EXHIBIT 99.5

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

This MD&A is intended to inform the reader about matters affecting the financial condition and results of operations of SMLP and its subsidiaries. As a result, the following discussion should be read in conjunction with the audited consolidated financial statements and notes thereto included in this report. Among other things, those financial statements and the related notes include more detailed information regarding the basis of presentation for the following information. This discussion contains forward-looking statements that constitute our plans, estimates and beliefs. These forward-looking statements involve numerous risks and uncertainties, including, but not limited to, those discussed in Forward-Looking Statements in this report. Actual results may differ materially from those contained in any forward-looking statements.

Item 7. MD&A is divided into the following sections:

• Overview

• Trends and Outlook

• How We Evaluate Our Operations

• Results of Operations

• Non-GAAP Financial Measures

• Liquidity and Capital Resources

• Critical Accounting Estimates

Overview

We are a growth-oriented limited partnership focused on developing, owning and operating midstream energy infrastructure assets that are strategically located in the core producing areas of unconventional resource basins, primarily shale formations, in North America. Our gathering systems and the unconventional resource basins in which they operate are as follows:

• Mountaineer Midstream, a natural gas gathering system located in the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia;

• Bison Midstream, an associated natural gas gathering system located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

• Polar and Divide, a crude oil and produced water gathering system and transmission pipelines (under development) located in the Williston Basin;

• DFW Midstream, a natural gas gathering system located in the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and

• Grand River Gathering, a natural gas gathering and processing system located in the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah.

We believe that our gathering systems are well positioned to capture volumes from producer activity in these regions in the future.

We provide natural gas gathering, treating and processing services as well as crude oil and produced water gathering services pursuant to primarily long-term and fee-based gathering and processing agreements with our customers and counterparties. We contract with producers to gather natural gas from pad sites, wells and central receipt points connected to our systems. We then compress, dehydrate, treat and/or process these volumes for delivery to downstream pipelines for ultimate delivery to third-party processing plants and/or end users. We also contract with producers to gather crude oil and produced water from wells connected to our systems for delivery to third-party rail terminals in the case of crude oil and to third-party disposal facilities in the case of produced water.

Our results are driven primarily by the volumes that we gather, treat and/or process. We generate the majority of our revenue from the natural gas gathering, treating and processing services that we provide to our natural gas producer customers. Under a substantial majority of these agreements, we are paid a fixed fee based on the volumes we gather, treat and/or process. These agreements enhance the stability of our cash flows by providing a

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revenue stream that is not subject to direct commodity price risk. We also earn revenue from (i) crude oil and produced water gathering, (ii) our marketing of natural gas and natural gas liquids, (iii) the sale of physical natural gas purchased from our customers under percentage-of-proceeds and keep-whole arrangements, and (iv) from the sale of condensate retained from our gathering services at Grand River Gathering. We can be exposed to commodity price risk from engaging in any of these additional activities with the exception of produced water gathering.

We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay drilling or temporarily shut-in production, which would reduce the volumes of natural gas and crude oil (and associated volumes of produced water) that we gather. If our customers delay drilling or temporarily shut-in production, our MVCs ensure that we will receive a certain amount of revenue from our customers.

Most of our gathering agreements are underpinned by AMIs and MVCs. Our AMIs cover over 1.6 million acres in the aggregate and provide that any production from wells drilled by our customers within the AMI will be shipped on our gathering systems. Our MVCs, which totaled 4.0 trillion cubic feet equivalent ("Tcfe," determined using a ratio of six Mcf of gas to one barrel ("Bbl") of oil) at December 31, 2014 and average approximately 1.3 Bcfe/d through 2018, are designed to ensure that we will generate a certain amount of revenue from each customer over the life of the respective gathering agreement, whether by collecting gathering fees on actual throughput or from cash payments to cover any minimum volume commitment shortfall. Our MVCs had a weighted-average remaining life of 9.5 years as of December 31, 2014, assuming minimum throughput volumes for the remainder of the term.

For additional information on our gathering systems, see Item 1. Business and "Results of Operations" below.

Trends and Outlook

Our business has been, and we expect our future business to continue to be, affected by the following key trends:

• Acquisitions from Summit Investments and third parties;

• Natural gas, NGL and crude oil supply and demand dynamics;

• Growth in production from U.S. shale plays;

• Capital markets activity and cost of capital; and

• Shifts in operating costs and inflation.

Our expectations are based on assumptions made by us and information currently available to us. To the extent our underlying assumptions about, or interpretations of, available information prove to be incorrect, our actual results may vary materially from our expected results.

Acquisitions from Summit Investments and third parties. Our principal business strategy is to increase the amount of cash distributions we make to our unitholders over time. Our ability to grow cash distributions depends, in part, on our ability to make acquisitions that increase the amount of cash generated from our operations on a per-unit basis, along with other factors. We pursue accretive acquisitions of midstream assets from Summit Investments and third parties. For example, since 2013, we have acquired Bison Midstream, Red Rock Gathering and Polar and Divide from a subsidiary of Summit Investments as well as Mountaineer Midstream from an affiliate of MarkWest.

Summit Investments owns and operates, and continuously seeks to acquire and develop, crude oil, natural gas and water-related midstream assets that are both in service and under construction in geographic areas in which we currently operate, as well as in geographic areas outside of our current areas of operations. Summit Investments has made and expects to continue making significant investments to further develop its portfolio of crude oil, natural gas, and water-related midstream energy infrastructure assets in the Bakken Shale in North Dakota, the DJ Niobrara Shale in Colorado and the Utica Shale in southeastern Ohio over the next several years.

The acquisition component of our principal business strategy, including future acquisitions from Summit Investments, has required and will continue to require significant expenditures by us and access to external sources of financing from the debt and equity capital markets. Furthermore, as our Sponsor and its affiliates are under no obligation to provide any direct or indirect financial assistance to us, we rely primarily on external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Any prospective transaction would be impacted by our ability to obtain financing on acceptable terms from the capital markets or other sources, among other factors.

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Given the size of Summit Investments’ midstream asset portfolio and the expected additional investment that it intends to make to sufficiently develop those midstream assets, we expect to have the opportunity to make significant additional acquisitions from Summit Investments. Based on current expectations, we are estimating drop down transactions from Summit Investments or its subsidiaries in the range of $400.0 million to $800.0 million, annually through 2017. However, Summit Investments or its subsidiaries have no obligation to offer any assets to us in the future and we have no obligation to acquire any assets that are offered to us. Moreover, there are a number of risks and uncertainties that could cause our current expectations and projections to change, including, but not limited to, (i) Summit Investments deciding, in its sole discretion, to offer us the right to acquire the assets; (ii) the ability to reach agreement on acceptable terms; (iii) the approval of the conflicts committee of our general partner's board of directors (if appropriate); (iv) prevailing conditions and outlook in the crude oil, natural gas and natural gas liquids industries and markets; and (v) our ability to obtain financing on acceptable terms from the capital markets or other sources. For a more extensive list of these risks and uncertainties, see “Risks Related to Our Business—We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from Summit Investments, its affiliates or third parties, our future growth will be affected, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations.” in the section entitled "Risk Factors" in this report.

We also continue to actively pursue third-party acquisitions. However, their size, timing and/or contribution to our results of operations cannot be reasonably estimated.

We expect to fund potential drop downs and acquisitions with equity offerings and borrowings under our revolving credit facility, initially. Longer-term financing is expected to be provided by the issuance of additional debt and equity securities. In each of 2014 and 2013, we accessed the bond markets for $300.0 million to fund portions of our acquisitions and to pay down a portion of our revolving credit facility. We also issued equity securities in 2014 to fund a portion of the Red Rock Drop Down and in 2013, we issued equity securities to a subsidiary of Summit Investments to fund portions of the Bison Drop Down and the Mountaineer Midstream acquisition. See the "Liquidity and Capital Resources—Capital Requirements" section herein and Notes 7 and 8 to the audited consolidated financial statements for additional information.

Natural gas, NGL and crude oil supply and demand dynamics. Natural gas continues to be a critical component of energy supply and demand in the United States. Recently, the price of natural gas has decreased, with the New York Mercantile Exchange, or NYMEX, natural gas futures price at $2.89 per MMBtu as of December 31, 2014 compared with $4.23 per MMBtu as of December 31, 2013. Lower prices in 2014 relative to 2013 are primarily attributable to a milder-than-expected winter, which resulted in lower-than-normal overall consumption of natural gas. As a result, the amount of natural gas in storage in the continental United States increased to approximately 3.2 Tcf as of December 26, 2014 from approximately 3.0 Tcf as of December 27, 2013, compared with a ten-year historical December average of 3.3 Tcf.

Current natural gas prices continue to be lower than historical prices due in part to increased production, especially from unconventional sources, such as natural gas shale plays. According to the U.S. Energy Information Administration (the "EIA"), average annual natural gas production in the United States increased to 66.7 Bcf/d, or 21.1%, in 2013 from 55.1 Bcf/d in 2008. Over the same time period, natural gas consumption increased only 12.3% to 71.6 Bcf/d. In response to lower natural gas prices, the number of natural gas drilling rigs has declined from approximately 1,350 in December 2008 to approximately 340 in December 2014, according to Baker Hughes. We believe that over the near term, until the supply of natural gas has been reduced or the broader economy experiences more robust growth, natural gas prices are likely to be constrained.

Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven by population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation. For example, according to the EIA, coal-fired power plants generated 39% of the electricity in the United States in 2013, compared with 48% in 2008. In April 2014, the EIA projected total annual domestic consumption of natural gas to increase from approximately 70.0 Bcf/d in 2012 to approximately 86.4 Bcf/d in 2040. Consistent with the rise in consumption, the EIA projects that total domestic natural gas production will continue to grow through 2040 to 102.8 Bcf/d. The EIA also projects the United States to be a net exporter of liquefied natural gas, or LNG, by 2018, with net U.S. exports of LNG projected to rise to 15.8 Bcf/d in 2040 from a 2013 net imported amount of 4.1 Bcf/d. We believe that increasing consumption of natural gas will continue to drive natural gas drilling and production over the long term throughout the United States.

In addition, the Bison Midstream and Polar and Divide systems are directly affected by crude oil supply and demand dynamics. Crude oil has been the focus of a recent global supply surplus, with OPEC stating in November 2014 that it would not decrease production levels, despite estimates of slowing global demand, particularly in historically high growth countries such as China. This, in conjunction with continued crude oil production growth in the United

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States, has played a significant role in the recent decline in crude oil prices, with NYMEX crude oil futures ending 2014 at $53.27 per barrel, compared to a high in June 2014 of $107.26 per barrel. For additional information, see the "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" section herein and Notes 4 and 5 to the audited consolidated financial statements.

Over the next two years, the EIA projects that domestic crude oil production will continue to increase from an average of 8.6 million Bbl/d in 2014 to 9.5 million Bbl/d in 2016. While long-term estimates vary due to uncertainty regarding long-term crude oil price trends, the EIA still sees continued growth in certain unconventional shale plays, with crude oil prices expected to remain high enough to support continued drilling and increasing production in the Bakken Shale, Eagle Ford Shale, Permian Basin, and Niobrara Shale.

In addition to the influence that crude oil market dynamics have on our Bison Midstream and Polar and Divide systems, they produce a secondary effect on the natural gas market as a whole. According to the EIA, of the 82.2 Bcf/d of natural gas that was produced in 2013, 14.9 Bcf/d, or 18%, was related to associated natural gas produced from crude oil wells. Effectively, a decrease in production from these types of wells could play a part in increasing natural gas prices.

Growth in production from U.S. shale plays.Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional resources. While the EIA expects total domestic natural gas production to grow from 24.1 Tcf in 2013 to 37.6 Tcf in 2040, it expects shale gas production to grow to 19.8 Tcf in 2040, representing 53% of total U.S. natural gas production. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per-unit economics when compared to most conventional plays.

In recent years, producers have leased large acreage positions in the areas in which we operate and other unconventional resource plays. To help fund their drilling programs in many of these areas, a number of producers have entered into joint venture arrangements with large international operators, industrial manufacturers and private equity sponsors. These producers and their joint venture partners have committed significant capital to the development of the Piceance Basin and the Barnett, Bakken and Marcellus shale plays and other unconventional resource plays, which we believe will support sustained drilling activity.

As a result of the current low commodity price environment, many producers have announced reductions to their capital expenditure budgets by limiting their drilling activities in lower performing resource plays or in lower tier areas within higher performing resource plays. Nevertheless, we believe producers will remain focused on deploying capital in their highest quality resource plays, even in a low commodity price environment.

Capital markets activity and cost of capital.The credit markets have continued to experience near-record lows in interest rates. As oil prices begin to stabilize and the overall economy strengthens, it is likely that monetary policy will tighten, resulting in higher interest rates to counter possible inflation. This could affect our ability to access the debt capital markets to the extent necessary to fund our future growth. In addition, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Although this could limit our ability to raise debt capital on acceptable terms, we expect to remain competitive with respect to acquisitions and capital projects, as our competitors would face similar circumstances.

Shifts in operating costs and inflation. During most of 2014, high levels of crude oil and natural gas exploration, development and production activities across the United States resulted in increased competition for personnel and equipment as well as higher prices for labor, supplies and equipment. An increase in the general level of goods and services in the broader economy could have a similar effect. In a highly competitive scenario, we attempt to recover increased costs from our customers, but there may be a delay in doing so or we may be unable to recover all of these costs. To the extent we are unable to procure necessary supplies or recover higher costs, our operating results will be negatively impacted.

How We Evaluate Our Operations

We conduct our operations in the midstream energy industry through five reportable segments:

• the Marcellus Shale, which is served by Mountaineer Midstream;

• the Williston Basin – Gas, which is served by Bison Midstream;

• the Williston Basin – Liquids, which is served by Polar and Divide;

• the Barnett Shale, which is served by DFW Midstream; and

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• the Piceance Basin, which is served by Grand River. Grand River is composed of the Legacy Grand River and Red Rock gathering systems.

Our management uses a variety of financial and operational metrics to analyze our consolidated and segment performance. We view these metrics as important factors in evaluating our profitability and review these measurements on a regular basis for consistency and trend analysis. These metrics include:

• throughput volume,

• revenues,

• operation and maintenance expenses,

• EBITDA,

• adjusted EBITDA and segment adjusted EBITDA, and

• distributable cash flow.

Throughput Volume

The volume of (i) natural gas that we gather, treat and/or process and (ii) crude oil and produced water that we gather depends on the level of production from natural gas or crude oil wells connected to our gathering systems. Aggregate production volumes are impacted by the overall amount of drilling and completion activity. Furthermore, because the production rate of natural gas and crude oil wells decline over time, production can only be maintained or increased by new drilling or other activity.

As a result, we must continually obtain new supplies of production to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new customers or counterparties is impacted by:

• successful drilling activity within our areas of mutual interest;

• the level of work-overs and recompletions of wells on existing pad sites to which our gathering systems are connected;

• the number of new pad sites in our areas of mutual interest awaiting connections;

• our ability to compete for volumes from successful new wells in the areas in which we operate outside of our existing areas of mutual interest; and

• our ability to gather, treat and/or process production that has been released from commitments with our competitors.

Following the Polar and Divide Drop Down, we will continue to report volumes for natural gas gathering and will now also report volumes for crude oil and produced water gathering. Crude oil and produced water gathering are aggregated and reported as "liquids" gathering and measured in thousands of barrels per day ("Mbbl/d"). Gathering rates are reported in barrels.

Revenues

Our revenues are primarily attributable to the volumes that we gather, treat and/or process and the rates we charge for those services. A substantial majority of our gathering and processing agreements are fee-based, which limits our direct commodity price exposure. We also have percent-of-proceeds and keep-whole arrangements under which the gathering and processing revenues that we earn correlate directly with the fluctuating price of natural gas, condensate and NGLs.

Many of our gathering and processing agreements contain MVCs pursuant to which our customers agree to ship or process a minimum volume of production on our gathering systems, or, in some cases, to pay a minimum monetary amount, over certain periods during the term of the MVC. These MVCs support our revenues and serve to mitigate the financial impact associated with declining volumes.

In connection with the Polar and Divide Drop Down, we evaluated our classification of revenues and concluded that creating an “other revenues” category would provide reporting that was more reflective of our results of operations and how we manage our business. As such, certain revenue transactions that previously represented the “and other” portions of (i) gathering services and (ii) natural gas, NGLs and condensate sales have been reclassified to other revenues. Other revenues largely comprises electricity pass-throughs for customers of Bison Midstream and Grand River Gathering and connection fees on the Polar and Divide system. Other revenues also includes the

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amortization expense associated with our favorable and unfavorable gas gathering contracts. These reclassifications had no impact on total revenues, net income or total partners' capital.

Operation and Maintenance Expenses

We seek to maximize the profitability of our operations in part by minimizing, to the extent appropriate, expenses directly tied to operating our assets. Direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services comprise the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of volumes delivered through our gathering systems but may fluctuate depending on the activities performed during a specific period.

The majority of the compressors on our DFW Midstream system are electric driven and power costs are directly correlated to the run-time of these compressors, which depends directly on the volume of natural gas gathered. As part of our contracts with our DFW Midstream system customers, we physically retain a percentage of throughput volumes that we subsequently sell to offset the power costs we incur. With respect to the Mountaineer Midstream, Bison Midstream and Grand River systems, we either (i) consume physical gas on the system to operate our gas-fired compressors or (ii) charge our customers for the power costs we incur to operate our electric-drive compressors.

EBITDA, Adjusted EBITDA and Distributable Cash Flow

EBITDA, adjusted EBITDA and distributable cash flow are used as supplemental financial measures by our management and by external users of our financial statements such as investors, commercial banks, research analysts and others.

EBITDA and adjusted EBITDA are used to assess:

• the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

• the ability of our assets to generate cash sufficient to support our indebtedness and make cash distributions to our unitholders and general partner;

• our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

• the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

In addition, adjusted EBITDA is used to assess:

• the financial performance of our assets without regard to the impact of the timing of minimum volume commitments shortfall payments under our gathering agreements or the timing of impairments or other noncash income or expense items.

Distributable cash flow is used to assess:

• the ability of our assets to generate cash sufficient to support our indebtedness and make future cash distributions to our unitholders; and

• the attractiveness of capital projects and acquisitions and the overall rates of return on alternative investment opportunities.

For additional information, see the "Results of Operations" and "Non-GAAP Financial Measures" sections herein and Note 3 to the audited consolidated financial statements.

Results of Operations

Our financial results are recognized as follows:

Gathering services and related fees. Revenue earned from the gathering, treating and processing services that we provide to our natural gas and crude oil producer customers.

Natural gas, NGLs and condensate sales. Revenue earned from (i) the sale of physical natural gas and natural gas liquids purchased under percentage-of-proceeds and keep-whole arrangements with certain of our customers

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on the Bison Midstream and Red Rock gathering systems, (ii) the sale of natural gas we retain from our DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River.

Other revenues. Revenue earned primarily from (i) electricity costs for which our Bison Midstream and Grand River Gathering customers have agreed to reimburse us and (ii) connection fees for customers of the Polar and Divide system.

Cost of natural gas and NGLs. The cost of natural gas and NGLs represents the costs associated with the percent-of-proceeds and keep-whole arrangements under which we sell natural gas purchased from certain of our customers on the Bison Midstream and Red Rock gathering systems.

Operation and maintenance. Operation and maintenance primarily comprises direct labor costs, compression costs, ad valorem taxes, repair and non-capitalized maintenance costs, integrity management costs, utilities and contract services. These items represent the most significant portion of our operation and maintenance expense. Other than utilities expense, these expenses are largely independent of variations in throughput volumes but may fluctuate depending on the activities performed during a specific period. Operation and maintenance also includes our procurement of electricity to operate our electric-drive compression assets on the DFW Midstream system.

General and administrative. Expenses associated with our operations that are not specifically associated with the operation and maintenance of a particular system or another cost and expense line item. These expenses largely reflect salaries, benefits and incentive compensation, professional fees, insurance and rent.

Transaction costs. Financial and legal advisory costs associated with completed acquisitions.

Depreciation and amortization. The amortization of our contract and right-of-way intangible assets and the depreciation of our property, plant and equipment.

Other income or expense. Generally represents interest income but may also include other items of gain or loss.

Interest expense. Interest expense associated with our revolving credit facility and senior notes.

Affiliated interest expense. Interest cost related to the $200.0 million promissory notes that we issued to affiliates in connection with the acquisition of the Grand River system in 2011. The promissory notes were repaid in 2012.

Income tax expense. Since we are structured as a partnership, we are generally not subject to federal and state income taxes, except the Texas Margin Tax, which is reflected herein.

Items Affecting the Comparability of Our Financial Results

SMLP's historical results of operations may not be comparable to its future results of operations for the reasons described below:

• The audited consolidated financial statements reflect the results of operations of Polar and Divide since February 16, 2013. We accounted for the Polar and Divide Drop Down on an "as-if pooled" basis because the transaction was executed by entities under common control. The Polar and Divide system commenced operations in May 2013.

• The audited consolidated financial statements reflect the results of operations of Red Rock Gathering since October 23, 2012. We accounted for the Red Rock Drop Down on an "as-if pooled" basis because the transaction was executed by entities under common control. Red Rock Gathering's contribution to the Partnership's financial and operating results have been reflected in the financial and operating results of its parent, Grand River.

• The audited consolidated financial statements reflect the results of operations of Bison Midstream since February 16, 2013. We accounted for the Bison Drop Down on an "as-if pooled" basis because the transaction was executed by entities under common control.

• The audited consolidated financial statements reflect the results of operations of Mountaineer Midstream since June 22, 2013.

For additional information, see the notes to the audited consolidated financial statements.

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Consolidated Overview of the Years Ended December 31, 2014, 2013 and 2012

The following table presents certain consolidated and other financial and operating data as of or for the years ended December 31.

	Year ended December 31,									Percentage Change
	2014			2013			2012			2014 v. 2013		2013 v. 2012
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	239,595		$	197,174		$	145,463		22	%	36	%
Natural gas, NGLs and condensate sales	97,094			88,185			22,825			10	%	*
Other revenues	16,446			11,454			6,135			44	%	87	%
Total revenues	353,135			296,813			174,423			19	%	70	%
Costs and expenses:
Cost of natural gas and NGLs	52,847			41,164			3,224			28	%	*
Operation and maintenance	88,927			77,114			53,882			15	%	43	%
General and administrative	38,269			32,273			22,182			19	%	45	%
Transaction costs	730			2,841			2,025			(74	)%	40	%
Depreciation and amortization	87,349			70,574			36,674			24	%	92	%
Loss on asset sales, net	442			113			—			*		*
Goodwill impairment	54,199			—			—			*		—	%
Long-lived asset impairment	5,505			—			—			*		—	%
Total costs and expenses	328,268			224,079			117,987			46	%	90	%
Other income	1,189			5			9			*		*
Interest expense	(40,159		)	(19,173		)	(7,340		)	109	%	*
Affiliated interest expense	—			—			(5,426		)	—	%	*
(Loss) income before income taxes	(14,103		)	53,566			43,679			(126	)%	23	%
Income tax expense	(631		)	(729		)	(682		)	(13	)%	7	%
Net (loss) income	$	(14,734	)	$	52,837		$	42,997		(128	)%	23	%
Other Financial Data:
EBITDA (1)	$	114,345		$	144,340		$	93,302		(21	)%	55	%
Adjusted EBITDA (1)	204,907			165,324			105,946			24	%	56	%
Capital expenditures (2)	220,820			182,978			77,296			21	%	137	%
Acquisitions of gathering systems (3)	315,872			458,914			—			*		*
Distributable cash flow (1)(2)	150,318			128,457			90,947			17	%	41	%
Operating Data:
Miles of pipeline as of December 31	2,622			2,449			1,874			7	%	31	%
Aggregate average throughput (MMcf/d)	1,418			1,138			952			25	%	20	%
Aggregate average throughput rate per Mcf	$	0.46		$	0.50		$	0.41		(8	)%	22	%
Average throughput (Mbbl/d)	33.6			10.9						*
Average throughput rate per Bbl	$	1.64		$	0.95					73	%

__________

*Not considered meaningful

(1) See "Non-GAAP Financial Measures" herein for additional information on EBITDA, adjusted EBITDA and distributable cash flow as well as their reconciliations to the most directly comparable GAAP financial measure.

(2) See "Liquidity and Capital Resources" herein for additional information on capital expenditures.

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(3) Reflects cash paid (including working capital and capital expenditure adjustments) and value of units issued, if any, to fund acquisitions and/or drop downs. For additional information, see Note 15 to the audited consolidated financial statements.

Volumes – Gas. For the year ended December 31, 2014, our aggregate throughput volumes increased to an average of 1,418 MMcf/d, compared with an average of 1,138 MMcf/d for the year ended December 31, 2013. The increase in volume throughput largely reflects the contribution from Mountaineer Midstream and the Grand River system as a result of growth at Red Rock Gathering, partially offset by volume throughput declines on the DFW Midstream and Legacy Grand River systems. Volume throughput on the DFW Midstream system benefited in the prior-year period due to the first quarter 2013 commissioning of an additional compressor which increased throughput capacity on the DFW Midstream system by 40 MMcf/d.

Our aggregate throughput volumes increased to an average of 1,138 MMcf/d for the year ended December 31, 2013, compared with an average of 952 MMcf/d for the year ended December 31, 2012. The 2013 increase in volume throughput largely reflects the combined effect of contributions from Bison Midstream and Mountaineer Midstream, an increase in volume throughput at Red Rock Gathering and the comparative impact of a temporary production curtailment by DFW Midstream's anchor customer during the first and second quarters of 2012.

Volumes – Liquids. Average daily throughput for crude oil and produced water increased to 33.6 Mbbl/d for the year ended December 31, 2014, compared with an average of 10.9 Mbbl/d in the prior-year period. The increase in crude oil and produced water volume throughput primarily reflects the continued development of the Polar and Divide system, new pad site connections and producers' ongoing drilling activity.

Revenues. For the year ended December 31, 2014, total revenues increased $56.3 million, or 19%, and primarily reflect:

• overall growth at Red Rock Gathering;

• overall growth at Polar and Divide;

• an increase in gathering services and other fees at Mountaineer Midstream, due in large part to the partial year of ownership in 2013;

• overall growth at Bison Midstream primarily due to higher volume throughput;

• an overall decline in revenues on the DFW Midstream primarily due to lower volume throughput.

For the year ended December 31, 2013, total revenues increased $122.4 million, or 70%, and primarily reflect:

• a full year of operations for Red Rock Gathering;

• Bison Midstream's contribution to natural gas, NGLs and condensate sales;

• Mountaineer Midstream's contribution to gathering services and related fees;

• an increase in revenues for the DFW Midstream system due to higher volume throughput; and

• Polar and Divide's partial-year contribution to gathering services and related fees.

Costs and Expenses. For the year ended December 31, 2014, total costs and expenses increased $104.2 million, or 46%, primarily due to a goodwill impairment for Bison Midstream, an increase in depreciation and amortization across our gathering systems, an increase in cost of natural gas and NGLs for Bison Midstream and Red Rock Gathering and an increase in operation and maintenance expense as a result of the continued development of the Polar and Divide system.

For the year ended December 31, 2013, total costs and expenses increased $106.1 million, or 90%, primarily as a result of a full year of operations for Red Rock Gathering and the partial-year contributions from Bison Midstream, Mountaineer Midstream and Polar and Divide in 2013.

Segment Overview of the Years Ended December 31, 2014, 2013 and 2012

Marcellus Shale. The Mountaineer Midstream gathering system provides our midstream services for the Marcellus Shale reportable segment. We acquired Mountaineer Midstream in June 2013. Marcellus Shale volume throughput averaged 382 MMcf/d for the year ended December 31, 2014, and reflects the continuation of active drilling by Antero, our anchor customer, and the connection of new wells upstream of the Mountaineer Midstream system and as new, upstream compressor stations were commissioned by third parties, also contributing to volume throughput. The Zinnia Loop project, which increased throughput capacity on the Mountaineer Midstream system from 550

EX 99.5-9

EXHIBIT 99.5

MMcf/d to 1,050 MMcf/d, was commissioned at the end of the third quarter of 2014. The Zinnia Loop is supported by a long-term minimum revenue commitment from Antero.

Information regarding our operations in the Marcellus Shale as of or for the years ended December 31 follow.

	Marcellus Shale(1)
	Year ended December 31,				Percentage Change
	2014		2013		2014 v. 2013
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	22,694	$	9,588	137	%
Total revenues	22,694		9,588		137	%
Costs and expenses:
Operation and maintenance	4,560		2,447		86	%
General and administrative	2,194		808		*
Depreciation and amortization	7,648		3,998		91	%
Total costs and expenses	14,402		7,253		99	%
Add:
Depreciation and amortization	7,648		3,998
Segment adjusted EBITDA	$	15,940	$	6,333	*
Average throughput (MMcf/d)(2)	382		87		*

__________

* Not considered meaningful

(1) Contract terms related to throughput rate per MCF are excluded for confidentiality purposes.

(2) For the period of SMLP's ownership in 2013, average throughput was 164 MMcf/d.

Gathering Services and Related Fees. Gathering services and related fees benefited in 2014 from a full year of operations under SMLP's management as well as our build out of the Mountaineer system to keep pace with increases in production from Antero as processing capacity at MarkWest’s Sherwood Processing Complex increased.

Total Costs and Expenses. Total costs and expenses, and the components thereof, increased during the year ended December 31, 2014, largely as a result of a full year of operations in 2014.

Williston Basin – Gas. The Bison Midstream gathering system provides our midstream services for the Williston Basin – Gas reportable segment. Bison Midstream was acquired from a subsidiary of Summit Investments in June 2013. Our results include activity for Bison Midstream since February 16, 2013, the date on which common control began. Williston Basin – Gas volume throughput averaged 18 MMcf/d for the year ended December 31, 2014, compared with 16 MMcf/d during our period of ownership in 2013. The increase in volume throughput in 2014 primarily reflects additional pad site connections and newly installed compression capacity, which improved system hydraulics. During the last half of 2014, Bison Midstream's results of operations were negatively impacted by declining commodity prices, most notably in relation to its percent-of-proceeds arrangements.

EX 99.5-10

EXHIBIT 99.5

Information regarding our operations in the Williston Basin – Gas as of or for the years ended December 31 follow.

	Williston Basin – Gas
	Year ended December 31,				Percentage Change
	2014		2013		2014 v. 2013
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	946	$	536	76	%
Natural gas, NGLs and condensate sales	56,040		47,130		19	%
Other revenues	5,468		3,069		78	%
Total revenues	62,454		50,735		23	%
Costs and expenses:
Cost of natural gas and NGLs	34,912		27,967		25	%
Operation and maintenance	14,360		7,269		98	%
General and administrative	3,503		2,234		57	%
Depreciation and amortization	18,132		16,057		13	%
Loss on asset sales	296		—		*
Goodwill impairment	54,199		—		*
Total costs and expenses	125,402		53,527		134	%
Add:
Depreciation and amortization	18,132		16,057
Adjustments related to MVC shortfall payments	10,743		3,600
Loss on asset sales	296		—
Goodwill impairment	54,199		—
Segment adjusted EBITDA	$	20,422	$	16,865	21	%
Average throughput (MMcf/d)(1)	18		14		29	%
Average throughput rate per Mcf	$	3.46	$	3.86	(10	)%

__________

* Not considered meaningful

(1) For the year ended December 31, 2013. For the period of SMLP's ownership in 2013, average throughput was 16 MMcf/d.

Gathering Services and Related Fees. Gathering services and related fees increased during the year ended December 31, 2014 primarily a result of increased volumes under our percent-of-proceeds arrangements on the Bison Midstream system. The aggregate average throughput rate declined to $3.46 per Mcf in 2014 from $3.86 per Mcf in 2013, primarily as a result of a shift in volume mix.

Natural Gas, NGLs and Condensate Sales. The increase in natural gas, NGLs and condensate sales for the year ended December 31, 2014 was primarily a result of increased volumes under percent-of-proceeds arrangements, partially offset by declining commodity prices.

Other Revenues. The increase in other revenues for the year ended December 31, 2014 reflects an increase in certain electricity expenses, which, due to their pass-through nature, is offset in operation and maintenance expense and has no impact on segment adjusted EBITDA.

Cost of Natural Gas and NGLs.The increase in the cost of natural gas and NGLs during the year ended December 31, 2014 was primarily a result of increased volumes under percent-of-proceeds arrangements, partially offset by declining commodity prices.

Operation and Maintenance. Operation and maintenance expense increased during the year ended December 31, 2014, largely as a result of a $2.2 million increase in electricity pass-through expense as discussed in other revenues above, a $1.6 million increase in salaries, benefits and incentive compensation, a $0.7 million increase in chemicals expense, a $0.4 million for field communications and meters and a $0.4 million increase in property taxes.

EX 99.5-11

EXHIBIT 99.5

General and Administrative. General and administrative expense increased during the year ended December 31, 2014, largely as a result of an increase in salaries, benefits and incentive compensation primarily as a result of increased head count.

Depreciation and Amortization. The increase in depreciation and amortization expense during the year ended December 31, 2014 was largely driven by an increase in contract amortization and assets placed into service.

Goodwill Impairment. During the fourth quarter of 2014, we determined that the goodwill associated with the Bison Midstream system had been impaired. Based on available information, we have preliminarily recognized an estimated goodwill impairment of $54.2 million. See "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets—Goodwill" and Note 5 to the audited consolidated financial statements for additional information.

Williston Basin – Liquids. The Polar and Divide system provides our midstream services for the Williston Basin – Liquids reportable segment. Polar and Divide was acquired from a subsidiary of Summit Investments in May 2015. Our results include activity for Polar and Divide since February 16, 2013, the date on which common control began. Volume throughput for Polar and Divide averaged 33.6 Mbbl/d for the year ended December 31, 2014, compared with 12.5 Mbbl/d during our period of ownership in 2013. The increase in volume throughput in 2014 reflects new pad site connections and ongoing drilling activity in Polar and Divide's service area.

Information regarding our operations in the Williston Basin – Liquids as of or for the years ended December 31 follow.

	Williston Basin – Liquids
	Year ended December 31,				Percentage Change
	2014		2013		2014 v. 2013
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	20,110	$	3,791	*
Other revenues	2,339		102		*
Total revenues	22,449		3,893		*
Costs and expenses:
Operation and maintenance	7,408		1,580		*
General and administrative	4,252		2,168		96	%
Depreciation and amortization	4,359		612		*
Total costs and expenses	16,019		4,360		*
Add:
Depreciation and amortization	4,359		612
Unit-based compensation	340		340
Segment adjusted EBITDA	$	11,129	$	485	*
Average throughput (Mbbl/d)(1)	33.6		10.9		*
Average throughput rate per Bbl	$	1.64	$	0.95	73	%

__________

* Not considered meaningful

(1) For the year ended December 31, 2013. For the period of SMLP's ownership in 2013, average throughput was 12.5 Mbbl/d.

Gathering Services and Related Fees. Gathering services and related fees increased during the year ended December 31, 2014 primarily a result of the impact of higher volume throughput on gathering services and related fees and higher gathering rates associated with contract amendments in 2014. The aggregate average throughput rate increased to $1.64 per Bbl in 2014 from $0.95 per Bbl in 2013, primarily as a result of contract amendments in 2014 which increased gathering rates in connection with our commitment to further expand the Polar and Divide system.

EX 99.5-12

EXHIBIT 99.5

Other revenues. The increase in other revenues for the year ended December 31, 2014 was primarily a result of an increase in connection fees, which, due to their pass-through nature, is offset in operation and maintenance expense.

Operation and Maintenance. Operation and maintenance expense increased during the year ended December 31, 2014, largely as a result of the previous mentioned increase in connection fees, which, due to their pass-through nature, is offset in other revenues and an increase in salaries, benefits and incentive compensation primarily as a result of increased head count.

General and Administrative. General and administrative expense increased during the year ended December 31, 2014, largely as a result of an increase in salaries, benefits and incentive compensation primarily as a result of increased head count.

Depreciation and Amortization. The increase in depreciation and amortization expense during the year ended December 31, 2014 was largely driven by assets being placed into service.

Barnett Shale. The DFW Midstream gathering system provides our midstream services for the Barnett Shale reportable segment. On September 30, 2014, DFW Midstream acquired certain natural gas gathering assets (the "Lonestar assets"). The Lonestar assets gather natural gas under two long-term, fee-based gathering agreements.

DFW Midstream volume throughput declined to 358 MMcf/d during 2014 from 391 MMcf/d in 2013 primarily reflecting continued natural declines and lack of drilling activity by DFW Midstream's anchor customer, partially offset by the benefit from the Lonestar assets as well as several customers bringing new wells on line early in the second quarter of 2014. For the year ended December 31, 2014, volume throughput was impacted by multiple customers temporarily shutting-in several large pad sites to drill or complete new wells. These shut-ins began in the third quarter of 2013 and continued into late 2014 when customer production recommenced from several pad sites.

Volume throughput increased to 391 MMcf/d during 2013 from 354 MMcf/d in 2012 largely as a result of the comparative impact of a temporary production curtailment by DFW Midstream's anchor customer during the first and second quarters of 2012 and a short-term boost from the January 2013 commissioning of a compressor which increased system capacity by 40 MMcf/d.

EX 99.5-13

EXHIBIT 99.5

Information regarding our operations in the Barnett Shale as of or for the years ended December 31 follow.

	Barnett Shale
	Year ended December 31,									Percentage Change
	2014			2013			2012			2014 v. 2013		2013 v. 2012
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	79,976		$	89,147		$	78,472		(10	)%	14	%
Natural gas, NGLs and condensate sales	13,448			17,190			15,173			(22	)%	13	%
Other revenues	(423		)	(1,013		)	(192		)	(58	)%	*
Total revenues	93,001			105,324			93,453			(12	)%	13	%
Costs and expenses:
Operation and maintenance	29,438			31,784			25,160			(7	)%	26	%
General and administrative	4,607			6,129			6,453			(25	)%	(5	)%
Depreciation and amortization	15,657			13,929			12,078			12	%	15	%
Loss on asset sales	—			113			—			*		*
Long-lived asset impairment	5,505			—			—			*		—	%
Total costs and expenses	55,207			51,955			43,691			6	%	19	%
Add:
Depreciation and amortization	16,601			14,961			12,270
Adjustments related to MVC shortfall payments	628			1,030			1,638
Loss on asset sales	—			113			—
Long-lived asset impairment	5,505			—			—
Segment adjusted EBITDA	$	60,528		$	69,473		$	63,670		(13	)%	9	%
Average throughput (MMcf/d)	358			391			354			(8	)%	10	%
Average throughput rate per Mcf	$	0.59		$	0.59		$	0.58		—	%	2	%

__________

* Not considered meaningful

Gathering Services and Related Fees. Gathering services and related fees decreased during the year ended December 31, 2014, reflecting the continued natural decline in volumes and lack of producer drilling activity. The aggregate average throughput rate was unchanged year over year.

The increase in gathering services and other fees during the year ended December 31, 2013 primarily reflected the comparative impact of the production curtailment in the first half of 2012, a short-term throughput volume boost which increased system capacity by 40 MMcf/d (both noted above) and an increase in the aggregate average throughput rate per Mcf.

Natural Gas, NGLs and Condensate Sales. The decrease in natural gas, NGLs and condensate sales for the year ended December 31, 2014, was primarily a result of a decline in revenue associated with natural gas retainage sales at DFW Midstream.

The increase in natural gas, NGLs and condensate sales for the year ended December 31, 2013, was primarily a result of higher throughput volumes and the associated retainage on our DFW Midstream system, and an increase in the prices we were able to obtain for natural gas sales.

Other Revenues. Other revenues increased during the year ended December 31, 2014 largely as a result of the contribution of Lonestar reimbursement revenues.

For the year ended December 31, 2013, a substantial majority of other revenues was related to the amortization of favorable and unfavorable gas gathering contracts. In 2012, other revenues comprised the amortization of favorable and unfavorable gas gathering contracts.

EX 99.5-14

EXHIBIT 99.5

Operation and Maintenance. Operation and maintenance expense decreased during the year ended December 31, 2014, largely as a result of a $3.8 million decline in third-party natural gas treating expenses, partially offset by a $0.9 million increase in insurance expense and a $0.6 million increase in compression-related expenses.

Operation and maintenance expense increased during the year ended December 31, 2013, largely as a result of a $4.3 million increase in power-related costs and a $1.6 million increase in third-party natural gas treating expenses.

General and Administrative. General and administrative expense decreased during the year ended December 31, 2014, largely as a result of a decrease in the proportionate share of salaries, benefits and incentive compensation allocated to the segment and a decline in professional services fees.

Depreciation and Amortization. The increases in depreciation and amortization expense during the years ended December 31, 2014 and 2013 largely reflect the impact of assets placed in service.

Long-Lived Asset Impairment. The long-lived asset impairment recognized in 2014 represents the write off of certain property, plant and equipment balances associated with a DFW Midstream compressor station project that was terminated and replaced with a pipeline looping project. See "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets—Property, Plant and Equipment and Intangible Assets" and Note 4 to the audited consolidated financial statements for additional information.

Piceance Basin. The Legacy Grand River and Red Rock Gathering systems provide our midstream services for the Piceance Basin reportable segment. Red Rock Gathering became part of the Grand River system in connection with the Red Rock Drop Down in March 2014. As noted above, our results include activity for Red Rock Gathering since October 23, 2012, the date on which common control began. For additional information, see the notes to the audited consolidated financial statements. References to the Grand River system refer collectively to the Legacy Grand River system and Red Rock Gathering.

Volume throughput for the Piceance Basin increased to 660 MMcf/d during 2014 from 646 MMcf/d during 2013 primarily as a result of growth at Red Rock Gathering. Volume throughput from Red Rock Gathering was favorably impacted by new pad site connections for WPX Energy, Inc. and Ursa Resources Group II as well as the March 2014 start-up of a cryogenic processing plant servicing production from Black Hills Corporation. Volume throughput on the Legacy Grand River system declined in 2014 primarily as a result of Encana's temporary suspension of drilling activities, which began in the fourth quarter of 2013.

Volume throughput for the Piceance Basin increased to 646 MMcf/d during 2013 from 598 MMcf/d during 2012 primarily as a result of growth at Red Rock Gathering, partially offset by lower drilling activity, including Encana as noted above, and the natural decline of previously drilled Mancos/Niobrara wells on our Legacy Grand River system.

Volume growth from Red Rock Gathering's anchor customers continues to offset volume declines from the Legacy Grand River system. This shift in volume throughput mix has translated into higher average gathering rates per Mcf. Further, certain of our gas gathering agreements for the Grand River system include MVCs that increase in both rate and volume commitment over the next few years and largely mitigate the financial impact associated with declining volumes from certain customers. As a result, lower volume throughput for the customers subject to these MVCs translated into larger MVC shortfall payments during 2014 and 2013.

EX 99.5-15

EXHIBIT 99.5

Information regarding our operations in the Piceance Basin as of or for the years ended December 31 follow.

	Piceance Basin
	Year ended December 31,						Percentage Change
	2014		2013		2012		2014 v. 2013		2013 v. 2012
	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	115,869	$	94,112	$	66,991	23	%	40	%
Natural gas, NGLs and condensate sales	27,606		23,865		7,652		16	%	*
Other revenues	9,062		9,296		7,318		(3	)%	27	%
Total revenues	152,537		127,273		81,961		20	%	55	%
Costs and expenses:
Cost of natural gas and NGLs	17,935		13,197		3,224		36	%	*
Operation and maintenance	33,111		33,964		28,709		(3	)%	18	%
General and administrative	8,732		11,566		5,979		(25	)%	93	%
Depreciation and amortization	40,965		35,527		24,310		15	%	46	%
Loss on asset sales, net	146		—		—		*		—	%
Total costs and expenses	100,889		94,254		62,222		7	%	51	%
Other income	1,185		—		—		*		—	%
Add:
Depreciation and amortization	40,965		35,527		24,310
Adjustments related to MVC shortfall payments	15,194		12,395		9,130
Loss on asset sales, net	146		—		—
Less:
Impact of purchase price adjustments	1,185		—		—
Segment adjusted EBITDA	$	107,953	$	80,941	$	53,179	33	%	52	%
Average throughput (MMcf/d)(1)	660		646		598		2	%	8	%
Average throughput rate per Mcf	$	0.49	$	0.40	$	0.31	23	%	29	%

__________

* Not considered meaningful

(1) For the year ended December 31, 2012. For the period of SMLP's ownership in 2012, average throughput was 715 MMcf/d.

Gathering Services and Related Fees. Gathering services and related fees increased during the year ended December 31, 2014, largely due to the proportionate contribution of higher margin volume throughput from certain customers and the first quarter 2014 commissioning of a natural gas processing plant. The aggregate average throughput rate increased to $0.49 per Mcf during 2014 from $0.40 per Mcf during 2013 largely as a result of the shift in volume throughput mix noted above.

Gathering services and related fees increased during the year ended December 31, 2013, largely as a result of the the full-year contribution from Red Rock Gathering in 2013. The aggregate average throughput rate increased to $0.40 per Mcf during 2013 from $0.31 per Mcf during 2012, largely as a result of the shift in volume throughput mix noted above. For the year ended December 31, 2013, gathering services and related fees included a $28.5 million contribution as a result of the Red Rock Drop Down, compared with a $3.9 million contribution in 2012.

Natural Gas, NGLs and Condensate Sales. The increase in natural gas, NGLs and condensate sales for the year ended December 31, 2014, was primarily a result of growth at Red Rock Gathering.

The increase in natural gas, NGLs and condensate sales for the year ended December 31, 2013, was primarily a result of the Red Rock Drop Down and an increase in the prices we were able to obtain for natural gas sales. For the year ended December 31, 2013, natural gas, NGLs and condensate sales included a $19.3 million contribution as a result of the Red Rock Drop Down, compared with a $4.1 million contribution in 2012.

EX 99.5-16

EXHIBIT 99.5

Other Revenues. The decrease in other revenues for the year ended December 31, 2014 was primarily a result of a $1.1 million decrease in field services revenue, which was partially offset by a $0.7 million increase in reimburseable electricity expense, which due to its pass-through nature, is offset in operation and maintenance expense.

Other revenues increased during the year ended December 31, 2013, largely as a result of the recognition of $1.1 million of field services revenue, a $0.6 million increase in NGL injection fees and a $0.5 million increase in reimburseable electricity expense, which due to its pass-through nature, is offset in operation and maintenance expense.

Cost of Natural Gas and NGLs.The increase in the year ended December 31, 2014 was primarily a result of the growth at Red Rock Gathering system.

For the year ended December 31, 2013, cost of natural gas and NGLs included a $13.2 million contribution as a result of the Red Rock Drop Down, compared with a $3.2 million contribution in 2012.

Operation and Maintenance. Operation and maintenance expense decreased during the year ended December 31, 2014, largely as a result of a $0.8 million decrease in property tax expense.

Operation and maintenance expense increased during the year ended December 31, 2013, largely as a result of the Red Rock Drop Down. For the year ended December 31, 2013, operation and maintenance expense included a $12.5 million contribution as a result of the Red Rock Drop Down in 2013, compared with a $2.2 million contribution in 2012. The increase in operation and maintenance expense was partially offset by a $2.8 million decline in compressor lease and contract maintenance expenses primarily as a result of our purchase of previously leased compression assets in the first quarter of 2013.

General and Administrative. General and administrative expense decreased during the year ended December 31, 2014, largely as a result of a decrease in the proportionate share of salaries, benefits and incentive compensation allocated to the segment.

General and administrative expense increased during the year ended December 31, 2013, largely as a result of an increase in salaries, benefits and incentive compensation primarily due to the Red Rock Drop Down. For the year ended December 31, 2013, general and administrative expense included a $5.5 million contribution as a result of the Red Rock Drop Down, compared with a $0.8 million contribution in 2012.

Depreciation and Amortization. The increase in depreciation and amortization expense during the year ended December 31, 2014 was largely driven by an increase in contract amortization and assets placed into service on the Grand River system.

Depreciation and amortization expense increased during the year ended December 31, 2013 largely due to the Red Rock Drop Down. An increase in contract amortization and assets placed into service in connection with the development of Grand River Gathering also contributed to the increase. Depreciation and amortization expense also included a $9.1 million contribution as a result of the Red Rock Drop Down in 2013, compared with a $1.4 million contribution in 2012.

Other income. Other income represents the write off of certain balances that had been previously recognized in connection with the purchase accounting for the Legacy Grand River system. See "Non-GAAP Financial Measures—Non-GAAP reconciliations items to note" and Note 15 to the audited consolidated financial statements for additional information.

Corporate. Corporate represents those results that are not specifically attributable to a reportable segment or that have not been allocated to our reportable segments, including certain general and administrative expense items, transaction costs and interest expense. Items to note follow.

General and Administrative. General and administrative expense increased during the year ended December 31, 2014, largely as a result of an increase in salaries, benefits and incentive compensation primarily due to increased head count, an increase in professional expenses associated with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 and our adoption of Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission ("COSO 2013"). The substantial majority of our first-year COSO 2013 implementation expenses are not expected to be incurred beyond 2014.

Transaction Costs. Transaction costs for the year ended December 31, 2014, primarily related to financial and legal advisory costs associated with the Red Rock Drop Down. Transaction costs were $2.8 million for the year ended December 31, 2013, of which $2.0 million related to the acquisition of the Mountaineer Midstream system and $0.8

EX 99.5-17

EXHIBIT 99.5

million related to the acquisition of the Bison Midstream system. Transaction costs of $2.0 million in 2012 largely reflect costs associated with Summit Investments' acquisition of Red Rock Gathering in October 2012.

Interest Expense and Affiliated Interest Expense.The increase in interest expense during the year ended December 31, 2014, was primarily driven by our issuance of $300.0 million of 5.50% senior notes in July 2014, our issuance of $300.0 million of 7.50% senior notes in June 2013, and a higher average outstanding balance on our revolving credit facility as a result of our June 2013 and March 2014 borrowings to partially fund the Partnership's acquisition capital expenditures. We used the proceeds from our July 2014 5.50% senior notes offering to partially pay down our revolving credit facility.

The increase in interest expense during the year ended December 31, 2013, primarily reflects our issuance of $300.0 million of 7.50% senior notes in June 2013. Additionally, higher balances on our revolving credit facility beginning in May 2012 as well as an increase in commitment fees as a result of the May 2012 amendment and restatement of the revolving credit facility, which increased our borrowing capacity by $265.0 million and the June 2013 amendment and restatement, which increased our borrowing capacity by $50.0 million, also contributed to the increase in interest expense.

Affiliated interest expense for the year ended December 31, 2012 related to the $200.0 million promissory notes that we issued to the Sponsors in connection with the acquisition of the Grand River system in October 2011. The promissory notes were partially prepaid in May 2012 with the remaining balance repaid in July 2012.

Non-GAAP Financial Measures

EBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with accounting principles generally accepted in the United States of America ("GAAP"). We define EBITDA as net income or loss, plus interest expense, income tax expense, and depreciation and amortization, less interest income and income tax benefit. We define adjusted EBITDA as EBITDA plus adjustments related to MVC shortfall payments, impairments and other noncash expenses or losses, less other noncash income or gains. We define distributable cash flow as adjusted EBITDA plus cash interest received, less cash interest paid, senior notes interest, cash taxes paid and maintenance capital expenditures. We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.

Net income or loss and net cash provided by operating activities are the GAAP financial measures most directly comparable to EBITDA, adjusted EBITDA and distributable cash flow. Our non-GAAP financial measures should not be considered as alternatives to the most directly comparable GAAP financial measure. Furthermore, each of these non-GAAP financial measures has limitations as an analytical tool because it excludes some but not all items that affect the most directly comparable GAAP financial measure. Some of these limitations include:

• certain items excluded from EBITDA, adjusted EBITDA and distributable cash flow are significant components in understanding and assessing a company's financial performance, such as a company's cost of capital and tax structure;

• EBITDA, adjusted EBITDA, and distributable cash flow do not reflect our cash expenditures or future requirements for capital expenditures or contractual commitments;

• EBITDA, adjusted EBITDA, and distributable cash flow do not reflect changes in, or cash requirements for, our working capital needs;

• although depreciation and amortization are noncash charges, the assets being depreciated and amortized will often have to be replaced in the future, and EBITDA, adjusted EBITDA and distributable cash flow do not reflect any cash requirements for such replacements; and

• our computations of EBITDA, adjusted EBITDA and distributable cash flow may not be comparable to other similarly titled measures of other companies.

We compensate for the limitations of EBITDA, adjusted EBITDA and distributable cash flows as analytical tools by reviewing the comparable GAAP financial measures, understanding the differences between the financial measures and incorporating these data points into our decision-making process.

EBITDA, adjusted EBITDA or distributable cash flow should not be considered in isolation or as a substitute for analysis of our results as reported under GAAP. Because EBITDA, adjusted EBITDA and distributable cash flow may be defined differently by other companies in our industry, our definitions of these non-GAAP financial measures may not be comparable to similarly titled measures of other companies, thereby diminishing their utility.

EX 99.5-18

EXHIBIT 99.5

Non-GAAP reconciliations items to note. The following items should be noted when reviewing our non-GAAP reconciliations:

• Interest expense presented in the net income-basis non-GAAP reconciliation includes amortization of deferred loan costs while interest expense presented in the cash flow-basis non-GAAP reconciliation is adjusted to exclude amortization of deferred loan costs. See the consolidated statements of cash flows for additional information.

• Depreciation and amortization includes the favorable and unfavorable gas gathering contract amortization expense reported in other revenues.

• Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected minimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment.

• The goodwill impairment recognized in the year ended December 31, 2014 relates to the Bison Midstream system of our Williston Basin – Gas segment. See "Results of Operations—Williston Basin – Gas," "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" and Note 5 to the audited consolidated financial statements for additional information.

• The long-lived asset impairment recognized in the year ended December 31, 2014 relates to the DFW Midstream system of our Barnett Shale segment. See "Results of Operations—Barnett Shale," "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" and Note 4 to the audited consolidated financial statements for additional information.

• The impact of purchase price adjustments reflects certain balances previously recognized in connection with the Predecessor's purchase accounting for the Legacy Grand River system that we wrote off during the fourth quarter of 2014. This write off was recognized in other income. See "Results of Operations—Piceance Basin" and Note 15 to the audited consolidated financial statements for additional information.

• Senior notes interest represents the net of interest expense accrued and paid during the period. See "Liquidity and Capital Resources—Long-Term Debt" and Note 7 to the audited consolidated financial statements for additional information.

• Maintenance capital expenditures are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity. In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the year ended December 31, 2012 the calculation of distributable cash flow and adjusted distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures.

• As a result of accounting for our drop down transactions similar to a pooling of interests, EBITDA, adjusted EBITDA, and distributable cash flow reflect the historical operations, financial position and cash flows of Polar Midstream, Epping and Red Rock Gathering for the periods beginning with the date that common control began and ending on the date that the respective drop down closed. See Notes 1 and 15 to the audited consolidated financial statements for additional information.

• EBITDA, adjusted EBITDA, distributable cash flow and net cash provided by operating activities include transaction costs. These unusual expenses are settled in cash. For additional information, see "Results of Operations—Corporate" herein.

EX 99.5-19

EXHIBIT 99.5

Net Income-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of net income to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.

	Year ended December 31,
	2014			2013		2012
	(In thousands)
Reconciliation of Net Income to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net (loss) income	$	(14,734	)	$	52,837	$	42,997
Add:
Interest expense	40,159			19,173		12,766
Income tax expense	631			729		682
Depreciation and amortization	88,293			71,606		36,866
Less:
Interest income	4			5		9
EBITDA	$	114,345		$	144,340	$	93,302
Add:
Adjustments related to MVC shortfall payments	26,565			17,025		10,768
Unit-based compensation	5,036			3,846		1,876
Loss on asset sales, net	442			113		—
Goodwill impairment	54,199			—		—
Long-lived asset impairment	5,505			—		—
Less:
Impact of purchase price adjustments	1,185			—		—
Adjusted EBITDA	$	204,907		$	165,324	$	105,946
Add:
Cash interest received	4			5		9
Less:
Cash interest paid	31,524			9,016		8,283
Senior notes interest	6,733			12,125		—
Cash taxes paid	—			660		650
Maintenance capital expenditures	16,336			15,071		6,075
Distributable cash flow	$	150,318		$	128,457	$	90,947

EX 99.5-20

EXHIBIT 99.5

Cash Flow-Basis Non-GAAP Reconciliation. The following table presents a reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow for the periods indicated.

	Year ended December 31,
	2014			2013			2012
	(In thousands)
Reconciliation of Net Cash Provided by Operating Activities to EBITDA, Adjusted EBITDA and Distributable Cash Flow:
Net cash provided by operating activities	$	154,997		$	140,469		$	89,392
Add:
Interest expense	37,389			16,927			5,882
Income tax expense	631			729			682
Impact of purchase price adjustments	1,185			—			—
Changes in operating assets and liabilities	(14,671		)	(9,821		)	(769		)
Less:
Unit-based compensation	5,036			3,846			1,876
Interest income	4			5			9
Loss on asset sales, net	442			113			—
Goodwill impairment	54,199			—			—
Long-lived asset impairment	5,505			—			—
EBITDA	$	114,345		$	144,340		$	93,302
Add:
Adjustments related to MVC shortfall payments	26,565			17,025			10,768
Unit-based compensation	5,036			3,846			1,876
Loss on asset sales, net	442			113			—
Goodwill impairment	54,199			—			—
Long-lived asset impairment	5,505			—			—
Less:
Impact of purchase price adjustments	1,185			—			—
Adjusted EBITDA	$	204,907		$	165,324		$	105,946
Add:
Cash interest received	4			5			9
Less:
Cash interest paid	31,524			9,016			8,283
Senior notes interest	6,733			12,125			—
Cash taxes paid	—			660			650
Maintenance capital expenditures	16,336			15,071			6,075
Distributable cash flow	$	150,318		$	128,457		$	90,947

Liquidity and Capital Resources

Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt securities. Prior to our IPO in October 2012, we largely relied on internally generated cash flows and capital contributions from the Sponsors to satisfy our capital expenditure requirements.

EX 99.5-21

EXHIBIT 99.5

Capital Markets Activity

November 2013 Shelf Registration Statement. In October 2013, we filed a shelf registration statement with the SEC to register up to $1.2 billion of equity and debt securities in primary offerings as well as all of the 14,691,397 common units held by a subsidiary of Summit Investments in accordance with our obligations under several registration rights agreements. In November 2013, the SEC declared our shelf registration statement effective.

In March 2014, we completed an underwritten public offering of 10,350,000 common units at a price of $38.75 per unit, of which 5,300,000 common units were offered by the Partnership and 5,050,000 common units were offered by a subsidiary of Summit Investments. Concurrent with the offering, our general partner made a capital contribution to maintain its 2% general partner interest. We used the proceeds from our primary offering of common units and the general partner capital contribution to fund a portion of the purchase of Red Rock Gathering.

In September 2014, a subsidiary of Summit Investments completed an underwritten public offering of 4,347,826 SMLP common units. We did not receive any proceeds from the this offering.

July 2014 Shelf Registration Statement. In July 2014, we filed a registration statement with the SEC to issue an unlimited amount of debt and equity securities and shortly thereafter completed a public offering of $300.0 million aggregate principal 5.5% senior notes due 2022. We used the proceeds to repay a portion of the outstanding borrowings under our revolving credit facility.

Private Offerings of Debt and Equity. In June 2013, we issued $300.0 million unregistered 7.5% senior unsecured notes and guarantees notes maturing July 1, 2021 (the "7.5% senior notes") and used the net proceeds to partially fund the acquisition of Mountaineer Midstream. In March 2014, the SEC declared our registration statement to exchange all of the unregistered 7.5% senior notes and guarantees for registered senior notes and guarantees with substantially identical terms effective. In April 2014, the exchange period concluded with 100% of the unregistered senior notes being exchanged for registered notes.

In June 2013, we issued common limited partner units and general partner interests to a subsidiary of Summit Investments to partially fund the Bison Drop Down and the acquisition of Mountaineer Midstream.

For additional information, see Notes 1, 7, 8 and 15 to the audited consolidated financial statements.

Long-Term Debt

Revolving Credit Facility. We have a $700.0 million senior secured revolving credit facility. The revolving credit facility is secured by the membership interests of Summit Holdings and those of its subsidiaries. Substantially all of Summit Holdings' and its subsidiaries' assets are pledged as collateral under the revolving credit facility. The facility, and Summit Holdings' obligations, are guaranteed by SMLP and each of its subsidiaries. As of December 31, 2014, the outstanding balance of the revolving credit facility was $208.0 million and the unused portion totaled $492.0 million. As of December 31, 2014, we were in compliance with the covenants in the revolving credit facility. There were no defaults or events of default during 2014.

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Summit Midstream Finance Corp. ("Finance Corp.," together with Summit Holdings, the "Co-Issuers") co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022. In June 2013, the Co-Issuers co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021. The 7.5% senior notes were initially sold in reliance on Rule 144A and Regulation S under the Securities Act. Effective as of April 7, 2014, all of the holders of our 7.5% senior notes exchanged their unregistered 7.5% senior notes and the guarantees of those notes for identical registered notes and guarantees. There were no defaults or events of default during 2014 on either series of senior notes.

For additional information, see Note 7 to the audited consolidated financial statements.

EX 99.5-22

EXHIBIT 99.5

Cash Flows

The components of the change in cash and cash equivalents were as follows:

	Year ended December 31,
	2014			2013			2012
	(In thousands)
Net cash provided by operating activities	$	154,997		$	140,469		$	89,392
Net cash used in investing activities	(536,367		)	(592,393		)	(77,296		)
Net cash provided by (used in) financing activities	387,517			460,947			(16,224		)
Change in cash and cash equivalents	$	6,147		$	9,023		$	(4,128	)

Operating activities. Cash flows from operating activities increased by $14.5 million for the year ended December 31, 2014 largely due to cash received as a result of MVCs.

Cash flows from operating activities increased by $51.1 million for the year ended December 31, 2013 largely as result of the Red Rock Drop Down, an increase in volumes on the DFW Midstream system and the contribution from the Polar and Divide, Bison Midstream and Mountaineer Midstream systems, partially offset by a decline in volumes on the Legacy Grand River system.

Investing activities. Cash flows used in investing activities for the year ended December 31, 2014 primarily reflect the Partnership's acquisition of Red Rock Gathering from a subsidiary of Summit Investments and build out of the Polar and Divide system. Additional expenditures for the year ended December 31, 2014 primarily reflect construction of a processing plant on the Grand River Gathering system, projects to expand compression capacity on the Bison Midstream system, adding pipeline on the Mountaineer Midstream system, the February 2014 commissioning of a new natural gas treating facility on the DFW Midstream system and the purchase of the Lonestar assets.

Cash flows used in investing activities for the year ended December 31, 2013 were largely due to the acquisitions of Bison Midstream and Mountaineer Midstream and construction of the Polar and Divide system. Additional expenditures in 2013 reflect the construction of seven miles of new gathering pipeline across the DFW Midstream system and the acquisition of previously leased compression assets on the Grand River system. We also commissioned a new compressor unit on the DFW Midstream system in January 2013. Development activities also included construction projects to connect new receipt points on the Bison Midstream and DFW Midstream systems and to expand compression capacity on the Bison Midstream system. We also began construction on a new 150 gallon per minute natural gas treating facility on the DFW Midstream system, which was commissioned in the first quarter of 2014.

In 2012, total capital expenditures were largely the result of the construction of new pipeline and compression infrastructure to connect new pad sites on our DFW Midstream system and to install meters and build out medium-pressure infrastructure on our Grand River system.

EX 99.5-23

EXHIBIT 99.5

Financing activities. Details of cash flows provided by financing activities for the three-year period ended December 31, 2014, were as follows:

	Year ended December 31,
	2014			2013			2012
	(In thousands)
Cash flows from financing activities:
Distributions to unitholders	$	(122,224	)	$	(90,196	)	$	—
Borrowings under revolving credit facility	237,295			380,950			213,000
Repayments under revolving credit facility	(315,295		)	(294,180		)	(160,770		)
Deferred loan costs	(5,320		)	(10,608		)	(3,344		)
Tax withholdings on vested SMLP LTIP awards	(656		)	—			—
Proceeds from issuance of common units, net	197,806			—			263,125
Contribution from general partner	4,235			2,229			—
Cash advance from Summit Investments to contributed subsidiaries, net	81,421			72,745			500
Expenses paid by Summit Investments on behalf of contributed subsidiaries	10,483			11,964			2,536
Issuance of senior notes	300,000			300,000			—
Issuance of units to affiliate in connection with the Mountaineer Acquisition	—			100,000			—
Repurchase of equity-based compensation awards	(228		)	(11,957		)	—
Red Rock Gathering cash contributed by Summit Investments	—			—			1,097
Repayment of promissory notes payable to Sponsors	—			—			(209,230		)
Distributions to Sponsors	—			—			(123,138		)
Net cash provided by (used in) financing activities	$	387,517		$	460,947		$	(16,224	)

Net cash provided by financing activities for the year ended December 31, 2014 was primarily composed of the following:

• Proceeds from the July 2014 issuance of 5.5% senior notes, the net of which was used to pay down our revolving credit facility. We incurred loan costs of $5.1 million in connection with their issuance which will be amortized over the life of the 5.5% senior notes;

• Borrowings of $100.0 million under our revolving credit facility to partially fund the Red Rock Drop Down;

• Net proceeds from an offering of common units in March 2014, which were used to partially fund the Red Rock Drop Down;

• Distributions declared in respect of the first, second and third quarters of 2014 and the fourth quarter of 2013 (paid in the first quarter of 2014); and

• Cash advances to support the buildout of the Polar and Divide system.

Net cash provided by financing activities for the year ended December 31, 2013 was primarily composed of the following:

• Distributions declared in respect of the first, second and third quarters of 2013 and the fourth quarter of 2012 (paid in the first quarter of 2013);

• Borrowings under our revolving credit facility, of which $200.0 million was used to partially fund the Bison Drop Down and $110.0 million was used to partially fund the Mountaineer Acquisition;

• Proceeds from the June 2013 issuance of 7.5% senior notes, the net of which was used to pay down our revolving credit facility. We incurred loan costs of $7.4 million in connection with the senior notes issuance which will be amortized over the life of the 7.5% senior notes;

• Payments of $294.2 million on our revolving credit facility, all of which was funded by the June 2013 issuance of 7.5% senior notes;

• Issuance of $98.0 million of common units and $2.0 million of general partner interests to Summit Investments for cash to partially fund the Mountaineer Acquisition; and

EX 99.5-24

EXHIBIT 99.5

• Cash advances to support the buildout of the Polar and Divide system.

Net cash used in financing activities for the year ended December 31, 2012 was primarily composed of the following:

• Borrowings of $163.0 million under the revolving credit facility in May 2012, of which we used $160.0 million to prepay principal amounts outstanding under certain unsecured promissory notes payable to the Sponsors and borrowings of $50.0 million in July 2012, of which we used $49.2 million to repay the balance of the unsecured promissory notes payable to the Sponsors; and

• Proceeds of $263.1 million from the issuance of our common units in connection with our IPO (including the proceeds from the exercise of the underwriters' option to purchase additional common units). We used $140.0 million of the IPO proceeds to pay down our revolving credit facility. We also paid $88.0 million to reimburse Summit Investments for certain capital expenditures it incurred with respect to assets it contributed to us and distributed $35.1 million to Summit Investments for the common units it sold from the units originally allocated to it in connection with the exercise of the underwriters' option to purchase additional common units.

Contractual Obligations

The table below summarizes our contractual obligations and other commitments as of December 31, 2014:

	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In thousands)
Long-term debt and interest payments (1)	$	1,128,219	$	47,014	$	94,027	$	292,678	$	694,500
Purchase obligations (2)	24,122		20,547		3,462		113		—
Total contractual obligations	$	1,152,341	$	67,561	$	97,489	$	292,791	$	694,500

__________

(1) For the purpose of calculating future interest on the revolving credit facility, assumes no change in balance or rate from December 31, 2014. Includes a 0.50% commitment fee on the unused portion of the revolving credit facility. See Note 7 to the audited consolidated financial statements for additional information.

(2) Represents agreements to purchase goods or services that are enforceable and legally binding.

Operating leases. A substantial majority of the operating leases that support our operations have been entered into by Summit Investments with the associated rent expense allocated to us. Future minimum lease payments associated with operating leases in the Partnership's name are immaterial. See Note 14 to the audited consolidated financial statements for additional information.

Capital Requirements

Our business is capital-intensive, requiring significant investment for the maintenance of existing gathering systems and the acquisition or construction and development of new gathering systems and other midstream assets and facilities. Our partnership agreement requires that we categorize our capital expenditures as either:

• maintenance capital expenditures, which are cash expenditures (including expenditures for the addition or improvement to, or the replacement of, our capital assets or for the acquisition of existing, or the construction or development of new, capital assets) made to maintain our long-term operating income or operating capacity; or

• expansion capital expenditures, which are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating income or operating capacity over the long term.

In the fourth quarter of 2012, we began tracking maintenance capital expenditures for the purposes of calculating distributable cash flow. Prior to the fourth quarter of 2012, we did not distinguish between maintenance and expansion capital expenditures. For the year ended December 31, 2012, distributable cash flow includes an estimate for the portion of total capital expenditures that were maintenance capital expenditures for nine months ended September 30, 2012.

For the year ended December 31, 2014, SMLP recorded total capital expenditures of $220.8 million, which included $16.3 million of maintenance capital expenditures. Total acquisition capital expenditures of $318.8 million included $307.9 million to fund the Red Rock Drop Down (including a $2.9 million working capital adjustment settled in 2015) and $10.9 million for the acquisition of the Lonestar assets. Other expansion capital expenditures during 2014 were

EX 99.5-25

EXHIBIT 99.5

primarily related to construction of the Polar and Divide system, compression capacity expansion work on the Bison Midstream system and the construction of pipeline and additional compressor capacity for Mountaineer Midstream.

We anticipate that we will continue to make significant expansion capital expenditures in the future. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives. We expect that our future expansion capital expenditures will be funded by borrowings under the revolving credit facility and the issuance of debt and equity securities.

We believe that our existing $700.0 million revolving credit facility, which had approximately $492.0 million of available capacity at December 31, 2014, together with our access to the debt and equity capital markets, will be adequate to finance our acquisition strategy for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.

Distributions

Based on the terms of our partnership agreement, we expect to distribute to unitholders most of the cash generated by our operations. For additional information, see "Our Cash Distribution Policy and Restrictions on Distributions" in Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities and Note 8 to the audited consolidated financial statements.

Credit Risk and Customer Concentration

We examine the creditworthiness of counterparties to whom we extend credit and manage our exposure to credit risk through credit analysis, credit approval, credit limits and monitoring procedures, and for certain transactions, we may request letters of credit, prepayments or guarantees. For additional information, see Note 11 to the audited consolidated financial statements.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the year ended December 31, 2014.

Critical Accounting Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the Financial Accounting Standards Board. We employ methods, estimates and assumptions based on currently available information when recording transactions resulting from business operations. Our significant accounting policies are described in Note 2 to the audited consolidated financial statements.

The estimates that we deem to be most critical to an understanding of our financial position and results of operations are those related to determination of fair value and recognition of deferred revenue. The preparation and evaluation of these critical accounting estimates involve the use of various assumptions developed from management's analyses and judgments. Subsequent experience or use of other methods, estimates or assumptions could produce significantly different results. Our critical accounting estimates are as follows:

Recognition and Impairment of Long-Lived Assets

Our long-lived assets include property, plant and equipment, our contract intangible assets and goodwill.

Property, Plant and Equipment and Intangible Assets. As of December 31, 2014, we had net property, plant and equipment with a carrying value of approximately $1.4 billion and net intangible assets with a carrying value of approximately $477.7 million.

When evidence exists that we will not be able to recover a long-lived asset's carrying value through future cash flows, we write down the carrying value of the asset to its estimated fair value. We test assets for impairment when events or circumstances indicate that the carrying value of a long-lived asset may not be recoverable. With respect to property, plant and equipment and our contract intangible assets, the carrying value of a long-lived asset is not recoverable if the carrying value exceeds the sum of the undiscounted cash flows expected to result from the asset's use and eventual disposal. In this situation, we recognize an impairment loss equal to the amount by which the carrying value exceeds the asset's fair value. We determine fair value using an income approach in which we discount the asset's expected future cash flows to reflect the risk associated with achieving the underlying cash flows.

• During the fourth quarter of 2014, prices for natural gas, NGLs and crude oil continued to decline such that we identified a need to evaluate the goodwill associated with the Polar and Divide and Bison Midstream systems. In connection with this evaluation, we also evaluated the property, plant and equipment and

EX 99.5-26

EXHIBIT 99.5

intangible assets of these reporting unit for impairment and concluded that no impairment was necessary. During the fourth quarter of 2014, we also reviewed certain property, plant and equipment balances associated with a compressor station project on our DFW Midstream system that was terminated and concluded that a portion of their carrying value was no longer recoverable. As such, we wrote off approximately $5.5 million of costs and reflected the net impact of this action in long-lived asset impairment on the statement of operations.

• During the years ended December 31, 2013 and 2012, we concluded that none of our long-lived assets had been impaired.

For additional information, see Notes 2, 4 and 5 to the audited consolidated financial statements.

Goodwill. We evaluate goodwill for impairment annually on September 30. We also evaluate goodwill whenever events or circumstances indicate that it is more likely than not that the fair value of a reporting unit is less than its carrying value, including goodwill. We have four reporting units which have goodwill: (i) Polar and Divide, (ii) Grand River Gathering, (iii) Bison Midstream and (iv) Mountaineer Midstream.

We performed our annual goodwill impairment analysis as of September 30, 2014. We determined that the fair value of the Polar and Divide, Grand River Gathering and Mountaineer Midstream reporting units substantially exceeded their carrying value, including goodwill. We also determined that the fair value of the Bison Midstream reporting unit exceeded its carrying value, including $54.2 million of goodwill, although it did not exceed its carrying value by a substantial amount. In connection therewith, we concluded that the fair values of our reporting units exceeded their carrying values, including goodwill, and as such concluded that none of our goodwill had been impaired.

During the latter part of the fourth quarter of 2014, the declines in prices for natural gas, NGLs and crude oil accelerated, negatively impacting producers in each of our areas of operation. As a result, we considered whether the goodwill associated with our Polar and Divide, Grand River Gathering, Mountaineer Midstream and Bison Midstream reporting units could have been impaired. Our assessments related to Grand River Gathering and Mountaineer Midstream did not result in an indication that the associated goodwill had been impaired. Furthermore, we do not believe that either reporting unit is at risk of failing step one of the goodwill impairment test as of December 31, 2014 due to the substantial amounts by which each reporting unit’s fair value, including goodwill, exceeded its carrying value, including goodwill.

We also assessed whether the goodwill associated with the Polar and Divide and Bison Midstream reporting units could have been impaired. In connection therewith, we noted that the Polar and Divide reporting unit had been impacted by the recent price declines, thereby increasing the likelihood that the associated goodwill could have been impaired. As such, we concluded that a triggering event occurred during the fourth quarter of 2014 requiring that we test Polar Midstream's goodwill. The results of our step one goodwill impairment testing indicated that the fair value of the Polar and Divide reporting unit exceeded its carrying value, including goodwill. Because its fair value exceeded its carrying value, including goodwill, there was no impairment associated with the fourth quarter triggering event.

We also noted that a key Bison Midstream customer announced that it was delaying its previously announced drilling plans. The combined impact of (i) the price declines on revenues under its percent-of proceeds contracts and (ii) the Partnership's reduction in its forecasted volume assumption in response to the decline in our customer’s drilling plans increased the likelihood that the goodwill associated with the Bison Midstream reporting unit was impaired. As such, we concluded that a triggering event occurred during the fourth quarter of 2014 requiring that we test the goodwill associated with the Bison Midstream reporting unit for impairment.

The results of our step one goodwill impairment testing indicated that the fair value of the Bison Midstream reporting unit was below its carrying value, including goodwill. This result required that we perform step two of the goodwill impairment test. To perform step two, we first determined the fair values of the identifiable assets and liabilities. Significant assumptions utilized in the determination of the fair value of each reporting unit's individual assets and liabilities included the determination of discount rate and contributing asset charge utilized in our contract intangibles, expected levels of throughput volume and associated capital expenditures and commodity prices.

Our preliminary estimates of the fair values of the identified assets and liabilities calculated in the step two testing of the Bison Midstream reporting unit indicated that all of the associated goodwill had been impaired. As such, we recorded an estimated goodwill impairment of $54.2 million. This amount represents our best estimate of impairment pending the finalization of the fair value calculations, which we expect to finalize in the first quarter of 2015.

See Notes 2 and 5 to the audited consolidated financial statements for additional information.

EX 99.5-27

EXHIBIT 99.5

Minimum Volume Commitments

The majority of our gathering agreements provide for a monthly or annual MVC from our customers. As of December 31, 2014, we had MVCs totaling 4.0 Tcf through 2026. Under these monthly, quarterly or annual MVCs, our customers agree to ship a minimum volume of throughput on our gathering systems or to pay a minimum monetary amount over certain periods during the term of the MVC. A customer must make a shortfall payment to us at the end of the contract month, quarter or year, as applicable, if its actual throughput volumes are less than its MVC for the applicable period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent periods to the extent that such customer's throughput volumes in subsequent periods exceed its MVC for that period.

We recognize customer billings for obligations under their MVCs as revenue when the obligations are billable under the contract and the customer does not have the right to utilize shortfall payments to offset gathering fees in excess of its MVCs in subsequent periods.

We record customer billings for obligations under their MVCs as deferred revenue when the customer has the right to utilize shortfall payments to offset gathering or processing fees in subsequent periods. We recognize deferred revenue under these arrangements in revenue once all contingencies or potential performance obligations associated with the related volumes have either (i) been satisfied through the gathering or processing of future excess volume throughput, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable gathering agreement.

We classify deferred revenue as a current liability for arrangements where the expiration of a customer's right to utilize shortfall payments is twelve months or less. We classify deferred revenue as noncurrent for arrangements where the expiration of the right to utilize shortfall payments and our estimate of its potential utilization is more than 12 months. As of December 31, 2014, current deferred revenue totaled $2.4 million. Noncurrent deferred revenue totaled $55.2 million at December 31, 2014 and represents amounts that provide these customers the ability to offset their gathering fees over a period up to seven years to the extent that their throughput volumes exceed their MVC.

We billed $50.9 million of MVC shortfall payments to customers that did not meet their MVCs during 2014. Certain of our gathering agreements do not have credit banking mechanisms and as such, the MVC shortfall payments from these customers are accounted for as revenue in the period that they are earned. We recognized $1.5 million of gathering revenue due to the credit bank expiration of previous MVC shortfall payments and $22.7 million of gathering revenue associated with MVC shortfall payments in 2014. Of the billings for MVC shortfall payments, $26.4 million was recorded as deferred revenue on SMLP’s balance sheet because these customers have the ability to use these MVC shortfall payments to offset gathering fees related to future throughput in excess of future period MVCs. MVC shortfall payment adjustments in the fourth quarter of 2014 totaled $0.2 million and included adjustments related to future anticipated shortfall payments. The net impact on adjusted EBITDA of MVC billings and their recognition was $50.8 million.

EX 99.5-28

EXHIBIT 99.5

The following table presents the impact of our MVC activity by reportable segment during the year ended December 31, 2014.

	Year ended December 31, 2014
	MVC billings		Gathering revenue		Adjustments to MVC shortfall payments			Net impact to adjusted EBITDA
	(In thousands)
Net change in deferred revenue:
Williston Basin – Gas	$	10,743	$	—	$	10,743		$	10,743
Barnett Shale	2,609		1,525		821			2,346
Piceance Basin	14,813		—		14,813			14,813
Total change in deferred revenue	$	28,165	$	1,525	$	26,377		$	27,902
MVC shortfall payment adjustments:
Marcellus Shale	$	1,742	$	1,742	$	—		$	1,742
Barnett Shale	495		495		(193		)	302
Piceance Basin	20,462		20,462		381			20,843
Total MVC shortfall payment adjustments	$	22,699	$	22,699	$	188		$	22,887
Total	$	50,864	$	24,224	$	26,565		$	50,789

For additional information, see Notes 2 and 6 to the audited consolidated financial statements.

EX 99.5-29