Summit Midstream Partners 8K/A Financial Statements and Exhibits | SMLP 1 Sep 16

EXHIBIT 99.1

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


•	Non-GAAP Financial Measures


•	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 conduct and report our operations in the midstream energy industry through five reportable segments:


•	the Utica Shale, which includes our ownership interest in Ohio Gathering and also is served by Summit Utica;


•	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;


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

Our results are driven primarily by the volumes that we gather, treat and/or process. We generate the majority of our revenue from the natural gas gathering, treating and processing services that we provide to our natural gas customers. Under the substantial majority of these agreements, we are paid a fixed fee based on the volumes we gather, treat and/or process. These agreements enhance the stability of our cash flows by providing a revenue stream that is not subject to direct commodity price risk.

We also earn revenue from (i) crude oil and produced water gathering, (ii) 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 gathering systems, (ii) the sale of natural gas we retain from our DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River. We are exposed to direct commodity price risk from engaging in any of these additional activities with the exception of crude oil and produced water gathering. We also have indirect exposure to changes in commodity prices in that persistent low commodity prices may cause our customers to delay 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 or natural gas) that we gather. If our customers cancel or delay drilling and/or completion activities or temporarily shut-in production, our MVCs ensure that we will receive a certain amount of revenue from certain of our customers.

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



	Year ended December 31,
	2015			2014			2013
	(In thousands)
Selected Financial Results:
Net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008
EBITDA (1)	(57,838		)	93,890			141,310
Adjusted EBITDA (1)	235,491			207,975			162,690
Distributable cash flow (1)	164,931			144,711			120,611

Acquisitions of gathering systems (2)	$	288,618		$	315,872		$	458,914
Capital expenditures (3)	(272,225		)	(343,380		)	(249,626		)

Proceeds from issuance of common units, net (4)	$	221,977		$	197,806		$	—
Issuance of senior notes	—			300,000			300,000
Borrowings (repayments) under revolving credit facility, net	216,000			(136,000		)	179,770
Distributions to unitholders	(152,074		)	(122,224		)	(90,196		)

__________

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

(2) Reflects consideration paid, including working capital and capital expenditure adjustments paid (received), for acquisitions and/or drop downs. For additional information, see Note 16 to the consolidated financial statements.

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

(4) Reflects proceeds from underwritten primary offerings and does not include proceeds from units issued to affiliates to affect acquisitions or drop downs.

Year ended December 31, 2015. 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 and adjusted EBITDA. 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.

During 2015, we acquired Polar and Divide from a subsidiary of Summit Investments in a drop down transaction. We also began and/or completed system expansion projects on the Polar and Divide, Grand River, Bison Midstream and Tioga Midstream systems.

In May 2015, we completed an underwritten primary offering of common units and used the proceeds along with borrowings under our revolving credit facility to fund the Polar and Divide Drop Down. Distributions declared in respect of the fourth quarter of 2015 increased 2.7% over distributions declared in respect of the fourth quarter of 2014.

Year ended December 31, 2014. 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.

During 2014, we acquired Red Rock Gathering from a subsidiary of Summit Investments in a drop down transaction. We also completed several system expansion projects across all systems.

In March 2014, we completed an underwritten public offering of primary and secondary units and we also completed a secondary offering in September 2014. We used the funds from the March 2014 primary offering to partially fund the Red Rock Drop Down. In July 2014, we also issued senior notes and used the proceeds to repay a portion of our outstanding revolving credit facility balance. Distributions declared in respect of the fourth quarter of 2014 increased 16.7% over distributions declared in respect of the fourth quarter of 2013.

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Year ended December 31, 2013. During 2013, we acquired Bison Midstream from a subsidiary of Summit Investments in a drop down transaction and Mountaineer Midstream in a third-party acquisition. We also completed several system expansion projects across all systems.

In June 2013, we issued senior notes and common units to Summit Investments to fund the acquisitions of Bison Midstream and Mountaineer Midstream. Distributions declared in respect of the fourth quarter of 2013 increased 17.1% over distributions declared in respect of the fourth quarter of 2012.

For additional information, see Item 1. Business, the remainder of this MD&A and the notes to the consolidated financial statements included herein.

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;


•	Acquisitions from third parties; 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 has decreased, with the New York Mercantile Exchange, or NYMEX, natural gas futures price at $2.28 per MMBtu as of December 31, 2015 compared with $2.89 per MMBtu as of December 31, 2014 and $4.23 per MMBtu as of December 31, 2013. Natural gas prices continue to trade at lower-than-average historical prices due in part to increased production, especially from unconventional sources, such as natural gas shale plays. According to the U.S. Energy Information Administration (the "EIA"), average annual natural gas production in the United States increased to 85.9 Bcf/d, or 55.9%, in 2014 from 55.1 Bcf/d in 2008. Over the same time period, natural gas consumption increased only 15.0% to 73.1 Bcf/d. In response to lower natural gas prices, the number of active natural gas drilling rigs has declined from approximately 1,350 in December 2008 to approximately 162 in December 2015, according to Baker Hughes.

Lower natural gas prices in 2015 relative to 2014 and 2013 are also attributable to U.S. weather patterns that contributed to temperatures that were 24% warmer than historical norms in the second half of 2015, which resulted in lower-than-normal overall consumption of natural gas. As a result, the amount of natural gas in storage in the continental United States increased to approximately 3.8 Tcf as of December 25, 2015, compared with approximately 3.2 Tcf as of December 26, 2014, and a five-year historical December average of 3.5 Tcf. Additionally, a number of exploration and production companies made public announcements in 2015 regarding abnormally high production rates from natural gas wells targeting the Utica Shale formation in Ohio, West Virginia and Pennsylvania, which has resulted in a recalibration of the market’s expectation for future natural gas supplies in the United States.

We believe that over the near term, until the supply of natural gas has been reduced, weather patterns change, resulting in colder temperatures, or the broader economy experiences more robust growth to stimulate higher demand, natural gas prices are likely to be constrained.

Over the long term, we believe that the prospects for continued natural gas demand are favorable and will be driven primarily by population and economic growth, as well as the continued displacement of coal-fired electricity generation by natural gas-fired electricity generation. For example, according to the EIA, coal-fired power plants generated 39% of the electricity in the United States in 2014, compared with 48% in 2008. The EIA expects this trend to continue, with coal-fired power plants representing 34% of total electricity generation by 2040.

In April 2015, the EIA projected total annual domestic consumption of natural gas to increase from approximately 71.8 Bcf/d in 2013 to approximately 81.4 Bcf/d in 2040. Consistent with the rise in consumption, the EIA projects that total domestic natural gas production will continue to grow through 2040 to 97.3 Bcf/d. The EIA also projects that the United States will be a net exporter of liquefied natural gas, or LNG, by 2017, with net U.S. exports of LNG

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projected to rise to 15.3 Bcf/d in 2040, compared with net imports of 4.1 Bcf/d in 2013. We believe that increasing consumption of natural gas will continue to drive natural gas drilling and production over the long term throughout the United States.

In addition, the Bison Midstream, Polar and Divide, Niobrara G&P and Tioga Midstream systems are directly affected by crude oil supply and demand dynamics. Crude oil has been the focus of a recent global supply surplus, with OPEC initially stating in November 2014 and throughout 2015 that it would not decrease production levels, despite concerns of slowing global demand, particularly in historically high growth countries such as China. This, in conjunction with continued crude oil production growth from unconventional shale plays in the United States, and expected crude oil production growth in countries that have had limited production outputs of late, such as Iran, has played a significant role in the recent decline in crude oil prices, with NYMEX crude oil futures ending 2015 at $37.13 per barrel, compared to a high in June 2014 of $107.26 per barrel. In response to lower crude oil prices, the number of active crude oil drilling rigs has declined from a peak of 1,609 in October 2014 to 536 in December 2015, according to Baker Hughes. For additional information, see the "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" section herein and Notes 4, 5 and 6 to the consolidated financial statements.

Over the next several years, the EIA projects that domestic crude oil production will continue to increase from an average of 8.7 million Bbl/d in 2014 to 10.6 million Bbl/d in 2020. While long-term estimates vary due to uncertainty regarding long-term crude oil price trends, the EIA still sees continued growth in certain unconventional shale plays, with crude oil prices expected to remain high enough to support continued drilling and increasing production in the Bakken Shale, Eagle Ford Shale, Permian Basin, and Niobrara Shale. Additionally, in December 2015, the United States lifted a ban that had previously prohibited crude oil exports. This repeal should, over time, enable the West Texas Intermediate ("WTI") crude oil price benchmark to become more competitive with other global crude oil price benchmarks, thus stimulating incremental domestic production.

Growth in production from U.S. shale plays. Over the past several years, a fundamental shift in production has emerged with the growth of natural gas production from unconventional shale resources. While the EIA expects total dry natural gas production to grow 38.1% from 25.7 Tcf in 2014 to 35.5 Tcf in 2040, it expects shale gas production to grow to 19.6 Tcf in 2040, representing 55% of total U.S. natural gas production. Most of this increase is due to the emergence of unconventional natural gas plays and advances in technology that have allowed producers to extract significant volumes of natural gas from these plays at cost-advantaged per-unit economics when compared to most conventional plays.

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

As a result of the current low commodity price environment, many producers have announced reductions to their capital expenditure budgets by limiting their drilling activities in lower performing resource plays or in lower tier areas within higher performing resource plays. In addition, the low commodity price environment has left a number of producers in financial distress, evidenced in part by the 31 U.S.-based exploration and production companies that filed for bankruptcy protection in 2015. Nevertheless, we believe producers will remain focused on deploying capital in their highest quality resource plays, even in a low commodity price environment.

Capital markets activity and cost of capital. After multiple years of near-record low interest rates, the credit markets reversed in 2015 and borrowing costs increased for virtually all crude oil and natural gas industry-related borrowers. Additionally, in December 2015, the Federal Reserve announced that it would raise its benchmark federal-funds rate from near zero to a range between 0.25% and 0.50%, the first such increase since 2006. 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 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 competitors would face similar circumstances.

Acquisitions from Third Parties. Our principal business strategy is to increase the amount of cash distributions we make to our unitholders over time. Our ability to grow cash distributions depends, in part, on our ability to make acquisitions that increase the amount of cash generated from our operations on a per-unit basis, along with other

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factors. Following the 2016 Drop Down, we intend to continue to pursue accretive acquisitions of midstream assets from third parties. However, their size, timing and/or contribution to our results of operations 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 on acceptable terms 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 on acceptable terms from commercial banks, the capital markets or other sources.

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

We expect to finance potential third-party acquisitions with equity offerings and borrowings under our revolving credit facility, initially. Longer-term financing is expected to be provided by the issuance of additional debt and equity securities. See the "Liquidity and Capital Resources—Capital Requirements" section herein and Notes 9 and 11 to the consolidated financial statements for additional information.

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 as overall demand for these goods and services declined. 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 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 five reportable segments:


•	the Utica Shale, which includes our ownership interest in Ohio Gathering as well as Summit Utica;


•	the Williston Basin, which includes Bison Midstream, Polar and Divide and Tioga Midstream;


•	the Piceance/DJ Basins, which includes Grand River and Niobrara G&P;


•	the Barnett Shale, which includes DFW Midstream;


•	the Marcellus Shale, which includes 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 for additional information.

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,


•	EBITDA,


•	adjusted EBITDA and segment adjusted EBITDA, and


•	distributable cash flow.

Throughput Volume

The volume of (i) natural gas that we gather, treat and/or process and (ii) crude oil and produced water that we gather depends on the level of production from natural gas or crude oil wells connected to our gathering systems.

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Aggregate production volumes are impacted by the overall amount of drilling and completion activity. Furthermore, because the production rate of natural gas and crude oil wells decline over time, production can only be maintained or increased by new drilling or other activity.

As a result, we must continually obtain new supplies of production to maintain or increase the throughput volume on our systems. Our ability to maintain or increase throughput volumes from existing customers and obtain new 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; natural gas gathering rates are reported in millions of cubic feet per day ("MMcf/d"). We aggregate crude oil and produced water gathering and report it in barrels; liquids gathering rates are reported in thousands of barrels per day ("Mbbl/d").

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. We report throughput rates for natural gas on a per thousand cubic feet ("Mcf") basis and throughput rates for liquids on a per barrel ("Bbl") basis.

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.

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

EBITDA, Adjusted EBITDA, Segment Adjusted EBITDA and Distributable Cash Flow

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

EBITDA and adjusted EBITDA (including segment adjusted EBITDA) are used to assess:


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

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


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


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

In addition, adjusted EBITDA (including segment adjusted EBITDA) is used to assess:


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

Distributable cash flow is used to assess:


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


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

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.


•	The consolidated financial statements reflect the results of operations of Bison Midstream, Polar and Divide and Niobrara G&P since February 2013. 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 Mountaineer Midstream since June 2013.

For additional information, see the "Results of Operations" and "Non-GAAP Financial Measures" sections 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 natural gas liquids purchased under percentage-of-proceeds arrangements with certain of our customers on the Bison Midstream and Grand River gathering systems, (ii) the sale of natural gas we retain from our DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River.

Other revenues. Revenue earned primarily from (i) 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.

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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 purchased from certain of our customers on the Bison Midstream and Grand River gathering systems.

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

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

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

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

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

Interest expense. Interest expense associated with our revolving credit facility, our senior notes and debt that was allocated to the 2016 Drop Down Assets (see Notes 2 and 9 to the consolidated financial statements).

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

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Consolidated Overview of the Years Ended December 31, 2015, 2014 and 2013

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



	Year ended December 31,									Percentage Change
	2015			2014			2013			2015 v. 2014		2014 v. 2013

	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	337,819		$	267,478		$	216,352		26	%	24	%
Natural gas, NGLs and condensate sales	42,079			97,094			88,185			(57	)%	10	%
Other revenues	20,659			22,597			21,623			(9	)%	5	%
Total revenues	400,557			387,169			326,160			3	%	19	%
Costs and expenses:
Cost of natural gas and NGLs	31,398			72,415			68,037			(57	)%	6	%
Operation and maintenance	94,986			94,869			78,175			—	%	21	%
General and administrative	45,108			43,281			36,716			4	%	18	%
Transaction costs	1,342			2,985			2,841			(55	)%	5	%
Depreciation and amortization	105,117			90,878			71,232			16	%	28	%
Environmental remediation	21,800			5,000			—			*		*
(Gain) loss on asset sales, net	(172		)	442			113			*		*
Long-lived asset impairment	9,305			5,505			—			69	%	*
Goodwill impairment	248,851			54,199			—			*		*
Total costs and expenses	557,735			369,574			257,114			51	%	44	%
Other income	2			1,189			5			*		*
Interest expense	(59,092		)	(48,586		)	(21,314		)	22	%	128	%
(Loss) income before income taxes	(216,268		)	(29,802		)	47,737			*		*
Income tax benefit (expense)	603			(854		)	(729		)	*		17	%
Loss from equity method investees	(6,563		)	(16,712		)	—			(61	)%	*
Net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008		*		*

Operating Data:
Aggregate average throughput – gas (MMcf/d)	1,498			1,423			1,139			5	%	25	%
Aggregate average throughput rate per Mcf – gas	$	0.47		$	0.47		$	0.50		—	%	(6	)%
Average throughput – liquids (Mbbl/d)	67.7			40.7			10.9			66	%	*
Average throughput rate per Bbl – liquids	$	1.84		$	1.69		$	0.95		9	%	78	%

__________

* Not considered meaningful

Volumes – Gas. For the year ended December 31, 2015, our aggregate natural gas throughput volumes increased primarily reflecting an increase in volume throughput for Mountaineer Midstream and Summit Utica, partially offset by volume throughput declines on Grand River.

For the year ended December 31, 2014, our aggregate natural gas throughput volumes increased largely reflecting the contribution from Mountaineer Midstream and Grand River. These production increases were partially offset by volume throughput declines on the DFW Midstream and Legacy Grand River systems.

Volumes – Liquids. Average daily throughput for crude oil and produced water increased during the years ended December 31, 2015 and 2014, primarily reflecting the continued development of the Polar and Divide and Tioga Midstream systems, new pad site connections and producers' ongoing drilling activity.

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Revenues. For the year ended December 31, 2015, total revenues increased $13.4 million primarily reflecting:


•	the recognition in 2015 of previously deferred revenue at Grand River (see Note 8 to the consolidated financial statements).


•	an increase in gathering services and related fees for the Polar and Divide, Mountaineer Midstream, Summit Utica and Tioga Midstream systems.


•	an offset to revenues as a result of declines in natural gas, NGLs and condensate sales for Bison Midstream, Grand River and DFW Midstream.

For the year ended December 31, 2014, total revenues increased $61.0 million, or 19%, primarily reflecting:


•	overall growth at Grand River and Polar and Divide.


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


•	gathering services and related fees at Tioga Midstream, which was brought into service in November 2014.


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


•	an overall decline in DFW Midstream revenues largely due to lower volume throughput.

Gathering Services and Related Fees. The increase in gathering services and related fees during the year ended December 31, 2015 was primarily driven by the recognition of previously deferred revenue noted above and higher volume throughput on the Polar and Divide, Mountaineer Midstream, Summit Utica and Tioga Midstream systems.

The aggregate average throughput rate for natural gas was flat at $0.47/Mcf during the years ended December 31, 2015 and 2014, primarily as a result of Tioga Midstream's contribution, partially offset by a larger proportion of gathering fee revenue from Mountaineer Midstream. The aggregate average throughput rate for crude oil and produced water increased to $1.84/Bbl during the year ended December 31, 2015, compared with $1.69/Bbl in the prior-year period primarily as a result of the effect of contract amendments in 2014 which increased gathering rates in connection with our commitment to further expand the Polar and Divide system.

For the year ended December 31, 2014, gathering services and related fees increased primarily reflecting the proportionate contribution of higher margin volume throughput from certain customers and the first quarter 2014 commissioning of a natural gas processing plant at Grand River; the impact of higher volume throughput on gathering services and related fees and higher gathering rates associated with contract amendments in 2014 for Polar and Divide; a full year of operations under SMLP's ownership as well as our build out of the Mountaineer Midstream system and the partial year of operations for Tioga Midstream. These increases were partially offset by the continued natural decline in volumes and lack of producer drilling activity on the DFW Midstream system.

The aggregate average throughput rate for natural gas decreased to $0.47/Mcf during the year ended December 31, 2014, compared with $0.50/Mcf in the prior-year period largely as a result of a larger proportion of gathering fee revenue from Mountaineer Midstream, partially offset by an increase for Grand River due to a shift in volume mix. The aggregate average throughput rate for crude oil and produced water increased to $1.69/Bbl during the year ended December 31, 2014, compared with $0.95/Bbl in the prior-year period primarily as a result of the effect of 2014 contract amendments noted above.

Natural Gas, NGLs and Condensate Sales. The decrease in natural gas, NGLs and condensate sales for the year ended December 31, 2015 was primarily a result of the impact of declining commodity prices. Declining commodity prices negatively impacted our percent-of-proceeds arrangements at Bison Midstream and Grand River, our fuel retainage revenue at DFW Midstream and condensate revenue for Grand River.

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

Costs and Expenses. Total costs and expenses increased $188.2 million, or 51%, for the year ended December 31, 2015 primarily reflecting:


•	the goodwill impairments recognized for Polar and Divide and Grand River.


•	a partial offset resulting from lower cost of natural gas and NGLs at Bison Midstream and Grand River.


•	a full year of operations for Summit Utica and Tioga Midstream.

EX 99.1-10

EXHIBIT 99.1


•	an environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down.


•	an increase in depreciation and amortization expense for all systems, except DFW Midstream.


•	a partial offset due to the impact of the 2014 goodwill and long-lived asset impairments.

For the year ended December 31, 2014, total costs and expenses increased $112.5 million, or 44%, primarily reflecting:


•	the goodwill impairment recognized for Bison Midstream.


•	an increase in depreciation and amortization across our gathering systems.


•	an increase in cost of natural gas and NGLs for Bison Midstream and Grand River.


•	a partial year of operations for Tioga Midstream and Niobrara G&P, which commenced operations in September 2013.


•	an increase in operation and maintenance expense as a result of the continued development of the Polar and Divide system.


•	an environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down.

Cost of Natural Gas and NGLs. The decrease in cost of natural gas and NGLs for the year ended December 31, 2015 was largely driven by declining commodity prices and the associated impact on our percent-of-proceeds arrangements at Bison Midstream and Grand River. The increase in cost of natural gas and NGLs for the year ended December 31, 2014 was primarily attributable to an increase in volume throughput, partially offset by declining commodity prices.

Operation and Maintenance. 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 a decline 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.)

Operation and maintenance expense increased during the year ended December 31, 2014 primarily as a result of the 2014 start up of Tioga Midstream, an environmental remediation accrual for assets contributed to Polar and Divide, a full year of operations for both Mountaineer Midstream and Polar and Divide as well as higher expenses at Bison Midstream, including an increase in pass-through electricity expense (revenue component is recognized in other revenues).

General and Administrative. General and administrative expense increased during the year ended December 31, 2015 reflecting a an increase in salaries, benefits and unit-based and noncash 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").

General and administrative expense increased during the year ended December 31, 2014, largely as a result of an increase in salaries, benefits and incentive compensation primarily due to increased head count, an increase in professional expenses associated with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002 and our adoption of COSO 2013 and rent expenses.

Transaction Costs. Transaction costs recognized primarily relate to financial and legal advisory costs associated with the Polar and Divide Drop Down in 2015, the Red Rock Drop Down in 2014 and the Bison Drop Down and the acquisition of Mountaineer Midstream in 2013. Transaction costs also include financial and legal advisory expenses incurred by Summit Investments in 2015 and 2014 for third-party acquisitions that were allocated to us in connection with the 2016 Drop Down.

Depreciation and Amortization. The increase in depreciation and amortization expense during the years ended December 31, 2015 and 2014 was largely driven by an increase in assets placed into service and an increase in contract amortization largely due to Grand River.

EX 99.1-11

EXHIBIT 99.1

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

The increase in interest expense during the year ended December 31, 2014 was primarily driven by our June 2013 issuance of 7.5% senior notes and an increase in interest expense allocated to us in connection with the 2016 Drop Down.

Segment Overview of the Years Ended December 31, 2015, 2014 and 2013

Utica Shale. Our ownership interests in Ohio Gathering are the primary component of the Utica Shale reportable segment. We acquired substantially all of Summit Investments' indirect ownership interest in Ohio Gathering, a natural gas gathering system and a condensate stabilization facility, in March 2016 (see the notes to the consolidated financial statements for additional information). The Utica Shale reportable segment also includes Summit Utica, a natural gas gathering system, which was acquired from a subsidiary of Summit Investments in March 2016. Our segment financial results include recognition of our proportional adjusted EBITDA activity for Ohio Gathering since January 2014, the date on which common control began.

Volume throughput for our Utica Shale reportable segment, exclusive of volume throughput data for Ohio Gathering which we do not operate, follows.



	Utica Shale (1)
	Year ended December 31,		Percentage Change
	2015	2014	2015 v. 2014
Operating Data:
Average throughput (MMcf/d) (2)	37	1	*

__________

(1) Summit Utica contract terms related to throughput rate per Mcf are excluded for confidentiality purposes.

(2) For the year ended December 31, 2014. For the period of SMLP's ownership in 2014, average throughput was 12 MMcf/d.

* Not considered meaningful

Financial data for our Utica Shale reportable segment follows.



	Utica Shale
	Year ended December 31,				Percentage Change
	2015		2014		2015 v. 2014

	(In thousands)
Revenues:
Gathering services and related fees	$	4,700	$	190	*
Total revenues	4,700		190		*
Costs and expenses:
Operation and maintenance	1,017		—		*
General and administrative	1,477		20		*
Depreciation and amortization	1,417		—		*
Total costs and expenses	3,911		20		*
Add:
Proportional adjusted EBITDA for equity method investees	33,667		6,006
Depreciation and amortization	1,417		—
Segment adjusted EBITDA	$	35,873	$	6,176	*

__________

EX 99.1-12

EXHIBIT 99.1

* Not considered meaningful

Year ended December 31, 2015. Segment adjusted EBITDA increased $29.7 million during 2015 reflecting:


•	an increase in Ohio Gathering's adjusted EBITDA due to ongoing growth and development.


•	a full year of operations and the growth and development of Summit Utica.

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

Williston Basin. Bison Midstream, Polar and Divide and Tioga Midstream provide our services for the Williston Basin reportable segment. Bison Midstream, an associated natural gas gathering system, was acquired from a subsidiary of Summit Investments in June 2013. Polar and Divide, a crude oil and produced water gathering system and transmission pipelines, was acquired from subsidiaries of Summit Investments in May 2015. Tioga Midstream, an associated natural gas, crude oil and produced water gathering system, was acquired from a subsidiary of Summit Investments in March 2016. Our results include activity for all periods during which the assets were under common control. Common control began in February 2013 for Bison Midstream and Polar and Divide and in April 2014 for Tioga Midstream.

Operating data for our Williston Basin reportable segment follows.



	Williston Basin
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013

Operating Data:
Average throughput – natural gas (MMcf/d) (1)	23		18		14		28	%	29	%
Average throughput rate per Mcf – gas	$	2.40	$	3.44	$	3.86	(30	)%	(11	)%
Average throughput – liquids (Mbbl/d) (2)	67.7		40.7		10.9		66	%	*
Average throughput rate per Bbl – liquids	$	1.84	$	1.69	$	0.95	9	%	78	%

__________

* Not considered meaningful

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

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

Natural gas. 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.

The increase in natural gas volume throughput in 2014 primarily reflects additional pad site connections and newly installed compression capacity on Bison Midstream, which improved system hydraulics.

The declines in natural gas gathering rates in 2015 and 2014 were primarily a result of the impact of declining commodity prices on volumes associated with a percent-of-proceeds contract.

Liquids. The increase in liquids volume throughput in 2015 and 2014 reflect new pad site connections and ongoing drilling activity in Polar and Divide's service area.

The increase in average throughput rate for liquids for 2015 and 2014 was primarily as a result of contract amendments in 2014 which increased gathering rates in connection with our commitment to further expand the Polar and Divide system.

EX 99.1-13

EXHIBIT 99.1

Financial data for our Williston Basin reportable segment follows.



	Williston Basin
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013

	(In thousands)
Revenues:
Gathering services and related fees	$	62,899	$	41,766	$	21,132	51	%	98	%
Natural gas, NGLs and condensate sales	23,525		56,040		47,130		(58	)%	19	%
Other revenues	12,505		12,001		13,239		4	%	(9	)%
Total revenues	98,929		109,807		81,501		(10	)%	35	%
Costs and expenses:
Cost of natural gas and NGLs	23,090		54,481		54,840		(58	)%	(1	)%
Operation and maintenance	26,586		22,926		8,849		16	%	159	%
General and administrative	5,400		8,474		4,402		(36	)%	93	%
Depreciation and amortization	31,376		24,027		16,669		31	%	44	%
Environmental remediation	21,800		5,000		—		*		*
(Gain) loss on asset sales, net	5		296		—		*		*
Long-lived asset impairment	7,554		—		—		*		*
Goodwill impairment	203,373		54,199		—		*		*
Total costs and expenses	319,184		169,403		84,760		88	%	100	%
Add:
Depreciation and amortization	31,376		24,027		16,669
Adjustments related to MVC shortfall payments	11,870		10,743		3,600
Unit-based compensation	85		340		340
Loss on asset sales	5		296		—
Long-lived asset impairment	7,554		—		—
Goodwill impairment	203,373		54,199		—
Segment adjusted EBITDA	$	34,008	$	30,009	$	17,350	13	%	73	%

__________

* Not considered meaningful

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


•	an environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down.


•	the impact of higher volume throughput on gathering services and related fees as well as other revenues generated by the Polar and Divide system.


•	higher gathering rates associated with amendments to liquids contracts in 2014.


•	a 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 impact of declining commodity prices which negatively affect the margins we earn under percent-of-proceeds arrangements at Bison Midstream.


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

Depreciation and amortization increased during 2015 largely as a result of assets placed into service. 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. The goodwill impairment

EX 99.1-14

EXHIBIT 99.1

recognized in 2015 relates to our determination that all of the goodwill associated with the Polar and Divide reporting unit had been impaired.

Year ended December 31, 2014. Segment adjusted EBITDA increased $12.7 million during 2014 reflecting:


•	the impact of higher volume throughput on gathering services and related fees as well as other revenues generated by the Polar and Divide system.


•	higher gathering rates associated with amendments to liquids contracts in 2014.


•	increased volumes under our percent-of-proceeds arrangements on the Bison Midstream system.


•	higher operating and maintenance expense to support volume growth across the systems.


•	an environmental remediation accrual for assets contributed to Polar and Divide in connection with the 2016 Drop Down

The increase in depreciation and amortization expense during 2014 was largely driven by an increase in assets placed into service and contract amortization. The goodwill impairment recognized in 2014 relates to our determination that all of the goodwill associated with the Bison Midstream reporting unit had been impaired.

For additional information, see the sections entitled "Non-GAAP Financial Measures—Non-GAAP reconciliations items to note," "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" herein and Notes 2 and 6 to the consolidated financial statements.

Piceance/DJ Basins. Grand River, a natural gas gathering and processing system, provides our midstream services for the Piceance/DJ Basins reportable segment. Red Rock Gathering became part of the Grand River system in connection with the Red Rock Drop Down in March 2014. As noted above, our results include activity for Red Rock Gathering since October 2012, the date on which common control began. Niobrara G&P, an associated natural gas gathering and processing system in the DJ Basin, was acquired from a subsidiary of Summit Investments in March 2016. Our results include activity for Niobrara G&P since February 2013, the date on which common control began. For additional information, see the notes to the consolidated financial statements.

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



	Piceance/DJ Basins
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013

Operating Data:
Average throughput (MMcf/d)	609		663		647		(8	)%	2	%
Average throughput rate per Mcf	$	0.57	$	0.51	$	0.41	12	%	24	%

Volume throughput during 2015 was favorably impacted by new pad site connections for WPX Energy, Inc. and Ursa Resources Group II as well as the March 2014 start-up of a cryogenic processing plant servicing production from Black Hills Corporation. Volume throughput on the Legacy Grand River system declined in 2014 primarily as a result of Encana's continued suspension of drilling activities, which began in the fourth quarter of 2013.

The aggregate average throughput rate increased during 2015 and 2014 largely as a result of a shift in volume throughput mix. Volume growth from Red Rock Gathering's anchor customers continues to offset volume declines on the Legacy Grand River system and thereby has translated into higher average gathering rates per Mcf.

EX 99.1-15

EXHIBIT 99.1

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



	Piceance/DJ Basins
	Year ended December 31,							Percentage Change
	2015			2014		2013		2015 v. 2014		2014 v. 2013

	(Dollars in thousands, except fee-rate data)
Revenues:
Gathering services and related fees	$	161,291		$	122,852	$	96,485	31	%	27	%
Natural gas, NGLs and condensate sales	11,854			27,606		23,865		(57	)%	16	%
Other revenues	7,273			11,019		9,397		(34	)%	17	%
Total revenues	180,418			161,477		129,747		12	%	24	%
Costs and expenses:
Cost of natural gas and NGLs	8,308			17,934		13,197		(54	)%	36	%
Operation and maintenance	36,674			37,945		35,025		(3	)%	8	%
General and administrative	3,624			10,029		14,233		(64	)%	(30	)%
Depreciation and amortization	47,433			42,959		36,185		10	%	19	%
(Gain) loss on asset sales	(190		)	146		—		*		*
Long-lived asset impairment	1,220			—		—		*		*
Goodwill impairment	45,478			—		—		*		*
Total costs and expenses	142,547			109,013		98,640		31	%	11	%
Other income	—			1,185		—		*		*
Add:
Depreciation and amortization	47,433			42,959		36,185
Adjustments related to MVC shortfall payments	(21,590		)	15,194		12,395
Loss on asset sales	24			146		—
Long-lived asset impairment	1,220			—		—
Goodwill impairment	45,478			—		—
Less:
Gain on asset sales	214			—		—
Impact of purchase price adjustment	—			1,185		—
Segment adjusted EBITDA	$	110,222		$	110,763	$	79,687	—	%	39	%

__________

* Not considered meaningful

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


•	the impact of declining commodity prices which negatively impacted the margins that we earn from our percent-of-proceeds contracts.


•	lower gathering services revenue from our Grand River anchor customer, partially offset by the contribution from Niobrara G&P.


•	the previously mentioned decision to discontinue allocating certain corporate general and administrative expenses to our reportable segments.


•	an increase in anticipated MVC shortfall payments due to increasing rate and volume commitment provisions in certain gas gathering agreements.

Gathering services and related fees also reflect the recognition of revenue that had been previously deferred in connection with an MVC arrangement, which was determined to no longer be recoverable by the customer. Because we exclude the impacts of adjustments related to MVC shortfall payments from our definition of segment adjusted EBITDA, this metric was not impacted by the 2015 deferred revenue release. (See Note 8 to the consolidated financial statements for additional information.) Other revenues and operation and maintenance also reflect the effect of a decrease in certain electricity expenses, which, due to their pass-through nature, have no

EX 99.1-16

EXHIBIT 99.1

impact on segment adjusted EBITDA. Depreciation and amortization increased during the year ended December 31, 2015 largely as a result of an increase in contract amortization for Grand River's anchor customer, the March 2014 commissioning of a cryogenic processing plant and the development of Niobrara G&P. 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. 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.

Year ended December 31, 2014. Segment adjusted EBITDA increased $31.1 million during 2014 reflecting:


•	higher gathering services and related fees, largely due to the proportionate contribution of higher margin volume throughput from certain customers, the contribution from Niobrara G&P and the first quarter 2014 commissioning of a natural gas processing plant.


•	an increase in anticipated MVC shortfall payments due to increasing rate and volume commitment provisions in certain gas gathering agreements.


•	a decline in operation and maintenance.

Other revenues and operation and maintenance also reflect the effect of a decrease in certain electricity expenses, which, due to their pass-through nature, have no impact on segment adjusted EBITDA. Depreciation and amortization increased during 2014 largely as a result an increase in contract amortization and assets placed into service on the Grand River system. Other income represents the write off of certain balances that had been previously recognized in connection with the purchase accounting for the Legacy Grand River system.

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

Operating data for our Barnett Shale reportable segment follows.



	Barnett Shale
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013

Operating Data:
Average throughput (MMcf/d)	352		358		391		(2	)%	(8	)%
Average throughput rate per Mcf	$	0.62	$	0.59	$	0.59	5	%	—	%

Volume throughput was flat in 2015 after declining in 2014. The 2015 year-over-year comparison reflects 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 anchor customer.

For 2014, the decline in volume throughput reflected the impact of multiple customers temporarily shutting-in several large pad sites to drill or complete new wells as noted above. In addition, 2013 volume throughput benefited early in the year due to the first quarter 2013 commissioning of an additional compressor which increased throughput capacity on the DFW Midstream system by 40 MMcf/d.

The higher average throughput rate in 2015 is primarily the result of a shift in volume mix.

Our customers have a number of wells that have been drilled and are in various stages of the completion process; many of which we expect to begin producing before the third quarter of 2016. In addition, one of our customers recently moved a drilling rig back into our service area to drill new wells which we expect will stimulate volume throughput in the second half of 2016.

EX 99.1-17

EXHIBIT 99.1

Financial data for our Barnett Shale reportable segment follows.



	Barnett Shale
	Year ended December 31,									Percentage Change
	2015			2014			2013			2015 v. 2014		2014 v. 2013

	(In thousands)
Revenues:
Gathering services and related fees	$	80,461		$	79,976		$	89,147		1	%	(10	)%
Natural gas, NGLs and condensate sales	6,700			13,448			17,190			(50	)%	(22	)%
Other revenues	881			(423		)	(1,013		)	*		*
Total revenues	88,042			93,001			105,324			(5	)%	(12	)%
Costs and expenses:
Operation and maintenance	25,823			29,438			31,784			(12	)%	(7	)%
General and administrative	1,297			4,607			6,129			(72	)%	(25	)%
Depreciation and amortization	15,606			15,657			13,929			—	%	12	%
Loss on asset sales	13			—			113			*		*
Long-lived asset impairment	531			5,505			—			*		*
Total costs and expenses	43,270			55,207			51,955			(22	)%	6	%
Add:
Depreciation and amortization	16,392			16,601			14,961
Adjustments related to MVC shortfall payments	(2,182		)	628			1,030
Loss on asset sales	13			—			113
Long-lived asset impairment	531			5,505			—
Segment adjusted EBITDA	$	59,526		$	60,528		$	69,473		(2	)%	(13	)%

__________

*Not considered meaningful

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


•	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.


•	lower electricity expense which is reflected in operation and maintenance. We purchase a fixed quantity of power at a fixed heat rate based on prevailing natural gas prices. As a result, the decline in natural gas prices translated into lower electricity expenses. This decline was partially offset by an increase in compression expense.


•	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 placing the Lonestar assets into service in September 2014.

Year ended December 31, 2014. Segment adjusted EBITDA decreased $8.9 million during 2014 reflecting:


•	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 decrease in gathering services and related fees due to lower volumes.

Depreciation and amortization increased during 2014 largely as a result of placing the Lonestar assets into service in September 2014.

EX 99.1-18

EXHIBIT 99.1

Marcellus Shale. Mountaineer Midstream, a natural gas gathering system, provides our midstream services for the Marcellus Shale reportable segment. We acquired Mountaineer Midstream in June 2013. Volume throughput for the Marcellus Shale reportable segment follows.



	Marcellus Shale (1)
	Year ended December 31,			Percentage Change
	2015	2014	2013 (2)	2015 v. 2014		2014 v. 2013

Operating Data:
Average throughput (MMcf/d)	478	382	87	25	%	*

__________

* Not considered meaningful

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

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

The increase in volume throughput in 2015, compared to 2014, was primarily driven by the upstream connection of wells owned by Mountaineer Midstream's anchor customer, Antero.

The increase in volume throughput in 2014, compared with 2013, reflects the continuation of active drilling by Antero and the connection of new wells upstream of the Mountaineer Midstream system as well as the impact of new, upstream compressor stations commissioned by third parties, which contributed to volume throughput.

We expect volumes on the Mountaineer Midstream system to increase throughout the second and third quarters of 2016 as Antero completes a portion of its deferred well inventory.

Financial data for our Marcellus Shale reportable segment follows.



	Marcellus Shale
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013

	(In thousands)
Revenues:
Gathering services and related fees	$	28,468	$	22,694	$	9,588	25	%	137	%
Total revenues	28,468		22,694		9,588		25	%	137	%
Costs and expenses:
Operation and maintenance	4,886		4,560		2,447		7	%	86	%
General and administrative	368		2,194		808		(83	)%	*
Depreciation and amortization	8,682		7,648		3,998		14	%	91	%
Total costs and expenses	13,936		14,402		7,253		(3	)%	99	%
Add:
Depreciation and amortization	8,682		7,648		3,998
Segment adjusted EBITDA	$	23,214	$	15,940	$	6,333	46	%	*

__________

* Not considered meaningful

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


•	the impact of an increase in volume throughput which translated into higher gathering services and related fees revenue.


•	minimum revenue commitment payments related to the Zinnia Loop project, beginning in the first quarter of 2015.


•	the previously mentioned decision to discontinue allocating certain corporate general and administrative expenses to our reportable segments.


•	an increase in operation and maintenance primarily as a result of system expansion and the associated increase in volume throughput.

EX 99.1-19

EXHIBIT 99.1

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

Year ended December 31, 2014. Segment adjusted EBITDA increased $9.6 million during 2014 reflecting:


•	a full year of operations under SMLP's management as well as our build out of the Mountaineer Midstream system to keep pace with increases in production from Antero as processing capacity at MPLX’s Sherwood Processing Complex increased.

Depreciation and amortization increased during the year ended December 31, 2014 largely as a result of a full year of operations.

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



	Corporate
	Year ended December 31,						Percentage Change
	2015		2014		2013		2015 v. 2014		2014 v. 2013

	(In thousands)
Costs and expenses:
General and administrative	$	32,942	$	17,957	$	11,144	83	%	61	%
Transaction costs	1,342		2,985		2,841		(55	)%	5	%
Interest expense	59,092		48,586		21,314		22	%	128	%

General and Administrative. The increase in general and administrative expense during the year ended December 31, 2015, largely reflects the impact of our decision to discontinue allocating certain expenses, primarily salaries, benefits, incentive compensation and rent expense, to our operating segments.

Non-GAAP Financial Measures

EBITDA, adjusted EBITDA and distributable cash flow are not financial measures presented in accordance with GAAP.


•	EBITDA. We define EBITDA as net income or loss, plus interest expense, income tax expense and depreciation and amortization, less interest income and income tax benefit.


•	Adjusted EBITDA. We define adjusted EBITDA as EBITDA plus our proportional adjusted EBITDA for equity method investees, adjustments related to MVC shortfall payments, impairments and other noncash expenses or losses, less income (loss) from equity method investees and other noncash income or gains.

EX 99.1-20

EXHIBIT 99.1


•	Distributable Cash Flow. We define distributable cash flow as adjusted EBITDA plus cash interest received, less cash interest paid, senior notes interest adjustment, cash taxes paid and maintenance capital expenditures.

We believe that the presentation of these non-GAAP financial measures provides useful information to investors in assessing our financial condition and results of operations.

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


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


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


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


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


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

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

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

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


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


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


•	Proportional adjusted EBITDA for equity method investees accounts for our pro rata share of Ohio Gathering's adjusted EBITDA.

•

Adjustments related to MVC shortfall payments account for (i) the net increases or decreases in deferred revenue for MVC shortfall payments and (ii) our inclusion of expected annual MVC shortfall payments. We include a proportional amount of these historical or expected minimum volume commitment shortfall payments in each quarter prior to the quarter in which we actually receive the shortfall payment. See Notes 2 and 3 to the consolidated financial statements for additional information.


•	Goodwill impairments recognized during 2015 and 2014 are discussed in the sections entitled "Results of Operations" and "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" as well as Note 6 to the consolidated financial statements.


•	Long-lived asset impairments recognized during 2015 and 2014 are discussed in the sections entitled "Results of Operations" and "Critical Accounting Estimates—Recognition and Impairment of Long-Lived Assets" as well as Note 4 to the consolidated financial statements.

EX 99.1-21

EXHIBIT 99.1

•

The impact of purchase price adjustment reflects certain balances previously recognized in connection with the Predecessor's purchase accounting for the Legacy Grand River system that we wrote off during the fourth quarter of 2014. This write off was recognized in other income. See "Results of Operations—Piceance/DJ Basins" and Note 16 to the consolidated financial statements for additional information.


•	Senior notes interest adjustment represents the net of interest expense accrued and paid during the period. See "Liquidity and Capital Resources—Long-Term Debt" and Note 9 to the consolidated financial statements for additional information.


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

•

As a result of accounting for our drop down transactions similar to a pooling of interests, EBITDA, adjusted EBITDA, and distributable cash flow reflect the historical operations, financial position and cash flows of contributed subsidiaries for the periods beginning with the date that common control began and ending on the date that the respective drop down closed. See Notes 1 and 16 to the consolidated financial statements for additional information.


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

EX 99.1-22

EXHIBIT 99.1

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



	Year ended December 31,
	2015			2014			2013

	(In thousands)
Reconciliation of net income to EBITDA, adjusted EBITDA and distributable cash flow:
Net (loss) income	$	(222,228	)	$	(47,368	)	$	47,008
Add:
Interest expense	59,092			48,586			21,314
Income tax expense	—			854			729
Depreciation and amortization	105,903			91,822			72,264
Less:
Interest income	2			4			5
Income tax benefit	603			—			—
EBITDA	$	(57,838	)	$	93,890		$	141,310
Add:
Proportional adjusted EBITDA for equity method investees	33,667			6,006			—
Adjustments related to MVC shortfall payments	(11,902		)	26,565			17,025
Unit-based and noncash compensation	7,017			5,841			4,242
Loss on asset sales	42			442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Less:
(Loss) from equity method investees	(6,563		)	(16,712		)	—
Gain on asset sales	214			—			—
Impact of purchase price adjustment	—			1,185			—
Adjusted EBITDA	$	235,491		$	207,975		$	162,690
Add cash interest received	2			4			5
Less:
Cash interest paid	59,302			38,453			13,170
Senior notes interest adjustment	(1,421		)	6,733			12,125
Cash taxes paid	—			—			660
Maintenance capital expenditures	12,681			18,082			16,129
Distributable cash flow	$	164,931		$	144,711		$	120,611

EX 99.1-23

EXHIBIT 99.1

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



	Year ended December 31,
	2015			2014			2013

	(In thousands)
Reconciliation of net cash provided by operating activities to EBITDA, adjusted EBITDA and distributable cash flow:
Net cash provided by operating activities	$	191,375		$	152,953		$	135,411
Add:
(Loss) from equity method investees	(6,563		)	(16,712		)	—
Interest expense, excluding deferred loan costs	54,783			44,750			18,557
Income tax expense	—			854			729
Impact of purchase price adjustment	—			1,185			—
Changes in operating assets and liabilities	3,541			(18,603		)	(9,027		)
Gain on asset sales	214			—			—
Less:
Unit-based compensation	7,017			5,841			4,242
Distributions from equity method investees	34,641			2,992			—
Interest income	2			4			5
Income tax benefit	603			—			—
Loss on asset sales	42			442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Write-off of debt issuance costs	727			1,554			—
EBITDA	$	(57,838	)	$	93,890		$	141,310
Add:
Proportional adjusted EBITDA for equity method investees	33,667			6,006			—
Adjustments related to MVC shortfall payments	(11,902		)	26,565			17,025
Unit-based compensation	7,017			5,841			4,242
Loss on asset sales	42			442			113
Long-lived asset impairment	9,305			5,505			—
Goodwill impairment	248,851			54,199			—
Less:
(Loss) from equity method investees	(6,563		)	(16,712		)	—
Gain on asset sales	214			—			—
Impact of purchase price adjustment	—			1,185			—
Adjusted EBITDA	$	235,491		$	207,975		$	162,690
Add cash interest received	2			4			5
Less:
Cash interest paid	59,302			38,453			13,170
Senior notes interest adjustment	(1,421		)	6,733			12,125
Cash taxes paid	—			—			660
Maintenance capital expenditures	12,681			18,082			16,129
Distributable cash flow	$	164,931		$	144,711		$	120,611

EX 99.1-24

EXHIBIT 99.1

Liquidity and Capital Resources

Based on the terms of our partnership agreement, we expect that we will distribute to our unitholders most of the cash generated by our operations. As a result, we expect to fund future capital expenditures from cash and cash equivalents on hand, cash flow generated from our operations, borrowings under our revolving credit facility and future issuances of equity and debt instruments.

Capital Markets Activity

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

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

In September 2014, a subsidiary of Summit Investments completed an underwritten public offering of 4,347,826 SMLP common units. We did not receive any proceeds from this 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 pursuant to an effective shelf registration statement on Form S-3 previously filed with the SEC (the "May 2015 Equity Offering"). 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 2% general partner interest. We used the proceeds from the May 13, 2015 transaction to partially fund the Polar and Divide Drop Down. We used $25.0 million of the $29.0 million proceeds from the exercise of the underwriters' option to pay down our revolving credit facility. Following the May 2015 Equity Offering and the exercise of the underwriters' option, we can issue up to $464.8 million of debt and equity securities in primary offerings and 5,293,571 common units pursuant to this shelf registration statement.

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 "June 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 June 2015 ATM Program during the period from inception to December 31, 2015.

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

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

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

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

Debt

Revolving Credit Facility. As of December 31, 2015, we had a $700.0 million senior secured revolving credit facility. As of December 31, 2015, the outstanding balance of the revolving credit facility was $344.0 million and the unused portion totaled $356.0 million. There were no defaults or events of default during 2015 and, as of December 31, 2015, we were in compliance with the covenants in the revolving credit facility.

EX 99.1-25

EXHIBIT 99.1

Senior Notes. In July 2014, Summit Holdings and its 100% owned finance subsidiary, Summit Midstream Finance Corp. ("Finance Corp.," together with Summit Holdings, the "Co-Issuers") co-issued $300.0 million of 5.50% senior unsecured notes maturing August 15, 2022 (the "5.5% senior notes"). In June 2013, the Co-Issuers co-issued $300.0 million of 7.50% senior unsecured notes maturing July 1, 2021 (the "7.5% senior notes"). The 7.5% senior notes were initially sold in reliance on Rule 144A and Regulation S under the Securities Act. Effective as of April 7, 2014, all of the holders of our 7.5% senior notes exchanged their unregistered 7.5% senior notes and the guarantees of those notes for identical registered notes and guarantees. There were no defaults or events of default during 2014 on either series of senior notes.

SMP Holdings Credit Facility. SMP Holdings had a senior secured revolving credit facility (the "SMP Revolving Credit Facility") and a senior secured term loan (the "Term Loan" and, collectively with the SMP Revolving Credit Facility, the "SMP Holdings Credit Facility") which were used to support the development of the 2016 Drop Down Assets. Borrowings under the SMP Holdings Credit Facility incurred interest at LIBOR or a base rate (as defined in the SMP Holdings Credit Facility) plus an applicable margin. Because the funding was used to support the development of the 2016 Drop Down Assets, Summit Investments allocated the SMP Holdings Credit Facility to us during the years ended December 31, 2015, 2014 and 2013.

On March 3, 2016, the outstanding balances on the SMP Holdings Credit Facility were repaid in full and the SMP Holdings Credit Facility was terminated concurrent with the closing of the 2016 Drop Down (see Note 16).

For additional information on our long-term debt and debt allocated to us, see Notes 9 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 a liability for a deferred purchase price obligation. For additional information on the deferred purchase price obligation, see Note 16 to the unaudited condensed consolidated financial statements.

Cash Flows

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



	Year ended December 31,
	2015			2014			2013

	(In thousands)
Net cash provided by operating activities	$	191,375		$	152,953		$	135,411
Net cash used in investing activities	(646,720		)	(1,384,803		)	(659,041		)
Net cash provided by financing activities	449,327			1,233,877			538,080
Net change in cash and cash equivalents	$	(6,018	)	$	2,027		$	14,450

Operating activities. Cash flows from operating activities increased by $38.4 million for the year ended December 31, 2015 primarily due to distributions from Ohio Gathering and cash received as a result of MVCs. The impact of these cash receipts was largely offset by an increase in interest due to the 5.5% senior notes and other operating activities.

Cash flows from operating activities increased by $17.5 million for the year ended December 31, 2014 largely due to cash received as a result of MVCs.

Investing activities. Cash flows used in investing activities for the year ended December 31, 2015 were related primarily to: (i) the Polar and Divide Drop Down, (ii) the ongoing expansion of compression capacity on the Bison Midstream system, (iii) ongoing expansion of the Summit Utica, Tioga Midstream, Niobrara G&P and Polar and Divide systems, including the Stampede Lateral and (iv) pipeline construction projects to connect new receipt points on the Grand River and Bison Midstream systems.

Cash flows used in investing activities for the year ended December 31, 2014 primarily reflect Summit Investments' investment in Ohio Gathering, the Partnership's acquisition of Red Rock Gathering from a subsidiary of Summit Investments and build out of the Summit Utica, Tioga Midstream, Niobrara G&P and Polar and Divide systems. Additional expenditures for the year ended December 31, 2014 primarily reflect construction of a processing plant on the Grand River system, projects to expand compression capacity on the Bison Midstream system, adding

EX 99.1-26

EXHIBIT 99.1

pipeline on the Mountaineer Midstream system, the February 2014 commissioning of a new natural gas treating facility on the DFW Midstream system and the purchase of the Lonestar assets.

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

Financing activities. Details of cash flows provided by financing activities were as follows:

Net cash used in financing activities for the year ended December 31, 2015 was primarily composed of the following:


•	Net proceeds from an offering of common units in May 2015, which were used to partially fund the Polar and Divide Drop Down;


•	Cash advances to support the buildout of the systems acquired in the 2016 Drop Down;


•	Net borrowings under our revolving credit facility, including $92.5 million to partially fund the Polar and Divide Drop Down; and


•	Distributions declared and paid in 2015.

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


•	Cash advances to fund the acquisition of Ohio Gathering and to support the buildout of the systems acquired in the 2016 Drop Down;


•	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 will be amortized over the life of the notes;


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


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


•	Distributions declared and paid in 2014; and


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

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


•	Distributions declared and paid in 2013;


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


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


•	Payments of $297.2 million on our revolving credit facility, $294.2 million of which was funded by the 7.5% senior notes issuance;


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


•	Cash advances to support the buildout of the Polar and Divide system as well as the systems acquired in the 2016 Drop Down.

EX 99.1-27

EXHIBIT 99.1

Contractual Obligations

The table below summarizes our contractual obligations as of December 31, 2015.



	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years

	(In thousands)
Long-term debt and interest payments (1)	$	1,229,089	$	50,859	$	444,730	$	78,000	$	655,500
Purchase obligations (2)	33,672		32,384		1,188		100		—
Total contractual obligations	$	1,262,761	$	83,243	$	445,918	$	78,100	$	655,500

__________

(1) For the purpose of calculating future interest on the revolving credit facility, assumes no change in balance or rate from December 31, 2015. Includes a 0.50% commitment fee on the unused portion of the revolving credit facility. See Note 9 to the consolidated financial statements for additional information.

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

Operating leases. A substantial majority of the operating leases that support our operations have been entered into by Summit Investments with the associated rent expense allocated to us. Future minimum lease payments associated with operating leases in the Partnership's name are immaterial. See Note 15 to the consolidated financial statements for additional information.

Subsequent events. In March 2016, we borrowed an additional $360.0 million under our revolving credit facility and recognized a liability of $507.4 million for the deferred purchase price obligation, both in connection with the 2016 Drop Down (see Notes 9 and 16 to the consolidated financial statements for additional information). Additional interest expense on the incremental revolving credit facility borrowings will total $8.7 million on an annualized basis with maturity in November 2018, assuming no change in the balance, rate or commitment fee from December 31, 2015. The deferred purchase price obligation is due no later than December 31, 2020 and is currently expected to be $860.3 million based on information available as of March 31, 2016. There are no cash interest payments associated with the deferred purchase price obligation.

Capital Requirements

The table below summarizes our capital expenditures by reportable segment and in total for the years ended December 31.



	Year ended December 31,
	2015		2014		2013

	(In thousands)
Capital expenditures:
Utica Shale	$	94,994	$	24,787	$	—
Williston Basin	147,477		227,283		129,236
Piceance/DJ Basins	21,144		42,417		88,104
Barnett Shale	6,875		14,567		29,534
Marcellus Shale	1,306		33,866		1,822
Total reportable segment capital expenditures	271,796		342,920		248,696
Corporate	429		460		930
Total capital expenditures	$	272,225	$	343,380	$	249,626

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


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

EX 99.1-28

EXHIBIT 99.1


•	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, 2015, SMLP recorded total capital expenditures of $272.2 million, which included $12.7 million of maintenance capital expenditures.

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

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 acquisition strategy 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 estimate the quarterly impact of expected MVC shortfall payments for inclusion in our calculation of adjusted EBITDA. As such, 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. The components of adjustments related to MVC shortfall payments by reportable segment for the year ended December 31, 2015 follow.



	Williston Basin		Piceance/DJ Basins			Barnett Shale			Total

	(In thousands)
Adjustments related to MVC shortfall payments:
Net change in deferred revenue for MVC shortfall payments (1)	$	11,870	$	(21,623	)	$	(1,700	)	$	(11,453	)
Expected MVC shortfall payments (2)	—		33			(482		)	(449		)
Total adjustments related to MVC shortfall payments	$	11,870	$	(21,590	)	$	(2,182	)	$	(11,902	)

__________

(1) See Notes 3 and 8 for additional information on the changes in deferred revenue.

(2) As of December 31, 2015, accounts receivable included $40.2 million of total shortfall payment billings, of which $12.7 million related to shortfall billings associated with MVC arrangements that can be utilized to offset gathering fees in future periods.

For additional information, see Notes 2, 3, 8 and 10 to the consolidated financial statements.

EX 99.1-29

EXHIBIT 99.1

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of or during the year ended December 31, 2015.

Critical Accounting Estimates

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

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

Recognition and Impairment of Long-Lived Assets

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

Property, Plant and Equipment and Amortizing Intangible Assets. As of December 31, 2015, we had net property, plant and equipment with a carrying value of approximately $1.8 billion and net amortizing intangible assets with a carrying value of approximately $461.3 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, including those recognized in 2015 and 2014 are disclosed in Note 4 to the consolidated financial statements, 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.

2014 Impairment Evaluations. We performed our 2014 annual goodwill impairment analysis as of September 30 and concluded that none of our goodwill had been impaired.

During the latter part of the fourth quarter of 2014, the declines in prices for natural gas, NGLs and crude oil accelerated, negatively impacting producers in each of our areas of operation. As a result, we considered whether 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. See Notes 2 and 6 for additional information.

2015 Impairment Evaluations. We performed our 2015 annual goodwill impairment analysis as of September 30 and concluded that none of our goodwill had been impaired.

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

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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 impairment as of December 31, 2014. See Notes 2 and 6 for additional information.

Minimum Volume Commitments

Certain of our gas gathering agreements provide for a monthly, quarterly or annual MVC from our customers. As of December 31, 2015, we had MVCs totaling 1.2 Bcfe/d through 2020.

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 $58.2 million of MVC shortfall payments to customers that did not meet their MVCs during 2015. 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 $39.5 million of gathering revenue due to the credit bank expiration of previous MVC shortfall payments. Of the gathering revenue, $37.1 million is related to the deferred revenue recognition associated with a certain Piceance/DJ Basins customer for which we determined that it would be remote that it could ship volumes in excess of its future MVC as an offset to future gathering fees. As such, the deferred revenue associated with this customer, as reflected on the balance sheet, was recognized as revenue on the income statement.

MVC shortfall payment adjustments in 2015 totaled $(0.4) million and included adjustments related to future anticipated shortfall payments from certain customers in the Piceance/DJ Basins, Williston Basin and Barnett Shale segments. The net impact of our MVC shortfall payment mechanisms increased adjusted EBITDA by $57.7 million in 2015.

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EXHIBIT 99.1

The following table presents the impact of our MVC activity by reportable segment during the year ended December 31, 2015.



	Year ended December 31, 2015
	MVC billings		Gathering revenue		Adjustments to MVC shortfall payments			Net impact to adjusted EBITDA

	(In thousands)
Net change in deferred revenue:
Williston Basin	$	11,897	$	27	$	11,870		$	11,897
Piceance/DJ Basins	15,508		37,131		(21,623		)	15,508
Barnett Shale	677		2,377		(1,700		)	677
Total change in deferred revenue	$	28,082	$	39,535	$	(11,453	)	$	28,082

MVC shortfall payment adjustments:
Piceance/DJ Basins	$	25,704	$	25,704	$	33		$	25,737
Barnett Shale	1,142		1,142		(482		)	660
Marcellus Shale	3,237		3,237		—			3,237
Total MVC shortfall payment adjustments	$	30,083	$	30,083	$	(449	)	$	29,634

Total	$	58,165	$	69,618	$	(11,902	)	$	57,716

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 natural gas 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, 2015, current deferred revenue totaled $0.7 million. Noncurrent deferred revenue totaled $45.5 million at December 31, 2015 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. 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 prior to the quarter in which 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 annual 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.

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.

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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 external 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:


•	fluctuations in natural gas, NGLs and crude oil prices;


•	the extent and success of drilling efforts, as well as the extent and quality 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 non-performance 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 any 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 from the credit and/or capital markets or other sources;


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


•	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;


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


•	weather conditions and seasonal trends;


•	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;


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

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EXHIBIT 99.1


•	the effects of litigation;


•	changes in general economic conditions; and


•	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.

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Summit Midstream Partners (SMLP) 8-K/AFinancial Statements and Exhibits