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ITEM 8. Financial Statements and Supplementary Data
Table of Contents

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.

   


Table of Contents


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.

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

    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").

    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.

GRAPHIC

        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:

    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.

    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.

    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.

    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.

    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.

    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.

GRAPHIC

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

    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.

    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:

    an existing strong competitive position;

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

    ample opportunities for long-term continued organic growth;

    ready access to markets; and

    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.

    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.

    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:

GRAPHIC

        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:

GRAPHIC

        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.

    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.

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

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

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

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

    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

    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.

    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.

    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

    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

    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    

      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.

      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.

      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

      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.

      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.

      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:

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

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

      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

      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.

    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.

    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.

    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.

    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:

    a large number of natural gas midstream providers, of varying financial resources and experience, that gather, process and market natural gas and NGLs;

    major integrated oil companies;

    medium and large sized independent exploration and production companies;

    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:

    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:

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

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

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

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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;

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

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

        Furthermore, these consequences could limit our ability, and the ability of our subsidiaries, to obtain future financings, make needed capital expenditures, withstand 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:

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

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

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

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

    the level of our operating costs; and

    prevailing economic conditions.

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

    our debt service requirements;

    fluctuations in our working capital needs;

    our ability to borrow funds and access capital markets;

    restrictions contained in our debt agreements;

    restrictions contained in our joint venture agreements;

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

    the cost of acquisitions, if any; and

    the amount of cash reserves established by our general partner.

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

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

    demand for natural gas and NGL products in localized markets;

    changes in interstate pipeline gas quality specifications;

    imports of crude oil, natural gas and NGLs;

    seasonality;

    the condition of the U.S. economy;

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

    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;

    inadvertent damage from vehicles and construction and farm equipment;

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

    fires and explosions; and

    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:

    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;

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

    the failure to realize expected synergies and cost savings;

    coordinating geographically disparate organizations, systems and facilities;

    integrating personnel from diverse business backgrounds and organizational cultures; and

    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.

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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.

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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.

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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.

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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

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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.

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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

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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.

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ITEM 6.    Selected Financial Data

        The following table sets forth selected consolidated historical financial and operating data for MarkWest Energy Partners (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  
                       

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  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.

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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