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

1515 Arapahoe Street, Tower 1, Suite 1600, Denver, CO 80202-2137
(Address of principal executive offices)

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

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.

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.

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.

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.

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

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.

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

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.

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

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):

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.

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.

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.

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.

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

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.

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.

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:

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:

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:

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

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

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.

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

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:

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.

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:

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

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

Complex			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

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.

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:

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:

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

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.

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).

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.

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

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

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.

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.

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.

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.

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.

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:

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.

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.

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

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

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:

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.

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

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.

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.

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:

Under the Natural Gas Act ("NGA"), FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services and various other matters. Natural gas companies may not charge rates that

have been determined not to be just and reasonable by FERC. In addition, FERC prohibits FERC regulated natural gas facilities from unduly preferring, or unduly discriminating against, any person with respect to pipeline rates or terms and conditions of service or other matters. The rates and terms and conditions for 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

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.

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.

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.

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

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.

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

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.

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.

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

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.

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.

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.

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.

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

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.

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.

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

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.

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.

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.

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.

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

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:

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.

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:

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

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.

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

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:

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.

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:

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.

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.

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:

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

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,

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

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.

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.

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.

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.

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.

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,

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.

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.

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:

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:

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.

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:

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

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:

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

We have partial ownership interests in a number of joint venture legal entities, including 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:

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

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.

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:

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.

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.

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

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.

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.

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.

						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

						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.

						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	%

						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	%

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.

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.

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 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

	Unit Price				Distributions Per Common Unit
Quarter Ended	High		Low		Distributions Per Common Unit		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.

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:

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

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.

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.

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.

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

	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

	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	)

	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

(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).

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

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.

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 for the year ended December 31, 2014 are listed below. Refer to Results of Operations and Liquidity and Capital Resources for further details.

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,

certain other non-cash items and any unrealized gains (losses) from derivative instruments are not allocated to individual business segments. Management does not consider these items allocable to or controllable by any individual business segment and therefore excludes these items when evaluating segment performance. The segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests.

The tables below present 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.

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.

The results of operations for the year ended December 31, 2014 include our operations in Utica Shale areas of eastern Ohio, including gas gathering revenue and facility expenses of Ohio Gathering, which was deconsolidated June 1, 2014 (see Note 3 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K). The first phase of operations commenced in the third quarter of 2012 and Utica was still in the early stages of development and operations at December 31, 2013.

Segment Revenue. Revenue increased due to ongoing expansion of the Utica segment operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $105.8 million due to an increase in gathering, processing and fractionation fees due to the increased capacities and corresponding volumes. Revenue also increased approximately $20.4 million due to an increase in NGLs inventory sold. These revenue increases were the direct result of a 370% increase in processing volumes, a 363% increase in volumes increased in gathered volumes and a 100% increase in fractionated volumes. Due to changes in contractual terms, we expect NGLs inventory sold to decline to near zero in 2015 as revenue from this activity will be presented net.

Segment Purchased Product Costs. Purchased product costs increased due to an increase in inventory sold and a decline in the value of line fill of $1.7 million.

Net Operating Margin. Net operating margin increased due to an overall increase in operations and corresponding volumes for the year ended December 31, 2014 compared to the same period in 2013. All of our gathering and processing contracts in the Utica segment are fee based.

Segment Facility Expenses. Facility expenses increased in 2014 due to significant increases in operations as compared to 2013 as a result of the start-up of additional processing, gathering and fractionation facilities in the Utica segment in 2014.

Segment Revenue. Revenue decreased primarily due to lower volumes sold compared to the same period in 2013.

Segment Purchased Product Costs. Purchased product costs increased slightly due to an increase in natural gas purchase prices and an increase in the value of linefill of $0.7 million, partially offset by lower volumes.

Net Operating Margin. Net operating margin decreased mainly due to an 8% decrease of NGL sales volumes and a decrease in the frac spread margins of 5% compared to the same period in 2013. Approximately 59% of the net operating margin was derived from keep-whole contracts. During 2014, frac spread margins generally declined throughout the year. In 2015, we expect net operating margin to be lower than 2014 assuming the current low commodity pricing continues.

Segment Facility Expenses. Facility expenses increased primarily due to an increase in plant operating expenses attributable to the timing of normal facility maintenance and repairs and overall increases in costs to provide services.

Segment Revenue. Revenue increased due to higher NGL sales, gas sales and higher fee-based revenue. NGL sales increased approximately $7.3 million primarily due to increased volumes in our East Texas area of 35% accounting for $39.5 million of the increase, partially offset by approximately $9.8 million decrease in Southeast Oklahoma due to a decrease of 32% in NGL sales volumes and approximately $18.7 million due to an 8% decrease in volumes in Western Oklahoma. Gas sales increased approximately $38.9 million primarily in our Western Oklahoma, East Texas and Southeast Oklahoma areas due to higher gas prices and operating in an environment of increased ethane rejection compared to the same period in 2013. Processing fee revenue increased by approximately

$26.7 million due to an increase in volumes in our Western Oklahoma, East Texas and Southeast Oklahoma areas of 40%, 18% and 13%, respectively. The 40% increase in processing volumes in the Western Oklahoma area primarily relates to the new Buffalo Creek plant that began operations in February 2014. Gathering fee revenue increased by approximately $14.3 million primarily in our Western Oklahoma and East Texas areas, where gathered volumes increased 42% and 9%, respectively. The 42% increase in gathered volumes in Western Oklahoma primarily relates to expanded operations from our acquisition of certain natural gas gathering and processing assets from Chesapeake Energy Corporation (the "Buffalo Creek Acquisition"). Hydrogen sales increased approximately $6.3 million in our Javelina area due to increased volumes of 9% and higher prices.

Segment Purchased Product Costs. Purchased product costs increased due to higher NGL purchases of approximately $37.3 million mainly due to increased volumes. NGL purchased product costs increased as a percent of NGL sales due to lower average percent of proceeds. Gas purchases increased by approximately $33.2 million primarily related to our East Texas and Western Oklahoma areas.

Net Operating Margin. Net operating margin increased mainly due to increases in fee based income partially offset by lower NGL pricing. Approximately two-thirds of the fee based income increased as a result of the Buffalo Creek Acquisition and West Asherton facilities. The Buffalo Creek plant, which began operations in February of 2014, contributed to the higher gathered and processed volumes in Western Oklahoma. During 2014, commodity prices generally declined throughout the year. In 2015, we expect net operating margin to be lower than 2014 assuming the current low commodity pricing continues.

Segment Facility Expenses. Facility expenses increased primarily due to $4.1 million of expenses related to the Buffalo Creek Acquisition and West Asherton facilities becoming operational in the second half of 2013, as well as an increase in utility expenses on new facilities of approximately $1.6 million.

Reconciliation of Segment Operating Income to Consolidated Income
Before Provision for Income Tax

revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Year ended December 31,

	2014			2013			$ Change			% Change
	(in thousands)
Total segment revenue	$	2,167,808		$	1,693,267		$	474,541			28	%
Derivative gain (loss) not allocated to segments		40,151			(24,638	)		64,789			263	%
Revenue adjustment for unconsolidated affiliate		(41,446	)		—			(41,446	)		N/A
Revenue deferral adjustment and other		9,660			(6,182	)		15,842			256	%

Total revenue	$	2,176,173		$	1,662,447		$	513,726			31	%



Operating income before items not allocated to segments	$	935,412		$	706,181		$	229,231			32	%
Portion of operating income attributable to non-controlling interests		21,425			(3,478	)		24,903			(716	)%
Derivative gain (loss) not allocated to segments		95,266			(25,770	)		121,036			470	%
Revenue adjustment for unconsolidated affiliate		(41,446	)		—			(41,446	)		N/A
Revenue deferral adjustment and other		4,455			(6,182	)		10,637			(172	)%
Compensation expense included in facility expenses not allocated to segments		(3,932	)		(2,421	)		(1,511	)		62	%
Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliate		19,559			—			19,559			N/A
Portion of operating income attributable to non-controlling interests of an unconsolidated affiliate		14,008			—			14,008			N/A
Facility expenses adjustments		10,751			10,751			—			0	%
Selling, general and administrative expenses		(126,499	)		(101,549	)		(24,950	)		25	%
Depreciation		(422,755	)		(299,884	)		(122,871	)		41	%
Amortization of intangible assets		(64,893	)		(64,644	)		(249	)		0	%
Impairment of goodwill		(62,445	)		—			(62,445	)		N/A
(Loss) gain on disposal of property, plant and equipment		(1,116	)		33,763			(34,879	)		(103	)%
Accretion of asset retirement obligations		(570	)		(824	)		254			(31	)%

Income from operations		377,220			245,943			131,277			53	%
Equity in (loss) earnings from unconsolidated affiliates		(4,477	)		1,422			(5,899	)		(415	)%
Interest expense		(166,372	)		(151,851	)		(14,521	)		10	%
Amortization of deferred financing costs and discount (a component of interest expense)		(7,289	)		(6,726	)		(563	)		8	%
Loss on redemption of debt		—			(38,455	)		38,455			(100	)%
Miscellaneous income, net		3,440			2,781			659			24	%

Income before provision for income tax	$	202,522		$	53,114		$	149,408			281	%

Portion of Operating Income (Loss) Attributable to Non-controlling Interests. Portion of operating income (loss) attributable to non-controlling interests increased primarily due to the deconsolidation of Ohio Gathering (See discussion above in Revenue adjustment for unconsolidated affiliate, Note 3 and Note 25 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K).

Derivative Gain (Loss) Not Allocated to Segments. Unrealized gain from the change in fair value of our derivative instruments was $82.1 million for the year ended December 31, 2014 compared to an unrealized loss of $15.6 million for the same period in 2013. Realized gain from the settlement of our derivative instruments was $13.2 million for the year ended December 31, 2014 compared to a realized loss of $10.2 million for the same period in 2013. The total change of $121.0 million is due primarily to increased volatility in commodity prices.

Revenue Adjustment for Unconsolidated Affiliate. Revenue adjustment for unconsolidated affiliate relates to Ohio Gathering revenues that the chief operating decision maker and management evaluate on a consolidated basis as we continue to operate and manage operations. Therefore, the impact of the revenue is included for segment reporting purposes, but removed to reconcile to GAAP (See Notes 3 and 25 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K).

Revenue Deferral Adjustment and Other. Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the year ended December 31, 2014, approximately $6.2 million and $0.8 million of the revenue deferral adjustment is attributable to the Northeast segment and Southwest segment, respectively. For the year ended December 31, 2013, approximately $6.4 million and $0.8 million of the revenue deferral adjustment is attributable to the Northeast segment and Southwest segment, respectively. Beginning in 2015, the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes. Other consists of management fee revenues from unconsolidated affiliates of $16.5 million for the year ended December 31, 2014 compared to $1.0 million for the year ended December 31, 2013, which have increased due to the deconsolidation of Ohio Gathering.

Compensation Expense Included in Facility Expenses not Allocated to Segments. Compensation expense included in facility expenses not allocated to segments increased due to an increase in our phantom unit grants due to increases in headcount.

Facility Expense and Purchased Product Cost Adjustments for Unconsolidated Affiliate. Facility expense and purchased product cost adjustments for unconsolidated affiliate relate to Ohio Gathering (see discussion above in Revenue adjustment for unconsolidated affiliate, Note 3 and Note 25 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K).

Portion of Operating Loss Income Attributable to Non-controlling Interests of Unconsolidated Affiliate. Portion of operating loss attributable to non-controlling interests of unconsolidated affiliate relates to Summit's portion of Ohio Gathering's operating loss, as a result of segment operating income being reported as if Ohio Gathering were consolidated (see discussion above in Revenue adjustment for unconsolidated affiliate, Note 3 and Note 25 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K).

Selling, General and Administration Expenses. Selling, general and administration expenses have increased to support the continued growth in our operations.

Depreciation. Depreciation increased due to additional projects completed during late 2013 and throughout 2014 mainly in the Utica and Marcellus segments.

(Loss) Gain on Disposal of Property, Plant and Equipment. The decrease in (loss) gain on disposal of property, plant and equipment relates primarily to a gain on our sale of certain gathering assets in Doddridge County, West Virginia to Summit (the "Sherwood Asset Sale") in June 2013 of approximately $39.7 million.

Impairment of Goodwill. During the year ended December 31, 2014, we recorded a full impairment charge of $62.4 million related to the Appalachia Reporting Unit in our Northeast segment. The impairment was due primarily to a decline in commodity prices and the uncertainty related to the extension of certain material processing facility operating contracts. See Note 14 of the accompanying Notes to the Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion.

Equity in (Loss) Earnings from Unconsolidated Affiliates. The change in equity in (loss) earnings from unconsolidated affiliate relates primarily to a $5.2 million loss from Ohio Gathering in 2014, which was an equity method investment effective June 1, 2014.

Interest Expense. Interest expense increased due to the increase in the 2014 ending balance in Long-term debt of approximately $97.6 million in outstanding borrowings related to our Credit Facility, which fluctuated throughout 2014, an increase of $500 million related to our November 2014 public debt offering and by decreases in our capitalized interest of approximately $7.0 million primarily due to a decrease in our capital expenditures in 2014 compared to 2013.

Loss on Redemption of Debt. The decrease in loss on redemption of debt was related to the redemption of the 2018 Senior Notes, a portion of the 2021 Senior Notes and a portion of the 2022 Senior Notes that occurred in the first quarter of 2013, while no such redemptions of debt occurred during 2014.

Provision for Income Tax. The total provision for income tax for the year ended December 31, 2014 was $42.2 million. See Note 23 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for details of the significant components of the provision.

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

The current provision for income tax was a tax expense of $0.6 million for the year ended December 31, 2014 compared to a tax benefit of $11.2 million for the year ended December 31, 2013. The decrease in the current tax benefit was primarily due to expected increases in additional losses allocated to MarkWest Hydrocarbon as a result of its ownership of Class A units due to increases in earnings offset by the election of bonus depreciation for federal and certain state tax purposes and additional income expected to be allocated by the Partnership in accordance with the Internal Revenue Code. We expect our current tax provision in 2015 to be near zero as we expect our NOLs to offset any taxable income generated.

The tables below present financial information, as evaluated by management, for the reported segments for the years ended December 31, 2013 and 2012. 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.

Segment Revenue. Revenue increased due to ongoing expansion of the Marcellus segment operations resulting in increased gathered, processed and fractionated volumes. Revenue increased approximately $157.3 million related to gathering, processing and fractionation fees, of which approximately $66.2 million is due to our acquisition of certain assets from Keystone Midstream Services, LLC ("Keystone") located in Butler County, Pennsylvania (the "Keystone Acquisition") and the opening of the Sherwood Complex and the Mobley Complex and the remainder of which is due to increased volumes at our Houston and Majorsville facilities. Revenue also increased by approximately $49.9 million related to an increase in NGL sales volumes partially offset by a decrease in NGL prices. These revenue increases were partially offset by the impact of several operational constraints discussed further in the Net Operating Margin section below.

Segment Purchased Product Costs. Purchased product costs increased due to an increase of inventory sold, offset by a decrease in NGL prices.

Net Operating Margin. Net operating margin increased as the volume of natural gas gathered, processed and fractionated increased by 29%, 122% and 91%, respectively. Approximately 80% of the net operating margin in 2013 is earned under fee-based contracts (75% in 2012) and was not significantly impacted by the decline in commodity prices for the year ended December 31, 2013 compared to the same period in 2012. In total, the volumes of natural gas gathered and processed for one major customer account for a large amount of our consolidated net operating margin. Given the liquids rich acreage of the Marcellus Shale, if that customer's volumes decreased, we believe we could replace at least a reasonable portion of those volumes with volumes from other customers. Certain temporary capacity and other operational constraints that occurred during the second half of 2013 prevented us from realizing the full economic benefit of the significant growth in our producer customers' volumes. Our net operating margin was approximately $13.5 million lower than expected due to the following constraints:

Segment Facility Expenses. Facility expenses increased due to the ongoing expansion of the Marcellus segment operations, additional expenses of approximately $7.7 million, net of insurance recoveries, related to the Wetzel County Landslides and additional expenses caused by the limitations in fractionation capacity discussed above under Net Operating Margin.

The results of operations for the year ended December 31, 2013 include our operations in the Utica Shale areas of eastern Ohio. The increase in revenues is due to increased processing volumes as we commenced operations of an additional 325 MMcf/d of processing capacity throughout the year. Facility expenses include start-up costs and other costs that cannot be capitalized, including approximately $5.9 million of amortization of costs to install temporary compression and treating facilities and approximately $4.8 million of costs related to the temporary constraints on our fractionation capacity discuss above in the Marcellus—Net Operating Margin section.

Segment Revenue. Revenue decreased by approximately $20.3 million due to lower NGL sales volumes and $6.1 million related to lower NGL prices. The decrease in revenue was partially offset by a $4.6 million increase in fractionation fees from NGLs fractionated for our Marcellus segment.

Segment Purchased Product Costs. Purchased product costs decreased primarily due to the 11% decline in keep-whole sales volumes. The decreases were partially offset by higher prices for natural gas that is purchased to satisfy the keep-whole arrangements.

Net Operating Margin. Net operating margin decreased due to a 7% decrease in gallons sold and the narrowing of the spread between NGL and natural gas prices, as approximately 61% of the net operating margin in 2013 was derived from commodity sensitive keep-whole contracts. The overall frac spread margins declined by approximately 15% as compared to 2012. These variances were partially offset by improvement in margins in percent of proceeds contracts due to a contractual increase in the percentage retained beginning November 2012 and an increase in fractionation fees earned on NGL volumes produced by the Marcellus segment.

Segment Facility Expenses. Facility expenses increased due primarily to a non-recurring prior year adjustment of approximately $1.3 million related to a reduction in property taxes resulting from a favorable rate determination related to one of our facilities. The remaining increase was for a non-recurring repair on our Michigan crude pipeline, as well as the timing of normal facility maintenance and repairs.

Segment Revenue. Revenues increased due to approximately $42.3 million higher gas sales and approximately $1.9 million higher hydrogen revenue. The increase in gas sales revenue is primarily caused by higher prices and operating in ethane rejection in certain areas. Hydrogen revenue increased in our Javelina facility mainly due to a 32.0% increase in price. Processing fees increased approximately $20.7 million related to increases in East Texas related to the Carthage east plant completed at the end of 2012 and change in contract mix, which resulted in more volumes processed under fee-based arrangements and increases in processed volumes in southeast Oklahoma. NGL sales revenue increased by approximately $35.1 million resulting primarily from a $45.5 million increase from the full year of operation of the new processing facility. The increase was partially offset by an $7.3 million decrease caused by a planned shutdown of one customer's refinery operations from mid-January through mid-March in our Javelina area and shutdowns for other planned maintenance activities. Changes in contract mix, lower prices and reduced volumes of condensate sales in other areas also contributed to the decrease in revenue.

Segment Purchased Product Costs. Purchased product costs increased due to increases of approximately $118.4 million in higher NGL purchases, which consisted of approximately $34.1 million in southeast Oklahoma, approximately $54.8 million in East Texas and approximately $29.5 million in western Oklahoma. NGL purchases increased significantly more than NGL sales due to a shift in contract mix, which resulted in less volumes processed under keep-whole contracts and more volumes processed under fee-based or other arrangements in which NGLs are purchased from producer customers and resold. The remainder of the increase is due to gas purchases of approximately $16.8 million primarily due to higher gas prices.

Net Operating Margin. Net operating margin decreased as a percentage of revenue due to the change in contract mix discussed above. The decrease in net operating margin was partially offset by an approximately 14% increase in the volume of natural gas processed. Such increase was primarily due to producers' increased production in the liquids-rich gas areas of the Haynesville Shale, Woodford Shale and Cotton Valley formations.

Segment Facility Expenses. Facility expenses increased due primarily to repairs and maintenance at our Javelina facility caused by the overhaul of three inlet compressors and a plant turnaround in the fourth quarter of 2013, which was partially offset by savings in compressor rentals.

Reconciliation of Segment Operating Income to Consolidated Income
Before Provision for Income Tax

The following table provides a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to our consolidated income before provision for income tax for the years ended December 31, 2013 and 2012. The ensuing items listed below the Total segment revenue and Operating income lines are not allocated to business segments as management does not consider these items allocable to any individual segment.

	Year ended December 31,

	2013			2012			$ Change			% Change
	(in thousands)
Total segment revenue	$	1,693,267		$	1,389,214		$	304,053			22	%
Derivative (loss) gain not allocated to segments		(24,638	)		56,535			(81,173	)		(144	)%
Revenue deferral adjustment and other		(6,182	)		(5,935	)		(247	)		4	%

Total revenue	$	1,662,447		$	1,439,814		$	222,633			15	%



Operating income before items not allocated to segments	$	706,181		$	643,479		$	62,702			10	%
Portion of operating income attributable to non-controlling interests		(3,478	)		(1,183	)		(2,295	)		194	%
Derivative (loss) gain not allocated to segments		(25,770	)		69,126			(94,896	)		(137	)%
Revenue deferral adjustment and other		(6,182	)		(5,935	)		(247	)		4	%
Compensation expense included in facility expenses not allocated to segments		(2,421	)		(1,022	)		(1,399	)		137	%
Facility expenses adjustments		10,751			10,751			—			0	%
Selling, general and administrative expenses		(101,549	)		(93,444	)		(8,105	)		9	%
Depreciation		(299,884	)		(183,250	)		(116,634	)		64	%
Amortization of intangible assets		(64,644	)		(53,320	)		(11,324	)		21	%
Gain (loss) on disposal of property, plant and equipment		33,763			(6,254	)		40,017			(640	)%
Accretion of asset retirement obligations		(824	)		(672	)		(152	)		23	%

Income from operations		245,943			378,276			(132,333	)		(35	)%
Earnings from unconsolidated affiliates		1,422			2,328			(906	)		(39	)%
Interest expense		(151,851	)		(120,191	)		(31,660	)		26	%
Amortization of deferred financing costs and discount (a component of interest expense)		(6,726	)		(5,601	)		(1,125	)		20	%
Loss on redemption of debt		(38,455	)		—			(38,455	)		N/A
Miscellaneous income, net		2,781			481			2,300			478	%

Income before provision for income tax	$	53,114		$	255,293		$	(202,179	)		(79	)%

Derivative (Loss) Gain Not Allocated to Segments. Unrealized loss from the change in fair value of our derivative instruments was $15.6 million for the year ended December 31, 2013 compared to an unrealized gain of $102.1 million for the same period in 2012. Realized loss from the settlement of our derivative instruments was $10.2 million for the year ended December 31, 2013 compared to a realized loss of $33.0 million for the same period in 2012. The total change of $94.9 million is due primarily to increased volatility in commodity prices.

Revenue Deferral Adjustment and Other. Revenue deferral adjustment relates primarily to certain contracts in which the cash consideration we receive for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as we will perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the year ended December 31, 2013, approximately $6.4 million and $0.8 million of the revenue deferral adjustment is attributable to the Northeast segment and Southwest segment, respectively. For the year ended December 31, 2012, approximately $6.6 million and $0.8 million of the revenue deferral adjustment is attributable to the Northeast segment and Southwest segment, respectively. Based on commodity prices, the revenue deferral in subsequent periods did approximate the amount for the twelve months ended December 31, 2013 until the beginning of 2015 when the cash consideration received from these contracts will decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes. Other consists of management fee revenues from an unconsolidated affiliate of $1.0 million for the year ended December 31, 2013 compared to $1.5 million for the year ended December 31, 2012.

Facility Expense Adjustments. Facility expense adjustments consist of the reallocation of the interest expense related to SMR which is included in facility expenses for the purposes of evaluating the performance of the Southwest segment.

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

Depreciation. Depreciation increased due to additional projects completed at the end of 2012 and throughout 2013.

Amortization of Intangible Assets. Amortization increased due to the customer relationship intangibles acquired in the Keystone Acquisition and the Buffalo Creek Acquisition.

Gain (loss) on Disposal of Property, Plant and Equipment. Gain on disposal of property, plant and equipment relates primarily to a gain on our Sherwood Asset Sale in June 2013 of approximately $39.7 million.

Interest Expense. Interest expense increased due to the increased amount of outstanding debt. The increase was partially offset by an increase in capitalized interest of $9.0 million.

Loss on Redemption of Debt. The loss on redemption of debt was related to the redemption of the 2018 Senior Notes, a portion of the 2021 Senior Notes and a portion of the 2022 Senior Notes, which occurred in the first quarter of 2013, while no such redemptions of debt occurred in 2012.

Provision for Income Tax. The total provision for income tax for the year ended December 31, 2013 was $12.7 million. See Note 23 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for details of the significant components of the provision.

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

The current provision for income tax was a tax benefit of $11.2 million for the year ended December 31, 2013 compared to a tax benefit of $2.4 million for the year ended December 31, 2012. The increase in the current tax benefit was primarily due to an increase in the bonus depreciation for tax purposes due to an increase in the value of assets placed into service.

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

Our 2014 capital expenditures and our 2015 capital plan are summarized in the table below (in millions):

Our primary sources of liquidity to meet operating expenses and pay distributions to our unitholders are cash flows generated by our operations.

Management believes that expenditures for our capital projects can be funded with current cash balances, proceeds from public equity or debt offerings, contributions from joint venture partners, cash flows from operations and our current borrowing capacity under the Credit Facility. We may also consider the use of alternative financing strategies such as entering into additional joint venture arrangements or selling non-strategic assets. Our access to capital markets can be impacted by factors outside our control, which include, but are not limited to, general economic conditions and the rights of our Class B unitholders to participate in any future equity offerings we may commence following the conversion of the Class B units into common units; however, we believe that our strong cash flows and balance sheet, our Credit Facility and our credit rating will provide us with adequate access to the capital markets to fund our expected cash needs. Any new borrowing cost would be affected by market conditions and long-term debt ratings assigned by independent rating agencies. As of February 18, 2015, our credit ratings were Ba2 with a Stable outlook by Moody's Investors Service and BB with a Stable outlook by Standard & Poor's. Our Credit Facility is investment grade rated BBB– by Standard & Poor's. Changes in our operating results, cash flows or financial position could impact the ratings assigned by the various rating agencies. Should our credit ratings be adjusted downward, we

may incur higher costs to borrow, which could have a material impact on our financial condition and results of operations.

Our Credit Facility has a borrowing capacity of $1.3 billion and a maturity date of March 20, 2019, providing us with the financial flexibility to continue to execute our growth strategy. Our Credit Facility has a maximum permissible total leverage ratio of 5.5 to 1. See Note 17 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further details of our Credit Facility.

As of February 18, 2015, we had $343.3 million borrowings outstanding and $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $945.4 million available for borrowing, all of which was available for borrowing based on financial covenant requirements. Additionally, the full amount of unused capacity is available for borrowing on a short-term basis to provide financial flexibility within a given fiscal quarter.

As of December 31, 2014, we had six series of senior notes outstanding: $500.0 million in aggregate principal issued in November 2010 and due November 2020; $325.0 million in aggregate principal amount on the senior notes issued in February and March 2011 and due August 2021; $455.0 million aggregate principal amount on senior notes issued in October 2011 and due September 2022; $750.0 million aggregate principal amount on senior notes issued in August 2012 and due in February 2023; $1.0 billion aggregate principal amount on senior notes issued in January 2013 and due in July 2023; and $500.0 million aggregate principal amount on senior notes issued in November 2014 and due in 2024 (altogether the "Senior Notes"). As of December 31, 2014, there were no minimum payments on the Senior Notes due during the next five years. For further discussion of the Senior Notes and the accounting impacts, see Note 17 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K.

The Credit Facility and indentures governing our Senior Notes require us to meet certain financial covenants and limit certain activities of the Partnership and its restricted subsidiaries as described below. The Credit Facility and indentures place limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership's restricted subsidiaries to pay dividends or distributions, make loans or transfer property to the Partnership; engage in transactions with the Partnership's affiliates; sell assets, including equity interests of the Partnership's subsidiaries; make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets.

The Credit Facility limits our ability to enter into transactions with parties that require margin calls under certain derivative instruments. Under the Credit Facility, neither we nor the bank can require margin calls for outstanding derivative positions. As of February 18, 2015, all of our derivative positions are with members of the participating bank group and are not subject to margin deposit requirements. We believe this arrangement gives us additional liquidity as it allows us to enter into derivative instruments without utilizing cash for margin calls or requiring the use of letters of credit. We do not believe that the recent Dodd-Frank legislation will change our ability to enter into derivatives without utilizing cash for margin calls.

Our public equity offerings for the years ended December 31, 2014, 2013 and 2012 are summarized in the table below (in millions).

	Year ended December 31, 2012				Year ended December 31, 2013				Year ended December 31, 2014				Total

	Common units		Net Proceeds		Common units		Net Proceeds		Common units		Net Proceeds		Common units		Net Proceeds(1)
January 13, 2012(2)		0.7	$	38		—	$	—		—	$	—		0.7	$	38
March 16, 2012(2)		6.8		388		—		—		—		—		6.8		388
May 14, 2012(3)		8.0		427		—		—		—		—		8.0		427
August 17, 2012(2)		6.9		338		—		—		—		—		6.9		338
November 19, 2012(2)		9.8		437		—		—		—		—		9.8		437
November 2012 ATM(4)		0.1		6		9.3		584		—		—		9.4		590
August 2013 ATM(5)		—		—		5.9		396		—		—		5.9		396
September 2013 ATM(6)		—		—		10.9		718		4.2		272		15.1		990
March 2014 ATM(7)		—		—		—		—		17.9		1,191		17.9		1,191
November 2014 ATM(8)		—		—		—		—		2.5		175		2.5		175

Total		32.3	$	1,634		26.1	$	1,698		24.6	$	1,638		83.0	$	4,970

(1): Net proceeds from equity offerings were used to repay borrowings under the Credit Facility, to fund acquisitions and capital expenditures and to provide working capital for general partnership purposes.
(2): Includes full exercise of the underwriters' overallotment option unless otherwise noted.
(3): The underwriters did not exercise their over-allotment option for this offering.
(4): In November 2012, we entered into an Equity Distribution Agreement with Citigroup Global Markets Inc. that established a $600.0 million At the Market offering program (the "November 2012 ATM") which allowed us from time to time, through Citigroup Global Markets Inc. (the "Manager"), as our sales agent, to offer and sell common units representing limited partner interests in the Partnership having an aggregate offering price of up to $600.0 million. Sales of such common units were made by means of ordinary brokers' transactions on the NYSE at market prices, in block transactions or as otherwise agreed upon by us and the Manager. We could also sell common units to the Manager as principal for its own account at a price to be agreed upon at the time of such sale. For any such sales, we would enter into a separate agreement with the Manager. In the year ended December 31, 2013, we incurred $9.5 million in manager fees and other third-party expenses. Common units sold in 2012 totaled 0.1 million raising $6.3 million. The proceeds from sales were used to fund capital expenditures and for general partnership purposes. We completed this $600.0 million program in July 2013.
(5): In August 2013, we and M&R entered into an Equity Distribution Agreement with the Manager that established a $400.0 million At the Market offering program (the "August 2013 ATM"). In addition, the Selling Unitholder was permitted to sell from time to time through the Manager up to 1,452,415 common units. During the year ended December 31, 2013, the Partnership sold an aggregate of 5.9 million common units under the August 2013 ATM, receiving net proceeds of approximately $396.0 million after deducting approximately $4.0 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general partnership purposes.
(6): In September 2013, we and M&R MWE Liberty L.L.C. (the "Selling Unitholder") entered into an Equity Distribution Agreement with the Manager that established an At the Market offering

program (the "September 2013 ATM") pursuant to which we could have sold from time to time through the Manager as our sales agent, common units representing limited partner interests having an aggregate offering price of up to $1.0 billion. In addition, the Selling Unitholder was permitted to sell from time to time through the Manager up to 794,761 common units. During the year ended December 31, 2014, we incurred approximately $4 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general Partnership purposes. During the year ended December 31, 2014, the Selling Unitholder sold an aggregate of 222,897 of its common units under the September 2013 ATM, receiving net proceeds of approximately $14.3 million after deducting approximately $0.1 million in manager fees. We completed the September 2013 ATM on March 31, 2014.

(7): In March 2014, we and the Selling Unitholder entered into an Equity Distribution Agreement with financial institutions (the "March 2014 Managers") that established an At the Market offering program (the "March 2014 ATM") pursuant to which we could sell from time to time through the March 2014 Managers, as our sales agents, common units having an aggregate offering price of up to $1.2 billion. In addition, the Selling Unitholder was permitted to sell from time to time through the March 2014 Managers up to 4,031,075 common units (including 3,990,878 common units that were issued on July 1, 2014). During the year ended December 31, 2014, we incurred approximately $5 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general Partnership purposes. We completed the March 2014 ATM in October 2014.
(8): In November 2014, we and the Selling Unitholder entered into an Equity Distribution Agreement with financial institutions (the "November 2014 Managers") that established an At the Market offering program (the "November 2014 ATM") pursuant to which we may sell from time to time through the November 2014 Managers, as our sales agents, common units having an aggregate offering price of up to $1.5 billion. In addition, the Selling Unitholder may sell from time to time through the November 2014 Managers up to 3,990,878 common units. During the year ended December 31, 2014, we incurred approximately $1.1 million in manager fees and other third-party expenses. The proceeds from sales were used to fund capital expenditures and for general Partnership purposes.

Approximately 4.0 million Class B units converted to common units on July 1, 2014. 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 next two anniversaries of such date. Class B units share in our income and losses and are not entitled to participate in any distributions of available cash prior to their conversion.

Pursuant to the Amended Utica LLC Agreement, EMG Utica was obligated to fund the first $950.0 million of capital required by MarkWest Utica EMG and they completed this funding commitment in May 2013. We began funding MarkWest Utica EMG in July 2013 and have contributed approximately $1,188.6 million as of December 31, 2014. We were required to contribute 100% of the additional capital required by MarkWest Utica EMG until the aggregate contributions from us and EMG Utica equal $2.0 billion, which occurred in November 2014. For further discussion of the funding requirements after $2.0 billion has been contributed to MarkWest Utica EMG, see Note 3 of the Notes to the Consolidated Financial Statements included in Item 8 of our Annual Report on Form 10-K.

In December 2013, we and EMG Utica Condensate formed MarkWest Utica EMG Condensate. As of December 31, 2014, we contributed $35.4 million and EMG Utica Condensate contributed a net

amount of $29 million to MarkWest Utica EMG Condensate. See Note 3 of the Notes to the Consolidated Financial Statements included in Item 8 of our Annual Report on Form 10-K for further discussion of the funding obligations for MarkWest Utica EMG Condensate.

We have partial ownership interests in a number of joint venture legal entities, 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 ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions depends upon our future operating performance. That, in turn, may be affected by prevailing economic conditions in our industry, as well as financial, business and other factors, some of which are beyond our control.

Due to our significant growth strategy and the length of the construction period for our assets, we spend a significant amount of capital prior to the realization of the revenues from our expansion projects. Many factors could impact our ability to generate the expected revenues and the timing of those revenues from our expansion projects including:

If we are unable to generate the expected revenues from our expansion projects, our liquidity would be adversely impacted, which may also impact our ability to meet our financial and other covenants under our Credit Facility and indentures governing our Senior Notes.

Net cash provided by operating activities increased primarily due to a $229.2 million increase in segment operating income before items not allocated to segments as a result of our expanded operations in most segments.

Net cash used in investing activities decreased primarily due to $341.1 million in proceeds related to the exercise of the Ohio Gathering Option by Summit, a decrease in capital expenditures of $677.2 million due partially to the deconsolidation of Ohio Gathering and $225.2 million from the 2013 Buffalo Creek Acquisition, partially offset by proceeds of approximately $208.7 million, net of cash paid for third-party transaction fees primarily from the Sherwood gathering asset sale in 2013, a $246.5 million increase in cash contributions to our equity method investments in 2014 and a release of $15.5 million of restricted cash in 2013.

Net cash provided by financing activities decreased primarily due to a $669.8 million decrease in contributions from non-controlling interest holders as EMG Utica completed its initial funding of MarkWest Utica EMG in May 2013, a $136.5 million increase in distributions to unitholders due to an increase in units primarily due to the conversion of 4 million Class B units to common units in July 2014 and July 2013, the issuance of new units as well as higher distribution amounts paid, and a $60.0 million decrease in proceeds from public equity offerings, partially offset by a $130.2 million increase in net borrowings.

A summary of our total contractual cash obligations as of December 31, 2014, is as follows (in thousands):

	Payment Due by Period

Type of obligation	Total Obligation		Due in 2015		Due in 2016 - 2017		Due in 2018 - 2019		Thereafter
Long-term debt	$	3,627,600	$	—	$	—	$	97,600	$	3,530,000
Interest payments on long-term debt(1)		1,528,475		198,330		396,659		392,999		540,487
Operating leases and long-term storage agreement(2)		248,840		32,374		63,367		52,372		100,727
Purchase obligations(3)		643,895		529,383		113,133		1,207		172
Natural gas purchase obligations(4)		136,132		14,641		32,608		34,660		54,223
SMR Liability(5)		264,853		17,412		34,824		34,824		177,793
Transportation and terminalling(6)		637,511		31,429		142,793		119,418		343,871
Other long-term liabilities reflected on the Consolidated Balance Sheets:
Asset retirement obligation(7)		11,966		—		—		—		11,966

Total contractual cash obligations	$	7,099,272	$	823,569	$	783,384	$	733,080	$	4,759,239

(2): Amounts relate primarily to a long-term propane storage agreement and our office and vehicle leases.
(3): Represents purchase orders and contracts related to purchase or build out of property, plant and equipment. Purchase obligations exclude current and long-term unrealized losses on derivative instruments included on the accompanying Consolidated Balance Sheets, which represent the current fair value of various derivative contracts and do not represent future cash purchase obligations. These contracts are generally settled financially at the difference between the future market price and the contractual price and may result in cash payments or cash receipts in the future, but generally do not require delivery of physical quantities of the underlying commodity.
(4): Natural gas purchase obligations consist primarily of a purchase agreement with a producer in the Northeast segment. The contract provides for the purchase of keep-whole volumes at a specific price and is a component of a broader regional arrangement. The contract price is designed to share a portion of the frac spread with the producer and as a result, the amounts reflected for the obligation exceed the cost of purchasing the keep-whole volumes at a market price. The contract is considered an embedded derivative (see Note 8 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for the fair value of the frac spread sharing component). We use the estimated future frac spreads as of December 31, 2014 for calculating this obligation.
(5): Represents amounts due under a product supply agreement (see Note 19 of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K for further discussion of the product supply agreement).
(6): Represents transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which will range from three to ten years. We expect to pass any minimum payment commitments through to producer customers. Minimum fees due under transportation agreements do not include potential future fee increases as required by FERC.
(7): Excludes estimated accretion expense of $16.6 million. The total amount to be paid is approximately $28.5 million.

Inflation did not have a material impact on our results of operations for the years ended December 31, 2014, 2013 or 2012. Although the impact of inflation has been insignificant in recent years, it is still a factor in the United States economy and may increase the cost to acquire, build or replace property, plant and equipment. It may also increase the costs of labor and supplies. To the extent permitted by competition, regulation and our existing agreements, we have and expect to continue to pass along all or a portion of increased costs to our customers in the form of higher fees.

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

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions

Intangible Assets
Intangible assets are comprised of customer contracts and relationships acquired in business combinations, recorded under the acquisition method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets.	The fair value of customer contracts is generally calculated using an income approach based on discounted future cash flows. The key assumptions include contract renewals, historical volumes, current and future capacity of the gathering system or processing plants, pricing volatility and the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. We consider alternative methods of amortization when the intangibles assets are initially recorded, however we have previously determined that alternative amortization methods do not create material differences in amortization expense each year and, therefore, concluded straight-line methodology to be appropriate. The estimated economic life is determined by assessing the life of the assets to which the contracts and relationships relate, likelihood of renewals, the projected reserves, competitive factors, regulatory or legal provisions and maintenance and renewal costs.	If the actual results differ significantly from the assumptions used to determine the fair value and economic lives of intangible assets, the carrying value of the intangible asset may be over/understated resulting in an over/understatement of amortization expense as the over/understatement of the intangible assets would create an under/overstatement of other assets (i.e. goodwill).

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions

Impairment of Long-Lived Assets
Management evaluates our long-lived assets, including intangibles, for impairment when certain events have taken place that indicate that the carrying value may not be recoverable from the expected undiscounted future cash flows. Qualitative and quantitative information is reviewed in order to determine if a triggering event has occurred or an impairment indicator exists. If we determine that a triggering event has occurred we would complete a full impairment analysis. If we determine that the carrying value of an asset group is not recoverable, a loss is recorded for the difference between the fair value and the carrying value. We evaluate our property, plant and equipment and intangibles on at least a segment level and at lower levels where cash flows for specific assets can be identified.	Management considers the volume of reserves dedicated to be processed by the asset and future NGL product and natural gas prices to estimate cash flows for each asset group. The amount of additional reserves developed by future drilling activity depends, in part, on expected commodity prices. Projections of reserves, drilling activity, ability to renew contracts of significant customers, and future commodity prices are inherently subjective and contingent upon a number of variable factors, many of which are difficult to forecast. Management considered the recent reductions in commodity prices in forecasted cash flows.	As of December 31, 2014, there were qualitative indicators of impairment related to our Appalachia asset group. A full impairment analysis was completed, which demonstrated the carrying value of the asset group was recoverable as of December 31, 2014. A decrease in the estimated future cash flows of 52% would indicate that the net book value may not be fully recoverable. As of December 31, 2014, there were no indicators of impairment for any of our other asset groups. A significant variance in any of the assumptions or factors used to estimate future cash flows could result in the impairment of an asset. For certain asset groups that comprise approximately 7% of total long-lived assets, a decrease in the estimated future cash flows used in our impairment analysis of 10% would indicate that the net book value of the asset groups may not be fully recoverable and further evaluation would be required to estimate a potential impairment.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions

Impairment of Goodwill
Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. We evaluate goodwill for impairment annually as of November 30 and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The first step of the evaluation is a qualitative analysis to determine if it is "more likely than not" that the carrying value of a reporting unit with goodwill exceeds its fair value. The additional quantitative steps in the goodwill impairment test may be performed if we determine that it is more likely than not that the carrying value is greater than the fair value.	Management performed a quantitative analysis and determined the fair value of our reporting units using the income and market approaches for our 2014 impairment analysis. A hypothetical purchase price allocation to determine the goodwill impairment charge in the Appalachia Reporting Unit was also performed utilizing these approaches. These types of analyses require us to make assumptions and estimates regarding industry and economic factors such as relevant commodity prices, contract renewals, and production volumes. It is our policy to conduct impairment testing based on our current business strategy in light of present industry and economic conditions, as well as future expectations. For the current year qualitative analysis, we analyzed the changes in the assumptions above in light of current economic conditions to determine if it was more likely than not that impairment exists. We looked at factors, including changes in the forecasted operating income and volumes for the three reporting units with goodwill, changes in the commodity price environment, changes in our per unit market value, changes in the our peers' market value and changes in industry EBITDA multiples. Management is also required to make certain assumptions when identifying the reporting units and determining the amount of goodwill allocated to each reporting unit. The method of allocating goodwill resulting from the acquisitions involved estimating the fair value of the reporting units and allocating the purchase price for each acquisition to each reporting unit. Goodwill is then calculated for each reporting unit as the excess of the allocated purchase price over the estimated fair value of the net assets.	As a result of the goodwill impairment testing, we recorded a full impairment charge related to the Appalachia Reporting Unit it in our Northeast segment. The impairment charge was $62.4 million as of December 31, 2014. The decline in commodity prices and the uncertainty related to extension of certain material processing facility operating contracts caused the decline in forecasted cash flows triggering impairment. We recorded no impairment expense related to our other reporting units. The fair value of our other reporting units with goodwill would have to decline by more than 28% to 60% for there to be a potential indicator of impairment.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions

Impairment of Equity Investments
We evaluate our equity method investments in Centrahoma, Ohio Gathering, MarkWest Pioneer and MarkWest Utica EMG Condensate, including its subsidiary Ohio Condensate, for impairment whenever events or changes in circumstances indicate, in management's judgment, that the carrying value of such investment may have experienced a decline in value. When evidence of an other-than-temporary loss in value has occurred, we compare the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment should be recorded.	Our impairment assessment requires us to apply judgment in estimating future cash flows received from or attributable to our equity method investments. The primary estimates may include the expected volumes, the terms of related customer agreements and future commodity prices. We determined that there were no material events or changes in circumstances that would indicate an other-than-temporary loss in value has occurred for Centrahoma, Ohio Gathering, MarkWest Pioneer or MarkWest Utica EMG Condensate.	Based on the current forecasts, our ownership in Centrahoma, Ohio Gathering, MarkWest Pioneer and MarkWest Utica EMG Condensate will generate cash flows with a present value in excess of the current carrying value of the respective investments. Management determined that there were no material events or changes in circumstances that would indicate an other-than-temporary decline in value of our investment in Centrahoma, Ohio Gathering, MarkWest Pioneer or MarkWest Utica EMG Condensate.
Accounting for Risk Management Activities and Derivative Financial Instruments
Our derivative financial instruments are recorded at fair value in the accompanying Consolidated Balance Sheets. Changes in fair value and settlements are reflected in our earnings in the accompanying Consolidated Statements of Operations as gains and losses related to revenue, purchased product costs, facility expenses and/or miscellaneous income.	When available, quoted market prices or prices obtained through external sources are used to determine a financial instrument's fair value. The valuation of Level 2 financial instruments is based on quoted market prices for similar assets and liabilities in active markets and other inputs that are observable. However, for other financial instruments for which quoted market prices are not available, the fair value is based on inputs that are largely unobservable such as option volatilities and NGL prices that are interpolated and extrapolated due to inactive markets. These instruments are classified as Level 3 under the fair value hierarchy. All fair value measurements are appropriately adjusted for nonperformance risk.	If the assumptions used in the pricing models for our Level 2 and 3 financial instruments are inaccurate or if we had used an alternative valuation methodology, the estimated fair value may have been different and we may be exposed to unrealized losses or gains that could be material. A 10% difference in our estimated fair value of Level 2 and 3 derivatives at December 31, 2014 would have affected net income before provision for income tax by approximately $3.7 million for the year ended December 31, 2014.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions

Accounting for Significant Embedded Derivative Instruments
Identifying, valuing and determining the inception date of embedded derivatives is complex and requires significant judgment. We have a Gas Purchase Agreement with a producer customer in which we are required to purchase natural gas based on a complex formula designed to share some of the frac spread with the producer, through December 31, 2022. This contract has been identified as an embedded derivative ("Natural Gas Embedded Derivative") and requires a complex valuation based on significant judgment. The agreement has a primary term that expires on December 31, 2022 and contains two successive term-extending options under which the producer can extend the purchase agreement an additional five years. Such options are part of the embedded feature and thus are required to be considered in the valuation of the embedded derivative. We are required to make a significant judgment about the probability that the options would be exercised when determining the value of the extension options.	We carry the Natural Gas Embedded Derivative at fair value with changes in fair value recognized in income each period. The valuation requires significant judgment when forming the assumptions used. Third-party forward curves for certain commodity prices utilized in the valuation do not extend through the term of the arrangement. Thus, pricing is required to be extrapolated for those periods. We utilize multiple cash flow techniques to extrapolate NGL pricing. Due to the illiquidity of future markets, we do not believe one method is more indicative of fair value than the other methods. The fair value is also appropriately adjusted for nonperformance risk each period. We evaluated various factors in order to determine the probability that the term-extending options would be exercised by the producer customer such as estimates of future gas reserves in the region, the competitive environment in which the contract operates, the commodity price environment and the producer's business strategy. We have asserted that the probability that the producer will exercise their option to extend the agreement is 0% as of December 31, 2014 based on the high degree of uncertainty.	The Natural Gas Embedded Derivative is an instrument that is not exchange-traded. The valuation of the instrument is complex and requires significant judgment. The inputs used in the valuation model require specialized knowledge, as NGL price curves do not exist for the entire term of the arrangement. The valuation is sensitive to NGL and natural gas future price curves. Holding the natural gas curves constant, a 10% increase (decrease) in NGL price curves causes a 43% increase (decrease) in the asset as of December 31, 2014. Holding the NGL curves constant, a 10% increase (decrease) in the natural gas curves causes a 21% (decrease) increase in the asset as of December 31, 2014. The determination of the fair value of the option to extend is based on our judgment about the probability of the producer exercising the extension. If it were determined that the probability of exercise was not 0% as of December 31, 2014, the liability would be understated or the asset would be overstated.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions

Variable Interest Entities
We evaluate all legal entities in which we hold an ownership or other pecuniary interest to determine if the entity is a VIE. Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership or other pecuniary interests in an entity that change with changes in the fair value of the VIE's assets. When we conclude that we hold an interest in a VIE we must determine if we are the entity's primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE. This controlling financial interest is evidenced by both (a) the power to direct the activities of the VIE that most significantly impact the VIE's economic performance and (b) the obligation to absorb losses that could potentially be significant to the VIE or the right to receive benefits that could potentially be significant to the VIE. We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any interests in a VIE that is not consolidated.	Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use primarily qualitative analysis to determine if an entity is a VIE. We evaluate the entity's need for continuing financial support; the equity holder's lack of a controlling financial interest; and/or if an equity holder's voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use primarily qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE. We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions.	MarkWest Utica EMG is a VIE and we are considered to be the primary beneficiary. Ohio Gathering is also a VIE; however, we are not considered to be the primary beneficiary. As a result, Ohio Gathering is accounted for under the equity method. Changes in the design or nature of the activities of either of these entities, or our involvement with an entity, may require us to reconsider our conclusions on the entity's status as a VIE and/or our status as the primary beneficiary. Such reconsideration requires significant judgment and understanding of the organization. This could result in the deconsolidation or consolidation of the affected subsidiary. The deconsolidation or consolidation of a subsidiary would have a significant impact on our financial statements. We account for our ownership interest in MarkWest Utica EMG Condensate, along with its subsidiary Ohio Condensate, Centrahoma and MarkWest Pioneer under the equity method and have determined that these entities are not VIEs. However, changes in the design or nature of the activities of the entity may require us to reconsider our conclusions. Such reconsideration would require the identification of the variable interests in the entity and a determination on which party is the entity's primary beneficiary. If an equity investment were considered a VIE and we were determined to be the primary beneficiary, the change could cause us to consolidate the entity. The consolidation of an entity that is currently accounted for under the equity method could have a significant impact on our financial statements.

Description	Judgments and Uncertainties	Effect if Actual Results Differ from Estimates and Assumptions

Acquisitions—Purchase Price Allocation
We allocate the purchase price of an acquired business to its identifiable assets and liabilities based on estimated fair values. The excess of the purchase price over the amount allocated to the assets and liabilities is recorded as goodwill. For significant acquisitions, we engage outside appraisal firms to assist in the fair value determination of identifiable intangible assets such as customer relationships, trade names and any other significant assets or liabilities. We adjust the preliminary purchase price allocation, as necessary, after the acquisition closing date through the end of the measurement period of up to one year as we finalize valuations for the assets acquired and liabilities assumed.	Purchase price allocation methodology requires management to make assumptions and apply judgment to estimate the fair value of acquired assets and liabilities. Management estimates the fair value of assets and liabilities primarily using a market approach, income approach or cost approach, as appropriate. Key inputs into the fair value determinations include estimates and assumptions related to future volumes, commodity prices, operating costs, replacement costs and construction costs, as well as an estimate of the expected term and profits of the related customer contract or contracts.	If estimates or assumptions used to complete the purchase price allocation and estimate the fair value of acquired assets and liabilities significantly differed from assumptions made, the allocation of purchase price between goodwill, intangibles and property plant and equipment could significantly differ. Such a difference would impact future earnings through depreciation and amortization expense. In addition, if forecasts supporting the valuation of the intangibles or goodwill are not achieved, impairments could arise.
Income Taxes
Under the asset and liability method of income tax accounting, deferred tax assets and liabilities are determined based on differences between the financial reporting and the tax basis of assets and liabilities and are measured using the tax rates and laws that are expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. A deferred tax asset must be reduced by a valuation allowance if it is more likely than not that some portion or all of the deferred tax asset will not be realized prior to expiration.	We have deferred tax assets related to NOL carryforwards. Management's assessment of our ability to utilize the NOL carryforwards depends upon our estimates of future taxable income. There are many risks and other factors that could cause our actual future taxable income to be significantly different that our estimates. These factors include but are not limited to, changes in production volumes of natural gas by our producer customers, our ability to retain customers, changes in laws or regulations impacting our operations, changes in commodity prices, etc.	As of December 31, 2014, we had NOL carryforwards for federal and state income tax purposes of approximately $47.8 million and $2.9 million, respectively. We believe that we will be able to fully utilize these NOL carryforwards and therefore have not recorded a valuation allowance. If for any reason our future taxable income is less than we have estimated, we may not realize the full benefit of these NOL carryforwards.

From time to time, new accounting pronouncements are issued by FASB that we adopt as of the specified effective date. If not discussed in Note 2—Recent Accounting Pronouncements of the accompanying Notes to Consolidated Financial Statements included in Item 8 of this Form 10-K, management believes that the impact of recently issued standards, which are not yet effective, will not have a material impact on our financial statements upon adoption.

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

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

To mitigate our cash flow exposure to fluctuations in the price of NGLs, we have entered into derivative financial instruments relating to the future price of NGLs and crude oil. We currently manage the majority of our NGL price risk using direct product NGL derivative contracts. We enter into NGL derivative contracts when adequate market liquidity exists and future prices are satisfactory. A small portion of our NGL price exposure is managed by using crude oil contracts. Based on our current volume forecasts, over 95% of our derivative positions used to manage our future commodity price exposure are direct product NGL derivative contracts.

To mitigate our cash flow exposure to fluctuations in the price of natural gas, we primarily utilize derivative financial instruments relating to the future price of natural gas and take into account the partial offset of our long and short natural gas positions resulting from normal operating activities. We have no such positions outstanding as of December 31, 2014.

As a result of our current derivative positions, we believe that we have mitigated a portion of our expected commodity price risk through the fourth quarter of 2015. We would be exposed to additional commodity risk in certain situations such as if producers under-deliver or over-deliver products or if processing facilities are operated in different recovery modes. In the event that we have derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

All of our financial derivative positions are with financial institutions that are participating members of the Credit Facility ("participating bank group members"). Management conducts a standard credit review on counterparties to derivative contracts. There are no collateral requirements for derivative contracts among us and any participating bank group members. Specifically, we are not required to post collateral when we enter into derivative contracts with participating bank group members as the participating bank group members have a collateral position in substantially all our of wholly-owned assets other than MarkWest Liberty Midstream and its subsidiaries. A separate agreement with certain participating bank group members allows MarkWest Liberty Midstream to enter

into derivative positions without posting cash collateral. We use standardized agreements that allow for offset of certain positive and negative exposures in the event of default or other terminating events, including bankruptcy.

The following tables provide information on the volume of our derivative activity for positions related to long liquids and keep-whole price risk at December 31, 2014, including the weighted-average prices ("WAVG"):

The following table provides information on the volume of MarkWest Liberty Midstream's commodity derivative activity positions related to long liquids price risk at December 31, 2014, including the WAVG:

The following table provides information on the derivative positions related to long liquids and keep-whole price risk as of February 18, 2015 that we have entered into subsequent to December 31, 2014, including the WAVG:

The following tables provide information on the derivative positions of MarkWest Liberty Midstream related to long liquids price risk as of February 18, 2015 that we have entered into subsequent to December 31, 2014, including the WAVG:

We have a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative gain related to purchased product costs. In February 2011, we executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022. The recorded asset excludes the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and, therefore, not recorded as a derivative liability. See the following table for a reconciliation of the asset recorded for the embedded derivative as of December 31, 2014 (in thousands):

Our primary interest rate risk exposure results from our Credit Facility which has a borrowing capacity of $1.3 billion. The applicable interest rate for our Credit Facility was 4.5% at December 31, 2014. As of February 18, 2015, we had $343.3 million borrowings outstanding on our Credit Facility. The debt related to this agreement bears interest at variable rates that are tied to either the U.S. prime rate or LIBOR at the time of borrowing.

We may make use of interest rate swap agreements in the future to adjust the ratio of fixed and floating rates in our debt portfolio, however we had no interest rate swaps outstanding as of December 31, 2014. Our debt portfolio as of December 31, 2014 is shown in the following table.

Based on our overall interest rate exposure at December 31, 2014, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our Credit Facility would change pre-tax earnings by approximately $1.0 million over a twelve-month period. Based on our overall interest rate exposure at February 18, 2015, a hypothetical increase or decrease of one percentage point in interest rates applied to borrowings under our Credit Facility would change pre-tax earnings by approximately $3.4 million over a twelve-month period.

We are subject to risk of loss resulting from nonpayment by our customers to whom we provide midstream services or sell natural gas or NGLs. We believe that certain contracts would allow us to pass those losses through to our producer customers, thus reducing our risk, when we are selling NGLs and acting as our producer customers' agent. Our credit exposure related to these customers is represented by the value of our trade receivables. Where exposed to credit risk, we analyze the customer's financial condition prior to entering into a transaction or agreement, establish credit terms and monitor the appropriateness of these terms on an ongoing basis. In the event of a customer default, we may sustain a loss and our cash receipts could be negatively impacted.

We are subject to risk of loss resulting from nonpayment or nonperformance by the counterparties to our derivative contracts. Our credit exposure related to commodity derivative instruments is represented by the fair value of contracts with a net positive fair value at the reporting date. These outstanding instruments expose us to credit loss in the event of nonperformance by the counterparties to the agreements. Should the creditworthiness of one or more of our counterparties decline, our ability to mitigate nonperformance risk is limited to a counterparty agreeing to either a voluntary termination and subsequent cash settlement or a novation of the derivative contract to a third party. In the event of a counterparty default, we may sustain a loss and our cash receipts could be negatively impacted. This counterparty credit risk does not apply to our embedded derivative as the overall value is a liability.

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

We have audited the accompanying consolidated balance sheets of MarkWest Energy Partners, L.P. and subsidiaries (the "Partnership") as of December 31, 2014 and 2013, and the related consolidated statements of operations, changes in equity, and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of MarkWest Energy Partners, L.P. and subsidiaries as of December 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2014, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 2015 expressed an unqualified opinion on the Partnership's internal control over financial reporting.

	December 31, 2014			December 31, 2013

ASSETS
Current assets:
Cash and cash equivalents ($73,300 and $4,114, respectively)	$	108,887		$	85,305
Restricted cash		20,000			10,000
Receivables, net ($22,722 and $5,346, respectively)		302,259			281,744
Receivables from unconsolidated affiliates, net ($30 and $0, respectively)		7,097			17,363
Inventories ($2,434 and $2,553, respectively)		31,749			41,363
Fair value of derivative instruments		20,921			11,457
Deferred income taxes		9			23,200
Other current assets ($9,511 and $5,527, respectively)		46,731			44,068

Total current assets		537,653			514,500

Property, plant and equipment ($1,411,797 and $1,655,789, respectively)		9,923,524			8,583,767
Less: accumulated depreciation ($56,987 and $33,583, respectively)		(1,270,624	)		(890,598	)

Total property, plant and equipment, net		8,652,900			7,693,169

Other long-term assets:
Restricted cash		—			10,000
Investment in unconsolidated affiliates ($696,784 and $0, respectively)		805,633			75,627
Intangibles, net of accumulated amortization of $350,327 and $285,732, respectively		809,277			874,792
Goodwill		82,411			144,856
Deferred financing costs, net of accumulated amortization of $31,298 and $25,083, respectively		52,919			52,132
Deferred contract cost ($0 and $6,591, respectively), net of accumulated amortization of $3,198 and $2,886 ($0), respectively		20,052			26,955
Fair value of derivative instruments		16,507			505
Other long-term assets ($664 and $658, respectively)		3,426			3,887

Total assets	$	10,980,778		$	9,396,423



LIABILITIES AND EQUITY
Current liabilities:
Accounts payable ($28,021 and $82,007, respectively)		270,997		$	401,088
Accrued liabilities ($48,793 and $112,029, respectively)		360,006			437,847
Deferred income taxes		239			—
Fair value of derivative instruments		—			28,838
Payables to unconsolidated affiliates, net ($5,500 and $0, respectively)		8,621			—

Total current liabilities		639,863			867,773

Deferred income taxes		357,260			287,566
Fair value of derivative instruments		—			27,763
Long-term debt, net of discounts of $6,196 and $6,929, respectively		3,621,404			3,023,071
Other long-term liabilities		169,012			156,500
Commitments and contingencies (see Note 19)
Redeemable non-controlling interest (see Note 3)		—			235,617
Equity:
Common units (186,553 and 157,766 common units issued and outstanding, respectively)		4,758,243			3,476,295
Class B units (11,973 and 15,964 Class B units issued and outstanding, respectively)		451,519			602,025
Non-controlling interest in consolidated subsidiaries		983,477			719,813

Total equity		6,193,239			4,798,133

Total liabilities and equity	$	10,980,778		$	9,396,423

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

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit amounts)

	Year ended December 31,

	2014			2013			2012
Revenue:
Product sales	$	1,198,642		$	1,093,711		$	1,002,224
Service revenue		937,380			593,374			381,055
Derivative gain (loss)		40,151			(24,638	)		56,535

Total revenue		2,176,173			1,662,447			1,439,814

Operating expenses:
Purchased product costs		832,428			691,165			530,328
Derivative gain related to purchased product costs		(58,392	)		(1,737	)		(13,962	)
Facility expenses		343,362			291,069			206,861
Derivative loss related to facility expenses		3,277			2,869			1,371
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

Total operating expenses		1,798,953			1,416,504			1,061,538

Income from operations		377,220			245,943			378,276
Other income (expense):
(Loss) earnings from unconsolidated affiliates		(4,477	)		1,422			2,328
Interest expense		(166,372	)		(151,851	)		(120,191	)
Amortization of deferred financing costs and discount (a component of interest expense)		(7,289	)		(6,726	)		(5,601	)
Loss on redemption of debt		—			(38,455	)		—
Miscellaneous income, net		3,440			2,781			481

Income before provision for income tax		202,522			53,114			255,293
Provision for income tax expense (benefit):
Current		618			(11,208	)		(2,366	)
Deferred		41,601			23,877			40,694

Total provision for income tax		42,219			12,669			38,328

Net income		160,303			40,445			216,965
Net (income) loss attributable to non-controlling interest		(26,422	)		(2,368	)		3,437

Net income attributable to the Partnership's unitholders	$	133,881		$	38,077		$	220,402



Net income attributable to the Partnership's common unitholders per common unit (Note 24):
Basic	$	0.77		$	0.26		$	1.98



Diluted	$	0.72		$	0.24		$	1.69



Weighted average number of outstanding common units:
Basic		171,009			138,409			109,979



Diluted		185,650			160,443			130,648

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY

(in thousands)

																		Redeemable Non- Controlling Interest (Temporary Equity)

	Common Units					Class B Units
	Common Units					Class B Units						Non- controlling Interest
	Units		Amount			Units			Amount			Non- controlling Interest			Total
December 31, 2011		94,940	$	642,522			19,954		$	752,531		$	189		$	1,395,242		$	—
Issuance of units in public offering, net of offering costs		32,308		1,634,081			—			—			—			1,634,081			—
Distributions paid		—		(339,967	)		—			—			(71	)		(340,038	)		—
Contributions from non-controlling interest		—		—			—			—			264,782			264,782			—
Share-based compensation activity		246		6,548			—			—			—			6,548			—
Excess tax benefits related to share-based compensation		—		907			—			—			—			907			—
Deferred income tax impact from changes in equity		—		(67,089	)		—			—			—			(67,089	)		—
Net income (loss)		—		220,402			—			—			(3,437	)		216,965			—

December 31, 2012		127,494		2,097,404			19,954			752,531			261,463			3,111,398			—
Issuance of units in public offering, net of offering costs		26,115		1,698,066			—			—			—			1,698,066			—
Conversion of Class B units to common units		3,990		150,506			(3,990	)		(150,506	)		—			—			—
Distributions paid		—		(462,488	)		—			—			(211	)		(462,699	)		—
Contributions from non-controlling interest		—		—			—			—			685,219			685,219			—
Redeemable non-controlling interest classified as temporary equity		—		—			—			—			(235,617	)		(235,617	)		235,617
Share-based compensation activity		167		11,072			—			—			—			11,072			—
Other		—		—			—			—			6,591			6,591			—
Deferred income tax impact from changes in equity		—		(56,342	)		—			—			—			(56,342	)		—
Net income		—		38,077			—			—			2,368			40,445			—

December 31, 2013		157,766		3,476,295			15,964			602,025			719,813			4,798,133			235,617
Issuance of units in public offerings, net of offering costs		24,585		1,638,090			—			—			—			1,638,090			—
Conversion of Class B units to common units		3,991		150,506			(3,991	)		(150,506	)		—			—			—
Distributions paid		—		(599,020	)		—			—			(7,183	)		(606,203	)		—
Contributions from non-controlling interest		—		—			—			—			15,400			15,400			—
Redeemable non-controlling interest classified as temporary equity		—		—			—			—			235,617			235,617			(235,617	)
Elimination of non-controlling interest from deconsolidation of subsidiary		—		—			—			—			(6,592	)		(6,592	)		—
Share-based compensation activity		211		10,014			—			—			—			10,014			—
Deferred income tax impact from changes in equity		—		(51,523	)		—			—			—			(51,523	)		—
Net income		—		133,881			—			—			26,422			160,303			—

December 31, 2014		186,553	$	4,758,243			11,973		$	451,519		$	983,477		$	6,193,239		$	—

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

MARKWEST ENERGY PARTNERS, L.P.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year ended December 31,

	2014			2013			2012
Cash flows from operating activities:
Net income	$	160,303		$	40,445		$	216,965
Adjustments to reconcile net income to net cash provided by operating activities (net of acquisitions):
Depreciation		422,755			299,884			183,250
Amortization of intangible assets		64,893			64,644			53,320
Impairment of goodwill		62,445			—			—
Loss on redemption of debt		—			38,455			—
Amortization of deferred financing costs and discount		7,289			6,726			5,601
Accretion of asset retirement obligations		570			824			672
Amortization of deferred contract cost		1,181			312			312
Phantom unit compensation expense		18,961			16,282			14,615
Equity in loss (earnings) of unconsolidated affiliates		4,477			(1,422	)		(2,328	)
Distributions from unconsolidated affiliates		12,459			6,370			8,416
Unrealized (gain) loss on derivative instruments		(82,067	)		15,602			(102,127	)
Gain (loss) on disposal of property, plant and equipment		1,116			(33,763	)		6,254
Deferred income taxes		41,601			23,877			40,694
Changes in operating assets and liabilities, net of working capital acquired and deconsolidation:
Receivables		(43,629	)		(68,564	)		31,993
Receivables from unconsolidated affiliates		10,531			(17,363	)		—
Inventories		9,551			(16,730	)		16,580
Other current assets		(4,597	)		(9,197	)		(23,285	)
Accounts payable and accrued liabilities		(41,946	)		68,070			28,417
Payables to unconsolidated affiliates		8,621			—			—
Other long-term assets		343			(21,747	)		(647	)
Other long-term liabilities		13,542			22,945			13,311

Net cash provided by operating activities		668,399			435,650			492,013

Cash flows from investing activities:
Restricted cash		—			15,500			(9,497	)
Capital expenditures		(2,369,715	)		(3,046,956	)		(1,950,324	)
Acquisition of business, net of cash acquired		—			(222,888	)		(506,797	)
Investment in unconsolidated affiliates		(264,005	)		(17,521	)		(6,066	)
Proceeds from sale of equity interest in unconsolidated affiliate		341,137			—			—
Proceeds from disposal of property, plant and equipment		22,487			209,303			596

Net cash flows used in investing activities		(2,270,096	)		(3,062,562	)		(2,472,088	)

Cash flows from financing activities:
Proceeds from public equity offerings, net		1,638,090			1,698,066			1,634,081
Proceeds from Credit facility		3,151,500			—			511,100
Payments of Credit facility		(3,053,900	)		—			(577,100	)
Proceeds from long-term debt		500,000			1,000,000			742,613
Payments of long-term debt		—			(501,112	)		—
Payments of premiums on redemption of long-term debt		—			(31,516	)		—
Payments for debt issuance costs, deferred financing costs and registration costs		(8,201	)		(14,046	)		(14,720	)
Contributions from non-controlling interest		15,400			685,219			264,781
Payments of SMR Liability		(2,460	)		(2,241	)		(2,058	)
Cash paid for taxes related to net settlement of share-based payment awards		(8,947	)		(5,210	)		(8,067	)
Excess tax benefits related to share-based compensation		—			—			907
Payment of distributions to common unitholders		(599,020	)		(462,488	)		(339,967	)
Payment of distributions to non-controlling interest		(7,183	)		(211	)		(71	)

Net cash flows provided by financing activities		1,625,279			2,366,461			2,211,499

Net increase (decrease) in cash and cash equivalents		23,582			(260,451	)		231,424
Cash and cash equivalents at beginning of year		85,305			345,756			114,332

Cash and cash equivalents at end of year	$	108,887		$	85,305		$	345,756

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

MarkWest Energy Partners, L.P. ("MarkWest Energy Partners") was formed in January 2002 as a Delaware limited partnership. MarkWest Energy Partners and its subsidiaries (collectively, the "Partnership") are engaged in the gathering, processing and transportation of natural gas; the gathering, transportation, fractionation, storage and marketing of NGLs and the gathering and transportation of crude oil. The Partnership has 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 formations. The Partnership's principal executive office is located in Denver, Colorado.

The Partnership's consolidated financial statements include all majority-owned or controlled subsidiaries. In addition, MarkWest Utica EMG and its subsidiaries, a VIE for which the Partnership has been determined to be the primary beneficiary, is included in the consolidated financial statements (see Note 3). For non-wholly-owned consolidated subsidiaries, the interests owned by third parties have been recorded as Non-controlling interest in consolidated subsidiaries in the accompanying Consolidated Balance Sheets. Intercompany investments, accounts and transactions have been eliminated. The Partnership's investment in MarkWest Pioneer and Centrahoma, in which the Partnership exercises significant influence but does not control and does not have a controlling financial interest, are accounted for using the equity method. The Partnership's investment in Ohio Gathering and Utica Condensate are VIEs, in which the Partnership exercises significant influence but does not control and is not the primary beneficiary, are accounted for using the equity method. The accompanying consolidated financial statements of the Partnership have been prepared in accordance with GAAP.

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

The Partnership considers investments in highly liquid financial instruments purchased with a remaining maturity of 90 days or less at the date of acquisition to be cash equivalents. Such investments include money market accounts.

Restricted cash consists primarily of cash and investments that must be maintained as collateral for letters of credit issued to certain third party producer customers. The balances will be outstanding until certain capital projects are completed and the third party releases the restriction. Restricted cash balances for which the restrictions are not expected to be released within a period of twelve months are classified as long-term assets in the Consolidated Balance Sheets.

Inventories, which consist primarily of natural gas, propane, other NGLs and spare parts and supplies, are valued at the lower of weighted-average cost or net realizable value. Processed natural gas and NGL inventories include material, labor and overhead. Shipping and handling costs related to purchases of natural gas and NGLs are included in inventory.

Property, plant and equipment are recorded at cost. Expenditures that extend the useful lives of assets are capitalized. Repairs, maintenance and renewals that do not extend the useful lives of the assets are expensed as incurred. Interest costs for the construction or development of long-lived assets are capitalized and amortized over the related asset's estimated useful life. Leasehold improvements are depreciated over the shorter of the useful life or lease term. Depreciation is provided, principally on the straight-line method, over a period of 10 to 25 years for all assets, with the exception of miscellaneous equipment and vehicles, which are depreciated over a period of three to ten years.

The Partnership evaluates transactions involving the sale of property, plant and equipment to determine if they are, in-substance, the sale of real estate. Tangible assets may be considered real estate if the costs to relocate them for use in a different location exceeds 10% of the asset's fair value. Financial assets, primarily in the form of ownership interests in an entity, may be in-substance real estate based on the significance of the real estate in the entity. Sales of real estate are not considered consummated if the Partnership maintains an interest in the asset after it is sold or has certain other forms of continuing involvement. Significant judgment is required to determine if a transaction is a sale of real estate and if a transaction has been consummated. If a sale of real estate is not considered consummated, the Partnership cannot record the transaction as a sale and must account for the transaction under an alternative method of accounting such as a financing or leasing arrangement. The Partnership's sale of the SMR in 2009, which was considered in-substance real estate, was not considered a sale due to the Partnership's continuing involvement and was accounted for as a financing arrangement. See Note 7 for a description of the transaction and its impact on the financial statements. The Partnership accounted for the deconsolidation of Ohio Gathering as a partial sale of in-substance real estate. See Note 3 for a description of the transaction and its impact on the financial statements.

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

Equity investments in which the Partnership exercises significant influence, but does not control and is not the primary beneficiary, are accounted for using the equity method and are reported in Investment in unconsolidated affiliates in the accompanying Consolidated Balance Sheets.

The Partnership believes the equity method is an appropriate means for it to recognize increases or decreases measured by GAAP in the economic resources underlying the investments. Regular evaluation of these investments is appropriate to evaluate any potential need for impairment. The Partnership uses evidence of a loss in value to identify if an investment has an other than a temporary decline.

Non-controlling interests that are puttable by the non-controlling interest holder to the Partnership are considered to be redeemable non-controlling interests if the redemption feature is not deemed to be a freestanding financial instrument and if the redemption is not solely within the control of the Partnership. Redeemable non-controlling interest is not considered to be a component of Equity and is reported as temporary equity in the mezzanine section on the Consolidated Balance Sheets. The amount recorded as redeemable non-controlling interest at each balance sheet date is the greater of the redemption value and the carrying value of the redeemable non-controlling interest (the initial carrying value increased or decreased for the non-controlling interest holders' share of net income or loss and distributions).

The Partnership's intangibles are mainly comprised of customer contracts and relationships acquired in business combinations and recorded under the acquisition method of accounting at their estimated fair values at the date of acquisition. Using relevant information and assumptions, management determines the fair value of acquired identifiable intangible assets. Fair value is generally calculated as the present value of estimated future cash flows using a risk-adjusted discount rate. The key assumptions include probability of contract renewals, economic incentives to retain customers, historical volumes, current and future capacity of the gathering system, pricing volatility and the discount rate. Amortization of intangibles with definite lives is calculated using the straight-line method over the estimated useful life of the intangible asset. The estimated economic life is determined by assessing the life of the assets related to the contracts and relationships, likelihood of renewals, the projected reserves, competitive factors, regulatory or legal provisions and maintenance and renewal costs.

Goodwill is the cost of an acquisition less the fair value of the net identifiable assets of the acquired business. The Partnership evaluates goodwill for impairment annually as of November 30, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. The Partnership may first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. The Partnership may elect to perform the two-step goodwill impairment test without

completing a qualitative assessment. If a two-step process goodwill impairment test is elected or required, the first step involves comparing the fair value of the reporting unit to which goodwill has been allocated, with its carrying amount. If the carrying amount of a reporting unit exceeds its fair value, the second step of the process involves comparing the implied fair value to the carrying value of the goodwill for that reporting unit. If the carrying value of the goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the implied fair value is recognized as an impairment loss.

The Partnership performed its goodwill impairment analysis as of November 30, 2014 and determined that the carrying value of the Appalachia Reporting Unit in its Northeast segment exceeded its fair value. The Partnership completed the second step of our goodwill impairment analysis comparing the implied fair value of the reporting unit's goodwill to the carrying amount of that goodwill and determined the goodwill related to the Appalachia Reporting Unit was fully impaired and recorded an impairment charge of $62.4 million. The impairment was due primarily to a decline in commodity prices and the uncertainty related to the extension of certain material processing facility operating contracts. There were no impairments as a result of the Partnership's 2013 and 2012 goodwill impairment analyses.

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

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

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

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

Derivative instruments (including derivative instruments embedded in other contracts) are recorded at fair value and included in the Consolidated Balance Sheets as assets or liabilities. Assets and liabilities related to derivative instruments with the same counterparty are not netted in the Consolidated Balance Sheets. The Partnership discloses the fair value of all of its derivative instruments separate from other assets and liabilities under the caption Fair value of derivative instruments in the Consolidated Balance Sheets, inclusive of option premiums, if any. Changes in the fair value of derivative instruments are reported in the Statements of Operations in accounts related to the item whose value or cash flows are being managed. Substantially all derivative instruments were marked to market through Revenue, Purchased product costs, or Facility expenses. Revenue gains and losses relate to contracts utilized to manage the cash flow for the sale of a product. Purchased product costs gains and losses relate to contracts utilized to manage the cost of natural gas purchases, typically related to keep-whole arrangements. Facility expenses gains and losses relate to a contract utilized to manage electricity costs. Changes in risk management activities are reported as an adjustment to net income in computing cash flow from operating activities on the accompanying Consolidated Statements of Cash Flows.

During the years ended December 31, 2014, 2013 and 2012, the Partnership did not designate any hedges or designate any contracts as normal purchases and normal sales.

Management believes the carrying amount of financial instruments, including cash and cash equivalents, restricted cash, receivables, receivables from unconsolidated affiliates, accounts payable, payables to unconsolidated affiliates and accrued liabilities approximate fair value because of the short-term maturity of these instruments. The recorded value of the amounts outstanding under the Credit Facility, if any, approximate fair value due to the variable interest rate that approximates current market rates. Derivative instruments are recorded at fair value, based on available market information (see Note 9). The following table shows the carrying value and related fair value of financial instruments that are not recorded in the financial statements at fair value as of December 31, 2014 and 2013 (in thousands):

The fair value of the long-term debt is estimated based on recent market non-binding indicative quotes. The Partnership has continued to report an asset and the related depreciation, for the total

capitalized costs of constructing the SMR and has recorded a liability equal to the proceeds from the transaction plus the estimated costs incurred by the buyer to complete construction ("SMR Liability"). The fair value of the SMR Liability is estimated using a discounted cash flow approach based on the contractual cash flows and the Partnership's unsecured borrowing rate. The long-term debt and SMR fair values are considered Level 2 measurements, as discussed below.

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

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

The determination to classify a financial instrument within Level 3 of the valuation hierarchy is based upon the significance of the unobservable inputs to the overall fair value measurement. However, Level 3 financial instruments typically include, in addition to the unobservable or Level 3 inputs, observable inputs (that is, inputs that are actively quoted and can be validated to external sources); accordingly, the gains and losses for Level 3 financial instruments include changes in fair value due in part to observable inputs that are part of the valuation methodology. Level 3 financial instruments include crude oil options, all NGL derivatives and the embedded derivatives in commodity contracts discussed in Note 8 as they have significant unobservable inputs.

The methods and assumptions described above may produce a fair value that may not be realized in future periods upon settlement. Furthermore, while the Partnership believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value at the reporting date. For further discussion see Note 9.

The Partnership generates the majority of its revenues from natural gas gathering, transportation and processing; NGL gathering, transportation, fractionation, marketing and storage; and crude oil gathering and transportation. The Partnership disaggregates revenue as Product sales and Service revenue on the Consolidated Statements of Operations. Revenue is reported as follows:

The Partnership enters into a variety of contract types in order to generate Product Sales and Service Revenue. The Partnership provides services under the following different types of arrangements:

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.

The Partnership's assessment of each of the revenue recognition criteria as they relate to its revenue producing activities are as follows: persuasive evidence of an arrangement exists, delivery, the fee is fixed or determinable and collectability is reasonably assured. It is upon delivery or title transfer to the customer that the Partnership meets all four revenue recognition criteria and it is at such time that the Partnership recognizes Product Sales. It is upon completion of services provided that the Partnership meets all four criteria and it is at such time that the Partnership recognizes Service Revenue.

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

The Partnership issues phantom units under its share-based compensation plans as described further in Note 21. A phantom unit entitles the grantee to receive a common unit upon the vesting of the phantom unit. Phantom units are treated as equity awards and compensation expense is measured

for these phantom unit grants based on the fair value of the units on the grant date, as defined by GAAP. The fair value of the units awarded is amortized into earnings, reduced for an estimate of expected forfeitures, over the period of service corresponding with the vesting period. For certain plans, the awards may be accounted for as liability awards and the compensation expense is adjusted monthly for the change in the fair value of the unvested units granted.

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

The Partnership elected to adopt the simplified method to establish the beginning balance of the additional paid-in capital pool ("APIC Pool") related to the tax effects of employee share-based compensation and to determine the subsequent impact on the APIC Pool and Consolidated Statements of Cash Flows of the tax effects of share-based compensation awards that were outstanding upon adoption. Additional paid-in capital is reported as Common units in the accompanying Consolidated Balance Sheets. Cash flows resulting from tax deductions in excess of the cumulative compensation cost recognized for share-based compensation awards exercised are classified as financing cash flows and are included as Excess tax benefits related to share-based compensation in the accompanying Consolidated Statements of Cash Flows.

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

In addition to paying tax on its own earnings, the Corporation recognizes a tax expense or a tax benefit on its proportionate share of Partnership income or loss resulting from the Corporation's ownership of Class A units of the Partnership even though for financial reporting purposes such income or loss is eliminated in consolidation. The Class A units represents limited partner interests with the same rights as common units except that the Class A units do not have voting rights, except as required by law. Class A units are not treated as outstanding common units in the Consolidated Balance Sheets as they are eliminated in the consolidation of the Corporation. The deferred income tax component relates to the change in the temporary book to tax basis difference in the carrying amount of the investment in the Partnership which results primarily from its timing differences in the Corporation's proportionate share of the book income or loss as compared with the Corporation's proportionate share of the taxable income or loss of the Partnership.

The Partnership and the Corporation account for income taxes under the asset and liability method. Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax basis, capital loss carryforwards and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates applied to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate

change on deferred taxes is recognized as tax expense (benefit) from continuing operations in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed and, if not more likely than not, a valuation allowance is recorded to reflect the deferred tax assets at net realizable value as determined by management. Deferred tax balances that are expected to be settled within twelve months are classified as current and all other deferred tax balances are classified as long-term in the accompanying Consolidated Balance Sheets. All changes in the tax bases of assets and liabilities are allocated among operations and items charged or credited directly to equity.

The Partnership's outstanding phantom units are considered to be participating securities and the Class B units are considered to be a separate class of common units that do not participate in cash distributions. Therefore, basic and diluted earnings per common unit are calculated pursuant to the two-class method described in GAAP for earnings per share. In accordance with the two-class method, basic earnings per common unit is calculated by dividing net income attributable to the Partnership's unitholders, after deducting amounts that are allocable to participating securities or separate class of common units, the outstanding phantom units and Class B units, by the weighted average number of common units outstanding during the period. The amount allocable to the phantom units and Class B units is generally calculated as if all of the net income attributable to the Partnership's unitholders were distributed and not on the basis of actual cash distributions for the period. Therefore, no earnings are allocable to Class B units as they do not participate in cash distributions. During periods in which a net loss attributable to the Partnership is reported or periods in which the total distributions exceed the reported net income attributable to the Partnership's unitholders, the amount allocable to the phantom units and Class B units is based on actual distributions to the phantom units and Class B unitholders. Diluted earnings per unit is calculated by dividing net income attributable to the Partnership's unitholders, after deducting amounts allocable to the outstanding phantom units and Class B units, by the weighted average number of potential common units outstanding during the period. Potential common units are excluded from the calculation of diluted earnings per unit during periods in which net income attributable to the Partnership's unitholders, after deducting amounts that are allocable to the outstanding phantom units and Class B units, is a loss as the impact would be anti-dilutive.

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

The Partnership's ownership interest in a consolidated subsidiary may change if it sells a portion of its interest or acquires additional interest or if the subsidiary issues or repurchases its own shares. If the transaction does not result in a change in control over the subsidiary, the transaction is accounted for as an equity transaction. If a sale results in a change in control, it would result in the deconsolidation of a subsidiary with a gain or loss recognized in the Consolidated Statements of Operations unless the subsidiary meets the definition of in substance real estate. Deconsolidation of in substance real estate is recorded at cost with no gain nor loss recognized. If the purchase of additional interest occurs which

changes the acquirer's ownership interest from non-controlling to controlling, the acquirer's preexisting interest in the acquiree is remeasured to its fair value, with a resulting gain or loss recorded in earnings upon consummation of the business combination. Once an entity has control of a subsidiary, its acquisitions of some or all of the noncontrolling interests in that subsidiary are accounted for as equity transactions and are not considered to be a business combination.

In April 2014, the FASB issued ASU 2014-08—Presentation Of Financial Statements (Topic 205) And Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations And Disclosures Of Disposals Of Components Of An Entity ("ASU 2014-08") that will supersede previous GAAP for accounting for discontinued operations. ASU 2014-08 raises the threshold for a disposal to qualify as a discontinued operation and requires new disclosures of both discontinued operations and certain other disposals that do not meet the definition of a discontinued operation. ASU 2014-08 is effective for the Partnership prospectively as of January 1, 2015; however the Partnership has elected to early adopt the guidance as of April 1, 2014. The adoption of the guidance did not have a material effect on the Partnership's consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09—Revenue from Contracts with Customers ("ASU 2014-09") that will supersede current revenue recognition guidance. ASU 2014-09 is intended to provide companies with a single comprehensive model to use for all revenue arising from contracts with customers, which would include real estate sales transactions. ASU 2014-09 is effective for the Partnership as of January 1, 2017 and must be adopted using either a full retrospective approach for all periods presented in the period of adoption (with some limited relief provided) or a modified retrospective approach. The Partnership is in the early stages of evaluating ASU 2014-09 and has not yet determined the impact on the Partnership's consolidated financial statements.

In August 2014, the FASB issued ASU 2014-15—Presentation of Financial Statements—Going Concern (Subtopic 205-40): Disclosure of Uncertainties about an Entity's Ability to Continue as a Going Concern ("ASU 2014-15"), that provides guidance on management's responsibility to perform interim and annual assessments of an entity's ability to continue as a going concern and provides related disclosure requirements. ASU 2014-15 applies to all entities and is effective for annual periods ending after December 15, 2016, and interim periods thereafter, with early adoption permitted. The Partnership is in the early stages of evaluating ASU 2014-15 and has not yet determined the impact on the Partnership's consolidated financial statements.

In February 2015, the FASB issued ASU 2015-02—Consolidation (Topic 810): Amendments to the Consolidation Analysis ("ASU 2015-02") that will modify current consolidation guidance. ASU 2015-02 makes changes to both the variable interest model and the voting interest model, including modifying the evaluation of whether limited partnerships or similar legal entities are VIEs or voting interest entities and amending the guidance for assessing how relationships of related parties affect the consolidation analysis of VIEs. ASU 2015-02 is effective for the Partnership as of January 1, 2016 and early adoption is permitted. The Partnership is in the early stages of evaluating ASU 2015-02 and has not yet determined the impact on the Partnership's consolidated financial statements.

Effective January 1, 2012, the Partnership and EMG Utica, LLC ("EMG Utica") (together the "Members"), executed agreements to form a joint venture, MarkWest Utica EMG, to develop significant natural gas gathering, processing and NGL fractionation, transportation and marketing infrastructure in eastern Ohio.

In February 2013, the Members entered into the Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG ("Amended Utica LLC Agreement") which replaced the original agreement. Pursuant to the Amended Utica LLC Agreement, the aggregate funding commitment of 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 Members 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, EMG Utica has contributed $965.4 million and the Partnership has contributed approximately $1,188.6 million to MarkWest Utica EMG.

Under the Amended Utica LLC Agreement, after EMG Utica has contributed more than $500.0 million to MarkWest Utica EMG and prior to December 31, 2016, EMG Utica's investment balance will also be increased by a quarterly special non-cash allocation of income ("Preference Amount") that is based upon the amount of capital contributed by EMG Utica in excess of $500.0 million. No Preference Amount will accrue to EMG Utica's investment balance after December 31, 2016. EMG Utica received a special non-cash allocation of income of approximately $36.9 million and approximately $23.2 million for the years ended December 31, 2014 and December 31, 2013, respectively.

During the fourth quarter of 2014, the Partnership's investment balance exceeded 51% of the aggregate investment balances of both Members. If the Partnership's investment balance did not equal at least 51% of the aggregate investment balances of both Members as of December 31, 2016, then EMG Utica could have required the Partnership to purchase membership interests from EMG Utica so that, following the purchase, the Partnership's investment balance equals 51% of the aggregate investment balances of the Members. The amount of non-controlling interest subject to the redemption option is reported as Redeemable non-controlling interest in the mezzanine equity section of the Partnership's Consolidated Balance Sheets.

Under the Amended Utica LLC Agreement, the Partnership will continue to receive 60% of cash generated by MarkWest Utica EMG that is available for distribution until the earlier of December 31, 2016 and the date on which the Partnership's investment balance equals 60% of the aggregate investment balances of the Members. After the earlier of those dates, cash generated by MarkWest

Utica EMG that is available for distribution will be allocated to the Members in proportion to their respective investment balances.

The Partnership has determined that MarkWest Utica EMG does not meet the business scope exception to be excluded as a VIE due to the unique investment structure, discussed above, which creates a de-facto agent relationship between the members, as EMG Utica has funded portions of the Partnership's ownership in MarkWest Utica EMG. MarkWest Utica EMG's inability to fund its planned activities without additional subordinated financial support qualifies it to be a VIE. The Partnership has concluded that it is the primary beneficiary of MarkWest Utica EMG. As the primary beneficiary of MarkWest Utica EMG, the Partnership consolidates the entity and recognizes non-controlling interest and redeemable non-controlling interest. The decision to consolidate MarkWest Utica EMG is re-evaluated quarterly and is subject to change. Upon the earlier of December 31, 2016 and the date on which the Partnership's investment balance equals 60% of the aggregate investments balances of the Members, a de-facto agent relationship between the members will no longer exist.

The assets of MarkWest Utica EMG are the property of MarkWest Utica EMG and are not available to the Partnership for any other purpose, including as collateral for its secured debt (See Notes 17 and 26). MarkWest Utica EMG's asset balances can only be used to settle its own obligations. The liabilities of MarkWest Utica EMG do not represent additional claims against the Partnership's general assets and the creditors or beneficial interest holders of MarkWest Utica EMG do not have recourse to the general credit of the Partnership. The Partnership's maximum exposure to loss as a result of its involvement with MarkWest Utica EMG includes its equity investment, any additional capital contribution commitments and any operating expenses incurred by the subsidiary operator in excess of its compensation received for the performance of the operating services. Other than temporary funding due to the timing of the administrative process associated with capital calls in the beginning of 2013, the Partnership did not provide any financial support to MarkWest Utica EMG that it was not contractually obligated to provide during the years ended December 31, 2014, 2013 and 2012.

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 1, 2014, MarkWest Utica EMG, as the primary beneficiary of a VIE, consolidated Ohio Gathering. Effective June 1, 2014 ("Summit Investment Date"), Summit exercised its Ohio Gathering Option and increased its equity ownership ("Summit Equity Ownership") from less than 1% to approximately 40% through a cash investment of approximately $341.1 million that Ohio Gathering received in 2014. MarkWest Utica EMG received $336.1 million as a distribution from Ohio Gathering as a result of the exercise of the Ohio Gathering Option. Summit purchased its initial 1% equity interest and the Ohio Gathering Option from Blackhawk Midstream LLC ("Blackhawk") in January 2014. As of the Summit Investment Date, MarkWest Utica EMG was no longer deemed the primary beneficiary due to Summit's voting rights on significant operating matters obtained as a result of its increased equity ownership in Ohio Gathering. As of the Summit Investment Date, the Partnership accounted for Ohio Gathering as an equity method investment. As of December 31, 2014, Ohio Gathering's net assets are reported under the caption Investment in unconsolidated affiliates on the Consolidated Balance Sheets.

The Partnership accounted for the increase in Summit's Equity Ownership and the deconsolidation of Ohio Gathering as a partial sale of in-substance real estate. In conjunction with Summit exercising

the Ohio Gathering Option, Summit reimbursed MarkWest Utica EMG $5.3 million related to a reimbursement of certain costs incurred on behalf of Ohio Gathering and payable to the Partnership. The Partnership accounted for the cash received as a Loss (gain) on disposal of property, plant and equipment in the Partnership's Consolidated Statements of Operations for the year ended December 31, 2014.

For the year ended December 31, 2014, the Partnership's consolidated results of operations include the consolidated results of operations of Ohio Gathering through May 31, 2014. For the period from June 1, 2014 to December 31, 2014, MarkWest Utica EMG has reported its pro rata share of Ohio Gathering's net loss under the caption (Loss) earnings from unconsolidated affiliates on the Consolidated Statements of Operations for the year ended December 31, 2014. Ohio Gathering is considered to be a related party. The Partnership receives engineering and construction and administrative management fee revenue and other direct personnel costs ("Operational Service" revenue) for operating Ohio Gathering. The December 31, 2014 receivable balance related to Ohio Gathering was $2.1 million and is reported as Receivables from unconsolidated affiliates, net in the Partnership's Consolidated Balance Sheets. The amount of Operational Service revenue related to Ohio Gathering for the seven months ended December 31, 2014 was approximately $12.2 million and is reported as Service revenue in the Consolidated Statements of Operations.

In December 2013, the Partnership and The Energy & Minerals Group ("EMG") (together the "Condensate Members") executed an agreement ("Utica Condensate LLC Agreement") to form Utica Condensate for the purpose of engaging in wellhead condensate gathering, stabilization, terminalling, storage and marketing in the state of Ohio. If Utica Condensate requires additional capital, each Condensate Member has the right, but not the obligation, to contribute capital in proportion to its ownership interest. As of December 31, 2014, the Partnership owned 55% of Utica Condensate.

Under the Utica Condensate LLC Agreement, oversight of the business and affairs of Utica Condensate is managed by a board of managers. The number of managers that each Condensate Member may designate is determined based upon ownership interests. In addition, both the Partnership and EMG have consent rights with respect to certain specified material transactions involving Utica Condensate; therefore, management has concluded that Utica Condensate is under joint control and will be accounted for as an equity method investment.

Utica Condensate's business is conducted solely through its subsidiary, Ohio Condensate Company L.L.C. ("Ohio Condensate"), which was formed in December 2013 through an agreement executed between Utica Condensate and Blackhawk ("Ohio Condensate LLC Agreement"), in which Utica Condensate and Blackhawk contributed cash in exchange for equity ownership interests of 99% and 1%, respectively. In January 2014, Summit purchased Blackhawk's less than 1% equity interest and its option to purchase up to an additional equity ownership interest of 40% in Ohio Condensate ("Ohio Condensate Option"). Effective as of the Summit Investment Date, Summit exercised the Ohio Condensate Option and increased its equity ownership from less than 1% to 40% through a cash investment of approximately $8.6 million.

As of December 31, 2014, Utica Condensate owned 60% of Ohio Condensate. The Partnership sold approximately $17 million of assets under construction to Utica Condensate in December 2013 and recorded that amount in Receivables from unconsolidated affiliates, net in the accompanying Condensed Consolidated Balance Sheets as of December 31, 2013. As of December 31, 2013, Ohio Condensate had not commenced operating activities and therefore had no impact on the Partnership's operating results. The Partnership received the $17 million in the first quarter of 2014 and has recorded the proceeds in the Proceeds from disposal of property, plant and equipment in the accompanying Condensed Consolidated Statements of Cash Flows for the twelve months ended December 31, 2014. The amount of Operational Service revenue related to Ohio Condensate for the twelve months ended December 31, 2014 was approximately $3.4 million and is reported as Service revenue in the Condensed Consolidated Statements of Operations.

On May 8, 2013, the Partnership acquired natural gas gathering and processing assets from Chesapeake Energy Corporation ("Chesapeake") for a cash purchase price of approximately $225.2 million. The acquired assets include a 200 MMcf/d cryogenic gas processing plant under construction (which commenced operation in February 2014), known as the Buffalo Creek Plant, 22 miles of gas gathering pipeline in Hemphill County, Texas and approximately 30 miles of rights-of-way associated with the future construction of a trunk line. Additional assets acquired from Chesapeake consist of an amine treating facility and a five-mile gas gathering pipeline in Washita County, Oklahoma. This acquisition is referred to as the "Buffalo Creek Acquisition."

Concurrently with the closing of the Buffalo Creek Acquisition, the Partnership entered into a long-term fee-based agreement to provide treating, processing and certain gathering and compression services for natural gas owned or controlled by Chesapeake at the acquired facilities. Chesapeake has dedicated 130,000 acres throughout the Anadarko Basin to the Partnership as part of this long-term agreement. As a result of the acquisition, the Partnership has expanded its presence in the Granite Wash and Hogshooter formations in Oklahoma.

Contemporaneously with the Buffalo Creek Acquisition, Chesapeake agreed to extend a keep-whole processing agreement for natural gas produced in the Appalachia Basin area of the Partnership's Northeast segment for five additional years, to 2020. The Partnership paid an additional $20.0 million of cash upon closing the Buffalo Creek Acquisition as consideration for the extension and has recorded it as Deferred contract cost in the accompanying Consolidated Balance Sheets. The deferred contract costs will be amortized over the extension term. This $20.0 million is not considered to be part of the purchase price of the Buffalo Creek Acquisition and is not included in the purchase price allocation table below.

The goodwill recognized from the Buffalo Creek Acquisition results primarily from the Partnership's ability to grow its business in the liquids-rich gas areas of the Granite Wash and Hogshooter formations in Oklahoma and access additional markets in a competitive environment as a result of securing the gathering and processing rights for a large area of dedicated acreage. All of the goodwill is deductible for tax purposes.

Pro forma financial results that give effect to the Buffalo Creek Acquisition are not presented as it is impractical to obtain the necessary information. Chesapeake did not operate the acquired assets as a standalone business and, therefore, historical financial information that is consistent with the operations under the current agreements is not available.

On May 29, 2012, the Partnership acquired natural gas gathering and processing assets from Keystone for a cash purchase price of approximately $507.3 million, giving effect to the final working capital adjustment. The Partnership paid cash of $509.6 million in May 2012. During 2013, we received $2.3 million related to a working capital adjustment.

Keystone's existing assets are located in Butler County, Pennsylvania and include two cryogenic gas processing plants totaling approximately 90 MMcf/d of processing capacity, a gas gathering system and associated field compression.

As a result of the Keystone Acquisition, the Partnership became a party to a long-term fee-based agreement to gather and process certain natural gas owned or controlled by a subsidiary of Rex Energy Corporation and a subsidiary of Sumitomo Corporation ("Sumitomo"), at the acquired facilities and in 2013 to exchange the resulting NGLs for fractionated products at facilities already owned and operated by the Partnership. Rex and Sumitomo have dedicated an area of approximately 900 square miles to the Partnership as part of this long-term gathering and processing agreement. As a result of the Keystone Acquisition, the Partnership has expanded its position in the liquids-rich Marcellus Shale area into northwest Pennsylvania.

The goodwill recognized from the Keystone Acquisition results primarily from synergies created from integrating the Keystone assets with the Partnership's existing Marcellus Shale operations and the Partnership's strengthened competitive position as it plans to expand its business in the newly developing liquids-rich areas of the Marcellus Shale. All of the goodwill is deductible for tax purposes.

Pro forma financial results that give effect to the Keystone Acquisition are not presented as any pro forma adjustments would not be material to the Partnership's historical results.

The acquired assets and the related results of operations are included in the Partnership's following segments:

The following table summarizes the purchase price allocation for the two acquisitions (in thousands):

The results of operations of the two acquisitions are included in the consolidated financial statements from their respective acquisition dates. Revenue and net income related to the two acquisitions are immaterial during the year each acquisition occurred.

In June 2013, the Partnership sold certain gathering assets in Doddridge County, West Virginia (the "Sherwood Asset Sale") to Summit for approximately $207.9 million cash, net of third party transaction costs. In connection with the Sherwood Asset Sale, Summit assumed liabilities associated with the purchased assets, other than certain identified liabilities that were retained by the Partnership. Liquids-rich gas gathered by these assets is dedicated to the Partnership for processing at the Marcellus segment's Sherwood processing complex, also located in Doddridge County, West Virginia. The assets included in this transaction consist of over 40 miles of newly constructed high-pressure gas gathering pipelines, certain rights-of-way associated with the pipeline and two compressor stations totaling over 21,000 horsepower of combined compression. The assets had a carrying value of approximately $168.2 million and were part of the Partnership's Marcellus segment. The gain of approximately $39.7 million on the Sherwood Asset Sale is included in Loss gain on disposal of property, plant and equipment in the accompanying Consolidated Statements of Operations.

On September 1, 2009, the Partnership completed the SMR Transaction. At that time, the Partnership had begun constructing the SMR at its Javelina gas processing and fractionation facility in Corpus Christi, Texas. Under the terms of the agreement, the Partnership received proceeds of $73.1 million and the purchaser completed the construction of the SMR. The Partnership and the purchaser also executed a related product supply agreement under which the Partnership will receive the entire product produced by the SMR through 2030 in exchange for processing fees and the reimbursement of certain other expenses. The processing fee payments began when the SMR commenced operations in March 2010. The Partnership is deemed to have continuing involvement with

the SMR as a result of certain provisions in the related agreements. Therefore, the transaction is treated as a financing arrangement under GAAP. The Partnership imputes interest on the SMR Liability at 9.35% annually, its incremental borrowing rate at transaction consummation. The accrued interest on the SMR Liability was capitalized until the SMR commenced operations and the Partnership began payment of the processing fee under the product supply agreement. Each processing fee payment has multiple elements: reduction of principal of the SMR Liability, interest expense associated with the SMR Liability and facility expense related to the operation of the SMR. As of December 31, 2014 and 2013, the following amounts related to the SMR are included in the accompanying Consolidated Balance Sheets (in thousands):

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

To mitigate its cash flow exposure to fluctuations in the price of NGLs, the Partnership has entered into derivative financial instruments relating to the future price of NGLs and crude oil. The Partnership currently manages the majority of its NGL price risk using direct product NGL derivative contracts. The Partnership enters into NGL derivative contracts when adequate market liquidity exists

and future prices are satisfactory. A portion of the Partnership's NGL price exposure is managed by using crude oil contracts. In periods where NGL prices and crude oil prices are not consistent with the historical relationship, the crude oil contracts create increased risk and additional gains or losses. The Partnership may settle its crude oil contracts prior to the contractual settlement date in order to take advantage of favorable terms and reduce the future exposure resulting from the less effective crude oil contracts. Based on our current volume forecasts, the majority of our derivative positions used to manage our future commodity price exposure are direct product NGL derivative contracts.

To mitigate its cash flow exposure to fluctuations in the price of natural gas, the Partnership primarily utilizes derivative financial instruments relating to the future price of natural gas and takes into account the partial offset of its long and short gas positions resulting from normal operating activities. The Partnership has no such positions outstanding as of December 31, 2014.

As a result of its current derivative positions, the Partnership has mitigated a portion of its expected commodity price risk through the fourth quarter of 2015. The Partnership would be exposed to additional commodity risk in certain situations such as if producers under deliver or over deliver product or when processing facilities are operated in different recovery modes. In the event the Partnership has derivative positions in excess of the product delivered or expected to be delivered, the excess derivative positions may be terminated.

All of the Partnership's financial derivative positions are with financial institutions that are participating members of the Credit Facility ("participating bank group members"). Management conducts a standard credit review on counterparties to derivative contracts. There are no collateral requirements for derivative contracts among the Partnership and any participating bank group members. Specifically, the Partnership is not required to post collateral when it enters into derivative contracts with participating bank group members as the participating bank group members have a collateral position in substantially all the wholly-owned assets of the Partnership other than MarkWest Liberty Midstream and its subsidiaries. A separate agreement with certain participating bank group members allows MarkWest Liberty Midstream to enter into derivative positions without posting cash collateral. The Partnership uses standardized agreements that allow for offset of certain positive and negative exposures ("master netting arrangements") in the event of default or other terminating events, including bankruptcy.

The Partnership records derivative contracts at fair value in the Consolidated Balance Sheets and has not elected hedge accounting or the normal purchases and normal sales designation. The Partnership's accounting may cause volatility in the Consolidated Statements of Operations as the Partnership recognizes in current earnings all unrealized gains and losses from the changes in fair value on derivatives.

As of December 31, 2014, the Partnership had the following outstanding commodity contracts that were executed to manage the cash flow risk associated with future sales of NGLs or future purchases of natural gas.

The Partnership has a commodity contract with a producer in the Appalachia region that creates a floor on the frac spread for gas purchases of 9,000 Dth/d. The commodity contract is a component of a broader regional arrangement that also includes a keep-whole processing agreement. This contract is accounted for as an embedded derivative and is recorded at fair value. The changes in fair value of this commodity contract are based on the difference between the contractual and index pricing and are recorded in earnings through Derivative gain related to purchased product costs. In February 2011, the Partnership executed agreements with the producer to extend the commodity contract and the related processing agreement from March 31, 2015 to December 31, 2022, with the producer's option to extend the agreement for successive five year terms through December 31, 2032. As of December 31, 2014, the estimated fair value of this contract was a liability of $34.7 million and the recorded value was an asset of $18.8 million. The recorded asset does not include the inception fair value of the commodity contract related to the extended period from April 1, 2015 to December 31, 2022. In accordance with GAAP for non-option embedded derivatives, the fair value of this extended portion of the commodity contract at its inception of February 1, 2011 is deemed to be allocable to the host processing contract and, therefore, not recorded as a derivative liability. See the following table for a reconciliation of the asset recorded for the embedded derivative as of December 31, 2014 (in thousands):

The Partnership had a commodity contract that gave it an option to fix a component of the utilities cost to an index price on electricity at its plant location in the Southwest segment through the fourth quarter of 2014. Changes in the fair value of the derivative component of this contract were recognized as Derivative loss related to facility expenses. As of December 31, 2014 and 2013, the estimated fair value of this contract was an asset of zero and $3.3 million, respectively.

The impact of the Partnership's derivative instruments on its Consolidated Balance Sheets is summarized below (in thousands):

Although certain derivative positions are subject to master netting agreements, the Partnership has elected not to offset any derivative assets and liabilities. The gross amounts in the table below equal the balances presented in the Consolidated Balance Sheets. The table below summarizes the impact if the Partnership had elected to net its derivative positions that are subject to master netting arrangements (in thousands):

	Assets						Liabilities

As of December 31, 2014	Gross Amounts of Assets in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount		Gross Amounts of Liabilities in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	18,652	$	—	$	18,652	$	—	$	—	$	—
Embedded derivatives in commodity contracts		2,269		—		2,269		—		—		—

Total current derivative instruments		20,921		—		20,921		—		—		—

Non-current
Commodity contracts		—		—		—		—		—		—
Embedded derivatives in commodity contracts		16,507		—		16,507		—		—		—

Total non-current derivative instruments		16,507		—		16,507		—		—		—

Total derivative instruments	$	37,428	$	—	$	37,428	$	—	$	—	$	—

	Assets							Liabilities

As of December 31, 2013	Gross Amounts of Assets in the Consolidated Balance Sheet		Gross Amounts Not Offset in the Consolidated Balance Sheet			Net Amount		Gross Amounts of Liabilities in the Consolidated Balance Sheet			Gross Amounts Not Offset in the Consolidated Balance Sheet		Net Amount
Current
Commodity contracts	$	8,181	$	(7,017	)	$	1,164	$	(18,293	)	$	7,017	$	(11,276	)
Embedded derivatives in commodity contracts		3,276		—			3,276		(10,545	)		—		(10,545	)

Total current derivative instruments		11,457		(7,017	)		4,440		(28,838	)		7,017		(21,821	)

Non-current
Commodity contracts		505		—			505		—			—		—
Embedded derivatives in commodity contracts		—		—			—		(27,763	)		—		(27,763	)

Total non-current derivative instruments		505		—			505		(27,763	)		—		(27,763	)

Total derivative instruments	$	11,962	$	(7,017	)	$	4,945	$	(56,601	)	$	7,017	$	(49,584	)

In the tables above, the Partnership does not offset a counterparty's current derivative contracts with the counterparty's non-current derivative contracts, although the Partnership's master netting arrangements would allow current and non-current positions to be offset in the event of default. Additionally, in the event of a default, the Partnership's master netting arrangements would allow for the offsetting of all transactions executed under the master netting arrangement. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions and other forms of non-cash collateral (such as letters of credit). These types of transactions are excluded from the offsetting tables presented above.

The impact of the Partnership's derivative instruments on its Consolidated Statements of Operations is summarized below (in thousands):

	Year ended December 31,

Derivative contracts not designated as hedging instruments and the location of gain or (loss) recognized in income	2014			2013			2012
Revenue: Derivative gain (loss)
Realized gain (loss)	$	15,002		$	(3,534	)	$	(6,508	)
Unrealized gain (loss)		25,149			(21,104	)		63,043

Total revenue: derivative gain (loss)		40,151			(24,638	)		56,535

Derivative gain (loss) related to purchased product costs
Realized loss		(1,803	)		(6,634	)		(26,493	)
Unrealized gain		60,195			8,371			40,455

Total derivative gain related to purchase product costs		58,392			1,737			13,962

Derivative loss related to facility expenses
Unrealized loss		(3,277	)		(2,869	)		(1,371	)

Total gain (loss)	$	95,266		$	(25,770	)	$	69,126

Fair value measurements and disclosures relate primarily to the Partnership's derivative positions as discussed in Note 8.

Money market funds are measured at fair value and are included in Level 1 measurements of the valuation hierarchy. The derivative contracts are measured at fair value on a recurring basis and classified within Level 2 and Level 3 of the valuation hierarchy. The Level 2 and Level 3 measurements are obtained using a market approach. LIBOR rates are an observable input for the measurement of all derivative contracts. The measurements for all commodity contracts contain observable inputs in the form of forward prices based on WTI crude oil prices; and Columbia Appalachia, Henry Hub, PEPL and Houston Ship Channel natural gas prices. Level 2 instruments include crude oil and natural gas swap contracts. The valuations are based on the appropriate commodity prices and contain no significant unobservable inputs. Level 3 instruments include crude oil options, all NGL transactions and embedded derivatives in commodity contracts. The significant unobservable inputs for crude oil options, NGL transactions and embedded derivatives in commodity contracts include option volatilities and NGL prices interpolated and extrapolated due to inactive markets, electricity price curves, and probability of renewal. The following table presents the financial instruments carried at fair value as of December 31, 2014 and 2013 and by the valuation hierarchy (in thousands):

The following table provides additional information about the significant unobservable inputs used in the valuation of Level 3 instruments as of December 31, 2014. The market approach is used for valuation of all instruments.

Level 3 Instrument	Balance Sheet Classification	Unobservable Inputs	Value Range	Time Period

Commodity contracts	Assets	Forward propane prices (per gallon)(1)	$0.50 - $0.50	Jan. 2015 - Mar. 2015
		Propane option volatilities (%)	30.24% - 44.16%	Jan. 2015 - Mar. 2015
Embedded derivatives in commodity contracts	Assets	Forward propane prices (per gallon)(1)	$0.50 - $0.61	Jan. 2015 - Dec. 2022
		Forward isobutane prices (per gallon)(1)	$0.69 - $0.84	Jan. 2015 - Dec. 2022
		Forward normal butane prices (per gallon)(1)	$0.64 - $0.81	Jan. 2015 - Dec. 2022
		Forward natural gasoline prices (per gallon)(1)	$0.99 - $1.27	Jan. 2015 - Dec. 2022
		Forward natural gas prices (per MMBtu)(2)	$2.69 - $4.27	Jan. 2015 - Dec. 2022
		Probability of renewal(3)	0%

Commodity contracts (assets and liabilities)—For the Partnership's commodity contracts, increases in forward NGL prices result in a decrease in the fair value of the derivative assets and an increase in the fair value of the derivative liabilities. The forward prices for the individual NGL products generally increase or decrease in a positive correlation with one another. An increase in crude option volatilities will generally result in an increase in the fair value of the Partnership's derivative assets and derivative liabilities in commodity contracts.

Embedded derivative in commodity contracts (asset and liability)—The embedded derivative asset relates to the natural gas purchase agreement embedded in a keep-whole processing agreement as discussed further in Note 8. Increases (decreases) in forward NGL prices result in an increase (decrease) in the fair value of the embedded derivative. An increase in the probability of renewal

would result in a decrease in the fair value of the related embedded derivative, which could result in a liability.

The Partnership's Risk Management Department (the "Risk Department") is responsible for the valuation of the Partnership's commodity derivative contracts and embedded derivatives in commodity contracts. The Risk Department reports to the Chief Financial Officer and is responsible for the oversight of the Partnership's commodity risk management program. The members of the Risk Department have the requisite experience, knowledge and day-to-day involvement in the energy commodity markets to ensure appropriate valuations and understand the changes in the valuations from period to period. The valuations of the Level 3 commodity derivative contracts are performed by a third-party pricing service and reviewed and validated on a quarterly basis by the Risk Department by comparing the pricing and option volatilities to actual market data and/or data provided by at least one other independent third-party pricing service. The valuations for the embedded derivative in the commodity contract are completed by the Risk Department utilizing the market data and price curves provided by the third-party pricing service. For the embedded derivative in the keep-whole processing arrangement discussed in Note 8, the Risk Department must develop forward price curves for NGLs and natural gas for periods in which price curves are not available from third-party pricing services due to insufficient market data. As of December 31, 2014, the Risk Department utilized internally developed price curves for the period of January 2016 through December 2022 in the valuation of the embedded derivative in the keep-whole processing arrangement. In developing the pricing curves for these periods, the Risk Department maximizes its use of the latest known market data and trends as well as its understanding of the historical relationships between forward NGL and natural gas prices and the forward market data that is available for the required period, such as crude oil pricing and natural gas pricing from other markets. However, there is very limited actual market data available to validate the Risk Department's estimated price curves.

The tables below include a roll forward of the balance sheet amounts for the years ended December 31, 2014 and 2013 (including the change in fair value) for assets and liabilities classified by the Partnership within Level 3 of the valuation hierarchy (in thousands):

For the years ended December 31, 2014, 2013 and 2012, revenues from a single customer totaled $303.8 million, $183.8 million and $138.7 million, representing 14.0%, 11.1% and 9.6% of Total Revenue, respectively. Revenues from this customer are from product sales, gathering, processing and fractionation services in the Marcellus segment. As of December 31, 2014 and 2013, the Partnership had $54.5 million and $45.7 million of accounts receivable from this customer, respectively.

For the years ended December 31, 2013 and 2012, revenues from a second customer totaled $184.0 million, and $175.1 million, representing 11.1% and 12.2% of Total Revenue, respectively. Revenues from this customer are for NGL sales made primarily from the Southwest segment. As of December 31, 2013, the Partnership had $20.3 million of accounts receivable from this customer.

For the year ended December 31, 2012, revenues from a third customer totaled $165.3 million, representing 11.5% of Total Revenue. Revenues from this customer are made primarily in the Southwest segment.

Goodwill. The table below shows the gross amount of goodwill acquired and the cumulative impairment loss recognized as of December 31, 2014 (in thousands).

The Partnership evaluates goodwill for impairment annually as of November 30, and whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount.

Management considered the decline in commodity prices and the uncertainty related to the extension of certain material processing facility operating contracts in the Northeast segment's

Appalachia Reporting Unit that expires December 31, 2015 if it is not renewed and will impact its ability to continue to process gas at the Boldman and Cobb processing facilities to be the primary reasons of impairment. The Partnership performed the first step of our goodwill impairment analysis as of November 30, 2014 and determined that the carrying value of the Appalachia Reporting Unit exceeded its fair value. The Partnership completed the second step of its goodwill impairment analysis comparing the implied fair value of that reporting unit's goodwill to the carrying amount of that goodwill and determined goodwill related to the Appalachia Reporting Unit was fully impaired and recorded an impairment charge of $62.4 million.

In completing this evaluation, management's best estimates of the expected future results are the primary driver in determining the fair value. Fair value determinations require considerable judgment and are sensitive to changes in underlying assumptions and factors. As a result, there can be no assurance that the estimates and assumptions made for purposes of the annual goodwill impairment test will prove to be an accurate prediction of the future. Management estimated the fair value of the Partnership's reporting units primarily using an income approach based on discounted future cash flows using significant unobservable inputs (Level 3).

There were no impairments recorded related to the Partnership's other reporting units as a result of its analyses as of November 30, 2014 for the year ended December 31, 2014. The Partnership did not record any impairment losses in the years ended December 31, 2013 and 2012.

Intangible Assets. The Partnership's intangible assets as of December 31, 2014 and 2013 are comprised of customer contracts and relationships, as follows (in thousands):

Estimated future amortization expense related to the intangible assets at December 31, 2014 is as follows (in thousands):

Accrued liabilities as of December 31, 2014 and 2013 consist of the following (in thousands):

Other long-term liabilities as of December 31, 2014 and 2013 consist of the following (in thousands):

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

The following is a reconciliation of the changes in the asset retirement obligation from January 1, 2013 to December 31, 2014 (in thousands):

At December 31, 2014, 2013 and 2012, there were no assets legally restricted for purposes of settling asset retirement obligations. The asset retirement obligation has been recorded as part of Other long-term liabilities in the accompanying Consolidated Balance Sheets.

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

	December 31, 2014		December 31, 2013

Credit Facility
Revolving credit facility, variable interest, due March 2019(1)	$	97,600	$	—
Senior Notes
2020 Senior Notes, 6.75% interest, issued November 2010 and due November 2020		500,000		500,000
2021 Senior Notes, 6.5% interest, net of discount of $413 and $474, respectively, issued February and March 2011 and due August 2021		324,587		324,526
2022 Senior Notes, 6.25% interest, issued October 2011 and due June 2022		455,000		455,000
2023A Senior Notes, 5.5% interest, net of discount of $5,783 and $6,455, respectively, issued August 2012 and due February 2023		744,217		743,545
2023B Senior Notes, 4.5% interest, issued January 2013 and due July 2023		1,000,000		1,000,000
2024 Senior Notes, 4.875% interest, issued November 2014 and due December 2024		500,000		—

Total long-term debt	$	3,621,404	$	3,023,071

On March 20, 2014, the Partnership amended the Credit Facility to increase total borrowing capacity to $1.3 billion, extend the maturity by approximately 18 months to March 20, 2019, amend the pricing terms, expand the existing accordion option from $250 million to $500 million and provide the Partnership with the right to release the collateral securing the Credit Facility. The right to release collateral will occur once the Partnership's long-term, senior unsecured debt ("Index Debt") has received an investment grade rating from Standard & Poor's equal to or more favorable than BBB– (stable) and from Moody's equal to or more favorable than Baa3 (stable) and the Partnership's Total Leverage Ratio (as defined in the Credit Facility) is not greater than 5.00 to 1.00 ("Collateral Release

Date"). The Partnership incurred approximately $2.0 million, $0 million and $2.5 million of deferred financing costs associated with modifications of the Credit Facility during the years ended December 31, 2014, 2013 and 2012, respectively.

The borrowings under the Credit Facility bear interest at a variable interest rate, plus a margin. The variable interest rate is based either on the London interbank market rate ("LIBO Rate Loans") or the higher of (a) the prime rate set by the Credit Facility's administrative agent, (b) the Federal Funds Rate plus 0.50% and (c) the rate for LIBO Rate Loans for a one month interest period plus 1% ("Alternate Base Rate Loans"). Prior to the Collateral Release Date, the margin is determined by the Partnership's Total Leverage Ratio, ranging from 0.5% to 1.5% for Alternate Base Rate Loans and from 1.5% to 2.5% for LIBO Rate Loans. After the Collateral Release Date, the margin is determined by the credit rating for the Partnership's Index Debt issued by Moody's and Standard & Poor's, ranging from 0.125% to 1% for Alternate Base Rate Loans and from 1.125% to 2% for LIBO Rate Loans. The Partnership may utilize up to $150.0 million of the Credit Facility for the issuance of letters of credit and $10.0 million for shorter-term swingline loans.

Under the provisions of the Credit Facility and indentures, the Partnership is subject to a number of restrictions and covenants. The Credit Facility and indentures place limits on the ability of the Partnership and its restricted subsidiaries to incur additional indebtedness; declare or pay dividends or distributions or redeem, repurchase or retire equity interests or subordinated indebtedness; make investments; incur liens; create any consensual limitation on the ability of the Partnership's restricted subsidiaries to pay dividends or distributions, make loans or transfer property to the Partnership; engage in transactions with the Partnership's affiliates; sell assets, including equity interests of the Partnership's subsidiaries; make any payment on or with respect to or purchase, redeem, defease or otherwise acquire or retire for value any subordinated obligation or guarantor subordination obligation (except principal and interest at maturity); and consolidate, merge or transfer assets. The Credit Facility also limits the Partnership's ability to enter into transactions with parties that require margin calls under certain derivative instruments. Under the Credit Facility, neither the Partnership nor the bank can require margin calls for outstanding derivative positions.

Significant financial covenants under the Credit Facility include the Interest Coverage Ratio (as defined in the Credit Facility), which must be greater than 2.50 to 1.0 and the Total Leverage Ratio (as defined in the Credit Facility), which must be less than 5.5 to 1.0 prior to January 1, 2015, and thereafter until the Collateral Release Date the maximum permissible Total Leverage Ratio will be 5.25 to 1.0. In February 2015, we entered into an amendment which permanently increases our maximum permissible total leverage ratio to 5.5 to 1. The Total Leverage Ratio at any fiscal quarter-end on or after the Collateral Release Date shall not be greater than 5.00 to 1.00.

As of December 31, 2014, the Partnership was in compliance with these financial covenants. These covenants are used to calculate the available borrowing capacity on a quarterly basis. The Credit Facility is guaranteed by and collateralized by substantially all assets of the Partnership's wholly-owned subsidiaries, other than MarkWest Liberty Midstream and its subsidiaries. As of December 31, 2014, the Partnership had approximately $97.6 million borrowings outstanding and $11.3 million of letters of credit outstanding under the Credit Facility, leaving approximately $1,191.1 million available for borrowing all of which was available for borrowing based on financial covenant requirements. Additionally, the full amount of unused capacity is available for borrowing on a short-term basis to provide financial flexibility within a given fiscal quarter.

2018 Senior Notes. In April 2008, the partnership and its wholly- owned subsidiary, MarkWest Energy Finance Corporation (the "Issuers") completed a private placement, subsequently registered, of $400.0 million in aggregate principal amount of 8.75% senior unsecured notes to qualified institutional buyers under Rule 144A. In May 2008, the Partnership completed the placement of an additional $100.0 million pursuant to the indenture to the 2018 Senior Notes. The notes issued in the April 2008 and May 2008 offerings are treated as a single class of debt under this same indenture. Approximately $253.3 million and $165.6 million of the 2018 Senior Notes were redeemed in the fourth quarter and first quarter of 2011, respectfully. The Partnership received combined proceeds of approximately $488.5 million, after including initial purchasers' premium and deducting the underwriting fees and third-party expenses associated with the offering. The 2018 Senior Notes were repaid in February 2013.

2020 Senior Notes. In November 2010, the Issuers completed a public offering of $500.0 million in aggregate principal amount of 6.75% senior unsecured notes. The 2020 Senior Notes mature on November 1, 2020 and interest is payable semi-annually in arrears on May 1 and November 1. The Partnership received proceeds of approximately $490.3 million after deducting the underwriting fees and the third-party expenses associated with the offering.

2021 Senior Notes. On February 24, 2011, the Issuers completed a public offering of $300.0 million in aggregate principal amount of 6.5% senior unsecured notes, which were issued at par. On March 10, 2011, the Issuers completed a follow-on public offering of an additional $200.0 million in aggregate principal amount of 2021 Senior Notes, which were issued at 99.5% of par and are treated as a single class of debt securities under the same indenture as the 2021 Senior Notes issued on February 24, 2011. The 2021 Senior Notes mature in August 2021 and interest is payable semi-annually in arrears on February 15 and August 15. The Partnership received aggregate net proceeds of approximately $492.4 million from the 2021 Senior Notes offerings after deducting the underwriting fees and third-party expenses associated with the offerings. The Partnership repaid approximately $175.0 million of the 2021 Senior Notes in February 2013.

2022 Senior Notes. On November 3, 2011, the Issuers completed a public offering of $700.0 million in aggregate principal amount of 6.25% senior unsecured notes due June 2022. Interest on the 2022 Notes is payable semi-annually in arrears on June 15 and December 15, commencing June 15, 2012. The Partnership received aggregate net proceeds of approximately $688.5 million from the 2022 Senior Notes offerings, after deducting the underwriting fees and third-party expenses. The Partnership repaid approximately $245.0 million of the 2021 Senior Notes in February 2013.

2023A Senior Notes. On August 10, 2012, the Issuers completed a public offering of $750.0 million in aggregate principal amount of 5.5% senior unsecured notes due February 2023. Interest on the 2023A Senior Notes is payable semi-annually in arrears on February 15 and August 15, commencing February 15, 2013. The Partnership received aggregate net proceeds of approximately $730.2 million from the 2023A Senior Notes offerings, after deducting the underwriting fees and third-party expenses.

2023B Senior Notes. In January 2013, the Partnership completed a public offering for $1.0 billion in aggregate principal amount of 4.5% senior unsecured notes due July 2023. Interest on the 2023B Senior Notes is payable semi-annually in arrears on January 15 and July 15, commencing July 15, 2013.

The Partnership received aggregate net proceeds of approximately $986.0 million from the 2023B Senior Notes offerings, after deducting underwriting fees and third-party expenses.

2024 Senior Notes. In November 2014, the Partnership completed a public offering for $500.0 million in aggregate principal amount of 4.875% senior unsecured notes due December 2024. Interest on the 2024 Senior Notes is payable semi-annually in arrears on June 1 and December 1, commencing June 1, 2015. The Partnership received aggregate net proceeds of approximately $493.8 million from the 2024 Senior Notes offerings, after deducting underwriting fees and third-party expenses.

The proceeds from the issuance of the 2021 and 2022 Senior Notes were used to redeem $275.0 million in aggregate principal amount of 2016 Senior Notes and $419.0 million in aggregate principal amount of 2018 Senior Notes and to provide additional working capital for general partnership purposes. The proceeds from the issuance of the 2020 Senior Notes were used to redeem the 2014 Senior Notes, repay the Credit Facility and to provide additional working capital for general partnership purposes. The proceeds from the issuance of the 2023A Senior Notes were used to repay borrowings under our Credit Facility, fund capital expenditures and provide additional working capital for general partnership purposes. The proceeds from the 2023B Senior Notes were used to repurchase the $81.1 million of the 2018 Senior Notes, approximately $175.0 million of the 2021 Senior Notes and approximately $245.0 million of the 2022 Senior Notes and to fund capital expenditures and provide general working capital. The proceeds from the 2024 Senior Notes were used to repay borrowings under our Credit Facility, fund capital expenditures and provide additional working capital for general partnership purposes.

The Partnership recorded a total pre-tax loss during 2013 of approximately $38.5 million related to repurchases of the $81.1 million of the 2018 Senior Notes, approximately $175.0 million of the 2021 Senior Notes and approximately $245.0 million of the 2022 Senior Notes. The pre-tax loss consisted of approximately $7.0 million related to the non-cash write-off of the unamortized discount and deferred finance costs and approximately $31.5 million related to the payment of redemption premiums. The loss was recorded in Loss on redemption of debt in the accompanying Consolidated Statements of Operations.

The Issuers have no independent operating assets or operations. All subsidiaries that are owned 100% by the Partnership, other than MarkWest Energy Finance Corporation and MarkWest Liberty Midstream and its subsidiaries, guarantee the Senior Notes, jointly and severally and fully and unconditionally, subject to certain customary release provisions, including:

Subsidiaries that are not 100% owned by the Partnership do not guarantee the Senior Notes (see Note 25 for required consolidating financial information). The Senior Notes are senior unsecured obligations equal in right of payment with all of the Partnership's existing and future senior debt. The Senior Notes are senior in right of payment to all of the Partnership's future subordinated debt but effectively junior in right of payment to its secured debt to the extent of the assets securing the debt, including the Partnership's obligations in respect of the Credit Facility.

The indentures governing the Senior Notes limit the activity of the Partnership and the restricted subsidiaries identified in the indentures. Subject to compliance with certain covenants, the Partnership may issue additional notes from time to time under the indentures. If at any time the Senior Notes are rated investment grade by both Moody's Investors Service, Inc. and Standard & Poor's Rating Services and no default (as defined in the indentures) has occurred and is continuing, many of such covenants will terminate, in which case the Partnership and its subsidiaries will cease to be subject to such terminated covenants.

As of December 31, 2014, there are no minimum principal payments on the Senior Notes due during the next five years.

The Partnership Agreement stipulates the circumstances under which the Partnership is authorized to issue new capital, maintain capital accounts and distribute cash and contains specific provisions for the allocation of net income and losses to each of the partners for purposes of maintaining their respective partner capital accounts.

The Partnership distributes all of its Available Cash, including the Available Cash of its subsidiaries, to all common unitholders of record within 45 days after the end of each quarter. Available Cash is generally defined as all cash and cash equivalents of the Partnership on hand at the end of each quarter, less reserves established by the general partner for future requirements, plus all cash for the quarter from working capital borrowings made after the end of the quarter. The general partner has the discretion to establish cash reserves that are necessary or appropriate to (i) provide for the proper conduct of the Partnership's business; (ii) comply with applicable law, any debt instruments or other agreements; or (iii) provide funds for distributions to unitholders and the general partner for up to the next four quarters. 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. Class B units are not entitled to participate in any distributions of Available Cash prior to their conversion into common units.

The quarterly cash distributions applicable to 2014, 2013 and 2012 were as follows:

Quarter Ended	Distribution Per Common Unit		Declaration Date	Record Date	Payment Date

December 31, 2014	$	0.90	January 21, 2015	February 5, 2015	February 13, 2015
September 30, 2014	$	0.89	October 22, 2014	November 5, 2014	November 14, 2014
June 30, 2014	$	0.88	July 24, 2014	August 5, 2014	August 14, 2014
March 31, 2014	$	0.87	April 22, 2014	May 7, 2014	May 15, 2014
December 31, 2013	$	0.86	January 22, 2014	February 6, 2014	February 14, 2014
September 30, 2013	$	0.85	October 23, 2013	November 7, 2013	November 14, 2013
June 30, 2013	$	0.84	July 24, 2013	August 6, 2013	August 14, 2013
March 31, 2013	$	0.83	April 25, 2013	May 7, 2013	May 15, 2013
December 31, 2012	$	0.82	January 23, 2013	February 6, 2013	February 14, 2013
September 30, 2012	$	0.81	October 25, 2012	November 7, 2012	November 14, 2012
June 30, 2012	$	0.80	July 26, 2012	August 6, 2012	August 14, 2012
March 31, 2012	$	0.79	April 26, 2012	May 7, 2012	May 15, 2012

The public equity offerings completed during the years ended December 31, 2014, 2013 and 2012 were as follows (in millions):

	Year ended December 31, 2012				Year ended December 31, 2013				Year ended December 31, 2014				Total

	Common units		Net Proceeds		Common units		Net Proceeds		Common units		Net Proceeds		Common units		Net Proceeds(1)
January 13, 2012(2)		0.7	$	38		—	$	—		—	$	—		0.7	$	38
March 16, 2012(2)		6.8		388		—		—		—		—		6.8		388
May 14, 2012(3)		8.0		427		—		—		—		—		8.0		427
August 17, 2012(2)		6.9		338		—		—		—		—		6.9		338
November 19, 2012(2)		9.8		437		—		—		—		—		9.8		437
November 2012 ATM(4)		0.1		6		9.3		584		—		—		9.4		590
August 2013 ATM(5)		—		—		5.9		396		—		—		5.9		396
September 2013 ATM(6)		—		—		10.9		718		4.2		272		15.1		990
March 2014 ATM(7)		—		—		—		—		17.9		1,191		17.9		1,191
November 2014 ATM(8)		—		—		—		—		2.5		175		2.5		175

Total		32.3	$	1,634		26.1	$	1,698		24.6	$	1,638		83.0	$	4,970

(4): Commencing in November 2012, the Partnership implemented the November 2012 ATM with a financial institution (the "Manager") which allowed the Partnership from time to time, through the Manager as its sales agent, to offer and sell common units representing limited partner interests in the Partnership having an aggregate offering price of up to $600.0 million. Sales of such common units were made by means of ordinary brokers' transactions on the NYSE at market prices, in block transactions or as otherwise agreed upon by the Manager and the Partnership. The Partnership could also sell common units to the Manager as principal for its own account at a price to be agreed upon at the time of the sale. For any such sales, the Partnership would enter into a separate agreement with the Manager.
(5): In August 2013, we entered into an Equity Distribution Agreement with the Manager that established the $400.0 million August 2013 ATM.
(6): In September 2013, we entered into the September 2013 ATM with the Manager that established a $1.0 billion ATM program.
(7): In March 2014, we entered into an Equity Distribution Agreement with financial institutions (the "March 2014 Managers") that established an At the Market offering program (the "March 2014 ATM") pursuant to which the Partnership sold from time to time through the March 2014 Managers, as its sales agents, common units having an aggregate offering price of up to $1.2 billion.
(8): In November 2014, we entered into an Equity Distribution Agreement with financial institutions (the "November 2014 Managers") that established an At the Market offering program (the "November 2014 ATM") pursuant to which the Partnership may sell from time to time through the November 2014 Managers, as its sales agents, common units having an aggregate offering price up to $1.5 billion.

On July 1, 2013 and July 1, 2014, approximately 4.0 million Class B units converted to common units. All of the Partnership's Class B units were issued to and are held by M&R MWE Liberty, LLC, an affiliate of EMG, as part of the Partnership's 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 next two anniversaries of such date.

The Partnership is subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its business. The Partnership maintains insurance policies in amounts and with coverage and deductibles that it believes are reasonable and prudent. However, the Partnership cannot assure that the insurance companies will promptly honor their policy obligations, or that the coverage or levels of insurance will be adequate to protect the Partnership from all material expenses related to future claims for property loss or business interruption to the Partnership, or for third-party claims of personal injury and property damage, or that the coverage or levels of insurance it currently has will be available in the future at economical prices. While it is not possible to predict the

outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the consolidated financial statements and that none of these actions, either individually or in the aggregate, will have a material adverse effect on the Partnership's financial condition, liquidity or results of operation.

Certain natural gas processing and gathering arrangements require the Partnership to construct new natural gas processing plants, natural gas gathering pipelines and NGL pipelines and contain certain fees and charges if specified construction milestones are not achieved for reasons other than force majeure. In certain cases, certain producers may have the right to cancel the processing arrangements if there are significant delays that are not due to force majeure. As of December 31, 2014, management does not believe there are any indications that the Partnership will not be able to meet the construction milestones, that force majeure does not apply, or that such fees and charges will otherwise be triggered.

The Partnership has various non-cancellable operating lease agreements and a long-term propane storage agreement expiring at various times through fiscal year 2040. Annual expense under these agreements was $32.1 million, $25.8 million and $20.8 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Partnership also executed transportation and terminalling agreements that obligate us to minimum volume, throughput or payment commitments over the terms of the agreements, which range from three to ten years. After the minimum volume commitments are met in the transportation and terminalling agreements, the Partnership pays additional amounts based on throughput. There are escalation clauses in the transportation and terminalling agreements, which are based on CPI adjustments. The minimum future payments under these agreements as of December 31, 2014 are as follows (in thousands):

On September 1, 2009, the Partnership entered into a product supply agreement creating a long-term contractual obligation for the payment of processing fees in exchange for the entire product processed by the SMR (see Note 7 for further discussion of this agreement and the related SMR Transaction). The product received under this agreement is sold to a refinery customer pursuant to a corresponding long-term agreement. The minimum amounts payable annually under the product supply agreement, excluding the potential impact of inflation adjustments per the agreement, are as follows (in thousands):

Based on the terms of certain natural gas gathering, transportation and processing agreements, the Partnership is considered to be the lessor under several implicit operating lease arrangements in accordance with GAAP. The Partnership's primary implicit lease operations relate to a natural gas gathering agreement in the Marcellus segment for which it earns a fixed-fee for providing gathering services to a single producer using a dedicated gathering system. As the gathering system is expanded, the fixed-fee charged to the producer is adjusted to include the additional gathering assets in the lease. The primary term of the natural gas gathering arrangement expires in 2024 and will continue thereafter on a year to year basis until terminated by either party. Other significant implicit leases relate to a natural gas processing agreement in the Marcellus segment and a natural gas processing agreement in the Northeast segment for which the Partnership earns minimum monthly fees for providing processing services to a single producer using a dedicated processing plant. The primary term of these natural gas processing agreements expire during 2023.

The Partnership's revenue from its implicit lease arrangements, excluding executory costs, totaled approximately $174.7 million, $122.9 million and $84.0 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Partnership's implicit lease arrangements related to the processing facilities contain contingent rental provisions whereby the Partnership receives additional fees if the producer customer exceeds the monthly minimum processed volumes. During the years ended December 31, 2014 and 2013, the Partnership received approximately $15.6 million and $16.9 million in

contingent lease payments, respectively. The following is a schedule of minimum future rentals on the non-cancellable operating leases as of December 31, 2014 (in thousands):

The following schedule provides an analysis of the Partnership's investment in assets held for operating lease by major classes as of December 31, 2014 and 2013 (in thousands):

The Partnership's compensation plan administered by the Compensation Committee of the Board ("Compensation Committee") that was active during the periods presented in the accompanying Consolidated Statements of Operations is the 2008 Long-Term Incentive Plan ("2008 LTIP"). The 2008 LTIP awards are classified as equity awards.

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

Compensation expense under the share-based compensation plans has been recorded as either Selling, general and administrative expenses or Facility expenses in the accompanying Consolidated Statements of Operations.

As of December 31, 2014, total compensation expense not yet recognized related to the unvested awards under the 2008 LTIP was approximately $14.6 million, with a weighted average remaining vesting period of approximately 0.9 years.

The 2008 LTIP was approved by unitholders on February 21, 2008. The 2008 LTIP provides 3.7 million common units for issuance to the Corporation's employees and affiliates as share-based payment awards. The 2008 LTIP was created to attract and retain highly qualified officers, directors and other key individuals and to motivate them to serve the General Partner, the Partnership and their affiliates and to expend maximum effort to improve the business results and earnings of the Partnership and its affiliates. Awards authorized under the 2008 LTIP include unrestricted units, restricted units, phantom units, DERs and performance awards to be granted in any combination.

In April 2010, the Board granted 282,000 TSR Performance Units under the 2008 LTIP to senior executives and other key employees. The TSR Performance Units are classified as equity awards and do not contain DERs. The TSR Performance Units vested in equal installments on January 31, 2011 and January 31, 2012, based on the Partnership's relative total unitholder return (unit price appreciation and distribution performance) over the three-year calendar period prior to the scheduled vesting date compared to the total unitholder return of a defined group of peer companies over the same period ("Market Criteria"). In January 2011 and 2012, 141,000 TSR Performance Units vested based on the Market Criteria and the Board exercised its discretion to issue and immediately vest an additional 35,250 units.

Compensation expense related to the TSR Performance Units that vested solely based on the Market Criteria was recognized over the requisite service period based on the fair value of the units as of the grant date. However, a grant date, as defined by GAAP, was not established for the TSR Performance Units that vest based on a combination of the Market Criteria and performance criteria until the Board exercised its discretion because the performance criteria prevents a mutual understanding of the key terms of the award. Therefore, compensation expense related to this portion of the TSR Performance Units was recognized over the requisite service period based on the fair value of the units as of each reporting date. The requisite service period for all TSR Performance Units began in April 2010 when the Board approved the awards. TSR Compensation expense recognized related to TSR Performance Units was approximately $2.2 million for the years ended December 31, 2012.

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

Awards under the 2008 LTIP qualify as equity awards. Accordingly, the fair value is measured at the grant date using the market price of the Partnership's common units. A phantom unit entitles an employee to receive a common unit upon vesting. The Partnership generally issues new common units upon vesting of phantom units. Phantom unit awards generally vest in equal tranches over a three-year period or cliff vest after three years. For service-based awards, compensation expense related to each tranche is recognized over its requisite service period, reduced for an estimate of expected forfeitures. Compensation expense related to performance-based awards is recognized when probability of vesting is established. As part of a net settlement option, employees may elect to surrender a certain number of phantom units and in exchange, the Partnership assumes the income tax withholding obligations related to the vesting. Phantom units surrendered for the payment of income tax withholdings will again become available for issuance under the plan from which the awards were initially granted, provided that further awards are authorized for issuance under the plan. The Partnership was required to pay approximately $8.9 million, $5.2 million and $8.1 million during the years ended December 31, 2014, 2013 and 2012, respectively, for income tax withholdings related to the vesting of equity awards. The Partnership received no proceeds from the issuance of phantom units and none of the phantom units that vested were redeemed by the Partnership for cash.

The following is a summary of all phantom unit activity under the 2008 LTIP for the year ended December 31, 2014:

The total fair value and intrinsic value of the phantom units vested under the 2008 LTIP was $16.8 million, $10.1 million and $10.4 million during the years ended December 31, 2014, 2013 and 2012, respectively. The total fair value and intrinsic value of the TSR Performance Units vested was zero, zero and $6.5 million during the years ended December 31, 2014, 2013 and 2012, respectively.

All employees dedicated to, or otherwise principally supporting, the Partnership are employees of MarkWest Hydrocarbon, and substantially all of these employees are participants in MarkWest Hydrocarbon's defined contribution benefit plan. The employer matching contribution expense related to this plan was $5.5 million, $4.2 million and $3.2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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

A reconciliation of the provision for income tax and the amount computed by applying the federal statutory rate of 35% to the income before income taxes for each of the years ended December 31, 2014, 2013 and 2012 is as follows (in thousands):

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

	December 31,

	2014			2013
Current deferred tax assets:
Accruals and reserves	$	208		$	221
Derivative instruments		—			4,845
Net operating loss carryforward		424			18,134
Capital loss carryforward		—			904
State tax credit		—			74

Current deferred tax assets		632			24,178
Valuation allowance		—			(978	)

Current deferred income tax assets		632			23,200

Current deferred income tax liabilities:
Derivative instruments		(862	)		—

Current deferred tax subtotal		(230	)		23,200
Long-term deferred tax assets:
Accruals and reserves		58			329
Derivative instruments		—			10,102
Phantom unit compensation		3,501			3,328
Net operating loss carryforward		48,640			9,283

Long-term deferred tax assets		52,199			23,042
Long-term deferred tax liabilities:
Property, plant and equipment and intangibles		(7,522	)		(4,755	)
Derivative instruments		(6,268	)		—
Investment in affiliated groups		(395,669	)		(305,853	)

Long-term deferred tax liabilities		(409,459	)		(310,608	)

Long-term subtotal		(357,260	)		(287,566	)

Net deferred tax liability	$	(357,490	)	$	(264,366	)

Significant judgment is required in evaluating tax positions and determining the Corporation's provision for income taxes. During the ordinary course of business, there may be transactions and calculations for which the ultimate tax determination is uncertain. However, the Corporation did not have any material uncertain tax positions for the years ended December 31, 2014, 2013 or 2012. As of December 31, 2014, the Corporation had NOL carryforwards for federal and state income tax purposes of approximately $47.8 million and $2.9 million, respectively. The federal NOL carryforwards expire in 20 years and the state NOL carryforwards expire from five to 20 years. Included in the NOL carryforwards is approximately $1.6 million attributable to tax deductions related to equity compensation in excess of compensation recognized for financial reporting. The Corporation had a capital loss carryforward of approximately $0.9 million and a state tax credit of $0.1 million, respectively, that expired in 2014. The Corporation did not anticipate utilizing the capital loss

carryforward or state tax credit and had previously provided a 100% valuation allowance against this deferred tax asset. While the Corporation's consolidated federal tax return and any significant state tax returns are not currently under examination, the tax years 2010 through 2013 remain open to examination by the major taxing jurisdictions to which the Corporation is subject.

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

The following table shows the computation of basic and diluted net income per common unit, for the years ended December 31, 2014, 2013 and 2012, respectively, and the weighted average units used to compute diluted net income per common unit (in thousands, except per unit data):

	Year ended December 31,

	2014			2013			2012
Net income attributable to the Partnership's unitholders	$	133,881		$	38,077		$	220,402
Less: Income allocable to phantom units		(2,229	)		(2,342	)		(2,142	)

Income available for common unitholders—basic		131,652			35,735			218,260
Add: Income allocable to phantom units and DER expense(1)		2,322			2,419			2,183

Income available for common unitholders—diluted	$	133,974		$	38,154		$	220,443



Weighted average common units outstanding—basic		171,009			138,409			109,979
Potential common units (Class B and phantom units)(1)		14,641			22,034			20,669

Weighted average common units outstanding—diluted		185,650			160,443			130,648



Net income attributable to the Partnership's common unitholders per common unit(2)
Basic	$	0.77		$	0.26		$	1.98
Diluted	$	0.72		$	0.24		$	1.69

The Partnership's chief operating decision maker is the chief executive officer ("CEO"). The CEO reviews the Partnership's discrete financial information on a geographic and operational basis, as the products and services are closely related within each geographic region and business operation. Accordingly, the CEO makes operating decisions, assesses financial performance and allocates resources on a geographical basis. The Partnership has the following segments: Marcellus, Utica, Northeast and Southwest. The Marcellus segment, which was referred to as the Liberty segment in prior years, has operations in Pennsylvania, Ohio and northern West Virginia. The Utica segment has operations in Ohio. The Northeast segment has operations in Kentucky, southern West Virginia and Michigan. The Southwest segment has operations in Texas, Oklahoma, Louisiana and New Mexico. All segments provide gathering, processing, transportation, fractionation and storage services. As disclosed in Note 3, Ohio Gathering was deconsolidated effective June 1, 2014 and its financial position as of December 31, 2014 and results of operations are reported under the equity method of accounting as of December 31, 2014 and for the seven months ended December 31, 2014, respectively. However, the Partnership's Chief Executive Officer and "chief operating decision maker" continues to view the Utica Segment inclusive of Ohio Gathering, and review its financial information as if it were still consolidated. The Partnership prepares segment information in accordance with GAAP. Certain items below Income from operations in the accompanying Consolidated Statements of Operations, certain compensation expense, certain other non-cash items and any gains (losses) from derivative instruments are not allocated to individual segments. Management does not consider these items allocable to or controllable by any individual segment and, therefore, excludes these items when evaluating segment performance. Segment results are also adjusted to exclude the portion of operating income attributable to the non-controlling interests.

The tables below present information about operating income and capital expenditures for the reported segments for the years ended December 31, 2014, 2013 and 2012 (in thousands):

	Marcellus		Utica		Northeast		Southwest		Elimination(1)			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		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
Segment 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



Capital expenditures	$	1,482,791	$	1,031,128	$	4,937	$	142,982	$	—		$	2,661,838
Capital expenditures for Ohio Gathering after deconsolidation(2)													(309,112	)
Capital expenditures not allocated to segments													16,989

Total capital expenditures												$	2,369,715

	Marcellus		Utica			Northeast		Southwest		Total

Segment revenue	$	527,073	$	26,442		$	204,326	$	935,426	$	1,693,267
Segment purchased product costs		100,262		—			65,192		525,711		691,165

Net operating margin		426,811		26,442			139,134		409,715		1,002,102
Segment facility expenses		108,781		35,081			28,425		127,112		299,399
Segment portion of operating (loss) income attributable to non-controlling interests		—		(3,499	)		—		21		(3,478	)

Operating income (loss) before items not allocated to segments	$	318,030	$	(5,140	)	$	110,709	$	282,582	$	706,181



Capital expenditures	$	1,613,580	$	1,242,158		$	4,586	$	175,565	$	3,035,889
Capital expenditures not allocated to segments											11,067

Total capital expenditures										$	3,046,956

	Marcellus		Utica			Northeast		Southwest		Total

Segment revenue	$	319,867	$	571		$	225,818	$	842,958	$	1,389,214
Segment purchased product costs		74,024		—			68,402		387,902		530,328

Net operating margin		245,843		571			157,416		455,056		858,886
Segment facility expenses		65,825		3,968			24,106		122,691		216,590
Segment portion of operating (loss) income attributable to non-controlling interests		—		(1,359	)		—		176		(1,183	)

Operating income (loss) before items not allocated to segments	$	180,018	$	(2,038	)	$	133,310	$	332,189	$	643,479



Capital expenditures	$	1,458,323	$	233,018		$	84,542	$	169,440	$	1,945,323
Capital expenditures not allocated to segments											5,001

Total capital expenditures										$	1,950,324

The following is a reconciliation of segment revenue to total revenue and operating income before items not allocated to segments to income before provision for income tax for the three years ended December 31, 2014, 2013 and 2012 (in thousands):

	Year ended December 31,

	2014			2013			2012
Total segment revenue	$	2,167,808		$	1,693,267		$	1,389,214
Derivative gain (loss) not allocated to segments		40,151			(24,638	)		56,535
Revenue adjustment for unconsolidated affiliate(1)		(41,446	)		—			—
Revenue deferral adjustment and other(2)		9,660			(6,182	)		(5,935	)

Total revenue	$	2,176,173		$	1,662,447		$	1,439,814



Operating income before items not allocated to segments	$	935,412		$	706,181		$	643,479
Portion of operating income (loss) attributable to non-controlling interests		21,425			(3,478	)		(1,183	)
Derivative gain (loss) not allocated to segments		95,266			(25,770	)		69,126
Revenue adjustment for unconsolidated affiliate(1)		(41,446	)		—			—
Revenue deferral adjustment and other(2)		4,455			(6,182	)		(5,935	)
Compensation expense included in facility expenses not allocated to segments		(3,932	)		(2,421	)		(1,022	)
Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliate(3)		19,559			—			—
Portion of operating income attributable to non-controlling interests of an unconsolidated affiliate(4)		14,008			—			—
Facility expenses adjustments(5)		10,751			10,751			10,751
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
(Loss) earnings from unconsolidated affiliates		(4,477	)		1,422			2,328
Interest expense		(166,372	)		(151,851	)		(120,191	)
Amortization of deferred financing costs and discount (a component of interest expense)		(7,289	)		(6,726	)		(5,601	)
Loss on redemption of debt		—			(38,455	)		—
Miscellaneous income, net		3,440			2,781			481

Income before provision for income tax	$	202,522		$	53,114		$	255,293

(2): Revenue deferral amount relates to certain contracts in which the cash consideration that the Partnership receives for providing service is greater during the initial years of the contract compared to the later years. In accordance with GAAP, the revenue is recognized evenly over the term of the contract as the Partnership expects to perform a similar level of service for the entire term; therefore, the revenue recognized in the current reporting period is less than the cash received. However, the chief operating decision maker and management evaluate the segment performance based on the cash consideration received and, therefore, the impact of the revenue deferrals is excluded for segment reporting purposes. For the year ended December 31, 2014, approximately $6.2 million and $0.8 million of the revenue deferral adjustment is attributable to the Northeast segment and Southwest segment, respectively. For the year ended December 31, 2013, approximately $6.4 million and $0.8 million of the revenue deferral adjustment is attributable to the Northeast segment and Southwest segment, respectively. For the year ended December 31, 2012, approximately $6.6 million and $0.8 million of the revenue deferral adjustment is attributable to the Northeast segment and Southwest segment, respectively. Beginning in the first half of 2015, the cash consideration received from these contracts is expected to decline and the reported segment revenue will be less than the revenue recognized for GAAP purposes. Other consists of management revenues from an unconsolidated affiliate of $16.5 million, $1.0 million, and $1.5 million for the years ended December 31, 2014, 2013, and 2012, respectively.
(3): Facility expense, operational service fees and purchased product cost adjustments for unconsolidated affiliate consist of the facility expenses and purchased product costs related to Ohio Gathering for the seven months ended December 31, 2014 (See note (1) above and Note 3 of these Notes to the Consolidated Financial Statements).
(4): Portion of operating loss attributable to non-controlling interests of an unconsolidated affiliate amount relates to Summit's portion of Ohio Gathering's operating income, which is included in segment operating income calculation as if Ohio Gathering is consolidated (See note (1) above and Note 3 of these Notes to the Consolidated Financial Statements).
(5): Facility expenses adjustments consist of the reallocation of the interest expense related to the SMR, which is included in facility expenses for the purposes of evaluating the performance of the Southwest segment.

The tables below present information about segment assets as of December 31, 2014 and 2013 (in thousands):

MarkWest Energy Partners has no significant operations independent of its subsidiaries. As of December 31, 2014, the Partnership's obligations under the outstanding Senior Notes (see Note 17) were fully, jointly and severally guaranteed, by all of the subsidiaries that are owned 100% by the Partnership, other than MarkWest Liberty Midstream and its subsidiaries. The guarantees are unconditional except for certain customary circumstances in which a subsidiary would be released from the guarantee under the indentures (see Note 17 for these circumstances). Subsidiaries that are not 100% owned by the Partnership do not guarantee the Senior Notes. For the purpose of the following financial information, the Partnership's investments in its subsidiaries and the guarantor subsidiaries' investments in their subsidiaries are presented in accordance with the equity method of accounting. The co-issuer, MarkWest Energy Finance Corporation, has no independent assets or operations. Condensed consolidating financial information for MarkWest Energy Partners and its combined guarantor and

combined non-guarantor subsidiaries as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 is as follows (in thousands):

	As of December 31, 2014

	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	—	$	—	$	108,887	$	—		$	108,887
Restricted cash		—		—		20,000		—			20,000
Receivables and other current assets		1,219		225,695		153,834		—			380,748
Receivables from unconsolidated affiliates, net		247		3,001		3,849		—			7,097
Intercompany receivables		633,994		24,683		178,109		(836,786	)		—
Fair value of derivative instruments		—		17,386		3,535		—			20,921

Total current assets		635,460		270,765		468,214		(836,786	)		537,653
Total property, plant and equipment, net		9,992		2,140,565		6,550,040		(47,697	)		8,652,900
Other long-term assets:
Investment in unconsolidated affiliates		—		82,616		733,226		(10,209	)		805,633
Investment in consolidated affiliates		7,990,532		6,500,008		—		(14,490,540	)		—
Intangibles, net of accumulated amortization		—		546,637		262,640		—			809,277
Fair value of derivative instruments		—		16,507		—		—			16,507
Intercompany notes receivable		186,100		—		—		(186,100	)		—
Other long-term assets		52,825		29,412		76,571		—			158,808

Total assets	$	8,874,909	$	9,586,510	$	8,090,691	$	(15,571,332	)	$	10,980,778



LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	3,287	$	729,714	$	103,787	$	(836,788	)	$	—
Payables to unconsolidated affiliates		—		—		8,621		—			8,621
Other current liabilities		69,552		177,269		386,821		(2,400	)		631,242

Total current liabilities		72,839		906,983		499,229		(839,188	)		639,863
Deferred income taxes		6,162		351,098		—		—			357,260
Long-term intercompany financing payable		—		186,100		95,061		(281,161	)		—
Long-term debt, net of discounts		3,621,404		—		—		—			3,621,404
Other long-term liabilities		8,794		151,797		8,421		—			169,012
Equity:
Common Units		4,714,191		7,990,532		7,487,980		(15,434,460	)		4,758,243
Class B Units		451,519		—		—		—			451,519
Non-controlling interest in consolidated subsidiaries		—		—		—		983,477			983,477

Total equity		5,165,710		7,990,532		7,487,980		(14,450,983	)		6,193,239

Total liabilities and equity	$	8,874,909	$	9,586,510	$	8,090,691	$	(15,571,332	)	$	10,980,778

	As of December 31, 2013

	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
Current assets:
Cash and cash equivalents	$	224	$	79,363	$	5,718	$	—		$	85,305
Restricted cash		—		—		10,000		—			10,000
Receivables and other current assets		6,248		266,610		117,517		—			390,375
Receivables from unconsolidated affiliates, net		—		—		17,363		—			17,363
Intercompany receivables		1,194,955		78,010		125,115		(1,398,080	)		—
Fair value of derivative instruments		—		10,444		1,013		—			11,457

Total current assets		1,201,427		434,427		276,726		(1,398,080	)		514,500
Total property, plant and equipment, net		5,379		2,149,845		5,622,602		(84,657	)		7,693,169
Other long-term assets:
Restricted cash		—		—		10,000		—			10,000
Investment in unconsolidated affiliates		—		75,627		—		—			75,627
Investment in consolidated affiliates		5,741,374		4,541,617		—		(10,282,991	)		—
Intangibles, net of accumulated amortization		—		595,995		278,797		—			874,792
Fair value of derivative instruments		—		505		—		—			505
Intercompany notes receivable		151,200		—		—		(151,200	)		—
Other long-term assets		52,338		92,276		83,216		—			227,830

Total assets	$	7,151,718	$	7,890,292	$	6,271,341	$	(11,916,928	)	$	9,396,423



LIABILITIES AND EQUITY
Current liabilities:
Intercompany payables	$	—	$	1,315,707	$	82,373	$	(1,398,080	)	$	—
Fair value of derivative instruments		—		26,382		2,456		—			28,838
Other current liabilities		58,110		199,146		583,810		(2,131	)		838,935

Total current liabilities		58,110		1,541,235		668,639		(1,400,211	)		867,773
Deferred income taxes		3,407		284,159		—		—			287,566
Long-term intercompany financing payable		—		151,200		97,461		(248,661	)		—
Fair value of derivative instruments		—		27,763		—		—			27,763
Long-term debt, net of discounts		3,023,071		—		—		—			3,023,071
Other long-term liabilities		3,745		144,561		8,194		—			156,500
Redeemable non-controlling interest		—		—		—		235,617			235,617
Equity:
Common Units		3,461,360		5,741,374		5,497,047		(11,223,486	)		3,476,295
Class B Units		602,025		—		—		—			602,025
Non-controlling interest in consolidated subsidiaries		—		—		—		719,813			719,813

Total equity		4,063,385		5,741,374		5,497,047		(10,503,673	)		4,798,133

Total liabilities and equity	$	7,151,718	$	7,890,292	$	6,271,341	$	(11,916,928	)	$	9,396,423

	Year ended December 31, 2014

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	1,301,713		$	911,768		$	(37,308	)	$	2,176,173
Operating expenses:
Purchased product costs		—			602,515			171,521			—			774,036
Facility expenses		—			158,178			191,007			(2,546	)		346,639
Selling, general and administrative expenses		49,572			45,261			44,765			(13,099	)		126,499
Depreciation and amortization		1,169			200,198			291,224			(4,943	)		487,648
Impairment of goodwill		—			62,445			—			—			62,445
Other operating expenses		—			(90	)		7,046			(5,270	)		1,686

Total operating expenses		50,741			1,068,507			705,563			(25,858	)		1,798,953

(Loss) income from operations		(50,741	)		233,206			206,205			(11,450	)		377,220
Earnings from consolidated affiliates		334,328			164,964			—			(499,292	)		—
Other expense, net		(173,758	)		(24,450	)		(14,820	)		38,330			(174,698	)

Income before provision for income tax		109,829			373,720			191,385			(472,412	)		202,522
Provision for income tax expense		(2,827	)		(39,392	)		—			—			(42,219	)

Net income		107,002			334,328			191,385			(472,412	)		160,303
Net income attributable to non-controlling interest		—			—			—			(26,422	)		(26,422	)

Net income attributable to the Partnership's unitholders	$	107,002		$	334,328		$	191,385		$	(498,834	)	$	133,881

	Year ended December 31, 2013

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	1,161,145		$	550,181		$	(48,879	)	$	1,662,447
Operating expenses:
Purchased product costs		—			588,670			100,758			—			689,428
Facility expenses		—			148,492			146,649			(1,203	)		293,938
Selling, general and administrative expenses		46,732			29,855			32,512			(7,550	)		101,549
Depreciation and amortization		847			183,610			185,810			(5,739	)		364,528
Other operating expenses		—			4,907			(39,926	)		2,080			(32,939	)

Total operating expenses		47,579			955,534			425,803			(12,412	)		1,416,504

(Loss) income from operations		(47,579	)		205,611			124,378			(36,467	)		245,943
Earnings from consolidated affiliates		276,995			110,763			—			(387,758	)		—
Loss on redemption of debt		(38,455	)		—			—			—			(38,455	)
Other expense, net		(161,975	)		(26,749	)		(11,247	)		45,597			(154,374	)

Income before provision for income tax		28,986			289,625			113,131			(378,628	)		53,114
Provision for income tax expense		(39	)		(12,630	)		—			—			(12,669	)

Net income		28,947			276,995			113,131			(378,628	)		40,445
Net income attributable to non-controlling interest		—			—			—			(2,368	)		(2,368	)

Net income attributable to the Partnership's unitholders	$	28,947		$	276,995		$	113,131		$	(380,996	)	$	38,077

	Year ended December 31, 2012

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Total revenue	$	—		$	1,125,368		$	324,738		$	(10,292	)	$	1,439,814
Operating expenses:
Purchased product costs		—			441,853			74,513			—			516,366
Facility expenses		—			137,261			71,138			(167	)		208,232
Selling, general and administrative expenses		48,949			19,069			29,674			(4,248	)		93,444
Depreciation and amortization		607			164,858			75,599			(4,494	)		236,570
Other operating expenses		2			4,341			2,583			—			6,926

Total operating expenses		49,558			767,382			253,507			(8,909	)		1,061,538

(Loss) income from operations		(49,558	)		357,986			71,231			(1,383	)		378,276
Earnings from consolidated affiliates		366,460			66,114			—			(432,574	)		—
Other expense, net		(118,563	)		(21,001	)		(8,554	)		25,135			(122,983	)

Income before provision for income tax		198,339			403,099			62,677			(408,822	)		255,293
Provision for income tax expense		(1,689	)		(36,639	)		—			—			(38,328	)

Net income		196,650			366,460			62,677			(408,822	)		216,965
Net income attributable to non-controlling interest		—			—			—			3,437			3,437

Net income attributable to the Partnership's unitholders	$	196,650		$	366,460		$	62,677		$	(405,385	)	$	220,402

	Year ended December 31, 2014

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(186,872	)	$	455,558		$	383,033		$	16,680		$	668,399
Cash flows from investing activities:
Capital expenditures		(5,755	)		(157,403	)		(2,187,824	)		(18,733	)		(2,369,715	)
Equity investments in consolidated affiliates		(64,890	)		(2,177,092	)		—			2,241,982			—
Intercompany advances, net		(1,430,429	)		—			—			1,430,429			—
Investment in unconsolidated affiliates		—			(13,008	)		(250,997	)		—			(264,005	)
Distributions from consolidated affiliates		103,100			382,756			—			(485,856	)		—
Investment in intercompany notes receivable, net		(34,900	)		—			—			34,900			—
Proceeds from sale of interest in unconsolidated affiliates		—			—			341,137			—			341,137
Proceeds from disposal of property, plant and equipment		—			5,089			17,398			—			22,487

Net cash flows used in investing activities		(1,432,874	)		(1,959,658	)		(2,080,286	)		3,202,722			(2,270,096	)

Cash flows from financing activities:
Proceeds from public equity offerings, net		1,638,090			—			—			—			1,638,090
Proceeds from Credit Facility		3,151,500			—			—			—			3,151,500
Payments of Credit Facility		(3,053,900	)		—			—			—			(3,053,900	)
Proceeds from long-term debt		500,000			—			—			—			500,000
Payments related to intercompany financing, net		—			34,900			(2,131	)		(32,769	)		—
Payments for debt issuance costs and deferred financing costs		(8,201	)		—			—			—			(8,201	)
Contributions from non-controlling interest		—			—			15,400			—			15,400
Contributions from parent and affiliates		—			64,890			2,177,092			(2,241,982	)		—
Payments of SMR liability		—			(2,460	)		—			—			(2,460	)
Share-based payment activity		(8,947	)		—			—			—			(8,947	)
Payment of distributions		(599,020	)		(103,100	)		(389,939	)		485,856			(606,203	)
Intercompany advances, net		—			1,430,507			—			(1,430,507	)		—

Net cash flows provided by financing activities		1,619,522			1,424,737			1,800,422			(3,219,402	)		1,625,279

Net (decrease) increase in cash and cash equivalents		(224	)		(79,363	)		103,169			—			23,582
Cash and cash equivalents at beginning of year		224			79,363			5,718			—			85,305

Cash and cash equivalents at end of period	$	—		$	—		$	108,887		$	—		$	108,887

	Year ended December 31, 2013

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(178,266	)	$	368,551		$	222,107		$	23,258		$	435,650
Cash flows from investing activities:
Restricted cash		—			—			15,500			—			15,500
Capital expenditures		(789	)		(182,339	)		(2,838,677	)		(25,151	)		(3,046,956	)
Equity investments in consolidated affiliates		(59,468	)		(2,200,000	)		—			2,259,468			—
Intercompany advances, net		(1,824,310	)		—			—			1,824,310			—
Acquisition of business, net of cash acquired		—			(222,888	)		—			—			(222,888	)
Investment in unconsolidated affiliates		—			(17,521	)		—			—			(17,521	)
Distributions from consolidated affiliates		95,548			517,635			—			(613,183	)		—
Investment in intercompany notes receivable, net		73,800			—			—			(73,800	)		—
Proceeds from disposal of property, plant and equipment		—			757			208,546			—			209,303

Net cash flows used in investing activities		(1,715,219	)		(2,104,356	)		(2,614,631	)		3,371,644			(3,062,562	)

Cash flows from financing activities:
Proceeds from public equity offerings, net		1,698,066			—			—			—			1,698,066
Proceeds from long-term debt		1,000,000			—			—			—			1,000,000
Payments of long-term debt		(501,112	)		—			—			—			(501,112	)
Payments related to intercompany financing, net		—			(73,800	)		(1,893	)		75,693			—
Payments of premiums on redemption of long-term debt		(31,516	)		—			—			—			(31,516	)
Payments for debt issuance costs, deferred financing costs and registration costs		(14,046	)		—			—			—			(14,046	)
Contributions from parent and affiliates		—			59,468			2,200,000			(2,259,468	)		—
Contribution from non-controlling interest		—			—			685,219			—			685,219
Payments of SMR liability		—			(2,241	)		—			—			(2,241	)
Share-based payment activity		(5,210	)		—			—			—			(5,210	)
Payment of distributions		(462,488	)		(95,548	)		(517,846	)		613,183			(462,699	)
Intercompany advances, net		—			1,824,310			—			(1,824,310	)		—

Net cash flows provided by financing activities		1,683,694			1,712,189			2,365,480			(3,394,902	)		2,366,461

Net decrease in cash and cash equivalents		(209,791	)		(23,616	)		(27,044	)		—			(260,451	)
Cash and cash equivalents at beginning of year		210,015			102,979			32,762			—			345,756

Cash and cash equivalents at end of period	$	224		$	79,363		$	5,718		$	—		$	85,305

	Year ended December 31, 2012

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net cash (used in) provided by operating activities	$	(154,328	)	$	468,671		$	158,412		$	19,258		$	492,013
Cash flows from investing activities:
Restricted cash		—			—			(9,497	)		—			(9,497	)
Capital expenditures		(138	)		(304,190	)		(1,626,809	)		(19,187	)		(1,950,324	)
Equity investments in consolidated affiliates		(55,283	)		(1,880,279	)		—			1,935,562			—
Intercompany advances, net		(1,591,329	)								1,591,329			—
Acquisition of business, net of cash acquired		—			—			(506,797	)		—			(506,797	)
Investment in unconsolidated affiliates		—			(5,227	)		—			(839	)		(6,066	)
Distributions from consolidated affiliates		75,431			140,362			—			(215,793	)		—
Investment in intercompany notes receivable, net		(12,300	)		—			—			12,300			—
Proceeds from disposal of property, plant and equipment		—			1,732			77			(1,213	)		596

Net cash flows used in investing activities		(1,583,619	)		(2,047,602	)		(2,143,026	)		3,302,159			(2,472,088	)

Cash flows from financing activities:
Proceeds from public equity offerings, net		1,634,081			—			—			—			1,634,081
Proceeds from Credit Facility		511,100			—			—			—			511,100
Payments of Credit Facility		(577,100	)		—			—			—			(577,100	)
Proceeds from long-term debt		742,613			—			—			—			742,613
Proceeds (payments) related to intercompany financing, net		—			12,300			(1,142	)		(11,158	)		—
Payments for debt issue costs and deferred financing costs		(14,720	)		—			—			—			(14,720	)
Contributions from parent and affiliates		—			55,283			1,879,440			(1,934,723	)		—
Contribution from non-controlling interest		—			—			264,781			—			264,781
Payments of SMR liability		—			(2,058	)		—			—			(2,058	)
Share-based payment activity		(8,067	)		907			—			—			(7,160	)
Payment of distributions		(339,967	)		(75,431	)		(140,433	)		215,793			(340,038	)
Intercompany advances, net		—			1,591,329			—			(1,591,329	)		—

Net cash flows provided by financing activities		1,947,940			1,582,330			2,002,646			(3,321,417	)		2,211,499

Net increase in cash and cash equivalents		209,993			3,399			18,032			—			231,424
Cash and cash equivalents at beginning of year		22			99,580			14,730			—			114,332

Cash and cash equivalents at end of period	$	210,015		$	102,979		$	32,762		$	—		$	345,756

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

The following summarizes the Partnership's quarterly results of operations for 2014 and 2013 (in thousands, except per unit data):

ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

The Partnership's management, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures, as defined in Rule 13a-15(e) of the 1934 Act, as of December 31, 2014. Based on this evaluation, the Partnership's management, including our Chief Executive Officer and Chief Financial Officer, concluded that as of December 31, 2014, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by us in the reports that we file or submit under the 1934 Act is recorded, processed, summarized, and reported within the time periods specified in the SEC's rules and forms and to provide reasonable assurance that such information is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate to allow timely decisions regarding required disclosures.

Management, under the supervision and with the participation of the Chief Executive Officer and Chief Financial Officer, of the Partnership is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rule 13a-15(f) of the 1934 Act. Management has assessed the effectiveness of our internal control over financial reporting as of December 31, 2014 based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that, as of December 31, 2014, our internal control over financial reporting was effective in providing reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

Management has designed our disclosure controls and procedures and internal control over financial reporting to provide reasonable assurance of achieving their objectives as specified above. Management does not expect, however, that our disclosure controls and procedures or our internal control over financial reporting will prevent or detect all error and fraud. Any control system, no matter how well designed and operated, is based upon certain assumptions and can provide only reasonable, not absolute, assurance that its objectives will be met. Further, no evaluation of controls can provide absolute assurance that misstatements due to error or fraud will not occur or that management has detected all control issues and instances of fraud, if any, within the Partnership.

There were no changes in our internal control over financial reporting during the quarter ended December 31, 2014 that materially affected or are reasonably likely to materially affect, our internal control over financial reporting.

Deloitte & Touche has independently assessed the effectiveness of our internal control over financial reporting and its report is included below.

We have audited the internal control over financial reporting of MarkWest Energy Partners, L.P. and subsidiaries (the "Partnership") as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed by, or under the supervision of, the company's principal executive and principal financial officers, or persons performing similar functions, and effected by the company's board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2014 of the Partnership and our report dated February 25, 2015 expressed an unqualified opinion on those financial statements.

Information required to be set forth in Item 10. Directors, Executive Officers and Corporate Governance, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2015 Annual Meeting of Common Unitholders expected to be filed no later than April 30, 2015.

Information required to be set forth in Item 11. Executive Compensation has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2015 Annual Meeting of Common Unitholders expected to be filed no later than April 30, 2015.

ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Information required to be set forth in Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2015 Annual Meeting of Common Unitholders expected to be filed no later than April 30, 2015.

ITEM 13. Certain Relationships and Related Transactions and Director Independence

Information required to be set forth in Item 13. Certain Relationships and Related Transactions and Director Independence, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2015 Annual Meeting of Common Unitholders expected to be filed no later than April 30, 2015.

Information required to be set forth in Item 14. Principal Accountant Fees and Services, has been omitted and will be incorporated herein by reference, when filed, to our Proxy Statement for our 2015 Annual Meeting of Common Unitholders expected to be filed no later than April 30, 2015.

Exhibit Number			Description

	2.1		Agreement and Plan of Redemption and Merger dated September 5, 2007 by and among MarkWest Hydrocarbon, Inc., MarkWest Energy Partners, L.P. and MWEP, L.L.C. (incorporated by reference to the Current Report on Form 8-K filed September 6, 2007).
	2.2+		Agreement and Plan of Merger dated as of May 7, 2012 among Keystone Midstream Services, L.L.C., R.E. Gas Development, L.L.C., Stonehenge Energy Resources, L.P., Summit Discovery Resources II, L.L.C., MarkWest Liberty Midstream & Resources, L.L.C., MarkWest Liberty Bluestone, L.L.C. and KMS Shareholder Representative, L.L.C. (incorporated by reference to Quarterly Report on Form 10-Q filed August 6, 2012).
	3.1		Certificate of Limited Partnership of MarkWest Energy Partners, L.P. (incorporated by reference to the Registration Statement (No. 33-81780) on Form S-1 filed January 31, 2002).
	3.2		Certificate of Formation of MarkWest Energy Operating Company, L.L.C. (incorporated by reference to the Registration Statement (No. 33-81780) on Form S-1 filed January 31, 2002).
	3.3		Amended and Restated Limited Liability Company Agreement of MarkWest Energy Operating Company, L.L.C., dated as of May 24, 2002 (incorporated by reference to the Current Report on Form 8-K filed June 7, 2002).
	3.4		Certificate of Formation of MarkWest Energy GP, L.L.C. (incorporated by reference to the Registration Statement (No. 33-81780) on Form S-1 filed January 31, 2002).
	3.5		Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of May 24, 2002 (incorporated by reference to the Current Report on Form 8-K filed June 7, 2002).
	3.6		Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated as of February 21, 2008 (incorporated by reference to the Current Report on Form 8-K filed February 21, 2008).
	3.7		Amendment No. 1 to Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of December 31, 2004 (incorporated by reference to the Form S-4 Registration Statement filed July 2, 2009).
	3.8		Amendment No. 2 to Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of January 19, 2005 (incorporated by reference to the Form S-4 Registration Statement filed July 2, 2009).
	3.9		Amendment No. 3 to Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of February 21, 2008 (incorporated by reference to the Form S-4 Registration Statement filed July 2, 2009).
	3.10		Amendment No. 4 to Amended and Restated Limited Liability Company Agreement of MarkWest Energy GP, L.L.C., dated as of March 31, 2008 (incorporated by reference to the Form S-4 Registration Statement filed July 2, 2009).
	3.11		Amendment No. 1 to the Third Amended and Restated Agreement of Limited Partnership of MarkWest Energy Partners, L.P., dated December 29, 2011 (incorporated by reference to the Current Report on Form 8-K filed December 30, 2011).

Exhibit Number			Description

	4.1		Indenture, dated as of November 2, 2010, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Current Report on Form 8-K filed November 3, 2010).
	4.2		First Supplemental Indenture, dated as of November 2, 2010, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Current Report on Form 8-K filed November 3, 2010).
	4.3		Form of 6.75% Senior Notes due 2020 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.2 hereto, which is incorporated by reference to the Current Report on Form 8-K filed November 3, 2010).
	4.4		Second Supplemental Indenture, dated as of February 24, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Current Report on Form 8-K filed February 24, 2011).
	4.5		Form of 6.5% Senior Notes due 2021 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.4 hereto, which is incorporated by reference to the Current Report on Form 8-K filed February 24, 2011).
	4.6		Third Supplemental Indenture dated as of March 10, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Quarterly Report on Form 10-Q filed May 9, 2011).
	4.7		Fourth Supplemental Indenture dated as of October 21, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Quarterly Report on Form 10-Q filed November 7, 2011).
	4.8		Fifth Supplemental Indenture, dated as of November 3, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Current Report on Form 8-K filed November 7, 2011).
	4.9		Form of 6.25% Senior Notes due 2022 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.8 hereto, which is incorporated by reference to the Current Report on Form 8-K filed November 7, 2011).
	4.10		Sixth Supplemental Indenture, dated as of December 27, 2011, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Annual Report on Form 10-K filed February 28, 2012).
	4.11		Seventh Supplemental Indenture dated as of January 30, 2012, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Quarterly Report on Form 10-Q filed May 7, 2012).

Exhibit Number			Description

	4.12		Eighth Supplemental Indenture, dated as of August 10, 2012, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Current Report on Form 8-K filed August 10, 2012).
	4.13		Form of 5.5% Senior Notes due 2023 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.12 hereto, which is incorporated by reference to the Current Report on Form 8-K filed August 10, 2012).
	4.14		Ninth Supplemental Indenture, dated as of December 21, 2012, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Post-Effective Amendment No. 1 to Registration Statement on Form S-3 filed January 7, 2013).
	4.15		Tenth Supplemental Indenture, dated as of January 10, 2013, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Current Report on Form 8-K filed January 10, 2013).
	4.16		Form of 4.5% Senior Notes due 2023 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.15 hereto, which is incorporated by reference to the Current Report on Form 8-K filed January 10, 2013).
	4.17		Eleventh Supplemental Indenture, dated as of April 17, 2013, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Quarterly Report on Form 10-Q filed May 8, 2013).
	4.18		Twelfth Supplemental Indenture, dated as of June 19, 2013, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Quarterly Report on Form 10-Q filed August 7, 2013).
	4.19		Acknowledgment of Release of Subsidiary Guarantor dated March 20, 2014 issued by Wells Fargo Bank, National Association (incorporated by reference to the Quarterly Report on Form 10-Q filed May 7, 2014).
	4.20		Thirteenth Supplemental Indenture, dated as of November 21, 2014, by and among MarkWest Energy Partners, L.P., MarkWest Energy Finance Corporation, the Subsidiary Guarantors named therein and Wells Fargo Bank, National Association, as trustee (incorporated by reference to the Current Report on Form 8-K filed November 21, 2014).
	4.21		Form of 4.875% Senior Notes due 2024 with attached notation of Guarantees (incorporated by reference to Exhibits A and B of Exhibit 4.20 hereto, which is incorporated by reference to the Current Report on Form 8-K filed November 21, 2014).
	4.22		Registration Rights Agreement dated December 29, 2011 between MarkWest Energy Partners, L.P. and M&R MWE Liberty, LLC (incorporated by reference to the Annual Report on Form 10-K filed February 28, 2012).

Exhibit Number			Description

	10.1		Amended and Restated Revolving Credit Agreement dated as of July 1, 2010 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as successor Administrative Agent, Issuing Bank and Swingline Lender, Royal Bank of Canada, as prior administrative agent, RBC Capital Markets, as Syndication Agent, BNP Paribas, Morgan Stanley Bank and U.S. Bank National Association, as Documentation Agents, and the lenders party thereto (incorporated by reference to the Current Report on Form 8-K filed July 7, 2010).
	10.2		Joinder Agreement dated as of July 29, 2010 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, individually and as Administrative Agent, Issuing Bank and Swingline Lender and Goldman Sachs Bank USA (incorporated by reference to the Current Report on Form 8-K filed August 4, 2010).
	10.3		Joinder Agreement dated as of June 15, 2011 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, individually and as Administrative Agent, Issuing Bank and Swingline Lender and Citibank, N.A. (incorporated by reference to the Current Report on Form 8-K filed June 17, 2011).
	10.4		First Amendment to Amended and Restated Credit Agreement dated as of September 7, 2011 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto (incorporated by reference to the Current Report on Form 8-K filed September 13, 2011).
	10.5		Second Amendment to Amended and Restated Credit Agreement dated as of December 29, 2011, among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto (incorporated by reference to the Current Report on Form 8-K filed December 30, 2011).
	10.6		Third Amendment to Amended and Restated Credit Agreement dated as of June 29, 2012, among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto (incorporated by reference to the Current Report on Form 8-K filed June 29, 2012).
	10.7		Fourth Amendment to Amended and Restated Credit Agreement dated as of December 20, 2012, among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto (incorporated by reference to the Current Report on Form 8-K filed December 26, 2012).
	10.8		Fifth Amendment to Amended and Restated Credit Agreement dated as of December 11, 2013, among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto (incorporated by reference to the Current Report on Form 8-K filed December 13, 2013).
	10.9		New Lender Agreement and Sixth Amendment to Amended and Restated Credit Agreement dated as of March 20, 2014, among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto (incorporated by reference to the Current Report on Form 8-K filed March 20, 2014).
	10.10		Seventh Amendment to Amended and Restated Credit Agreement dated as of February 3, 2015 among MarkWest Energy Partners, L.P., Wells Fargo Bank, National Association, as Administrative Agent, and the other agents and lenders party thereto (incorporated by reference to the Current Report on Form 8-K filed February 3, 2015).

Exhibit Number			Description

	10.11		Equity Distribution Agreement dated as of November 7, 2012, among MarkWest Energy Partners, L.P., MarkWest Energy Operating Company, L.L.C. and Citigroup Global Markets Inc. (incorporated by reference to the Current Report on Form 8-K filed November 7, 2012).
	10.12		Equity Distribution Agreement dated as of August 7, 2013, among MarkWest Energy Partners, L.P., MarkWest Energy Operating Company, L.L.C., M&R MWE Liberty, LLC and Citigroup Global Markets Inc. (incorporated by reference to the Current Report on Form 8-K filed August 7, 2013).
	10.13		Equity Distribution Agreement dated as of September 5, 2013, among MarkWest Energy Partners, L.P., MarkWest Energy Operating Company, L.L.C., M&R MWE Liberty, LLC and Citigroup Global Markets Inc. (incorporated by reference to the Current Report on Form 8-K filed September 5, 2013).
	10.14		Terms Agreement dated as of December 17, 2013, among MarkWest Energy Partners, L.P., MarkWest Energy Operating Company, L.L.C., MarkWest Energy Partners, L.P. (in its capacity as custodian for M&R MWE Liberty, LLC) and Citigroup Global Markets Inc. (incorporated by reference to the Current Report on Form 8-K filed December 23, 2013).
	10.15		Equity Distribution Agreement dated as of March 11, 2014, among MarkWest Energy Partners, L.P., MarkWest Energy Operating Company, L.L.C., M&R MWE Liberty, LLC, Citigroup Global Markets Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, J.P. Morgan Securities LLC and UBS Securities LLC (incorporated by reference to the Current Report on Form 8-K filed March 11, 2014).
	10.16		Equity Distribution Agreement dated as of November 19, 2014, among MarkWest Energy Partners, L.P., MarkWest Energy Operating Company, L.L.C., M&R MWE Liberty, LLC, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, RBC Capital Markets LLC and UBS Securities LLC (incorporated by reference to the Current Report on Form 8-K filed November 19, 2014).
	10.17		Services Agreement dated January 1, 2004 between MarkWest Energy GP, L.L.C. and MarkWest Hydrocarbon, Inc. (incorporated by reference to the Annual Report on Form 10-K filed March 15, 2004).
	10.18		Exchange Agreement dated September 5, 2007 by and among MarkWest Energy Partners, L.P., MarkWest Hydrocarbon, Inc., and MarkWest Energy, GP L.L.C. (incorporated by reference to the Current Report on Form 8-K filed September 6, 2007).
	10.19		Form of Second Amended and Restated Indemnification Agreement dated April 24, 2008 by and among MarkWest Energy Partners, L.P., MarkWest Energy GP, L.L.C., and each director and officer of MarkWest Energy GP, L.L.C., including the following named executive officers: Frank Semple, President and Chief Executive Officer; Nancy Buese, Executive Vice President and Chief Financial Officer; Randy Nickerson, Executive Vice President and Chief Commercial Officer; John Mollenkopf, Executive Vice President and Chief Operating Officer; and C. Corwin Bromley, Executive Vice President, General Counsel and Secretary (incorporated by reference to the Quarterly Report on Form 10-Q filed August 11, 2008).
	10.20		MarkWest Energy Partners, L.P. 2008 Long-Term Incentive Plan (incorporated by reference to the Form S-4/A Registration Statement filed December 21, 2007).

Exhibit Number			Description

	10.21		Amendment No. 1 to MarkWest Energy Partners, L.P. 2008 Long-Term Incentive Plan (incorporated by reference to Appendix B to the Proxy Statement on Schedule 14A filed April 20, 2012).
	10.22D		Executive Employment Agreement effective September 5, 2007 between MarkWest Hydrocarbon, Inc. and Frank Semple (incorporated by reference to the Current Report on Form 8-K filed September 11, 2007).
	10.23D		Form of Executive Employment Agreement effective September 5, 2007 between MarkWest Hydrocarbon, Inc. and Nancy K. Buese, C. Corwin Bromley, John C. Mollenkopf and Randy S. Nickerson (incorporated by reference to the Current Report on Form 8-K filed September 11, 2007).
	10.24+		Contribution Agreement dated December 29, 2011 among M&R MWE Liberty, LLC, MarkWest Energy Partners, L.P. and MarkWest Liberty Gas Gathering L.L.C. (incorporated by reference to the Annual Report on Form 10-K filed February 28, 2012).
	10.25+		Limited Liability Company Agreement of MarkWest Utica EMG, L.L.C., dated December 29, 2011 and effective January 1, 2012, between MarkWest Utica Operating Company, L.L.C. and EMG Utica, LLC (incorporated by reference to the Annual Report on Form 10-K filed February 28, 2012).
	10.26+		Amendment No. 1 to Limited Liability Company Agreement of MarkWest Utica EMG, L.L.C. dated January 30, 2013, between MarkWest Utica Operating Company, L.L.C. and EMG Utica, LLC (incorporated by reference to the Quarterly Report on Form 10-Q filed May 8, 2013).
	10.27+		Amended and Restated Limited Liability Company Agreement of MarkWest Utica EMG, L.L.C. dated February 18, 2013, between MarkWest Utica Operating Company, L.L.C. and EMG Utica, LLC (incorporated by reference to the Quarterly Report on Form 10-Q filed May 8, 2013).
	12.1*		Computation of Ratio of Earnings to Fixed Charges
	14.1		MarkWest Energy Partners, L.P. Code of Conduct and Ethics (incorporated by reference to the Current Report on Form 8-K filed October 31, 2012).
	21.1*		List of subsidiaries
	23.1*		Consent of Deloitte & Touche LLP
	31.1*		Chief Executive Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act
	31.2*		Chief Financial Officer Certification Pursuant to Section 13a-14 of the Securities Exchange Act
	32*		Certification of Chief Executive Officer and the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
	101.INS*		XBRL Taxonomy Extension Instance Document.
	101.SCH*		XBRL Taxonomy Extension Schema Document.
	101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.
	101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

Pursuant to the requirements of section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized.

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the Registrant and in the capacities with MarkWest Energy GP, L.L.C., the General Partner of MarkWest Energy Partners, L.P., the Registrant and on the dates indicated.


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


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

Gathering system		Key producer customers		Counties that gathering system serves

Gas gathering		AEU Gulfport PDC Rex Energy		Harrison, Belmont, Guernsey and Noble Counties, OH

		Weighted average exercise price of outstanding options, warrants and rights(1)

Equity compensation plans approved by security holders:
2008 Long-Term Incentive Plan	675,341	$	—	1,693,431

							Actual

	2015 Full Year Plan						Actual
	2015 Full Year Plan						Year ended December 31, 2014
	Low			High			Year ended December 31, 2014
Consolidated growth capital(1)	$	1,970		$	2,395		$	2,660
Joint venture partner's estimated share of growth capital		(470	)		(495	)		(474	)

Partnership share of growth capital	$	1,500		$	1,900		$	2,186


Delaware (State or other jurisdiction of incorporation or organization)		27-0005456 (I.R.S. Employer Identification No.)



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



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	%

	Remaining contract term

Marcellus	7 to 11 years	100	%
Utica	7 to 15 years	97	%
Northeast	More than 4 years	54	%
Southwest	More than 4 years	39	%

Complex			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

Location

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

Complex			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



Marcellus	87	%	13	%	0	%
Utica(3)	100	%	0	%	0	%
Northeast	24	%	17	%	59	%
Southwest	59	%	36	%	5	%
Total	73	%	20	%	7	%

	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		—		—

	Year ended December 31,

	2014			2013			Change
Net cash provided by operating activities	$	668,399		$	435,650		$	232,749
Net cash used in investing activities		(2,270,096	)		(3,062,562	)		792,466
Net cash provided by financing activities		1,625,279			2,366,461			(741,182	)


Fair value of commodity contract	$	(34,731	)
Inception value for period from April 1, 2015 to December 31, 2022		(53,507	)

Derivative asset as of December 31, 2014	$	18,776

Long-Term Debt	Interest Rate	Lending Limit		Due Date	Outstanding at December 31, 2014

Credit Facility	Variable	$	1.3 billion	March 2019	$	97.6 million
2020 Senior Notes	Fixed	$	500.0 million	November 2020	$	500.0 million
2021 Senior Notes	Fixed	$	325.0 million	August 2021	$	325.0 million
2022 Senior Notes	Fixed	$	455.0 million	June 2022	$	455.0 million
2023A Senior Notes	Fixed	$	750.0 million	February 2023	$	750.0 million
2023B Senior Notes	Fixed	$	1.0 billion	July 2023	$	1.0 billion
2024 Senior Notes	Fixed	$	500.0 million	December 2024	$	500.0 million


Report of Deloitte & Touche LLP, Independent Registered Public Accounting Firm		108
Consolidated Balance Sheets at December 31, 2014 and 2013		109
Consolidated Statements of Operations for the years ended December 31, 2014, 2013 and 2012		110
Consolidated Statements of Changes in Equity for the years ended December 31, 2014, 2013 and 2012		111
Consolidated Statements of Cash Flows for the years ended December 31, 2014, 2013 and 2012		112
Notes to Consolidated Financial Statements for the years ended December 31, 2014, 2013 and 2012		113

	December 31, 2014				December 31, 2013

	Carrying Value		Fair Value		Carrying Value		Fair Value
Long-term debt	$	3,621,404	$	3,660,628	$	3,023,071	$	3,079,460
SMR Liability		87,113		111,686		89,592		120,922

Acquisition	Segment	Intangible Assets Acquired	Useful Life	Amortization Method

Buffalo Creek	Southwest	Identifiable customer contract with Chesapeake	20 years	Straight-line
Keystone	Marcellus	Identifiable customer contract with Rex and Sumitomo	19 years	Straight-line

	Buffalo Creek			Keystone

Assets:
Cash	$	—		$	2,837
Accounts receivable		—			1,756
Inventory		—			86
Property, plant and equipment		144,115			136,593
Goodwill		2,682			74,256
Intangible asset		84,500			304,708
Liabilities:
Accounts payable		(6,087	)		(12,117	)
Other short-term liabilities		—			(175	)
Other long-term liabilities		—			(632	)

Total	$	225,210		$	507,312

	December 31, 2014		December 31, 2013

Assets
Property, plant and equipment, net of accumulated depreciation of $25,463 and $20,195, respectively	$	79,901	$	85,169
Liabilities
Accrued liabilities	$	2,721	$	2,479
Other long-term liabilities		84,392		87,113

	Assets				Liabilities

Derivative contracts not designated as hedging instruments and their balance sheet location	Fair Value at December 31, 2014		Fair Value at December 31, 2013		Fair Value at December 31, 2014		Fair Value at December 31, 2013
Commodity contracts(1)
Fair value of derivative instruments—current	$	20,921	$	11,457	$	—	$	(28,838	)
Fair value of derivative instruments—long-term		16,507		505		—		(27,763	)

Total	$	37,428	$	11,962	$	—	$	(56,601	)

As of December 31, 2014	Assets		Liabilities

Significant other observable inputs (Level 2)
Commodity contracts	$	14,812	$	—
Significant unobservable inputs (Level 3)
Commodity contracts		3,840		—
Embedded derivatives in commodity contracts		18,776		—

Total carrying value in Consolidated Balance Sheet	$	37,428	$	—

As of December 31, 2013	Assets		Liabilities

Significant other observable inputs (Level 2)
Commodity contracts	$	544	$	(4,691	)
Significant unobservable inputs (Level 3)
Commodity contracts		8,142		(13,602	)
Embedded derivatives in commodity contracts		3,276		(38,308	)

Total carrying value in Consolidated Balance Sheet	$	11,962	$	(56,601	)

	Year Ended December 31, 2014

	Commodity Derivative Contracts (net)			Embedded Derivatives in Commodity Contracts (net)
Fair value at beginning of period	$	(5,460	)	$	(35,032	)
Total loss (realized and unrealized) included in earnings(1)		24,555			46,360
Settlements		(15,255	)		7,448

Fair value at end of period	$	3,840		$	18,776



The amount of total losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at end of period	$	3,840		$	46,539

	December 31, 2014		December 31, 2013

Trade, net	$	274,211	$	266,560
Other		28,048		15,184

Total receivables	$	302,259	$	281,744

	December 31, 2014		December 31, 2013

NGLs	$	9,687	$	21,131
Line fill		6,241		7,960
Spare parts, materials and supplies		15,821		12,272

Total inventories	$	31,749	$	41,363

	December 31, 2014			December 31, 2013

Natural gas gathering and NGL transportation pipelines and facilities	$	4,623,465		$	4,290,918
Processing plants		2,967,428			1,879,184
Fractionation and storage facilities		380,367			220,344
Crude oil pipelines		17,779			16,730
Land, building, office equipment and other		974,104			710,737
Construction in progress		960,381			1,465,854

Property, plant and equipment		9,923,524			8,583,767
Less: accumulated depreciation		(1,270,624	)		(890,598	)

Total property, plant and equipment, net	$	8,652,900		$	7,693,169

	Marcellus		Northeast			Southwest			Total

Gross goodwill	$	74,256	$	62,445		$	34,178		$	170,879
Impairment losses(1)		—		—			(28,705	)		(28,705	)

Balance as of December 31, 2012		74,256		62,445			5,473			142,174
Acquisition(2)		—		—			2,682			2,682

Balance as of December 31, 2013		74,256		62,445			8,155			144,856
Impairment losses(1)		—		(62,445	)		—			(62,445	)

Balance as of December 31, 2014	$	74,256	$	—		$	8,155		$	82,411



Gross goodwill as of December 31, 2014	$	74,256	$	62,445		$	36,860		$	173,561
Impairment losses(1)		—		(62,445	)		(28,705	)		(91,150	)

Balance as of December 31, 2014	$	74,256	$	—		$	8,155		$	82,411

	December 31, 2014							December 31, 2013

Description	Gross		Accumulated Amortization			Net		Gross		Accumulated Amortization			Net		Useful Life
Marcellus	$	304,708	$	(42,211	)	$	262,497	$	304,708	$	(26,382	)	$	278,326		19 yrs.
Northeast		102,473		(58,084	)		44,389		102,473		(48,402	)		54,071		12 yrs.
Southwest		752,423		(250,032	)		502,391		753,343		(210,948	)		542,395		10 - 25 yrs.

Total	$	1,159,604	$	(350,327	)	$	809,277	$	1,160,524	$	(285,732	)	$	874,792

Year ending December 31,

2015	$	63,768
2016		63,768
2017		63,768
2018		63,768
2019		63,768
Thereafter		490,437

	$	809,277

	December 31, 2014		December 31, 2013

Accrued property, plant and equipment	$	234,662	$	324,641
Interest		55,441		52,683
Product and operations		16,246		24,505
Taxes (other than income tax)		19,415		11,528
Employee compensation		19,625		11,377
Other		14,617		13,113

Total accrued liabilities	$	360,006	$	437,847

	December 31, 2014		December 31, 2013

SMR Liability (see Note 7)	$	84,392	$	87,113
Deferred revenue		63,889		55,621
Asset retirement obligation (See Note 16)		11,966		9,996
Deferred rent and other		8,765		3,770

Total other long-term liabilities	$	169,012	$	156,500

	December 31, 2014		December 31, 2013

Beginning asset retirement obligation	$	9,996	$	8,469
Liabilities incurred		1,400		799
Disposals		—		(96	)
Accretion expense		570		824

Ending asset retirement obligation	$	11,966	$	9,996