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ITEM 8. Financial Statements and Supplementary Data

Table of Contents

 

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



FORM 10-K


ý

 

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2014

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, 2014 was approximately $12.1 billion. As of February 18, 2015, the number of the registrant's common units and Class B units outstanding were 186,751,224 and 11,972,634, 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 Common Unitholders to be held in 2015, 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.

   


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

Table of Contents

 
   
   

PART I

 

 

   

Item 1.

 

Business

  4

Item 1A.

 

Risk Factors

  37

Item 1B.

 

Unresolved Staff Comments

  63

Item 2.

 

Properties

  64

Item 3.

 

Legal Proceedings

  68

Item 4.

 

Mine Safety Disclosures

  69

PART II

 

 

   

Item 5.

 

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

  70

Item 6.

 

Selected Financial Data

  72

Item 7.

 

Management's Discussion and Analysis of Financial Condition and Results of Operations

  75

Item 7A.

 

Quantitative and Qualitative Disclosures About Market Risk

  103

Item 8.

 

Financial Statements and Supplementary Data

  107

Item 9.

 

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

  175

Item 9A.

 

Controls and Procedures

  175

Item 9B.

 

Other Information

  177

PART III

   

Item 10.

 

Directors, Executive Officers and Corporate Governance

  177

Item 11.

 

Executive Compensation

  177

Item 12.

 

Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

  177

Item 13.

 

Certain Relationships and Related Transactions, and Director Independence

  177

Item 14.

 

Principal Accountant Fees and Services

  177

PART IV

   

Item 15.

 

Exhibits and Financial Statement Schedules

  177

SIGNATURES

  185

        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. 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

Condensate

  A natural gas liquid with a low vapor pressure mainly composed of propane, butane, pentane and heavier hydrocarbon fractions

Credit Facility

  Revolving loan facility provided for under our Amended and Restated Credit Agreement dated July 1, 2010

DER

  Distribution equivalent right

Dth/d

  Dekatherms per day

EBITDA (a non-GAAP financial measure)

  Earnings Before Interest, Taxes, Depreciation and Amortization

EPA

  United States 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

MBbl/d

  Million barrels per day

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. Undue reliance should not be placed on forward-looking statements as many of these factors are beyond our ability to control or predict.


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 that owns and operates midstream services related businesses. We have a leading presence in many natural gas resource plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formation where we provide midstream services for producer customers.

        Our integrated midstream energy asset network links producers of natural gas, NGLs and crude oil from some of the largest supply basins in the United States to domestic and international markets. Our midstream energy operations include: natural gas gathering, processing and transportation; NGL gathering, transportation, fractionation, storage, and marketing; and crude oil gathering and transportation. Our assets include approximately 5,800 MMcf/d of natural gas processing capacity, 379,000 Bbl/d of NGL fractionation capacity and over 4,000 miles of pipelines.

        We conduct our operations in the following operating segments: Marcellus, Utica, Northeast and Southwest. 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, 2014 (amounts in thousands). For further discussion of our segments and a reconciliation

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to our consolidated statement of operations, see Note 25 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

 
  Marcellus   Utica   Northeast   Southwest   Eliminations   Total  

Segment revenue

  $ 791,505   $ 152,975   $ 194,477   $ 1,035,026     (6,175 ) $ 2,167,808  

Segment purchased product costs

    147,500     23,773     66,345     595,064         832,682  

Net operating margin(1)

    644,005     129,202     128,132     439,962     (6,175 )   1,335,126  

Segment facility expenses

    151,898     54,224     31,974     132,360     (6,175 )   364,281  

Portion of operating income attributable to non-controlling interests

        35,422         11         35,433  

Operating income before items not allocated to segments

  $ 492,107   $ 39,556   $ 96,158   $ 307,591       $ 935,412  

(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, as a result of the ownership structure adopted after the February 2008 merger of the Partnership and MarkWest Hydrocarbon (the "Merger"). The Class A units generally share in our income or losses on a pro-rata basis with our common units and our Class B units, however the Class A units do not share in any income or losses that are attributable to our ownership interest (or disposition of such interest) in MarkWest Hydrocarbon. The only impact of the Class A units on our consolidated results of operations and financial position is that MarkWest Hydrocarbon pays income tax on its pro-rata share of our income or losses. The Class A units are not treated as outstanding common units in the accompanying Consolidated Balance Sheets as they are all held by our wholly-owned subsidiaries and therefore eliminated in consolidation.

    All of our remaining Class B units were issued to and are held by M&R MWE Liberty LLC and certain of its affiliates ("M&R"), an affiliate of The Energy & 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"). Approximately 4.0 million Class B units converted to common units on July 1, 2013 and July 1, 2014. The remaining 12.0 million Class B units will convert to common units on a one-for-one basis (the "Converted Units") in three equal installments beginning on July 1, 2015 and each of the next two anniversaries of such date. Class B units (i) share in our income and losses, (ii) are not entitled to participate in any distributions of available cash prior to their conversion and (iii) do not have the right to vote on, approve or disapprove, or otherwise consent to or not consent to any matter (including mergers, unit 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

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      Partnership's outstanding common units. Upon the conversion of each tranche of Class B units, M&R will have the right with respect to such Converted Units to participate in the Partnership's underwritten offerings of our common units including continuous equity or similar programs in an amount up to 20% of the total number of common units offered by the Partnership. In addition, M&R 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. 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. 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 18, 2015 (units in millions):

 
  Units   %  

Common units

    186.8     84.4 %

Class A units

    22.6     10.2 %

Class B units

    12.0     5.4 %

Total units

    221.4     100.0 %

        The ownership percentages as of February 18, 2015 in the graphic depicted below reflect the Partnership structure from the basis of the consolidated financial statements with the Class A units eliminated in consolidation. All Class B units are owned by M&R and included in the public ownership percentage.

GRAPHIC

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        The primary benefit of our organizational structure is the absence of incentive distribution rights ("IDRs"), which represents a general partner's right to receive a percentage of quarterly distributions of available cash after a minimum quarterly distribution and certain target distribution levels have been achieved. The absence of IDRs 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 organic growth projects and new acquisitions, and improves the returns to our unitholders on all future expansion projects.

Key Developments

        We continued to expand our leading midstream systems that are located in many of the most productive natural gas resource plays in the United States. During 2014, we completed construction of 16 major infrastructure projects, increasing our total gas processing capacity to approximately 5.8 Bcf/d and our total NGL fractionation capacity to 379,000 Bbl/d. We also continued to expand our gathering infrastructure with the completion of approximately 350 miles of gas and NGL pipelines. Our long-term partnerships with producer customers continue to provide us with significant opportunities to expand our infrastructure.

Expansion of Operations in the Marcellus Shale

        During 2014, we continued our large-scale development of gathering, processing and fractionation infrastructure in the liquids-rich area of the Marcellus Shale. We expanded our natural gas processing infrastructure with the completion of five new cryogenic facilities, which increased our total processing capacity in southwest Pennsylvania and northern West Virginia to approximately 3.2 Bcf/d. In addition, we expanded our integrated natural gas and NGL gathering pipeline network with the construction of approximately 160 miles of new pipelines. As a result of these expansions and our existing infrastructure, during 2014 we gathered over 668.6 MMcf/d and processed approximately 2.1 Bcf/d of gas for our producer customers.

        We commenced operations of additional fractionation capacity to support growing NGL volumes in the region, including 26,000 Bbl/d of ethane and heavier NGL fractionation capacity at our Keystone complex in Butler County, Pennsylvania ("Keystone Complex") and 120,000 Bbl/d of shared propane and heavier NGL fractionation at our Hopedale Complex in Harrison County, Ohio ("Hopedale Complex"). The Hopedale Complex is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, LLC ("MarkWest Utica EMG"). We are constructing a third 60,000 Bbl/d propane and heavier fractionation facility at the Hopedale Complex that is expected to commence operations in the first quarter of 2016.

        In addition, we have announced the development of 141,000 Bbl/d of additional ethane and heavier NGL fractionation capacity to support our producer customers in the Marcellus Shale.

Expansion of Operations in the Utica Shale

        During 2014, MarkWest Utica EMG, a joint venture between MarkWest Energy and EMG, continued to expand its midstream presence in the Utica Shale. MarkWest Utica EMG commenced operation of three cryogenic processing facilities totaling 600 MMcf/d of capacity. Together, these complexes support our producer customers' ongoing rich-gas development with 925 MMcf/d of total processing capacity.

        As discussed above, in 2014 we commenced operations at our Hopedale Complex, which is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG. An NGL pipeline network connecting the Hopedale Complex to the Marcellus and Utica processing complexes allows us to fractionate NGLs produced in both shale plays. In July 2014, we completed construction and

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commenced operation of a 40,000 Bbl/d de-ethanization facility at the Cadiz complex in Harrison County, Ohio ("Cadiz Complex").

        During 2014, Ohio Gathering Company, LLC ("Ohio Gathering"), a subsidiary of MarkWest Utica EMG, of which we indirectly own approximately 36%, continued to expand its gathering system in the core acreage of the Utica Shale. The gathering system is expected to continue to grow significantly, as producers operating in Ohio continue to develop both liquids-rich and dry-gas areas of the Utica Shale. Prior to June 2014, Ohio Gathering results of operations and financial position were consolidated with the operations and financial position of MarkWest Utica EMG. In June 2014, Summit Midstream Partners L.P. ("Summit") exercised an option to acquire a 40% interest in Ohio Gathering, which resulted in the deconsolidation of Ohio Gathering. See Note 3 to the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion.

Expansion of Southwest Operations

        In December 2014, we began operations of a fourth processing plant at our Carthage facilities in Panola County, Texas to support growing rich-gas production from the Haynesville Shale and Cotton Valley formations. The new plant has an initial capacity of 120 MMcf/d, bringing the total processing capacity at our East Texas operations to 520 MMcf/d.

        In April 2014, our Centrahoma Joint Venture ("Centrahoma") commenced operations of the Stonewall processing facility, a 120 MMcf/d plant in the Woodford Shale in Southwest Oklahoma. We agreed to fund our 40% share of the construction of an additional 80 MMcf/d of processing capacity of which 40 MMcf/d became operational in December 2014. The remaining 40 MMcf/d is expected to begin processing in the first half of 2015. When completed, the expansion of the Stonewall plant will increase Centrahoma's total processing capacity to 300 MMcf/d.

        In 2014, we completed approximately 100 miles of gathering pipeline in Oklahoma and Texas.

        See Our Operating Segments below for additional discussion of our existing operations and planned expansions.

Business Strategy

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

    Developing long-term integrated relationships with our producer customers.  We develop long-term integrated relationships with our producer customers. Our relationships are characterized by an intense focus on customer service and a deep understanding of our producer customers' requirements coupled with the ability to increase the level of our midstream services in response to their midstream requirements. Through joint planning, we continue to construct high-quality midstream infrastructure and provide unique solutions that are critical to the ongoing success of our producer customers' development plans. As a result of delivering high-quality midstream services, we have been the top-rated midstream service provider since 2006 as determined by an independent research provider.

    Expanding operations through organic growth projects.  By expanding our existing infrastructure for existing and new customer relationships, we intend to continue growing in our primary areas of operation to meet the anticipated demand for additional midstream services. From January 1, 2011 through December 31, 2014, we have spent approximately $6.9 billion on capital expenditures (excluding the portion funded from our current and former joint venture partners), to develop midstream infrastructure in the Marcellus and Utica Shales, have placed into service approximately 4.1 Bcf/d of processing capacity and have constructed approximately one thousand miles of pipelines. During that time, we also executed long-term agreements with producers that have supported or will support the construction of 35 new processing plants in the Marcellus and Utica Shales, which we expect will increase our total company-wide processing capacity by the end of 2015 by approximately 500% since the end of 2010.

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    Expanding operations through strategic acquisitions.  We have completed a significant strategic acquisition in two of the last three years to support growth in our Marcellus and Southwest segments. 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 regions outside of our current areas of operation.

    Maintaining our financial flexibility.  Our goal is to maintain a capital structure that provides us flexibility to achieve our long-term growth strategy and ultimately achieve investment grade metrics. We currently have access to capital through our $1.3 billion investment-grade rated Credit Facility, and the public debt and equity markets. We plan to continue to strategically access the debt and equity markets. See Note 17 and Note 18 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, common unit offerings and Credit Facility.

    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. During 2014, fee-based contracts accounted for approximately 73% of our net operating margin and we estimate that this percentage will increase to approximately 89% for the full year ended December 31, 2015. The increase in fee-based net operating margin is due to an increase in fee-based contracts and assumes the current low commodity price environment continues such that it reduces the net operating margin earned from non-fee-based contracts. For the part of our business that is subject to commodity price exposure, we engage in risk management activities in order to reduce the effect of volatility in future natural gas, NGL and crude oil prices. We generally utilize swaps and options traded on the OTC market and fixed-price forward contracts to manage commodity price risk. We monitor these activities to ensure compliance with our commodity risk management policy. See Note 8 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. In addition, we maximize efficiency by coordinating the completion of new facilities in a manner that is consistent with the expected production that supports them.

        Execution of our business strategy has allowed us to grow substantially since our inception. As a result, we are now a leading provider of gathering, processing and fractionation services in the United States.

        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 to strengthen our leading positions in the liquids-rich areas of the Marcellus and Utica shale formations. As of February 18, 2015, our Marcellus, Utica and Northeast segments have combined processing capacity of approximately 4.7 Bcf/d and combined fractionation capacity of approximately 350,000 Bbl/d as well as an integrated NGL pipeline network and extensive logistics and marketing infrastructure. Our processing and fractionation capacity is supported by strategic long-term agreements, which include significant acreage dedications and minimum volumes commitments from our producer customers. We believe our significant asset base and full-service midstream model provides us with strategic competitive advantages in capturing and contracting for new supplies of natural gas as production in the Northeast continues to increase.

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    Strategic position with high-quality assets in the southwestern United States.  Over the past decade we have developed our presence in several long-lived natural gas supply basins in the Southwest, particularly in Texas and Oklahoma. All of our major operating assets and growth projects in this region have been characterized by several common 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 expansion opportunities. In 2014 we placed into service 320 MMcf/d of processing capacity and as of February 18, 2015, our Southwest segment has processing capacity of approximately 1.1 Bcf/d.

    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. The table below provides long-term contract details by segment as of December 31, 2014:

 
  Remaining contract term   % of volumes  

Marcellus

  7 to 11 years     100 %

Utica

  7 to 15 years     97 %

Northeast

  More than 4 years     54 %

Southwest

  More than 4 years     39 %
    Experienced management with operational, technical and acquisition expertise.  Each member of our executive management team has substantial experience in the energy industry and has interests aligned with those of our common unitholders through our long-term incentive compensation plans. Our facility managers have extensive industry experience with respect to the operation of midstream facilities. Our management team has decades of operational and technical expertise that has enabled us to successfully execute our business plans. Since our initial public offering in May 2002, our management team has utilized a disciplined approach to analyze and evaluate numerous growth opportunities, and has executed over $11 billion in organic growth projects and strategic acquisitions.

Industry Overview

        We provide services in the midstream sector of the natural gas industry. The midstream natural gas industry is the link between the exploration for and production of natural gas and the delivery of its hydrocarbon components to end-use markets. Operators within this industry create value at various stages along the natural gas value chain by gathering raw natural gas from producers at the wellhead, separating the hydrocarbons into dry gas (primarily methane) and NGLs, and then routing the separated dry gas and NGL streams for delivery to end-use markets or to the next intermediate stage of the value chain. The following diagram illustrates the assets and processes found along the natural gas value chain:

GRAPHIC

Service Types

        The services provided by us and other midstream natural gas companies are generally classified into the categories described below.

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    Gathering and Compression.

    Gathering.    The natural gas production process begins with the drilling of wells into gas-bearing rock formations. At the initial stages of the midstream value chain, a network of typically smaller diameter pipelines known as gathering systems directly connect to wellheads in the production area. These gathering systems transport raw, or untreated, natural gas to a central location for treating and processing. A large gathering system may involve thousands of miles of gathering lines connected to thousands of wells. Gathering systems are typically designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow gathering of additional production without significant incremental capital expenditures.

    Compression.    Natural gas compression is a mechanical process in which a volume of natural gas at a given pressure is compressed to a desired higher pressure, which allows the natural gas to be gathered more efficiently and delivered into a higher pressure system, processing plant or pipeline. Field compression is typically used to allow a gathering system to operate at a lower pressure or provide sufficient discharge pressure to deliver natural gas into a higher pressure system. Since wells produce at progressively lower field pressures as they deplete, field compression is needed to maintain throughput across the gathering system.

    Treating and dehydration.    To the extent that gathered natural gas contains contaminants, such as water vapor, carbon dioxide and/or hydrogen sulfide, such natural gas is dehydrated to remove the saturated water and treated to separate the carbon dioxide and hydrogen sulfide from the gas stream.

    Processing.  Natural gas has a widely varying composition depending on the field, formation reservoir or facility from which it is produced. Processing removes the heavier and more valuable hydrocarbon components, which are extracted as a mixed NGL stream that includes ethane, propane, butanes and natural gasoline (also referred to as "y-grade"). Processing aids in allowing the residue gas remaining after extraction of NGLs to meet the quality specifications for long-haul pipeline transportation or commercial use.

    Fractionation.  Fractionation is the separation of the mixture of extracted NGLs into individual components for end-use sale. It is accomplished by controlling the temperature and pressure of the stream of mixed NGLs in order to take advantage of the different boiling points and vapor pressures of separate products. 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. A fractionator can fractionate one product or in central fractionator, multiple products. We operate fractionation facilities at certain processing complexes that separate ethane from the remainder of the y-grade stream. We also operate central fractionation facilities that separate y-grade into propane, butanes and natural gasoline.

    Storage, transportation and marketing.  Once the raw natural gas has been treated or processed and the raw NGL mix has been fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. Each pipeline system typically has storage capacity located both throughout the pipeline network and at major market centers to help temper seasonal demand and daily operational or supply-demand shifts. We have caverns for propane storage in the northeast United States. We market NGLs domestically as well as for export to international markets.

        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 using

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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 and tight sand formations, have become the most significant source of current and expected future natural gas production. 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 shale plays will likely have a competitive advantage.

        Basic NGL products and their typical uses are discussed below. The basic products are sold in all of our segments.

    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.

    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.

    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, housewares and medical products.

Our Operating Segments

        We conduct our operations in the following operating segments: Marcellus, Utica, Northeast and Southwest. Our assets and operations in each of these segments are described below.

        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, 2014:

 
  Marcellus   Utica   Northeast   Southwest  

Segment revenue

    36 %   7 %   9 %   48 %

Net operating margin

    48 %   10 %   9 %   33 %

Marcellus Segment

        In our Marcellus segment, we provide fully integrated natural gas midstream services in southwestern Pennsylvania and northern West Virginia through our wholly owned subsidiary, MarkWest Liberty Midstream. With a total current processing capacity of approximately 3.2 Bcf/d, we are the largest processor of natural gas in the Marcellus Shale, and have fully integrated gathering, processing, fractionation, storage and marketing operations that support the growing liquids-rich natural gas production in the northeast United States.

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Natural Gas Gathering and Processing

        We currently operate five processing complexes in our Marcellus segment, including: the Houston Complex located in Washington County, Pennsylvania (the "Houston Complex"); the Majorsville Complex located in Marshall County, West Virginia (the "Majorsville Complex"); the Mobley Complex located in Wetzel County, West Virginia (the "Mobley Complex"); the Sherwood Complex located in Doddridge County, West Virginia (the "Sherwood Complex"); and the Keystone Complex. In addition, we operate two natural gas gathering systems. The gathering and processing capacity at these facilities are supported by long-term fee-based agreements with eleven major producer customers. The following tables summarize our current and planned operations at these facilities:

    Gathering

        The following table summarizes our current gathering assets at these facilities:

Complex associated with gathering system
  Key producer
customers
  Counties that
gathering system serves
Keystone Complex   Rex Energy   Butler County, PA
Houston Complex   Range Resources Corporation ("Range")   Washington County, PA

    Processing

        The following table summarizes our current and planned processing assets at these facilities:

Complex
  Existing
capacity
(MMcf/d)
  Expansion
capacity under
construction
(MMcf/d)
  Expected
in-service of
expansion capacity
(amounts are MMcf/d)
  Key producer
customers

Keystone Complex

   
210
   
400
 

200 Q4 2015
200 Q3 2016

 

Rex Energy

Fox Complex

   
   
200
 

Q3 2016

 

Range Resources

Houston Complex

   
355
   
200
 

Q2 2015

 

Range Resources

Mobley Complex

   
720
   
200
 

Q4 2015

 

CNX
EQT
Magnum Hunter
Noble
Stone Energy

Sherwood Complex

   
1,000
   
400
 

200 Q2 2015
200 Q2 2016

 

Antero
CNX
Noble

Majorsville Complex

   
870
   
400
 

200 Q2 2015
200 Q1 2016

 

Southwestern Energy
CNX
Noble
Range Resources
Statoil

Total

    3,155     1,800        

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NGL Gathering and Fractionation Facilities

        The NGLs produced at our Majorsville Complex, Mobley Complex, Sherwood Complex and a third-party's Fort Beeler processing facility are gathered to the Houston Complex or to the Hopedale Complex through a system of NGL pipelines to allow for fractionation into purity NGL products. In addition, NGL's produced at a third party's processing facility in Butler County, Pennsylvania are transported through an NGL pipeline to our Keystone Complex for fractionation into purity NGL products.

    Fractionation Facilities

        Our fractionation facilities for propane and heavier NGLs are supported by long-term fee-based agreements with our key producer customers. The following tables summarize our current and planned fractionation assets at these facilities:

Complex
  Existing propane
and heavier
NGLs + capacity
(Bbl/d)
  Propane and
heavier NGLs
expansion
capacity under
construction
(Bbl/d)
  Expected in
Service
  Market outlets

Keystone Complex

    12,000     31,000   Q4 2015   Railcar and truck loading

Hopedale Complex(1)

   
120,000
   
60,000
 

Q1 2016

 

Key interstate pipeline access
Railcar and truck loading

Houston Complex

   
60,000
   
 

 

Key interstate pipeline access
Railcar and truck loading
Marine vessels

Total

    192,000     91,000        

(1)
Hopedale is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, which are consolidated proportionally in the Marcellus and Utica segments, respectively.

    Ethane Recovery and Associated Market Outlets

        Due to increased natural gas production from the liquids-rich area of the Marcellus Shale, we have begun recovering ethane from the natural gas stream for producer customers, which allows them to meet residue gas pipeline quality specifications and downstream pipeline commitments. Depending on market conditions, producer customers may also benefit from the potential price uplift received from the sale of their ethane. The following table summarizes our current and planned de-ethanization assets, which are, or are expected to be, supported by a network of purity ethane pipelines:

Location
  Status/
Expected
in Service
  Ethane
Capacity
(Bbl/d)
 

Keystone Complex

    Operational     14,000  

Keystone Complex

    Q4 2016     40,000  

Fox Complex

    Q3 2016     20,000  

Houston Complex

    Operational     40,000  

Mobley Complex

    Q4 2015     10,000  

Sherwood Complex

    Q3 2015     40,000  

Majorsville Complex

    Operational     40,000  

Total

          204,000  

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        We have connections to several downstream ethane pipeline projects from many of our complexes as follows:

    We began delivering purity ethane to Sunoco Logistics Partners L.P.'s ("Sunoco") Mariner West pipeline ("Mariner West") from the Houston Complex in the fourth quarter of 2013 and from the Keystone Complex in the second quarter of 2014.

    We began delivering purity ethane to Enterprise Products Partners L.P.'s Appalachia-to-Texas Express ("ATEX") pipeline in the fourth quarter of 2013.

    Sunoco is developing the Mariner East project ("Mariner East"), a pipeline and marine project that originates at our Houston Complex. Beginning in December 2014, Mariner East began transporting propane to Sunoco's terminal near Philadelphia, Pennsylvania ("Marcus Hook Facility") where it is loaded onto marine vessels and delivered to international markets. By mid-2015, Mariner East will transport purity ethane in addition to propane to the Marcus Hook Facility.

    Sunoco has announced phase two of Mariner East ("Mariner East II") with plans to construct a pipeline from our Houston and Hopedale complexes in Western Pennsylvania and Eastern Ohio, respectively, to transport propane and butane to the Marcus Hook Facility where it will be loaded onto marine vessels and delivered to domestic and international markets. The Mariner East II pipeline is expected to be operational in the fourth quarter of 2016.

        Revenue earned from gathering and processing fees from Range are significant to the segment, accounting for 38.4% of the segment revenue and 14.0% of consolidated revenue during 2014. Additionally, the Marcellus segment had one customer that accounted for 12.5% of its segment revenue, but this customer did not account for a significant portion of our consolidated revenue.

Utica Segment

        In our Utica section, MarkWest Utica EMG provides gathering, processing, fractionation and marketing services in the liquids-rich and dry-gas areas of the Utica Shale in Ohio. The graphic depicted below reflects our Utica ownership summary as of December 31, 2014 (shaded boxes represent third-party entities).

GRAPHIC


(1)
Results of operations and financial position are consolidated by MarkWest Energy.

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(2)
Results of operations and financial position are reported under the equity method of accounting. Prior to June 1, 2014, Ohio Gathering's results of operations and financial position were consolidated.

(3)
Results of operations and financial position are consolidated for segment reporting.

(4)
Each MarkWest Energy entity pays its share of operating expenses based partially on its ownership percentage and partially on its actual usage of the facility. From time to time as additional fractionation capacity is completed, ownership percentages may change. The capital funding is based on ownership percentages.

(5)
Capital contributed based on ownership percentages.

(6)
Pursuant to the Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG, the aggregate funding commitment of EMG Utica, LLC ("EMG Utica") increased to $950.0 million (the "Minimum EMG Investment"). EMG Utica was required to fund all capital until the Minimum EMG Investment was satisfied, which occurred in May 2013. After EMG Utica funded the Minimum EMG Investment, the Partnership was required to fund, as needed, 100% of future capital for MarkWest Utica EMG until such time as the aggregate capital that had been contributed by the Partnership and EMG Utica reached $2.0 billion, which occurred in November 2014. After such time, and until such time as the investment balances of the Partnership and EMG Utica are in the ratio of 70% and 30%, respectively (such time being referred to as the "Second Equalization Date"), EMG Utica will have the right, but not the obligation, to fund up to 10% of each capital call for MarkWest Utica EMG, and the Partnership will be required to fund all remaining capital not elected to be funded by EMG Utica. After the Second Equalization Date, the Partnership and EMG Utica will have the right, but not the obligation, to fund their pro rata portion (based on their respective investment balances) of any additional required capital and may also fund additional capital that the other party elects not to fund. As of December 31, 2014, we have contributed approximately 55% of the capital to MarkWest Utica EMG; however, we currently own 60% of MarkWest Utica EMG and we receive 60% of cash generated by that entity. We will continue to own such amount of, and to receive such portion of the cash generated by, MarkWest Utica EMG until the earlier of December 31, 2016 and the date that our investment balance equals 60%, at which time the amount of MarkWest Utica EMG that we own, and the percentage of cash generated by that entity that we will receive, will be based on the Partnership's and EMG Utica's respective investment balances.

(7)
We own 100% of MarkWest Liberty Midstream.

Natural Gas Gathering and Processing

        MarkWest Utica EMG operates two processing complexes in the Utica Shale with a total capacity of approximately 925 MMcf/d: the Cadiz Complex in Harrison County, Ohio and the Seneca Complex in Noble County, Ohio. In addition, we continue to expand our gathering system which currently spans more than 320 miles and delivers natural gas to both of the processing complexes. Our gathering and processing facilities are supported by long-term fee based agreements with several key producers in the Utica Shale.

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    Gathering

        The following table summarizes our current gathering assets:

Gathering system
  Key producer
customers
  Counties that
gathering system serves
Gas gathering   AEU
Gulfport
PDC
Rex Energy
  Harrison, Belmont, Guernsey and Noble Counties, OH

        We have executed a dry gas gathering agreement serving Monroe County, Ohio that is expected to be operational in the first half of 2015.

    Processing

        The following table summarizes our current and planned processing assets at these facilities:

Complex
  Existing
capacity
(MMcf/d)
  Expansion
capacity under
construction
(MMcf/d)
  Expected
in-service of
expansion
capacity
  Key
producer
customers(1)

Cadiz Complex

    325     400   200—Q2 2015
200—Q1 2016
  AEU
Gulfport

Seneca Complex

   
600
   
200
 

Q2 2015

 

AEU
Antero
Gulfport
PDC
Rex Energy

Total

    925     600        

(1)
We have the operational flexibility to process gas for all of the key producer customers at either complex.

Fractionation Facility and Market Outlets

        The Hopedale Complex is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, which are included in the Marcellus and Utica segments, respectively. See the table above in the Marcellus segment for information related to the current and planned operations at the Hopedale Complex.

Ethane Recovery and Associated Market Outlets

        We completed a 40,000 Bbl/d de-ethanization facility at our Cadiz Complex in the third quarter of 2014. Ethane produced at our Cadiz Complex is delivered to the ATEX Pipeline.

        The Utica segment had two individual customers that accounted for 56.9% and 18.1% of its segment revenue, respectively during 2014. Neither of these customers accounted for a significant portion of our consolidated revenues.

Northeast Segment

    Kentucky and southern West Virginia.  Our Northeast segment assets include the Kenova, Boldman, Cobb, Kermit and Langley natural gas processing complexes, an NGL pipeline and the

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      Siloam fractionation facility (together our "Appalachia Reporting Unit"). The Siloam fractionation facility can also be used to provide fractionation services to MarkWest Liberty and MarkWest Utica EMG. In addition, we have two caverns for storing propane at our Siloam facility and we have additional propane storage capacity under a firm-capacity agreement with a third party utilized by the Siloam facility as well as MarkWest Liberty and MarkWest Utica EMG producer customers.

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

        The Northeast segment had one customer that accounted for 17.8% of its segment revenue during 2014, but this customer did not account for a significant portion of our consolidated revenue. Additionally, all of the natural gas processed in the segment is attributable to three producers. The contract with one producer whose volumes accounted for approximately 22% of the segment's net operating margin for the year ended December 31, 2014, expires on December 31, 2015.

Southwest Segment

    East Texas.  We own a system that consists of natural gas gathering pipelines, centralized compressor stations, two natural gas processing complexes and two NGL pipelines (the "East Texas System"). 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, Haynesville and Bossier formations. In December 2014 we commenced operations of an additional 120 MMcf/d processing plant in our East Texas area, bringing our total processing capacity in East Texas to 520 MMcf/d.

    Oklahoma.  We own gas gathering systems in the Granite Wash formation of Western Oklahoma and the Texas panhandle, both of which are connected to natural gas processing complexes in Western Oklahoma. The gathering systems include compression facilities and the majority of the gathered gas is ultimately compressed and delivered to the natural gas processing complexes. Our 200 MMcf/d Buffalo Creek plant and high-pressure gathering trunk line, which was acquired partially constructed in May 2013 commenced operations in February 2014. The addition of the Buffalo Creek plant brings our total natural gas processing capacity in Western Oklahoma to 435 MMcf/d.

      In addition, we own an extensive 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, or other third-party processors. Centrahoma commenced operations of an additional 120 MMcf/d processing capacity at its Stonewall plant in the second quarter of 2014. We agreed to fund the construction of an additional 80 MMcf/d processing capacity at Centrahoma's Stonewall plant, of which 40 MMcf/d became operational in December 2014. The remaining 40 MMcf/d of additional capacity will commence operations in the first half of 2015. Through another equity method investment, MarkWest Pioneer L.L.C. ("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.

    Javelina.  We own and operate the Javelina processing and fractionation facility in Corpus Christi, Texas that treats, processes and fractionates 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 the entire product processed by the SMR, which is operated by a third-party. See Note 7 of the accompanying Notes to Consolidated Financial Statements for further discussion of this agreement and the

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      related sale of the SMR (the "SMR Transaction"). The product received under this agreement is sold to a refinery customer pursuant to a corresponding long-term agreement.

    Other Southwest.  We own a number of natural gas gathering systems and lateral pipelines located in Texas, Louisiana and New Mexico, including the Appleby gathering system in Nacogdoches County, Texas. Our Hobbs, New Mexico natural gas lateral pipeline ("Hobbs Pipeline") is subject to regulation by FERC. We also operate natural gas gathering pipelines and field compression to support production from Newfield Exploration Co.'s West Asherton area of the Eagle Ford Shale in Dimmit County, Texas ("West Asherton facilities").

        Approximately 64% of our Southwest segment volumes in 2014 resulted from contracts with eight producer customers. We sell substantially all of the NGLs produced in the Western Oklahoma processing complexes to one customer under a long-term contract. Such sales represented approximately 15.4% of our Southwest segment revenue in 2014, but this customer did not account for a significant portion of our consolidated revenue.

        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.

    Equity Investment in Unconsolidated Affiliates

    Ohio Gathering.  Ohio Gathering is a subsidiary of MarkWest Utica EMG and is engaged in providing natural gas gathering services in the Utica Shale in eastern Ohio. Prior to June 2014, Ohio Gathering results of operations and financial position were consolidated. In June 2014, Summit exercised an option to acquire 40% interest in Ohio Gathering, which resulted in the deconsolidation of Ohio Gathering. See Note 3 to the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion. After the option was exercised by Summit, MarkWest Utica EMG owns 60% of Ohio Gathering, resulting in our indirectly owning 36% of Ohio Gathering.

    MarkWest Utica EMG Condensate.  MarkWest Utica EMG Condensate, L.L.C. ("MarkWest Utica EMG Condensate") is our joint venture with EMG Utica Condensate, LLC ("EMG Utica Condensate"). MarkWest Utica EMG Condensate and its subsidiary, Ohio Condensate, support the development of industry-leading condensate facilities and services for producers in the Utica Shale. In June 2014, Summit exercised an option to acquire a 40% interest in Ohio Condensate. See Note 3 to the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of Summit's option. The 23,000 Bbl/d condensate stabilization facility, located in Harrison County, Ohio is expected to begin operations in early 2015. We own 55% of MarkWest Utica EMG Condensate, and thus we indirectly own 33% of Ohio Condensate.

    Centrahoma.  We own a 40% non-operating membership interest in Centrahoma, a joint venture in the Southwest segment with Atlas Pipeline Partners, L.P. ("Atlas") that is accounted for using the equity method. Centrahoma owns certain processing plants in the Arkoma Basin and Atlas 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 Atlas' independently owned processing facility. The Centrahoma processing facility is being expanded by an additional 80 MMcf/d of which 40 MMcf/d became operational in December 2014. The remaining 40 MMcf/d of the expansion will commence operations in the first half of 2015.

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    MarkWest Pioneer.  Through our joint venture, MarkWest Pioneer, we operate the Arkoma Connector Pipeline, a 50-mile FERC-regulated pipeline in Oklahoma that is designed to provide approximately 638,000 Dth/d of Woodford Shale takeaway capacity and that interconnects with the Midcontinent Express Pipeline, Gulf Crossing Pipeline and Natural Gas Pipeline of America L.L.C.

        The financial results for Ohio Gathering, MarkWest Utica EMG Condensate and its subsidiary, Centrahoma and MarkWest Pioneer are included in Earnings from unconsolidated affiliates in our Consolidated Statements of Operations. They are not included in our segment results, except for Ohio Gathering. For a complete discussion of the formation of, and the accounting treatment for, Ohio Gathering, see Note 3 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

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 gathering, 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, the Partnership receives a fee or fees for one or more of the following services: gathering, processing and transmission of natural gas; gathering, transportation, fractionation, exchange and storage of NGLs; and gathering and transportation of crude oil. The revenue the Partnership earns from these arrangements is generally directly related to the volume of natural gas, NGLs or crude oil that flows through the Partnership's systems and facilities and is not normally directly dependent on commodity prices. In certain cases, the Partnership's arrangements provide for minimum annual payments or fixed demand charges.

      Fee-based arrangements are reported as Service Revenue on the Consolidated Statements of Operations. In certain instances when specifically stated in the contract terms, the Partnership purchases product after fee-based services have been provided. Revenue from the sale of products purchased after services are provided is reported as Product Sales and recognized on a gross basis as the Partnership is the principal in the transaction.

    Percent-of-proceeds arrangements—Under percent-of-proceeds arrangements, the Partnership gathers and processes natural gas on behalf of producers, sells the resulting residue gas, condensate and NGLs at market prices and remits to producers an agreed-upon percentage of the proceeds. In other cases, instead of remitting cash payments to the producer, the Partnership delivers an agreed-upon percentage of the residue gas and NGLs to the producer (take-in-kind arrangements) and sells the volumes the Partnership retains to third parties. Revenue from these arrangements is reported on a gross basis where the Partnership acts as the principal, as the Partnership has physical inventory risk and does not earn a fixed dollar amount. The agreed-upon percentage paid to the producer is reported as Purchased Product Costs on the Consolidated Statements of Operations. Revenue is recognized on a net basis when the Partnership acts as an agent and earns a fixed dollar amount of physical product and does not have risk of loss of the gross amount of gas and/or NGLs. Percent-of-proceeds revenue is reported as Product Sales on the Consolidated Statements of Operations.

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

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      third parties at market prices. Because the extraction of the condensate and NGLs from the natural gas during processing reduces the Btu content of the natural gas, the Partnership must either purchase natural gas at market prices for return to producers or make cash payment to the producers equal to the energy content of this natural gas. Certain keep-whole arrangements also have provisions that require the Partnership to share a percentage of the keep-whole profits with the producers based on the oil to gas ratio or the NGL to gas ratio. Sales of NGLs under these arrangements are reported as Product Sales on the Consolidated Statements of Operations and are reported on a gross basis as the Partnership is the principal in the arrangement. Natural gas purchased to return to the producer and shared NGL profits are recorded as Purchase Product Costs in the Consolidated Statement of Operations.

    Percent-of-index arrangements—Under percent-of-index arrangements, the Partnership purchases natural gas at either (1) a percentage discount to a specified index price, (2) a specified index price less a fixed amount or (3) a percentage discount to a specified index price less an additional fixed amount. The Partnership then gathers and delivers the natural gas to pipelines where the Partnership resells the natural gas at the index price or at a different percentage discount to the index price. Revenue generated from percent of index arrangements are reported as Product Sales on the Consolidated Statements of Operations and are recognized on a gross basis as the Partnership purchases and takes title to the product prior to sale and is the principal in the transaction.

        In many cases, the Partnership provides services under contracts that contain a combination of more than one of the arrangements described above. When fees are charged (in addition to product received) under keep-whole arrangements, percent-of-proceeds-arrangements or percent-of-index-arrangements, the Partnership records such fees as Service Revenue on the Consolidated Statements of Operations. The terms of the Partnership's contracts vary based on gas quality conditions, the competitive environment when the contracts are signed and customer requirements.

        Amounts billed to customers for shipping and handling, including fuel costs, are included in Product Sales on the Consolidated Statements of Operations, except under contracts where we are acting as an agent. Shipping and handling costs associated with product sales are included in Purchased Product Costs on the Consolidated Statements of Operations. Taxes collected from customers and remitted to the appropriate taxing authority are excluded from revenue. Facility expenses and depreciation represent those expenses related to operating our various facilities and are necessary to provide both Product Sales and Services Revenue.

        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 25 to the accompanying Consolidated Financial Statements and are considered non-GAAP financial measures when presented outside of the Notes to the 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 25 to the accompanying 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.

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        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.

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

 
  Year ended December 31,  
 
  2014   2013   2012  

Segment revenue

  $ 2,167,808   $ 1,693,267   $ 1,389,214  

Segment purchased product costs

    (832,682 )   (691,165 )   (530,328 )

Net operating margin

    1,335,126     1,002,102     858,886  

Facility expenses

    (343,362 )   (291,069 )   (206,861 )

Derivative gain (loss)

    95,266     (25,770 )   69,126  

Revenue deferral adjustment and other

    9,660     (6,182 )   (5,935 )

Revenue adjustment for unconsolidated affiliate(1)

    (41,446 )        

Purchased product costs from unconsolidated affiliate(1)

    254          

Selling, general and administrative expenses

    (126,499 )   (101,549 )   (93,444 )

Depreciation

    (422,755 )   (299,884 )   (183,250 )

Amortization of intangible assets

    (64,893 )   (64,644 )   (53,320 )

Impairment of goodwill

    (62,445 )        

(Loss) gain on disposal of property, plant and equipment

    (1,116 )   33,763     (6,254 )

Accretion of asset retirement obligations

    (570 )   (824 )   (672 )

Income from operations

  $ 377,220   $ 245,943   $ 378,276  

(1)
These amounts relate to Ohio Gathering. The chief operating decision maker and management includes Ohio Gathering to evaluate the segment performance as we continue to operate and manage Ohio Gathering operations. Therefore, the impact of the revenue and purchased product costs is included for segment reporting purposes, but removed for GAAP purposes.

        The following table does not give effect to our active commodity risk management program. For further discussion of how we manage commodity price volatility for the portion of our net operating margin that is not fee-based, see Note 8 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K. We manage our business by taking into account the partial offset of short natural gas positions primarily in our Southwest segment. The calculated percentages for net operating margin for percent-of-proceeds, percent-of-index and keep-whole contracts reflect the partial offset of our natural gas positions. The calculated percentages are less than one percent for percent-of-index due to the offset of our natural gas positions and, therefore, not

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meaningful to the table below. For the year ended December 31, 2014, we calculated the following approximate percentages of our segment net operating margin from the following types of contracts:

 
  Fee-Based   Percent-of-
Proceeds(1)
  Keep-Whole(2)  

Marcellus

    87 %   13 %   0 %

Utica(3)

    100 %   0 %   0 %

Northeast

    24 %   17 %   59 %

Southwest

    59 %   36 %   5 %

Total

    73 %   20 %   7 %

(1)
Includes condensate sales and other types of arrangements tied to NGL prices.

(2)
Includes condensate sales and other types of arrangements tied to both NGL and natural gas prices.

(3)
Includes Ohio Gathering, an unconsolidated affiliate (See Note 3 of the Consolidated Financial Statements included in Item 8 of this Form 10-K).

Competition

        In each of our operating segments, we face competition for natural gas gathering, crude oil transportation and in obtaining natural gas supplies for our processing and related services; in obtaining unprocessed NGLs for gathering and fractionation; and in marketing our products and services. Competition for natural gas supplies is based primarily on the location of gas gathering facilities and gas processing plants, operating efficiency and reliability and the ability to obtain a satisfactory price for products recovered. Competitive factors affecting our fractionation services include availability of capacity, proximity to supply and industry marketing centers and cost efficiency and reliability of service. Competition for customers 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:

    natural gas midstream providers, of varying financial resources and experience, that gather, transport, process, fractionate, store and market natural gas and NGLs;

    major integrated oil companies;

    medium and large sized independent exploration and production companies; and

    major interstate and intrastate pipelines.

        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, 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 believe we have critical connections to the key market outlets for NGLs and natural gas in each of our segments. In the Marcellus and Utica segments, our early entrance in the liquids-rich corridors of the Marcellus and Utica Shales through our strategic gathering and processing agreements with key producers enhances our competitive position to participate in the further development of these resource plays. In the Northeast segment, our operational experience of more than 20 years as the largest processor and fractionator and our existing presence in the Appalachian Basin provide a significant competitive advantage. In the Southwest

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segment, our major gathering systems are less than 15 years old, located primarily in the heart of shale plays with significant long-term growth opportunities and provide producers with low-pressure and fuel-efficient service, which differentiates us from many competing gathering systems in those areas. The strategic location of our assets and the long-term nature of many of our contracts also provide a significant competitive advantage.

Seasonality

        Our business can be affected by seasonal fluctuations in the demand for natural gas and NGLs and the related fluctuations in commodity prices caused by various factors such as changes in transportation and travel patterns and variations in weather patterns from year to year. Our Northeast segment could be particularly impacted by seasonality as the majority of its revenues are generated by NGL sales. However, we manage the seasonality impact through the execution of our marketing strategy. We have access to up to 50 million gallons of propane storage capacity in the northeast region provided by an arrangement with a third-party which provides us with flexibility to manage the seasonality impact. Overall, our exposure to the seasonal fluctuations in the commodity markets is declining due to our growth in fee-based business.

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 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 Pipeline and the Arkoma Connector Pipeline have FERC gas tariffs on file for MarkWest New Mexico, L.L.C. and MarkWest Pioneer, L.L.C., respectively. These pipelines are subject to regulation by FERC, and it is possible that we may have additional gas pipelines in the future that may require such tariffs and may be subject to similar 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

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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 the Hobbs Pipeline and the Arkoma Connector Pipeline can be found in their respective FERC-approved tariffs. Pursuant to FERC's jurisdiction, existing rates and/or other tariff provisions may be challenged by complaint and rate increases proposed by the pipeline or other tariff changes may be challenged by protest. We also 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, rights of access, capacity and other issues that impact natural gas facilities. Any successful complaint or protest related to our facilities could have an adverse impact on our revenues.

        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. 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, 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.

        Standards of Conduct.    In 2008, FERC issued standards of conduct for transmission providers in Order 717, as amended and clarified in subsequent orders on rehearing, 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).

        Market Transparency Rulemakings.    In 2007, FERC issued Order 704, as amended and clarified in subsequent orders on rehearing, 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, 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. The Partnership typically files the report required by Order 704 on behalf of its subsidiaries that engage in reportable transactions. On November 15, 2012, FERC issued a Notice of Inquiry in Docket No. RM 13-1-000 requesting comments on whether it should propose to require the quarterly reporting of certain data relating to next-day and next-month transactions. FERC issued data requests to certain natural gas marketers in July 2013 and FERC has not proceeded with any further action in the docket since that time.

        Intrastate Natural Gas Pipeline Regulation.    Some of our intrastate gas pipeline facilities are subject to various state laws and regulations 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

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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. Additionally, FERC has adopted certain regulations and reporting requirements applicable to intrastate natural gas pipelines (and Hinshaw natural gas pipelines) that provide certain interstate services subject to FERC's jurisdiction. We could become subject to such regulations and reporting requirements in the future to the extent that any of our intrastate pipelines were to begin providing, or were found to provide, such interstate services.

        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. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. We own a number of facilities that we believe meet the traditional tests FERC uses to establish a pipeline's status as a gatherer not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so we cannot provide assurance that FERC will not at some point assert that these facilities are within its jurisdiction or that such an assertion would not adversely affect our results of operations and revenues. In such a case, we would possibly be required to file a tariff with FERC, provide a cost justification for the transportation charge and obtain certificate(s) of public convenience and necessity for the FERC-regulated pipelines, and comply with additional FERC requirements.

        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 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 gather 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 requirements 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.

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        Natural Gas Processing.    Our natural gas processing operations are not presently subject to FERC or state regulation. There can be no assurance that our processing operations will continue to be exempt from FERC regulation in the future. In addition, although the processing facilities may not be directly related, other laws and regulations may affect the availability of natural gas for processing, such as state regulation of production rates and maximum daily production allowables from gas wells, which could impact our processing business.

        NGL Pipelines.    We have constructed various NGL product pipelines to transport NGL products, some of which are regulated by FERC and we may elect to construct additional NGL product pipelines in the future that may be subject to these requirements. Common carrier NGL pipelines providing transportation of NGLs in interstate commerce are subject to the same regulatory requirements as common carrier crude oil pipelines. See "Common Carrier Crude Oil Pipeline Operations" below. We have several NGL pipelines that carry NGLs across state lines; however, we do not have FERC tariffs on file for these pipelines because they are not subject to the FERC requirements or would otherwise meet the qualifications for a waiver from FERC's tariff 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 gathering is subject to FERC requirements for common carrier pipelines or is otherwise not exempt from its filing or reporting requirements, or that such an assertion would not adversely affect our results of operations. In the event FERC were to determine that these NGL pipelines are subject to FERC requirements for common carrier pipelines or otherwise 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, and we may also be subject to fines, penalties or other sanctions. 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 pipelines and operations may also be or become subject to state public utility or related jurisdiction 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 U.S. Department of Transportation ("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 Oil Pipeline Operations.    Our Michigan Crude Pipeline is a crude oil pipeline that is a common carrier and subject to regulation by FERC under the October 1, 1977 version of the Interstate Commerce Act ("ICA") and the Energy Policy Act of 1992 ("EPAct 1992"). The ICA and its implementing regulations give FERC authority to regulate the rates charged for service on the interstate common carrier liquids pipelines and 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.

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        Pipeline Interconnections.    One or more of our plants include pipeline interconnections to interstate pipelines. These pipeline interconnections are an integral part of our facilities and are not currently being used, nor can they be used in the future, by any third party due to their origin points at our proprietary facilities. Therefore, we believe these pipeline interconnections are part of our plant facilities and are not subject to the jurisdiction of FERC. In the event that FERC were to determine that these pipeline interconnections were subject to its jurisdiction, we believe the pipelines would qualify for a waiver from most FERC reporting and filing requirements, including the obligation to file a FERC tariff. In the event that FERC were to determine that the pipeline interconnections did not qualify for such waivers, we would likely be required to file a tariff with FERC for the pipeline interconnections, provide a cost justification for the transportation charge and provide service to all potential shippers without undue discrimination. In such event, we may experience increased operating costs and reduced revenues.

Environmental Matters

    General.

        Our processing and fractionation plants, pipelines and associated facilities are subject to multiple obligations and potential liabilities under a variety of federal, regional, state and local laws and regulations relating to environmental protection. Such environmental laws and regulations may affect many aspects of our present and future operations, including for example, 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 construction or other activities in environmentally sensitive areas such as wetlands or areas inhabited by endangered species, requiring us to incur capital costs to construct, maintain and/or upgrade processes, equipment and/or facilities, restricting the locations in which we may construct our compressor stations and other facilities and/or requiring the relocation of existing stations and facilities, and requiring remedial actions to mitigate any pollution that might be caused by our operations or attributable to former operations. Spills, releases or other incidents may occur in connection with our active operations or as a result of events outside of our reasonable control, which incidents may result in non-compliance with such laws and regulations. Any failure to comply with these legal requirements may expose us to the assessment of sanctions, including administrative, civil and criminal penalties, the imposition of remedial or corrective actions 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 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 environmental 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 adversely affect the environment. For example, in Pennsylvania, we are experiencing additional issues associated with permitting, land use and zoning. Following a Pennsylvania Supreme Court decision that declared unconstitutional portions of a statute adopting a statewide permitting regime under the state's Oil and Gas Act ("Act 13") pursuant to a new application of a 1971 amendment to the Constitution of the Commonwealth of Pennsylvania (the Environmental Rights Amendment, PA. CONST. Art. 1, § 27), new challenges have been asserted with respect to local townships' permitting, land use and zoning regulation of oil and gas activities relying in part on the Court decision. These challenges may cause significant delays in obtaining permitting approvals for our facilities, result in the denial of our permitting applications, or cause us to become involved in time consuming and costly litigation. Conversely, the Ohio Supreme Court recently affirmed the state-wide permitting system under Ohio's oil and gas statutes and regulations preempted local permitting, land

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use and zoning regulations and ordinances. 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 requirements, or remedial actions pursuant to such laws and regulations, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional environmental requirements may result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, and 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 substantially increased costs and material delays in the construction of new facilities or expansion of our existing facilities, which may materially impact our ability to meet our construction obligations with our producer customers.

    Hazardous Substances and Wastes.

        A comprehensive framework of environmental laws and regulations governs our operations as they relate to the possible release of hazardous substances or non-hazardous or hazardous wastes into soils, groundwater and surface water and measures taken to mitigate pollution into the environment. For instance, the Comprehensive Environmental Response, Compensation, and Liability Act, as amended ("CERCLA"), also known as the "Superfund" law, as well as comparable state laws impose liability without regard to fault or the legality of the original conduct on certain classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include current and prior owners or operators of a site where a release occurred and companies that transported or disposed or arranged for the transport or disposal of the hazardous substances released from the site. Under CERCLA, these persons may be subject to strict joint and several liabilities 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 may be regulated 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 ("RCRA"), and comparable state statutes, which impose requirements relating to the handling and disposal of non-hazardous and hazardous 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. In the course of our operations, we generate some amount of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes. While we are required to comply with RCRA requirements relating to hazardous wastes, currently our operations generate minimal quantities of hazardous wastes. However, it is possible that some wastes generated by us that are currently classified as non-hazardous wastes may in the future be designated as hazardous wastes, resulting in the wastes being subject to more rigorous and costly transportation, storage, treatment and 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 waste disposal practices within the NGL industry and other oil and natural gas related industries have been enhanced and improved over the years, it is possible that petroleum hydrocarbons and other non-hazardous 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

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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 wastes for which we are currently responsible.

    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.

        The prior third-party owner and/or operator of certain facilities on the real property on which our rail facility is 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.

        From time to time, we have acquired, and we may acquire in the future, facilities from third parties that previously have been or currently are the subject of investigatory, remedial or monitoring activities relating to environmental matters. The terms of each acquisition will vary, and in some cases we may receive contractual indemnification from the prior owner or operator for some or all of the liabilities relating to such matters, and in other cases we may agree to accept some or all of such liabilities. We do not believe that the portion of any such liabilities that the Partnership may bear with respect to any such properties previously acquired by the Partnership 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 ("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

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navigable waters in the event of a hydrocarbon tank spill, rupture or leak. Any unpermitted release of pollutants, including oil, NGLs or condensates, could result in administrative, civil and criminal 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 storm water from certain types of facilities, but these requirements are subject to several exemptions specifically related to oil and natural gas operations and facilities. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit. 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 storm water 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, there is no assurance that we will not incur material increases in our operating costs or delays in the construction or expansion of our facilities because of future developments, the implementation of new laws and regulations, the reinterpretation of existing laws and regulations, or otherwise, including, for example, increased construction activities, potential inadvertent releases arising from pursuing borings for pipelines, and earth slips due to heavy rain and/or other cause.

    Hydraulic Fracturing.

        We do not conduct hydraulic fracturing operations, but we do provide gathering, processing and fractionation services with respect to natural gas and NGLs produced by our producer customers as a result of such operations. 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 targeted subsurface formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing typically is regulated by state oil and natural gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the BLM issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015. In addition, Congress has from time to time considered legislation to provide for additional regulation of hydraulic fracturing, and some states have adopted, and other states are considering adopting, laws and/or regulations that could impose more stringent permitting, disclosure and well construction requirements on natural gas drilling activities. States could elect to prohibit hydraulic fracturing altogether, as Governor Andrew Cuomo of the State of New York announced in December 2014 with regard to fracturing activities in New York. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. 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 hydraulic fracturing-related 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.

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        In addition, certain governmental reviews are underway 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. In addition, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources is expected to be available for public comment and peer review in the first half of 2015. These ongoing or proposed studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing that 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 United States, 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. We may be required to incur capital expenditures in the future for installation of air pollution control equipment and encounter construction or operational delays while applying for, or awaiting the review, processing and issuance of new or amended permits, and we may be required to modify certain of our operations which could increase our operating costs. For example, in December 2014, the EPA published proposed regulations to revise the National Ambient Air Quality Standard for ozone, recommending a standard between 65 to 70 parts per billion, or ppb, for both the 8-hour primary and secondary standards protective of public health and public welfare. The EPA requested public comments on whether the standard should be set as low as 60 ppb or whether the existing 75 ppb standard should be retained. The EPA anticipates issuing a final rule by October 1, 2015. If the EPA lowers the ozone standard, states could be required to implement new more stringent regulations, which could apply to our operations and those of our producer customers. Compliance with these or other new regulations could, among other things, require installation of new emission controls on some of our equipment, result in longer permitting timelines, and significantly increase our capital expenditures and operating costs, which could adversely impact our business. The EPA has also been evaluating possible changes to regulations regarding flare operations, upsets and malfunctions, thresholds for determining non-attainment, and methane emissions from new and modified oil and gas production and natural gas processing and transmission facilities, any of which could require additional capital expenditures, increase our operating costs or otherwise restrict our operations. We have been in discussions with various state agencies in the areas in which we operate with respect to their guidance, 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 of an EPA administrative conclusion that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") into the ambient air endangers public health and welfare, the EPA adopted regulations establishing the Prevention of Significant Deterioration ("PSD") construction and Title V operating permit programs for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. In addition, the EPA, is considering regulation of methane emissions from oil and gas activities, as further described below, the EPA is also gathering information regarding existing facilities in various industries which

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may be used to support potential future regulation of GHGs. Although the EPA's PSD and Title V permit programs are limited to large stationary sources that already are potential major sources of criteria pollutant emissions, states may seek to adopt their own permitting programs under state laws that require permit reviews of large stationary sources emitting only GHGs. If we were to become subject to Title V and PSD permitting requirements due to non-GHG criteria pollutants, or if EPA implemented more stringent permitting requirements relating to GHG emissions without regard to non-GHG criteria pollutants, or if states adopt their own permitting programs that require permit reviews based on GHG emissions, we may be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future. In addition, we may experience substantial delays or possible curtailment of construction or projects in connection with applying for, obtaining or maintaining preconstruction and operating permits, we may encounter limitations on the design capacities or size of facilities, and we may incur material increases in our construction and operating costs. The EPA has also adopted rules requiring the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas 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 includes certain of our operations. In addition, on December 9, 2014, the EPA published a proposed rule that would expand the petroleum and natural gas system sources for which annual GHG emissions reporting is currently required to include GHG emissions reporting beginning in the 2016 reporting year for certain onshore gathering and boosting systems consisting primarily of gathering pipelines, compressors and process equipment used to perform natural gas compression, dehydration and acid gas removal. We are monitoring GHG emissions from certain of our facilities in accordance with current GHG emissions reporting requirements in a manner that we believe is in substantial compliance with applicable reporting obligations and we are currently assessing the potential impact that the December 9, 2014 proposed rule may have on our future reporting obligations, should the proposal be adopted. Additional reporting requirements could materially increase our construction and operating costs.

        Also, Congress has from time to time considered legislation to reduce emissions of GHGs, and while there has not been federal climate legislation adopted in the United States in recent years, it is possible that such legislation could be enacted in the future. In the absence of federal climate legislation in the U.S., a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress were to undertake comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for oil, natural gas, NGLs and products derived therefrom. Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emission allowances or comply with new regulatory or reporting requirements including the imposition of a carbon tax. For example, on January 14, 2015, the Obama Administration announced that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration's efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and natural gas produced by our exploration and production customers that, in turn, could reduce the demand for our services and thus adversely affect our cash available for distribution to our unitholders.

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    Endangered Species Act and Migratory Bird Treaty Act Considerations.

        The federal Endangered Species Act ("ESA") and analogous laws regulate activities that may affect endangered or threatened species, including their habitats. Endangered or threatened species that are located in various states in which we operate include the Indiana Bat, the American Burying Beetle and the Lesser Prairie Chicken. 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 in certain of those locations or during certain times, when our operations could result in a taking of the species. We also may be obligated to develop plans to avoid potential takings of protected species, the implementation of which could materially increase our operating and capital costs. Existing laws, regulations, policies and guidance relating to protected species may also be revised or reinterpreted in a manner that further increase our construction and mitigation costs or restricts our construction activities. Additionally, construction and operational activities could result in inadvertent impact to a 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 in September 2011, the U.S. Fish and Wildlife Service ("FWS") is required to make a determination on listing numerous species as endangered or threatened under the ESA by completion of the agency's 2017 fiscal year. For example, in October 2013, the FWS published a proposed rule to list the Northern Long Eared Bat as endangered under the ESA and is expected to make a final determination on this listing in 2015. In another example, in March 2014, the FWS announced the listing of the lesser prairie chicken as a threatened species under the ESA. Both of these species are in areas in which we operate. The listing of these or other species as threatened or endangered in areas where we conduct operations or plan to construct pipelines or facilities may cause us to incur increased costs arising from species protection measures or could result in delays in the construction of our facilities or limitations on our customer's exploration and production activities, which could have an adverse impact on demand for our midstream operations.

        The Migratory Bird Treaty Act implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds. In accordance with this law, the taking, killing or possessing of migratory birds covered under this act is unlawful without a permit. If there is the potential to adversely affect migratory birds as a result of our operations or construction activities, we may be required to obtain necessary permits to conduct those operations or construction activities, which may result in specified operating or construction restrictions on a temporary, seasonal, or permanent basis in affected areas and thus have an adverse impact on our ability to provide timely gathering, processing or fractionation services to our exploration and production customers.

Pipeline Safety Matters

        Our pipelines are subject to regulation by the Pipeline and Hazardous Materials Safety Administration ("PHMSA") of the 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 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

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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 regulations 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 certain pipelines and increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. 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 of which could have a material adverse effect on our results of operations or financial position.

        Our pipelines are also subject to regulation by PHMSA under the Pipeline Safety Improvement Act of 2002, which was amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006. PHMSA has established a series of regulations 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 regulations are also in place under 49 C.F.R. Part 195 for operators of hazardous liquid pipelines including lines transporting NGLs and condensates. PHMSA also has adopted regulations 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 sought public comment on a number of changes to regulations governing the safety of gas transmission pipelines and gathering lines, including, for example, revising the definitions of "high consequence areas" and "gathering lines" and strengthening integrity management requirements as they apply to existing regulated operators and to currently exempt operators should certain exemptions be removed. Most recently, in an August 2014 report to Congress from the U.S. Government Accountability Office ("GAO"), the GAO acknowledged PHMSA's August 2011 proposed rulemaking as well as PHMSA's continued assessment of the safety risks posed by gathering lines. In its report, the GAO recommended that PHMSA move forward with rulemaking to address larger-diameter, higher-pressure gathering lines, including subjecting such pipelines to emergency response planning requirements that currently do not apply.

        States are largely preempted by federal law from regulating pipeline safety for interstate lines but most are certified by the DOT to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, however, because states in some circumstances can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate lines, states vary considerably in their authority and capacity to address pipeline safety. We believe that our operations are in substantial compliance with applicable state pipeline safety laws and regulations. However, new state pipeline safety requirements may be implemented in the future that could materially increase our operating costs.

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Facility Safety

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

        At unmanned facilities, the EPA's Risk Management Planning requirements at regulated facilities are intended to protect the safety of the surrounding public. The application of these regulations, which are often unclear, can result in increased compliance expenditures.

        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.

        Notwithstanding the foregoing, PHMSA and one or more state regulators, including the Texas Railroad Commission, have recently expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities, to assess compliance with hazardous liquids pipeline safety requirements. These recent actions by PHMSA are currently subject to judicial and administrative challenges by one or more midstream operators; however, to the extent that such challenges are unsuccessful, midstream operators of NGL fractionation facilities and associated storage facilities may be required to make operational changes or modifications at their facilities to meet standards beyond current requirements. These changes or modifications may result in additional capital costs, possible operational delays and increased costs of operation.

Employees

        Through our subsidiary MarkWest Hydrocarbon, we employ approximately 1,404 individuals to operate our facilities and provide general and administrative services as of February 18, 2015. 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.

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ITEM 1A.    Risk Factors

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

Risks Inherent in Our Business

Our substantial debt and other financial obligations could impair our financial condition, results of operations and cash 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;

    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 our assets and guaranteed by all of our wholly-owned subsidiaries other than MarkWest Liberty Midstream and its subsidiaries (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 our Credit Facility, make distributions on equity investments and declare or make, directly or indirectly, any distribution on our common units. Maintaining compliance with such covenants may be exacerbated from time to time to the extent that the fluctuations in our working capital needs are not consistent with the timing for our receipt of funds from our operations. 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, or our indentures, which could result in acceleration of our debt and other financial obligations. If we were unable to repay those amounts, the lenders could initiate a bankruptcy or liquidation proceeding or proceed against the collateral.

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Global economic conditions may have adverse impacts on our business and financial condition and adversely impact our ability to access capital markets on acceptable terms.

        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, government spending sequestration, strength of U.S. currency versus other international currencies, consumer confidence and debt levels, retail trends, 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, any 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 raise capital and, therefore, have an adverse impact on 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 our common units.

        The severe decline in oil prices that occurred late in 2014, which has continued into 2015, has increased the volatility and amplitude of the other risks facing us as described in this report and has impacted our unit price and may have an impact on our business and financial condition. A continued decline in our unit price may adversely affect our ability to access the capital markets on acceptable terms, which could adversely impact our ability to execute our long-term organic growth projects and satisfy our obligations to our producer customers. The decline in oil prices may also negatively impact our producer customers' drilling programs, which over time would reduce the supply of natural gas and NGLs delivered to us and reduce our revenues and cash flows available for distribution. These adverse impacts could also result in noncash impairments of long-lived assets and goodwill, other-than-temporary noncash impairments of our equity method investments, and have an adverse impact on cash flows from operations.

Sustained declines in oil, natural gas and NGL prices may result in curtailments of our producer customers' drilling programs, which may delay the production of volumes of oil, natural gas and NGLs to be delivered to our facilities and may adversely affect our revenues, financial condition, and cash available for distribution.

        During 2012 through 2014, there were significant fluctuations in natural gas prices, and in late 2014, oil and NGL prices also declined substantially. This has led some producers to significantly reduce their drilling plans for oil and dry gas, and sustained periods of low prices could result in producers also significantly curtailing or limiting their liquids-rich gas drilling operations. Curtailments or reductions in drilling operations could substantially delay the production and delivery of volumes of oil, gas and NGLs to our facilities and adversely affect our revenues and cash available for distribution. This impact may also be exacerbated to the extent of our commodity based contracts, which are more directly impacted by changes in gas and NGL prices than our fee-based contracts due to frac spread exposure. If these impacts continued to occur, our unit price may be adversely affected, which could adversely affect our ability to fund our organic growth projects and satisfy our contractual obligations, or may result in non-cash impairments of long-lived assets or goodwill or other-than-temporary noncash impairments of our equity method investments, or adversely affect our cash flows from operations.

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 common 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;

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

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

    the level of our operating costs including repairs and maintenance;

    prevailing economic conditions; and

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

        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 and timing 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.

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

        Our operations are dependent upon production from natural gas reserves and wells, which 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 and processing facilities.

        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, operational challenges, access to downstream markets, 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 2012 through 2014, there were significant fluctuations in natural gas prices, leading some producers to announce significant reductions to their drilling plans specifically in dry gas areas. In late 2014, oil and NGL prices also declined substantially. If sustained over the long-term, low gas, oil and NGL prices could lead to a material reduction in volumes in certain areas of our operations.

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        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 may not always be able to accurately estimate hydrocarbon reserves and expected production volumes; therefore, volumes we service in the future could be less than we anticipate.

        We work closely with our producer customers in an effort to understand hydrocarbon reserves and expected production volumes, and we periodically review or have outside consultants review hydrocarbon reserve information and expected production data that is publicly available or that is provided to us by our producer customers. However, we may not always be able to accurately estimate hydrocarbon reserves and production volumes expected to be delivered to us for a variety of reasons, including as a result of the unavailability of sufficiently detailed information and unanticipated changes in producers' expected drilling schedules. Significant declines in oil, natural gas or NGL prices could also cause producers to curtail or limit drilling operations, which may result in the volumes delivered to us being less than anticipated. Accordingly, we may not have accurate estimates of total reserves serviced by our assets, the anticipated life of such reserves, or the expected volumes to be produced from those reserves. If the total reserves, estimated life of the reserves or anticipated volume to be produced from the reserves is less than we anticipate and we are unable to secure additional sources, then the volumes that we gather or process in the future could be less than anticipated. A decline in the volumes could have a material adverse effect on our results of operations and financial condition.

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 or may be delivered prior to completion of such 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. Construction involves many factors beyond our control including delays caused by third-party landowners, unavailability of materials, labor disruptions, environmental hazards, financing, accidents, weather and other factors. Additionally, we are subject to numerous regulatory, environmental, political, legal and inflationary uncertainties, as well as stringent, lengthy and occasionally unreasonable or impractical federal, state and local permitting, zoning, 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 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

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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.

        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. In order to attract additional natural gas or NGL supplies from a producer, we may be required to order equipment and facilities, obtain rights of way or other land rights, or otherwise commence construction activities for facilities that will be required to serve such producer's additional supplies prior to executing agreements with the producer. If such agreements are not executed, we may be unable to recover such costs and expenses. 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. Alternatively, natural gas or NGL supplies committed to facilities under construction may be delivered prior to completion of such facilities. In such event, we may be required to temporarily utilize third-party facilities for such natural gas or NGLs, which may increase our operating costs and reduce our cash available for distribution.

Due to capacity, market and other constraints relating to the growth of our business, we may experience difficulties in the execution of our business plan, which may increase our costs and reduce our revenues and our cash available for distribution.

        The successful execution of our business strategy is impacted by a variety of factors, including our ability to grow our business and satisfy our producer customers' requirements for gathering, processing, fractionation and marketing services. Our ability to grow our business and satisfy our customers' requirements may be adversely affected by a variety of factors, including the following:

    more stringent permitting and other regulatory requirements;

    a limited supply of qualified fabrication and construction contractors, which could delay or increase the cost of the construction and installation of our facilities or increase the cost of operating our existing facilities;

    unexpected increases in the volume of natural gas and NGLs being delivered to our facilities, which could adversely affect our ability to expand our facilities in a manner that is consistent with our customers' production schedules;

    unexpected outages or downtime at our facilities or at upstream or downstream third-party facilities, which could reduce the volumes of gas and NGLs that we receive; and

    market and capacity constraints affecting downstream natural gas and NGL facilities, including limited gas and NGL capacity downstream of our facilities, limited railcar and NGL pipeline facilities and reduced demand or limited markets for certain NGL products, which could reduce the volumes of gas and NGLs that we receive and adversely affect the pricing received for NGLs.

        If we are unable to successfully execute our business strategy, then our operating and capital expenditures may materially increase and our revenues and our cash available for distribution to our common unitholders may be adversely affected.

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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 2013 ranged from a high of $4.46 per MMBtu to a low of $3.11 per MMBtu. In 2014, the same index ranged from a high of $6.15 per MMBtu to a low of $2.89 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 2013 ranged from a high of approximately $1.43 per gallon to a low of approximately $1.02 per gallon. In 2014, the same composite ranged from a high of approximately $1.72 per gallon to a low of approximately $0.58 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 oil, natural gas and NGL production domestically and, in some cases, globally;

    demand for natural gas and NGL products in localized markets;

    changes in interstate pipeline gas quality specifications;

    imports and exports of crude oil, natural gas and NGLs;

    seasonality and weather conditions;

    the condition of the U.S. and global economies;

    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.

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 a 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.

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Our net operating loss carryforwards may be limited or they may expire before utilization.

        As of December 31, 2014, the Corporation had U.S. federal tax net operating loss carryforwards ("NOLs") of approximately $47.8 million, which expire in twenty years. These net operating loss carryforwards may be used to offset future taxable income and thereby reduce its U.S. federal income taxes otherwise payable. If the Corporation does not generate enough taxable income prior to the expiration of our NOLs, it may not be able to meet the "more likely than not" standard in accordance with GAAP that the Corporation can utilize our NOLs in the future which, among other factors and circumstances, could require us to recognize a valuation allowance. Although the recognition of a valuation allowance is a non-cash charge to earnings and does not preclude the Corporation from using the NOLs to reduce future taxable income otherwise payable, the recognition of a valuation allowance would reduce earnings and would also result in a corresponding reduction of equity.

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 our contract mix and 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 that are subject to commodity price volatility and, as a result, we expect to continue to have some direct commodity price exposure. 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. Alternatively, we may seek to amend the terms of our derivative financial instruments, including the extension of the settlement date of such instruments. Additionally, because we may use derivative financial instruments relating to the future price of crude oil to mitigate our exposure to NGL price risk, the volatility of 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 risk management 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 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. 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 7 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, our risk management activities may expose us to financial risks and may 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.

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        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.

Due to an increased domestic supply of NGLs, we may be required to find alternative NGL market outlets and to rely more heavily on the export of NGLs to foreign countries, which may increase our operating costs or reduce the price received for NGLs and thereby reduce our cash available for distribution.

        Due to the increased production of natural gas in the United States, particularly in shale plays, there is an increased supply of NGLs, which is currently outpacing and could continue to outpace, demand for NGLs domestically. As a result, we and our producer customers may need to continue to find alternate NGL market outlets and to rely more heavily on the export of NGLs to foreign countries. Our ability to find alternative NGL market outlets is dependent upon a variety of factors, including the construction and installation of additional NGL transportation infrastructure necessary to transport NGLs to other markets. In order to obtain committed transportation capacity, it may be necessary to make significant minimum volume commitments, with take or pay payments or deficiency fees if the minimum volume is not delivered. In many cases, we market NGLs on behalf of our producer customers, and as a result, we may make such commitments on behalf of our producer customers. We expect to be able to pass such commitments through to our producer customers, but if we were unable to do so, our operating costs may increase significantly, which could have a material adverse effect on our results of operations and our ability to make cash distributions. Similarly, our ability to export NGLs to foreign countries on a competitive basis is impacted by various factors, including:

    availability of sufficient terminalling facilities in the United States;

    availability of sufficient rail car and tanker capacity;

    currency fluctuations, particularly to the extent sales are denominated in foreign currencies as we do not currently hedge against currency fluctuations;

    compliance with additional governmental regulations and maritime requirements, including U.S. export controls and foreign laws, sanctions regulations and the Foreign Corrupt Practices Act;

    risks of loss resulting from nonpayment or nonperformance by international purchasers; and

    political and economic disturbances in the countries to which NGLs are being exported.

        The above factors could increase our operating costs or adversely affect the price that we and our producer customers receive for NGLs, which in turn may have a material adverse effect on our volumes, revenues, income and cash available for distribution to our common unitholders.

We depend on third parties for the natural gas and refinery off-gas we process, and the NGLs we fractionate and stabilize 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 and fractionation 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, refinery off-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, refinery off-gas or NGLs to our systems and facilities for any reason, we could experience difficulty in replacing those lost volumes. In some cases, the producers are responsible for gathering natural gas, refinery off-gas or NGLs to our

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facilities or we rely on other third parties to deliver the natural gas, refinery off-gas or NGLs to us on behalf of the producers. If such producers or other third parties are unable, or otherwise fail to, deliver the natural gas, refinery off-gas or NGLs to our facilities, or if our agreements with any of these third parties terminate or expire such that our facilities are no longer connected to their gathering or transportation systems or the third parties modify the flow of natural gas, refinery off-gas or NGLs on those systems away from our facilities, the volumes of natural gas, refinery off-gas and NGLs that we process and fractionate may be reduced, or we may be required to construct and install gathering pipelines or other facilities to be able to receive such natural gas, refinery off-gas or NGLs which may require us to incur significant capital expenditures. Because our operating costs are primarily fixed, a reduction in the volumes of natural gas, refinery off-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.

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

        A significant portion of our natural gas supply comes from a limited number of key producers/suppliers. 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. Our competitors may also include our joint venture partners, who in some cases are permitted to compete with us, and those joint venture partners who exercise this right may have a competitive advantage due to their familiarity with our business arising from our joint venture arrangements, or third parties on whom we rely to deliver natural gas, NGLs and crude oil to our facilities, who may have a competitive advantage due to their ability to modify the flow of natural gas, NGLs and crude oil on their systems away from our facilities. 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 Form 10-K.

The fees charged to third parties under our gathering, processing, transmission, transportation, fractionation, stabilization 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,

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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 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. We may also determine to expand our business through expanding our service offerings. For example, in 2015 we will begin providing condensate stabilization services through Ohio Condensate, and the condensate stabilization business is subject to unique operational and business complexities. If we are unable to successfully grow our business, or to successfully execute on our business plan including increasing or maintaining distributions, the market price of the common units is likely to decline.

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

        Congress has adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, such as us, that participate in that market. The 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 legislation. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.

        The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and exchange trading. To the extent we engage in such transactions that are or become subject to such rules in the future, we will be required to comply or to take steps to qualify for an exemption to such requirements. Although we believe that we qualify for the end-user exception to the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. Additional mandatory clearing requirements that may be proposed by the CFTC in the future under the Dodd-Frank Act could also affect our ability to maintain over-the-counter hedging positions, and we may be exposed to clearing and collateral requirements if we are not able to qualify for exceptions to those requirements.

        Certain other regulations proposed under the Dodd-Frank Act have not yet been finalized. The CFTC has proposed regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions would be exempt from these position limits. The proposed position limits may increase our costs for trading and compliance and limit the positions we can maintain at certain times, but as these proposed position limit rules are not yet final, the effect of those provisions on us is uncertain at this time. In addition, certain banking regulators and the CFTC have proposed rules to establish minimum margin requirements. Posting of collateral could affect liquidity and reduce cash available to us for

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capital expenditures, therefore reducing our ability to execute derivatives to reduce risk and protect cash flows. Although such margin rules, as proposed, do not require the collection of margin from non-financial end users, the timing and final content of these rules, and their effect on us, remain uncertain at this time.

        The Dodd-Frank Act and its implementing regulations could significantly increase the cost of derivative contracts, 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, increase the administrative burden and regulatory risk associated with entering into certain derivative contracts, and increase our exposure to less creditworthy counterparties. If we reduce our use of derivatives as a result of the Dodd-Frank Act and its implementing 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. In addition, if the Dodd-Frank Act and any new regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could have a material adverse effect on our income from operations, cash flows and quarterly distribution to common unitholders.

        In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent we transact with counterparties in foreign jurisdictions, we may become subject to such regulations, the impact of which is not clear at this time.

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. Joint venture arrangements may not permit us to distribute cash attributable to joint venture operations when we would otherwise desire to do so. We also may not be able to expand the joint venture operations when we believe it would be beneficial to do so. 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, certain joint venture partners have the option not to make any capital investments or to cease making capital investments after a certain time period. See Note 3 to the accompanying Notes to the Financial Statements included in Item 8 of this Form 10-K. If our joint venture partners elect not to contribute as much as we anticipate or if our joint venture partners are unable to meet their economic or other obligations, we may be required to fulfill those obligations alone. In addition, in some cases, our joint venture partners may be permitted to compete with us, including in areas in which our joint ventures operate, which may limit or reduce the benefits that we would otherwise receive from joint venture arrangements. 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 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 customers or our derivative counterparties could reduce our ability to make distributions to our unitholders.

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 natural gas, NGL and crude oil pipelines are, or may in the future be, subject to siting, public necessity, rate and service regulations by FERC and/or various state or other regulatory bodies, depending upon jurisdiction. FERC generally regulates the transportation of natural gas, NGLs and crude oil in interstate commerce and FERC's regulatory authority includes: facilities construction, acquisition, extension or abandonment of services or facilities (for natural gas pipelines only); rates; operations; 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 own NGL product pipelines and a common carrier crude oil pipeline to transport crude oil in interstate commerce. For two of these pipelines, we have a FERC tariff on file and we may have additional common carrier pipelines in the future that may be subject to these requirements. We also own and are constructing pipelines that are carrying or are expected to carry NGLs owned by us across state lines that are not subject to FERC's requirements for common carrier NGL pipelines or would otherwise meet the qualifications for a waiver from many of FERC's reporting and filing requirements. However, we cannot provide assurance that FERC will not at some point find that some or all of these pipelines are subject to FERC's requirements for common carrier pipelines or are otherwise not exempt from its reporting and filing requirements. Such a finding could subject us to potentially burdensome and expensive operational, reporting and other requirements as well as fines, penalties or other sanctions.

        Most of our natural gas and liquids pipelines are generally not subject to regulation by FERC. The NGA specifically exempts natural gas gathering systems from FERC's jurisdiction. 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 and that we offer service to our shippers on a not unduly discriminatory basis. We cannot assure unitholders that FERC will not at some point determine that some or all of such pipelines are within its jurisdiction, and regulate such services, which could limit the rates that we may charge, increase our costs of operation, and subject us to fines, penalties or other sanctions. 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 Annual Report on Form 10-K.

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Some of our natural gas, NGL and crude oil 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 and natural gas 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 NGL 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, including the renewal of leases for land on which our processing facilities are located. 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. If we are unable to renew a lease for land on which any of our processing facilities are located, we may be required to remove our facilities from that site, which could require us to incur significant costs and expenses, disrupt our operations, and adversely affect our cash available for distribution to our common unitholders.

Increases in interest rates could increase our costs and reduce our cash available for distribution.

        Although interest rates have been low during the past several years, it is possible that interest rates may increase in the future, and the United Stated Federal Reserve has indicated that it may consider raising interest rates in 2015. The interest rate charged under our Credit Facility is subject to fluctuation if interest rates increase. In addition, from time to time, we may seek to refinance existing long-term debt or to incur additional long-term debt, and increases in interest rates could cause the interest rate on any such refinanced or additional debt to increase. In such event, our costs may increase, which could reduce our cash available for distribution to our common 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 an indemnifying party fails to perform its indemnification obligations.

        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 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.

        From time to time, we have acquired, and may acquire in the future, facilities from third parties which previously have been or currently are the subject of investigatory, remedial or monitoring activities relating to environmental matters. The terms of each acquisition will vary, and in some cases we may receive indemnification from the prior owner or operator for some or all of the liabilities relating to such matters, and in other cases we may agree to accept some or all of such liabilities. There is no assurance that any such third parties will perform such indemnification obligations, or that the obligations and liabilities that we may accept in connection with any such acquisition will not be larger than anticipated, and in such event, our results of operations and cash available for distribution to our unitholders could be adversely affected.

Our business is subject to laws and regulations with respect to environmental, occupational safety and health, 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 federal, regional, state and local laws and regulations on a wide range of environmental, occupational safety and health, 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 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.

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New, more stringent environmental laws, regulations and enforcement policies, and new, amended or re-interpreted permitting requirements, policies and processes, might adversely affect our operations 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, it is possible that future amendment or re-interpretation of existing air emission laws could impose more stringent permitting or pollution control equipment requirements on us if two or more of our facilities are aggregated into one air emissions permit or permit application, which could increase our costs. Federal, state and local agencies also could impose additional safety requirements, any of which could increase our operating costs. Local governments may adopt more stringent local permitting and zoning ordinances that impose additional time, place and manner restrictions, delays or constraints on our activities to construct and operate our facilities, require the relocation of our facilities, prevent or restrict the expansion of our facilities, or increase our costs to construct and operate our facilities, including the construction of sound mitigation devices.

        In addition, we face the risk of accidental releases or spills associated with our operations, which 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 or alleged non-compliance 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 Annual Report on Form 10-K.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs, reduced demand for our services, 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 adopted regulations establishing PSD construction and Title V operating permit requirements for GHG emissions from certain large stationary sources that already are potential major sources of certain principal, or criteria, pollutant emissions. In addition, the EPA continues to examine whether or not methane emissions should be specifically limited from oil and gas activities, and the EPA is gathering information on existing facilities in various industries, which may be used to support potential future regulation of carbon emissions. Although EPA's PSD and Title V permit programs are limited to large stationary sources that already are potential major sources of criteria pollutant emissions, states may seek to adopt their own permitting programs under state laws that require permit reviews of large stationary sources emitting only GHGs. If we were to become subject to Title V and PSD permitting requirements due to non-GHG criteria pollutants, or if EPA implemented more stringent permitting requirements relating to GHG emissions without regard to non-GHG criteria pollutants, or if states adopt their own permitting programs that require permit reviews based on GHG emissions, we may be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities that we may seek to construct in the future . In addition, we may experience substantial delays or possible curtailment of construction or projects in connection with applying for, obtaining or maintaining preconstruction and operating permits, we may encounter limitations on the design capacities or size of facilities, and our construction and operating costs may materially increase.

        The EPA has also adopted rules regulating the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas sources in the United States including, among others, certain onshore and offshore oil and natural gas production and onshore oil and natural gas processing,

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fractionation, transmission, storage and distribution facilities. On December 9, 2014, the EPA published a proposed rule that would expand the petroleum and natural gas system sources for which annual GHG emissions reporting is currently required to include GHG emissions reporting beginning in the 2016 reporting year for certain onshore gathering and boosting systems consisting primarily of gathering pipelines, compressors and process equipment used to perform natural gas compression, dehydration and acid gas removal. In addition, Congress has from time to time considered legislation to reduce emissions of GHGs, but, in the absence of federal climate legislation in the United States in recent years, a number of state and regional efforts have emerged that are aimed at tracking and/or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. If Congress were to undertake comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for oil, natural gas, NGLs and products derived therefrom.

        These requirements or the adoption of any new legislation or regulations that requires additional reporting, monitoring or recordkeeping of GHGs, limits emissions of GHGs from our equipment and operations, or imposes a carbon tax, 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 example, pursuant to President Obama's Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015 that EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities as part of the Administration's efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. We may experience delays in the construction and installation of new facilities due to more stringent permitting requirements, incur additional costs to reduce emissions of GHGs associated with our operations or be required to aggregate the emissions from separate facilities for permitting purposes or to relocate one or more of our facilities due to more stringent emissions standards. To the extent that we incur additional costs or delays, our cash available for distribution may be adversely affected. Our producer customers may also experience similar issues, which may adversely impact their drilling schedules and production volumes and reduce the volumes of natural gas that we receive for gathering and processing. For more information regarding greenhouse gas emission and regulation, please read Item 1. Business—Environmental Matters—Climate Change.

        Finally, for a variety of reasons, natural and/or anthropogenic, some members of the scientific community believe that 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, state and local legislation and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could delay or impede producer customers' gas production or result in reduced volumes available for us to gather, process and fractionate.

        We do not conduct hydraulic fracturing operations, but we do provide gathering, processing and fractionation services with respect to natural gas and NGLs produced by our producer customers as a result of such operations. 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 targeted subsurface formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions but several federal agencies have asserted regulatory authority over

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certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the BLM issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015. In addition, Congress has from time to time considered legislation to provide for additional regulation of hydraulic fracturing. 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. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new federal, state or local 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. Also, certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices. Most notably, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, with a draft report drawing conclusions about the potential impacts of hydraulic fracturing on drinking water resources expected to be available for public comment and peer review in the first half of 2015. Moreover, the White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. These studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing and reduce demand for our gathering, processing and fractionating services.

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, limits on or changes in or inability to meet 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 or other outlets 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 and our natural gas processing services and our revenues and net operating margin would be reduced. 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 upstream or downstream pipelines or to ours or other's facilities. 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.

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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 gathering, 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 and, even if we are able to obtain such insurance, we may not be able to recover amounts from the insurance carrier for events that we believe are covered. 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.

We may incur significant costs and liabilities resulting from performance of pipeline integrity programs and related repairs.

        Pursuant to the Pipeline Safety Improvement Act of 2002, as reauthorized and amended by the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011, the DOT through the PHMSA has adopted regulations requiring pipeline operators to develop integrity management programs for gas transmission and hazardous liquids pipelines located where a leak or rupture could do the most harm. The regulations require the following of operators of covered pipelines to:

    perform ongoing assessments of pipeline integrity;

    identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

    improve data collection, integration and analysis;

    repair and remediate the pipeline as necessary; and

    implement preventive and mitigating actions.

        In addition, states have adopted regulations similar to existing PHMSA regulations for intrastate gathering and transmission lines. We cannot predict the ultimate cost of compliance with this regulation, as the cost will vary significantly depending on the number and extent of any repairs found to be necessary as a result of the pipeline integrity testing. The results of these tests could cause us to incur significant and unanticipated capital and operating expenditures or repairs or upgrades deemed necessary to ensure the continued safe and reliable operations of our gathering and transmission lines.

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Pipeline safety laws and regulations expanding integrity management programs or requiring the use of certain safety technologies, or expanding to in-plant equipment and pipelines within NGL fractionation and storage facilities, could require us to use more comprehensive and stringent safety controls and subject us to increased capital and operating costs.

        On January 3, 2012, President Obama signed the 2011 Pipeline Safety Act, which, among other things, increases the maximum civil penalty for pipeline safety violations and directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation and testing to confirm the material strength of certain pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of the pipeline safety regulations from $100,000 to $200,000 per violation per day of violation and also from $1 million to $2 million for a related series of violations. In addition, the PHMSA published a final rule in May 2011 expanding pipeline safety requirements including added reporting obligations and integrity management standards to certain rural low-stress hazardous liquid pipelines that were not previously regulated in such manner. Also, in August 2011, the 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, gathering lines and related facilities. Most recently, in an August 2014 GAO report to Congress, the GAO acknowledged PHMSA's August 2011 proposed rulemaking as well as PHMSA's continued assessment of the safety risks posed by gathering lines, and recommended that PHMSA move forward with rulemaking to address larger-diameter, higher-pressure gathering lines, including subjecting such pipelines to emergency response planning requirements that currently do not apply. In addition, PHMSA and other state regulators have recently expanded the scope of their regulatory inspections to include certain in-plant equipment and pipelines found within NGL fractionation facilities and associated storage facilities to assess compliance with hazardous liquids pipeline safety requirements. These recent actions by PHMSA are currently subject to judicial and administrative challenges by one or more midstream operators. The adoption of these and other laws or regulations that apply more comprehensive or stringent safety standards to gas or NGL lines, or the expansion of regulatory inspections by PHMSA and other state regulators described above, could require us to install new or modified safety controls, pursue added capital projects, make modifications or operational changes, or conduct maintenance programs on an accelerated basis, all of which could require us to incur increased capital and operational costs or operational delays that could be significant and have a material adverse effect on its financial position or results of operations and ability to make distributions 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, gathering facilities, various means of transportation and marketing services. Any significant interruption at these facilities or pipelines, or in our ability to transmit natural gas or NGLs, or to transport crude oil to or from these facilities or pipelines for any reason, or to market or transport the natural gas or NGLs, 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;

    restrictions imposed by governmental authorities or court proceedings;

    labor difficulties that result in a work stoppage or slowdown;

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    a disruption in the supply of crude oil to our crude oil pipeline, natural gas to our processing plants or gathering pipelines, or NGLs to our NGL pipelines and fractionation facilities;

    disruption in our supply of power, water and other resources necessary to operate our facilities;

    damage to our facilities resulting from gas or NGLs that do not comply with applicable specifications; and

    inadequate fractionation, transportation or storage capacity or market access to support production volumes, including lack of availability of rail cars, trucks and pipeline capacity.

        Our NGL fractionation, storage and marketing operations in the Marcellus and Utica segments are integrated, and as a result, it is possible that an interruption of these operations in either segment may impact operations in the other segment, which may exacerbate the impacts of such interruption.

        In addition, the construction and operation of certain of our facilities in our Marcellus, Utica and Northeast segments may be impacted by surface or subsurface mining operations. One or more third parties may have previously engaged in, may currently be 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 or adversely impact our construction activities. 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, fractionation, stabilization, marketing 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, fractionation, stabilization, marketing 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.

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, although the effectiveness of those plans may be adversely affected by sustained declines in our common unit price. 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 qualified labor may make it difficult for us to maintain labor productivity and continue to grow our business, and competitive costs could adversely affect our operations and cash flows available for distribution to our unitholders.

        The ability to hire, train and retain skilled and experienced personnel is required to manage and operate our growing business. In recent years, there has been a shortage of personnel trained in various skills associated with the operations and management of the midstream energy business. 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

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experienced labor continues or worsens, it could have an adverse impact on our labor productivity and costs and our ability to expand production in the event there is an increase in the demand for our products and services, which could adversely affect our operations and cash flows available for distribution to our unitholders.

If we are unable to make strategic acquisitions on economically acceptable terms, our ability to implement our business strategy may be impaired.

        In addition to organic growth, a component of our business strategy can include the expansion of our operations through strategic acquisitions. If we are unable to make accretive strategic acquisitions that increase the cash generated from operations per unit, whether due to an inability to identify attractive acquisition candidates, to negotiate acceptable purchase contracts, or to obtain financing for these acquisitions on economically acceptable terms, then our ability to successfully implement our business strategy may be impaired.

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.

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We have partial ownership interests in a number of joint venture legal entities, including MarkWest Pioneer, MarkWest Utica EMG and its subsidiary, MarkWest Utica EMG Condensate and its subsidiary, MarkWest POET, L.L.C., Wirth Gathering 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 ownership interest, such as Centrahoma and MarkWest POET, L.L.C., or for entities that we operate but in which the non-controlling interest owners have participative rights, we will be unable to control ongoing operational decisions, including the incurrence of capital expenditures that we may be required to fund or the pursuit of certain projects that we may want to pursue. 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, timing and amount of distributions to us, and facility expansions;

    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.

Our operations depend on the use of information technology ("IT") systems that could be the target of industrial espionage or cyber-attack.

        Our business has become increasingly dependent upon digital technologies, including information systems, infrastructure and cloud applications for the gathering and processing of natural gas, the gathering, fractionation, transportation and marketing of NGLs, and the gathering and transportation of crude oil. The U.S. government has issued public warnings that indicate that energy assets might be specific targets of cyber security threats. Our systems and networks, as well as those of our customers, vendors and counterparties, may become the target of cyber-attacks or information security breaches, which in turn could result in the unauthorized release and misuse of confidential or proprietary information as well as disrupt our operations or damage our facilities or those of third parties, which could have a material adverse effect on our revenues and increase our operating and capital costs, which could reduce the amount of cash otherwise available for distribution. Additionally, as cyber incidents continue to evolve we may be required to incur additional costs to modify or enhance our systems or in order to try to prevent or remediate any such attacks.

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

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issued by recognized accounting standard setters or regulators, including the FASB and the SEC. It is possible that future requirements, including the proposed adoption and 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.

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. Our 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 the Board.

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 our amended and restated 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.

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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 for state purposes, 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. Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for federal income tax purposes unless we satisfy a "qualifying income" requirement. Based on our current operations, we believe we satisfy the qualifying income requirement. Failing to meet the qualifying income requirement 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.

        Our amended and restated 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 a material amount of 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. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. For example, the state of Texas has instituted an income-based tax that results in an entity level tax for us, and 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. Imposition of a similar tax on us in other jurisdictions in which we operate or in jurisdictions to which we may expand could substantially reduce our cash available for distribution to you.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

        The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration's budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, any such proposal could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

        Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

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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.

        The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and the General Partner because the costs will reduce our cash available for distribution.

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

        Each unitholder will be required to pay federal income taxes and, in some cases, state and local income taxes on his or her share of our taxable income whether or not the unitholder receives 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 which 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 or her common units, they 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 results in a decrease in the unitholder's tax basis in his or her 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 or her tax basis in those common units, even if the price the unitholder receives is less than the 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 ("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

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them. Allocations and/or distributions to non-U.S. persons will be reduced by withholding taxes at the highest effective tax rate applicable to non-U.S. persons, 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.

        Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations in order to maintain the uniformity of the economic and tax characteristics of our common units. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from a unitholder's sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to a unitholder's tax returns.

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

        We generally 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. The U.S. Treasury Department has 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 successfully 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 the subject of a "securities loan" (e.g., a loan 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 there are no specific rules governing the federal income tax consequence of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, 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, 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 securities loan are urged to modify any applicable brokerage account agreements to prohibit their brokers from lending their common units.

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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 ("IRC") Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of income, gain, loss and deduction between our unitholders.

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

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

        We will be considered to have terminated as a partnership, 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. Currently, our termination 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 ten 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 the responsibility of our unitholders 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, 2014. All capacities and throughputs included are weighted-averages for days in operation.

Gas Processing Facilities:

 
   
   
   
  Year ended
December 31, 2014
 
Facility
  Location   Year of Initial
Construction
  Design
Throughput
Capacity
  Natural Gas
Throughput(1)
  Utilization
of Design
Capacity(1)
  NGL
Throughput
 
 
   
   
  (Mcf/d)
  (Mcf/d)
   
  (Gal/d)
 

Marcellus

                                   

Marcellus Shale:

                                   

Houston Complex

  Washington County, PA     2009     355,000     279,600     79 %   696,400  

Majorsville Complex

  Marshall County, WV     2010     870,000     634,700     80 %   1,445,300  

Mobley Complex

  Wetzel County, WV     2012     720,000     444,400     84 %   665,200  

Sherwood Complex

  Doddridge County, WV     2012     1,000,000     587,200     83 %   756,200  

Keystone Complex(2)

  Butler County, PA     2010     210,000     118,000     72 %   209,200  

Total Marcellus

              3,155,000     2,063,900     81 %   3,772,300  

Utica

 

 

   
 
   
 
   
 
   
 
   
 
 

Utica Shale:

                                   

Cadiz Complex

  Harrison County, OH     2012     325,000     129,100     82 %   254,900  

Seneca Complex

  Noble County, OH     2013     600,000     286,400     61 %   493,800  

Total Utica

              925,000     415,500     67 %   748,700  

Northeast

 

 

   
 
   
 
   
 
   
 
   
 
 

Appalachia:

                                   

Kenova Complex(3)

  Wayne County, WV     1996     160,000     104,000     65 %   195,200  

Boldman Complex(3)

  Pike County, KY     1991     70,000     29,300     42 %   39,500  

Cobb Complex

  Kanawha County, WV     2005     65,000     28,000     43 %   64,800  

Kermit Complex(3)(4)

  Mingo County, WV     2001     32,000     N/A     N/A     N/A  

Langley Complex

  Langley, KY     2000     325,000     118,500     36 %   328,000  

Total Northeast(4)

              620,000     279,800     45 %   627,500  

Southwest

 

 

   
 
   
 
   
 
   
 
   
 
 

East Texas:

                                   

Carthage Complex(5)

  Panola County, TX     2005     520,000     395,000     97 %   1,181,900  

Oklahoma:

                                   

Western Oklahoma Complex

  Custer and Beckham Counties, OK     2000     435,000     284,600     69 %   600,900  

Gulf Coast:

                                   

Javelina Complex

  Corpus Christi, TX     1989     142,000     114,100     80 %   872,600  

Total Southwest(6)

              1,097,000     793,700     83 %   2,655,400  

Total Gas Processing

              5,797,000     3,552,900     75 %   7,803,900  

(1)
Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

(2)
The NGL throughput excludes NGL volumes received from a third party processing facility.

(3)
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.

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(4)
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. As such, the design capacity has been excluded from the subtotal.

(5)
Excludes certain amounts in 2014 in excess of East Texas' operating capacity that were processed by third-parties.

(6)
Centrahoma processing capacity of 260 MMcf/d is not included in this table as we own a non-operating interest.

Fractionation Facilities:

 
   
   
   
  Year ended
December 31, 2014
 
Facility
  Location   Year of Initial
Construction
  Design
Throughput
Capacity
  NGL
Throughput(1)
  Utilization
of Design
Capacity(1)
 
 
   
   
  (Bbl/d)
  (Bbl/d)
   
 

Marcellus

                             

Marcellus Shale:

                             

Houston propane and heavier fractionation facility(2)

  Washington County, PA     2009     60,000     55,600     93 %

Houston de-ethanization facility

  Washington County, PA     2013     40,000     17,100     43 %

Majorsville de-ethanization facility

  Marshall County, WV     2013     40,000     31,700     79 %

Keystone propane and heavier fractionation facility(2)

  Butler County, PA     2010     12,000     3,900     56 %

Keystone de-ethanization facility

  Butler County, PA     2014     14,000     5,600     69 %

Total Marcellus

              166,000     113,900     73 %

Hopedale propane and heavier fractionation facility(2)(3)

 

Harrison County, OH

   
2014
   
120,000
   
48,600
   
84

%

Northeast

 

 

   
 
   
 
   
 
   
 
 

Appalachia:

                             

Siloam propane and heavier fractionation facility(4)

  South Shore, KY     1957     24,000     19,500     81 %

Total Northeast

              24,000     19,500     81 %

Southwest

 

 

   
 
   
 
   
 
   
 
 

Gulf Coast:

                             

Javelina propane and heavier fractionation facility

  Corpus Christi, TX     1989     29,000     20,800     72 %

Total Southwest

              29,000     20,800     72 %

Total Fractionation

              339,000     202,800     76 %

(1)
NGL throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

(2)
Our Houston, Hopedale and Keystone Complexes have above ground NGL storage with a usable capacity of twenty million gallons, large-scale truck and rail loading. In addition, our Houston Complex has large-scale truck unloading. We also have access to up to an additional fifty million gallons of propane storage capacity that can be utilized by our Marcellus, Utica and Northeast segments under an agreement with a third party that expires in 2018. Lastly, we have up to nine million gallons of butane storage and eleven million gallons of propane storage with third parties that can be utilized by our Marcellus and Utica segments.

(3)
Our Hopedale Complex is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG, respectively.

(4)
Our Siloam Complex 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 and can be transported from the facility by truck, rail or barge. This facility has large-scale truck and rail loading and unloading capabilities, and a river barge facility capable of loading barges up to 840,000 gallons.

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Natural Gas Gathering Systems:

 
   
   
   
  Year ended
December 31, 2014
 
Facility
  Location   Year of Initial
Construction
  Design
Throughput
Capacity
  Natural Gas
Throughput(1)
  Utilization
of Design
Capacity(1)
 
 
   
   
  (Mcf/d)
  (Mcf/d)
   
 

Marcellus

                             

Marcellus Shale:

                             

Houston System

  Washington County, PA     2008     797,000     550,600     69 %

Keystone System

  Butler County, PA     2010     227,000     118,000     52 %

Total Marcellus

              1,024,000     668,600     65 %

Utica

 

 

   
 
   
 
   
 
   
 
 

Ohio Gathering System(2)

  Harrison County, OH     2012     700,000     288,800     41 %

Total Utica(2)

              700,000     288,800     41 %

Southwest

 

 

   
 
   
 
   
 
   
 
 

East Texas:

                             

East Texas System

  Panola County, TX     1990     640,000     548,100     86 %

Oklahoma:

                             

Western Oklahoma System

  Wheeler County, TX and Roger Mills, Ellis, Custer, Beckham and Washita Counties, OK     1998     775,000     338,800     45 %

Southeast Oklahoma System

  Hughes, Pittsburg and Coal Counties, OK     2006     550,000     397,600     72 %

Other Southwest:

                             

Eagle Ford System

  Dimmit County, TX     2013     45,000     33,200     74 %

Other Systems(3)

  Various     Various     111,500     14,600     13 %

Total Southwest

              2,121,500     1,332,300     64 %

Total Natural Gas Gathering(4)

             
3,845,500
   
2,289,700
   
60

%

(1)
Natural gas throughput is a weighted average for days in operation. The utilization of design capacity has been calculated using the weighted average design throughput capacity.

(2)
The Ohio Gathering System is owned by Ohio Gathering, which we deconsolidated on June 1, 2014. We account for Ohio Gathering as an equity method investment. See discussion in Note 3 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

(3)
Excludes lateral pipelines where revenue is not based on throughput.

(4)
Includes Utica subtotal, which is owned by one of our joint ventures and accounted for as an equity method investment (see note 2 above).

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NGL Pipelines:

 
   
   
   
  Year ended
December 31, 2014
 
Pipeline
  Location   Year of Initial
Construction
  Design
Throughput
Capacity
  NGL
Throughput
  Utilization
of Design
Capacity(1)
 
 
   
   
  (Bbl/d)
  (Bbl/d)
   
 

Marcellus

                             

Marcellus Shale:

                             

Sherwood to Mobley propane and heavier liquids pipeline

  Doddridge County, WV to Wetzel County, WV     2013     27,400     16,000     58 %

Mobley to Fort Beeler propane and heavier liquids pipeline

  Wetzel County, WV to Marshall County, WV     2012     64,000     31,800     50 %

Fort Beeler to Majorsville propane and heavier liquids pipeline

  Marshall County, WV     2011     45,000     33,600     75 %

Majorsville to Houston propane and heavier liquids pipeline

  Marshall County, WV to Washington County, PA     2010     43,400     33,500     77 %

Majorsville to Hopedale propane and heavier liquids pipeline

  Marshall County, WV to Harrison County, OH     2014     96,900     30,000     31 %

Third party processing plant to Keystone propane and heavier liquids pipeline

  Butler County, PA     2014     32,500     5,300     16 %

Keystone to Mariner West ethane pipeline(2)

  Butler County, PA to Beaver County, PA     2014     35,000     3,300     9 %

Houston to Mariner West ethane pipeline(3)

  Washington County, PA to Beaver County, PA     2014     54,600     21,600     40 %

Majorsville to Houston ethane pipeline(2)

  Marshall County, WV to Washington County, PA     2013     40,000     31,600     79 %

Utica

 

 

   
 
   
 
   
 
   
 
 

Utica Shale:

                             

Seneca to Hopedale

  Noble County, OH to Harrison County, OH     2013     97,000     11,800     12 %

Northeast

 

 

   
 
   
 
   
 
   
 
 

Appalachia:

                             

Langley to Siloam(4)

  Langley, KY to South Shore, KY     1957     19,000     13,000     68 %

Southwest

 

 

   
 
   
 
   
 
   
 
 

East Texas:

                             

East Texas liquid line

  Panola County, TX     2005     39,000     27,100     69 %

(1)
We have built the Marcellus and Utica pipelines to support our expected growth and for ethane recovery.

(2)
This pipeline is FERC-regulated.

(3)
This pipeline is FERC-regulated and is operated by Sunoco as part of Mariner West.

(4)
NGLs transported through the Langley to Ranger and Ranger to Kenova pipelines are combined with NGLs recovered at the Kenova facility. The design capacity and volume reported for the Langley to Siloam pipeline represent the combined NGL stream.

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Crude Oil Pipeline:

 
   
   
   
  Year ended
December 31, 2014
 
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     9,700     16 %

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. Many of our processing and fractionation facilities, including our Siloam, Houston and Hopedale fractionation plants, and certain of our pipelines and other facilities, are on land that we either own in fee or that is held under long-term leases, but for any such facilities that are on land that we lease, including our Majorsville, Sarsen, Keystone, Boldman, Kermit and Cobb processing facilities, we could be required to remove our facilities upon the termination or expiration of the leases.

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

        We have pledged our assets and those of our wholly-owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries, 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 coverage 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.

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        On March 21, 2014, MarkWest Liberty Midstream received a Draft Consent Order from the West Virginia Department of Environmental Protection ("WVDEP") incorporating 16 separate inspections in 2013 of various operations and construction sites with claimed regulatory violations relating to erosion and sediment control measures, damage in 2013 to a portion of the Marcellus NGL pipeline in Wetzel County, West Virginia which resulted from landslides ("Wetzel County Landslides") and associated issues, pipeline borings and other disparate matters. The Draft Consent Order aggregated those matters and proposed a total aggregate administrative penalty of $115,120 for all of the various alleged claims, as well as the development of an approved remediation plan and certain provisions for approval of pipeline boring plans and other construction related activities in West Virginia going forward. MarkWest Liberty Midstream believes there are substantial defenses and disputable issues regarding the alleged claims, remedial action plans and the proposed penalty as set forth in the Draft Consent Order and MarkWest Liberty Midstream has and will continue to assert those defenses and issues in discussions with WVDEP.

        In connection with construction activities in eastern Ohio, MarkWest Utica EMG experienced incidents of inadvertent returns of a bentonite clay solution used during construction of borings under areas primarily involving reclaimed strip coal mine lands. MarkWest Utica EMG self-reported these incidents to the Ohio Environmental Protection Agency ("OEPA") and has remediated any impacts from these bentonite-clay inadvertent returns. There was no adverse impact on human health from these incidents and the impact to the receiving areas was a temporary physical sedimentation impact, without any chemicals or additives involved. On November 20, 2014, OEPA and MarkWest Utica EMG entered into an Administrative Order to settle all issues associated with the reported inadvertent returns under which MarkWest agreed to pay a civil penalty of $95,000 and agreed to establish a conservation/hunting easement for a wetland in the inadvertent return area and fund certain municipal and educational projects.

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. All of our Class B units were issued to and are held by M&R as part of our December 31, 2011 acquisition of the non-controlling interest in MarkWest Liberty Midstream. The remaining Class B units will convert to common units on a one-for-one basis in three equal installments beginning on July 1, 2015 and each of the first two anniversaries of such date.

        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 2014 and 2013:

 
  Unit Price    
   
   
   
 
  Distributions Per
Common Unit
   
   
   
Quarter Ended
  High   Low   Declaration Date   Record Date   Payment Date

December 31, 2014

  $ 77.31   $ 58.67   $ 0.90     January 21, 2015   February 5, 2015   February 13, 2015

September 30, 2014

  $ 80.79   $ 67.70   $ 0.89     October 22, 2014   November 5, 2014   November 14, 2014

June 30, 2014

  $ 71.88   $ 58.62   $ 0.88     July 24, 2014   August 5, 2014   August 14, 2014

March 31, 2014

  $ 73.42   $ 61.60   $ 0.87     April 22, 2014   May 7, 2014   May 15, 2014

December 31, 2013

  $ 75.79   $ 62.56   $ 0.86     January 22, 2014   February 6, 2014   February 14, 2014

September 30, 2013

  $ 72.35   $ 65.27   $ 0.85     October 23, 2013   November 7, 2013   November 14, 2013

June 30, 2013

  $ 71.20   $ 56.90   $ 0.84     July 24, 2013   August 6, 2013   August 14, 2013

March 31, 2013

  $ 61.97   $ 51.77   $ 0.83     April 25, 2013   May 7, 2013   May 15, 2013

December 31, 2012

  $ 55.95   $ 46.03   $ 0.82     January 23, 2013   February 6, 2013   February 14, 2013

        As of February 18, 2015, there were approximately 433 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" (as defined below), including the "Available Cash" of our subsidiaries, on a pro rata basis to common unitholders of record on the applicable record date. Class B unitholders do not receive cash distributions. Class A unitholders receive distributions of Available Cash (excluding the Available Cash attributable to MarkWest Hydrocarbon). However, because all Class A unitholders are wholly-owned subsidiaries, these intercompany distributions do not impact the amount of Available Cash that can be distributed to common unitholders.

        We define "Available Cash" in our amended and restated partnership agreement, and we generally mean, for each fiscal quarter:

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

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

    provide for the proper conduct of our business;

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

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

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

        Our ability to distribute available cash is contractually restricted by the terms of our Credit Facility and our indentures. Our Credit Facility and indentures contain covenants requiring us to maintain

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certain financial ratios and a minimum net worth. We are prohibited from making any distribution to unitholders if such distribution would cause an event of default or otherwise violate a covenant under our Credit Facility or indentures. 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 our 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, 2014, 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
  Weighted average
exercise price of
outstanding options,
warrants and rights(1)
  Number of securities
remaining available
for future issuance
under equity
compensation plans
 

Equity compensation plans approved by security holders:

                   

2008 Long-Term Incentive Plan          

    675,341   $     1,693,431  

(1)
Phantom units are granted with no exercise price.

Recent Sales of Unregistered Units

        None.

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

        None.

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ITEM 6.    Selected Financial Data

        The following table sets forth selected consolidated historical financial and operating data for MarkWest Energy Partners (dollars in thousands, except per unit amounts). 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,  
 
  2014   2013   2012   2011   2010  

Statement of Operations:

                               

Revenue:

                               

Product sales

  $ 1,198,642   $ 1,093,711   $ 1,002,224   $ 1,235,052   $ 1,007,254  

Service revenue

    937,380     593,374     381,055     287,540     219,535  

Derivative gain (loss)(1)

    40,151     (24,638 )   56,535     (29,035 )   (53,932 )

Total revenue

    2,176,173     1,662,447     1,439,814     1,493,557     1,172,857  

Operating expenses:

                               

Purchased product costs

    832,428     691,165     530,328     682,370     578,627  

Derivative (gain) loss related to purchased product costs(1)

    (58,392 )   (1,737 )   (13,962 )   52,960     27,713  

Facility expenses

    343,362     291,069     206,861     171,497     148,416  

Derivative loss (gain) related to facility expenses(1)

    3,277     2,869     1,371     (6,480 )   (1,295 )

Selling, general and administrative expenses

    126,499     101,549     93,444     80,441     74,558  

Depreciation

    422,755     299,884     183,250     143,704     116,949  

Amortization of intangible assets

    64,893     64,644     53,320     43,617     40,833  

Loss (gain) on disposal of property, plant and equipment

    1,116     (33,763 )   6,254     8,797     3,149  

Accretion of asset retirement obligations

    570     824     672     1,185     240  

Impairment of goodwill

    62,445                  

Total operating expenses

    1,798,953     1,416,504     1,061,538     1,178,091     989,190  

Income from operations

    377,220     245,943     378,276     315,466     183,667  

Other income (expenses):

                               

(Loss) earnings from unconsolidated affiliates

    (4,477 )   1,422     2,328     158     3,823  

Interest expense

    (166,372 )   (151,851 )   (120,191 )   (113,631 )   (103,873 )

Amortization of deferred financing costs and discount (a component of interest expense)

    (7,289 )   (6,726 )   (5,601 )   (5,114 )   (10,264 )

Derivative gain related to interest expense(1)

                    1,871  

Loss on redemption of debt

        (38,455 )       (78,996 )   (46,326 )

Miscellaneous income, net(1)

    3,440     2,781     481     566     2,859  

Income before provision for income tax

    202,522     53,114     255,293     118,449     31,757  

Provision for income tax expense (benefit):

                               

Current

    618     (11,208 )   (2,366 )   17,578     7,655  

Deferred

    41,601     23,877     40,694     (3,929 )   (4,466 )

Total provision for income tax

    42,219     12,669     38,328     13,649     3,189  

Net income

    160,303     40,445     216,965     104,800     28,568  

Net (income) loss attributable to non-controlling interest

    (26,422 )   (2,368 )   3,437     (44,105 )   (28,101 )

Net income attributable to the Partnership's unitholders

  $ 133,881   $ 38,077   $ 220,402   $ 60,695   $ 467  

Net income (loss) attributable to the Partnership's common unitholders per common unit(2):

                               

Basic

  $ 0.77   $ 0.26   $ 1.98   $ 0.75   $ (0.01 )

Diluted

  $ 0.72   $ 0.24   $ 1.69   $ 0.75   $ (0.01 )

Cash distribution declared per common unit

  $ 3.50   $ 3.34   $ 3.16   $ 2.75   $ 2.56  

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  Year ended December 31,  
 
  2014   2013   2012   2011   2010  

Balance Sheet Data (at December 31):

                               

Working capital

  $ (102,210 ) $ (353,273 ) $ (84,512 ) $ 1,060   $ (46,152 )

Property, plant and equipment, net

    8,652,900     7,693,169     4,939,618     2,723,049     2,171,986  

Total assets

    10,980,778     9,396,423     6,728,362     3,959,874     3,220,156  

Total long-term debt

    3,621,404     3,023,071     2,523,051     1,846,062     1,273,434  

Total equity

    6,193,239     4,798,133     3,111,398     1,395,242     1,350,294  

Cash Flow Data:

                               

Net cash flow provided by (used in):

                               

Operating activities

  $ 668,399   $ 435,650   $ 492,013   $ 410,403   $ 306,117  

Investing activities

    (2,270,096 )   (3,062,562 )   (2,472,088 )   (776,111 )   (484,804 )

Financing activities

    1,625,279     2,366,461     2,211,499     415,503     149,246  

Other Financial Data:

                               

Maintenance capital expenditures(3)

  $ 19,120   $ 18,985   $ 16,782   $ 15,909   $ 10,286  

Growth capital expenditures(3)

    2,350,595     3,027,971     1,933,542     534,930     447,182  

Total capital expenditures

  $ 2,369,715   $ 3,046,956   $ 1,950,324   $ 550,839   $ 457,468  

(1)
As discussed further in Note 8 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,  
 
  2014   2013   2012   2011   2010  

Realized gain (loss)—revenue

  $ 15,002   $ (3,534 ) $ (6,508 ) $ (48,093 ) $ (33,560 )

Unrealized gain (loss)—revenue

    25,149     (21,104 )   63,043     19,058     (20,372 )

Realized loss—purchased product costs

    (1,803 )   (6,634 )   (26,493 )   (27,711 )   (21,909 )

Unrealized gain (loss)—purchased product costs

    60,195     8,371     40,455     (25,249 )   (5,804 )

Unrealized (loss) gain—facility expenses

    (3,277 )   (2,869 )   (1,371 )   6,480     1,295  

Realized gain—interest expense

                    2,380  

Unrealized loss—interest expense

                    (509 )

Unrealized gain—miscellaneous income (expense), net

                    190  

Total derivative gain (loss)

    95,266   $ (25,770 ) $ 69,126   $ (75,515 ) $ (78,289 )
(2)
For the calculation of Net income attributable to the Partnership's common unitholders per common unit, see Note 24 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

(3)
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 volumes gathered, processed, transported or fractionated, or to decrease operating expenses, within our facilities. Growth capital also includes costs associated with new well connections. In general, growth capital includes costs that are expected to generate additional or new cash flow for the Partnership. Growth capital excludes expenditures for third-party acquisitions and equity investment.

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Operating Data

 
  Year ended December 31,  
 
  2014   2013   2012   2011   2010  

Marcellus

                               

Gathering system throughput (Mcf/d)(1)

    668,600     549,500     425,000     245,700     142,200  

Natural gas processed (Mcf/d)

    2,063,900     1,101,900     496,400     323,900     215,700  

C2 (purity ethane) produced (Bbl/d)(2)

    54,400     100              

C3+ NGLs fractionated (Bb/d)(3)

    93,000     47,600     24,900     11,800     4,200  

Total NGLs fractionated (Bbl/d)

    147,400     47,700     24,900     11,800     4,200  

Utica(4)

                               

Gathering system throughput (Mcf/d)

    288,800     62,400     5,000     N/A     N/A  

Natural gas processed (Mcf/d)

    415,500     88,400     4,200     N/A     N/A  

C3+ NGLs fractionated (Bbl/d)(3)

    18,500                  

Northeast(5)

                               

Natural gas processed (Mcf/d)

    279,800     296,100     320,500     305,900     188,700  

NGLs fractionated (Bbl/d)(6)

    19,500     20,200     17,300     20,300     20,700  

Keep-whole NGL sales (gallons, in thousands)

    112,200     117,500     131,600     113,800     136,700  

Percent-of-proceeds NGL sales (gallons, in thousands)

    119,700     134,300     139,700     130,300     120,300  

Total NGL sales (gallons, in thousands)(7)

    231,900     251,800     271,300     244,100     257,000  

Crude oil transported for a fee (Bbl/d)

    9,700     9,700     9,300     10,300     12,800  

Southwest

                               

East Texas gathering systems throughput (Mcf/d)

    548,100     504,000     450,000     423,600     430,300  

East Texas natural gas processed (Mcf/d)(8)

    419,100     355,100     270,800     228,300     233,100  

East Texas NGL sales (gallons, in thousands)(9)

    431,400     320,000     248,700     238,700     245,800  

Western Oklahoma gathering system throughput (Mcf/d)(10)

    338,800     238,600     235,600     237,900     191,100  

Western Oklahoma natural gas processed (Mcf/d)(11)

    284,600     202,600     206,500     175,500     134,700  

Western Oklahoma NGL sales (gallons, in thousands)(9)

    219,300     239,200     214,400     177,200     134,100  

Southeast Oklahoma gathering systems throughput (Mcf/d)

    397,600     443,700     487,900     511,900     521,400  

Southeast Oklahoma natural gas processed (Mcf/d)(12)

    173,500     153,800     121,800     103,400     81,600  

Southeast Oklahoma NGL sales (gallons, in thousands)

    108,400     159,600     163,300     125,100     102,300  

Other Southwest gathering system throughput (Mcf/d)(13)

    48,300     35,000     24,300     29,900     39,500  

Gulf Coast refinery off-gas processed (Mcf/d)

    114,100     103,400     118,400     113,300     118,600  

Gulf Coast liquids fractionated (Bbl/d)(14)

    20,800     18,800     22,500     21,200     22,500  

Gulf Coast NGL sales (gallons in thousands)(14)

    318,500     288,800     345,300     325,700     345,500  

Total Southwest gathering system throughput (Mcf/d)

    1,332,800     1,221,300     1,197,800     1,203,300     1,182,300  

Total Southwest natural gas and refinery off-gas processed (Mcf/d)

    991,300     814,900     717,500     620,500     568,000  

(1)
The 2013 volumes exclude Sherwood gathering as this system was sold to Summit in June 2013.

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(2)
The Keystone ethane fractionation facility began operations in June 2014. The volumes reported for 2014 are the average daily rate for the days of operation.

(3)
Hopedale is jointly owned by MarkWest Liberty Midstream and MarkWest Utica EMG. Each segment includes its respective portion of the capacity utilized of the jointly owned Hopedale Fractionation Facility. Operations began in January 2014 and December 2014. The volumes reported for 2014 are the average daily rate for the days of operation.

(4)
Utica operations began in August 2012. The volumes reported for 2012 are the average daily rate for the days of operation.

(5)
Includes throughput from the Kenova, Cobb, Boldman and Langley processing plants. We acquired the Langley processing plant in February 2011. The volumes reported for 2011 represent the average daily rates for the days of operation.

(6)
Includes NGLs fractionated for Utica and Marcellus segments.

(7)
Represents sales at the Siloam fractionator. The total sales exclude approximately 68,400,000 gallons, 59,700,000 gallons, 6,500,000 gallons, 59,200,000 gallons and 60,900,000 gallons sold by the Northeast on behalf of Marcellus and Utica for 2014 and 2013, and on behalf of Marcellus for 2012, 2011 and 2010, respectively. These volumes are included as part of NGLs sold at Marcellus and Utica.

(8)
Includes certain amounts in 2014 in excess of East Texas' operating capacity that were processed by third-parties.

(9)
Excludes gallons processed in conjunction with take-in-kind contracts for the years ended December 31, 2014, 2013 and 2012, respectively, as shown below (gallons, in thousands).

 
  Year ended December 31,  
Gallons processed in conjunction with
take-in-kind contracts
  2014   2013   2012  

East Texas

    318,000     14,423,000     27,149,000  

Western Oklahoma

    122,310,000          
(10)
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.

(11)
The Buffalo Creek plant began operations in February 2014.

(12)
The natural gas processing in Southeast Oklahoma is outsourced to Centrahoma or other third-party processors.

(13)
Excludes lateral pipelines where revenue is not based on throughput.

(14)
Excludes Hydrogen volumes.

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 Form 10-K. 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

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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 that owns and operates midstream services related businesses. We have a leading presence in many natural gas resource plays including the Marcellus Shale, Utica Shale, Huron/Berea Shale, Haynesville Shale, Woodford Shale and Granite Wash formation where we provide midstream services for producer customers.

Significant Financial and Other Highlights

        Significant financial and other highlights for the year ended December 31, 2014 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 $229.2 million, or 32%, for the year ended December 31, 2014 as compared to the same period in 2013. The increase consists of the following:

    An increase of $174.1 million due to the continued growth in our Marcellus segment with an 87% increase in processed volumes and a 209% increase in fractionation volumes, mainly related to volumes in our Hopedale Complex commencing operations in 2014.

    An increase of $44.7 million due to the continued growth in our Utica segment with a 370% increase in processed volumes and an increase in fractionation volumes, related to our Hopedale Complex commencing operations in 2014.

    An increase of $25.0 million in the Southwest segment primarily due to a 22% increase in processed volumes.

    A decrease of $14.6 million in the Northeast segment due to a reduction in the frac spread margin and lower sales volumes.

    Realized gains from the settlement of our derivative instruments were $13.2 million for the year ended 2014 compared to realized losses of $10.2 million for the same period in 2013 due primarily to lower NGL pricing throughout 2014.

    We continued our expansion primarily in the Marcellus and Utica segments. We have both completed construction and placed into service sixteen new major facilities adding processing capacity of over 2.0 Bcf/d and fractionation capacity of 150 MBbl/d in 2014.

    In November 2014, we received net proceeds of approximately $493.8 million from a public offering of $500 million in aggregate principal amount of our 4.875% senior unsecured notes due in 2024, which were issued at par.

    During 2014, we received total net proceeds of approximately $1.6 billion from public offerings of approximately 24.6 million common units as part of our ongoing At the Market ("ATM") programs.

Results of Operations

Segment Reporting

        We classify our business in the following reportable segments: Marcellus, Utica, Northeast and Southwest. We capture information in MD&A by geographical segment. Items below Income from operations in the accompanying Consolidated Statements of Operations, certain compensation expense,

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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, 2014 Compared to Year Ended December 31, 2013

        The tables below present financial information, as evaluated by management, for the reported segments for the years ended December 31, 2014 and 2013. The information includes net operating margin, a non-GAAP financial measure. For a reconciliation of net operating margin to Income from operations, the most comparable GAAP financial measure, see Our Contracts discussion in Item 1. Business. This section should be read in conjunction with our Operating Data table that details volumes in Item 6. Selected Financial Data and our contract mix table found on page 23 of Item 1. Business.


Marcellus

 
  Year ended
December 31,
   
   
 
 
  2014   2013   $ Change   % Change  
 
  (in thousands)
   
 

Segment revenue

  $ 791,505   $ 527,073   $ 264,432     50 %

Segment purchased product costs

    147,500     100,262     47,238     47 %

Net operating margin

    644,005     426,811     217,194     51 %

Segment facility expenses

    151,898     108,781     43,117     40 %

Operating income before items not allocated to segments

  $ 492,107   $ 318,030   $ 174,077     55 %

        Segment Revenue.    Revenue increased due to ongoing expansion of the Marcellus segment operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $208.2 million due to an increase in gathering, processing and fractionation fees due to the increased capacities and corresponding volumes. Revenue also increased approximately $47.2 million due to an increase in NGLs inventory sold. Due to changes in contractual terms, we expect NGLs inventory sold to decline in 2015. Revenue increased approximately $6.6 million due to business interruption insurance proceeds related to the Wetzel County Landslides.

        Segment Purchased Product Costs.    Purchased product costs increased primarily due to an increase in inventory sales.

        Net Operating Margin.    Net operating margin increased as the volume of natural gas gathered, natural gas processed and propane and heavier NGL products fractionated increased by 22%, 87% and 95%, respectively. Approximately 87% of the net operating margin in 2014 was earned under fee-based contracts.

        Segment Facility Expenses.    Facility expenses increased due to the ongoing expansion of the Marcellus segment operations, partially offset by approximately $7.0 million of insurance proceeds received related to the Wetzel County Landslides.

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Utica

 
  Year ended December 31,    
   
 
 
  2014   2013   $ Change   % Change  
 
  (in thousands)
   
   
   
 

Segment revenue

  $ 152,975   $ 26,442   $ 126,533     479 %

Segment purchased product costs

    23,773         23,773     N/A  

Net operating margin

    129,202     26,442     102,760     389 %

Segment facility expenses

    54,224     35,081     19,143     55 %

Segment portion of operating income (loss) attributable to non-controlling interests

    35,422     (3,499 )   38,921     (1,112 )%