smlp-ex992

EX-99 4 smlp-ex992_7.htm EX-99.2 smlp-ex992_7.htm

EXHIBIT 99.2

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

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 consolidated financial statements and notes thereto included in this report. Among other things, the consolidated 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. Actual results may differ materially from those contained in any forward-looking statements.

This MD&A comprises the following sections:

•

Overview

•

Trends and Outlook

•

How We Evaluate Our Operations

•

Results of Operations

•

Liquidity and Capital Resources

•

Critical Accounting Estimates

•

Forward-Looking Statements

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 the continental United States. We are the owner-operator of or have significant ownership interests in the following gathering systems:

•

Ohio Gathering, a natural gas gathering system and a condensate stabilization facility operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;

•

Summit Utica, a natural gas gathering system operating in the Appalachian Basin, which includes the Utica and Point Pleasant shale formations in southeastern Ohio;

•

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

•

Polar and Divide, crude oil and produced water gathering systems and transmission pipelines located in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

•

Tioga Midstream, crude oil, produced water and associated natural gas gathering systems operating in the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

•

Grand River, 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;

•

Niobrara G&P, an associated natural gas gathering and processing system operating in the DJ Basin, which includes the Niobrara and Codell shale formations in northeastern Colorado;

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•

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

•

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

For additional information on our organization and systems, see Notes 1 and 3 to the consolidated financial statements.

Our financial results are driven primarily by volume throughput and expense management. We generate the majority of our revenues from the gathering, treating and processing services that we provide to our customers. A substantial majority of the volumes that we gather, treat and/or process have a fixed-fee rate structure thereby enhancing the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk. We also earn revenues from (i) the sale of physical natural gas and NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream and Grand River systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. These additional activities, which expose us to direct commodity price risk, accounted for less than 9% of total revenues during the year ended December 31, 2016.

We also have indirect exposure to changes in commodity prices in that persistently low commodity prices may cause our customers to delay and/or cancel drilling and/or completion activities 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 certain of our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, the associated MVCs ensure that we will recognize a minimum amount of revenue.

The following table presents certain annual consolidated financial data.

	Year ended December 31,
	2016			2015			2014
	(In thousands)
Net loss	$	(38,187	)	$	(222,228	)	$	(47,368	)
Reportable segment adjusted EBITDA:
Utica Shale		21,035			2,206			170
Ohio Gathering		45,602			33,667			6,006
Williston Basin		79,475			34,008			30,009
Piceance/DJ Basins		109,241			110,222			110,763
Barnett Shale		54,634			59,526			60,528
Marcellus Shale		19,203			23,214			15,940

Net cash provided by operating activities	$	230,495		$	191,375		$	152,953
Acquisitions of gathering systems (1)		866,858			288,618			315,872
Capital expenditures (2)		142,719			272,225			343,380
Contributions to equity method investees		31,582			86,200			145,131

Distributions to unitholders	$	167,504		$	152,074		$	122,224
Issuance of senior notes		—			—			300,000
Borrowings (repayments) under Revolving Credit Facility, net		316,000			216,000			(136,000	)
Proceeds from issuance of common units, net (3)		125,233			221,977			197,806

(1) Reflects cash and noncash consideration, including working capital and capital expenditure adjustments paid (received), for acquisitions and/or drop downs (see Notes 11 and 16 to the consolidated financial statements).

(2) See "Liquidity and Capital Resources" herein and Note 3 to the consolidated financial statements for additional information on capital expenditures.

(3) Reflects proceeds from underwritten primary offerings.

Year ended December 31, 2016. The following items are reflected in our financial results:

•

In March 2016, we acquired the 2016 Drop Down Assets from a subsidiary of Summit Investments. We funded the drop down with borrowings under our Revolving Credit Facility and the execution of the Deferred

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Purchase Price Obligation with Summit Investments (see Notes 9, 11 and 16 to the consolidated financial statements).

•

In June 2016, an impairment loss was recognized by OCC. We recorded our 40% share of the impairment loss, or $37.8 million, in loss from equity method investees in the consolidated statements of operations. We exclude income or loss from equity method investees from our definition of segment adjusted EBITDA. As such, the Ohio Gathering segment adjusted EBITDA was not impacted by the impairment loss (see Note 7 to the consolidated financial statements).

•

In September 2016, we completed an underwritten public offering of 5,500,000 common units at a price of $23.20 per unit and used the net proceeds to pay down our Revolving Credit Facility. Following the offering, our General Partner made a capital contribution to us to maintain its approximate 2% general partner interest (see Note 11 to the consolidated financial statements).

Year ended December 31, 2015. The following items are reflected in our financial results:

•

In May 2015, we acquired Polar and Divide from a subsidiary of Summit Investments. We funded the drop down with the issuance of common units, borrowings under our Revolving Credit Facility and a General Partner contribution (see Notes 11 and 16 to the consolidated financial statements).

•

In May 2015, we completed an underwritten public offering of 7,475,000 common units at a price of $30.75 per unit and used a portion of the net proceeds to partially fund the Polar and Divide Drop Down. Following the offering, our General Partner made a capital contribution to us to maintain its approximate 2% general partner interest (see Note 11 to the consolidated financial statements).

•

In September 2015, we recognized $34.4 million of gathering services and related fees revenue that had been previously deferred in connection with an MVC arrangement with a certain Piceance/DJ Basins customer, which was determined to no longer be recoverable by the customer. We include the effect of adjustments related to MVC shortfall payments in our definition of segment adjusted EBITDA. As such, Piceance/DJ Basins segment adjusted EBITDA was not impacted because the revenue recognition was offset by the associated adjustments related to MVC shortfall payments for this customer (see Note 8 to the consolidated financial statements).

•

In September and December 2015, we recognized additional accruals for environmental remediation expenses totaling $21.8 million associated with the rupture of a produced water gathering pipeline in the Williston Basin reportable segment (see Note 15 to the consolidated financial statements).

•

After a slight pause mid-year 2015, crude oil and NGL prices continued to decline in response to the global supply surplus. As a result, several of the producers in our areas of operations announced plans to cancel, delay and/or reduce drilling plans, which in turn negatively impacted the margins that we earn, slowing the growth in net income. In addition to impacting the margins that we earn and net income, the goodwill that we had previously recognized in connection with our acquisitions of Polar and Divide and Grand River was determined to be fully impaired, resulting in a write-off of $248.9 million (see Note 6 to the consolidated financial statements).

Year ended December 31, 2014. The following items are reflected in our financial results:

•

In the second half of 2014, crude oil and NGL prices began to decline, negatively impacting producers in each of our areas of operation. The impact of these declines were most evident in our North Dakota operations where our percentage of fee-based gathering agreements is less than that of our other systems. In addition to impacting the margins that we earned, the goodwill that we had previously recognized in connection with our acquisition of Bison Midstream was determined to be fully impaired, resulting in a write-off of $54.2 million (see Note 6 to the consolidated financial statements).

•

In March 2014, we acquired Red Rock Gathering from a subsidiary of Summit Investments in a drop down transaction (see Notes 11 and 16 to the consolidated financial statements). We also completed several system expansion projects across all systems.

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•

In March 2014, we completed an underwritten public offering of 5,300,000 common units at a price of $38.75 per unit and used a portion of the net proceeds to partially fund the Red Rock Drop Down. Following the offering, our General Partner made a capital contribution to us to maintain its approximate 2% general partner interest (see Note 11 to the consolidated financial statements).

•

In July 2014, we issued $300.0 million of 5.5% Senior Notes and used the proceeds to repay a portion of our outstanding Revolving Credit Facility balance (see Note 9 to the consolidated financial statements).

Trends and Outlook

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

•

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.

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. The price of natural gas rebounded during 2016, with the New York Mercantile Exchange, or NYMEX, natural gas futures price at $3.71 per one million British Thermal Units ("MMBtu") as of December 30, 2016, compared with $2.28 per MMBtu as of December 31, 2015. Despite the significant increase, natural gas prices continue to trade at lower-than-average historical prices due in part to increased natural gas production and the amount of natural gas in storage in the continental United States. In the near term, we believe that until the supply of natural gas in storage has been reduced, natural gas prices are likely to remain constrained. Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by global population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation.

In addition, certain of our gathering systems are directly affected by crude oil supply and demand dynamics. Similar to natural gas prices, crude oil prices increased significantly during 2016, with the West Texas Intermediate ("WTI") crude oil price benchmark increasing by 105% from February to December of 2016, when it closed at $53.75 per barrel. In response to the increase in crude oil prices, the number of active crude oil drilling rigs in the continental United States increased from a low of 316 in May 2016 to 525 in December 2016, according to Baker Hughes. Over the next several years, we expect that crude oil prices will rebound sufficiently to support continued drilling and increasing production in the Bakken Shale, Eagle Ford Shale, Permian Basin and Niobrara Shale.

Growth in production from U.S. shale plays. Over the past several years, natural gas production from unconventional shale resources has increased significantly due to advances in technology that allow producers to extract significant volumes of natural gas from unconventional shale plays on favorable economic terms relative to most conventional plays. In recent years, a number of producers and their joint venture partners, including large international operators, industrial manufacturers and private equity sponsors, have committed significant capital to the development of these unconventional resources, including the Piceance Basin, Barnett, Bakken, Marcellus and Utica shale plays in which we operate, and we believe that these long-term capital investments will support sustained drilling activity in unconventional shale plays.

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Capital markets availability and cost of capital. Credit markets improved substantially throughout 2016, as borrowing costs were lower relative to the levels generally experienced during the 2008 global financial crisis for virtually all energy industry-related borrowers. The credit market trends in the crude oil and natural gas industry during 2016 were unique relative to the broader economy. While borrowing costs came down for the oil and natural gas industry as a whole, the Federal Reserve announced that it raised its benchmark federal-funds rate from 0.25% and 0.50% to a range between 0.50% and 0.75% in December 2016. The Federal Reserve also announced its intent to continue to raise interest rates gradually in the future, to the extent that economic growth continues. Capital markets conditions, including but not limited to availability and higher borrowing costs, 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 peers and competitors would likely face similar circumstances.

Shifts in operating costs and inflation. Throughout most of the last five years, 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, equipment and other services. Beginning in 2015, this dynamic began to shift as prices for crude oil and natural gas-related services decreased in line with overall decline in demand for these goods and services. While we expect lower service-related costs in the near term, we expect that over the longer term, these costs will continue to have a high correlation to changes in the prevailing price of crude oil and natural gas.

How We Evaluate Our Operations

We conduct and report our operations in the midstream energy industry through six reportable segments:

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the Utica Shale, which is served by Summit Utica;

•

Ohio Gathering, which includes our ownership interest in OGC and OCC;

•

the Williston Basin, which is served by Bison Midstream, Polar and Divide and Tioga Midstream;

•

the Piceance/DJ Basins, which is served by Grand River and Niobrara G&P;

•

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

•

the Marcellus Shale, which is served by Mountaineer Midstream.

Each of our reportable segments provides midstream services in a specific geographic area. Our reportable segments reflect the way in which we internally report the financial information used to make decisions and allocate resources in connection with our operations (see Note 3 to the consolidated financial statements).

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 determining the amounts of cash distributions to pay to our unitholders. These metrics include:

•

throughput volume,

•

revenues,

•

operation and maintenance expenses and

•

segment adjusted EBITDA.

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.

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EXHIBIT 99.2

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 supplies of throughput is impacted by:

•

successful drilling activity within our AMIs;

•

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 AMIs awaiting connections;

•

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

•

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

We report volumes gathered for natural gas in cubic feet per day. We aggregate crude oil and produced water gathering and report volumes gathered in barrels per day.

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 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.

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.

Segment Adjusted EBITDA

Segment adjusted EBITDA is used as a supplemental financial measure by management and by external users of our financial statements such as investors, commercial banks, research analysts and others.

Segment adjusted EBITDA is used to assess:

•

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

•

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

•

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;

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EXHIBIT 99.2

•

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

•

the financial performance of our assets without regard to (i) income or loss from equity method investees, (ii) the impact of the timing of minimum volume commitment shortfall payments under our gathering agreements or (iii) the timing of impairments or other noncash income or expense items.

Items Affecting the Comparability of Our Financial Results

Our historical results of operations may not be comparable to our future results of operations for the reasons described below:

•

The consolidated financial statements reflect the results of operations of Summit Utica since December 2014. We accounted for the drop down of these assets on an "as-if pooled" basis because the transactions were executed by entities under common control.

•

The consolidated financial statements reflect the results of operations of Tioga Midstream since April 2014. We accounted for the drop down of these assets on an "as-if pooled" basis because the transactions were executed by entities under common control.

•

The consolidated financial statements reflect the results of operations of Ohio Gathering since January 2014. We accounted for the drop down of these assets on an "as-if pooled" basis because the transactions were executed by entities under common control.

Additional Information. For additional information, see the "Results of Operations" section herein and the notes to the consolidated financial statements. For information on impending accounting changes that are expected to materially impact our financial results reported in future periods, see Note 2 to the 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 NGLs purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream and Grand River systems, (ii) the sale of natural gas we retain from certain DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services on the Grand River system.

Other revenues. Revenue earned primarily from (i) certain costs for which our Bison Midstream and Grand River 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 arrangements under which we sell natural gas and NGLs purchased from certain of our customers on the Bison Midstream and Grand River 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.

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.

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EXHIBIT 99.2

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

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

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

Interest expense. Interest expense associated with our Revolving Credit Facility, our Senior Notes and debt that was previously incurred by SMP Holdings and allocated to SMLP in connection with the 2016 Drop Down.

Deferred Purchase Price Obligation expense. Represents the expense associated with the Deferred Purchase Price Obligation.

Income tax expense or benefit. Represents the expense or benefit associated with the Texas Margin Tax.

Income or loss from equity method investees. Represents the income or loss associated with our ownership interest in Ohio Gathering.

Consolidated Overview of the Years Ended December 31, 2016, 2015 and 2014

The following table presents certain consolidated and operating data for the years ended December 31.

	Year ended December 31,									Percentage Change
	2016			2015			2014			2016 v. 2015			2015 v. 2014
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	345,961		$	337,819		$	267,478			2	%		26	%
Natural gas, NGLs and condensate sales		35,833			42,079			97,094			(15	)%		(57	)%
Other revenues		20,568			20,659			22,597		—		%		(9	)%
Total revenues		402,362			400,557			387,169		—		%		3	%
Costs and expenses:
Cost of natural gas and NGLs		27,421			31,398			72,415			(13	)%		(57	)%
Operation and maintenance		95,334			94,986			94,869		—		%	—		%
General and administrative		52,410			45,108			43,281			16	%		4	%
Depreciation and amortization		112,239			105,117			90,878			7	%		16	%
Transaction costs		1,321			1,342			2,985			(2	)%		(55	)%
Environmental remediation		—			21,800			5,000		*			*
Loss (gain) on asset sales, net		93			(172	)		442		*			*
Long-lived asset impairment		1,764			9,305			5,505		*			*
Goodwill impairment		—			248,851			54,199		*			*
Total costs and expenses		290,582			557,735			369,574			(48	)%		51	%
Other income		116			2			1,189		*			*
Interest expense		(63,810	)		(59,092	)		(48,586	)		8	%		22	%
Deferred Purchase Price Obligation expense		(55,854	)		—			—		*			—		%
Loss before income taxes and loss from equity method investees		(7,768	)		(216,268	)		(29,802	)	*			*
Income tax (expense) benefit		(75	)		603			(854	)	*			*
Loss from equity method investees		(30,344	)		(6,563	)		(16,712	)	*				(61	)%
Net loss	$	(38,187	)	$	(222,228	)	$	(47,368	)		(83	)%	*

Operating Data:
Aggregate average daily throughput – natural gas (MMcf/d)		1,528			1,499			1,423			2	%		5	%
Aggregate average daily throughput – liquids (Mbbl/d)		88.9			67.7			40.7			31	%		66	%

* Not considered meaningful

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Volumes – Gas. Natural gas throughput volumes increased 29 MMcf/d during the year ended December 31, 2016, as compared to the prior year, primarily reflecting:

•

a volume throughput increase of 149 MMcf/d for the Utica Shale segment.

•

a volume throughput decrease of 63 MMcf/d for the Marcellus Shale segment.

•

a volume throughput decrease of 33 MMcf/d for the Barnett Shale segment.

•

a volume throughput decrease of 23 MMcf/d for the Piceance/DJ Basins segment.

Natural gas throughput volumes increased 76 MMcf/d during the year ended December 31, 2015, as compared to the prior year, primarily reflecting:

•

a volume throughput increase of 96 MMcf/d for the Marcellus Shale segment.

•

a volume throughput increase of 36 MMcf/d for the Utica Shale segment.

•

a volume throughput decrease of 54 MMcf/d for the Piceance/DJ Basins segment.

Volumes – Liquids. Crude oil and produced water throughput volumes increased 21.2 Mbbl/d during the year ended December 31, 2016, primarily reflecting the continued development of the Polar and Divide and Tioga Midstream systems, new pad site connections and producers' ongoing drilling activity, partially offset by the second quarter 2016 impact of certain customers shutting in existing production while completion activities occurred.

Crude oil and produced water throughput volumes increased 27.0 Mbbl/d during the year ended December 31, 2015, primarily reflecting the continued development of the Polar and Divide and Tioga Midstream systems, new pad site connections and producers' ongoing drilling activity, partially offset by the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines constrained volume throughput in the first nine months of 2015 (see Note 15 to the consolidated financial statements).

Revenues. Total revenues increased $1.8 million, or 0.5%, during the year ended December 31, 2016, as compared to the prior year, primarily reflecting:

•

an $8.1 million increase in gathering services and related fees primarily as a result of increases for the Utica Shale and Williston Basin segments, partially offset by decreases for the Piceance/DJ Basins, Barnett Shale and Marcellus Shale segments.

•

a $6.2 million decline in natural gas, NGLs and condensate sales due to decreases for the Williston Basin, Piceance/DJ Basins and Barnett Shale segments.

Total revenues increased $13.4 million, or 3%, during the year ended December 31, 2015, as compared to the prior year, primarily reflecting:

•

a $70.3 million increase in gathering services and related fees primarily as a result of the recognition in 2015 of $34.4 million of previously deferred revenue at Grand River (see Note 8 to the consolidated financial statements) and general growth across all segments.

•

a $55.0 million decrease in natural gas, NGLs and condensate sales for the Williston Basin, Piceance/DJ Basins and Barnett Shale segments primarily as a result of the impact of commodity price declines.

Gathering Services and Related Fees. The increase in gathering services and related fees during the year ended December 31, 2016 primarily reflected:

•

an increase of $27.1 million for the Williston Basin segment primarily due to higher volume throughput on the Polar and Divide system as well as the growth of the Tioga Midstream system.

•

an increase of $19.6 million for the Utica Shale segment due to the development of the Summit Utica system.

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EXHIBIT 99.2

•

a $27.9 million decrease in gathering services and related fees for the Piceance/DJ Basins segment primarily as a result of the 2015 recognition of $34.4 million of deferred revenue for the Grand River system.

•

an $8.2 million decrease for the Barnett Shale segment primarily due to lower volume throughput on the DFW Midstream system.

The increase in gathering services and related fees during the year ended December 31, 2015 primarily reflected:

•

the above-mentioned $34.4 million recognition of previously deferred revenue for the Grand River system.

•

higher volume throughput for the Polar and Divide, Tioga Midstream, Mountaineer Midstream and Summit Utica systems.

Natural Gas, NGLs and Condensate Sales. The decrease in natural gas, NGLs and condensate sales during the year ended December 31, 2016 primarily reflected the impact on pricing and throughput of lower commodity prices on our Williston Basin, Piceance/DJ Basins and Barnett Shale segments, which in turn impacted volume throughput as well as the associated sales, during the first half of 2016.

The decrease in natural gas, NGLs and condensate sales during the year ended December 31, 2015 was primarily a result of the impact on pricing and throughput of declining commodity prices during 2015 on our Williston Basin, Piceance/DJ Basins and Barnett Shale segments.

Commodity prices and changes therein have a direct impact on our percent-of-proceeds arrangements for the Bison Midstream and Grand River systems, our fuel retainage revenue for the DFW Midstream system and condensate revenue for the Grand River system.

Costs and Expenses. Total costs and expenses decreased $267.2 million, or 48%, for the year ended December 31, 2016, as compared to the prior year, primarily reflecting:

•

the 2015 recognition of $248.9 million of goodwill impairments for the Williston Basin and Piceance/DJ Basins segments.

•

the 2015 recognition of a $21.8 million environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down.

•

a $7.5 million decrease in long-lived asset impairments, primarily for the Williston Basin segment.

•

a $4.0 million decrease in cost of natural gas and NGLs for the Bison Midstream and Grand River systems primarily due the impact of declining commodity prices on their percent-of-proceeds and condensate sales activity during the first half of 2016.

•

a $7.3 million increase in general and administrative expense primarily due to an increase in salaries, benefits and incentive compensation.

•

a $7.1 million increase in depreciation and amortization for all segments.

Total costs and expenses increased $188.2 million, or 51%, for the year ended December 31, 2015, as compared to the prior year, primarily reflecting:

•

the 2015 recognition of $248.9 million of goodwill impairments for the Williston Basin and Piceance/DJ Basins segments.

•

the 2015 recognition of a $21.8 million environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down.

•

a $14.2 million increase in depreciation and amortization expense for all systems, except DFW Midstream.

•

the 2014 recognition of a $54.2 million goodwill impairment for the Williston Basin segment.

•

a $41.0 million decrease resulting from lower cost of natural gas and NGLs for the Bison Midstream and Grand River systems.

•

the 2014 recognition of a $5.0 million environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down.

EX 99.2-10

EXHIBIT 99.2

Cost of Natural Gas and NGLs. The decrease in cost of natural gas and NGLs during the year ended December 31, 2016 largely reflected the impact on pricing and throughput of lower comparative commodity prices on our Williston Basin and Piceance/DJ Basins segments during the first half of 2016 and the associated impact on (i) our percent-of-proceeds arrangements for the Bison Midstream system and (ii) our percent-of-proceeds arrangements and condensate sales for the Grand River system.

The decrease in cost of natural gas and NGLs for the year ended December 31, 2015 largely reflected the impact on pricing and throughput of declining commodity prices on our Williston Basin and Piceance/DJ Basins segments and the associated impact on our percent-of-proceeds arrangements for the Bison Midstream and Grand River systems.

Operation and Maintenance. Operation and maintenance expense increased during the year ended December 31, 2016 primarily reflecting (i) overall increases for Utica Shale and Williston Basin segments, primarily as a result of the development of the Summit Utica, Tioga Midstream and Polar and Divide systems and (ii) an increase for the Marcellus Shale segment for expenses associated with repairs to rights-of-ways on the Mountaineer Midstream system. The impact of these items was partially offset by declines for the Piceance/DJ Basins and Barnett Shale segments.

Operation and maintenance expense increased during the year ended December 31, 2015 primarily reflecting an environmental remediation accrual for assets contributed to Polar and Divide, an increase in connection fee pass-through expense for Polar and Divide as a result of increased volumes (revenue component is recognized in other revenues), an increase in property taxes and an increase in compensation expense. These increases were partially offset by volume-driven declines in electricity expense associated with DFW Midstream's electric-drive compression assets and a decline in pass-through electricity expense for Grand River (revenue component is recognized in other revenues.)

General and Administrative. General and administrative expense increased during the year ended December 31, 2016 primarily reflecting an increase in expenses for salaries, benefits and incentive compensation.

General and administrative expense increased during the year ended December 31, 2015 reflecting an increase in salaries, benefits and incentive compensation and an increase in rent expense. These increases were partially offset by a decline in professional services, primarily the result of expenses incurred in 2014 in connection 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").

Depreciation and Amortization. The increase in depreciation and amortization expense during 2016 and 2015 was largely driven by an increase in assets placed into service.

Transaction Costs. Transaction costs recognized during the year ended December 31, 2016 primarily relate to financial and legal advisory costs associated with the 2016 Drop Down. Transaction costs recognized during the year ended December 31, 2015 primarily relate to financial and legal advisory costs associated with the Polar and Divide Drop Down. Transaction costs recognized during the year ended December 31, 2014 primarily relate to financial and legal advisory costs associated with the Red Rock Drop Down. Transaction costs in 2015 and 2014 also include financial and legal advisory expenses incurred by Summit Investments for third-party acquisitions that were allocated to us in connection with the 2016 Drop Down.

Interest Expense. The increase in interest expense during the year ended December 31, 2016 was primarily driven by (i) higher costs associated with increased borrowings on our Revolving Credit Facility and (ii) debt incurred by Summit Investments that was allocated to the Partnership in connection with the 2016 Drop Down. The Revolving Credit Facility borrowings incurred in March 2016 in connection with funding a portion of the 2016 Drop Down purchase price replaced the lower-rate Summit Investments' debt that had been allocated to us prior to our March 2016 closing of the 2016 Drop Down, resulting in an increase in interest expense.

EX 99.2-11

EXHIBIT 99.2

The increase in interest expense during the year ended December 31, 2015 was primarily driven by our July 2014 issuance of the 5.5% Senior Notes and an increase in interest expense allocated to us in connection with the 2016 Drop Down.

Deferred Purchase Price Obligation Expense. Deferred Purchase Price Obligation expense recognized in 2016 relates to our March 2016 issuance of the deferred payment in connection with the 2016 Drop Down (see Notes 2 and 16 to the consolidated financial statements).

For additional information, see the "Segment Overview of the Years Ended December 31, 2016, 2015 and 2014" and "Corporate and Other Overview of the Years Ended December 31, 2016, 2015 and 2014" sections herein.

Segment Overview of the Years Ended December 31, 2016, 2015 and 2014

Utica Shale. The Utica Shale reportable segment includes the Summit Utica system, which was acquired from a subsidiary of Summit Investments in March 2016.

Volume throughput for our Summit Utica system follows.

	Utica Shale
	Year ended December 31,						Percentage Change
	2016		2015		2014		2016 v. 2015	2015 v. 2014
Average daily throughput (MMcf/d) (1)		186		37		1	*	*

* Not considered meaningful

(1) For the period of SMLP's ownership in 2014, average throughput was 12 MMcf/d.

Volume throughput increased in 2016 and 2015 due to our continued buildout of the Summit Utica system and our customer's commissioning of new wells throughout 2015 and into 2016.

Financial data for our Utica Shale reportable segment follows.

	Utica Shale
	Year ended December 31,							Percentage Change
	2016			2015		2014		2016 v. 2015			2015 v. 2014
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	24,263		$	4,700	$	190	*			*
Total revenues		24,263			4,700		190	*			*
Costs and expenses:
Operation and maintenance		2,280			1,017		—		124	%	*
General and administrative		948			1,477		20		(36	)%	*
Depreciation and amortization		4,331			1,417		—	*			*
Loss (gain) on asset sales, net		(4	)		—		—	*			*
Total costs and expenses		7,555			3,911		20		93	%	*
Add:
Depreciation and amortization		4,331			1,417		—
Loss (gain) on asset sales, net		(4	)		—		—
Segment adjusted EBITDA	$	21,035		$	2,206	$	170	*			*

* Not considered meaningful

Year ended December 31, 2016. Segment adjusted EBITDA increased $18.8 million during 2016 primarily reflecting the growth and development of the Summit Utica system.

Depreciation and amortization increased over 2015 as a result of placing assets into service at the Summit Utica system.

EX 99.2-12

EXHIBIT 99.2

Year ended December 31, 2015. Segment adjusted EBITDA increased $2.0 million during 2015 primarily reflecting a full year of operations in 2015 as well as the growth and development of the Summit Utica system.

Depreciation and amortization increased over 2014 as a result of placing assets into service at the Summit Utica system.

Ohio Gathering. The Ohio Gathering reportable segment includes Ohio Gathering which was acquired from a subsidiary of Summit Investments in March 2016.

Gross volume throughput for Ohio Gathering, based on a one-month lag follows.

	Ohio Gathering
	Year ended December 31,						Percentage Change
	2016		2015		2014		2016 v. 2015			2015 v. 2014
Average daily throughput (MMcf/d)		865		645		270		34	%		139	%

Financial data for our Ohio Gathering reportable segment, based on a one-month lag follows.

	Ohio Gathering
	Year ended December 31,						Percentage Change
	2016		2015		2014		2016 v. 2015			2015 v. 2014
	(Dollars in thousands)
Proportional adjusted EBITDA for equity method investees	$	45,602	$	33,667	$	6,006		35	%	*
Segment adjusted EBITDA	$	45,602	$	33,667	$	6,006		35	%	*

* Not considered meaningful

Year ended December 31, 2016. Segment adjusted EBITDA increased $11.9 million during 2016 primarily reflecting an increase in our proportional share of Ohio Gathering's adjusted EBITDA primarily due to growth and development in the first half of 2016. Volume growth decelerated for both OGC and OCC beginning in the third quarter of 2016 thereby slowing the year-over-year overall increase.

Year ended December 31, 2015. Segment adjusted EBITDA increased $27.7 million during 2015 primarily reflecting an increase in our proportional share of Ohio Gathering's adjusted EBITDA due to ongoing growth and development.

Williston Basin. The Bison Midstream, Polar and Divide and Tioga Midstream systems provide our midstream services for the Williston Basin reportable segment. Polar and Divide was acquired from subsidiaries of Summit Investments in May 2015, with additional assets that currently comprise a portion of the Polar and Divide system, subsequently acquired from Summit Investments in March 2016. Tioga Midstream was acquired from a subsidiary of Summit Investments in March 2016. Our results include activity for (i) the Bison Midstream and Polar and Divide systems for all periods presented and (ii) the Tioga Midstream system since April 2014.

Operating data for our Williston Basin reportable segment follows.

	Williston Basin
	Year ended December 31,						Percentage Change
	2016		2015		2014		2016 v. 2015			2015 v. 2014
Aggregate average daily throughput – liquids (Mbbl/d)		88.9		67.7		40.7		31	%		66	%
Aggregate average daily throughput – natural gas (MMcf/d)		22		23		18		(4	)%		28	%

Liquids. The increase in liquids volume throughput during 2016 reflects the completion of new wells across our gathering footprint and the connection of pad sites that had been previously using third-party trucks to gather crude oil and/or produced water. In addition, the impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines constrained 2015 volume throughput.

The increase in liquids volume throughput in 2015 reflect new pad site connections and ongoing drilling activity in the Polar and Divide system's service area.

EX 99.2-13

EXHIBIT 99.2

Natural gas. Natural gas volume throughput remained flat during 2016 largely reflecting the offsetting effects of the growth of the Tioga Midstream system throughout 2015 and into the first quarter of 2016 and lower volume throughput on the Bison Midstream system.

Natural gas volume throughput increased in 2015 due to growth on the Tioga Midstream system and increases in gas-to-oil ratios on existing production. This effect was partially offset by the effects of customers reducing their drilling activities in response to continued declines in commodity prices.

Financial data for our Williston Basin reportable segment follows.

	Williston Basin
	Year ended December 31,						Percentage Change
	2016		2015		2014		2016 v. 2015			2015 v. 2014
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	89,962	$	62,899	$	41,766		43	%		51	%
Natural gas, NGLs and condensate sales		20,158		23,525		56,040		(14	)%		(58	)%
Other revenues		12,054		12,505		12,001		(4	)%		4	%
Total revenues		122,174		98,929		109,807		23	%		(10	)%
Costs and expenses:
Cost of natural gas and NGLs		20,384		23,090		54,481		(12	)%		(58	)%
Operation and maintenance		28,430		26,586		22,926		7	%		16	%
General and administrative		2,576		5,400		8,474		(52	)%		(36	)%
Depreciation and amortization		33,676		31,376		24,027		7	%		31	%
Environmental remediation		—		21,800		5,000	*			*
Loss (gain) on asset sales, net		88		5		296	*			*
Long-lived asset impairment		569		7,554		—	*			*
Goodwill impairment		—		203,373		54,199	*			*
Total costs and expenses		85,723		319,184		169,403		(73	)%		88	%
Add:
Depreciation and amortization		33,676		31,376		24,027
Adjustments related to MVC shortfall payments		8,691		11,870		10,743
Unit-based compensation		—		85		340
Loss (gain) on asset sales, net		88		5		296
Long-lived asset impairment		569		7,554		—
Goodwill impairment		—		203,373		54,199
Segment adjusted EBITDA	$	79,475	$	34,008	$	30,009		134	%		13	%

* Not considered meaningful

Year ended December 31, 2016. Segment adjusted EBITDA increased $45.5 million during 2016 primarily reflecting:

•

a $23.9 million increase, after taking into account the adjustments related to MVC shortfall payments, in gathering services and related fees primarily due to (i) the development of the Polar and Divide and Tioga Midstream systems, (ii) higher gathering rates associated with a rate redetermination, which was in effect in the first and second quarters of 2016 and (iii) the prior-year impact of an early-January 2015 shut in of certain produced water and crude oil gathering pipelines.

•

the 2015 recognition of an additional accrual of $21.8 million for environmental remediation costs associated with a produced water pipeline that became part of the Polar and Divide system in connection with the 2016 Drop Down.

EX 99.2-14

EXHIBIT 99.2

•

a $2.8 million decrease in general and administrative expense largely as a result of a higher allocation of certain corporate general and administrative expenses in 2015 for both the Polar and Divide and Tioga Midstream systems (see the "Corporate and Other Overview of the Years Ended December 31, 2016, 2015 and 2014—General and Administrative" section herein).

Other items to note:

•

Depreciation and amortization increased during 2016 largely as a result of assets placed into service.

•

In September 2015, we impaired certain property, plant and equipment balances associated with terminated projects. These impairments had no impact on segment adjusted EBITDA for the year ended December 31, 2015.

•

In the fourth quarter of 2015, we recognized a goodwill impairment for the Polar and Divide system. This impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2015.

Year ended December 31, 2015. Segment adjusted EBITDA increased $4.0 million during 2015 primarily reflecting:

•

a $22.3 million increase, after taking into account the adjustments related to MVC shortfall payments, in gathering services and related fees primarily due to the impact of higher volume throughput and higher gathering rates associated with amendments to liquids contracts in 2014 generated by the Polar and Divide system.

•

a $3.1 million decline in general and administrative expenses primarily as a result of our decision to discontinue allocating certain corporate general and administrative expenses to our reportable segments beginning in the first quarter of 2015.

•

a $16.8 million increase in environmental remediation accruals associated with assets contributed to Polar and Divide in connection with the 2016 Drop Down.

•

a $3.7 million increase in operation and maintenance expense largely as a result of system buildout on the Polar and Divide and Tioga Midstream systems.

Other items to note:

•

Depreciation and amortization increased during 2015 largely as a result of assets placed into service that were acquired in connection with the Polar and Divide Drop Down and the 2016 Drop Down.

•

In the fourth quarter of 2015, we recognized a goodwill impairment for the Polar and Divide system. In the fourth quarter of 2014, we recognized a goodwill impairment for the Bison Midstream system. These impairments had no impact on segment adjusted EBITDA for the year ended December 31, 2015 or 2014.

Piceance/DJ Basins. The Grand River system provides midstream services for the Piceance/DJ Basins reportable segment. The Red Rock Gathering system was acquired from a subsidiary of Summit Investments in March 2014. Niobrara G&P was acquired from a subsidiary of Summit Investments in March 2016. Our results include activity for the Grand River, Red Rock Gathering and Niobrara G&P systems for all periods presented.

Operating data for our Piceance/DJ Basins reportable segment follows.

	Piceance/DJ Basins
	Year ended December 31,						Percentage Change
	2016		2015		2014		2016 v. 2015			2015 v. 2014
Aggregate average daily throughput (MMcf/d)		586		609		663		(4	)%		(8	)%

Volume throughput decreased during 2016 primarily as a result of the continued suspension of drilling activities by one of Grand River's key customers and the resulting natural declines from existing production. The impact of these decreases was partially offset by an increase in volume throughput by other producer customers.

EX 99.2-15

EXHIBIT 99.2

Volume throughput declined during 2015 primarily as a result of the suspension of drilling activities by one of Grand River's key customers and the resulting natural declines from existing production. The impact of these factors was partially offset by volume throughput from new pad site connections for WPX (subsequently acquired by Terra) and Ursa Resources Group II as well as the March 2014 start-up of a cryogenic processing plant servicing production from Black Hills Corporation.

Financial data for our Piceance/DJ Basins reportable segment follows.

	Piceance/DJ Basins
	Year ended December 31,							Percentage Change
	2016		2015			2014		2016 v. 2015			2015 v. 2014
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	133,436	$	161,291		$	122,852		(17	)%		31	%
Natural gas, NGLs and condensate sales		9,808		11,854			27,606		(17	)%		(57	)%
Other revenues		6,659		7,273			11,019		(8	)%		(34	)%
Total revenues		149,903		180,418			161,477		(17	)%		12	%
Costs and expenses:
Cost of natural gas and NGLs		7,082		8,308			17,934		(15	)%		(54	)%
Operation and maintenance		33,524		36,674			37,945		(9	)%		(3	)%
General and administrative		3,027		3,624			10,029		(16	)%		(64	)%
Depreciation and amortization		49,140		47,433			42,959		4	%		10	%
Loss (gain) on asset sales, net		9		(190	)		146	*			*
Long-lived asset impairment		—		1,220			—	*			*
Goodwill impairment		—		45,478			—	*			*
Total costs and expenses		92,782		142,547			109,013		(35	)%		31	%
Other income		—		—			1,185	*			*
Add:
Depreciation and amortization		49,140		47,433			42,959
Adjustments related to MVC shortfall payments		2,971		(21,590	)		15,194
Loss (gain) on asset sales, net		9		(190	)		146
Long-lived asset impairment		—		1,220			—
Goodwill impairment		—		45,478			—
Less:
Impact of purchase price adjustment		—		—			1,185
Segment adjusted EBITDA	$	109,241	$	110,222		$	110,763		(1	)%	—		%

* Not considered meaningful

Year ended December 31, 2016. Segment adjusted EBITDA decreased $1.0 million during 2016 primarily reflecting:

•

a $3.3 million decrease in gathering services and related fees, after taking into account the adjustments related to MVC shortfall payments, primarily as a result of declining volumes from one of Grand River's key customers. This impact was partially offset by higher average volume throughput and rates due to a shift in customer mix.

•

a $3.2 million decrease in operation and maintenance primarily due to lower general repairs and maintenance expenses.

Other items to note:

•

Depreciation and amortization increased during 2016 largely as a result of an increase in contract amortization for one of Grand River's key customers.

•

A portion of the change in adjustments for MVC shortfall payments is associated with our September 2015 decision to no longer defer $34.4 million of MVC shortfall payments from a certain Grand River customer. As a result, the decrease in gathering services and related fees compared with 2015 was offset by the change in adjustments related to MVC shortfall payments, with no impact on segment adjusted EBITDA (see Note 8 to the consolidated financial statements).

EX 99.2-16

EXHIBIT 99.2

Year ended December 31, 2015. Segment adjusted EBITDA decreased $0.5 million during 2015 primarily reflecting:

•

a $6.1 million decrease in margin primarily due to the impact on price and throughput of declining commodity prices which negatively impacted the margins that we earn from our percent-of-proceeds contracts.

•

a $2.0 million increase in operation and maintenance, net of the decrease in pass-through expenses which are also included in other revenues, primarily as a result of compression-related expenses and higher property tax expense.

•

a $6.4 million decrease in general and administrative primarily as a result of the previously mentioned decision to discontinue allocating certain corporate general and administrative expenses to our reportable segments.

•

a $1.7 million increase in gathering services and related fees, after taking into account the adjustments related to MVC shortfall payments, primarily as a result of the contribution from Niobrara G&P, partially offset by declining volumes from one of Grand River's key customers.

Other items to note:

•

The decrease in other revenues was primarily a result of a decline in certain electricity expense reimbursements, which due to their pass-through nature, had no impact on segment adjusted EBITDA

•

Depreciation and amortization increased during 2015 largely as a result of an increase in contract amortization for Grand River's key customer, the March 2014 commissioning of a cryogenic processing plant and the development of Niobrara G&P.

•

A portion of the change in adjustments for MVC shortfall payments is associated with our September 2015 decision to no longer defer MVC shortfall payments from a certain Grand River customer. As a result, the increase in gathering services and related fees compared with 2014 was offset by the change in adjustments related to MVC shortfall payments, with no impact on segment adjusted EBITDA (see Note 8 to the consolidated financial statements).

•

During 2015, we identified certain events, facts and circumstances which indicated that certain of our property, plant and equipment was impaired. As such, we recognized a long-lived asset impairment. This impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2015.

•

The goodwill impairment recognized in 2015 relates to our determination that all of the goodwill associated with the Grand River reporting unit had been impaired. This impairment had no impact on segment adjusted EBITDA for the year ended December 31, 2015.

Barnett Shale. The DFW Midstream system provides our midstream services for the Barnett Shale reportable segment. In September 2014, DFW Midstream acquired certain natural gas gathering assets (the "Lonestar assets") from a third party. Our results include activity for (i) the DFW Midstream system for all periods presented and (ii) the Lonestar assets since September 2014.

Operating data for our Barnett Shale reportable segment follows.

	Barnett Shale
	Year ended December 31,						Percentage Change
	2016		2015		2014		2016 v. 2015			2015 v. 2014
Average daily throughput (MMcf/d)		319		352		358		(9	)%		(2	)%

Volume throughput declined during 2016 reflecting reduced drilling and completion activity, together with natural production declines, partially offset by the commissioning of an 11-well pad site in the second quarter of 2016 and the commissioning of 14 wells in December 2015 and January 2016.

EX 99.2-17

EXHIBIT 99.2

Volume throughput was relatively flat during 2015 reflecting several offsetting effects related to customer drilling and completion activities, the contribution from the Lonestar assets beginning in the fourth quarter of 2014 and a lack of drilling activity by DFW Midstream's then-key customer, Chesapeake.

Financial data for our Barnett Shale reportable segment follows.

	Barnett Shale
	Year ended December 31,									Percentage Change
	2016			2015			2014			2016 v. 2015			2015 v. 2014
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	72,234		$	80,461		$	79,976			(10	)%		1	%
Natural gas, NGLs and condensate sales		5,867			6,700			13,448			(12	)%		(50	)%
Other revenues		1,855			881			(423	)		111	%	*
Total revenues		79,956			88,042			93,001			(9	)%		(5	)%
Costs and expenses:
Operation and maintenance		24,594			25,823			29,438			(5	)%		(12	)%
General and administrative		1,088			1,297			4,607			(16	)%		(72	)%
Depreciation and amortization		15,671			15,606			15,657		—		%	—		%
Loss (gain) on asset sales, net		—			13			—		*			*
Long-lived asset impairment		1,195			531			5,505		*			*
Total costs and expenses		42,548			43,270			55,207			(2	)%		(22	)%
Add:
Depreciation and amortization		16,093			16,392			16,601
Adjustments related to MVC shortfall payments		(62	)		(2,182	)		628
Loss (gain) on asset sales, net		—			13			—
Long-lived asset impairment		1,195			531			5,505
Segment adjusted EBITDA	$	54,634		$	59,526		$	60,528			(8	)%		(2	)%

*Not considered meaningful

Year ended December 31, 2016. Segment adjusted EBITDA decreased $4.9 million during 2016 primarily reflecting:

•

a $6.1 million decrease, after taking into account the adjustments related to MVC shortfall payments, in gathering services and related fees largely as a result of reduced volume throughput.

•

a $1.2 million decrease in operation and maintenance expense largely as a result of lower electricity expense. The decline in electricity expense was largely the result of (i) lower volumes not requiring as much compression as the prior-year period and (ii) the impact of lower natural gas prices on our cost of electricity.

Other items to note:

•

Other revenues also reflect the effect of a $0.8 million increase in electricity expense reimbursements that we began passing through to certain customers beginning in the fourth quarter of 2016. Previously we had retained a portion of the gathered natural gas which was then sold to offset the electricity expense necessary to operate our electric-drive compression assets. Due to their pass-through nature, these revenues had no impact on segment adjusted EBITDA.

•

The long-lived asset impairments in 2016 and 2015 reflect our decisions to impair certain property, plant and equipment balances associated with the decommissioning of certain assets. These impairments had no impact on segment adjusted EBITDA for the years ended December 31, 2016 or 2015.

EX 99.2-18

EXHIBIT 99.2

Year ended December 31, 2015. Segment adjusted EBITDA decreased $1.0 million during 2015 primarily reflecting:

•

a $6.7 million decrease in natural gas, NGLs and condensate sales primarily due to the impact of declining natural gas prices on the fuel retainage fee that is paid in-kind by certain of our customers to offset the costs we incur to operate DFW Midstream's electric-drive compression assets.

•

a $3.6 million decrease in operation and maintenance primarily due to lower electricity expense. The decline in electricity expense was largely the result of the impact of lower natural gas prices on our cost of electricity. This decline was partially offset by an increase in compression expense.

•

a $3.3 million decline in general and administrative expenses primarily as a result of our decision to discontinue allocating certain corporate general and administrative expenses to our reportable segments beginning in the first quarter of 2015.

The long-lived asset impairments in 2015 and 2014 reflect our decisions to impair certain property, plant and equipment balances associated with the decommissioning of certain assets. These impairments had no impact on segment adjusted EBITDA for the years ended December 31, 2015 or 2014.

Marcellus Shale. The Mountaineer Midstream system provides our midstream services for the Marcellus Shale reportable segment.

Volume throughput for the Marcellus Shale reportable segment follows.

	Marcellus Shale
	Year ended December 31,						Percentage Change
	2016		2015		2014		2016 v. 2015			2015 v. 2014
Average daily throughput (MMcf/d)		415		478		382		(13	)%		25	%

Volume throughput declined during 2016 due to natural production declines which were not offset by new production as a result of Antero's decision to defer completion activities in the third quarter of 2015. Volume throughput during 2016 was also impacted by repairs on a third-party NGL pipeline located downstream of the Sherwood Processing Complex in June and July 2016 limiting the amount of natural gas we could deliver during the repair work.

The increase in volume throughput in 2015 was primarily driven by Antero's connection of new wells located upstream of the Mountaineer Midstream system.

Financial data for our Marcellus Shale reportable segment follows.

	Marcellus Shale
	Year ended December 31,						Percentage Change
	2016		2015		2014		2016 v. 2015			2015 v. 2014
	(Dollars in thousands)
Revenues:
Gathering services and related fees	$	26,111	$	28,468	$	22,694		(8	)%		25	%
Total revenues		26,111		28,468		22,694		(8	)%		25	%
Costs and expenses:
Operation and maintenance		6,506		4,886		4,560		33	%		7	%
General and administrative		402		368		2,194		9	%		(83	)%
Depreciation and amortization		8,841		8,682		7,648		2	%		14	%
Total costs and expenses		15,749		13,936		14,402		13	%		(3	)%
Add:
Depreciation and amortization		8,841		8,682		7,648
Segment adjusted EBITDA	$	19,203	$	23,214	$	15,940		(17	)%		46	%

EX 99.2-19

EXHIBIT 99.2

Year ended December 31, 2016. Segment adjusted EBITDA decreased $4.0 million during 2016 primarily reflecting:

•

a $2.4 million decrease in gathering services and related fees primarily as a result of lower volume throughput and lower compression revenues due to a shift in volume mix. These declines were partially offset by an increase in minimum revenue commitment payments.

•

a $1.6 million increase in operation and maintenance primarily as a result of expenses associated with repairs to rights-of-way.

Year ended December 31, 2015. Segment adjusted EBITDA increased $7.3 million during 2015 primarily reflecting:

•

a $5.8 million increase in gathering services and related fees primarily as a result of an increase in volume throughput and minimum revenue commitment payments related to the Zinnia Loop project, beginning in the first quarter of 2015.

•

a $1.8 million decrease in general and administrative primarily as a result of the previously mentioned decision to discontinue allocating certain corporate general and administrative expenses to our reportable segments.

Depreciation and amortization increased during 2015 largely as a result of commissioning the Zinnia Loop project late in the third quarter of 2014.

Corporate and Other Overview of the Years Ended December 31, 2016, 2015 and 2014

Corporate and other 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, interest expense and Deferred Purchase Price Obligation income or expense. Items to note follow.

	Corporate and Other
	Year ended December 31,						Percentage Change
	2016		2015		2014		2016 v. 2015			2015 v. 2014
	(Dollars in thousands)
Costs and expenses:
General and administrative	$	44,369	$	32,942	$	17,957		35	%		83	%
Transaction costs		1,321		1,342		2,985		(2	)%		(55	)%
Interest expense (1)		63,810		59,092		48,586		8	%		22	%
Deferred Purchase Price Obligation expense		55,854		—		—	*			*

* Not considered meaningful

(1) Includes interest expense on debt allocated to the 2016 Drop Down Assets during the common control period (see Note 2 to the consolidated financial statements).

General and Administrative. In the first quarter of 2015, the Partnership discontinued allocating certain administrative expenses, primarily salaries, benefits, incentive compensation and rent expense, to its then-reportable segments. As a result, the amount of expense allocated to and reported within the Company’s operating segments decreased, with a commensurate increase in corporate general and administrative expenses. This change, however, did not impact the historical results of entities under common control which were acquired subsequent to the first quarter of 2015. As a result, general and administrative expense allocations were higher for Polar and Divide and the 2016 Drop Down Assets during their respective common control periods because Summit Investments continued to allocate these administrative expenses to its non-Partnership subsidiaries. With respect to Polar and Divide, general and administrative expense allocations during the period from January 1, 2014 to May 18, 2015 included items that SMLP was no longer allocating to its then-operating segments. With respect to the 2016 Drop Down Assets, general and administrative expense allocations during the period from January 1, 2014 to March 3, 2016 included items that SMLP was no longer allocating to its then-operating segments. As such, subsequent to a given drop down, the application of the new expense allocation methodology to the newly acquired

EX 99.2-20

EXHIBIT 99.2

entities resulted in a decrease in reportable segment general and administrative expenses and an increase in corporate general and administrative expenses.

The increase in general and administrative expenses during the years ended December 31, 2016 primarily reflects the impact of a change in our expense allocation methodology and an increase in salaries, benefits and incentive compensation.

The increase in general and administrative expenses during the year ended December 31, 2015 primarily reflects the impact of a change in our expense allocation methodology. The increase was also a result of an increase in salaries, benefits and incentive compensation and rent expense. These increases were partially offset by a decline in professional services, primarily the result of expenses incurred in 2014 in connection with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 and our adoption of COSO 2013.

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 flows generated from our operations, borrowings under our Revolving Credit Facility and future issuances of equity and debt instruments.

Capital Markets Activity

November 2016 Shelf Registration Statement. In October 2016, we filed the 2016 SRS and in November 2016, the SEC declared it effective. The following transaction has been executed pursuant thereto:

•

In January 2017, we completed a secondary public offering of 4,000,000 SMLP common units held by a subsidiary of Summit Investments in accordance with our obligations under several registration rights agreements. We did not receive any proceeds from this secondary offering.

Following the January 2017 secondary offering, we can issue up to $1.50 billion of debt and equity securities in primary offerings and a total of 32,701,230 common units held by (i) a subsidiary of Summit Investments and (ii) affiliates of our Sponsor pursuant to the 2016 SRS. The 2016 SRS expires in November 2019.

EX 99.2-21

EXHIBIT 99.2

July 2014 Shelf Registration Statement. In July 2014, we filed the 2014 SRS 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 unsecured notes due 2022. We used the proceeds to repay a portion of the outstanding borrowings under our Revolving Credit Facility.

In February 2017, we amended the 2014 SRS to include additional guarantor subsidiaries and completed a public offering of $500.0 million principal 5.75% senior unsecured notes due 2025. Concurrent therewith, we made a tender offer to purchase all of the outstanding 7.5% Senior Notes. The tender offer expired on February 14, 2017 with $276.9 million validly tendered. On February 16, 2017, we issued a notice of redemption for the 7.5% Senior Notes that remained outstanding subsequent to the tender offer. The remaining 7.5% Senior Notes will be redeemed on March 18, 2017, with payment made on March 20, 2017. In addition to using the proceeds to purchase all of the outstanding 7.5% Senior Notes, we have also used the proceeds to repay a portion of the outstanding borrowings under our Revolving Credit Facility.

November 2013 Shelf Registration Statement. In October 2013, we filed the 2013 SRS and in November 2013, the SEC declared it effective. The following transactions have been executed pursuant to the 2013 SRS:

•

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 approximate 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, we completed a secondary public offering of 4,347,826 SMLP common units held by a subsidiary of Summit Investments in accordance with our obligations under several registration rights agreements. We did not receive any proceeds from this secondary offering.

•

On May 13, 2015, we completed an underwritten public offering of 6,500,000 common units at a price of $30.75 per unit. On May 22, 2015, the underwriters exercised in full their option to purchase an additional 975,000 common units from us at a price of $30.75 per unit. Concurrent with both transactions, our General Partner made a capital contribution to us to maintain its approximate 2% general partner interest. We used the proceeds from the May 13, 2015 offering to partially fund the Polar and Divide Drop Down. We used $25.0 million of the $29.0 million of proceeds from the exercise of the underwriters' option to pay down our Revolving Credit Facility.

•

In June 2015, we executed an equity distribution agreement and filed a prospectus and a prospectus supplement with the SEC for the issuance and sale from time to time of SMLP common units having an aggregate offering price of up to $150.0 million (the "2015 ATM Program"). These sales will be made (i) pursuant to the terms of the equity distribution agreement between us and the sales agents named therein and (ii) by means of ordinary brokers' transactions at market prices, in block transactions or as otherwise agreed between us and the sales agents. Sales of our common units may be made in negotiated transactions or transactions that are deemed to be at-the-market offerings as defined by SEC Rules. There were no transactions under the 2015 ATM Program.

•

In September 2016, we completed an underwritten public offering of 5,500,000 common units at a price of $23.20 per unit. Following the offering, our General Partner made a capital contribution to us to maintain its approximate 2% general partner interest. We used the net proceeds therefrom to pay down our Revolving Credit Facility.

The 2013 SRS expired in November 2016 when it was replaced with the 2016 SRS.

For additional information, see Notes 1, 9, 11 and 16 to the consolidated financial statements.

EX 99.2-22

EXHIBIT 99.2

Debt

Revolving Credit Facility. We have a $1.25 billion senior secured Revolving Credit Facility. As of December 31, 2016, the outstanding balance of the Revolving Credit Facility was $648.0 million and the unused portion totaled $602.0 million. There were no defaults or events of default during 2016 and, as of December 31, 2016, we were in compliance with the covenants in the Revolving Credit Facility.

Senior Notes. In July 2014, the Co-Issuers co-issued the 5.5% Senior Notes, and in June 2013, they co-issued the 7.5% Senior Notes. There were no defaults or events of default during 2016 on either series of senior notes.

SMP Holdings Credit Facility. SMP Holdings had a senior secured revolving credit facility and a senior secured term loan which were used to support the development of the assets acquired in the 2016 Drop Down. As such, Summit Investments allocated this debt and the associated interest expense to us during the common control period but retained the debt subsequent to the closing of the 2016 Drop Down.

For additional information on our long-term debt and debt allocated to us, see Notes 9, 16 and 17 to the consolidated financial statements.

Deferred Purchase Price Obligation

In March 2016, we entered into an agreement with a subsidiary of Summit Investments to fund a portion of the 2016 Drop Down whereby we have recognized the Deferred Purchase Price Obligation (see Critical Accounting Estimates below and Note 16 to the consolidated financial statements).

Cash Flows

Due to the common control aspect in a drop down transaction, we account for drop downs on an “as-if pooled” basis for the periods during which common control existed. As such, cash flows retrospectively reflect the cash flows associated with (i) the assets acquired from Summit Investments and (ii) the assets and liabilities allocated to the Partnership from Summit Investments.

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

	Year ended December 31,
	2016			2015			2014
	(In thousands)
Net cash provided by operating activities	$	230,495		$	191,375		$	152,953
Net cash used in investing activities		(534,126	)		(646,720	)		(1,384,803	)
Net cash provided by financing activities		289,266			449,327			1,233,877
Net change in cash and cash equivalents	$	(14,365	)	$	(6,018	)	$	2,027

Operating activities. Cash flows from operating activities for the year ended December 31, 2016 increased primarily as a result of:

•

a $10.4 million increase in distributions from Ohio Gathering;

•

the prior-year impact of net cash paid for environmental remediation expenses; and

•

cash received as a result of MVCs.

Cash flows from operating activities for the year ended December 31, 2015 increased primarily as a result of:

•

a $31.6 million increase in distributions from Ohio Gathering and

•

cash received as a result of MVCs.

These items were partially offset by the 2015 impact of net cash paid for environmental remediation expenses.

Investing activities. Details of cash flows from investing activities follow.

Cash flows used in investing activities for the year ended December 31, 2016 primarily reflected:

•

$359.4 million for our acquisition of the assets acquired in the 2016 Drop Down;

EX 99.2-23

EXHIBIT 99.2

•

$142.7 million of capital expenditures primarily attributable to the ongoing expansion of the 2016 Drop Down Assets and the Polar and Divide system; and

•

$31.6 million of capital contributions to Ohio Gathering.

Cash flows used in investing activities for the year ended December 31, 2015 primarily reflected:

•

$288.6 million for our acquisition of the Polar and Divide system;

•

$272.2 million of capital expenditures primarily attributable to the buildout of the gathering systems acquired in the 2016 Drop Down and the ongoing expansion of the Polar and Divide and Bison Midstream systems; and

•

$86.2 million of capital contributions to Ohio Gathering.

Cash flows used in investing activities for the year ended December 31, 2014 primarily reflected:

•

$580.7 million of total cash flows for the acquisition of our initial investment in Ohio Gathering and the subsequent option exercise which increased our ownership interest to 40%;

•

$343.4 million of capital expenditures primarily attributable to the build out of the Summit Utica, Tioga Midstream, Niobrara G&P and Polar and Divide systems as well as expenditures to expand existing systems;

•

$305.0 million for our acquisition of Red Rock Gathering; and

•

$145.1 million of capital contributions to Ohio Gathering.

Financing activities. Details of cash flows from financing activities follow.

Net cash provided by financing activities for the year ended December 31, 2016 primarily reflected:

•

$316.0 million of net borrowings under our Revolving Credit Facility, which included $360.0 million of borrowings to fund the 2016 Drop Down and reflected a repayment in September 2016 with funds from the issuance of common units noted below;

•

$167.5 million of distributions paid in 2016; and

•

$125.2 million of net proceeds from the issuance of common units in September 2016.

Net cash provided by financing activities for the year ended December 31, 2015 primarily reflected:

•

$320.5 million of cash advances from Summit Investments to fund the development of the 2016 Drop Down Assets;

•

$222.0 million of net proceeds from the issuance of common units in May 2015, of which $193.4 million was used to partially fund the Polar and Divide Drop Down;

•

$216.0 million of net borrowings under our Revolving Credit Facility, of which $92.0 million was used to partially fund the Polar and Divide Drop Down;

•

a $182.5 million repayment under Summit Investments' term loan; and

•

$152.1 million of distributions paid in 2015.

Net cash provided by financing activities for the year ended December 31, 2014 primarily reflected:

•

$674.4 million of cash advances to fund the acquisition of Ohio Gathering, to support the buildout of the systems acquired in the 2016 Drop Down and to support the buildout of the Polar and Divide system;

•

$300.0 million of proceeds from the 5.5% Senior Notes issuance, 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 are being amortized over the life of the notes;

•

$197.8 million of net proceeds from an offering of common units in March 2014, which were used to partially fund the Red Rock Drop Down;

EX 99.2-24

EXHIBIT 99.2

•

$164.0 million of net borrowings under our Revolving Credit Facility and Summit Investments revolving credit facility to partially fund the Red Rock Drop Down and the buildout of the systems acquired in the 2016 Drop Down; and

•

$122.2 million of distributions paid in 2014.

Contractual Obligations

The table below summarizes our contractual obligations as of December 31, 2016.

	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In thousands)
Long-term debt and interest payments (1)	$	1,505,883	$	63,200	$	748,183	$	378,000	$	316,500
Deferred Purchase Price Obligation (2)		830,345		—		—		830,345		—
Purchase obligations (3)		6,278		6,278		—		—		—
Operating leases (4)		9,686		3,512		5,698		476		—
Total contractual obligations	$	2,352,192	$	72,990	$	753,881	$	1,208,821	$	316,500

(1) For the purpose of calculating future interest on the Revolving Credit Facility, assumes no change in balance or rate from December 31, 2016. Includes a 0.50% commitment fee on the unused portion of the Revolving Credit Facility. See Note 9 to the consolidated financial statements.

(2) See Note 16 to the consolidated financial statements.

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

(4) See Item 2. Properties and Note 15 to the consolidated financial statements.

In February 2017, we issued $500.0 million of 5.75% senior, unsecured notes due 2025. We used the proceeds therefrom to purchase and redeem all of the $300.0 million 7.5% Senior Notes due 2021 and to pay down $172.0 million on our Revolving Credit Facility which is due 2018.

Capital Requirements

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 capitalize on organic growth opportunities and make acquisitions that increase the amount of cash generated from our operations on a per-unit basis, along with other factors.

Developing, owning and operating midstream energy infrastructure assets requires significant investment in the maintenance of existing gathering systems and the 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.

For the year ended December 31, 2016, cash paid for capital expenditures totaled $142.7 million, compared with $272.2 million for the year ended December 31, 2015 and $343.4 million for the year ended December 31, 2014 (see Note 3 to the consolidated financial statements). Maintenance capital expenditures totaled $17.7 million for the year ended December 31, 2016, compared with $12.7 million for the year ended December 31, 2015 and $18.1 million for the year ended December 31, 2014. For the year ended December 31, 2016, contributions to equity method investees totaled $31.6 million, compared with $86.2 million for the year ended December 31, 2015 and $145.1 million for the year ended December 31, 2014 (see Note 7 to the consolidated financial statements). The

EX 99.2-25

EXHIBIT 99.2

year-over-year declines in cash paid for capital expenditures primarily reflected the buildout in 2015 and 2014 of recently acquired systems and the completion of several large capital projects on legacy systems.

The acquisition component of our principal business strategy has required and will continue to require significant expenditures by us. 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 intend to continue to pursue accretive acquisitions of midstream assets from third parties. However, their size, timing and/or contribution to our operations and financial results cannot be reasonably estimated. Furthermore, there are a number of risks and uncertainties that could cause our current expectations to change, including, but not limited to, (i) the ability to reach agreement with third parties; (ii) prevailing conditions and outlook in the natural gas, crude oil and natural gas liquids industries and markets and (iii) our ability to obtain financing from commercial banks, the capital markets, or other sources such as our Sponsor and Summit Investments, among other factors.

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. We believe that our Revolving Credit Facility, together with financial support from our Sponsor and/or access to the debt and equity capital markets, will be adequate to finance our growth objectives for the foreseeable future without adversely impacting our liquidity or our ability to make quarterly cash distributions to our unitholders.

Distributions, Including IDRs

Based on the terms of our Partnership Agreement, we expect to distribute most of the cash generated by our operations to our unitholders. With respect to our payment of IDRs to the General Partner, we reached the second target distribution in connection with the distribution declared in respect of the fourth quarter of 2013. We reached the third target distribution in connection with the distribution declared in respect of the second quarter of 2014. 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 11 to the consolidated financial statements.

Credit and Counterparty Concentration Risks

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.

Given the current environment, certain of our customers may be temporarily unable to meet their current obligations. While this may cause disruption to cash flows, we believe that we are properly positioned to deal with the potential disruption because the vast majority of our gathering assets are strategically positioned at the beginning of the midstream value chain. The majority of our infrastructure is connected directly to our customer’s wellheads and pad sites, which means our gathering systems are typically the first third-party infrastructure through which our customer’s commodities flow and, in many cases, the only way for our customers to get their production to market.

We have exposure due to nonperformance under our MVC contracts whereby a customer, who was not meeting their MVCs, does not have the wherewithal to make its MVC shortfall payments when they become due. We typically receive payment for all prior-year MVC shortfall billings in the quarter immediately following billing. Therefore, our exposure to risk of nonperformance is limited to and accumulates during the current year-to-date contracted measurement period.

For additional information, see Notes 3, 8 and 10 to the consolidated financial statements.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the year ended December 31, 2016.

EX 99.2-26

EXHIBIT 99.2

Critical Accounting Estimates

We prepare our financial statements in accordance with GAAP. These principles are established by the FASB. 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 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, amortizing intangible assets and goodwill.

Property, Plant and Equipment and Amortizing Intangible Assets. As of December 31, 2016, we had net property, plant and equipment with a carrying value of approximately $1.85 billion and net amortizing intangible assets with a carrying value of approximately $421.5 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 as well as in connection with any goodwill impairment evaluations.

With respect to property, plant and equipment and our amortizing 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. Any impairment determinations involve significant assumptions and judgments. Differing assumptions regarding any of these inputs could have a significant effect on the various valuations. As such, the fair value measurements utilized within these estimates are classified as non-recurring Level 3 measurements in the fair value hierarchy because they are not observable from objective sources. Due to the volatility of the inputs used, we cannot predict the likelihood of any future impairment.

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

Goodwill. We evaluate goodwill for impairment annually on September 30 and 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.

2016 Impairment Evaluations. We performed our 2016 annual goodwill impairment analysis as of September 30 and concluded that none of our goodwill had been impaired.

2015 Impairment Evaluations. During the latter part of the fourth quarter of 2015 and the early part of the first quarter of 2016, the declines in forward prices for natural gas, NGLs and crude oil accelerated significantly. As a result, the energy sector's public debt and equity market experienced increased volatility, particularly for comparable companies operating in the midstream services sector. Additionally, during this period, the values of our publicly traded equity and debt instruments decreased as did those of comparable midstream companies. Due to (i) the increased market volatility, (ii) the decrease in market values of comparable companies, (iii) the continued trend of falling commodity prices and (iv) the finalization of our annual financial and operating plans which took into account changes resulting from expected levels of drilling activity, we concluded that a triggering event occurred which required that we test the goodwill associated with our Grand River and Polar and Divide reporting units for

EX 99.2-27

EXHIBIT 99.2

impairment as of December 31, 2015. In connection therewith, we concluded that the goodwill associated with our Grand River and Polar and Divide reporting units was fully impaired and we wrote off the associated balances.

2014 Impairment Evaluations. 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 any of our goodwill could have been impaired. In connection with this assessment, we concluded that a fourth quarter triggering event had occurred which required that we test the goodwill associated with our Polar and Divide and Bison Midstream reporting units for impairment as of December 31, 2014. In connection therewith, we concluded that (i) the goodwill associated with our Polar and Divide reporting unit was not impaired and (ii) the goodwill associated with our Bison Midstream reporting unit was fully impaired and we wrote off the associated balance.

See Notes 2 and 6 for additional information.

Deferred Purchase Price Obligation

We recognized the Deferred Purchase Price Obligation to reflect the present value of the Remaining Consideration. Our calculation of the Remaining Consideration incorporates:

•

actual capital expenditures and Business Adjusted EBITDA for the period from March 3, 2016 through the respective balance sheet date and

•

estimates of (i) capital expenditures made between the respective balance sheet date and December 31, 2019 and (ii) Business Adjusted EBITDA, an income-based measure, during the period from the respective balance sheet date to December 31, 2019. The calculation of the prospective component of Remaining Consideration represents management's best estimate of these two financial measures.

We then discount the Remaining Consideration using a commensurate risk-adjusted discount rate and recognize the present value on our consolidated balance sheets with the change in present value recognized in earnings in the period of change.

The estimates and expectations used in calculating the prospective component of Remaining Consideration and the present value calculation of the Remaining Consideration involve a significant amount of judgment as the calculations are based on future events and/or conditions, including (i) revenues, (ii) estimates of future volume throughput, capital expenditures, operating costs and their timing and (iii) economic and regulatory climates, among other factors. Our estimates of these inputs are inherently imprecise because they reflect our expectation of future conditions that are largely outside of our control. While the assumptions used are consistent with our current business plans and investment decisions, these assumptions could change significantly during the period leading up to settlement of the Deferred Purchase Price Obligation. See Note 16 to the consolidated financial statements for additional information.

Minimum Volume Commitments

Certain of our gathering agreements provide for a monthly, quarterly or annual MVC from our customers. As of December 31, 2016, we had MVCs totaling 1.1 Bcfe/d through 2021.

Under these MVCs, our customers agree to ship and/or process a minimum volume of production 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 contracted measurement period if its actual throughput volumes are less than its MVC for that period. Certain customers are entitled to utilize shortfall payments to offset gathering fees in one or more subsequent contracted measurement periods to the extent that such customer's throughput volumes in a subsequent contracted measurement period 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 billed $64.6 million of MVC shortfall payments to customers that did not meet their MVCs during 2016. For those customers that do not have credit banking mechanisms in their gathering agreements, or have no ability to use MVC shortfall payments as credits, the MVC shortfall payments from these customers are accounted for as gathering revenue in the period that they are earned. We recognized $13.3 million of gathering revenue due to the credit bank expiration of previous MVC shortfall payments. MVC shortfall payment adjustments in 2016 totaled $0.3 million and included adjustments related to future anticipated shortfall payments from certain customers in the Williston Basin, Piceance/DJ Basins, Barnett Shale and Marcellus Shale segments.

EX 99.2-28

EXHIBIT 99.2

The following table presents the impact of our MVC activity by reportable segment during the year ended December 31, 2016.

	Year ended December 31, 2016
	MVC billings		Gathering revenue		Adjustments to MVC shortfall payments
	(In thousands)
Net change in deferred revenue:
Williston Basin	$	8,691	$	—	$	8,691
Piceance/DJ Basins		15,926		12,638		3,288
Barnett Shale		—		677		(677	)
Marcellus Shale		—		—		—
Total change in deferred revenue	$	24,617	$	13,315	$	11,302

MVC shortfall payment adjustments:
Williston Basin	$	7,536	$	7,536	$	—
Piceance/DJ Basins		27,183		27,183		(317	)
Barnett Shale		1,373		1,373		615
Marcellus Shale		3,895		3,895		—
Total MVC shortfall payment adjustments	$	39,987	$	39,987	$	298

Total	$	64,604	$	53,302	$	11,600

Deferred Revenue. 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 volumes of natural gas, or (ii) expired (or lapsed) through the passage of time pursuant to the terms of the applicable gathering agreement. We also recognize deferred revenue when it is determined that a given amount of MVC shortfall payments cannot be recovered by offsetting gathering or processing fees in subsequent contracted measurement periods. In making this determination, we consider both quantitative and qualitative facts and circumstances, including, but not limited to, contract terms, capacity of the associated pipeline or receipt point and/or expectations regarding future investment, drilling and production.

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, 2016, noncurrent deferred revenue totaled $57.5 million and represents amounts that provide these customers the ability to offset their gathering fees, as determined by the MVC contract, to the extent that their throughput volumes exceed their MVC.

Adjustments for MVC Shortfall Payments. We estimate the impact of expected MVC shortfall payments for inclusion in our calculation of segment adjusted EBITDA. Adjustments related to MVC shortfall payments account for:

•

the net increases or decreases in deferred revenue for MVC shortfall payments and

•

our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected MVC shortfall payments in our calculation of segment adjusted EBITDA each quarter until we actually recognize the shortfall payment. These adjustments have not been billed to our customers and are not recognized in our consolidated financial statements.

We estimate expected MVC shortfall payments based on assumptions including, but not limited to, contract terms, historical volume throughput data and expectations regarding future investment, drilling and production.

EX 99.2-29

EXHIBIT 99.2

For additional information, see Notes 2, 3 and 8 to the consolidated financial statements and the "Results of Operations" and "Liquidity and Capital Resources—Credit and Counterparty Concentration Risks" sections herein.

Forward-Looking Statements

Investors are cautioned that certain statements contained in this report as well as in periodic press releases and certain oral statements made by our officials during our presentations are “forward-looking” statements. Forward-looking statements include, without limitation, any statement that may project, indicate or imply future results, events, performance or achievements and may contain the words “expect,” “intend,” “plan,” “anticipate,” “estimate,” “believe,” “will be,” “will continue,” “will likely result,” and similar expressions, or future conditional verbs such as “may,” “will,” “should,” “would,” and “could.” In addition, any statement concerning future financial performance (including future revenues, earnings or growth rates), ongoing business strategies or prospects, and possible actions taken by us, Summit Investments or our Sponsor, are also forward-looking statements. These forward-looking statements involve various risks and uncertainties, including, but not limited to, those described in Item 1A. Risk Factors included in this report.

Forward-looking statements are based on current expectations and projections about future events and are inherently subject to a variety of risks and uncertainties, many of which are beyond the control of our management team. All forward-looking statements in this report and subsequent written and oral forward-looking statements attributable to us, or to persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements in this paragraph. These risks and uncertainties include, among others:

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fluctuations in natural gas, NGLs and crude oil prices;

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the extent and success of our customers' drilling efforts, as well as the quantity of natural gas and crude oil volumes produced within proximity of our assets;

•

failure or delays by our customers in achieving expected production in their natural gas, crude oil and produced water projects;

•

competitive conditions in our industry and their impact on our ability to connect hydrocarbon supplies to our gathering and processing assets or systems;

•

actions or inactions taken or nonperformance by third parties, including suppliers, contractors, operators, processors, transporters and customers, including the inability or failure of our shipper customers to meet their financial obligations under our gathering agreements and our ability to enforce the terms and conditions of certain of our gathering agreements in the event of a bankruptcy of one or more of our customers;

•

our ability to acquire assets owned by third parties, which is subject to a number of factors, including prevailing conditions and outlook in the natural gas, NGL and crude oil industries and markets and our ability to obtain financing on acceptable terms;

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our ability to consummate acquisitions, successfully integrate the acquired businesses, realize any cost savings and other synergies from any acquisition;

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the ability to attract and retain key management personnel;

•

commercial bank and capital market conditions and the potential impact of changes or disruptions in the credit and/or capital markets;

•

changes in the availability and cost of capital and the results of our financing efforts, including availability of funds in the credit and/or capital markets;

•

restrictions placed on us by the agreements governing our debt instruments;

•

the availability, terms and cost of downstream transportation and processing services;

•

natural disasters, accidents, weather-related delays, casualty losses and other matters beyond our control;

EX 99.2-30

EXHIBIT 99.2

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operational risks and hazards inherent in the gathering, treating and/or processing of natural gas, crude oil and produced water;

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weather conditions and terrain in certain areas in which we operate;

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any other issues that can result in deficiencies in the design, installation or operation of our gathering, treating and processing facilities;

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timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and rights-of-way and other factors that may impact our ability to complete projects within budget and on schedule;

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the effects of existing and future laws and governmental regulations, including environmental, safety and climate change requirements;

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the effects of litigation;

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changes in general economic conditions; and

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certain factors discussed elsewhere in this report.

Developments in any of these areas could cause actual results to differ materially from those anticipated or projected or cause a significant reduction in the market price of our common units and senior notes.

The foregoing list of risks and uncertainties may not contain all of the risks and uncertainties that could affect us. In addition, in light of these risks and uncertainties, the matters referred to in the forward-looking statements contained in this document may not in fact occur. Accordingly, undue reliance should not be placed on these statements. We undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events or otherwise, except as otherwise required by law.

EX 99.2-31