise on the same terms and conditions set forth in the Qualifying Third Party Offer. In the event that one or more of the Remaining Members exercise such ** purchase right, the closing of the Transfer of the ROFO Interest shall occur within 30 days of the Remaining Members' purchase election or on such other date as the participating parties mutually agree.

        (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 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

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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 (A) such Sale Proposal is consummated within 90 days after the end of the Tag-Along Notice Period and (B) 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 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 ("Company Sale Offer"), it may cause a Company Sale pursuant to the terms and provisions set forth in Section 7.2(b)(iii). 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.

        (iii)  Within five days after receipt of a Company Sale Offer that the Class B Seller desires to accept, the Board shall notify each Member, in writing, of such Company Sale Offer ("Company Sale Notice"). The Company Sale Notice shall identify the transferee, the proposed consideration and all other material terms and conditions of the Company Sale, including the form of the proposed agreement, if any, and provide a copy of all relevant documents and agreements related to such Company Sale. Each Member agrees that upon receipt of a Company Sale Notice it will (i) take such action as may reasonably be required, including voting its Interest and/or including its Interest in any such Company Sale, (ii) cause its designated Managers to take such action required, to approve and cause such Company Sale to promptly be consummated, (iii) provide for the execution of such agreements and such instruments and other actions reasonably necessary to

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provide, to the extent necessary, customary several (and not joint) representations, warranties, indemnities, and escrow/holdback arrangements relating to such Company Sale, in each case only to the extent that each other holder of Interests is similarly obligated; provided that, no Affiliated Member Group shall be obligated in respect of any indemnity obligations with respect to the customary representations, warranties and indemnities made on a several (and not joint) basis and referred to in the immediately preceding clause in such Company Sale for an aggregate amount in excess of the total consideration payable to such Affiliated Member Group in such Company Sale. The Member proposing such Company Sale shall have the right in connection with any such transaction (or in connection with the investigation or consideration of any such potential transaction) to require the Company to cooperate fully with potential acquirors in such prospective Company Sale by taking all customary and other actions reasonably requested by the Member proposing the Company Sale or such potential acquirors, including making the Company's properties, books and records, and other assets reasonably available for inspection by such potential acquirors, establishing a data room including materials customarily made available to potential acquirors in connection with such processes and making its employees reasonably available for presentations, interviews and other diligence activities, in each case subject to reasonable and customary confidentiality provisions. The Company and each Member shall provide assistance with respect to these actions as reasonably requested by the Member proposing the Company Sale. In addition, once a Company Sale is properly initiated under this Section 7.2, the Board shall be entitled to take all steps reasonably necessary to carry out an auction of the Company, including selecting an investment bank, providing Confidential Information (pursuant to confidentiality agreements), selecting the winning bidder and negotiating the requisite documentation; provided, however, that the rights granted the Board in this sentence shall not permit the Board to veto such a properly initiated Company Sale.

        (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, 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.

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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 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 45 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 to the Members of record, as follows.

        (a)   Within 60 days following the end of each calendar quarter prior to the earlier to occur of (i) the Trigger Date and (ii) the First Equalization Date, Available Cash shall be distributed to the Members as follows:

          (i)  40% to the Class A Members in accordance with their Class A Percentage Interests; and

         (ii)  60% to the Class B Members in accordance with their Class B Percentage Interests.

        (b)   With respect to the calendar quarter during which the Trigger Date or the First Equalization Date occurs, within 60 days following the end of such calendar quarter, Available Cash shall be distributed to the Members based on the quotient (expressed as a percentage) obtained by dividing the weighted average Investment Balance of such Member by the weighted average Investment Balances of all Members during such period.

        (c)   Within 60 days following the end of each calendar quarter after the earlier to occur of (i) the Trigger Date and (ii) the First Equalization Date, Available Cash shall be distributed to the Members in accordance with their respective Percentage Interests.

Section 8.2    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.

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Section 8.3    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 8.4    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.

        (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.

        (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 8.4 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.

        After giving effect to the special allocations set forth in Section 9.2, 9.3 and 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, that 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. To the extent Losses allocated to a Member would cause such Member to have an Adjusted Capital Account Deficit at the end of any Fiscal Year, the Losses will be reallocated to other Members. If any Member receives an allocation of Losses otherwise allocable to another Member in accordance with this Section 9.1(a), such Member shall be allocated Profits in subsequent Fiscal Years necessary to reverse the effect of such allocation of Losses. Such allocation of Profits (if any) shall be made before any other Profit allocations under this Section 9.1(a).

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.

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        (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 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) or 9.2(d). 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)    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(f) 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(f) were not in this Agreement.

Section 9.3    Curative Allocations.

        The allocations set forth in Section 9.2 (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

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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.

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.

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        (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.

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 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;

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        (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 6.16;

        (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 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.

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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 Operating Company, so long as MWE Operating Company 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."

        (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)(6), (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.

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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 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

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repay such amount if it shall be determined that the Covered Person is not entitled to be indemnified as authorized in Section 12.3.

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(q);

        (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 First Equalization Date has not yet occurred, then:

        (A)  First, 100% to the Class A Members until the **; and

        (B)  Second, to the Class A Members and the Class B Members in proportion to their Investment Balances until **;

        (C)  Third, 40% to the Class A Members and 60% to the Class B Members until **; and

        (D)  Thereafter, to the Class A Members and to the Class B Members in proportion to their Investment Balances (determined immediately prior to any distributions made pursuant to this Section 13.4).

         (ii)  If the First Equalization Date has occurred, then to the Members in accordance with their respective Percentage Interests.

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        (b)   In the event of any liquidation and winding up of the Company under Section 13.4 or a sale, exchange or other disposition of all or substantially all of the assets of the Company, either voluntary or involuntary, Profits and Losses and each item of gross income, gain, loss and deduction for such period 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) (referred to as "Liquidation Amounts"), and no other allocation of Profit or Loss pursuant to this Agreement shall reverse the effect of such allocation. If in the year of such liquidation, dissolution or winding up, the Members' Capital Accounts are not equal to their respective Liquidation Amounts after the application of the preceding sentence, then to the extent permitted by law and notwithstanding anything to the contrary contained in this Agreement, items of gross income and gain for any preceding taxable period(s) with respect to which IRS Form 1065 Schedules K-1 have not been filed by the Company shall be reallocated among the Members until the Members' Capital Accounts are equal to their respective Liquidation Amounts, and no other allocation of Profit or Loss pursuant to this Agreement shall reverse the effect of such allocation.

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.

46

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 is fully authorized and qualified to become a Member of the Company and is authorized to make the initial Capital Contribution to the Company, 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 Company may raise additional capital by selling Interests to one or more Members or other Persons, (iii) the Member

47

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 (a) upon delivery, if delivered personally, or if delivered by facsimile, upon confirmation of delivery, (b) when notice is sent to the recipient provided that confirmation of receipt is obtained by sender orally, by facsimile or by electronic mail, if sent by electronic mail (unless otherwise provided in this Agreement), (c) three days after mailing, if mailed, or (d) 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 and Exhibit B 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.

48

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.

49

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.

[Signature Page Follows]

50

        IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above written.

MWE OPERATING COMPANY:
MARKWEST UTICA OPERATING COMPANY, 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 1, Suite 1600 Denver, CO 80202-2137 Attention:    Senior Vice President and Chief Operating Officer

Signature Page

EMG:
EMG UTICA, LLC
By:	/s/ John T. Raymond
Name:	John T. Raymond
Title:	Chairman & Chief Executive Officer
Address for notice: 811 Main Street, Suite 4200 Houston, TX 77002 Attention:    John T. Raymond
with a copy to:
Locke Lord LLP 600 Travis Street, Suite 2800 Houston, Texas 77002 Facsimile: (713) 226-2563 Attention: H. William Swanstrom

Signature Page

EXHIBIT A

AREA OF MUTUAL INTEREST

        **

A-1

EXHIBIT B

MEMBERS AND CAPITAL CONTRIBUTIONS

Member Name and Address	Capital Contribution	Type of Membership Interest	Initial Percentage Interest	Initial Investment Balance
EMG Utica, LLC 811 Main Street, Suite 4200 Houston, TX 77002 Attention: John T. Raymond Facsimile: (713) 579-5010 Email: jraymond@emgtx.com             jrawls@emgtx.com             pwade@emgtx.com with a copy to: Locke Lord LLP 600 Travis Street, Suite 2800 Houston, Texas 77002 Facsimile: (713) 226-2563 Attention: H. William Swanstrom	**	Class A	40%	**
MarkWest Utica Operating Company, L.L.C. 1515 Arapahoe Street, Tower 1, Suite 1600 Denver, CO 80202 Attention:    Senior Vice President and Chief Operating Officer Facsimile: (303) 925-9305 Email: jmollenkopf@markwest.com with a copy to: MarkWest Utica Operating Company, L.L.C. 1515 Arapahoe Street, Tower 1, Suite 1600 Denver, CO 80202 Attention:    Senior Vice President, General Counsel and Secretary Facsimile: (303) 925-9308 Email: cbromley@markwest.com	**	Class B	60%	**

B-1

EXHIBIT C

BASE PROJECT

**

C-1

EXHIBIT D

INITIAL BUDGET

**

D-1

EXHIBIT E

PRE-APPROVED AFFILIATED TRANSACTIONS

1.

Services Agreement

E-1

EXHIBIT F

**

F-1

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Exhibit 10.35

TABLE OF CONTENTS
LIMITED LIABILITY COMPANY AGREEMENT OF MARKWEST UTICA EMG, L.L.C.
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 A
EXHIBIT C
EXHIBIT D

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)

	2007			2008			2009			2010			2011
Total fixed charges	$	49,191		$	86,559		$	112,981		$	120,711		$	123,893
Earnings:
Earnings from continuing operations before income taxes	$	(59,155	)	$	273,602		$	(155,370	)	$	34,291		$	119,894
Add:
Fixed charges		49,191			86,559			112,981			120,711			123,893
Amortization of capitalized interest		478			1,110			1,444			1,583			1,639
Cash distributions from equity method investments		10,840			445			—			2,508			300
(Income) Loss from equity method investments		(5,309	)		(90	)		(3,505	)		(1,562	)		1,095
Subtract:
Interest capitalized		(3,344	)		(9,486	)		(12,228	)		(2,766	)		(1,121	)
Total earnings	$	(7,299	)	$	352,140		$	(56,678	)	$	154,765		$	245,700
Ratio		(0.15	)		4.07			(0.50	)		1.28			1.98
Deficit	$	(56,490	)	$	—		$	(169,659	)	$	—		$	—

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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 Mountaineer Pipeline Company, L.L.C.	Delaware
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 Ranger Pipeline Company, L.L.C.	Delaware
MarkWest Texas PNG Utility, L.L.C.	Texas
MarkWest Utica EMG, L.L.C.	Delaware
MarkWest Utica Operating Company, L.L.C.	Delaware
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. 333-164323 (as amended by Post-Effective Amendment No. 1 and Post-Effective Amendment No. 2), 333-142358, 333-149742 and 333-157883 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 February 28, 2012, 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 the Annual Report on Form 10-K of MarkWest Energy Partners, L.P. for the year ended December 31, 2011.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
February 28, 2012

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Exhibit 23.1

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: February 28, 2012 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: February 28, 2012 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, 2010, 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: February 28, 2012 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, 2010, 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: February 28, 2012 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

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Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2011

Variable Interest Entities

Consolidated assets and liabilities attributable to VIEs reflected in the Partnership's Consolidated Balance Sheets

	MarkWest Liberty Midstream		MarkWest Pioneer		Total
ASSETS
Cash and cash equivalents	$	—	$	2,913	$	2,913
Receivables, net		42,181		1,602		43,783
Inventories		8,431		—		8,431
Other current assets		271		1		272
Property, plant and equipment, net of accumulated depreciation of $28,869 and $9,300, respectively		664,778		147,039		811,817
Restricted cash		28,001		—		28,001
Other long-term assets		281		102		383
Total assets	$	743,943	$	151,657	$	895,600
LIABILITIES
Accounts payable	$	5,945	$	—	$	5,945
Accrued liabilities		63,450		1,263		64,713
Other long-term liabilities		86		68		154
Total liabilities	$	69,481	$	1,331	$	70,812

Net income (loss) attributable to the entity and transfers to the non-controlling interest

	Year ended December 31,
	2011			2010		2009
Net income (loss) attributable to the Partnership	$	60,695		$	467	$	(118,668	)
Transfers to the non-controlling interests:
Decrease in common unit equity for 2011 acquisition of equity interest in MarkWest Liberty Midstream, net of $51,321 income tax benefit		(1,194,865	)		—		—
Decrease in common unit equity for transaction costs related to 2011 acquisition of equity interest in MarkWest Liberty Midstream		(3,600	)		—		—
Decrease in common unit equity for transfer to non- controlling interest from 2009 sale of equity interest in MarkWest Pioneer, net of $1,491 income tax benefit		—			—		(10,288	)
Decrease in common unit equity for transaction costs related to 2009 sales of equity interests in MarkWest Liberty Midstream and MarkWest Pioneer		—			—		(7,310	)
Net (loss) income attributable to the Partnership and transfers to the non-controlling interest	$	(1,137,770	)	$	467	$	(136,266	)

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Tax

Summary of components of the provision for income tax expense (benefit)

	Year ended December 31,
	2011			2010			2009
Current income tax expense:
Federal	$	15,039		$	5,850		$	6,525
State		2,539			1,805			1,547
Total current		17,578			7,655			8,072
Deferred income tax (benefit) expense:
Federal		(4,732	)		(3,870	)		(43,409	)
State		803			(596	)		(6,679	)
Total deferred		(3,929	)		(4,466	)		(50,088	)
Provision for income tax	$	13,649		$	3,189		$	(42,016	)

Reconciliation of the provision for income tax to the amount computed by applying the federal statutory rate

Year ended December 31, 2011:

	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax.	$	3,813		$	124,087		$	(8,006	)	$	119,894
Federal statutory rate		35	%		0	%		0	%
Federal income tax at statutory rate		1,335			—			—			1,335
Permanent items		36			—			—			36
State income taxes net of federal benefit		102			2,742			—			2,844
Current year change in valuation allowance		(64	)		—			—			(64	)
Prior period adjustments and tax rate changes		163			—			—			163
Provision on income from Class A units(1)		9,323			—			—			9,323
Other		12			—			—			12
Provision for income tax	$	10,907		$	2,742		$	—		$	13,649

Year ended December 31, 2010:

	Corporation			Partnership			Eliminations			Consolidated
(Loss) income before provision for income tax	$	(8,120	)	$	47,761		$	(5,350	)	$	34,291
Federal statutory rate		35	%		0	%		0	%
Federal income tax at statutory rate		(2,842	)		—			—			(2,842	)
Permanent items		20			—			—			20
State income taxes net of federal benefit		(272	)		1,299			—			1,027
Current year change in valuation allowance		(1,022	)		—			—			(1,022	)
Prior period adjustments and tax rate changes		70			—			—			70
Provision on income from Class A units(1)		5,753			—			—			5,753
Other		183			—			—			183
Provision for income tax	$	1,890		$	1,299		$	—		$	3,189

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	$	(40,577	)	$	(1,439	)	$	—		$	(42,016	)

(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. This amount includes intra period allocations to continued operations and excludes allocations to equity.

Schedule of deferred tax assets and liabilities resulting from temporary book-tax differences

	December 31,
	2011			2010
Current deferred tax assets:
Accruals and reserves	$	78		$	64
Derivative instruments		14,807			16,031
Current deferred tax assets		14,885			16,095
Current deferred tax liabilities:
Derivative instruments		—			16
Current deferred tax liabilities		—			16
Current subtotal		14,885			16,079
Long-term deferred tax assets:
Accruals and reserves		48			34
Derivative instruments		20,301			14,241
Phantom unit compensation		2,103			1,684
Capital loss carryforward		971			975
State net operating loss carryforward		101			156
Long-term deferred tax assets		23,524			17,090
Valuation allowance		(977	)		(1,036	)
Net long-term deferred tax assets		22,547			16,054
Long-term deferred tax liabilities:
Property, plant and equipment and intangibles		2,123			3,529
Phantom unit compensation		—			31
Investment in affiliated groups		114,088			100,345
Derivative instruments		—			30
Long-term deferred tax liabilities		116,211			103,935
Long-term subtotal		(93,664	)		(87,881	)
Net deferred tax liability	$	(78,779	)	$	(71,802	)

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Asset Retirement Obligation (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation

Schedule of reconciliation of the changes in the asset retirement obligation

	December 31, 2011		December 31, 2010
Beginning asset retirement obligation	$	4,029	$	2,877
Liabilities incurred		1,599		915
Accretion expense		1,190		237
Ending asset retirement obligation	$	6,818	$	4,029

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Significant Customers and Concentration of Credit Risk (Details) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Significant Customers and Concentration of Credit Risk
Accounts receivable from a significant customer	$ 221,343,000	$ 174,216,000
Revenues | Customer concentration | First significant customer
Significant Customers and Concentration of Credit Risk
Revenues from a significant customer	297,800,000	198,600,000	134,800,000
Percentage of revenues from a significant customer	19.40%	16.00%	15.70%
Accounts receivable from a significant customer	8,000,000	5,100,000
Revenues | Customer concentration | Second significant customer
Significant Customers and Concentration of Credit Risk
Revenues from a significant customer	203,300,000	115,000,000	81,600,000
Percentage of revenues from a significant customer	13.20%	9.30%	9.50%
Accounts receivable from a significant customer	$ 21,900,000	$ 13,100,000

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Earnings (Loss) Per Common Unit (Tables)

12 Months Ended

Dec. 31, 2011

Earnings (Loss) Per Common Unit

Computation of basic and diluted net income (loss) per common unit

	Year ended December 31,
	2011(2)		2010			2009
Net income (loss) attributable to the Partnership	$	60,695	$	467		$	(118,668	)
Less: Income allocable to phantom units		1,749		1,308			1,518
Income (loss) available for common unitholders	$	58,946	$	(841	)	$	(120,186	)
Weighted average common units outstanding—basic		78,466		70,128			60,957
Effect of dilutive instruments(1)		153		—			—
Weighted average common units outstanding—diluted		78,619		70,128			60,957
Net income (loss) attributable to the Partnership's common unitholders per common unit:
Basic	$	0.75	$	(0.01	)	$	(1.97	)
Diluted	$	0.75	$	(0.01	)	$	(1.97	)

(1)

For the years ended December 31, 2011 and 2010, dilutive instruments include TSR Phantom Units and are based on the number of units, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period. For the year ended December 31, 2010, 195 units were excluded from the calculation of diluted units because the impact was anti-dilutive. See Note 20 for further discussion of TSR Phantom Units.

(2)

The Class B units had no impact to the earnings per unit calculation as they were issued on December 31, 2011 and as such were not outstanding for any portion of the fiscal year and were not allocated any of the Net income (loss) attributable to the Partnership.

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Asset Retirement Obligation (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Reconciliation of the changes in the asset retirement obligation
Beginning asset retirement obligation	$ 4,029	$ 2,877
Liabilities incurred	1,599	915
Ending asset retirement obligation	6,818	4,029	2,877
Accretion expense	$ 1,190	$ 237	$ 198

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Goodwill and Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2011

Goodwill and Intangible Assets

Schedule of gross amount of goodwill acquired and the cumulative impairment loss recognized

	Southwest			Northeast		Gulf Coast			Total
Gross goodwill as of December 31, 2010	$	24,324		$	3,948	$	9,854		$	38,126
Acquisition(1)		—			58,497		—			58,497
Gross Goodwill as of December 31, 2011		24,324			62,445		9,854			96,623
Cumulative impairment(2)		(18,851	)		—		(9,854	)		(28,705	)
Balance as of December 31, 2011	$	5,473		$	62,445	$	—		$	67,918

(1)

Represents goodwill associated with the Langley Acquisition (see Note 3).

(2)

All impairments recorded in the fourth quarter of 2008.

Schedule of intangible assets

	December 31, 2011							December 31, 2010
Description	Gross		Accumulated Amortization			Net		Gross		Accumulated Amortization			Net		Useful Life
Southwest	$	406,690	$	(92,340	)	$	314,350	$	406,801	$	(69,655	)	$	337,146	10 - 20 yrs
Northeast		102,473		(29,037	)		73,436		68,573		(19,590	)		48,983	12 yrs
Gulf Coast		262,772		(46,791	)		215,981		262,772		(35,323	)		227,449	20 - 25 yrs
Total	$	771,935	$	(168,168	)	$	603,767	$	738,146	$	(124,568	)	$	613,578

Schedule of estimated future amortization expense related to the intangible assets

Year ending December 31,
2012	$	43,940
2013		43,940
2014		43,940
2015		43,940
2016		43,940
Thereafter		384,067
	$	603,767

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Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2011

Valuation and Qualifying Accounts

Valuation and Qualifying Accounts

27. Valuation and Qualifying Accounts

        Activity in the Partnership's allowance for doubtful accounts and deferred tax asset valuation allowance is as follows (in thousands):

	Year ended December 31,
	2011			2010			2009
Allowance for Doubtful Accounts
Balance at beginning of period	$	162		$	162		$	175
Charged to costs and expenses		—			134			12
Other charges(1)		(2	)		(134	)		(25	)
Balance at end of period	$	160		$	162		$	162
Deferred Tax Asset Valuation Allowance
Balance at beginning of period	$	1,036		$	1,688		$	30
Charged to costs and expenses		(59	)		(652	)		1,667
Other charges		—			—			(9	)
Balance at end of period	$	977		$	1,036		$	1,688

(1)

Bad debts written-off (net of recoveries).

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Long-Term Debt (Details) (USD $)	3 Months Ended			12 Months Ended											12 Months Ended				1 Months Ended		3 Months Ended	4 Months Ended	12 Months Ended		1 Months Ended		3 Months Ended		12 Months Ended		1 Months Ended			1 Months Ended			1 Months Ended		12 Months Ended
	Dec. 31, 2011	Mar. 31, 2011	Dec. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Revolving credit facility	Dec. 31, 2010 Revolving credit facility	Dec. 31, 2009 Revolving credit facility	Dec. 31, 2011 Revolving credit facility Minimum	Dec. 31, 2011 Revolving credit facility Maximum	Dec. 31, 2011 Revolving credit facility LIBOR Loans	Dec. 31, 2011 Revolving credit facility LIBOR Loans Maximum	Dec. 31, 2011 Revolving credit facility Alternate Base Rate Loans Maximum	Dec. 31, 2011 Revolving credit facility Prime rate	Dec. 31, 2011 Revolving credit facility Federal Funds rate	Dec. 31, 2011 Revolving credit facility One month LIBOR	Dec. 31, 2011 Senior Notes Y	May 31, 2009 2014 Senior Notes, 6.875% interest, issued October 2004 and May 2009 and due November 2014	Oct. 31, 2004 2014 Senior Notes, 6.875% interest, issued October 2004 and May 2009 and due November 2014	Dec. 31, 2010 2014 Senior Notes, 6.875% interest, issued October 2004 and May 2009 and due November 2014	Dec. 31, 2006 2016 Senior Notes, 8.5% interest, issued July 2006 and due July 2016	Dec. 31, 2011 2016 Senior Notes, 8.5% interest, issued July 2006 and due July 2016	Dec. 31, 2010 2016 Senior Notes, 8.5% interest, issued July 2006 and due July 2016	May 31, 2008 2018 Senior Notes, 8.75% interest, issued April and May 2008 and due April 2018	Apr. 30, 2008 2018 Senior Notes, 8.75% interest, issued April and May 2008 and due April 2018	Dec. 31, 2011 2018 Senior Notes, 8.75% interest, issued April and May 2008 and due April 2018	Mar. 31, 2011 2018 Senior Notes, 8.75% interest, issued April and May 2008 and due April 2018	Dec. 31, 2011 2018 Senior Notes, 8.75% interest, issued April and May 2008 and due April 2018	Dec. 31, 2010 2018 Senior Notes, 8.75% interest, issued April and May 2008 and due April 2018	Nov. 30, 2010 2020 Senior Notes, 6.75% interest, issued November 2010and due November 2020	Dec. 31, 2011 2020 Senior Notes, 6.75% interest, issued November 2010and due November 2020	Dec. 31, 2010 2020 Senior Notes, 6.75% interest, issued November 2010and due November 2020	Mar. 31, 2011 2021 Senior Notes, 6.5% interest, issued February and March 2011 and due August 2021	Feb. 28, 2011 2021 Senior Notes, 6.5% interest, issued February and March 2011 and due August 2021	Dec. 31, 2011 2021 Senior Notes, 6.5% interest, issued February and March 2011 and due August 2021	Nov. 30, 2011 2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022	Dec. 31, 2011 2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022	Dec. 31, 2011 2016 and 2018 Senior Notes	Dec. 31, 2011 Revolving Credit Facility LIBOR Loans Minimum	Dec. 31, 2011 Revolving Credit Facility Alternate Base Rate Loans Minimum
Long-Term Debt
Long-term debt, net of discounts	$ 1,846,062,000		$ 1,273,434,000	$ 1,846,062,000	$ 1,273,434,000		$ 66,000,000																	$ 274,358,000			$ 80,983,000		$ 80,983,000	$ 499,076,000		$ 500,000,000	$ 500,000,000			$ 499,079,000		$ 700,000,000
Debt instrument, stated interest rate percentage							4.00%												6.875%	6.875%			8.50%				8.75%		8.75%			6.75%				6.50%		6.25%
Long-term debt, discounts	1,050,000		1,566,000	1,050,000	1,566,000																		0	642,000			129,000		129,000	924,000						921,000
Credit facility current lending capacity							900,000,000
Uncommitted accordion feature							250,000,000
Deferred financing costs				20,163,000	20,912,000	8,554,000	2,100,000	11,200,000	4,400,000
Basis of variable interest rate												LIBOR			Prime Rate	Federal Funds Rate	One month LIBOR
Spread on variable rate basis (as a percent)													2.75%	1.75%		0.50%	1.00%																							1.75%	0.75%
Letters of credit maximum borrowing capacity							150,000,000
Short-term swingline loan maximum borrowing capacity							10,000,000
Principal amount due in 2016							66,000,000
Interest coverage ratio, numerator										2.75
Interest coverage ratio, denominator										1.0
Total leverage ratio, numerator											5.25
Total leverage ratio, denominator											1.0
Borrowings outstanding amount							66,000,000
Letters of credit outstanding amount	19,300,000			19,300,000
Credit facility remaining borrowing capacity							814,700,000
Outstanding senior notes																											81,100,000		81,100,000			500,000,000				500,000,000		700,000,000
Aggregate principal amount of debt issued																			150,000,000	225,000,000		275,000,000			100,000,000	400,000,000					500,000,000			200,000,000	300,000,000		700,000,000
Combined proceeds after including initial purchasers' premium and deducting the underwriting fees and the other expenses of the offering																									488,500,000						490,300,000			492,000,000			688,000,000
Debt redeemed																							275,000,000				253,300,000	165,600,000	419,000,000
Loss on redemption of debt	35,500,000	43,300,000	46,300,000	78,996,000	46,326,000																46,300,000																		79,000,000
Issue price as percentage of par value																																		99.50%
Write off of the unamortized discount and deferred finance costs on extinguishment of debt																					36,600,000																		7,600,000
Payment of premiums and third-party expenses																					9,700,000																		71,400,000
Period with no maturities of long-term debt (in years)																		5
Principal amount due between 2018 and 2021																		$ 1,781,000,000

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Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Property, plant and equipment
Property, plant and equipment	$ 3,302,369	$ 2,613,027
Less: accumulated depreciation	(438,062)	(294,003)
Total property, plant and equipment, net	2,864,307	2,319,024
Natural gas gathering and NGL transportation pipelines and facilities
Property, plant and equipment
Property, plant and equipment	2,039,524	1,625,170
Processing plants
Property, plant and equipment
Property, plant and equipment	660,928	584,886
Fractionation and storage facilities
Property, plant and equipment
Property, plant and equipment	120,474	81,317
Crude oil pipelines
Property, plant and equipment
Property, plant and equipment	16,678	16,810
Land, building, office equipment and other
Property, plant and equipment
Property, plant and equipment	185,462	155,437
Construction in progress
Property, plant and equipment
Property, plant and equipment	$ 279,303	$ 149,407

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Segment Information (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment information
Revenue									$ 1,534,434	$ 1,241,563	$ 858,635
Derivative (loss) gain not allocated to segments									(29,035)	(53,932)	(120,352)
Revenue deferral adjustment									(15,385)
Total revenue	333,913	507,826	400,439	263,221	299,991	255,411	323,850	308,379	1,505,399	1,187,631	738,283
Selling, general and administrative expenses									(81,229)	(75,258)	(63,728)
Depreciation									(149,954)	(123,198)	(95,537)
Amortization of intangible assets									(43,617)	(40,833)	(40,831)
Loss on disposal of property, plant and equipment									(8,797)	(3,149)	(1,677)
Accretion of asset retirement obligations									(1,190)	(237)	(198)
Impairment of goodwill and long-lived assets											5,855
Income (loss) from operations	(7,557)	207,801	133,214	(15,294)	25,172	646	109,071	53,573	318,164	188,462	(73,856)
Earnings from unconsolidated affiliates									(1,095)	1,562	3,505
Gain on sale of unconsolidated affiliate											6,801
Interest income									422	1,670	349
Interest expense									(113,631)	(103,873)	(87,419)
Amortization of deferred financing costs and discount (a component of interest expense)									(5,114)	(10,264)	(9,718)
Derivative gain related to interest expense										1,871	2,509
Loss on redemption of debt	(35,500)			(43,300)	(46,300)				(78,996)	(46,326)
Miscellaneous income (expense), net									144	1,189	2,459
Income (loss) before provision for income tax									119,894	34,291	(155,370)
Total reportable segments
Segment information
Revenue									1,549,819	1,241,563	858,635
Portion of operating income attributable to non-controlling interests									69,162	32,566	9,250
Income (loss) from operations									615,051	471,720	314,237
Southwest Segment
Segment information
Revenue									935,513	665,768	492,369
Revenue deferral adjustment									7,200
Portion of operating income attributable to non-controlling interests									5,431	6,440	2,613
Income (loss) from operations									340,410	268,596	195,114
Northeast Segment
Segment information
Revenue									268,884	384,724	260,529
Revenue deferral adjustment									8,200
Income (loss) from operations									150,146	112,384	64,864
Unallocated Segment
Segment information
Derivative (loss) gain not allocated to segments									(75,515)	(80,350)	(188,862)
Revenue deferral adjustment									(15,385)
Compensation expense included in facility expenses not allocated to segments									(1,781)	(1,890)	(1,032)
Facility expenses adjustments									$ 11,419	$ 9,091	$ 377

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Supplemental Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Condensed Consolidating Financial Information

Condensed Consolidating Balance Sheets

Condensed Consolidating Balance Sheets

	As of December 31, 2011
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	22	$	99,580	$	17,414	$	—		$	117,016
Restricted cash		—		—		26,193		—			26,193
Receivables and other current assets		7,097		232,010		55,098		(5	)		294,200
Intercompany receivables		19,981		40,519		22,193		(82,693	)		—
Fair value of derivative instruments		—		8,015		683		—			8,698
Total current assets		27,100		380,124		121,581		(82,698	)		446,107
Total property, plant and equipment, net		4,012		1,714,857		1,163,226		(17,788	)		2,864,307
Other long-term assets:
Investment in unconsolidated affiliate		—		27,853		—		—			27,853
Investment in consolidated affiliates		3,071,124		1,097,350		—		(4,168,474	)		—
Intangibles, net of accumulated amortization		—		603,224		543		—			603,767
Fair value of derivative instruments		—		16,092		—		—			16,092
Intercompany notes receivable		235,700		—		—		(235,700	)		—
Other long-term assets		41,492		70,434		373		—			112,299
Total assets(1)	$	3,379,428	$	3,909,934	$	1,285,723	$	(4,504,660	)	$	4,070,425
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	40,503	$	40,374	$	1,816	$	(82,693	)	$	—
Fair value of derivative instruments		—		90,551		—		—			90,551
Other current liabilities		38,775		219,622		92,930		(5	)		351,322
Total current liabilities		79,278		350,547		94,746		(82,698	)		441,873
Deferred income taxes		1,228		92,436		—		—			93,664
Intercompany notes payable		—		212,700		23,000		(235,700	)		—
Fair value of derivative instruments		—		65,403		—		—			65,403
Long-term debt, net of discounts		1,846,062		—		—		—			1,846,062
Other long-term liabilities		3,232		117,724		400		—			121,356
Equity:
Common Units		697,097		3,071,124		1,167,577		(4,256,489	)		679,309
Class B Units		752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries		—		—		—		70,227			70,227
Total equity		1,449,628		3,071,124		1,167,577		(4,186,262	)		1,502,067
Total liabilities and equity	$	3,379,428	$	3,909,934	$	1,285,723	$	(4,504,660	)	$	4,070,425

(1)

In accordance with the December 2011 amendment to the Partnership's Credit Facility, certain assets in the Liberty segment included in Total property, plant, and equipment, net are expected to be contributed from a non-guarantor subsidiary to a guarantor subsidiary by April 2012. The contributed assets would include only the natural gas processing facilities at the Partnership's Houston Complex and any other equipment related solely to these processing facilities.

	As of December 31, 2010
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	63,850	$	3,600	$	—		$	67,450
Receivables and other current assets		1,708		172,209		52,834		—			226,751
Intercompany receivables		1,440,302		1,099		7,635		(1,449,036	)		—
Fair value of derivative instruments		—		4,345		—		—			4,345
Total current assets		1,442,010		241,503		64,069		(1,449,036	)		298,546
Total property, plant and equipment, net		4,623		1,512,763		812,898		(11,260	)		2,319,024
Other long-term assets:
Restricted cash		—		—		28,001		—			28,001
Investment in unconsolidated affiliate		—		28,688		—		—			28,688
Investment in consolidated affiliates		639,219		368,864		—		(1,008,083	)		—
Intangibles, net of accumulated amortization		—		613,000		578		—			613,578
Fair value of derivative instruments		—		417		—		—			417
Intercompany notes receivable		197,710		—		—		(197,710	)		—
Other long-term assets		32,587		12,139		382		—			45,108
Total assets	$	2,316,149	$	2,777,374	$	905,928	$	(2,666,089	)	$	3,333,362
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	672	$	1,447,799	$	565	$	(1,449,036	)	$	—
Fair value of derivative instruments		—		65,489		—		—			65,489
Other current liabilities		31,882		173,667		70,804		—			276,353
Total current liabilities		32,554		1,686,955		71,369		(1,449,036	)		341,842
Deferred income taxes		2,533		85,348		—		—			87,881
Intercompany notes payable		—		197,710		—		(197,710	)		—
Fair value of derivative instruments		—		66,290		—		—			66,290
Long-term debt, net of discounts		1,273,434		—		—		—			1,273,434
Other long-term liabilities		3,319		101,852		178		—			105,349
Equity:
Common Units		1,004,309		639,219		834,381		(1,484,860	)		993,049
Non-controlling interest in consolidated subsidiaries		—		—		—		465,517			465,517
Total equity		1,004,309		639,219		834,381		(1,019,343	)		1,458,566
Total liabilities and equity	$	2,316,149	$	2,777,374	$	905,928	$	(2,666,089	)	$	3,333,362

Condensed Consolidating Statements of Operations

Condensed Consolidating Statements of Operations

	Year ended December 31, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	1,240,004		$	265,395		$	—		$	1,505,399
Operating expenses:
Purchased product costs		—			651,132			84,198			—			735,330
Facility expenses		—			128,612			39,171			(665	)		167,118
Selling, general and administrative expenses		46,903			31,015			9,011			(5,700	)		81,229
Depreciation and amortization		719			151,362			42,198			(708	)		193,571
Other operating expenses		673			9,030			284			—			9,987
Total operating expenses		48,295			971,151			174,862			(7,073	)		1,187,235
(Loss) income from operations		(48,295	)		268,853			90,533			7,073			318,164
Earnings from consolidated affiliates		288,870			44,425			—			(333,295	)		—
Loss on redemption of debt		(78,996	)		—			—			—			(78,996	)
Other expense, net		(91,612	)		(13,501	)		(558	)		(13,603	)		(119,274	)
Income before provision for income tax		69,967			299,777			89,975			(339,825	)		119,894
Provision for income tax expense		2,742			10,907			—			—			13,649
Net income		67,225			288,870			89,975			(339,825	)		106,245
Net income attributable to non-controlling interest		—			—			—			(45,550	)		(45,550	)
Net income attributable to the Partnership	$	67,225		$	288,870		$	89,975		$	(385,375	)	$	60,695

	Year ended December 31, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Total revenue	$	—		$	1,063,621		$	124,010	$	—		$	1,187,631
Operating expenses:
Purchased product costs		—			589,403			16,937		—			606,340
Facility expenses		—			122,240			28,566		(652	)		150,154
Selling, general and administrative expenses		46,549			27,339			6,317		(4,947	)		75,258
Depreciation and amortization		594			136,781			27,054		(398	)		164,031
Other operating expenses		753			2,342			291		—			3,386
Total operating expenses		47,896			878,105			79,165		(5,997	)		999,169
(Loss) income from operations		(47,896	)		185,516			44,845		5,997			188,462
Earnings from consolidated affiliates		183,557			15,963			—		(199,520	)		—
Loss on redemption of debt		(46,326	)		—			—		—			(46,326	)
Other (expense) income, net		(82,000	)		(16,032	)		1,753		(11,566	)		(107,845	)
Income before provision for income tax		7,335			185,447			46,598		(205,089	)		34,291
Provision for income tax expense		1,299			1,890			—		—			3,189
Net income		6,036			183,557			46,598		(205,089	)		31,102
Net income attributable to non-controlling interest		—			—			—		(30,635	)		(30,635	)
Net income attributable to the Partnership	$	6,036		$	183,557		$	46,598	$	(235,724	)	$	467

	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 consolidated affiliates		2,243			1,501			—		(3,744	)		—
Gain on sale of unconsolidated affiliate		—			6,801			—		—			6,801
Other (expense) income, net		(69,951	)		(12,692	)		3,997		(9,669	)		(88,315	)
(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	)

Condensed Consolidating Statements of Cash Flows

Condensed Consolidating Statements of Cash Flows

	Year ended December 31, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(126,782	)	$	410,762		$	137,961		$	(7,243	)	$	414,698
Cash flows from investing activities:
Restricted cash		—			—			2,006			—			2,006
Capital expenditures		(789	)		(162,517	)		(399,992	)		12,017			(551,281	)
Acquisitions		—			(230,728	)		—			—			(230,728	)
Equity investments		(47,295	)		(252,367	)		—			299,662			—
Distributions from consolidated affiliates		50,718			68,651			—			(119,369	)		—
Investment in intercompany notes, net		(37,990	)		—			—			37,990			—
Proceeds from disposal of property, plant and equipment		—			606			7,617			(4,773	)		3,450
Net cash flows used in investing activities		(35,356	)		(576,355	)		(390,369	)		225,527			(776,553	)
Cash flows from financing activities:
Proceeds from revolving credit facility		1,182,200			—			—			—			1,182,200
Payments of revolving credit facility		(1,116,200	)		—			—			—			(1,116,200	)
Proceeds from long-term debt		1,199,000			—			—			—			1,199,000
Payments of long-term debt		(693,888	)		—			—			—			(693,888	)
Payments of premiums on redemption of long-term debt		(71,377	)		—			—			—			(71,377	)
Proceeds from intercompany notes, net		—			14,990			23,000			(37,990	)		—
Payments for debt issuance costs, deferred financing costs and registration costs		(20,163	)		—			—			—			(20,163	)
Acquisition of non-controlling interest, including transaction costs		(997,601	)		—			—			—			(997,601	)
Contributions from parent, net		—			47,295			—			(47,295	)		—
Contributions to joint ventures, net		—			—			378,759			(252,367	)		126,392
Payments of SMR Liability		—			(1,875	)		—			—			(1,875	)
Proceeds from public equity offerings, net		1,095,488			—			—			—			1,095,488
Share-based payment activity		(6,354	)		1,084			—			—			(5,270	)
Payment of distributions		(218,398	)		(50,718	)		(135,537	)		119,368			(285,285	)
Intercompany advances, net		(190,547	)		190,547			—			—			—
Net cash flows provided by financing activities		162,160			201,323			266,222			(218,284	)		411,421
Net increase in cash		22			35,730			13,814			—			49,566
Cash and cash equivalents at beginning of year		—			63,850			3,600			—			67,450
Cash and cash equivalents at end of period	$	22		$	99,580		$	17,414		$	—		$	117,016

	Year ended December 31, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(102,042	)	$	373,483		$	46,852		$	(5,965	)	$	312,328
Cash flows from investing activities:
Restricted cash		—			—			(28,001	)		—			(28,001	)
Capital expenditures		(1,924	)		(123,005	)		(347,231	)		13,492			(458,668	)
Equity investments		(44,346	)		(171,252	)		—			215,598			—
Distributions from consolidated affiliates		41,167			22,246			—			(63,413	)		—
Collection of intercompany notes, net		12,350			—			—			(12,350	)		—
Proceeds from disposal of property, plant and equipment		—			733			7,527			(7,527	)		733
Net cash flows provided by (used in) investing activities		7,247			(271,278	)		(367,705	)		145,800			(485,936	)
Cash flows from financing activities:
Proceeds from revolving credit facility		494,404			—			—			—			494,404
Payments of revolving credit facility		(553,704	)		—			—			—			(553,704	)
Proceeds from long-term debt		500,000			—			—			—			500,000
Payments of long-term debt		(375,000	)		—			—			—			(375,000	)
Payments of premiums on redemption of long-term debt		(9,732	)		—			—			—			(9,732	)
Payments of intercompany notes, net		—			(12,350	)		—			12,350			—
Payments for debt issuance costs, deferred financing costs and registration costs		(20,912	)		—			—			—			(20,912	)
Contributions from parent, net		—			44,346			—			(44,346	)		—
Contributions to joint ventures, net		—			—			329,545			(171,252	)		158,293
Payments of SMR Liability		—			(1,354	)		—			—			(1,354	)
Proceeds from public equity offering, net		142,255			—			—			—			142,255
Share-based payment activity		(3,834	)		98			—			—			(3,736	)
Payment of distributions		(181,058	)		(41,167	)		(28,396	)		63,413			(187,208	)
Intercompany advances, net		102,376			(102,376	)		—			—			—
Net cash flows provided by (used in) financing activities		94,795			(112,803	)		301,149			(139,835	)		143,306
Net decrease in cash		—			(10,598	)		(19,704	)		—			(30,302	)
Cash and cash equivalents at beginning of year		—			74,448			23,304			—			97,752
Cash and cash equivalents at end of period	$	—		$	63,850		$	3,600		$	—		$	67,450

	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, net		21,340			—			—			(21,340	)		—
Proceeds from 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 investing activities		(18,722	)		(218,289	)		(281,285	)		56,543			(461,753	)
Cash flows from financing activities:
Proceeds from revolving credit facility		725,200			—			—			—			725,200
Payments of revolving credit facility		(850,600	)		—			—			—			(850,600	)
Proceeds from long-term debt		117,000			—			—			—			117,000
Payments of intercompany notes, net		—			(21,340	)		—			21,340			—
Payments for debt issuance costs, deferred financing costs and registration costs		(8,054	)		(500	)		—			—			(8,554	)
Contributions from parent, 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 period	$	—		$	74,448		$	23,304		$	—		$	97,752

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Impairment of Long-Lived Assets (Details) (USD $)	12 Months Ended
	Dec. 31, 2009
Impairment of Long-Lived Assets
Impairment of long-lived assets	$ 5,855,000
Increase in net loss attributable to the Partnership due to impairment of long-lived assets	$ 2,900,000

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Income Taxes (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current income tax expense:
Federal	$ 15,039,000	$ 5,850,000	$ 6,525,000
State	2,539,000	1,805,000	1,547,000
Total current	17,578,000	7,655,000	8,072,000
Deferred income tax (benefit) expense:
Federal	(4,732,000)	(3,870,000)	(43,409,000)
State	803,000	(596,000)	(6,679,000)
Total deferred	(3,929,000)	(4,466,000)	(50,088,000)
Total provision for income tax	13,649,000	3,189,000	(42,016,000)
Income Tax
Income before provision for income tax	119,894,000	34,291,000	(155,370,000)
Federal statutory income tax rate (as a percent)	35.00%	35.00%	35.00%
Federal income tax at statutory rate	1,335,000	(2,842,000)	(39,377,000)
Permanent items	36,000	20,000	1,000
State income taxes net of federal benefit	2,844,000	1,027,000	(5,625,000)
Current year change in valuation allowance	(64,000)	(1,022,000)	1,562,000
Prior period adjustments and tax rate changes	163,000	70,000	1,497,000
Provision on income from Class A units	9,323,000	5,753,000	(525,000)
Write-off of deferred income tax assets			293,000
Other	12,000	183,000	158,000
Provision for income tax	13,649,000	3,189,000	(42,016,000)
Current deferred tax assets
Accruals and reserves	78,000	64,000
Derivative instruments	14,807,000	16,031,000
Current deferred tax assets	14,885,000	16,095,000
Current deferred tax liabilities
Derivative instruments		16,000
Current subtotal	14,885,000	16,079,000
Long-term deferred tax assets
Accruals and reserves	48,000	34,000
Derivative instruments	20,301,000	14,241,000
Phantom unit compensation	2,103,000	1,684,000
Capital loss carryforward	971,000	975,000
State net operating loss carryforward	101,000	156,000
Long-term deferred tax assets	23,524,000	17,090,000
Valuation allowance	(977,000)	(1,036,000)
Net long-term deferred tax assets	22,547,000	16,054,000
Long-term deferred tax liabilities
Property, plant and equipment and intangibles	2,123,000	3,529,000
Phantom unit compensation		31,000
Investment in affiliated groups	114,088,000	100,345,000
Derivative instruments		30,000
Long-term deferred tax liabilities	116,211,000	103,935,000
Long-term subtotal	(93,664,000)	(87,881,000)
Net deferred tax liabilitiy	(78,779,000)	(71,802,000)
Corporation
Deferred income tax (benefit) expense:
Total provision for income tax	10,907,000	1,890,000	(40,577,000)
Income Tax
Income before provision for income tax	3,813,000	(8,120,000)	(112,506,000)
Federal statutory income tax rate (as a percent)	35.00%	35.00%	35.00%
Federal income tax at statutory rate	1,335,000	(2,842,000)	(39,377,000)
Permanent items	36,000	20,000	1,000
State income taxes net of federal benefit	102,000	(272,000)	(4,186,000)
Current year change in valuation allowance	(64,000)	(1,022,000)	1,562,000
Prior period adjustments and tax rate changes	163,000	70,000	1,497,000
Provision on income from Class A units	9,323,000	5,753,000	(525,000)
Write-off of deferred income tax assets			293,000
Other	12,000	183,000
Provision for income tax	10,907,000	1,890,000	(40,577,000)
Long-term deferred tax liabilities
State net operating loss carryforwards	100,000
Valuation allowance as a percentage of long-term deferred tax asset attributable to state net operating losses	100.00%
Capital loss carryforward	1,000,000
Valuation allowance as a percentage of long-term deferred tax asset attributable to capital loss carryforwards	100.00%
Partnership
Deferred income tax (benefit) expense:
Total provision for income tax	2,742,000	1,299,000	(1,439,000)
Income Tax
Income before provision for income tax	124,087,000	47,761,000	(32,800,000)
Federal statutory income tax rate (as a percent)	0.00%	0.00%	0.00%
State income taxes net of federal benefit	2,742,000	1,299,000	(1,439,000)
Provision for income tax	2,742,000	1,299,000	(1,439,000)
Eliminations
Income Tax
Income before provision for income tax	$ (8,006,000)	$ (5,350,000)	$ (10,064,000)
Federal statutory income tax rate (as a percent)	0.00%	0.00%	0.00%

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Commitments and Contingencies (Details) (USD $)	12 Months Ended			1 Months Ended				12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Jan. 31, 2012 Legal- Notice of Probable Violation and proposed Civil penalty Corporation	Mar. 31, 2011 Legal- Notice of Probable Violation and proposed Civil penalty Equitable Production Company violation	Mar. 31, 2011 Legal- Notice of Probable Violation and proposed Civil penalty Equitable Production Company Corporation violation	Dec. 31, 2011 Legal- Notice of Probable Violation and proposed Civil penalty Equitable Production Company Corporation violation	Dec. 31, 2011 Contract Contingencies
Commitments and Contingencies
Actual number of counts of violations of applicable regulations							6
Proposed civil penalty							$ 1,100,000
Actual number of counts for which order assessing penalty received					1	4
Penalty assessed					500,000
Penalty amount related to the proposed dismissal of count				200,000		200,000
Charges if milestones are not achieved								1,000,000
Annual expense under non-cancelable operating lease agreements and long-term propane storage agreement	15,000,000	18,400,000	18,600,000
Minimum future payments under non-cancelable operating lease agreements and long-term propane storage agreement
2012	10,299,000
2013	8,688,000
2014	7,793,000
2015	7,606,000
2016	7,334,000
2017 and thereafter	17,663,000
Total minimum future payments	59,383,000
SMR Product Supply Agreement, Future Minimum Payments, Net Minimum Payments
2012	17,412,000
2013	17,412,000
2014	17,412,000
2015	17,412,000
2016	17,412,000
2017 and thereafter	230,029,000
Total minimum payments	317,089,000
Less: Services element	121,295,000
Less: Interest	101,885,000
Total SMR Liability	93,909,000	95,784,000
Less: Current portion of SMR Liability	2,058,000
Long-term portion of SMR Liability	$ 91,851,000

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Earnings (Loss) Per Common Unit (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Earnings (Loss) Per Common Unit
Net income (loss) attributable to the Partnership	$ (74,085)	$ 140,312	$ 78,497	$ (84,029)	$ (54,109)	$ (27,151)	$ 60,217	$ 21,510	$ 60,695	$ 467	$ (118,668)
Less: Income allocable to phantom units									1,749	1,308	1,518
Income (loss) available for common unitholders									$ 58,946	$ (841)	$ (120,186)
Weighted average common units outstanding-basic (in units)									78,466	70,128	60,957
Effect of dilutive instruments (in units)									153
Weighted average common units outstanding-diluted (in units)									78,619	70,128	60,957
Net income (loss) attributable to the Partnership's common unitholders
Basic (in dollars per unit)	$ (0.87)	$ 1.77	$ 1.03	$ (1.13)	$ (0.76)	$ (0.39)	$ 0.84	$ 0.32	$ 0.75	$ (0.01)	$ (1.97)
Diluted (in dollars per unit)	$ (0.87)	$ 1.77	$ 1.03	$ (1.13)	$ (0.76)	$ (0.39)	$ 0.84	$ 0.32	$ 0.75	$ (0.01)	$ (1.97)
Anti-dilutive units (in units)										195

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Accrued Liabilities and Other Long-Term Liabilities (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accrued liabilities
Accrued property, plant and equipment	$ 87,098	$ 65,908
Interest	27,458	26,607
Product and operations	22,969	31,241
Employee compensation	12,600	9,167
Taxes (other than income tax)	9,914	8,670
Other	11,412	12,276
Total accrued liabilities	171,451	153,869
Other long-term liabilities
SMR Liability	91,851	93,909
Deferred revenue	19,383	4,018
Asset retirement obligation	6,818	4,029	2,877
Other	3,304	3,393
Total other long-term liabilities	$ 121,356	$ 105,349

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Receivables (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Receivables
Trade, net	$ 221,343	$ 174,216
Other	5,218	4,993
Total receivables	$ 226,561	$ 179,209

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Lease Operations

12 Months Ended

Dec. 31, 2011

Lease Operations

Lease Operations

19. Lease Operations

        Based on the terms of certain natural gas gathering, transportation, and processing agreements, the Partnership is considered to be the lessor under several implicit operating lease arrangements in accordance with GAAP. The Partnership's primary implicit lease operations relate to a natural gas gathering agreement in the Liberty segment for which it earns a fixed-fee for providing gathering services to a single producer using a dedicated gathering system. As the gathering system is expanded the fixed-fee charged to the producer is adjusted to include the additional gathering assets in the lease. The primary term of the natural gas gathering arrangement expires in 2024 and will continue thereafter on a year to year basis until terminated by either party. Another significant implicit lease relates to natural gas processing agreement in the Northeast segment for which the Partnership earns a minimum monthly fee for providing processing services to a single producer using a dedicated processing plant. The primary term of the natural gas processing agreement expires in 2022 and may be extended at the option of the producer for up to two successive five year terms.

        The Partnership's revenue from its implicit lease arrangements, excluding executory costs, totaled approximately $67.4 million, $32.2 million and $14.9 million for the years ended December 31, 2011, 2010 and 2009, respectively. The Partnership's implicit lease arrangements do not contain any significant contingent rental provisions. The following is a schedule of minimum future rentals on the non-cancellable operating leases as of December 31, 2011 (in thousands):

Year ending December 31,
2012	$	61,081
2013		61,081
2014		61,081
2015		59,794
2016		59,794
2017 and thereafter		352,760
Total minimum future rentals	$	655,591

        The following schedule provides an analysis of the Partnership's investment in assets held for operating lease by major classes as of December 31, 2011 and 2010 (in thousands):

	December 31, 2011			December 31, 2010
Natural gas gathering and NGL transportation pipelines and facilities	$	479,567		$	264,669
Construction in progress		38,386			60,170
Property, plant and equipment		517,953			324,839
Less: accumulated depreciation		(46,006	)		(21,742	)
Total property, plant and equipment, net	$	471,947		$	303,097

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Equity (Tables)

12 Months Ended

Dec. 31, 2011

Equity

Distributions of Available Cash

Quarter Ended	Distribution Per Common Unit		Declaration Date		Record Date		Payment Date
December 31, 2011	$	0.76		January 26, 2012		February 6, 2012		February 14, 2012
September 30, 2011	$	0.73		October 18, 2011		November 7, 2011		November 14, 2011
June 30, 2011	$	0.70		July 21, 2011		August 1, 2011		August 12, 2011
March 31, 2011	$	0.67		April 21, 2011		May 2, 2011		May 13, 2011
December 31, 2010	$	0.65		January 27, 2011		February 7, 2011		February 14, 2011
September 30, 2010	$	0.64		October 27, 2010		November 8, 2010		November 12, 2010
June 30, 2010	$	0.64		July 22, 2010		August 2, 2010		August 13, 2010
March 31, 2010	$	0.64		April 22, 2010		May 3, 2010		May 14, 2010
December 31, 2009	$	0.64		January 26, 2010		February 5, 2010		February 12, 2010
September 30, 2009	$	0.64		October 22, 2009		November 2, 2009		November 13, 2009
June 30, 2009	$	0.64		July 23, 2009		August 3, 2009		August 14, 2009
March 31, 2009	$	0.64		April 23, 2009		May 4, 2009		May 15, 2009

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Fair Value (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value

Derivative instruments carried at fair value

As of December 31, 2011	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	5,063	$	(79,358	)
Significant unobservable inputs (Level 3)
Commodity contracts		12,210		(15,175	)
Embedded derivatives in commodity contracts		7,517		(61,421	)
Total carrying value in Consolidated Balance Sheet	$	24,790	$	(155,954	)

As of December 31, 2010	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	52	$	(77,776	)
Significant unobservable inputs (Level 3)
Commodity contracts		3,674		(18,031	)
Embedded derivatives in commodity contracts		1,036		(35,972	)
Total carrying value in Consolidated Balance Sheet	$	4,762	$	(131,779	)

Rollforward of the balance sheet amounts for assets and liabilities classified within Level 3 of the valuation hierarchy

	Year Ended December 31, 2011
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(14,357	)	$	(34,936	)
Total gain or loss (realized and unrealized) included in earnings(1)		3,182			(30,827	)
Settlements		8,210			11,859
Fair value at end of period	$	(2,965	)	$	(53,904	)
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at end of period	$	6,241		$	(29,556	)

	Year Ended December 31, 2010
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Interest Rate Contracts			Embedded Derivative in Debt Contract
Fair value at beginning of period	$	(11,340	)	$	(34,199	)	$	509		$	(190	)
Total gain or loss (realized and unrealized) included in earnings(1)		(11,093	)		(11,792	)		1,871			190
Purchases, sales, issuances and settlements (net)		8,076			11,055			(2,380	)		—
Fair value at end of period	$	(14,357	)	$	(34,936	)	$	—		$	—
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at December 31(1)	$	(13,101	)	$	(9,329	)	$	—		$	—

(1)

Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Derivative (loss) gain related to revenue. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Purchased product costs, Derivative loss related to purchased product costs and Derivative gain related to facility expenses. Gains on Embedded Derivative in Debt Contract are recorded in Miscellaneous income (expense), net. Gains and losses on Interest Rate Contracts are recorded in Derivative gain related to interest expense.

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Goodwill and Intangible Assets (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Intangible Assets
Gross	$ 771,935	$ 738,146
Accumulated Amortization	(168,168)	(124,568)
Net	603,767	613,578
Estimated amortization expense
2012	43,940
2013	43,940
2014	43,940
2015	43,940
2016	43,940
Thereafter	384,067
Total estimated amortization expense	603,767
Southwest Segment
Intangible Assets
Gross	406,690	406,801
Accumulated Amortization	(92,340)	(69,655)
Net	314,350	337,146
Useful Life, Minimum (in years)	10
Useful Life, Maximum (in years)	20
Northeast Segment
Intangible Assets
Gross	102,473	68,573
Accumulated Amortization	(29,037)	(19,590)
Net	73,436	48,983
Useful Life (in years)	12
Gulf Coast Segment
Intangible Assets
Gross	262,772	262,772
Accumulated Amortization	(46,791)	(35,323)
Net	$ 215,981	$ 227,449
Useful Life, Minimum (in years)	20
Useful Life, Maximum (in years)	25

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Subsequent Events (Details) (Utica Shale Joint Venture)	Dec. 31, 2011
Utica Shale Joint Venture
Subsequent events
Percentage of ownership interest held in joint venture	60.00%

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies

Schedule of the carrying value and related fair value of financial instruments that are not recorded in the financial statements at fair value

	December 31, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	1,846,062	$	1,880,710	$	1,273,434	$	1,333,875
SMR Liability		93,909		119,887		95,784		125,600

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Lease Operations (Tables)

12 Months Ended

Dec. 31, 2011

Lease Operations

Schedule of minimum future rentals on the non-cancellable operating leases

Year ending December 31,
2012	$	61,081
2013		61,081
2014		61,081
2015		59,794
2016		59,794
2017 and thereafter		352,760
Total minimum future rentals	$	655,591

Schedule provides an analysis of the Partnership's investment in assets held for operating lease by major classes

	December 31, 2011			December 31, 2010
Natural gas gathering and NGL transportation pipelines and facilities	$	479,567		$	264,669
Construction in progress		38,386			60,170
Property, plant and equipment		517,953			324,839
Less: accumulated depreciation		(46,006	)		(21,742	)
Total property, plant and equipment, net	$	471,947		$	303,097

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Derivative Financial Instruments (Details) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivative contracts not designated as hedging instruments
Fair value of derivative instruments - current assets		$ 8,698,000	$ 4,345,000
Fair value of derivative instruments - long-term assets		16,092,000	417,000
Total derivative assets		24,790,000	4,762,000	24,631,000
Fair value of derivative instruments - current liabilities		(90,551,000)	(65,489,000)
Fair value of derivative liabilities - long-term liabilities		(65,403,000)	(66,290,000)
Total derivative liabilities		(155,954,000)	(131,779,000)
Financial Statement Impact of Derivative Contracts
Unrealized gain (loss)			190,000	336,000
Total Revenue: derivative gain (loss)		(29,035,000)	(53,932,000)	(120,352,000)
Total derivative loss related to purchased product costs		(52,960,000)	(27,713,000)	(68,883,000)
Derivative gain related to facility expenses		6,480,000	1,295,000	373,000
Derivative gain related to interest expense			1,871,000	2,509,000
Total loss		(75,515,000)	(78,289,000)	(186,017,000)
Premium payments, net of amortization		0	4,400,000
Producer's option to extend successive years, number		5
Embedded derivative in natural gas processing and purchase contract
Financial Statement Impact of Derivative Contracts
Notional amount for embedded derivative in commodity contract (in Dth per day)		9,000
Estimated fair value of embedded derivative contract liability including portion allocable to host processing agreement		114,928,000
Inception value for period from April 1, 2015 to December 31, 2022		(53,507,000)
Recorded value of embedded derivative contract liability		61,421,000
Embedded derivative in electricity purchase contract
Financial Statement Impact of Derivative Contracts
Estimated fair value of embedded derivative contract asset		7,500,000	1,000,000
Derivative instruments not designated as hedging instruments
Derivative contracts not designated as hedging instruments
Fair value of derivative instruments - current assets		8,698,000	4,345,000
Fair value of derivative instruments - long-term assets		16,092,000	417,000
Total derivative assets		24,790,000	4,762,000
Fair value of derivative instruments - current liabilities		(90,551,000)	(65,489,000)
Fair value of derivative liabilities - long-term liabilities		(65,403,000)	(66,290,000)
Total derivative liabilities		(155,954,000)	(131,779,000)
Financial Statement Impact of Derivative Contracts
Notional quantity of crude oil contract (in bbl)		8,244,902
Notional quantity of natural gas contract (in MMBtu)		16,021,887
Natural Gas Liquids (gal)		86,563,841
Derivative instruments not designated as hedging instruments | Derivative revenue
Financial Statement Impact of Derivative Contracts
Realized (loss) gain		(48,093,000)	(33,560,000)	87,289,000
Unrealized gain (loss)		19,058,000	(20,372,000)	(207,641,000)
Total Revenue: derivative gain (loss)		(29,035,000)	(53,932,000)	(120,352,000)
Amortization of premium payments		4,400,000	3,300,000	5,700,000
Realized gain (loss) on early settlement	15,200,000
Realized gains on early settlement recorded in Realized (loss) gain - revenue	26,500,000
Realized gains on early settlement recorded in derivative loss related to purchased product cost	11,300,000
Derivative instruments not designated as hedging instruments | Derivative related to purchased product costs
Financial Statement Impact of Derivative Contracts
Realized (loss) gain		(27,711,000)	(21,909,000)	(53,052,000)
Unrealized gain (loss)		(25,249,000)	(5,804,000)	(15,831,000)
Total derivative loss related to purchased product costs		(52,960,000)	(27,713,000)	(68,883,000)
Derivative instruments not designated as hedging instruments | Derivative related to facility expenses
Financial Statement Impact of Derivative Contracts
Unrealized gain (loss)		6,480,000	1,295,000	373,000
Derivative instruments not designated as hedging instruments | Derivative related to interest expense
Financial Statement Impact of Derivative Contracts
Realized (loss) gain			2,380,000	2,000,000
Unrealized gain (loss)			(509,000)	509,000
Derivative gain related to interest expense			1,871,000	2,509,000
Derivative instruments not designated as hedging instruments | Miscellaneous income, net
Financial Statement Impact of Derivative Contracts
Unrealized gain			$ 190,000	$ 336,000

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Organization and Basis of Presentation (Details)	Dec. 31, 2011
Organization and Basis of Presentation
Percentage of non-controlling interest acquired by the Partnership	49.00%

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Accrued Liabilities and Other Long-Term Liabilities (Tables)

12 Months Ended

Dec. 31, 2011

Accrued Liabilities and Other Long-Term Liabilities

Schedule of accrued liabilities

	December 31, 2011		December 31, 2010
Accrued property, plant and equipment	$	87,098	$	65,908
Interest		27,458		26,607
Product and operations		22,969		31,241
Employee compensation		12,600		9,167
Taxes (other than income tax)		9,914		8,670
Other		11,412		12,276
Total accrued liabilities	$	171,451	$	153,869

Schedule of other long-term liabilities

	December 31, 2011		December 31, 2010
SMR Liability (see Note 5)	$	91,851	$	93,909
Deferred revenue		19,383		4,018
Asset retirement obligation		6,818		4,029
Other		3,304		3,393
Total other long-term liabilities	$	121,356	$	105,349

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Business Combination

12 Months Ended

Dec. 31, 2011

Business Combination

Business Combination

3. Business Combination

        On February 1, 2011, the Partnership acquired natural gas processing and NGL pipeline assets from EQT for a cash purchase price of approximately $230.7 million. The assets acquired include natural gas processing facilities located near Langley, Kentucky, consisting of a cryogenic natural gas processing plant with a capacity of approximately 100 MMcf/d and a refrigeration natural gas processing plant with a capacity of approximately 75 MMcf/d, the partially constructed Ranger pipeline that extends through parts of Kentucky and West Virginia, and certain other related assets. The acquired assets do not include certain residue gas compression and transportation facilities at the same location as the Langley Processing Facilities. This acquisition is referred to as the Langley Acquisition. In connection with the Langley Acquisition, the Partnership completed the construction of the Ranger Pipeline to connect the Langley Processing Facilities to the Partnership's existing pipeline that transports NGLs to its Siloam fractionation facility in South Shore, Kentucky.

        Concurrently with the closing of the Langley Acquisition, the Partnership entered into a long-term agreement to process certain natural gas owned or controlled by EQT at the Langley Processing Facilities. The processing agreement requires the Partnership to install an additional cryogenic natural gas processing plant with a capacity of at least 60 MMcf/d in 2012. The Partnership exchanges the NGLs produced at the Langley Processing Facilities for fractionated products from its Siloam facility and markets the fractionated products on behalf of EQT in accordance with a long-term NGL exchange and marketing agreement. As a result of the acquisition, the Partnership has significantly expanded its midstream operations in the liquids-rich gas areas of the Appalachian Basin.

        The Langley Acquisition is accounted for as a business combination. The total purchase price is allocated to the identifiable assets acquired and liabilities assumed based on the estimated fair values at the acquisition date. The remaining purchase price in excess of the fair value of the identifiable assets and liabilities is recorded as goodwill. The acquired assets and the related results of operations are included in the Partnership's Northeast segment.

        The following table summarizes the purchase price allocation for the Langley Acquisition (in thousands):

Property, plant and equipment	$	136,525
Goodwill		58,497
Intangible asset		33,900
Inventory		1,806
Total	$	230,728

        The goodwill recognized from the Langley Acquisition results primarily from the Partnership's ability to continue to grow its business in the liquids-rich gas areas of the Appalachian Basin and access additional markets in a competitive environment as a result of securing the processing rights for a large area of dedicated acreage and acquiring expanded midstream infrastructure in the acquisition. All of the goodwill is deductible for tax purposes.

        The intangible asset consists of an identifiable customer contract. The acquired intangible will be amortized on a straight-line basis over the estimated remaining customer contract useful life of approximately twelve years.

        The results of operations from the Langley Acquisition are included in the consolidated financial statements from the acquisition date. Revenue and income before provision for income tax related to the Langley Acquisition were approximately $21.8 million and $6.8 million, respectively, for the year ended December 31, 2011.

        Pro forma financial results that give effect to the Langley Acquisition are not presented as it is impracticable to obtain the necessary information. EQT did not operate the acquired assets as a stand-alone business and, therefore, historical financial information that is consistent with the operations under the current agreements is not available.

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Summary of Significant Accounting Policies (Details)	12 Months Ended
	Dec. 31, 2011 month
Minimum
Property, Plant and Equipment
Threshold relocation cost of tangible assets as percentage of fair value to be classified as real estate (as a percent)	10.00%
Restricted Cash
Threshold period for project completion for which restricted cash is held to classify as long-term asset (in months)	12
Maximum
Cash and Cash Equivalents
Threshold period of original maturity of investments to be considered as cash equivalents (in days)	90
Property, plant and equipment other than miscellaneous equipment and vehicles
Property, Plant and Equipment
Estimated useful lives of assets, minimum (in years)	20
Estimated useful lives of assets, maximum (in years)	25
Miscellaneous equipment and vehicles
Property, Plant and Equipment
Estimated useful lives of assets, minimum (in years)	3
Estimated useful lives of assets, maximum (in years)	10

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Receivables (Tables)

12 Months Ended

Dec. 31, 2011

Receivables

Summary of receivables

	December 31, 2011		December 31, 2010
Trade, net	$	221,343	$	174,216
Other		5,218		4,993
Total receivables	$	226,561	$	179,209

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Earnings (Loss) Per Common Unit

12 Months Ended

Dec. 31, 2011

Earnings (Loss) Per Common Unit

Earnings (Loss) Per Common Unit

23. Earnings (Loss) Per Common Unit

        The following table shows the computation of basic and diluted net (loss) income per common unit, for the years ended December 31, 2011, 2010 and 2009, respectively, and the weighted average units used to compute diluted net (loss) income per common unit (in thousands, except per unit data):

	Year ended December 31,
	2011(2)		2010			2009
Net income (loss) attributable to the Partnership	$	60,695	$	467		$	(118,668	)
Less: Income allocable to phantom units		1,749		1,308			1,518
Income (loss) available for common unitholders	$	58,946	$	(841	)	$	(120,186	)
Weighted average common units outstanding—basic		78,466		70,128			60,957
Effect of dilutive instruments(1)		153		—			—
Weighted average common units outstanding—diluted		78,619		70,128			60,957
Net income (loss) attributable to the Partnership's common unitholders per common unit:
Basic	$	0.75	$	(0.01	)	$	(1.97	)
Diluted	$	0.75	$	(0.01	)	$	(1.97	)

(1)

For the years ended December 31, 2011 and 2010, dilutive instruments include TSR Phantom Units and are based on the number of units, if any, that would be issuable at the end of the respective reporting period, assuming that date was the end of the contingency period. For the year ended December 31, 2010, 195 units were excluded from the calculation of diluted units because the impact was anti-dilutive. See Note 20 for further discussion of TSR Phantom Units.

(2)

The Class B units had no impact to the earnings per unit calculation as they were issued on December 31, 2011 and as such were not outstanding for any portion of the fiscal year and were not allocated any of the Net income (loss) attributable to the Partnership.

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Income Tax

12 Months Ended

Dec. 31, 2011

Income Tax

Income Tax

22. Income Tax

        As discussed in Note 2, all changes in the tax bases of assets and liabilities are allocated among continued operations and items charged or credited directly to equity. During the fourth quarter of 2011, the Partnership determined it had understated its deferred tax liability related to its investment in consolidated subsidiaries for timing differences created as a result of items charged or credited directly to equity. The Partnership evaluated the materiality of the error from a qualitative and quantitative perspective and concluded that the error was not material to any prior period.

        In the accompanying Consolidated Balance Sheet as of December 31, 2010, the correction of the error discussed above results in an increase in long-term deferred tax liabilities and a corresponding decrease in equity of $77.5 million as compared to the amounts previously reported. In the accompanying Consolidated Statement of Changes in Equity, the correction resulted in a cumulative decrease in the balances associated with common units and total equity of $77.5 million, $69.8 million, and $59.6 million as of December 31, 2010, 2009, and 2008, respectively. This cumulative adjustment gives effect to the Deferred tax impact of equity transactions, which was previously not reported, of $7.6 million and $10.2 million for the years ended December 31, 2010 and 2009, respectively.

        The components of the provision for income tax expense (benefit) are as follows (in thousands):

	Year ended December 31,
	2011			2010			2009
Current income tax expense:
Federal	$	15,039		$	5,850		$	6,525
State		2,539			1,805			1,547
Total current		17,578			7,655			8,072
Deferred income tax (benefit) expense:
Federal		(4,732	)		(3,870	)		(43,409	)
State		803			(596	)		(6,679	)
Total deferred		(3,929	)		(4,466	)		(50,088	)
Provision for income tax	$	13,649		$	3,189		$	(42,016	)

        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, 2011, 2010 and 2009 is as follows (in thousands):

Year ended December 31, 2011:

	Corporation			Partnership			Eliminations			Consolidated
Income before provision for income tax.	$	3,813		$	124,087		$	(8,006	)	$	119,894
Federal statutory rate		35	%		0	%		0	%
Federal income tax at statutory rate		1,335			—			—			1,335
Permanent items		36			—			—			36
State income taxes net of federal benefit		102			2,742			—			2,844
Current year change in valuation allowance		(64	)		—			—			(64	)
Prior period adjustments and tax rate changes		163			—			—			163
Provision on income from Class A units(1)		9,323			—			—			9,323
Other		12			—			—			12
Provision for income tax	$	10,907		$	2,742		$	—		$	13,649

Year ended December 31, 2010:

	Corporation			Partnership			Eliminations			Consolidated
(Loss) income before provision for income tax	$	(8,120	)	$	47,761		$	(5,350	)	$	34,291
Federal statutory rate		35	%		0	%		0	%
Federal income tax at statutory rate		(2,842	)		—			—			(2,842	)
Permanent items		20			—			—			20
State income taxes net of federal benefit		(272	)		1,299			—			1,027
Current year change in valuation allowance		(1,022	)		—			—			(1,022	)
Prior period adjustments and tax rate changes		70			—			—			70
Provision on income from Class A units(1)		5,753			—			—			5,753
Other		183			—			—			183
Provision for income tax	$	1,890		$	1,299		$	—		$	3,189

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	$	(40,577	)	$	(1,439	)	$	—		$	(42,016	)

(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. This amount includes intra period allocations to continued operations and excludes allocations to equity.

        The deferred tax assets and liabilities resulting from temporary book-tax differences are comprised of the following (in thousands):

	December 31,
	2011			2010
Current deferred tax assets:
Accruals and reserves	$	78		$	64
Derivative instruments		14,807			16,031
Current deferred tax assets		14,885			16,095
Current deferred tax liabilities:
Derivative instruments		—			16
Current deferred tax liabilities		—			16
Current subtotal		14,885			16,079
Long-term deferred tax assets:
Accruals and reserves		48			34
Derivative instruments		20,301			14,241
Phantom unit compensation		2,103			1,684
Capital loss carryforward		971			975
State net operating loss carryforward		101			156
Long-term deferred tax assets		23,524			17,090
Valuation allowance		(977	)		(1,036	)
Net long-term deferred tax assets		22,547			16,054
Long-term deferred tax liabilities:
Property, plant and equipment and intangibles		2,123			3,529
Phantom unit compensation		—			31
Investment in affiliated groups		114,088			100,345
Derivative instruments		—			30
Long-term deferred tax liabilities		116,211			103,935
Long-term subtotal		(93,664	)		(87,881	)
Net deferred tax liability	$	(78,779	)	$	(71,802	)

        Significant judgment is required in evaluating tax positions and determining the Corporation's provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. However, the Corporation did not have any material uncertain tax positions for the years ended December 31, 2011, 2010 or 2009. As of December 31, 2011, the Corporation had state net operating loss carryforwards of approximately $0.1 million that expire between 2024 and 2027. 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, 2011, the Corporation had a capital loss carryforward of approximately $1.0 million that expires in 2014. The Corporation does not anticipate utilizing this carryforward and has provided a 100% valuation allowance against this long-term deferred tax asset. While the Corporation's consolidated federal tax return and any significant state tax returns are not currently under examination, the tax years 2007 through 2010 remain open to examination by the major taxing jurisdictions to which the Corporation is subject.

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2011

Segment Information

Schedule of operating income and capital expenditures of geographical segments

Year ended December 31, 2011:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	935,513	$	268,884	$	248,949	$	96,473	$	1,549,819
Purchased product costs		506,911		91,612		83,847		—		682,370
Net operating margin		428,602		177,272		165,102		96,473		867,449
Facility expenses		82,761		27,126		34,913		38,436		183,236
Portion of operating income attributable to non-controlling interests		5,431		—		63,731		—		69,162
Operating income before items not allocated to segments	$	340,410	$	150,146	$	66,458	$	58,037	$	615,051
Capital expenditures	$	103,968	$	51,280	$	388,850	$	2,093	$	546,191
Capital expenditures not allocated to segment										5,090
Total capital expenditures									$	551,281

Year ended December 31, 2010:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	665,768	$	384,724	$	105,911	$	85,160	$	1,241,563
Purchased product costs		308,960		252,827		16,840		—		578,627
Net operating margin		356,808		131,897		89,071		85,160		662,936
Facility expenses		81,772		19,513		24,028		33,337		158,650
Portion of operating income attributable to non-controlling interests		6,440		—		26,126		—		32,566
Operating income before items not allocated to segments	$	268,596	$	112,384	$	38,917	$	51,823	$	471,720
Capital expenditures	$	114,109	$	2,179	$	332,793	$	3,947	$	453,028
Capital expenditures not allocated to segments										5,640
Total capital expenditures									$	458,668

Year ended December 31, 2009:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	492,369	$	260,529	$	47,968	$	57,769	$	858,635
Purchased product costs		221,021		175,326		12,479		—		408,826
Net operating margin		271,348		85,203		35,489		57,769		449,809
Facility expenses		73,621		20,339		16,268		16,094		126,322
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

Reconciliation of segment revenue total revenue and operating income to before items not allocated to segments to (loss) income before provision for income tax

	Year ended December 31,
	2011			2010			2009
Total segment revenue	$	1,549,819		$	1,241,563		$	858,635
Derivative loss not allocated to segments		(29,035	)		(53,932	)		(120,352	)
Revenue deferral adjustment(1)		(15,385	)		—			—
Total revenue	$	1,505,399		$	1,187,631		$	738,283
Operating income before items not allocated to segments	$	615,051		$	471,720		$	314,237
Portion of operating income attributable to non-controlling interests		69,162			32,566			9,250
Derivative loss not allocated to segments		(75,515	)		(80,350	)		(188,862	)
Revenue deferral adjustment(1)		(15,385	)		—			—
Compensation expense included in facility expenses not allocated to segments		(1,781	)		(1,890	)		(1,032	)
Facility expenses adjustments(2)		11,419			9,091			377
Selling, general and administrative expenses		(81,229	)		(75,258	)		(63,728	)
Depreciation		(149,954	)		(123,198	)		(95,537	)
Amortization of intangible assets		(43,617	)		(40,833	)		(40,831	)
Loss on disposal of property, plant and equipment		(8,797	)		(3,149	)		(1,677	)
Accretion of asset retirement obligations		(1,190	)		(237	)		(198	)
Impairment of goodwill and long-lived assets		—			—			(5,855	)
Income (loss) from operations		318,164			188,462			(73,856	)
(Loss) earnings from unconsolidated affiliates		(1,095	)		1,562			3,505
Gain on sale of unconsolidated affiliate		—			—			6,801
Interest income		422			1,670			349
Interest expense		(113,631	)		(103,873	)		(87,419	)
Amortization of deferred financing costs and discount (a component of interest expense)		(5,114	)		(10,264	)		(9,718	)
Derivative gain related to interest expense		—			1,871			2,509
Loss on redemption of debt		(78,996	)		(46,326	)		—
Miscellaneous income, net		144			1,189			2,459
Income (loss) before provision for income tax	$	119,894		$	34,291		$	(155,370	)

(1)

Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership expects to perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and, therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the year ended December 31, 2011, approximately $7.2 million and $8.2 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts is expected to decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

(2)

Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR, which is included in facility expenses for the purposes of evaluating the performance of the Gulf Coast segment. The increase is due to a full year of interest expense related to the SMR in 2011 compared to approximately nine months of SMR interest expense in 2010.

Segment assets information

	December 31, 2011		December 31, 2010		December 31, 2009
Southwest	$	1,701,919	$	1,646,607	$	1,637,749
Northeast		533,591		244,219		249,804
Liberty		1,114,654		743,943		373,127
Gulf Coast		553,043		573,456		587,830
Total segment assets		3,903,207		3,208,225		2,848,510
Assets not allocated to segments:
Certain cash and cash equivalents		66,212		49,776		73,184
Fair value of derivatives		24,790		4,762		24,631
Investment in unconsolidated affiliate		27,853		28,688		29,633
Other(1)		48,363		41,911		38,779
Total assets	$	4,070,425	$	3,333,362	$	3,014,737

(1)

As of December 31, 2011, includes corporate fixed assets, deferred financing costs, income tax receivable, deferred tax asset and other corporate assets not allocated to segments. As of December 31, 2010 and 2009, includes corporate fixed assets, deferred financing costs, income tax receivable, receivables and other corporate assets not allocated to segments.

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Inventories (Tables)

12 Months Ended

Dec. 31, 2011

Inventories

Components of inventory

	December 31, 2011		December 31, 2010
NGLs	$	32,352	$	15,930
Spare parts, materials and supplies		8,654		7,502
Total inventories	$	41,006	$	23,432

XML

Segment Information

12 Months Ended

Dec. 31, 2011

Segment Information

Segment Information

24. 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 the following segments: Southwest, Northeast, Liberty and Gulf Coast. The Southwest segment provides gathering, processing, transportation and storage services. The Northeast segment provides gathering, processing, transportation, fractionation and storage services. The Liberty segment provides gathering, processing, transportation, fractionation and storage services. The Gulf Coast segment provides processing, transportation, fractionation and storage services.

        The Partnership prepares segment information in accordance with GAAP. Certain items below Income (loss) from operations in the accompanying Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any gains (losses) from derivative instruments are not allocated to individual segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. 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, 2011, 2010 and 2009 (in thousands).

Year ended December 31, 2011:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	935,513	$	268,884	$	248,949	$	96,473	$	1,549,819
Purchased product costs		506,911		91,612		83,847		—		682,370
Net operating margin		428,602		177,272		165,102		96,473		867,449
Facility expenses		82,761		27,126		34,913		38,436		183,236
Portion of operating income attributable to non-controlling interests		5,431		—		63,731		—		69,162
Operating income before items not allocated to segments	$	340,410	$	150,146	$	66,458	$	58,037	$	615,051
Capital expenditures	$	103,968	$	51,280	$	388,850	$	2,093	$	546,191
Capital expenditures not allocated to segment										5,090
Total capital expenditures									$	551,281

Year ended December 31, 2010:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	665,768	$	384,724	$	105,911	$	85,160	$	1,241,563
Purchased product costs		308,960		252,827		16,840		—		578,627
Net operating margin		356,808		131,897		89,071		85,160		662,936
Facility expenses		81,772		19,513		24,028		33,337		158,650
Portion of operating income attributable to non-controlling interests		6,440		—		26,126		—		32,566
Operating income before items not allocated to segments	$	268,596	$	112,384	$	38,917	$	51,823	$	471,720
Capital expenditures	$	114,109	$	2,179	$	332,793	$	3,947	$	453,028
Capital expenditures not allocated to segments										5,640
Total capital expenditures									$	458,668

Year ended December 31, 2009:

	Southwest		Northeast		Liberty		Gulf Coast		Total
Segment revenue	$	492,369	$	260,529	$	47,968	$	57,769	$	858,635
Purchased product costs		221,021		175,326		12,479		—		408,826
Net operating margin		271,348		85,203		35,489		57,769		449,809
Facility expenses		73,621		20,339		16,268		16,094		126,322
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

        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, 2011, 2010 and 2009 (in thousands):

	Year ended December 31,
	2011			2010			2009
Total segment revenue	$	1,549,819		$	1,241,563		$	858,635
Derivative loss not allocated to segments		(29,035	)		(53,932	)		(120,352	)
Revenue deferral adjustment(1)		(15,385	)		—			—
Total revenue	$	1,505,399		$	1,187,631		$	738,283
Operating income before items not allocated to segments	$	615,051		$	471,720		$	314,237
Portion of operating income attributable to non-controlling interests		69,162			32,566			9,250
Derivative loss not allocated to segments		(75,515	)		(80,350	)		(188,862	)
Revenue deferral adjustment(1)		(15,385	)		—			—
Compensation expense included in facility expenses not allocated to segments		(1,781	)		(1,890	)		(1,032	)
Facility expenses adjustments(2)		11,419			9,091			377
Selling, general and administrative expenses		(81,229	)		(75,258	)		(63,728	)
Depreciation		(149,954	)		(123,198	)		(95,537	)
Amortization of intangible assets		(43,617	)		(40,833	)		(40,831	)
Loss on disposal of property, plant and equipment		(8,797	)		(3,149	)		(1,677	)
Accretion of asset retirement obligations		(1,190	)		(237	)		(198	)
Impairment of goodwill and long-lived assets		—			—			(5,855	)
Income (loss) from operations		318,164			188,462			(73,856	)
(Loss) earnings from unconsolidated affiliates		(1,095	)		1,562			3,505
Gain on sale of unconsolidated affiliate		—			—			6,801
Interest income		422			1,670			349
Interest expense		(113,631	)		(103,873	)		(87,419	)
Amortization of deferred financing costs and discount (a component of interest expense)		(5,114	)		(10,264	)		(9,718	)
Derivative gain related to interest expense		—			1,871			2,509
Loss on redemption of debt		(78,996	)		(46,326	)		—
Miscellaneous income, net		144			1,189			2,459
Income (loss) before provision for income tax	$	119,894		$	34,291		$	(155,370	)

(1)

Amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership expects to perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and, therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the year ended December 31, 2011, approximately $7.2 million and $8.2 million of the revenue deferral adjustment is attributable to the Southwest segment and Northeast segment, respectively. Beginning in 2015, the cash consideration received from these contracts is expected to decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes.

(2)

Facility expenses adjustments consist of the reallocation of the MarkWest Pioneer field services fee and the reallocation of the interest expense related to the SMR, which is included in facility expenses for the purposes of evaluating the performance of the Gulf Coast segment. The increase is due to a full year of interest expense related to the SMR in 2011 compared to approximately nine months of SMR interest expense in 2010.

        The tables below present information about segment assets as of December 31, 2011, 2010, and 2009 (in thousands):

	December 31, 2011		December 31, 2010		December 31, 2009
Southwest	$	1,701,919	$	1,646,607	$	1,637,749
Northeast		533,591		244,219		249,804
Liberty		1,114,654		743,943		373,127
Gulf Coast		553,043		573,456		587,830
Total segment assets		3,903,207		3,208,225		2,848,510
Assets not allocated to segments:
Certain cash and cash equivalents		66,212		49,776		73,184
Fair value of derivatives		24,790		4,762		24,631
Investment in unconsolidated affiliate		27,853		28,688		29,633
Other(1)		48,363		41,911		38,779
Total assets	$	4,070,425	$	3,333,362	$	3,014,737

(1)

As of December 31, 2011, includes corporate fixed assets, deferred financing costs, income tax receivable, deferred tax asset and other corporate assets not allocated to segments. As of December 31, 2010 and 2009, includes corporate fixed assets, deferred financing costs, income tax receivable, receivables and other corporate assets not allocated to segments.

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Supplemental Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2011

Supplemental Condensed Consolidating Financial Information

Supplemental Condensed Consolidating Financial Information

25. Supplemental Condensed Consolidating Financial Information

        MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of December 31, 2011, the Partnership's obligations under the outstanding Senior Notes (see Note 16) were fully, jointly and severally guaranteed, by all of its wholly-owned subsidiaries other than MarkWest Liberty Midstream. The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the guarantee under the indentures. 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. Condensed consolidating financial information for MarkWest Energy Partners and its combined guarantor and combined non-guarantor subsidiaries as of December 31, 2011 and 2010 and for the years ended December 31, 2011, 2010 and 2009 is as follows (in thousands):

Condensed Consolidating Balance Sheets

	As of December 31, 2011
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	22	$	99,580	$	17,414	$	—		$	117,016
Restricted cash		—		—		26,193		—			26,193
Receivables and other current assets		7,097		232,010		55,098		(5	)		294,200
Intercompany receivables		19,981		40,519		22,193		(82,693	)		—
Fair value of derivative instruments		—		8,015		683		—			8,698
Total current assets		27,100		380,124		121,581		(82,698	)		446,107
Total property, plant and equipment, net		4,012		1,714,857		1,163,226		(17,788	)		2,864,307
Other long-term assets:
Investment in unconsolidated affiliate		—		27,853		—		—			27,853
Investment in consolidated affiliates		3,071,124		1,097,350		—		(4,168,474	)		—
Intangibles, net of accumulated amortization		—		603,224		543		—			603,767
Fair value of derivative instruments		—		16,092		—		—			16,092
Intercompany notes receivable		235,700		—		—		(235,700	)		—
Other long-term assets		41,492		70,434		373		—			112,299
Total assets(1)	$	3,379,428	$	3,909,934	$	1,285,723	$	(4,504,660	)	$	4,070,425
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	40,503	$	40,374	$	1,816	$	(82,693	)	$	—
Fair value of derivative instruments		—		90,551		—		—			90,551
Other current liabilities		38,775		219,622		92,930		(5	)		351,322
Total current liabilities		79,278		350,547		94,746		(82,698	)		441,873
Deferred income taxes		1,228		92,436		—		—			93,664
Intercompany notes payable		—		212,700		23,000		(235,700	)		—
Fair value of derivative instruments		—		65,403		—		—			65,403
Long-term debt, net of discounts		1,846,062		—		—		—			1,846,062
Other long-term liabilities		3,232		117,724		400		—			121,356
Equity:
Common Units		697,097		3,071,124		1,167,577		(4,256,489	)		679,309
Class B Units		752,531		—		—		—			752,531
Non-controlling interest in consolidated subsidiaries		—		—		—		70,227			70,227
Total equity		1,449,628		3,071,124		1,167,577		(4,186,262	)		1,502,067
Total liabilities and equity	$	3,379,428	$	3,909,934	$	1,285,723	$	(4,504,660	)	$	4,070,425

(1)

In accordance with the December 2011 amendment to the Partnership's Credit Facility, certain assets in the Liberty segment included in Total property, plant, and equipment, net are expected to be contributed from a non-guarantor subsidiary to a guarantor subsidiary by April 2012. The contributed assets would include only the natural gas processing facilities at the Partnership's Houston Complex and any other equipment related solely to these processing facilities.

	As of December 31, 2010
	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	63,850	$	3,600	$	—		$	67,450
Receivables and other current assets		1,708		172,209		52,834		—			226,751
Intercompany receivables		1,440,302		1,099		7,635		(1,449,036	)		—
Fair value of derivative instruments		—		4,345		—		—			4,345
Total current assets		1,442,010		241,503		64,069		(1,449,036	)		298,546
Total property, plant and equipment, net		4,623		1,512,763		812,898		(11,260	)		2,319,024
Other long-term assets:
Restricted cash		—		—		28,001		—			28,001
Investment in unconsolidated affiliate		—		28,688		—		—			28,688
Investment in consolidated affiliates		639,219		368,864		—		(1,008,083	)		—
Intangibles, net of accumulated amortization		—		613,000		578		—			613,578
Fair value of derivative instruments		—		417		—		—			417
Intercompany notes receivable		197,710		—		—		(197,710	)		—
Other long-term assets		32,587		12,139		382		—			45,108
Total assets	$	2,316,149	$	2,777,374	$	905,928	$	(2,666,089	)	$	3,333,362
LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	672	$	1,447,799	$	565	$	(1,449,036	)	$	—
Fair value of derivative instruments		—		65,489		—		—			65,489
Other current liabilities		31,882		173,667		70,804		—			276,353
Total current liabilities		32,554		1,686,955		71,369		(1,449,036	)		341,842
Deferred income taxes		2,533		85,348		—		—			87,881
Intercompany notes payable		—		197,710		—		(197,710	)		—
Fair value of derivative instruments		—		66,290		—		—			66,290
Long-term debt, net of discounts		1,273,434		—		—		—			1,273,434
Other long-term liabilities		3,319		101,852		178		—			105,349
Equity:
Common Units		1,004,309		639,219		834,381		(1,484,860	)		993,049
Non-controlling interest in consolidated subsidiaries		—		—		—		465,517			465,517
Total equity		1,004,309		639,219		834,381		(1,019,343	)		1,458,566
Total liabilities and equity	$	2,316,149	$	2,777,374	$	905,928	$	(2,666,089	)	$	3,333,362

Condensed Consolidating Statements of Operations

	Year ended December 31, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	1,240,004		$	265,395		$	—		$	1,505,399
Operating expenses:
Purchased product costs		—			651,132			84,198			—			735,330
Facility expenses		—			128,612			39,171			(665	)		167,118
Selling, general and administrative expenses		46,903			31,015			9,011			(5,700	)		81,229
Depreciation and amortization		719			151,362			42,198			(708	)		193,571
Other operating expenses		673			9,030			284			—			9,987
Total operating expenses		48,295			971,151			174,862			(7,073	)		1,187,235
(Loss) income from operations		(48,295	)		268,853			90,533			7,073			318,164
Earnings from consolidated affiliates		288,870			44,425			—			(333,295	)		—
Loss on redemption of debt		(78,996	)		—			—			—			(78,996	)
Other expense, net		(91,612	)		(13,501	)		(558	)		(13,603	)		(119,274	)
Income before provision for income tax		69,967			299,777			89,975			(339,825	)		119,894
Provision for income tax expense		2,742			10,907			—			—			13,649
Net income		67,225			288,870			89,975			(339,825	)		106,245
Net income attributable to non-controlling interest		—			—			—			(45,550	)		(45,550	)
Net income attributable to the Partnership	$	67,225		$	288,870		$	89,975		$	(385,375	)	$	60,695

	Year ended December 31, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
Total revenue	$	—		$	1,063,621		$	124,010	$	—		$	1,187,631
Operating expenses:
Purchased product costs		—			589,403			16,937		—			606,340
Facility expenses		—			122,240			28,566		(652	)		150,154
Selling, general and administrative expenses		46,549			27,339			6,317		(4,947	)		75,258
Depreciation and amortization		594			136,781			27,054		(398	)		164,031
Other operating expenses		753			2,342			291		—			3,386
Total operating expenses		47,896			878,105			79,165		(5,997	)		999,169
(Loss) income from operations		(47,896	)		185,516			44,845		5,997			188,462
Earnings from consolidated affiliates		183,557			15,963			—		(199,520	)		—
Loss on redemption of debt		(46,326	)		—			—		—			(46,326	)
Other (expense) income, net		(82,000	)		(16,032	)		1,753		(11,566	)		(107,845	)
Income before provision for income tax		7,335			185,447			46,598		(205,089	)		34,291
Provision for income tax expense		1,299			1,890			—		—			3,189
Net income		6,036			183,557			46,598		(205,089	)		31,102
Net income attributable to non-controlling interest		—			—			—		(30,635	)		(30,635	)
Net income attributable to the Partnership	$	6,036		$	183,557		$	46,598	$	(235,724	)	$	467

	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 consolidated affiliates		2,243			1,501			—		(3,744	)		—
Gain on sale of unconsolidated affiliate		—			6,801			—		—			6,801
Other (expense) income, net		(69,951	)		(12,692	)		3,997		(9,669	)		(88,315	)
(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	)

Condensed Consolidating Statements of Cash Flows

	Year ended December 31, 2011
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(126,782	)	$	410,762		$	137,961		$	(7,243	)	$	414,698
Cash flows from investing activities:
Restricted cash		—			—			2,006			—			2,006
Capital expenditures		(789	)		(162,517	)		(399,992	)		12,017			(551,281	)
Acquisitions		—			(230,728	)		—			—			(230,728	)
Equity investments		(47,295	)		(252,367	)		—			299,662			—
Distributions from consolidated affiliates		50,718			68,651			—			(119,369	)		—
Investment in intercompany notes, net		(37,990	)		—			—			37,990			—
Proceeds from disposal of property, plant and equipment		—			606			7,617			(4,773	)		3,450
Net cash flows used in investing activities		(35,356	)		(576,355	)		(390,369	)		225,527			(776,553	)
Cash flows from financing activities:
Proceeds from revolving credit facility		1,182,200			—			—			—			1,182,200
Payments of revolving credit facility		(1,116,200	)		—			—			—			(1,116,200	)
Proceeds from long-term debt		1,199,000			—			—			—			1,199,000
Payments of long-term debt		(693,888	)		—			—			—			(693,888	)
Payments of premiums on redemption of long-term debt		(71,377	)		—			—			—			(71,377	)
Proceeds from intercompany notes, net		—			14,990			23,000			(37,990	)		—
Payments for debt issuance costs, deferred financing costs and registration costs		(20,163	)		—			—			—			(20,163	)
Acquisition of non-controlling interest, including transaction costs		(997,601	)		—			—			—			(997,601	)
Contributions from parent, net		—			47,295			—			(47,295	)		—
Contributions to joint ventures, net		—			—			378,759			(252,367	)		126,392
Payments of SMR Liability		—			(1,875	)		—			—			(1,875	)
Proceeds from public equity offerings, net		1,095,488			—			—			—			1,095,488
Share-based payment activity		(6,354	)		1,084			—			—			(5,270	)
Payment of distributions		(218,398	)		(50,718	)		(135,537	)		119,368			(285,285	)
Intercompany advances, net		(190,547	)		190,547			—			—			—
Net cash flows provided by financing activities		162,160			201,323			266,222			(218,284	)		411,421
Net increase in cash		22			35,730			13,814			—			49,566
Cash and cash equivalents at beginning of year		—			63,850			3,600			—			67,450
Cash and cash equivalents at end of period	$	22		$	99,580		$	17,414		$	—		$	117,016

	Year ended December 31, 2010
	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(102,042	)	$	373,483		$	46,852		$	(5,965	)	$	312,328
Cash flows from investing activities:
Restricted cash		—			—			(28,001	)		—			(28,001	)
Capital expenditures		(1,924	)		(123,005	)		(347,231	)		13,492			(458,668	)
Equity investments		(44,346	)		(171,252	)		—			215,598			—
Distributions from consolidated affiliates		41,167			22,246			—			(63,413	)		—
Collection of intercompany notes, net		12,350			—			—			(12,350	)		—
Proceeds from disposal of property, plant and equipment		—			733			7,527			(7,527	)		733
Net cash flows provided by (used in) investing activities		7,247			(271,278	)		(367,705	)		145,800			(485,936	)
Cash flows from financing activities:
Proceeds from revolving credit facility		494,404			—			—			—			494,404
Payments of revolving credit facility		(553,704	)		—			—			—			(553,704	)
Proceeds from long-term debt		500,000			—			—			—			500,000
Payments of long-term debt		(375,000	)		—			—			—			(375,000	)
Payments of premiums on redemption of long-term debt		(9,732	)		—			—			—			(9,732	)
Payments of intercompany notes, net		—			(12,350	)		—			12,350			—
Payments for debt issuance costs, deferred financing costs and registration costs		(20,912	)		—			—			—			(20,912	)
Contributions from parent, net		—			44,346			—			(44,346	)		—
Contributions to joint ventures, net		—			—			329,545			(171,252	)		158,293
Payments of SMR Liability		—			(1,354	)		—			—			(1,354	)
Proceeds from public equity offering, net		142,255			—			—			—			142,255
Share-based payment activity		(3,834	)		98			—			—			(3,736	)
Payment of distributions		(181,058	)		(41,167	)		(28,396	)		63,413			(187,208	)
Intercompany advances, net		102,376			(102,376	)		—			—			—
Net cash flows provided by (used in) financing activities		94,795			(112,803	)		301,149			(139,835	)		143,306
Net decrease in cash		—			(10,598	)		(19,704	)		—			(30,302	)
Cash and cash equivalents at beginning of year		—			74,448			23,304			—			97,752
Cash and cash equivalents at end of period	$	—		$	63,850		$	3,600		$	—		$	67,450

	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, net		21,340			—			—			(21,340	)		—
Proceeds from 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 investing activities		(18,722	)		(218,289	)		(281,285	)		56,543			(461,753	)
Cash flows from financing activities:
Proceeds from revolving credit facility		725,200			—			—			—			725,200
Payments of revolving credit facility		(850,600	)		—			—			—			(850,600	)
Proceeds from long-term debt		117,000			—			—			—			117,000
Payments of intercompany notes, net		—			(21,340	)		—			21,340			—
Payments for debt issuance costs, deferred financing costs and registration costs		(8,054	)		(500	)		—			—			(8,554	)
Contributions from parent, 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 period	$	—		$	74,448		$	23,304		$	—		$	97,752

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

2. Summary of Significant Accounting Policies

• 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.

• Restricted Cash

        Restricted cash includes cash and investments that must be held in escrow until certain capital projects are completed and the third party releases the restriction. Restricted cash balances for which the restrictions will not be released within a period of twelve months are classified as a long-term asset in the Consolidated Balance Sheets.

• Inventories

        Inventories, which consist primarily of natural gas, propane, other NGLs and spare parts and supplies, are valued at the lower of weighted-average cost or market. 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 a period of 20 to 25 years for all assets, with the exception of miscellaneous equipment and vehicles, which are depreciated over a period of three to ten years.

        The Partnership evaluates transactions involving the sale of property, plant and equipment to determine if they are, in-substance, the sale of real estate. Tangible assets may be considered real estate if the costs to 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. The Partnership's 2009 sale of the SMR, which was considered in-substance real estate, was not considered a sale 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 in 2009 was considered the sale of in-substance real estate. See Note 5 and Note 4, respectively, for a description of each transaction and its impact on the financial statements.

• 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.

• Investment in Unconsolidated Affiliate

        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 affiliate in the accompanying Consolidated Balance Sheets.

        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.

• Intangibles

        The Partnership's intangibles are comprised of customer contracts and relationships acquired in business combinations and 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 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. The Partnership first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. If a two-step process goodwill impairment test is required, 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 an 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 group.

        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 contractual term of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced, using the effective interest method.

• Deferred Contract Cost

        The Partnership may pay consideration to a producer upon entering a long-term arrangement to provide midstream services to the producer. In such cases, the amount of consideration paid is recorded as Deferred contract cost, net of accumulated amortization on the accompanying Consolidated Balance Sheets and is amortized over the term of the arrangement.

• Derivative Instruments

        Derivative instruments (including derivative instruments embedded in other contracts) are recorded at fair value and included in the consolidated balance sheet as assets or liabilities. Assets and liabilities related to derivative instruments with the same counterparty are not netted in the consolidated balance sheet. The Partnership discloses the fair value of 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). Changes in the fair value of derivative instruments are reported in the Statement of Operations in accounts related to the item whose value or cash flows are being managed. 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 manage 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 manage costs, typically in a keep-whole arrangement. Facility expenses gains and losses relate to a contract utilized to manage 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 Note 6). Changes in risk management activities are reported as an adjustment to net income in computing cash flow from operating activities on the accompanying Consolidated Statements of Cash Flows.

        During 2011, 2010 and 2009, the Partnership did not designate any hedges or designate any contracts as normal purchases and normal sales.

• 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. The recorded value of the amounts outstanding under the Credit Facility approximates fair value due to the variable interest rate that approximates current market rates. Derivative instruments are recorded at fair value, based on available market information (see Note 6). 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, 2011 and 2010 (in thousands):

	December 31, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	1,846,062	$	1,880,710	$	1,273,434	$	1,333,875
SMR Liability		93,909		119,887		95,784		125,600

        The fair value of the long-term debt is estimated based on recent market quotes. The fair value of the SMR Liability is estimated using a discounted cash flow approach based on the contractual cash flows and the Partnership's unsecured borrowing rate.

• Fair Value Measurement

        Financial assets and liabilities recorded at fair value in the Consolidated Balance Sheet are categorized based upon a fair value hierarchy established by GAAP, which classifies the inputs used to measure fair value into the following levels:

• • •

    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 derivatives, the embedded derivatives in commodity contracts and the embedded put options discussed in Note 6 and Note 16 as they have significant unobservable inputs.

        The methods and assumptions described above may produce a fair value that may not be realized in future periods upon settlement. 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 7.

• 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. 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 exchange 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 or fixed demand charges.

  •

  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 delivers an agreed-upon percentage of the residue gas and NGLs to the producer and sell the volumes the Partnership keeps to third parties.

  •

  Percent-of-index arrangements—Under percent-of-index arrangements, the Partnership purchases 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 then gathers and delivers the natural gas to pipelines where the Partnership resells 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 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. 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 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. 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.

        Collectability is reasonably assured.    Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates a customer's financial position (e.g. cash position and credit rating) and its ability to pay. If collectability 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 customers' 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 acts as an agent and earns a fixed amount and does not take ownership of the gas and/or NGLs.

        Amounts billed to customers for shipping and handling, including fuel costs, 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.

• 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 adjusted 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 its share-based compensation plans as described further in Note 20. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. Phantom units are treated as equity awards and compensation expense is measured for these phantom unit grants based on the fair value of the units on the grant date, as defined by GAAP. 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.

• 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 balances are classified as long-term in the accompanying Consolidated Balance Sheets. All changes in the tax bases of assets and liabilities are allocated among continued operations and items charged or credited directly to equity.

        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 Class A units were issued to the Corporation as part of the Merger and represent limited partner interests with the same rights as common units except that the Class A units do not have voting rights, except as required by law. Class A units are not treated as outstanding common units in the Consolidated Balance Sheet as they are eliminated in the consolidation of the Corporation. The deferred income tax component relates to the change in the temporary 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.

• Earnings (Loss) Per Unit

        The Partnership's outstanding phantom units are considered to be participating securities and the Class B units are considered to be a separate class of common units that do not participate in cash distributions. 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 the Partnership, after deducting amounts that are allocable to the outstanding phantom units and Class B units, by the weighted average number of common units outstanding during the period. The amount allocable to the phantom units and Class B 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, no earnings are allocable to Class B units as they do not participate in cash distributions. 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 and Class B units is based on actual distributions to the phantom units and Class B unitholders. Diluted earnings per unit is calculated by dividing net income attributable to the Partnership, after deducting amounts allocable to the outstanding phantom units and Class B 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 net income attributable to the Partnership, after deducting amounts that are allocable to the outstanding phantom units and Class B units, is a 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 acquires additional interest or if the subsidiary issues or repurchases its own shares. If the transaction does not result in a change in control over the subsidiary, the transaction is accounted for as an equity transaction. If a sale 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. If the purchase of additional interest occurs which changes the acquirer's ownership interest from non-controlling to controlling, the acquirer's preexisting interest in the acquiree is remeasured to its fair value, with a resulting gain or loss recorded in earnings upon consummation of the business combination. Once an entity has control of a subsidiary, its acquisitions of some or all of the noncontrolling interests in that subsidiary are accounted for as equity transactions and are not considered to be a business combination. See Note 4 for a description of the transactions that resulted in a change in the Partnership's ownership interest in a subsidiary and the impact of these transactions to the financial statements.

• Recent Accounting Pronouncements

        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 for the Partnership prospectively for all revenue arrangements entered into or materially modified on or after January 1, 2011. The amendment did not have a material effect on the Partnership's consolidated financial statements.

        In May 2011, the FASB amended the accounting guidance for fair value measurement and disclosure. The amended guidance was intended to converge the fair value measurement and disclosure requirements under GAAP and IFRS. The amendment primarily clarifies the application of the existing guidance and provides for increased disclosures, particularly related to Level 3 fair value measurements. The amended guidance is effective for the Partnership prospectively as of January 1, 2012. Except for the additional disclosures, the adoption of the amended guidance is not expected to have a material effect on the Partnership's consolidated financial statements.

        In September 2011, the FASB amended the accounting guidance for goodwill impairment testing. The amended guidance provides an entity with an option to first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership elected early adoption for the period ended December 31, 2011 and the adoption did not have a material effect on the Partnership's consolidated financial statements.

        In December 2011, the FASB amended the accounting guidance for balance sheet offsetting for financial assets and financial liabilities. The amended guidance was intended to help investors and other financial statement users to better assess the effect or potential effect of offsetting arrangements on a company's financial position and provides for increased disclosures. The amended guidance is effective for the Partnership prospectively as of January 1, 2013. Except for the additional disclosures, the adoption of the amended guidance is not expected to have a material effect on the Partnership's consolidated financial statements.

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Information

Supplemental Cash Flow Information

26. Supplemental Cash Flow Information

        The following table provides information regarding supplemental cash flow information (in thousands):

	Year ended December 31,
	2011		2010		2009
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	112,780	$	101,459	$	85,817
Cash paid for income taxes, net of refunds		10,115		8,683		4,609
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	87,098	$	65,908	$	60,738
Interest capitalized on construction in progress		1,121		2,766		12,228
Issuance of common units for vesting of share-based payment awards		5,412		7,238		9,402
Issuance of Class B units for acquisition of non-controlling interest		752,531		—		—

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Incentive Compensation Plans (Details) (USD $)	12 Months Ended										1 Months Ended	12 Months Ended			1 Months Ended	12 Months Ended				1 Months Ended	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Phantom units	Dec. 31, 2010 Phantom units	Dec. 31, 2009 Phantom units	Dec. 31, 2011 Distribution equivalent rights	Dec. 31, 2010 Distribution equivalent rights	Dec. 31, 2009 Distribution equivalent rights	Dec. 31, 2011 2008 LTIP Y	Apr. 30, 2010 2008 LTIP TSR Performance Units	Dec. 31, 2012 2008 LTIP TSR Performance Units	Dec. 31, 2011 2008 LTIP TSR Performance Units Y	Dec. 31, 2010 2008 LTIP TSR Performance Units	Jan. 31, 2010 2008 LTIP Unrestricted units	Dec. 31, 2012 2008 LTIP Performance units	Dec. 31, 2011 2008 LTIP Performance units	Dec. 31, 2010 2008 LTIP Performance units	Dec. 31, 2009 2008 LTIP Performance units	Feb. 28, 2008 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan unit	Dec. 31, 2011 2002 LTIP Plan Phantom units	Dec. 31, 2010 2002 LTIP Plan Phantom units	Dec. 31, 2009 2002 LTIP Plan Phantom units	Dec. 31, 2011 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan Phantom units	Dec. 31, 2010 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan Phantom units	Dec. 31, 2009 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan Phantom units
Share-based compensation arrangement by share-based payment award
Total share-based compensation expense	$ 13,925,000	$ 16,784,000	$ 8,772,000	$ 13,479,000	$ 15,319,000	$ 7,448,000	$ 446,000	$ 1,465,000	$ 1,324,000				$ 4,800,000	$ 4,500,000	$ 4,800,000		$ 0	$ 0	$ 500,000
Total compensation expense not yet recognized										12,100,000			200,000
Unrecognized compensation costs on unvested awards, weighted average period of recognition (in years)										0.8
Vesting period of share-based awards (in years)																	3 years				3 years			3 years
Cash paid for taxes related to vesting of share-based payment awards related to tax withholding for share-based compensation	6,354,000	3,834,000	1,385,000																		400,000	400,000	200,000	6,000,000	3,400,000	1,100,000
Common units provided for issuance to employees and affiliates as share-based payment awards (in units)										2,500,000
Performance period used in computation of total unitholder return (in years)													3
Percentage of units vested if relative ranking is less than 40th percentile (Expressed as a decimal)													0.00%
Percentage of units vested if relative ranking ranges from 40th to 60th percentile (Expressed as a decimal)													50.00%
Percentage of units vested if relative ranking ranges from 60th to 80th percentile (Expressed as a decimal)													75.00%
Percentage of units vested if relative ranking ranges from 80th to 100th percentile (Expressed as a decimal)													100.00%
Percentage of increase or decrease in the number of units to vest, which the board can approve based on certain performance criteria (Expressed as a decimal)													25.00%
Number of units that vested based on actual performance with regards to the market criteria (in units)												141,000	141,000
Number of units that vested based on actual performance with regards to the market criteria and performance criteria (in units)												35,250	35,250
Percentage of units that will vest based on actual performance with regards to the market criteria (Expressed as a decimal)													75.00%
Percentage of units that will vest based on actual performance with regards to the market criteria and performance criteria (Expressed as a decimal)													25.00%
Unit activity
Unvested at the beginning of the period (in units)												141,000	282,000			141,000					23,645	69,555	145,927	1,329,160	977,241	909,306
Granted (in units)											282,000	35,250	35,250		166,000									309,629	736,688	442,035
Vested (in units)													(176,250)								(23,645)	(44,942)	(69,652)	(396,934)	(363,502)	(309,052)
Forfeited (in units)																(141,000)						(968)	(6,720)	(306,346)	(21,267)	(65,048)
Unvested at the end of the period (in units)													141,000	282,000			141,000					23,645	69,555	935,509	1,329,160	977,241
Weighted-average Grant-date Fair Value
Unvested at the beginning of the period (in dollars per unit)																					$ 33.83	$ 32.75	$ 31.45	$ 25.29	$ 22.00	$ 31.80
Granted (in dollars per unit)																								$ 42.75	$ 30.25	$ 8.64
Vested (in dollars per unit)																					$ 33.83	$ 32.15	$ 29.94	$ 27.04	$ 26.85	$ 31.93
Forfeited (in dollars per unit)																						$ 34.00	$ 33.64	$ 31.66	$ 19.28	$ 20.96
Unvested at the end of the period (in dollars per unit)																						$ 33.83	$ 32.75	$ 28.50	$ 25.29	$ 22.00
Total grant-date fair value of units outstanding																	1,200,000
Other Award Information
Shares of restricted stock granted under an equity-based compensation plan which are converted in connection with merger																				25,897
Number of phantom units issued against restricted stock converted in connection with merger (in units)																				49,354
Total fair value of phantom units vested during the period													4,900,000								1,000,000	1,300,000	900,000	10,700,000	9,800,000	9,900,000
Total intrinsic value of phantom units vested during the period													$ 4,900,000								$ 1,000,000	$ 1,300,000	$ 900,000	$ 10,700,000	$ 9,800,000	$ 9,900,000

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Divestitures (Tables)

12 Months Ended

Dec. 31, 2011

Divestitures

Schedule of assets and liabilities of SMR transaction included in accompanying consolidated balance sheets

	December 31, 2011		December 31, 2010
ASSETS
Property, plant and equipment, net of accumulated depreciation of $9,658 and $4,390, respectively	$	95,705	$	100,973
LIABILITIES
Accrued liabilities	$	2,058	$	1,875
Other long-term liabilities		91,851		93,909

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Incentive Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2011

Incentive Compensation Plans

Schedule of share-based compensation plans

Share-based compensation plan	Award Classification	Further awards authorized for issuance under plan as of December 31, 2011	Awards outstanding under the plan as of December 31, 2011	Final Year of Activity
2008 Long-Term Incentive Plan ("2008 LTIP")	Equity	Yes	Yes		N/A
2006 Hydrocarbon Stock Incentive Plan ("2006 Hydrocarbon Plan")	Equity	No	No		2010
Long-Term Incentive Plan ("2002 LTIP")	Liability	No	No		2011
1996 Hydrocarbon Stock Incentive Plan ("1996 Hydrocarbon Plan")	Equity	No	No		2009

Compensation expense recorded for share-based pay arrangements

	Year ended December 31,
	2011		2010		2009
Phantom units	$	13,479	$	15,319	$	7,448
Distribution equivalent rights(1)		446		1,465		1,324
Total compensation expense	$	13,925	$	16,784	$	8,772

(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.

2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan

Share-based compensation arrangement by share-based payment award

Phantom unit activity

	Number of Units			Weighted-average Grant-date Fair Value(1)
Unvested at January 1, 2009		909,306		$	31.80
Granted		442,035			8.64
Vested		(309,052	)		31.93
Forfeited		(65,048	)		20.96
Unvested at December 31, 2009		977,241			22.00
Granted (includes 282,000 TSR units)		736,688			30.25
Vested		(363,502	)		26.85
Forfeited		(21,267	)		19.28
Unvested at December 31, 2010 (includes 282,000 TSR units)		1,329,160			25.29
Granted (includes 35,250 TSR units)		309,629			42.75
Vested (includes 176,250 TSR units)		(396,934	)		27.04
Forfeited		(306,346	)		31.66
Unvested at December 31, 2011 (includes 141,000 TSR units)(2)		935,509			28.50

(1)

The calculation of the weighted average grant-date fair value for units granted during the year ended December 31, 2010 and unvested as of December 2010 and December 2011 is recalculated to include the fair value as of December 31, 2011 for 35,250 TSR Performance Units. A grant date, as defined by GAAP, has not been established for these units.

(2)

Includes 141,000 Performance Units that did not vest and were forfeited in January 2012.

2002 LTIP

Share-based compensation arrangement by share-based payment award

Phantom unit activity

	Number of Units			Weighted-average Grant-date Fair Value
Unvested at January 1, 2009		145,927		$	31.45
Vested		(69,652	)		29.94
Forfeited		(6,720	)		33.64
Unvested at December 31, 2009		69,555			32.75
Vested		(44,942	)		32.15
Forfeited		(968	)		34.00
Unvested at December 31, 2010		23,645			33.83
Vested		(23,645	)		33.83
Unvested at December 31, 2011		—			—

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Inventories (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Inventories
NGLs	$ 32,352	$ 15,930
Spare parts, materials and supplies	8,654	7,502
Total inventories	$ 41,006	$ 23,432

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CONSOLIDATED BALANCE SHEETS (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents ($2,684 and $2,913, respectively)	$ 117,016	$ 67,450
Restricted cash	26,193
Receivables, net ($1,569 and $43,783, respectively)	226,561	179,209
Inventories ($0 and $8,431)	41,006	23,432
Fair value of derivative instruments	8,698	4,345
Deferred income taxes	14,885	16,090
Other current assets ($169 and $272, respectively)	11,748	8,020
Total current assets	446,107	298,546
Property, plant and equipment ($156,808 and $849,986, respectively)	3,302,369	2,613,027
Less: accumulated depreciation ($15,551 and $38,169, respectively)	(438,062)	(294,003)
Total property, plant and equipment, net	2,864,307	2,319,024
Other long-term assets:
Restricted cash ($0 and $28,001)		28,001
Investment in unconsolidated affiliate	27,853	28,688
Intangibles, net of accumulated amortization of $168,168 and $124,568, respectively	603,767	613,578
Goodwill	67,918	9,421
Deferred financing costs, net of accumulated amortization of $13,194 and $11,445, respectively	41,798	32,901
Deferred contract cost, net of accumulated amortization of $2,262 and $1,950, respectively	988	1,300
Fair value of derivative instruments	16,092	417
Other long-term assets ($102 and $383, respectively)	1,595	1,486
Total assets	4,070,425	3,333,362
Current liabilities:
Accounts payable ($96 and $5,945, respectively)	179,871	122,473
Accrued liabilities ($1,144 and $64,713, respectively)	171,451	153,869
Deferred income taxes		11
Fair value of derivative instruments	90,551	65,489
Total current liabilities	441,873	341,842
Deferred income taxes	93,664	87,881
Fair value of derivative instruments	65,403	66,290
Long-term debt, net of discounts of $1,050 and $1,566, respectively	1,846,062	1,273,434
Other long-term liabilities ($73 and $154, respectively)	121,356	105,349
Commitments and contingencies (see Note 18)
Equity:
Common units	679,309	993,049
Non-controlling interest in consolidated subsidiaries	70,227	465,517
Total equity	1,502,067	1,458,566
Total liabilities and equity	4,070,425	3,333,362
Common Units
Equity:
Common units	679,309	993,049
Total equity	679,309	993,049
Class B Units
Equity:
Common units	752,531
Total equity	$ 752,531

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment

Summary of property, plant and equipment

	December 31, 2011			December 31, 2010
Natural gas gathering and NGL transportation pipelines and facilities	$	2,039,524		$	1,625,170
Processing plants		660,928			584,886
Fractionation and storage facilities		120,474			81,317
Crude oil pipelines		16,678			16,810
Land, building, office equipment and other		185,462			155,437
Construction in progress		279,303			149,407
Property, plant and equipment		3,302,369			2,613,027
Less: accumulated depreciation		(438,062	)		(294,003	)
Total property, plant and equipment, net	$	2,864,307		$	2,319,024

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Quarterly Results of Operations (Unaudited) (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Quarterly Results of Operations (Unaudited)
Total revenue	$ 333,913	$ 507,826	$ 400,439	$ 263,221	$ 299,991	$ 255,411	$ 323,850	$ 308,379	$ 1,505,399	$ 1,187,631	$ 738,283
(Loss) income from operations	(7,557)	207,801	133,214	(15,294)	25,172	646	109,071	53,573	318,164	188,462	(73,856)
Net (loss) income	(61,743)	153,454	89,205	(74,671)	(43,194)	(18,676)	66,968	26,004	106,245	31,102	(113,354)
Net (loss) income attributable to the Partnership	(74,085)	140,312	78,497	(84,029)	(54,109)	(27,151)	60,217	21,510	60,695	467	(118,668)
Net (loss) income attributable to the Partnership's common unitholders per common unit(4):
Basic (in dollars per unit)	$ (0.87)	$ 1.77	$ 1.03	$ (1.13)	$ (0.76)	$ (0.39)	$ 0.84	$ 0.32	$ 0.75	$ (0.01)	$ (1.97)
Diluted (in dollars per unit)	$ (0.87)	$ 1.77	$ 1.03	$ (1.13)	$ (0.76)	$ (0.39)	$ 0.84	$ 0.32	$ 0.75	$ (0.01)	$ (1.97)
Loss on redemption of debt	$ (35,500)			$ (43,300)	$ (46,300)				$ (78,996)	$ (46,326)

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash flows from operating activities:
Net income (loss)	$ 106,245	$ 31,102	$ (113,354)
Adjustments to reconcile net income (loss) to net cash provided by operating activities (net of acquisitions):
Depreciation	149,954	123,198	95,537
Amortization of intangible assets	43,617	40,833	40,831
Impairment of goodwill and long-lived assets			5,855
Loss on redemption of debt	78,996	46,326
Amortization of deferred financing costs and discount	5,114	10,264	9,718
Accretion of asset retirement obligations	1,190	237	198
Amortization of deferred contract cost	312	312	312
Phantom unit compensation expense	13,479	15,319	7,448
Loss (earnings) of unconsolidated affiliates	1,095	(1,562)	(3,505)
Gain on sale of unconsolidated affiliate			(6,801)
Contribution to unconsolidated affiliate	(560)
Distributions from unconsolidated affiliate	300	2,508
Unrealized loss on derivative instruments	4,147	28,475	227,920
Loss on disposal of property, plant and equipment	8,797	3,149	1,677
Deferred income taxes	(3,929)	(4,466)	(50,088)
Other	1,626		(2,228)
Changes in operating assets and liabilities, net of working capital acquired:
Receivables	(45,463)	(37,090)	(33,133)
Inventories	(16,025)	5,710	6,245
Other current assets	(3,728)	2,654	1,074
Accounts payable and accrued liabilities	54,745	45,361	30,717
Other long-term assets	(307)	174	(2,808)
Other long-term liabilities	15,093	(176)	7,486
Net cash provided by operating activities	414,698	312,328	223,101
Cash flows from investing activities:
Restricted cash	2,006	(28,001)
Capital expenditures	(551,281)	(458,668)	(486,623)
Acquisition of business	(230,728)
Equity investments			(405)
Proceeds from sale of unconsolidated affiliate			25,000
Proceeds from disposal of property, plant and equipment	3,450	733	275
Net cash flows used in investing activities	(776,553)	(485,936)	(461,753)
Cash flows from financing activities:
Proceeds from revolving credit facility	1,182,200	494,404	725,200
Payments of revolving credit facility	(1,116,200)	(553,704)	(850,600)
Proceeds from long-term debt	1,199,000	500,000	117,000
Payments of long-term debt	(693,888)	(375,000)
Payments of premiums on redemption of long-term debt	(71,377)	(9,732)
Payments for debt issuance costs, deferred financing costs and registration costs	(20,163)	(20,912)	(8,554)
Acquisition of non-controlling interest, including transaction costs	(997,601)
Contributions to MarkWest Liberty Midstream joint venture, net	126,392	158,293	194,536
Proceeds from sale of equity interest in joint venture, net			60,654
Payments of SMR Liability	(1,875)	(1,354)
Proceeds from SMR Transaction			73,129
Proceeds from public equity offerings, net	1,095,488	142,255	178,565
Cash paid for taxes related to net settlement of share-based payment awards	(6,354)	(3,834)	(1,385)
Excess tax benefits related to share-based compensation	1,084	98
Payment of distributions to common unitholders	(218,398)	(181,058)	(155,307)
Payment of distributions to non-controlling interest	(66,887)	(6,150)	(155)
Net cash flows provided by financing activities	411,421	143,306	333,083
Net increase (decrease) in cash and cash equivalents	49,566	(30,302)	94,431
Cash and cash equivalents at beginning of year	67,450	97,752	3,321
Cash and cash equivalents at end of year	$ 117,016	$ 67,450	$ 97,752

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Supplemental Cash Flow Information (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	$ 112,780	$ 101,459	$ 85,817
Cash paid for income taxes, net of refunds	10,115	8,683	4,609
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	87,098	65,908	60,738
Interest capitalized on construction in progress	1,121	2,766	12,228
Issuance of common units for vesting of share-based payment awards	5,412	7,238	9,402
Issuance of Class B units for acquisition of non-controlling interest	$ 752,531

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Valuation and Qualifying Accounts (Tables)

12 Months Ended

Dec. 31, 2011

Valuation and Qualifying Accounts

Summary of activity in valuation allowance and reserve accounts

	Year ended December 31,
	2011			2010			2009
Allowance for Doubtful Accounts
Balance at beginning of period	$	162		$	162		$	175
Charged to costs and expenses		—			134			12
Other charges(1)		(2	)		(134	)		(25	)
Balance at end of period	$	160		$	162		$	162
Deferred Tax Asset Valuation Allowance
Balance at beginning of period	$	1,036		$	1,688		$	30
Charged to costs and expenses		(59	)		(652	)		1,667
Other charges		—			—			(9	)
Balance at end of period	$	977		$	1,036		$	1,688

(1) Bad debts written-off (net of recoveries).

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Subsequent Events

12 Months Ended

Dec. 31, 2011

Subsequent Events

Subsequent Events

29. Subsequent Events

• Utica Shale Joint Venture

        Effective January 1, 2012, the Partnership and EMG Utica entered into the Utica Joint Venture to develop significant natural gas processing and NGL fractionation, transportation and marketing infrastructure in the Utica Shale in eastern Ohio beginning in 2012. Under the terms of the Utica Joint Venture, EMG will fund a majority of the initial capital expenditures required to develop the Utica midstream infrastructure. The Partnership has a 60% ownership in the Utica Joint Venture. A wholly-owned subsidiary of the Partnership serves as the operator of MarkWest Utica EMG and provides field operating and general and administrative services. A portion of the fee for providing these services is fixed.

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Variable Interest Entities (Details) (USD $) Share data in Thousands, unless otherwise specified	3 Months Ended								12 Months Ended						1 Months Ended	9 Months Ended	12 Months Ended				12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2011 Total Variable Interest Entities	Dec. 31, 2010 Total Variable Interest Entities	Feb. 27, 2009 MarkWest Liberty Midstream	Dec. 31, 2009 MarkWest Liberty Midstream	Dec. 31, 2011 MarkWest Liberty Midstream	Dec. 31, 2010 MarkWest Liberty Midstream	Dec. 31, 2009 MarkWest Liberty Midstream	Mar. 01, 2009 MarkWest Liberty Midstream	Dec. 31, 2009 MarkWest Pioneer	Dec. 31, 2011 MarkWest Pioneer mile	Dec. 31, 2010 MarkWest Pioneer
Variable interest entities
MarkWest's percentage of ownership															60.00%		51.00%	60.00%	60.00%
Agreed-to value of contributed assets															$ 107,500,000
Cash contributed by M&R MWE Liberty, LLC in exchange for a minority ownership interest											60,654,000
Cash contributed by M&R MWE Liberty, LLC in exchange for a minority ownership interest															50,000,000	150,000,000	126,400,000	158,300,000
Funding commitment by M&R requirements after which time the Partnership agreed to fund the future capital requirements until each member's contributed capital was proportionate to its ownership interest															150,000,000
Percentage of non-controlling interest																40.00%	49.00%	40.00%	40.00%	40.00%	50.00%	50.00%	50.00%
Percentage of non-controlling interest acquired by the Partnership	49.00%								49.00%								49.00%
Special non-cash allocation of net income received by M & R																	1,300,000	11,400,000	3,400,000
MarkWest additional contributions to Liberty																	252,400,000	171,100,000	8,000,000
Non-controlling interest purchase consideration																	1,746,500,000
Non-controlling interest purchase consideration, cash paid																	994,000,000
Non-controlling interest purchase consideration, shares																	19,954
Non-controlling interest purchase consideration, value Class B units									752,531,000								752,500,000
Transaction costs related to acquisition of non-controlling interests																	3,600,000
Carrying value of non-controlling interest acquired																	500,300,000
Percentage of profit loss attributable to the entity																	100.00%
Net income (loss) of VIE attributable to non-controlling interests									45,550,000	30,635,000	5,314,000						44,000,000	27,900,000	6,300,000
Length of FERC-regulated pipeline (in miles)																						50
Takeaway capacity of Arkoma Connector Pipeline (in dekatherms per day)																						638,000
Threshold above which entity is obligated to fund all capital expenditures																					125,000,000
ASSETS
Cash and cash equivalents	117,016,000				67,450,000				117,016,000	67,450,000	97,752,000	3,321,000	2,684,000	2,913,000									2,913,000
Receivables, net	226,561,000				179,209,000				226,561,000	179,209,000			1,569,000	43,783,000				42,181,000					1,602,000
Inventories	41,006,000				23,432,000				41,006,000	23,432,000			0	8,431,000				8,431,000
Other current assets	11,748,000				8,020,000				11,748,000	8,020,000			169,000	272,000				271,000					1,000
Property, plant and equipment, net	2,864,307,000				2,319,024,000				2,864,307,000	2,319,024,000				811,817,000				664,778,000					147,039,000
Accumulated depreciation	438,062,000				294,003,000				438,062,000	294,003,000			15,551,000	38,169,000				28,869,000					9,300,000
Restricted cash					28,001,000					28,001,000			0	28,001,000				28,001,000
Other long-term assets	1,595,000				1,486,000				1,595,000	1,486,000			102,000	383,000				281,000					102,000
Total assets	4,070,425,000				3,333,362,000				4,070,425,000	3,333,362,000	3,014,737,000			895,600,000				743,943,000					151,657,000
LIABILITIES
Accounts payable	179,871,000				122,473,000				179,871,000	122,473,000			96,000	5,945,000				5,945,000
Accrued liabilities	171,451,000				153,869,000				171,451,000	153,869,000			1,144,000	64,713,000				63,450,000					1,263,000
Other long-term liabilities	121,356,000				105,349,000				121,356,000	105,349,000			73,000	154,000				86,000					68,000
Total liabilities														70,812,000				69,481,000					1,331,000
Summary of net income (loss) attributable to the entity and transfers to the non-controlling interest
Net income (loss) attributable to the Partnership	(74,085,000)	140,312,000	78,497,000	(84,029,000)	(54,109,000)	(27,151,000)	60,217,000	21,510,000	60,695,000	467,000	(118,668,000)
Transfers to the non-controlling interest:
Decrease in common unit equity for 2011 acquisition of equity interest in MarkWest Liberty Midstream, net of $51,321 income tax benefit									(1,194,865,000)
Tax benefit resulting from change in equity due to purchase of additional interest in consolidated subsidiary									51,321,000
Decrease in common unit equity for transaction costs related to 2011 acquisition of equity interest in MarkWest Liberty Midstream									(3,600,000)
Decrease in Partners' Capital common unit equity for transfer to non-controlling interest from 2009 sale of equity interest in MarkWest Pioneer, net of $1,491 income tax benefit											(10,288,000)
Tax benefit resulting from change in equity due to sale of interest in consolidated subsidiary											1,491,000
Decrease in Partners' Capital for transaction costs related to sale of equity interest in MarkWest Liberty Midstream and MarkWest Pioneer											(7,310,000)
Net (loss) income attributable to the Partnership and transfers to the non-controlling interest									$ (1,137,770,000)	$ 467,000	$ (136,266,000)

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Long-Term Debt

12 Months Ended

Dec. 31, 2011

Long-Term Debt

Long-Term Debt

16. Long-Term Debt

        Debt is summarized below (in thousands):

	December 31, 2011		December 31, 2010
Credit Facility
Revolving credit facility, 4.0% interest due September 2016	$	66,000	$	—
Senior Notes
2016 Senior Notes, 8.5% interest, net of discount of $0 and $642, respectively, issued July 2006 and due July 2016		—		274,358
2018 Senior Notes, 8.75% interest, net of discount of $129 and $924, respectively, issued April and May 2008 and due April 2018		80,983		499,076
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020		500,000		500,000
2021 Senior Notes, 6.5% interest, net of discount of $921, issued February and March 2011 and due August 2021		499,079		—
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022		700,000		—
Total long-term debt	$	1,846,062	$	1,273,434

• Credit Facility

        The Partnership's Credit Facility has a current lending capacity of $900 million and provides for an uncommitted accordion feature whereby the Credit Facility may be increased from time to time by the Partnership upon the satisfaction of certain requirements by up to an aggregate of $250 million. The Credit Facility matures on September 7, 2016. The Partnership incurred approximately $2.1 million, $11.2 million, and $4.4 million of deferred financing costs associated with modifications of the Credit Facility during the years ended December 31, 2011, 2010 and 2009, respectively.

        The borrowings under the Credit Facility bear interest at a variable interest rate, plus basis points. The variable interest rate is based either on the London interbank market rate ("LIBO Rate Loans"), or the higher of (a) the prime rate set by the Facility's administrative agent, (b) the Federal Funds Rate plus 0.50% and (c) the rate for LIBO Rate Loans for a one month interest period plus 1% ("Alternate Base Rate Loans"). The basis points correspond to the Partnership's Total Leverage Ratio (which is the ratio of the Partnership's consolidated funded debt to the Partnership's adjusted consolidated EBITDA), ranging from 0.75% to 1.75% for Alternate Base Rate Loans and from 1.75% to 2.75% for LIBO Rate Loans. The Partnership may utilize up to $150 million of the Credit Facility for the issuance of letters of credit and $10 million for shorter-term swingline loans.

        Under the provisions of the Credit Facility, the Partnership is subject to a number of restrictions and covenants. Significant financial covenants under the Credit Facility include the Interest Coverage Ratio (as defined in the Credit Facility), which must be greater than 2.75 to 1.0, and the Total Leverage Ratio (as defined in the Credit Facility), which must be less than 5.25 to 1.0. As of December 31, 2011, the Partnership was in compliance with these covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by the Partnership's wholly-owned subsidiaries other than MarkWest Liberty Midstream and collateralized by substantially all of the Partnership's assets and those of its wholly-owned subsidiaries other than MarkWest Liberty Midstream. As of December 31, 2011, the Partnership had $66.0 million of borrowings outstanding and $19.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $814.7 million available for borrowing.

• Senior Notes

        As of December 31, 2011, MarkWest Energy Partners, L.P. in conjunction with its wholly-owned subsidiary MarkWest Energy Finance Corporation (the "Issuers"), had the following series of senior notes outstanding: $81.1 million aggregate principal issued in April and May 2008 and due in April 2018; $500.0 million aggregate principal issued in November 2010 and due in November 2020; $500.0 million aggregate principal issued in February and March 2011, due August 2021; and $700.0 million of Senior aggregate principal issued in November 2011, due June 2022.

        2014 Senior Notes.    In October 2004, the Issuers completed a private placement, subsequently registered, of $225 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. In May 2009, the Issuers completed an additional private placement, subsequently registered, of $150 million in aggregate principal amount of 6.875% senior unsecured notes to qualified institutional buyers under Rule 144A under an indenture substantially similar to the indenture relating to the notes issued in October 2004. The 2014 Senior Notes were redeemed in the fourth quarter of 2010.

        2016 Senior Notes.    In July and October 2006, the Issuers completed a private placement, subsequently registered, of $275 million in aggregate principal amount of 8.5% senior unsecured notes due 2016 ("2016 Senior Notes") to qualified institutional buyers. The 2016 Senior Notes were redeemed in the first and third quarters of 2011.

        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 unsecured notes to qualified institutional buyers under Rule 144A. The 2018 Senior Notes mature on April 15, 2018, and interest is payable semi-annually in arrears on April 15 and October 15, commencing October 15, 2008. In May 2008, the Partnership completed the placement of an additional $100 million pursuant to the indenture to the 2018 Senior Notes. The notes issued in the April 2008 and May 2008 offerings are treated a single class of debt under this same indenture. The Partnership received combined proceeds of approximately $488.5 million, after including initial purchasers' premium and deducting the underwriting fees and the other expenses of the offering. Approximately $253.3 million and $165.6 million of the 2018 Senior Notes were redeemed in the fourth quarter and first quarter of 2011, respectfully.

        2020 Senior Notes.    In November 2010, the Issuers completed a public offering of $500 million in aggregate principal amount of 6.75% senior unsecured notes. The 2020 Senior Notes mature on November 1, 2020, and interest is payable semi-annually in arrears on May 1 and November 1, commencing May 1, 2011. The Partnership received proceeds of approximately $490.3 million after deducting the underwriting fees and the other third-party expenses associated with the offering.

        2021 Senior Notes.    On February 24, 2011, the Issuers completed a public offering of $300 million in aggregate principal amount of 6.5% senior unsecured notes, which were issued at par. On March 10, 2011, the Issuers completed a follow-on public offering of an additional $200 million in aggregate principal amount of 2021 Senior Notes, which were issued at 99.5% of par and are treated as a single class of debt securities under the same indenture as the 2021 Senior Notes issued on February 24, 2011. The 2021 Senior Notes mature on August 15, 2021, and interest is payable semi-annually in arrears on February 15 and August 15, commencing August 15, 2011. The Partnership received aggregate net proceeds of approximately $492 million from the 2021 Senior Notes offerings after deducting the underwriting fees and other third-party expenses associated with the offerings.

        2022 Senior Notes.    On November 3, 2011, the Issuers completed a public offering of $700 million in aggregate principal amount of 6.25% senior unsecured notes due June 2022. Interest on the 2022 Notes is payable semi-annually in arrears on June 15 and December 15, commencing June 15, 2012. The Partnership received aggregate net proceeds of approximately $688 million from the 2022 Senior Notes offerings, after deducting the underwriting fees and other third-party expenses.

        The proceeds from the issuance of the 2021 and 2022 Senior Notes were used to redeem $275 million of 2016 Senior Notes and $419 million of 2018 Senior Notes and to provide additional working capital for general partnership purposes. The proceeds from the issuance of the 2020 Senior Notes were used to redeem the 2014 Senior Notes, repay the Credit Facility and to provide additional working capital for general partnership purposes.

        The Partnership recorded a total pre-tax loss of approximately $79.0 million during 2011 related to the redemption of the 2016 Senior Notes and 2018 Senior Notes. The pre-tax loss consisted of approximately $7.6 million related to the non-cash write-off of the unamortized discount and deferred finance costs and approximately $71.4 million related to the payment of tender premiums and third party expenses. The loss is recorded in Loss on redemption of debt in the accompanying Consolidated Statements of Operations.

        The Partnership recorded a total pre-tax loss of approximately $46.3 million in the fourth quarter of 2010 related to the redemption of the senior notes issued in October 2004 and May 2009. The pre-tax loss consisted of approximately $36.6 million related to the non-cash write-off of the unamortized discount and deferred finance costs and approximately $9.7 million related to the payment of premiums. The loss is recorded in Loss on redemption of debt in the accompanying Consolidated Statements of Operations.

        The Issuers have no independent operating assets or operations. All wholly-owned subsidiaries, other than MarkWest Energy Finance Corporation and MarkWest Liberty Midstream, guarantee the Senior Notes, jointly and severally and fully and unconditionally. The Partnership's less than wholly-owned subsidiaries do not guarantee the Senior Notes (see Note 25 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 Credit Facility.

        The indentures governing the Senior Notes limit the activity of the Partnership and the restricted subsidiaries identified in the indentures. 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 terminate, in which case the Partnership and its subsidiaries will cease to be subject to such terminated covenants.

        As of December 31, 2011, there are no minimum principal payments on Senior Notes due during the next five years. The full $1,781 million principal amounts for Senior Notes are due between 2018 and 2022. The $66 million of borrowings outstanding under the Credit Facility as of December 31, 2011 is due in 2016.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies

Use of Estimates

• 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

• 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.

Restricted Cash

• Restricted Cash

        Restricted cash includes cash and investments that must be held in escrow until certain capital projects are completed and the third party releases the restriction. Restricted cash balances for which the restrictions will not be released within a period of twelve months are classified as a long-term asset in the Consolidated Balance Sheets.

Inventories

• Inventories

        Inventories, which consist primarily of natural gas, propane, other NGLs and spare parts and supplies, are valued at the lower of weighted-average cost or market. 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

        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 a period of 20 to 25 years for all assets, with the exception of miscellaneous equipment and vehicles, which are depreciated over a period of three to ten years.

        The Partnership evaluates transactions involving the sale of property, plant and equipment to determine if they are, in-substance, the sale of real estate. Tangible assets may be considered real estate if the costs to 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. The Partnership's 2009 sale of the SMR, which was considered in-substance real estate, was not considered a sale 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 in 2009 was considered the sale of in-substance real estate. See Note 5 and Note 4, respectively, for a description of each transaction and its impact on the financial statements.

Asset Retirement Obligations

• 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.

Investment in Unconsolidated Affiliates

• Investment in Unconsolidated Affiliate

        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 affiliate in the accompanying Consolidated Balance Sheets.

        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.

Intangibles

• Intangibles

        The Partnership's intangibles are comprised of customer contracts and relationships acquired in business combinations and 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 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

        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. The Partnership first assesses qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. If a two-step process goodwill impairment test is required, 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

• Impairment of 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 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 group.

        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

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

Deferred Contract Costs

• Deferred Contract Cost

        The Partnership may pay consideration to a producer upon entering a long-term arrangement to provide midstream services to the producer. In such cases, the amount of consideration paid is recorded as Deferred contract cost, net of accumulated amortization on the accompanying Consolidated Balance Sheets and is amortized over the term of the arrangement.

Derivative Instruments

• Derivative Instruments

        Derivative instruments (including derivative instruments embedded in other contracts) are recorded at fair value and included in the consolidated balance sheet as assets or liabilities. Assets and liabilities related to derivative instruments with the same counterparty are not netted in the consolidated balance sheet. The Partnership discloses the fair value of 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). Changes in the fair value of derivative instruments are reported in the Statement of Operations in accounts related to the item whose value or cash flows are being managed. 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 manage 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 manage costs, typically in a keep-whole arrangement. Facility expenses gains and losses relate to a contract utilized to manage 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 Note 6). Changes in risk management activities are reported as an adjustment to net income in computing cash flow from operating activities on the accompanying Consolidated Statements of Cash Flows.

        During 2011, 2010 and 2009, the Partnership did not designate any hedges or designate any contracts as normal purchases and normal sales.

Fair Value of Financial Instruments

• 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. The recorded value of the amounts outstanding under the Credit Facility approximates fair value due to the variable interest rate that approximates current market rates. Derivative instruments are recorded at fair value, based on available market information (see Note 6). 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, 2011 and 2010 (in thousands):

	December 31, 2011				December 31, 2010
	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	1,846,062	$	1,880,710	$	1,273,434	$	1,333,875
SMR Liability		93,909		119,887		95,784		125,600

        The fair value of the long-term debt is estimated based on recent market quotes. The fair value of the SMR Liability is estimated using a discounted cash flow approach based on the contractual cash flows and the Partnership's unsecured borrowing rate.

• Fair Value Measurement

        Financial assets and liabilities recorded at fair value in the Consolidated Balance Sheet are categorized based upon a fair value hierarchy established by GAAP, which classifies the inputs used to measure fair value into the following levels:

• • •

    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 derivatives, the embedded derivatives in commodity contracts and the embedded put options discussed in Note 6 and Note 16 as they have significant unobservable inputs.

        The methods and assumptions described above may produce a fair value that may not be realized in future periods upon settlement. 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 7.

Revenue Recognition

• 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. 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 exchange 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 or fixed demand charges.

  •

  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 delivers an agreed-upon percentage of the residue gas and NGLs to the producer and sell the volumes the Partnership keeps to third parties.

  •

  Percent-of-index arrangements—Under percent-of-index arrangements, the Partnership purchases 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 then gathers and delivers the natural gas to pipelines where the Partnership resells 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 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. 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 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. 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.

        Collectability is reasonably assured.    Collectability is evaluated on a customer-by-customer basis. New and existing customers are subject to a credit review process, which evaluates a customer's financial position (e.g. cash position and credit rating) and its ability to pay. If collectability 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 customers' 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 acts as an agent and earns a fixed amount and does not take ownership of the gas and/or NGLs.

        Amounts billed to customers for shipping and handling, including fuel costs, 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.

Revenue and Expense Accruals

• 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 adjusted when actual information is received from third parties and the Partnership's internal records have been reconciled.

Incentive Compensation Plan

• Incentive Compensation Plans

        The Partnership issues phantom units under its share-based compensation plans as described further in Note 20. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. Phantom units are treated as equity awards and compensation expense is measured for these phantom unit grants based on the fair value of the units on the grant date, as defined by GAAP. 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.

Income Taxes

• 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 balances are classified as long-term in the accompanying Consolidated Balance Sheets. All changes in the tax bases of assets and liabilities are allocated among continued operations and items charged or credited directly to equity.

        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 Class A units were issued to the Corporation as part of the Merger and represent limited partner interests with the same rights as common units except that the Class A units do not have voting rights, except as required by law. Class A units are not treated as outstanding common units in the Consolidated Balance Sheet as they are eliminated in the consolidation of the Corporation. The deferred income tax component relates to the change in the temporary 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.

Earnings (Loss) Per Unit

• Earnings (Loss) Per Unit

        The Partnership's outstanding phantom units are considered to be participating securities and the Class B units are considered to be a separate class of common units that do not participate in cash distributions. 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 the Partnership, after deducting amounts that are allocable to the outstanding phantom units and Class B units, by the weighted average number of common units outstanding during the period. The amount allocable to the phantom units and Class B 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, no earnings are allocable to Class B units as they do not participate in cash distributions. 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 and Class B units is based on actual distributions to the phantom units and Class B unitholders. Diluted earnings per unit is calculated by dividing net income attributable to the Partnership, after deducting amounts allocable to the outstanding phantom units and Class B 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 net income attributable to the Partnership, after deducting amounts that are allocable to the outstanding phantom units and Class B units, is a loss as the impact would be anti-dilutive.

Business Combinations

• 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

• 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 acquires additional interest or if the subsidiary issues or repurchases its own shares. If the transaction does not result in a change in control over the subsidiary, the transaction is accounted for as an equity transaction. If a sale 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. If the purchase of additional interest occurs which changes the acquirer's ownership interest from non-controlling to controlling, the acquirer's preexisting interest in the acquiree is remeasured to its fair value, with a resulting gain or loss recorded in earnings upon consummation of the business combination. Once an entity has control of a subsidiary, its acquisitions of some or all of the noncontrolling interests in that subsidiary are accounted for as equity transactions and are not considered to be a business combination. See Note 4 for a description of the transactions that resulted in a change in the Partnership's ownership interest in a subsidiary and the impact of these transactions to the financial statements.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies

Commitments and Contingencies

18. 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 and that none of these actions, either individually or in the aggregate, will have a material adverse effect on our financial condition, liquidity or results of operation.

        In June 2006, the Pipeline and Hazardous Materials Safety Administration 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 of the Partnership, 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. In March 2011, MarkWest received an order assessing a penalty solely against Equitable for count one of the NOPV in the amount of $0.5 million and assessing a penalty jointly and severally against MarkWest and Equitable for four of the other counts in the NOPV in the amount of $0.2 million. In March 2011, the parties filed separate petitions for reconsideration. In January 2012, the Agency issued an order that dismissed the penalty assessed solely against Equitable but retained the $0.2 million penalty assessed jointly and severally against MarkWest and Equitable. MarkWest did not appeal the Agency's decision and paid the entire penalty.

• Contract Contingencies

        Certain natural gas processing arrangements in our Liberty and Northeast segments require the Partnership to construct new natural gas processing plants and NGL pipelines and contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. The Partnership has experienced a couple of months' delays in the construction of one processing facility in our Liberty Segment due to inabilities or delays in obtaining requisite permits, as well as due to extreme weather events. The requisite permits have subsequently been issued and construction has re-commenced. Delay charges could be up to $1.0 million for each month (pro-rated for partial months) that the Partnership does not achieve certain intermediate and final completion construction milestones, other than delays due to force majeure. The Partnership currently estimates the construction completion dates of the processing plant will occur approximately two months after the milestone dates specified in the applicable agreement, but the Partnership has made a force majeure claim as the delays were a direct result of permit delays and weather which are force majeure events under the applicable contract. The customer has reserved its rights to dispute the claim, but the Partnership's management believes it has a convincing legal position and believes that it is unlikely that its force majeure claim would not prevail if contested.

• Lease and Other Contractual Obligations

        The Partnership has various non-cancellable operating lease agreements and a long-term propane storage agreement expiring at various times through fiscal year 2040. Annual expense under these agreements was $15.0 million, $18.4 million and $18.6 million for the years ended December 31, 2011, 2010 and 2009, respectively. The minimum future payments under these agreements as of December 31, 2011 are as follows (in thousands):

Year ending December 31,
2012	$	10,299
2013		8,688
2014		7,793
2015		7,606
2016		7,334
2017 and thereafter		17,663
	$	59,383

• SMR Transaction

        On September 1, 2009, the Partnership entered into a product supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for all of the product processed by the SMR (see Note 5 for further discussion of this agreement and the related SMR Transaction). The product received under this agreement is sold to a refinery customer pursuant to a corresponding long-term agreement. The minimum amounts payable annually under the product supply agreement, excluding the potential impact of inflation adjustments per the agreement, are as follows (in thousands):

Year ending December 31,
2012	$	17,412
2013		17,412
2014		17,412
2015		17,412
2016		17,412
2017 and thereafter		230,029
Total minimum payments		317,089
Less: Services element		121,295
Less: Interest		101,885
Total SMR liability		93,909
Less: Current portion of SMR Liability		2,058
Long-term portion of SMR Liability	$	91,851

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Fair Value (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivative instruments carried at fair value in Condensed Consolidated Balance Sheet
Total carrying value of derivative assets in Condensed Consolidated Balance Sheet	$ 24,790	$ 4,762	$ 24,631
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheet	(155,954)	(131,779)
Recurring | Significant other observable inputs (Level 2) | Commodity contracts (net)
Derivative instruments carried at fair value in Condensed Consolidated Balance Sheet
Total carrying value of derivative assets in Condensed Consolidated Balance Sheet	5,063	52
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheet	(79,358)	(77,776)
Recurring | Significant unobservable inputs (Level 3) | Commodity contracts (net)
Derivative instruments carried at fair value in Condensed Consolidated Balance Sheet
Total carrying value of derivative assets in Condensed Consolidated Balance Sheet	12,210	3,674
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheet	(15,175)	(18,031)
Recurring | Significant unobservable inputs (Level 3) | Embedded derivatives in commodity contracts (net)
Derivative instruments carried at fair value in Condensed Consolidated Balance Sheet
Total carrying value of derivative assets in Condensed Consolidated Balance Sheet	7,517	1,036
Total carrying value of derivative liabilities in Condensed Consolidated Balance Sheet	$ (61,421)	$ (35,972)

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Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2011

Organization and Basis of Presentation

Organization and Basis of Presentation

1. Organization and Basis of Presentation

        MarkWest Energy Partners, L.P. ("MarkWest Energy Partners") was formed in January 2002 as a Delaware limited partnership. In February 2008, MarkWest Energy Partners completed its Merger with MarkWest Hydrocarbon, Inc. (the "Corporation" or "MarkWest Hydrocarbon") and MWEP, L.L.C, whereby MarkWest Hydrocarbon became a wholly-owned subsidiary of MarkWest Energy Partners. 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 and fractionator of natural gas in the Appalachian Basin and continues to expand this position through the growth of its operations in the Marcellus Shale. Finally, the Partnership owns a crude oil transportation pipeline in Michigan. The Partnership's principal executive office is located in Denver, Colorado.

        The Partnership's consolidated financial statements include all majority-owned or majority-controlled subsidiaries. In addition, MarkWest Liberty Midstream and MarkWest Pioneer, variable interest entities for which the Partnership has been determined to be the primary beneficiary, are included in the consolidated financial statements. Effective December 31, 2011, the Partnership acquired the remaining 49% interest of MarkWest Liberty Midstream. As a result, as of December 31, 2011, MarkWest Liberty Midstream is not a variable interest entity but is consolidated as a wholly-owned subsidiary (see Note 4 for further discussion of MarkWest Pioneer and MarkWest Liberty Midstream). For non-wholly-owned subsidiaries, the interests owned by third parties have been recorded as Non-controlling interest in consolidated subsidiaries in the accompanying Consolidated Balance Sheets. All significant intercompany investments, accounts and transactions have been eliminated. Investments in which the Partnership exercises significant influence but does not control, or 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.

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CONSOLIDATED BALANCE SHEETS (Parenthetical) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010
Cash and cash equivalents	$ 117,016	$ 67,450
Receivables, net	226,561	179,209
Inventories	41,006	23,432
Other current assets	11,748	8,020
Property, plant and equipment	3,302,369	2,613,027
Accumulated depreciation	438,062	294,003
Restricted cash		28,001
Other long-term assets	1,595	1,486
Accounts payable	179,871	122,473
Accrued liabilities	171,451	153,869
Other long-term liabilities	121,356	105,349
Accumulated amortization, intangibles	168,168	124,568
Accumulated amortization, deferred financing costs	13,194	11,445
Accumulated amortization, deferred contract cost	2,262	1,950
Long-term debt, discounts	1,050	1,566
Common Units
Common units issued (in units)	94,940	71,440
Common units outstanding (in units)	94,940	71,440
Class B Units
Common units issued (in units)	19,954	0
Common units outstanding (in units)	19,954	0
Total Variable Interest Entities
Cash and cash equivalents	2,684	2,913
Receivables, net	1,569	43,783
Inventories	0	8,431
Other current assets	169	272
Property, plant and equipment	156,808	849,986
Accumulated depreciation	15,551	38,169
Restricted cash	0	28,001
Other long-term assets	102	383
Accounts payable	96	5,945
Accrued liabilities	1,144	64,713
Other long-term liabilities	$ 73	$ 154

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2011

Property, Plant and Equipment

Property, Plant and Equipment

11. Property, Plant and Equipment

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

	December 31, 2011			December 31, 2010
Natural gas gathering and NGL transportation pipelines and facilities	$	2,039,524		$	1,625,170
Processing plants		660,928			584,886
Fractionation and storage facilities		120,474			81,317
Crude oil pipelines		16,678			16,810
Land, building, office equipment and other		185,462			155,437
Construction in progress		279,303			149,407
Property, plant and equipment		3,302,369			2,613,027
Less: accumulated depreciation		(438,062	)		(294,003	)
Total property, plant and equipment, net	$	2,864,307		$	2,319,024

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Supplemental Condensed Consolidating Financial Information (Details 3) (USD $) In Thousands, unless otherwise specified	1 Months Ended								12 Months Ended
	Jan. 31, 2012	Dec. 31, 2011	Oct. 31, 2011	Jul. 31, 2011	Jan. 31, 2011	Apr. 30, 2010	Aug. 31, 2009	Jun. 30, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Condensed Consolidating Statements of Cash Flows
Net cash (used in) provided by operating activities									$ 414,698	$ 312,328	$ 223,101
Cash flows from investing activities:
Restricted cash									2,006	(28,001)
Capital expenditures									(551,281)	(458,668)	(486,623)
Acquisitions									(230,728)
Equity investments											(405)
Proceeds from disposal of property, plant and equipment									3,450	733	275
Proceeds from sale of unconsolidated affiliate											25,000
Net cash flows used in investing activities									(776,553)	(485,936)	(461,753)
Cash flows from financing activities:
Proceeds from revolving credit facility									1,182,200	494,404	725,200
Payments of revolving credit facility									(1,116,200)	(553,704)	(850,600)
Proceeds from long-term debt									1,199,000	500,000	117,000
Payments of long-term debt									(693,888)	(375,000)
Payments of premiums on redemption of long-term debt									(71,377)	(9,732)
Payments for debt issuance costs, deferred financing costs and registration costs									(20,163)	(20,912)	(8,554)
Acquisition of non-controlling interest, including transaction costs									(997,601)
Contributions to joint ventures, net									126,392	158,293	194,536
Proceeds from SMR Transaction											73,129
Proceeds from sale of equity interest in joint venture, net											60,654
Payments of SMR Liability									(1,875)	(1,354)
Proceeds from public equity offerings, net	38,000	521,000	251,000	185,100	138,200	142,300	120,900	57,700	1,095,488	142,255	178,565
Share-based payment activity									(5,270)	(3,736)	(1,385)
Payment of distributions									(285,285)	(187,208)	(155,462)
Net cash flows provided by financing activities									411,421	143,306	333,083
Net increase in cash									49,566	(30,302)	94,431
Cash and cash equivalents at beginning of year	117,016				67,450				67,450	97,752	3,321
Cash and cash equivalents at end of year		117,016							117,016	67,450	97,752
Parent
Condensed Consolidating Statements of Cash Flows
Net cash (used in) provided by operating activities									(126,782)	(102,042)	(98,853)
Cash flows from investing activities:
Capital expenditures									(789)	(1,924)	(1,688)
Equity investments									(47,295)	(44,346)	(52,358)
Distributions from consolidated affiliates									50,718	41,167	13,984
Collection of (Investment in) intercompany notes, net									(37,990)	12,350	21,340
Net cash flows used in investing activities									(35,356)	7,247	(18,722)
Cash flows from financing activities:
Proceeds from revolving credit facility									1,182,200	494,404	725,200
Payments of revolving credit facility									(1,116,200)	(553,704)	(850,600)
Proceeds from long-term debt									1,199,000	500,000	117,000
Payments of long-term debt									(693,888)	(375,000)
Payments of premiums on redemption of long-term debt									(71,377)	(9,732)
Payments for debt issuance costs, deferred financing costs and registration costs									(20,163)	(20,912)	(8,054)
Acquisition of non-controlling interest, including transaction costs									(997,601)
Contributions to joint ventures, net											(5,464)
Proceeds from sale of equity interest in joint venture, net											(1,846)
Proceeds from public equity offerings, net									1,095,488	142,255	178,565
Share-based payment activity									(6,354)	(3,834)	(1,385)
Payment of distributions									(218,398)	(181,058)	(155,307)
Intercompany advances, net									(190,547)	102,376	119,466
Net cash flows provided by financing activities									162,160	94,795	117,575
Net increase in cash									22
Cash and cash equivalents at end of year		22							22
Guarantor Subsidiaries
Condensed Consolidating Statements of Cash Flows
Net cash (used in) provided by operating activities									410,762	373,483	322,540
Cash flows from investing activities:
Capital expenditures									(162,517)	(123,005)	(209,485)
Acquisitions									(230,728)
Equity investments									(252,367)	(171,252)	(127,806)
Distributions from consolidated affiliates									68,651	22,246	31,227
Proceeds from disposal of property, plant and equipment									606	733	275
Proceeds from sale of equity interest in consolidated subsidiary											62,500
Proceeds from sale of unconsolidated affiliate											25,000
Net cash flows used in investing activities									(576,355)	(271,278)	(218,289)
Cash flows from financing activities:
Proceeds (Payments) of intercompany notes, net									14,990	(12,350)	(21,340)
Payments for debt issuance costs, deferred financing costs and registration costs											(500)
Contributions from parent, net									47,295	44,346	52,358
Proceeds from SMR Transaction											73,129
Payments of SMR Liability									(1,875)	(1,354)
Share-based payment activity									1,084	98
Payment of distributions									(50,718)	(41,167)	(13,984)
Intercompany advances, net									190,547	(102,376)	(119,466)
Net cash flows provided by financing activities									201,323	(112,803)	(29,803)
Net increase in cash									35,730	(10,598)	74,448
Cash and cash equivalents at beginning of year					63,850				63,850	74,448
Cash and cash equivalents at end of year		99,580							99,580	63,850	74,448
Non-Guarantor Subsidiaries
Condensed Consolidating Statements of Cash Flows
Net cash (used in) provided by operating activities									137,961	46,852	5,249
Cash flows from investing activities:
Restricted cash									2,006	(28,001)
Capital expenditures									(399,992)	(347,231)	(281,285)
Proceeds from disposal of property, plant and equipment									7,617	7,527
Net cash flows used in investing activities									(390,369)	(367,705)	(281,285)
Cash flows from financing activities:
Proceeds (Payments) of intercompany notes, net									23,000
Contributions to joint ventures, net									378,759	329,545	327,401
Payment of distributions									(135,537)	(28,396)	(31,382)
Net cash flows provided by financing activities									266,222	301,149	296,019
Net increase in cash									13,814	(19,704)	19,983
Cash and cash equivalents at beginning of year					3,600				3,600	23,304	3,321
Cash and cash equivalents at end of year		17,414							17,414	3,600	23,304
Consolidating Adjustments
Condensed Consolidating Statements of Cash Flows
Net cash (used in) provided by operating activities									(7,243)	(5,965)	(5,835)
Cash flows from investing activities:
Capital expenditures									12,017	13,492	5,835
Equity investments									299,662	215,598	179,759
Distributions from consolidated affiliates									(119,369)	(63,413)	(45,211)
Collection of (Investment in) intercompany notes, net									37,990	(12,350)	(21,340)
Proceeds from disposal of property, plant and equipment									(4,773)	(7,527)
Proceeds from sale of equity interest in consolidated subsidiary											(62,500)
Net cash flows used in investing activities									225,527	145,800	56,543
Cash flows from financing activities:
Proceeds (Payments) of intercompany notes, net									(37,990)	12,350	21,340
Contributions from parent, net									(47,295)	(44,346)	(52,358)
Contributions to joint ventures, net									(252,367)	(171,252)	(127,401)
Proceeds from sale of equity interest in joint venture, net											62,500
Payment of distributions									119,368	63,413	45,211
Net cash flows provided by financing activities									$ (218,284)	$ (139,835)	$ (50,708)

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Supplemental Condensed Consolidating Financial Information (Details) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Current assets:
Cash and cash equivalents	$ 117,016	$ 67,450	$ 97,752	$ 3,321
Restricted cash	26,193
Receivables and other current assets	294,200	226,751
Fair value of derivative instruments	8,698	4,345
Total current assets	446,107	298,546
Total property, plant and equipment, net	2,864,307	2,319,024
Other long-term assets:
Restricted cash		28,001
Investment in unconsolidated affiliate	27,853	28,688	29,633
Intangibles, net of accumulated amortization	603,767	613,578
Fair value of derivative instruments	16,092	417
Other long-term assets	112,299	45,108
Total assets	4,070,425	3,333,362	3,014,737
Current liabilities:
Fair value of derivative instruments	90,551	65,489
Other current liabilities	351,322	276,353
Total current liabilities	441,873	341,842
Deferred income taxes	93,664	87,881
Fair value of derivative instruments	65,403	66,290
Long-term debt, net of discounts	1,846,062	1,273,434
Other long-term liabilities	121,356	105,349
Equity:
Common units	679,309	993,049
Non-controlling interest in consolidated subsidiaries	70,227	465,517
Total equity	1,502,067	1,458,566	1,309,553	1,148,155
Total liabilities and equity	4,070,425	3,333,362
Common Units
Equity:
Common units	679,309	993,049
Total equity	679,309	993,049	1,026,814	1,144,854
Class B Units
Equity:
Common units	752,531
Total equity	752,531
Parent
Current assets:
Cash and cash equivalents	22
Receivables and other current assets	7,097	1,708
Intercompany receivables	19,981	1,440,302
Total current assets	27,100	1,442,010
Total property, plant and equipment, net	4,012	4,623
Other long-term assets:
Investment in consolidated affiliates	3,071,124	639,219
Intercompany notes receivable	235,700	197,710
Other long-term assets	41,492	32,587
Total assets	3,379,428	2,316,149
Current liabilities:
Intercompany payables	40,503	672
Other current liabilities	38,775	31,882
Total current liabilities	79,278	32,554
Deferred income taxes	1,228	2,533
Long-term debt, net of discounts	1,846,062	1,273,434
Other long-term liabilities	3,232	3,319
Equity:
Common units		1,004,309
Total equity	1,449,628	1,004,309
Total liabilities and equity	3,379,428	2,316,149
Parent | Common Units
Equity:
Common units	697,097
Parent | Class B Units
Equity:
Common units	752,531
Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	99,580	63,850	74,448
Receivables and other current assets	232,010	172,209
Intercompany receivables	40,519	1,099
Fair value of derivative instruments	8,015	4,345
Total current assets	380,124	241,503
Total property, plant and equipment, net	1,714,857	1,512,763
Other long-term assets:
Investment in unconsolidated affiliate	27,853	28,688
Investment in consolidated affiliates	1,097,350	368,864
Intangibles, net of accumulated amortization	603,224	613,000
Fair value of derivative instruments	16,092	417
Other long-term assets	70,434	12,139
Total assets	3,909,934	2,777,374
Current liabilities:
Intercompany payables	40,374	1,447,799
Fair value of derivative instruments	90,551	65,489
Other current liabilities	219,622	173,667
Total current liabilities	350,547	1,686,955
Deferred income taxes	92,436	85,348
Intercompany notes payable	212,700	197,710
Fair value of derivative instruments	65,403	66,290
Other long-term liabilities	117,724	101,852
Equity:
Common units		639,219
Total equity	3,071,124	639,219
Total liabilities and equity	3,909,934	2,777,374
Guarantor Subsidiaries | Common Units
Equity:
Common units	3,071,124
Non-Guarantor Subsidiaries
Current assets:
Cash and cash equivalents	17,414	3,600	23,304	3,321
Restricted cash	26,193
Receivables and other current assets	55,098	52,834
Intercompany receivables	22,193	7,635
Fair value of derivative instruments	683
Total current assets	121,581	64,069
Total property, plant and equipment, net	1,163,226	812,898
Other long-term assets:
Restricted cash		28,001
Intangibles, net of accumulated amortization	543	578
Other long-term assets	373	382
Total assets	1,285,723	905,928
Current liabilities:
Intercompany payables	1,816	565
Other current liabilities	92,930	70,804
Total current liabilities	94,746	71,369
Intercompany notes payable	23,000
Other long-term liabilities	400	178
Equity:
Common units		834,381
Total equity	1,167,577	834,381
Total liabilities and equity	1,285,723	905,928
Non-Guarantor Subsidiaries | Common Units
Equity:
Common units	1,167,577
Consolidating Adjustments
Current assets:
Receivables and other current assets	(5)
Intercompany receivables	(82,693)	(1,449,036)
Total current assets	(82,698)	(1,449,036)
Total property, plant and equipment, net	(17,788)	(11,260)
Other long-term assets:
Investment in consolidated affiliates	(4,168,474)	(1,008,083)
Intercompany notes receivable	(235,700)	(197,710)
Total assets	(4,504,660)	(2,666,089)
Current liabilities:
Intercompany payables	(82,693)	(1,449,036)
Other current liabilities	(5)
Total current liabilities	(82,698)	(1,449,036)
Intercompany notes payable	(235,700)	(197,710)
Equity:
Common units		(1,484,860)
Non-controlling interest in consolidated subsidiaries	70,227	465,517
Total equity	(4,186,262)	(1,019,343)
Total liabilities and equity	(4,504,660)	(2,666,089)
Consolidating Adjustments | Common Units
Equity:
Common units	$ (4,256,489)

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Document and Entity Information (USD $) In Billions, except Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Jun. 30, 2011	Feb. 17, 2012 Common Units	Feb. 17, 2012 Class B Units
Entity Registrant Name	MARKWEST ENERGY PARTNERS L P
Entity Central Index Key	0001166036
Document Type	10-K
Document Period End Date	Dec. 31, 2011
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 3.6
Entity Common Stock, Shares Outstanding			95,908,615	19,954,389
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	FY

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Goodwill and Intangible Assets

12 Months Ended

Dec. 31, 2011

Goodwill and Intangible Assets

Goodwill and Intangible Assets

12. Goodwill and Intangible Assets

        Goodwill.    The table below shows the gross amount of goodwill acquired and the cumulative impairment loss recognized as of December 31, 2011 (in thousands). There was no activity related to goodwill during 2009 or 2010.

	Southwest			Northeast		Gulf Coast			Total
Gross goodwill as of December 31, 2010	$	24,324		$	3,948	$	9,854		$	38,126
Acquisition(1)		—			58,497		—			58,497
Gross Goodwill as of December 31, 2011		24,324			62,445		9,854			96,623
Cumulative impairment(2)		(18,851	)		—		(9,854	)		(28,705	)
Balance as of December 31, 2011	$	5,473		$	62,445	$	—		$	67,918

(1)

Represents goodwill associated with the Langley Acquisition (see Note 3).

(2)

All impairments recorded in the fourth quarter of 2008.

        Intangible Assets.    The Partnership's intangible assets as of December 31, 2011 and 2010 are comprised of customer contracts and relationships, as follows (in thousands):

	December 31, 2011							December 31, 2010
Description	Gross		Accumulated Amortization			Net		Gross		Accumulated Amortization			Net		Useful Life
Southwest	$	406,690	$	(92,340	)	$	314,350	$	406,801	$	(69,655	)	$	337,146	10 - 20 yrs
Northeast		102,473		(29,037	)		73,436		68,573		(19,590	)		48,983	12 yrs
Gulf Coast		262,772		(46,791	)		215,981		262,772		(35,323	)		227,449	20 - 25 yrs
Total	$	771,935	$	(168,168	)	$	603,767	$	738,146	$	(124,568	)	$	613,578

        Estimated future amortization expense related to the intangible assets at December 31, 2011 is as follows (in thousands):

Year ending December 31,
2012	$	43,940
2013		43,940
2014		43,940
2015		43,940
2016		43,940
Thereafter		384,067
	$	603,767

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Equity (Details) (USD $) In Thousands, except Share data, unless otherwise specified	1 Months Ended								3 Months Ended												12 Months Ended
	Jan. 31, 2012	Dec. 31, 2011	Oct. 31, 2011	Jul. 31, 2011	Jan. 31, 2011	Apr. 30, 2010	Aug. 31, 2009	Jun. 30, 2009	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Distributions of Available Cash
Declaration Date									January 26, 2012	October 18, 2011	July 21, 2011	April 21, 2011	January 27, 2011	October 27, 2010	July 22, 2010	April 22, 2010	January 26, 2010	October 22, 2009	July 23, 2009	April 23, 2009
Record Date									February 6, 2012	November 7, 2011	August 1, 2011	May 2, 2011	February 7, 2011	November 8, 2010	August 2, 2010	May 3, 2010	February 5, 2010	November 2, 2009	August 3, 2009	May 4, 2009
Payment Date									February 14, 2012	November 14, 2011	August 12, 2011	May 13, 2011	February 14, 2011	November 12, 2010	August 13, 2010	May 14, 2010	February 12, 2010	November 13, 2009	August 14, 2009	May 15, 2009
Distribution per common unit (in dollars per unit)									$ 0.76	$ 0.73	$ 0.70	$ 0.67	$ 0.65	$ 0.64	$ 0.64	$ 0.64	$ 0.64	$ 0.64	$ 0.64	$ 0.64	$ 2.75	$ 2.56	$ 2.56
Equity Offerings
Issuance of units in public offerings, net of offering costs (in units)	700,000	10,000,000	5,750,000	4,000,000	3,450,000	4,900,000	6,030,000	3,340,000
Net proceeds from public offering after deducting underwriters fees and other third-party expenses	$ 38,000	$ 521,000	$ 251,000	$ 185,100	$ 138,200	$ 142,300	$ 120,900	$ 57,700													$ 1,095,488	$ 142,255	$ 178,565
Percentage of non-controlling interest acquired by the Partnership		49.00%							49.00%												49.00%
MarkWest Liberty Midstream
Class B Units Issuance
Non-controlling interest purchase consideration, shares																					19,954,000
Equity Offerings
Percentage of non-controlling interest acquired by the Partnership		49.00%							49.00%												49.00%
Class B Units
Class B Units Issuance
Non-controlling interest purchase consideration, shares																					19,954,000
Partner's units conversion basis																					1
Number of installments in which partner's units are converted																					5
Number of anniversaries of July 31, 2013 on which Class B units will be converted into common units																					4
Limited partners' capital account, units authorized for distribution		2,500,000							2,500,000												2,500,000
Minimum
Class B Units Issuance
Number of offerings in any twelve month period																					1
Maximum
Equity
Period after the end of each quarter within which available cash is distributed to unitholders (in days)																					45
Period for which cash reserves are created for distribution to unitholders (in quarters)																					4
Class B Units Issuance
Participation in underwritten offerings as percentage of common stock offered																					20.00%
Number of underwritten offerings																					3
Maximum | Class B Units
Class B Units Issuance
Partner's unit voting rights based on specified percentage of total common units																					0.05

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Segment Information (Details 3) (USD $) In Thousands, unless otherwise specified	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Segment Assets
Certain cash and cash equivalents	$ 117,016	$ 67,450	$ 97,752	$ 3,321
Fair value of derivatives	24,790	4,762	24,631
Investment in unconsolidated affiliate	27,853	28,688	29,633
Total assets	4,070,425	3,333,362	3,014,737
Total reportable segments
Segment Assets
Total assets	3,903,207	3,208,225	2,848,510
Southwest Segment
Segment Assets
Total assets	1,701,919	1,646,607	1,637,749
Northeast Segment
Segment Assets
Total assets	533,591	244,219	249,804
Liberty Segment
Segment Assets
Total assets	1,114,654	743,943	373,127
Gulf Coast Segment
Segment Assets
Total assets	553,043	573,456	587,830
Unallocated Segment
Segment Assets
Certain cash and cash equivalents	66,212	49,776	73,184
Fair value of derivatives	24,790	4,762	24,631
Investment in unconsolidated affiliate	27,853	28,688	29,633
Other	$ 48,363	$ 41,911	$ 38,779

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Thousands, except Per Share data, unless otherwise specified	3 Months Ended												12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2009	Sep. 30, 2009	Jun. 30, 2009	Mar. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenue:
Revenue													$ 1,534,434	$ 1,241,563	$ 858,635
Derivative loss													(29,035)	(53,932)	(120,352)
Total revenue	333,913	507,826	400,439	263,221	299,991	255,411	323,850	308,379					1,505,399	1,187,631	738,283
Operating expenses:
Purchased product costs													682,370	578,627	408,826
Derivative loss related to purchased product costs													52,960	27,713	68,883
Facility expenses													173,598	151,449	126,977
Derivative gain related to facility expenses													(6,480)	(1,295)	(373)
Selling, general and administrative expenses													81,229	75,258	63,728
Depreciation													149,954	123,198	95,537
Amortization of intangible assets													43,617	40,833	40,831
Loss on disposal of property, plant and equipment													8,797	3,149	1,677
Accretion of asset retirement obligations													1,190	237	198
Impairment of goodwill and long-lived assets															5,855
Total operating expenses													1,187,235	999,169	812,139
Income (loss) from operations	(7,557)	207,801	133,214	(15,294)	25,172	646	109,071	53,573					318,164	188,462	(73,856)
Other income (expense):
(Loss) earnings from unconsolidated affiliates													(1,095)	1,562	3,505
Gain on sale of unconsolidated affiliate															6,801
Interest income													422	1,670	349
Interest expense													(113,631)	(103,873)	(87,419)
Amortization of deferred financing costs and discount (a component of interest expense)													(5,114)	(10,264)	(9,718)
Derivative gain related to interest expense														1,871	2,509
Loss on redemption of debt	(35,500)			(43,300)	(46,300)								(78,996)	(46,326)
Miscellaneous income, net													144	1,189	2,459
Income (loss) before provision for income tax													119,894	34,291	(155,370)
Provision for income tax expense (benefit):
Current													17,578	7,655	8,072
Deferred													(3,929)	(4,466)	(50,088)
Total provision for income tax													13,649	3,189	(42,016)
Net income (loss)	(61,743)	153,454	89,205	(74,671)	(43,194)	(18,676)	66,968	26,004					106,245	31,102	(113,354)
Net income attributable to non-controlling interest													(45,550)	(30,635)	(5,314)
Net income (loss) attributable to the Partnership	$ (74,085)	$ 140,312	$ 78,497	$ (84,029)	$ (54,109)	$ (27,151)	$ 60,217	$ 21,510					$ 60,695	$ 467	$ (118,668)
Net income (loss) attributable to the Partnership's common unitholders per common unit (Note 23):
Basic (in dollars per unit)	$ (0.87)	$ 1.77	$ 1.03	$ (1.13)	$ (0.76)	$ (0.39)	$ 0.84	$ 0.32					$ 0.75	$ (0.01)	$ (1.97)
Diluted (in dollars per unit)	$ (0.87)	$ 1.77	$ 1.03	$ (1.13)	$ (0.76)	$ (0.39)	$ 0.84	$ 0.32					$ 0.75	$ (0.01)	$ (1.97)
Weighted average number of outstanding common units:
Basic (in units)													78,466	70,128	60,957
Diluted (in units)													78,619	70,128	60,957
Cash distribution declared per common unit (in dollars per unit)	$ 0.76	$ 0.73	$ 0.70	$ 0.67	$ 0.65	$ 0.64	$ 0.64	$ 0.64	$ 0.64	$ 0.64	$ 0.64	$ 0.64	$ 2.75	$ 2.56	$ 2.56

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Derivative Financial Instruments

12 Months Ended

Dec. 31, 2011

Derivative Financial Instruments

Derivative Financial Instruments

6. Derivative Financial Instruments

• Commodity Contracts

        NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond the Partnership's control. The Partnership's profitability is directly affected by prevailing commodity prices primarily as a result of processing or conditioning at its or third-party processing plants, purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and the cost of third-party transportation and fractionation services. To the extent that commodity prices influence the level of drilling activity, such prices also affect profitability. To protect itself financially against adverse price movements and to maintain more stable and predictable cash flows so the Partnership can meet its cash distribution objectives, debt service requirements and fund its capital expenditures, the Partnership executes a strategy governed by the risk management policy approved by the Board. The Partnership has a committee comprised of senior management that oversees risk management activities, continually monitors the risk management program and adjusts its strategy as conditions warrant. The Partnership enters into certain derivative contracts to reduce the risks associated with unfavorable changes in the prices of natural gas, NGLs and crude oil. Derivative contracts utilized are swaps, options and fixed price forward contracts traded on the OTC market. The risk management policy does not allow for trading derivative contracts.

        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. Generally the Partnership manages its NGL price risk using crude oil as NGL financial markets lack adequate liquidity and historically there has been a strong relationship between changes in NGL and crude oil prices. The pricing relationship between NGLs and crude oil may vary in certain periods due to various market conditions. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the Partnership incurs increased risk and additional gains or losses. The Partnership enters into NGL derivative contracts when adequate market liquidity exists.

        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 and takes into account the partial offset of its long and short gas positions resulting from normal operating activities.

        As a result of its derivative positions outstanding on December 31, 2011, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2014. The Partnership would be exposed to additional commodity risk in certain situations that include, but are not limited to, when producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions will be terminated.

        The Partnership enters into derivative contracts primarily with financial institutions that are participating members of the amended and restated credit agreement as collateral is not posted by the Partnership as the participating members have a collateral position in substantially all the wholly-owned assets of the Partnership other than MarkWest Liberty Midstream. All of the Partnership's financial derivative positions are currently with participating bank group members. Management conducts a standard credit review on counterparties and the Partnership has agreements containing collateral requirements. For all participating bank group members, collateral requirements do not exist when a derivative contract favors the Partnership. The Partnership uses standardized agreements that allow for offset of positive and negative exposures (master netting arrangements).

        The Partnership records derivative contracts at fair value in the Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation which may cause volatility in the Statement of Operations as the Partnership recognizes in current earnings all unrealized gains and losses from the changes in the fair value of its derivatives.

• Embedded Derivative in Debt Contract

        On May 26, 2009, the Partnership completed the private placement of senior notes with contingent written put options as described in Note 16. The written put options were considered embedded derivatives and were not considered clearly and closely related to the indenture governing the notes. When a hybrid contract contains multiple embedded derivatives requiring separate accounting, the embedded derivatives must be aggregated and accounted for as a compound embedded derivative. These senior notes were redeemed in the fourth quarter of 2010 and the put options no longer exist as of December 31, 2010.

• 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.

        During the first quarter of 2010, the Partnership terminated all of its outstanding interest rate swap contracts. The financial statement impact is disclosed in the tables below.

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

	Assets				Liabilities
Derivative contracts not designated as hedging instruments and their balance sheet location	Fair Value at December 31, 2011		Fair Value at December 31, 2010		Fair Value at December 31, 2011			Fair Value at December 31, 2010
Commodity contracts(1)
Fair value of derivative instruments—current	$	8,698	$	4,345	$	(90,551	)	$	(65,489	)
Fair value of derivative instruments—long-term		16,092		417		(65,403	)		(66,290	)
Total	$	24,790	$	4,762	$	(155,954	)	$	(131,779	)

(1)

Includes Embedded Derivatives in Commodity Contracts as discussed below.

	Year ended December 31,
Derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in income	2011			2010			2009
Revenue: Derivative loss
Realized (loss) gain	$	(48,093	)	$	(33,560	)	$	87,289
Unrealized gain (loss)		19,058			(20,372	)		(207,641	)
Total revenue: derivative loss		(29,035	)		(53,932	)		(120,352	)
Derivative loss related to purchased product costs
Realized loss		(27,711	)		(21,909	)		(53,052	)
Unrealized loss		(25,249	)		(5,804	)		(15,831	)
Total derivative loss related to purchase product costs		(52,960	)		(27,713	)		(68,883	)
Derivative gain related to facility expenses
Unrealized gain		6,480			1,295			373
Derivative gain related to interest expense
Realized gain		—			2,380			2,000
Unrealized (loss) gain		—			(509	)		509
Total derivative gain related to interest expense		—			1,871			2,509
Miscellaneous income, net
Unrealized gain		—			190			336
Total loss	$	(75,515	)	$	(78,289	)	$	(186,017	)

        At December 31, 2011 and 2010, the fair value of the Partnership's commodity derivative contracts is inclusive of premium payments of zero and $4.4 million, net of amortization, respectively. For 2011, 2010 and 2009, the Realized (loss) gain—revenue includes amortization of premium payments of $4.4 million, $3.3 million and $5.7 million, respectively.

        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 Revenue: Derivative loss and $11.3 million of loss included in Derivative loss related to purchased product costs in the accompanying Consolidated Statements of Operations.

• Volume of Derivative Activity

        As of December 31, 2011, the Partnership had the following outstanding commodity contracts that were executed to manage the cash flow risk associated with future sales of NGLs or future purchases of natural gas.

Derivative contracts not designated as hedging instruments	Position	Notional Quantity (net)
Crude Oil (bbl)	Short		8,244,902
Natural Gas (MMBtu)	Long		16,021,887
NGLs (gal)	Short		86,563,841

• Embedded Derivatives in Commodity Contracts

        The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative loss related to purchased product costs. In February 2011, the Partnership executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer's option to extend the agreement for successive five year terms through December 31, 2032. As of December 31, 2011, the estimated fair value of this contract was a liability of $114.9 million and the recorded value was a liability of $61.4 million. The recorded liability does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and, therefore, not recorded as a derivative liability. See the following table for a reconciliation of the liability recorded for the embedded derivative as of December 31, 2011 (in thousands).

Fair value of commodity contract	$	114,928
Inception value for period from April 1, 2015 to December 31, 2022.		(53,507	)
Derivative liability as of December 31, 2011	$	61,421

        The Partnership has a commodity contract that gives it an option to fix a component of the utilities cost to an index price on electricity at its plant location in the Gulf Coast segment through the fourth quarter of 2014. Changes in the fair value of the derivative component of this contract are recognized as Derivative gain related to facility expenses. As of December 31, 2011 and 2010, the estimated fair value of this contract was an asset of $7.5 million and $1.0 million, respectively.

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Divestitures

12 Months Ended

Dec. 31, 2011

Divestitures

Divestitures

5. Divestitures

• SMR Transaction

        On September 1, 2009, the Partnership completed the sale of the steam methane reformer ("SMR Transaction") the Partnership began constructing 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 completed the construction of the SMR. The Partnership and the purchaser also executed a related product supply agreement under which the Partnership will receive all of the product produced by the SMR through 2030 in exchange for processing fees and the reimbursement of certain other expenses. The processing fee payments began when the SMR commenced operations 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 estimated costs incurred by the buyer to complete construction ("SMR Liability"). The Partnership imputes interest on the SMR Liability at 9.35% annually, its incremental borrowing rate at transaction consummation. The accrued interest on the SMR Liability was capitalized until the SMR commenced operations and the Partnership began payment of the processing fee under the product supply agreement. Each processing fee payment has 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, 2011 and 2010, the following amounts related to the SMR are included in the accompanying Consolidated Balance Sheets (in thousands):

	December 31, 2011		December 31, 2010
ASSETS
Property, plant and equipment, net of accumulated depreciation of $9,658 and $4,390, respectively	$	95,705	$	100,973
LIABILITIES
Accrued liabilities	$	2,058	$	1,875
Other long-term liabilities		91,851		93,909

• Sale of Starfish

        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 purchase price of $25.0 million. The Partnership recorded a $6.8 million gain on the sale of its equity interest in Starfish.

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Equity

12 Months Ended

Dec. 31, 2011

Equity

Equity

17. Equity

        The Partnership Agreement stipulates the circumstances under which the Partnership is authorized to issue new capital, maintain capital accounts and distribute cash and 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 has the discretion to establish cash reserves 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 up to the next four quarters.

        The quarterly cash distributions applicable to 2011, 2010 and 2009 were as follows:

Quarter Ended	Distribution Per Common Unit		Declaration Date		Record Date		Payment Date
December 31, 2011	$	0.76		January 26, 2012		February 6, 2012		February 14, 2012
September 30, 2011	$	0.73		October 18, 2011		November 7, 2011		November 14, 2011
June 30, 2011	$	0.70		July 21, 2011		August 1, 2011		August 12, 2011
March 31, 2011	$	0.67		April 21, 2011		May 2, 2011		May 13, 2011
December 31, 2010	$	0.65		January 27, 2011		February 7, 2011		February 14, 2011
September 30, 2010	$	0.64		October 27, 2010		November 8, 2010		November 12, 2010
June 30, 2010	$	0.64		July 22, 2010		August 2, 2010		August 13, 2010
March 31, 2010	$	0.64		April 22, 2010		May 3, 2010		May 14, 2010
December 31, 2009	$	0.64		January 26, 2010		February 5, 2010		February 12, 2010
September 30, 2009	$	0.64		October 22, 2009		November 2, 2009		November 13, 2009
June 30, 2009	$	0.64		July 23, 2009		August 3, 2009		August 14, 2009
March 31, 2009	$	0.64		April 23, 2009		May 4, 2009		May 15, 2009

• Equity Offerings

        On June 10, 2009, the Partnership completed a public offering of approximately 3.34 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option. Net proceeds after deducting underwriters' fees and other third-party expenses were approximately $57.7 million.

        On August 18, 2009, the Partnership completed a public offering of approximately 6.03 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option. Net proceeds after deducting underwriters' fees and other third-party expenses were approximately $120.9 million.

        On April 6, 2010, the Partnership completed a public offering of approximately 4.9 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option. Net proceeds after deducting underwriters' fees and other third-party expenses were approximately $142.3 million.

        On January 14, 2011, the Partnership completed a public offering of approximately 3.45 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriter's over-allotment option. Net proceeds after deducting underwriter's fees and other third-party expenses were approximately $138.2 million and were used to partially fund the ongoing capital expenditure program, including a portion of the costs associated with the Langley Acquisition.

        On July 13, 2011, the Partnership completed a public offering of approximately 4.0 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option. Net proceeds after deducting underwriters' fees and other third-party expenses were approximately $185.1 million.

        On October 13, 2011, the Partnership completed a public offering of approximately 5.75 million newly issued common units representing limited partner interests, which includes the full exercise of the underwriters' over-allotment option. Net proceeds after deducting underwriters' fees and other third-party expenses were approximately $251 million.

        On December 19, 2011, we completed a public offering of 10.0 million newly issued common units representing limited partner interests. Total net proceeds of approximately $521 million were used to partially fund the cash consideration to acquire the remaining 49% interest in MarkWest Liberty Midstream. On January 13, 2012, we issued an additional 0.7 million units to cover the exercise of the underwriters' over-allotment option. Total net proceeds of approximately $38 million were used to fund our growth capital program.

        Net proceeds from equity offerings, unless specifically identified otherwise, were used to repay borrowings under the Credit Facility and to provide working capital for general partnership purposes.

• Class B Units Issuance

        The Partnership issued approximately 19,954,000 Class B units to M&R as part of our acquisition of the non-controlling interest in MarkWest Liberty Midstream which was effective December 31, 2011. See Note 4 for further discussion of the acquisition. The Class B units will convert to common units on a one-for-one basis in five equal installments beginning on July 1, 2013 and each of the first four anniversaries of such date. Class B units (i) are not entitled to participate in any distributions of available cash prior to their conversion and (ii) 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) other than those matters that disproportionately and adversely affect the rights and preferences of the Class B units. Upon conversion of the Class B units, M&R's right to vote as a common unitholder of the Partnership will be limited to a maximum of 5% of the Partnership's outstanding Common Units. Once converted, M&R has the right to participate in underwritten offerings undertaken by the Partnership up to 20% of the total number of common units offered. M&R also has limited rights to distribute an aggregate of 2,500,000 common units to its members and their limited partners beginning in 2016, and EMG Liberty and certain of its affiliates will have the right to demand that we conduct up to three underwritten offerings beginning in 2017, but restricted to no more than one offering in any twelve-month period. Except as described above, M&R is not permitted to transfer its Class B units or Converted Units without the prior written consent of the Board.

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Impairment of Long-Lived Assets

12 Months Ended

Dec. 31, 2011

Impairment of Long-Lived Assets

Impairment of Long-Lived Assets

13. Impairment of 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 a segment level and at lower levels where cash flows for specific assets can be identified.

        An analysis completed during 2009 indicated that the future estimated operating cash flows could be at or below zero for Wirth Gathering. Wirth Gathering'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 expense.

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Employee Benefit Plan (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Employee Benefit Plan
Employer matching contribution expense related to defined contribution benefit plan	$ 2.7	$ 2.3	$ 1.8

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Receivables

12 Months Ended

Dec. 31, 2011

Receivables

Receivables

9. Receivables

        Receivables consist of the following (in thousands):

	December 31, 2011		December 31, 2010
Trade, net	$	221,343	$	174,216
Other		5,218		4,993
Total receivables	$	226,561	$	179,209

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Quarterly Results of Operations (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2011

Quarterly Results of Operations (Unaudited)

Summary of quarterly results of operations

	Three months ended
	March 31(1)			June 30		September 30		December 31(2)
2011
Total revenue	$	263,221		$	400,439	$	507,826	$	333,913
(Loss) income from operations		(15,294	)		133,214		207,801		(7,557	)
Net (loss) income		(74,671	)		89,205		153,454		(61,743	)
Net (loss) income attributable to the Partnership		(84,029	)		78,497		140,312		(74,085	)
Net (loss) income attributable to the Partnership's common unitholders per common unit(4):
Basic	$	(1.13	)	$	1.03	$	1.77	$	(0.87	)
Diluted	$	(1.13	)	$	1.03	$	1.77	$	(0.87	)

	Three months ended
	March 31		June 30		September 30			December 31(3)
2010
Total revenue	$	308,379	$	323,850	$	255,411		$	299,991
Income from operations		53,573		109,071		646			25,172
Net income (loss)		26,004		66,968		(18,676	)		(43,194	)
Net income (loss) attributable to the Partnership		21,510		60,217		(27,151	)		(54,109	)
Net income (loss) attributable to the Partnership's common unitholders per common unit(4):
Basic	$	0.32	$	0.84	$	(0.39	)	$	(0.76	)
Diluted	$	0.32	$	0.84	$	(0.39	)	$	(0.76	)

(1)

During the first quarter of 2011, the Partnership recorded a loss on redemption of debt of approximately $43.3 million related to the repurchase of the 2016 Senior Notes and a portion of 2018 Senior Notes. See Note 16 for further details.

(2)

During the fourth quarter of 2011, the Partnership recorded a loss on redemption of debt of approximately $35.5 million related to the repurchase of a portion of the 2018 Senior Notes. See Note 16 for further details.

(3)

During the fourth quarter of 2010, the Partnership recorded a loss on redemption of debt of approximately $46.3 million related to the redemption of the 2014 Senior Notes. See Note 16 for further details.

(4)

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.

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Fair Value

12 Months Ended

Dec. 31, 2011

Fair Value

Fair Value

7. Fair Value

Fair Value Measurement

        Fair value measurements and disclosures relate primarily to the Partnership's derivative positions discussed in Note 6. See Note 2 for a description of the guidance and the fair value hierarchy.

        The derivative contracts are measured at fair value on a recurring basis and classified within Level 2 and Level 3 of the valuation hierarchy. The Level 2 and Level 3 measurements are obtained using a market approach. LIBOR rates are an observable input for the measurement of all derivative contracts. The measurements for all commodity contracts contain observable inputs in the form of forward prices based on WTI crude oil prices; Columbia Appalachia, Henry Hub, PEPL and Houston Ship Channel natural gas prices; Mont Belvieu and Conway NGL prices; and ERCOT electricity prices. Level 2 instruments include crude oil and natural gas swap contracts. The valuations are based on the appropriate commodity prices and contain no significant unobservable inputs. Level 3 instruments include crude oil options, all NGL transactions, embedded derivatives in commodity contracts and the embedded put options. The significant unobservable inputs for crude oil options, NGL transactions and embedded derivatives in commodity contracts include option volatilities and commodity prices interpolated and extrapolated due to inactive markets. The significant unobservable inputs for the embedded put options are option volatilities and management's assumptions about the probability of specific events occurring in the future. The following table presents the financial instruments carried at fair value as of December 31, 2011 and 2010, and by the valuation hierarchy (in thousands):

As of December 31, 2011	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	5,063	$	(79,358	)
Significant unobservable inputs (Level 3)
Commodity contracts		12,210		(15,175	)
Embedded derivatives in commodity contracts		7,517		(61,421	)
Total carrying value in Consolidated Balance Sheet	$	24,790	$	(155,954	)

As of December 31, 2010	Assets		Liabilities
Significant other observable inputs (Level 2)
Commodity contracts	$	52	$	(77,776	)
Significant unobservable inputs (Level 3)
Commodity contracts		3,674		(18,031	)
Embedded derivatives in commodity contracts		1,036		(35,972	)
Total carrying value in Consolidated Balance Sheet	$	4,762	$	(131,779	)

Changes in Level 3 Fair Value Measurements

        The tables below include a rollforward of the balance sheet amounts for the years ended December 31, 2011 and 2010 (including the change in fair value) for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands):

	Year Ended December 31, 2011
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(14,357	)	$	(34,936	)
Total gain or loss (realized and unrealized) included in earnings(1)		3,182			(30,827	)
Settlements		8,210			11,859
Fair value at end of period	$	(2,965	)	$	(53,904	)
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at end of period	$	6,241		$	(29,556	)

	Year Ended December 31, 2010
	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)			Interest Rate Contracts			Embedded Derivative in Debt Contract
Fair value at beginning of period	$	(11,340	)	$	(34,199	)	$	509		$	(190	)
Total gain or loss (realized and unrealized) included in earnings(1)		(11,093	)		(11,792	)		1,871			190
Purchases, sales, issuances and settlements (net)		8,076			11,055			(2,380	)		—
Fair value at end of period	$	(14,357	)	$	(34,936	)	$	—		$	—
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at December 31(1)	$	(13,101	)	$	(9,329	)	$	—		$	—

(1)

Gains and losses on Commodity Derivative Contracts classified as Level 3 are recorded in Derivative (loss) gain related to revenue. Gains and losses on Embedded Derivatives in Commodity Contracts are recorded in Purchased product costs, Derivative loss related to purchased product costs and Derivative gain related to facility expenses. Gains on Embedded Derivative in Debt Contract are recorded in Miscellaneous income (expense), net. Gains and losses on Interest Rate Contracts are recorded in Derivative gain related to interest expense.

Assets and liabilities measured at fair value on a nonrecurring basis

        Certain assets and liabilities are remeasured 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. During 2009, certain long-lived assets of Wirth Gathering, 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 in 2009. The Partnership estimated the fair value of these assets based on an income approach using significant unobservable inputs (Level 3). See Note 13 for further discussion of the 2009 impairment. During the three years ended December 31, 2011, there were no other assets or liabilities to be measured at fair value on a nonrecurring basis.

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Significant Customers and Concentration of Credit Risk

12 Months Ended

Dec. 31, 2011

Significant Customers and Concentration of Credit Risk

Significant Customers and Concentration of Credit Risk

8. Significant Customers and Concentration of Credit Risk

        For the years ended December 31, 2011, 2010 and 2009, revenues from a single customer totaled $297.8 million, $198.6 million and $134.8 million, representing 19.4%, 16.0% and 15.7% of Revenue, respectively. Revenues from this customer are for NGL sales made primarily in the Southwest segment. As of December 31, 2011 and 2010, the Partnership had $8.0 million and $5.1 million of accounts receivable from this customer, respectively.

        For the years ended December 31, 2011, 2010 and 2009, revenues from another customer totaled $203.3 million, $115.0 million and $81.6 million, representing 13.2%, 9.3% and 9.5% of Revenue, respectively. Revenues from this customer are for NGL sales made primarily from the Southwest segment. As of December 31, 2011 and 2010, the Partnership had $21.9 million and $13.1 million of accounts receivable from this customer, respectively.

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Inventories

12 Months Ended

Dec. 31, 2011

Inventories

Inventories

10. Inventories 

Inventories consist of the following (in thousands):

	December 31, 2011		December 31, 2010
NGLs	$	32,352	$	15,930
Spare parts, materials and supplies		8,654		7,502
Total inventories	$	41,006	$	23,432

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Business Combination (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011 Langley Acquisition MMcf Y	Feb. 02, 2011 Langley Acquisition
Business Combination
Cash purchase price													$ 230,700,000
Capacity of cryogenic natural gas processing plant (in MMcf/d)												100
Capacity of refrigeration natural gas processing plant (in MMcf/d)												75
Minimum additional capacity of cryogenic natural gas processing plant by mid-2012 (in MMcf/d)												60
Purchase price allocation
Property, plant and equipment												136,525,000
Goodwill												58,497,000
Intangibles asset												33,900,000
Inventory												1,806,000
Total												230,728,000
Estimated remaining useful life of intangibles (in years)												12
Revenue									1,534,434,000	1,241,563,000	858,635,000	21,800,000
Net income	$ (61,743,000)	$ 153,454,000	$ 89,205,000	$ (74,671,000)	$ (43,194,000)	$ (18,676,000)	$ 66,968,000	$ 26,004,000	$ 106,245,000	$ 31,102,000	$ (113,354,000)	$ 6,800,000

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Income Taxes (Details) (USD $)					12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008	Dec. 31, 2010 Impact of Correction of error	Dec. 31, 2009 Impact of Correction of error	Dec. 31, 2008 Impact of Correction of error
Long-term deferred tax liabilities	$ (93,664,000)	$ (87,881,000)			$ (77,500,000)	$ (69,800,000)	$ (59,600,000)
Total equity	1,502,067,000	1,458,566,000	1,309,553,000	1,148,155,000	(77,500,000)	(69,800,000)	(59,600,000)
Deferred tax impact of equity transactions					$ 7,600,000	$ 10,200,000

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Divestitures (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended			1 Months Ended			12 Months Ended
	Dec. 31, 2009	Dec. 31, 2011	Dec. 31, 2010	Sep. 30, 2009 SMR Transaction	Dec. 31, 2011 SMR Transaction	Dec. 31, 2010 SMR Transaction	Dec. 31, 2009 Starfish
Divestitures
Proceeds from SMR Transaction	$ 73,129			$ 73,100
Imputed interest rate on SMR liability (as a percent)					9.35%
ASSETS
Property, plant and equipment, net of accumulated depreciation of $9,658 and $4,390, respectively		2,864,307	2,319,024		95,705	100,973
Accumulated depreciation		438,062	294,003		9,658	4,390
LIABILITIES
Accrued liabilities		171,451	153,869		2,058	1,875
Other long-term liabilities		121,356	105,349		91,851	93,909
Percentage of equity interest sold							50.00%
Purchase price on sale of equity interest in equity method investments	25,000						25,000
Gain on sale of equity interest	$ 6,801						$ 6,800

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Summary of Significant Accounting Policies (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011 month	Dec. 31, 2010
Carrying value and related fair value of financial instruments
Long-term debt	$ 1,846,062	$ 1,273,434
Carrying value SMR liability	93,909	95,784
Fair value of long-term debt	1,880,710	1,333,875
Fair value SMR liability	$ 119,887	$ 125,600
Income tax policy
Expected settlement period of deferred tax balances to classify the balances as current (in months)	12

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Supplemental Condensed Consolidating Financial Information (Details 2) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Condensed Consolidating Statements of Operations
Total revenue	$ 333,913	$ 507,826	$ 400,439	$ 263,221	$ 299,991	$ 255,411	$ 323,850	$ 308,379	$ 1,505,399	$ 1,187,631	$ 738,283
Operating expenses:
Purchased product costs									735,330	606,340	477,709
Facility expenses									167,118	150,154	126,604
Selling, general and administrative expenses									81,229	75,258	63,728
Depreciation and amortization									193,571	164,031	136,368
Other operating expenses									9,987	3,386	1,875
Impairment of long-lived assets											5,855
Total operating expenses									1,187,235	999,169	812,139
Income (loss) from operations	(7,557)	207,801	133,214	(15,294)	25,172	646	109,071	53,573	318,164	188,462	(73,856)
Loss on redemption of debt	(35,500)			(43,300)	(46,300)				(78,996)	(46,326)
Gain on sale of unconsolidated affiliate											6,801
Other (expense) income, net									(119,274)	(107,845)	(88,315)
Income before provision for income tax									119,894	34,291	(155,370)
Provision for income tax expense									13,649	3,189	(42,016)
Net income (loss)	(61,743)	153,454	89,205	(74,671)	(43,194)	(18,676)	66,968	26,004	106,245	31,102	(113,354)
Net income attributable to non-controlling interest									(45,550)	(30,635)	(5,314)
Net income (loss) attributable to the Partnership	(74,085)	140,312	78,497	(84,029)	(54,109)	(27,151)	60,217	21,510	60,695	467	(118,668)
Parent
Operating expenses:
Selling, general and administrative expenses									46,903	46,549	46,317
Depreciation and amortization									719	594	559
Other operating expenses									673	753	(161)
Total operating expenses									48,295	47,896	46,715
Income (loss) from operations									(48,295)	(47,896)	(46,715)
Earnings from consolidated affiliates									288,870	183,557	2,243
Loss on redemption of debt									(78,996)	(46,326)
Other (expense) income, net									(91,612)	(82,000)	(69,951)
Income before provision for income tax									69,967	7,335	(114,423)
Provision for income tax expense									2,742	1,299	(1,439)
Net income (loss)									67,225	6,036	(112,984)
Net income (loss) attributable to the Partnership									67,225	6,036	(112,984)
Guarantor Subsidiaries
Condensed Consolidating Statements of Operations
Total revenue									1,240,004	1,063,621	686,340
Operating expenses:
Purchased product costs									651,132	589,403	465,152
Facility expenses									128,612	122,240	110,147
Selling, general and administrative expenses									31,015	27,339	17,990
Depreciation and amortization									151,362	136,781	124,976
Other operating expenses									9,030	2,342	2,019
Total operating expenses									971,151	878,105	720,284
Income (loss) from operations									268,853	185,516	(33,944)
Earnings from consolidated affiliates									44,425	15,963	1,501
Gain on sale of unconsolidated affiliate											6,801
Other (expense) income, net									(13,501)	(16,032)	(12,692)
Income before provision for income tax									299,777	185,447	(38,334)
Provision for income tax expense									10,907	1,890	(40,577)
Net income (loss)									288,870	183,557	2,243
Net income (loss) attributable to the Partnership									288,870	183,557	2,243
Non-Guarantor Subsidiaries
Condensed Consolidating Statements of Operations
Total revenue									265,395	124,010	51,943
Operating expenses:
Purchased product costs									84,198	16,937	12,557
Facility expenses									39,171	28,566	16,834
Selling, general and administrative expenses									9,011	6,317	2,878
Depreciation and amortization									42,198	27,054	10,984
Other operating expenses									284	291	17
Impairment of long-lived assets											5,855
Total operating expenses									174,862	79,165	49,125
Income (loss) from operations									90,533	44,845	2,818
Other (expense) income, net									(558)	1,753	3,997
Income before provision for income tax									89,975	46,598	6,815
Net income (loss)									89,975	46,598	6,815
Net income (loss) attributable to the Partnership									89,975	46,598	6,815
Consolidating Adjustments
Operating expenses:
Facility expenses									(665)	(652)	(377)
Selling, general and administrative expenses									(5,700)	(4,947)	(3,457)
Depreciation and amortization									(708)	(398)	(151)
Total operating expenses									(7,073)	(5,997)	(3,985)
Income (loss) from operations									7,073	5,997	3,985
Earnings from consolidated affiliates									(333,295)	(199,520)	(3,744)
Other (expense) income, net									(13,603)	(11,566)	(9,669)
Income before provision for income tax									(339,825)	(205,089)	(9,428)
Net income (loss)									(339,825)	(205,089)	(9,428)
Net income attributable to non-controlling interest									(45,550)	(30,635)	(5,314)
Net income (loss) attributable to the Partnership									$ (385,375)	$ (235,724)	$ (14,742)

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Quarterly Results of Operations (Unaudited)

12 Months Ended

Dec. 31, 2011

Quarterly Results of Operations (Unaudited)

Quarterly Results of Operations (Unaudited)

28. Quarterly Results of Operations (Unaudited)

        The following summarizes the Partnership's quarterly results of operations for 2011 and 2010 (in thousands, except per unit data):

	Three months ended
	March 31(1)			June 30		September 30		December 31(2)
2011
Total revenue	$	263,221		$	400,439	$	507,826	$	333,913
(Loss) income from operations		(15,294	)		133,214		207,801		(7,557	)
Net (loss) income		(74,671	)		89,205		153,454		(61,743	)
Net (loss) income attributable to the Partnership		(84,029	)		78,497		140,312		(74,085	)
Net (loss) income attributable to the Partnership's common unitholders per common unit(4):
Basic	$	(1.13	)	$	1.03	$	1.77	$	(0.87	)
Diluted	$	(1.13	)	$	1.03	$	1.77	$	(0.87	)

	Three months ended
	March 31		June 30		September 30			December 31(3)
2010
Total revenue	$	308,379	$	323,850	$	255,411		$	299,991
Income from operations		53,573		109,071		646			25,172
Net income (loss)		26,004		66,968		(18,676	)		(43,194	)
Net income (loss) attributable to the Partnership		21,510		60,217		(27,151	)		(54,109	)
Net income (loss) attributable to the Partnership's common unitholders per common unit(4):
Basic	$	0.32	$	0.84	$	(0.39	)	$	(0.76	)
Diluted	$	0.32	$	0.84	$	(0.39	)	$	(0.76	)

(1)

During the first quarter of 2011, the Partnership recorded a loss on redemption of debt of approximately $43.3 million related to the repurchase of the 2016 Senior Notes and a portion of 2018 Senior Notes. See Note 16 for further details.

(2)

During the fourth quarter of 2011, the Partnership recorded a loss on redemption of debt of approximately $35.5 million related to the repurchase of a portion of the 2018 Senior Notes. See Note 16 for further details.

(3)

During the fourth quarter of 2010, the Partnership recorded a loss on redemption of debt of approximately $46.3 million related to the redemption of the 2014 Senior Notes. See Note 16 for further details.

(4)

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.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2011

Commitments and Contingencies

Schedule of minimum future payments under the non-cancellable operating lease agreement and long-term propane storage agreement

Year ending December 31,
2012	$	10,299
2013		8,688
2014		7,793
2015		7,606
2016		7,334
2017 and thereafter		17,663
	$	59,383

Schedule of minimum amounts payable annually under the product supply agreement

Year ending December 31,
2012	$	17,412
2013		17,412
2014		17,412
2015		17,412
2016		17,412
2017 and thereafter		230,029
Total minimum payments		317,089
Less: Services element		121,295
Less: Interest		101,885
Total SMR liability		93,909
Less: Current portion of SMR Liability		2,058
Long-term portion of SMR Liability	$	91,851

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Asset Retirement Obligation

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation

Asset Retirement Obligation

15. 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, 2010 to December 31, 2011 (in thousands):

	December 31, 2011		December 31, 2010
Beginning asset retirement obligation	$	4,029	$	2,877
Liabilities incurred		1,599		915
Accretion expense		1,190		237
Ending asset retirement obligation	$	6,818	$	4,029

        At December 31, 2011, 2010 and 2009, 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.

        In addition to recorded asset retirement obligations, the Partnership has other asset retirement obligations related to certain gathering, processing and other assets as a result of environmental and other legal requirements. The Partnership is not required to perform such work until it permanently ceases operations of the respective assets. Because the Partnership considers the operational life of these assets to be indeterminable, an associated asset retirement obligation cannot be calculated and is not recorded.

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Incentive Compensation Plans

12 Months Ended

Dec. 31, 2011

Incentive Compensation Plans

Incentive Compensation Plans

20. Incentive Compensation Plans

        The following table summarizes the share-based compensation plans administered by the Compensation Committee of the Board ("Compensation Committee") that were active during the periods presented in the accompanying Consolidated Statements of Operations:

Share-based compensation plan	Award Classification	Further awards authorized for issuance under plan as of December 31, 2011	Awards outstanding under the plan as of December 31, 2011	Final Year of Activity
2008 Long-Term Incentive Plan ("2008 LTIP")	Equity	Yes	Yes		N/A
2006 Hydrocarbon Stock Incentive Plan ("2006 Hydrocarbon Plan")	Equity	No	No		2010
Long-Term Incentive Plan ("2002 LTIP")	Liability	No	No		2011
1996 Hydrocarbon Stock Incentive Plan ("1996 Hydrocarbon Plan")	Equity	No	No		2009

Compensation Expense

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

	Year ended December 31,
	2011		2010		2009
Phantom units	$	13,479	$	15,319	$	7,448
Distribution equivalent rights(1)		446		1,465		1,324
Total compensation expense	$	13,925	$	16,784	$	8,772

(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, 2011, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP was approximately $12.1 million, with a weighted average remaining vesting period of approximately 0.8 years. Total compensation expense not yet recognized includes approximately $0.2 million related to the TSR Performance Units (see discussion of TSR Performance Units below).

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.

        TSR Performance Units.    In April 2010, the Board granted 282,000 performance phantom units ("TSR Performance Units") under the 2008 LTIP to senior executives and other key employees. The TSR Performance Units are classified as equity awards and do not contain distribution equivalent rights. The TSR Performance Units were scheduled to vest in equal installments on January 31, 2011 and January 31, 2012, subject to the Partnership's relative total unitholder return (unit price appreciation and distribution performance) over the three-year calendar period prior to the scheduled vesting date compared to the total unitholder return of a defined group of peer companies over the same period ("Market Criteria"). Zero TSR Performance Units vest if the Partnership's relative ranking is less than the 40^th percentile; 50% of the TSR Performance Units vest if the Partnership's relative ranking is in the 40^th to 60^th percentile; 75% of the TSR Performance Units vest if the Partnership's relative ranking is in the 60^th to 80^th percentile; and 100% of the TSR Performance Units vest if the Partnership's relative ranking is in the 80^th to 100^th percentile. Additionally, the Board can increase or decrease the number of units to vest by up to 25% of the number of units that would otherwise vest based on the Performance Criteria. In January 2011 and 2012, 141,000 TSR performance vested based on the Market Criteria and the Board exercised its discretion to issue and immediately vest an additional 35,250 units.

        The effect of vesting conditions is that 75% of the TSR Performance Units vested based solely on the Partnership's actual performance with regards to the Market Criteria. The remaining 25% of the TSR Performance Units vested based on a combination of the Market Criteria and the Performance Criteria. Compensation expense related to the TSR Performance Units that vested solely based on the Market Criteria was recognized over the requisite service period based on the fair value of the units as of the grant date. However, a grant date, as defined by GAAP, was not established for the TSR Performance Units that vest based on a combination of the Market Criteria and Performance Criteria until the Board exercised its discretion because the Performance Criteria prevents a mutual understanding of the key terms of the award. Therefore, compensation expense related to this portion of the TSR Performance Units was recognized over the requisite service period based on the fair value of the units as of each reporting date. The requisite service period for all TSR Performance Units began in April 2010 when the Board approved the awards. TSR Compensation expense recognized related to TSR Performance Units was approximately $4.8 million and $4.5 million for the years ended December 31, 2011 and 2010, respectively.

        The fair value of the TSR Performance Units was measured at each appropriate measurement date using a Monte Carlo simulation model that estimated the most likely outcome based on the terms of the award. The key inputs in the model include the market price of the Partnership's common units as of the valuation date, the historical volatility of the market price of the Partnership's common units, the historical volatility of the market price of the common units or common stock of the peer companies, and the correlation between changes in the market price of the Partnership's common units and those of the peer companies.

        Unrestricted Units.    In January 2010, the Board granted 166,000 unrestricted units to senior executives and other key employees under the 2008 LTIP. The unrestricted units vested immediately and the Partnership recognized approximately $4.8 million of expense related to these units.

        Performance Units.    Phantom units containing performance vesting criteria ("Performance Units") were granted to senior executives and other key employees under the 2008 LTIP in 2008 and 2009. The Performance Units vest on a performance-based schedule over a three-year period, and vesting of these units occurs if the Partnership achieves established financial performance goals determined by the Compensation Committee. Management conducts an analysis on an ongoing basis to assess the probability of meeting the established performance goals and records compensation expense as required. As of December 31, 2011, there are 141,000 Performance Units outstanding with a grant date fair value of $1.2 million. The outstanding Performance Units did not vest. Compensation expense recorded for the Performance Units expected to vest was zero for the years ended December 31, 2011 and 2010, and approximately $0.5 million year ended December 31, 2009.

• 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan

        On February 21, 2008, the 25,897 outstanding shares of restricted stock granted under the 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan were converted to 49,354 phantom units in connection with the Merger. The converted phantom unit awards remained outstanding under the terms of the 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan until their respective settlement dates. The last converted phantom units outstanding under the 2006 Hydrocarbon Plan or the 1996 Hydrocarbon Plan vested on January 31, 2010 and 2009, respectively.

Summary of Equity Awards

        Awards under the 2008 LTIP, and historically the 2006 Hydrocarbon Plan and the 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. Phantom unit awards generally vest in equal tranches over a three-year period. For service-based awards, compensation expense related to each tranche is recognized over its requisite service period, reduced for an estimate of expected forfeitures. 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 assumes 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 $6.0 million, $3.4 million, and $1.1 million during the years ended December 31, 2011, 2010 and 2009, 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.

        The following is a summary of all phantom unit activity under the 2008 LTIP, 2006 Hydrocarbon Plan and 1996 Hydrocarbon Plan for the years ended December 31, 2011, 2010 and 2009:

	Number of Units			Weighted-average Grant-date Fair Value(1)
Unvested at January 1, 2009		909,306		$	31.80
Granted		442,035			8.64
Vested		(309,052	)		31.93
Forfeited		(65,048	)		20.96
Unvested at December 31, 2009		977,241			22.00
Granted (includes 282,000 TSR units)		736,688			30.25
Vested		(363,502	)		26.85
Forfeited		(21,267	)		19.28
Unvested at December 31, 2010 (includes 282,000 TSR units)		1,329,160			25.29
Granted (includes 35,250 TSR units)		309,629			42.75
Vested (includes 176,250 TSR units)		(396,934	)		27.04
Forfeited		(306,346	)		31.66
Unvested at December 31, 2011 (includes 141,000 TSR units)(2)		935,509			28.50

(1)

The calculation of the weighted average grant-date fair value for units granted during the year ended December 31, 2010 and unvested as of December 2010 and December 2011 is recalculated to include the fair value as of December 31, 2011 for 35,250 TSR Performance Units. A grant date, as defined by GAAP, has not been established for these units.

(2)

Includes 141,000 Performance Units that did not vest and were forfeited in January 2012.

        The total fair value and intrinsic value of the phantom units vested under the 2008 LTIP was $10.7 million, $9.8 million, and $9.9 million during the years ended December 31, 2011, 2010, and 2009, respectively. The total fair value and intrinsic value of the TSR Performance Units vested during the year ended December 31, 2011 was $4.9 million.

2002 LTIP

        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 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 assumes the income tax withholding obligations related to the vesting. The Partnership received no proceeds 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 $0.4 million, $0.4 million and $0.2 million for the years ended December 31, 2011, 2010 and 2009, respectively.

        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, 2009		145,927		$	31.45
Vested		(69,652	)		29.94
Forfeited		(6,720	)		33.64
Unvested at December 31, 2009		69,555			32.75
Vested		(44,942	)		32.15
Forfeited		(968	)		34.00
Unvested at December 31, 2010		23,645			33.83
Vested		(23,645	)		33.83
Unvested at December 31, 2011		—			—

        The total fair value and intrinsic value of the phantom units vested under the 2002 LTIP was $1.0 million, $1.3 million, and $0.9 million during the years ended December 31, 2011, 2010, and 2009, respectively.

Tax effects of share-based compensation

        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. Additional paid-in capital 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 and are included as Excess tax benefits related to share-based compensation in the accompanying Consolidated Statements of Cash Flows.

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Valuation and Qualifying Accounts (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Allowance for doubtful accounts
Activity in valuation and qualifying accounts
Balance at beginning of period	$ 162	$ 162	$ 175
Charged to costs and expenses		134	12
Other charges	(2)	(134)	(25)
Balance at end of period	160	162	162
Deferred tax assets valuation allowance
Activity in valuation and qualifying accounts
Balance at beginning of period	1,036	1,688	30
Charged to costs and expenses	(59)	(652)	1,667
Other charges			(9)
Balance at end of period	$ 977	$ 1,036	$ 1,688

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2011

Long-Term Debt

Schedule of long-term debt

	December 31, 2011		December 31, 2010
Credit Facility
Revolving credit facility, 4.0% interest due September 2016	$	66,000	$	—
Senior Notes
2016 Senior Notes, 8.5% interest, net of discount of $0 and $642, respectively, issued July 2006 and due July 2016		—		274,358
2018 Senior Notes, 8.75% interest, net of discount of $129 and $924, respectively, issued April and May 2008 and due April 2018		80,983		499,076
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020		500,000		500,000
2021 Senior Notes, 6.5% interest, net of discount of $921, issued February and March 2011 and due August 2021		499,079		—
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022		700,000		—
Total long-term debt	$	1,846,062	$	1,273,434

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Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2011

Derivative Financial Instruments

Derivative contracts not designated as hedging instruments

	Assets				Liabilities
Derivative contracts not designated as hedging instruments and their balance sheet location	Fair Value at December 31, 2011		Fair Value at December 31, 2010		Fair Value at December 31, 2011			Fair Value at December 31, 2010
Commodity contracts(1)
Fair value of derivative instruments—current	$	8,698	$	4,345	$	(90,551	)	$	(65,489	)
Fair value of derivative instruments—long-term		16,092		417		(65,403	)		(66,290	)
Total	$	24,790	$	4,762	$	(155,954	)	$	(131,779	)

(1)

Includes Embedded Derivatives in Commodity Contracts as discussed below.

	Year ended December 31,
Derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in income	2011			2010			2009
Revenue: Derivative loss
Realized (loss) gain	$	(48,093	)	$	(33,560	)	$	87,289
Unrealized gain (loss)		19,058			(20,372	)		(207,641	)
Total revenue: derivative loss		(29,035	)		(53,932	)		(120,352	)
Derivative loss related to purchased product costs
Realized loss		(27,711	)		(21,909	)		(53,052	)
Unrealized loss		(25,249	)		(5,804	)		(15,831	)
Total derivative loss related to purchase product costs		(52,960	)		(27,713	)		(68,883	)
Derivative gain related to facility expenses
Unrealized gain		6,480			1,295			373
Derivative gain related to interest expense
Realized gain		—			2,380			2,000
Unrealized (loss) gain		—			(509	)		509
Total derivative gain related to interest expense		—			1,871			2,509
Miscellaneous income, net
Unrealized gain		—			190			336
Total loss	$	(75,515	)	$	(78,289	)	$	(186,017	)

Volume of Derivative Activity

Derivative contracts not designated as hedging instruments	Position	Notional Quantity (net)
Crude Oil (bbl)	Short		8,244,902
Natural Gas (MMBtu)	Long		16,021,887
NGLs (gal)	Short		86,563,841

Reconciliation of liability recorded for embedded derivative

Fair value of commodity contract	$	114,928
Inception value for period from April 1, 2015 to December 31, 2022.		(53,507	)
Derivative liability as of December 31, 2011	$	61,421

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CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY (USD $) In Thousands, unless otherwise specified	Total	Common Units	Class B Units	Non-controlling Interest
Balance at Dec. 31, 2008	$ 1,148,155	$ 1,144,854		$ 3,301
Balance (in units) at Dec. 31, 2008		56,640
Increase (Decrease) in Equity
Share-based compensation activity	5,204	5,204
Share-based compensation activity (in units)		275
Distributions paid	(155,462)	(155,307)		(155)
Issuance of units in public offering, net of offering costs	178,565	178,565
Issuance of units in public offerings, net of offering costs (in units)		9,360
Contributions to MarkWest Liberty Midstream joint venture, net	194,536	(5,464)		200,000
Proceeds from sale of equity interest in joint venture, net	60,654	(1,846)		62,500
Transfer to non-controlling interest from sale of equity interest in joint venture, net of tax	1,491	(10,288)		11,779
Deferred income tax impact from changes in equity	(10,236)	(10,236)
Net income (loss)	(113,354)	(118,668)		5,314
Balance at Dec. 31, 2009	1,309,553	1,026,814		282,739
Balance (in units) at Dec. 31, 2009		66,275
Increase (Decrease) in Equity
Share-based compensation activity	12,087	12,087
Share-based compensation activity (in units)		278
Excess tax benefits related to share-based compensation	98	98
Distributions paid	(187,208)	(181,058)		(6,150)
Issuance of units in public offering, net of offering costs	142,255	142,255
Issuance of units in public offerings, net of offering costs (in units)		4,887
Contributions to MarkWest Liberty Midstream joint venture, net	158,293			158,293
Deferred income tax impact from changes in equity	(7,614)	(7,614)
Net income (loss)	31,102	467		30,635
Balance at Dec. 31, 2010	1,458,566	993,049		465,517
Balance (in units) at Dec. 31, 2010		71,440	0
Increase (Decrease) in Equity
Share-based compensation activity	8,083	8,083
Share-based compensation activity (in units)		275
Excess tax benefits related to share-based compensation	1,084	1,084
Distributions paid	(285,285)	(218,398)		(66,887)
Issuance of units in public offering, net of offering costs	1,095,488	1,095,488
Issuance of units in public offerings, net of offering costs (in units)		23,225
Issuance of Class B units	752,531		752,531
Issuance of Class B units (in units)			19,954
Contributions to MarkWest Liberty Midstream joint venture, net	126,392			126,392
Purchase of non-controlling interest of MarkWest Liberty M&R, net of tax benefit	(1,698,810)	(1,198,465)		(500,345)
Deferred income tax impact from changes in equity	(62,227)	(62,227)
Net income (loss)	106,245	60,695		45,550
Balance at Dec. 31, 2011	$ 1,502,067	$ 679,309	$ 752,531	$ 70,227
Balance (in units) at Dec. 31, 2011		94,940	19,954

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Dec. 31, 2010	Sep. 30, 2010	Jun. 30, 2010	Mar. 31, 2010	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Segment information
Revenue									$ 1,534,434	$ 1,241,563	$ 858,635
Purchased product costs									682,370	578,627	408,826
Facility expenses									173,598	151,449	126,977
Income (loss) from operations	(7,557)	207,801	133,214	(15,294)	25,172	646	109,071	53,573	318,164	188,462	(73,856)
Capital expenditures									551,281	458,668	486,623
Total reportable segments
Segment information
Revenue									1,549,819	1,241,563	858,635
Purchased product costs									682,370	578,627	408,826
Net operating margin									867,449	662,936	449,809
Facility expenses									183,236	158,650	126,322
Portion of operating income attributable to non-controlling interests									69,162	32,566	9,250
Income (loss) from operations									615,051	471,720	314,237
Capital expenditures									546,191	453,028	479,991
Southwest Segment
Segment information
Revenue									935,513	665,768	492,369
Purchased product costs									506,911	308,960	221,021
Net operating margin									428,602	356,808	271,348
Facility expenses									82,761	81,772	73,621
Portion of operating income attributable to non-controlling interests									5,431	6,440	2,613
Income (loss) from operations									340,410	268,596	195,114
Capital expenditures									103,968	114,109	236,705
Northeast Segment
Segment information
Revenue									268,884	384,724	260,529
Purchased product costs									91,612	252,827	175,326
Net operating margin									177,272	131,897	85,203
Facility expenses									27,126	19,513	20,339
Income (loss) from operations									150,146	112,384	64,864
Capital expenditures									51,280	2,179	21,538
Liberty Segment
Segment information
Revenue									248,949	105,911	47,968
Purchased product costs									83,847	16,840	12,479
Net operating margin									165,102	89,071	35,489
Facility expenses									34,913	24,028	16,268
Portion of operating income attributable to non-controlling interests									63,731	26,126	6,637
Income (loss) from operations									66,458	38,917	12,584
Capital expenditures									388,850	332,793	181,142
Gulf Coast Segment
Segment information
Revenue									96,473	85,160	57,769
Net operating margin									96,473	85,160	57,769
Facility expenses									38,436	33,337	16,094
Income (loss) from operations									58,037	51,823	41,675
Capital expenditures									2,093	3,947	40,606
Unallocated Segment
Segment information
Capital expenditures									$ 5,090	$ 5,640	$ 6,632

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Variable Interest Entities

12 Months Ended

Dec. 31, 2011

Variable Interest Entities

Variable Interest Entities

4. Variable Interest Entities

• MarkWest Liberty Midstream

        On February 27, 2009, the Partnership entered into a joint venture with M&R, an affiliate of The Energy & Minerals Group 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. Under the original joint venture agreement, MarkWest Liberty Midstream was owned 60% by the Partnership and 40% by M&R. Upon closing, the Partnership contributed its existing Marcellus Shale natural gas gathering and processing assets with an agreed to value of $107.5 million and M&R contributed cash of $50.0 million to MarkWest Liberty Midstream. M&R also committed to fund the next $150 million of MarkWest Liberty Midstream's capital requirements after which time the Partnership agreed to fund the future capital requirements until each member's contributed capital was proportionate to its ownership interest ("Equalization"). Effective November 1, 2009, the Partnership and M&R executed the Second Amended and Restated Limited Liability Company Agreement of MarkWest Liberty Midstream & Resources L.L.C. pursuant to which M&R increased its participation in MarkWest Liberty Midstream. The Partnership and M&R agreed to maintain a 60%/40% respective ownership interest in MarkWest Liberty Midstream until January 1, 2011, at which time M&R's ownership interest increased from 40% to 49%. In addition to its initial contribution of assets at closing, the Partnership contributed an additional $252.4 million, $171.1 million, and $8.0 million during 2011, 2010, and 2009 respectively. In addition to its $50 million contribution at closing, M&R contributed $126.4 million, $158.3 million, and $150.0 million during 2011, 2010 and 2009, respectively.

        The cumulative capital contributed by M&R exceeded its ownership interest until the third quarter of 2011. Under the terms of the joint venture agreement, M&R received a special $1.3 million, $11.4 million, and $3.4 million allocation of net income from MarkWest Liberty Midstream during the years ended December 31, 2011, 2010 and 2009, respectively, due to its excess contributions. The allocation is recorded in Net income attributable to non-controlling interest in the Consolidated Statements of Operations.

        The Partnership determined that MarkWest Liberty Midstream was a VIE until December 31, 2011, primarily due to the Partnership's disproportionate economic interests as compared to its voting interests in the entity. Additionally, MarkWest Liberty Midstream had insufficient equity at risk, as evidenced by the additional capital funding requirements discussed above. Although voting interests were shared equally between the respective members of MarkWest Liberty Midstream until December 31, 2011, the Partnership had concluded that it was the primary beneficiary based on its affiliate's role as the operator. The Partnership believes that its role as the operator along with its equity interests gave it the power to direct the activities that most significantly affected the economic performance of MarkWest Liberty Midstream. As the primary beneficiary of a VIE, the Partnership consolidated MarkWest Liberty Midstream for all periods presented in the accompanying financial statements.

        Effective December 31, 2011, the Partnership acquired M&R's 49% non-controlling interest of MarkWest Liberty Midstream for total consideration of approximately $1,746.5 million, which includes cash of $994.0 million and approximately 19,954,000 Class B units valued at approximately $752.5 million (see Note 17 for discussion of Class B units). The Partnership paid transaction fees of approximately $3.6 million related to this transaction. As a result of the transaction, MarkWest Liberty Midstream is a wholly-owned subsidiary of the Partnership and is no longer a VIE. However, the Partnership continues to consolidate MarkWest Liberty Midstream.

        In accordance with GAAP, a change in the Partnership's ownership interest in a subsidiary while it retains a controlling interest is recorded as an equity transaction. As such, the fair value of the consideration paid in excess of the $500.3 million carrying amount of the non-controlling interest acquired and the related transaction costs of approximately $3.6 million are recognized as a reduction of equity attributable to the Partnership's common units. See table below in this Note 4 for a summary of the impact on equity attributable to the Partnership's common units as of December 31, 2011.

        As the accompanying Consolidated Statements of Operations include the historical results of MarkWest Liberty Midstream, pro forma results of operations are not presented for this acquisition of non-controlling interest. The primary impact of the transaction on the financial statements is that none of MarkWest Liberty Midstream's net income will be allocable to a non-controlling interest in future periods as 100% of MarkWest Liberty Midstream's net income will be attributable to the Partnership. During the years ended December 31, 2011, 2010 and 2009, the portion of MarkWest Liberty Midstream's net income attributable to non-controlling interest was $44.0 million, $27.9 million and $6.3 million, respectively.

• 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 mid-July 2009. The Arkoma Connector Pipeline is designed to provide approximately 638,000 Dth/d of Arkoma Basin takeaway capacity and interconnects with the Midcontinent Express Pipeline and the Gulf Crossing Pipeline. In 2009, the Partnership sold a 50% interest in MarkWest Pioneer to ArcLight Capital Partners, LLC. Under the terms of the sale, the Partnership was required to fund all of the capital expenditures required to complete construction of the Arkoma Connector Pipeline in excess of $125 million, and as a result the Partnership has made capital contributions to MarkWest Pioneer in excess of its stated ownership and voting interests. A wholly-owned subsidiary of the Partnership serves as the operator and provides field operating and general and administrative services for fixed fees. The Partnership has determined that MarkWest Pioneer is a VIE primarily due to the Partnership's disproportionate economic interests as compared to its voting interests. Although voting interests are shared equally between the respective members of MarkWest Pioneer, the Partnership has concluded that it is the primary beneficiary based on its role as the operator. The Partnership believes that its role as the operator along with its equity interests give it the power to direct the activities that most significantly affect the economic performance of MarkWest Pioneer.

• Financial Statement Impact of VIEs

        As of December 31, 2011, MarkWest Pioneer is the only VIE included in the Partnership's consolidated financial statements. The assets and liabilities attributable to MarkWest Pioneer as of December 31, 2011 are disclosed parenthetically on the accompanying Consolidated Balance Sheets. As of December 31, 2010, MarkWest Pioneer and MarkWest Liberty Midstream were both consolidated VIEs. The following table shows the assets and liabilities attributable to VIEs reflected in the Consolidated Balance Sheets as of December 31, 2010 (in thousands):

	MarkWest Liberty Midstream		MarkWest Pioneer		Total
ASSETS
Cash and cash equivalents	$	—	$	2,913	$	2,913
Receivables, net		42,181		1,602		43,783
Inventories		8,431		—		8,431
Other current assets		271		1		272
Property, plant and equipment, net of accumulated depreciation of $28,869 and $9,300, respectively		664,778		147,039		811,817
Restricted cash		28,001		—		28,001
Other long-term assets		281		102		383
Total assets	$	743,943	$	151,657	$	895,600
LIABILITIES
Accounts payable	$	5,945	$	—	$	5,945
Accrued liabilities		63,450		1,263		64,713
Other long-term liabilities		86		68		154
Total liabilities	$	69,481	$	1,331	$	70,812

        The assets of MarkWest Pioneer are not available to the Partnership for any other purpose, including collateral for its secured debt (see Note 16 and Note 25). MarkWest Pioneer's asset balances can only be used to settle it own obligations and not those of the Partnership or any other subsidiaries of the Partnership. The liabilities of MarkWest Pioneer do not represent additional claims against the Partnership's general assets and the creditors or beneficial interest holders of MarkWest Pioneer do not have recourse to the general credit of the Partnership. The Partnership's maximum exposure to loss as a result of its involvement with the MarkWest Pioneer includes its equity investment and any operating expense incurred by the subsidiary operator in excess of its subsidiary's compensation for the performance of those services.

        For the years ended December 31, 2011, 2010 and 2009, the results of operations and cash flow information of MarkWest Liberty Midstream and MarkWest Pioneer comprise substantially all of the results of operations and cash flow information of the non-guarantor subsidiaries (see Note 25). Individually, the results of operations and cash flow of MarkWest Pioneer, the remaining VIE, are not material to the Partnership. The Partnership did not provide any financial support to the MarkWest Liberty Midstream or MarkWest Pioneer that it was not contractually obligated to provide during the years ended December 31, 2011, 2010 and 2009.

        As discussed above, the Partnership's ownership interest in MarkWest Liberty Midstream and MarkWest Pioneer changed as a result of transactions completed in 2009 and 2011.The following table summarizes the effect of these changes of ownership interest on the equity attributable to the Partnership's common units (in thousands):

	Year ended December 31,
	2011			2010		2009
Net income (loss) attributable to the Partnership	$	60,695		$	467	$	(118,668	)
Transfers to the non-controlling interests:
Decrease in common unit equity for 2011 acquisition of equity interest in MarkWest Liberty Midstream, net of $51,321 income tax benefit		(1,194,865	)		—		—
Decrease in common unit equity for transaction costs related to 2011 acquisition of equity interest in MarkWest Liberty Midstream		(3,600	)		—		—
Decrease in common unit equity for transfer to non- controlling interest from 2009 sale of equity interest in MarkWest Pioneer, net of $1,491 income tax benefit		—			—		(10,288	)
Decrease in common unit equity for transaction costs related to 2009 sales of equity interests in MarkWest Liberty Midstream and MarkWest Pioneer		—			—		(7,310	)
Net (loss) income attributable to the Partnership and transfers to the non-controlling interest	$	(1,137,770	)	$	467	$	(136,266	)

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2011

Supplemental Cash Flow Information

Information regarding supplemental cash flow information

	Year ended December 31,
	2011		2010		2009
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	$	112,780	$	101,459	$	85,817
Cash paid for income taxes, net of refunds		10,115		8,683		4,609
Supplemental schedule of non-cash investing and financing activities:
Accrued property, plant and equipment	$	87,098	$	65,908	$	60,738
Interest capitalized on construction in progress		1,121		2,766		12,228
Issuance of common units for vesting of share-based payment awards		5,412		7,238		9,402
Issuance of Class B units for acquisition of non-controlling interest		752,531		—		—

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Lease Operations (Details) (USD $)	12 Months Ended
	Dec. 31, 2011 Y term	Dec. 31, 2010	Dec. 31, 2009
Lease Operations
Number of renewal terms at option of producer	2
Number of years in each renewal term	5
Revenue from lease arrangements	$ 67,400,000	$ 32,200,000	$ 14,900,000
Minimum future rentals on the non-cancellable operating leases
2012	61,081,000
2013	61,081,000
2014	61,081,000
2015	59,794,000
2016	59,794,000
2017 and thereafter	352,760,000
Total minimum future rentals	655,591,000
Investment in assets held for operating lease by major classes
Property, plant and equipment	517,953,000	324,839,000
Less: accumulated depreciation	(46,006,000)	(21,742,000)
Total property, plant and equipment, net	471,947,000	303,097,000
Natural gas gathering and NGL transportation pipelines and facilities
Investment in assets held for operating lease by major classes
Property, plant and equipment	479,567,000	264,669,000
Construction in progress
Investment in assets held for operating lease by major classes
Property, plant and equipment	$ 38,386,000	$ 60,170,000

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Fair Value (Details 2) (USD $)	12 Months Ended
	Dec. 31, 2009	Dec. 31, 2011 Commodity contracts (net)	Dec. 31, 2010 Commodity contracts (net)	Dec. 31, 2011 Embedded derivatives in commodity contracts (net)	Dec. 31, 2010 Embedded derivatives in commodity contracts (net)	Dec. 31, 2010 Interest rate contracts	Dec. 31, 2010 Embedded derivative in debt contract
Derivative assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy
Fair value at beginning of period		$ (14,357,000)	$ (11,340,000)	$ (34,936,000)	$ (34,199,000)	$ 509,000	$ (190,000)
Total gain or (loss) (realized and unrealized) included in earnings		3,182,000	(11,093,000)	(30,827,000)	(11,792,000)	1,871,000	190,000
Purchases, sales, issuances and settlements (net)		8,210,000	8,076,000	11,859,000	11,055,000	(2,380,000)
Fair value at end of period		(2,965,000)	(14,357,000)	(53,904,000)	(34,936,000)
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to contracts still held at end of period		6,241,000	(13,101,000)	(29,556,000)	(9,329,000)
Net book value of property plant and equipment that was written down to an estimated fair value of zero	5,200,000
Net book value of intangible assets that were written down to an estimated fair value of zero	700,000
Asset impairment charge	$ 5,855,000

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Employee Benefit Plan

12 Months Ended

Dec. 31, 2011

Employee Benefit Plan

Employee Benefit Plan

21. 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 $2.7 million, $2.3 million and $1.8 million for the years ended December 31, 2011, 2010 and 2009, respectively.

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Goodwill and Intangible Assets (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Changes in goodwill
Gross goodwill beginning of the year	$ 38,126
Acquisition	58,497
Gross goodwill end of the year	96,623
Cumulative impairment	(28,705)	(28,705)
Balance at the end of the period	67,918	9,421
Southwest Segment
Changes in goodwill
Gross goodwill beginning of the year		24,324
Gross goodwill end of the year	24,324	24,324
Cumulative impairment	(18,851)
Balance at the end of the period	5,473
Northeast Segment
Changes in goodwill
Gross goodwill beginning of the year	3,948
Acquisition	58,497
Gross goodwill end of the year	62,445
Balance at the end of the period	62,445
Gulf Coast Segment
Changes in goodwill
Gross goodwill beginning of the year		9,854
Gross goodwill end of the year	9,854	9,854
Cumulative impairment	$ (9,854)

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Business Combination (Tables)

12 Months Ended

Dec. 31, 2011

Business Combination

Schedule of purchase price allocation

Property, plant and equipment	$	136,525
Goodwill		58,497
Intangible asset		33,900
Inventory		1,806
Total	$	230,728

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Accrued Liabilities and Other Long-Term Liabilities

12 Months Ended

Dec. 31, 2011

Accrued Liabilities and Other Long-Term Liabilities.

Accrued Liabilities and Other Long-Term Liabilities

14. Accrued Liabilities and Other Long-Term Liabilities

        Accrued liabilities as of December 31, 2011 and 2010 consist of the following (in thousands):

	December 31, 2011		December 31, 2010
Accrued property, plant and equipment	$	87,098	$	65,908
Interest		27,458		26,607
Product and operations		22,969		31,241
Employee compensation		12,600		9,167
Taxes (other than income tax)		9,914		8,670
Other		11,412		12,276
Total accrued liabilities	$	171,451	$	153,869

        Other long-term liabilities as of December 31, 2011 and 2010 consist of the following (in thousands):

	December 31, 2011		December 31, 2010
SMR Liability (see Note 5)	$	91,851	$	93,909
Deferred revenue		19,383		4,018
Asset retirement obligation		6,818		4,029
Other		3,304		3,393
Total other long-term liabilities	$	121,356	$	105,349