---

---

---

---

---

---

•	Overview

•	Business Strategies

•	Competitive Strengths

•	Our Midstream Assets

•	Regulation of the Natural Gas and Crude Oil Industries

•	Environmental Matters

•	Other Information

•	the Appalachian Basin, which includes the Marcellus Shale formation in northern West Virginia;

•	the Williston Basin, which includes the Bakken and Three Forks shale formations in northwestern North Dakota;

•	the Fort Worth Basin, which includes the Barnett Shale formation in north-central Texas; and

•	the Piceance Basin, which includes the Mesaverde formation and the Mancos and Niobrara shale formations in western Colorado and eastern Utah.

•	the Mountaineer Midstream system, a natural gas gathering system ("Mountaineer Midstream"), which serves the Appalachian Basin;

•	the Bison Midstream system, an associated natural gas gathering system ("Bison Midstream"), which serves the Williston Basin;

•	the Polar and Divide system, a crude oil and produced water gathering system and recently commissioned transmission pipelines ("Polar and Divide"), which serves the Williston Basin;

•	the DFW Midstream system, a natural gas gathering system ("DFW Midstream"), which serves the Fort Worth Basin; and

---

•	the Grand River system, a natural gas gathering and processing system ("Grand River"), which serves the Piceance Basin.

•	Antero Resources Corp. ("Antero"), the anchor for Mountaineer Midstream;

•	EOG Resources, Inc. ("EOG") and Oasis Petroleum, Inc. ("Oasis"), the anchors for Bison Midstream;

•	Whiting Petroleum Corp. ("Whiting") and SM Energy Company ("SM Energy"), the anchors for Polar and Divide;

•	Chesapeake Energy Corporation ("Chesapeake"), the anchor for DFW Midstream; and

•	Encana Corporation ("Encana") and WPX Energy, Inc. ("WPX"), the anchors for Grand River.

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

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

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

•	the Piceance Basin, which is served by Grand River.

---

•	Summit Investments conveyed an interest in Summit Midstream Holdings, LLC ("Summit Holdings") to our general partner as a capital contribution;

•	our general partner conveyed its interest in Summit Holdings to SMLP in exchange for a continuation of its 2% general partner interest in SMLP and the incentive distribution rights ("IDRs");

•	Summit Investments conveyed its remaining interest in Summit Holdings to SMLP in exchange for (i) 10,029,850 common units, (ii) 24,409,850 subordinated units, and (iii) the right to receive cash reimbursement for certain capital expenditures made with respect to the contributed assets; and

•	SMLP issued 14,375,000 common units to the public.

---

•	six-and-one-half (6.5) multiplied by the average adjusted EBITDA, as defined in the Contribution Agreement, of the 2016 Drop Down Assets for 2018 and 2019;

•	less the Initial Payment;

•	less all capital expenditures incurred for the 2016 Drop Down Assets between the Initial Close and December 31, 2019;

•	plus all adjusted EBITDA from the 2016 Drop Down Assets between the Initial Close and December 31, 2019.

---

•

Maintaining our focus on fee-based revenue with minimal direct commodity price exposure. As we expand our business, we intend to maintain our focus on providing midstream energy services under fee-based arrangements. Our midstream services are provided under primarily long-term and fee-based contracts with original terms of up to 25 years. Currently, all of the contracts associated with assets owned and being developed by Summit Investments are fee based. We believe that our focus on fee-based revenues with minimal direct commodity exposure is essential to maintaining stable cash flows.

•

Capitalizing on organic growth opportunities to maximize throughput on our existing systems. We intend to continue to leverage our management team's expertise in constructing, developing and optimizing our midstream assets to grow our business through organic development projects. We believe that our broad and geographically diverse operating footprint provides us with a competitive advantage to pursue organic development projects that are designed to extend our geographic reach, diversify our customer

---

•

Diversifying our asset base by expanding our midstream service offerings to new geographic areas. Our gathering operations in the Marcellus, Bakken, Three Forks and Barnett shale plays and the Piceance Basin currently represent our core business. We intend to diversify our operations into other geographic regions, as a result of the 2016 Drop Down and through both greenfield development projects and acquisitions from third parties.

•

Partnering with producers to provide midstream services for their development projects in high-growth, unconventional resource plays. We seek to promote commercial relationships with established and well-capitalized producers that are willing to serve as anchor customers and commit to long-term MVCs and AMIs. We will continue to pursue partnership opportunities with established producers to develop new midstream energy infrastructure in unconventional resource basins that we believe will complement our existing assets and/or enhance our overall business by facilitating our entry into new basins. These opportunities generally consist of a strategic acreage position in an unconventional resource play that is well-positioned for accelerated production but has limited existing midstream energy infrastructure to support such growth.

•

Strategically located assets in core areas of prolific unconventional resource basins supported by partnerships with large producers. We believe our assets are strategically positioned within the core areas of four established unconventional resource basins. The geologic formations in the basins served by our assets have either relatively low drilling and completion costs, highly economic production profiles, or a combination of both which incent producers to develop more actively than in more marginal areas.

•	Fee-based revenues underpinned by long-term contracts with AMIs and MVCs. A substantial majority of our revenue for the year ended December 31, 2015 was generated under long-term and fee-based gathering and processing agreements. We believe that long-term, fee-based gathering and processing agreements enhance the stability of our cash flows by limiting our direct commodity price exposure.

•

Capital structure and financial flexibility. At December 31, 2015, we had $944.0 million of total indebtedness and the unused portion of our $700.0 million amended and restated senior secured revolving credit facility (the "revolving credit facility") totaled $356.0 million. Under the terms of our revolving credit facility, our total leverage ratio (total net indebtedness to consolidated trailing 12-month EBITDA, as defined in the credit agreement) was approximately 4.2 to 1.0 at December 31, 2015, which compares with a total leverage ratio upper limit of not more than 5.0 to 1.0, or not more than 5.5 to 1.0 for up to 270 days following certain acquisitions (as defined in the credit agreement). Additionally, the total leverage ratio upper limit can be increased from 5.0 to 1.0 to 5.5 to 1.0 at our option, subject to the inclusion of a senior secured leverage ratio (senior secured net indebtedness to consolidated trailing 12-month EBITDA, as defined in the credit agreement) upper limit of 3.75 to 1.0.

•

Relationship with a large and committed financial sponsor. Our Sponsor, Energy Capital Partners, is an experienced energy investor with a proven track record of making substantial, long-term investments in high-quality energy assets. In addition to its direct investment in Summit Investments, Energy Capital Partners began purchasing our common units in open market transactions beginning in December 2015. We believe that the relationship with and support of our Sponsor is a competitive advantage as it brings not only significant financial and management experience, but also numerous relationships throughout the energy industry that we believe will continue to benefit us as we seek to grow our business.

•

Experienced management team with a proven record of asset acquisition, construction, development, operations and integration expertise. Our board members and senior leadership team have extensive energy experience (see Item 10. Directors, Executive Officers and Corporate Governance—Directors and Executive Officers) and a proven track record of identifying, consummating and integrating significant acquisitions in addition to partnering with major producers to construct and develop midstream energy infrastructure.

---

•	Mountaineer Midstream in northern West Virginia;

•	Bison Midstream in northwestern North Dakota;

•	Polar and Divide in northwestern North Dakota;

•	DFW Midstream in north-central Texas; and

•	Grand River in western Colorado and eastern Utah.

---

---

---

---

---

---

•	perform ongoing assessments of pipeline integrity;

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

•	maintain processes for data collection, integration and analysis;

•	repair and remediate pipelines as necessary;

•	adopt and maintain procedures, standards and training programs for control room operations; and

•	implement preventive and mitigating actions.

•	requiring the installation of pollution-control equipment or otherwise restricting the way we operate;

•	limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;

•	delaying system modification or upgrades during permit reviews;

•	requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and

---

•	enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations.

---

---

---

•	the volumes we gather, treat and process;

•	the level of production of natural gas and crude oil (and associated volumes of produced water) from wells connected to our gathering systems, which is dependent in part on the demand for, and the market prices of, crude oil, natural gas and NGLs;

•	damage to pipelines, facilities, related equipment and surrounding properties caused by earthquakes, floods, fires, severe weather, explosions and other natural disasters, accidents and acts of terrorism;

•	leaks or accidental releases of hazardous materials into the environment;

•	weather conditions and seasonal trends;

•	changes in the fees we charge for our services;

•	the level of competition from other midstream energy companies in our areas of operation;

•	changes in the level of our operating, maintenance and general and administrative expenses;

•	regulatory action affecting the supply of, or demand for, crude oil, natural gas and NGLs, the fees we can charge, how we contract for services, our existing contracts, our operating and maintenance costs or our operating flexibility; and

•	prevailing economic and market conditions.

•	the level and timing of capital expenditures we make;

•	the level of our operating, maintenance and general and administrative expenses, including reimbursements of expenses incurred on our behalf by our general partner;

•	the cost of acquisitions, if any;

---

•	our debt service requirements and other liabilities;

•	fluctuations in our working capital needs;

•	our ability to borrow funds and access capital markets;

•	restrictions contained in our debt agreements;

•	the amount of cash reserves established by our general partner;

•	not receiving anticipated shortfall payments from our customers; and

•	other business risks affecting our cash levels.

---

•	the availability and cost of capital;

•	prevailing and projected commodity prices, including the prices of crude oil, natural gas and other hydrocarbon products, including NGLs;

•	demand for crude oil, natural gas and other hydrocarbon products, including NGLs;

•	levels of reserves;

•	geological considerations;

•	environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

•	the availability of drilling rigs and other costs of production and equipment.

•	worldwide economic and geopolitical conditions;

•	weather conditions and seasonal trends;

•	the levels of domestic production and consumer demand;

•	the availability of imported liquefied natural gas ("LNG");

•	the ability to export LNG;

---

•	the availability of transportation systems with adequate capacity;

•	the volatility and uncertainty of regional pricing differentials and premiums;

•	the price and availability of alternative fuels;

•	the effect of energy conservation measures;

•	the nature and extent of governmental regulation and taxation; and

•	the anticipated future prices of crude oil, natural gas and other hydrocarbon products, including NGLs.

---

•	the level of existing and new competition to provide gathering and/or processing services in our areas of operation;

•	the macroeconomic factors affecting gathering, treating and processing economics for our current and potential customers;

•	the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;

•	the extent to which the customers in our areas of operation are willing to contract on a long-term basis; and

•	the effects of federal, state or local regulations on the contracting practices of our customers.

---

•	unscheduled turnarounds or catastrophic events at our physical plants or pipeline facilities;

•	restrictions imposed by governmental authorities or court proceedings;

•	labor difficulties that result in a work stoppage or slowdown;

•	a disruption in the supply of resources necessary to operate our midstream facilities;

•	damage to our facilities resulting from production volumes that do not comply with applicable specifications; and

•	inadequate transportation or market access to support production volumes, including lack of pipeline, rail terminals, produced water disposal facilities and/or third-party processing capacity.

---

•	damage to pipelines, processing plants, compression assets, related equipment and surrounding properties caused by tornadoes, floods, fires and other natural disasters and acts of terrorism;

•	inadvertent damage from construction, vehicles, farm and utility equipment;

•	leaks or losses resulting from the malfunction of equipment or facilities;

•	ruptures, fires and explosions; and

•	other hazards that could also result in personal injury and loss of life, pollution and suspension of operations.

---

•	mistaken assumptions about volumes, revenue and costs, including synergies and potential growth;

•	an inability to secure adequate customer commitments to use the acquired systems or facilities;

•	the risk that natural gas or crude oil reserves expected to support the acquired assets may not be of the anticipated magnitude or may not be developed as anticipated;

•	an inability to successfully integrate the assets or businesses we acquire;

•	coordinating geographically disparate organizations, systems and facilities;

•	the assumption of unknown liabilities for which we are not indemnified or for which our indemnity is inadequate;

•	mistaken assumptions about the overall costs of debt or equity capital;

•	the diversion of management's and employees' attention from other business concerns;

•	unforeseen difficulties operating in new geographic areas and business lines;

•	customer or key employee losses at the acquired businesses;

•	production declines higher than anticipated; and

•	facilities being properly constructed.

---

---

•	limiting our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes and/or obtaining such financing on favorable terms;

•	reducing our funds available for operations, future business opportunities and cash distributions to unitholders by that portion of our cash flow required to make interest payments on our debt;

•	increasing our vulnerability to competitive pressures or a downturn in our business or the economy generally; and

•	limiting our flexibility in responding to changing business and economic conditions.

•	incur or guarantee certain additional debt;

•	make certain cash distributions on or redeem or repurchase certain units;

•	make certain investments and acquisitions;

•	make certain capital expenditures;

•	incur certain liens or permit them to exist;

•	enter into certain types of transactions with affiliates;

•	merge or consolidate with another company or otherwise engage in a change of control transaction; and

•	transfer, sell or otherwise dispose of certain assets.

---

---

---

•	perform ongoing assessments of pipeline integrity;

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

•	maintain processes for data collection, integration and analysis;

---

•	repair and remediate pipelines as necessary;

•	adopt and maintain procedures, standards and training programs for control room operations; and

•	implement preventive and mitigating actions.

---

---

---

•

Neither our partnership agreement nor any other agreement requires Summit Investments or its owners to pursue a business strategy that favors us, and the directors and officers of Summit Investments have a fiduciary duty to make these decisions in the best interests of the owners of Summit Investments, which may be contrary to our interests. Summit Investments may choose to shift the focus of their investment and growth to areas not served by our assets.

•	Summit Investments is not limited in its ability to compete with us and may offer business opportunities or sell midstream assets to third parties without first offering us the right to bid for them.

•	Our general partner is allowed to take into account the interests of parties other than us, such as Summit Investments and its owners, in resolving conflicts of interest.

•

Our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner to us and our unitholders with contractual standards governing its duties to us and our unitholders. These contractual standards limit our general partner's liabilities and the rights of our unitholders with respect to actions that, without the limitations, might constitute breaches of fiduciary duty.

•	Except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval.

•	Our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership interests and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders.

•

Our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of the subordinated units to convert to common units.

•	Our general partner determines which costs incurred by it are reimbursable by us.

•	Our general partner may cause us to borrow funds to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distribution payments.

•	Our partnership agreement permits us to classify up to $50.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our common units or to our general partner in respect of the general partner interest or the IDRs.

•	Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf.

•	Our general partner intends to limit its liability regarding our contractual and other obligations.

•	Our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units.

---

•	Our general partner controls the enforcement of the obligations that it and its affiliates owe to us.

•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

•	Our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's IDRs without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our other unitholders in certain situations.

---

•	our quarterly distributions;

•	our quarterly or annual earnings or those of other companies in our industry;

•	the loss of a large customer;

•	announcements by our customers or others regarding our customers or changes in our customers’ credit ratings, liquidity position, leverage profile and/or other financial or credit-related metrics;

•	announcements by our competitors of significant contracts or acquisitions;

•	changes in accounting standards, policies, guidance, interpretations or principles;

•	general economic and geopolitical conditions;

•	the failure of securities analysts to cover our common units or changes in financial estimates by analysts;

•	future sales of our common units, including those held by Summit Investments and its subsidiaries; and

•	other factors described in these Risk Factors.

---

•	how to allocate corporate opportunities among us and its affiliates;

•	whether to exercise its limited call right;

•	whether to seek approval of the resolution of a conflict of interest by the conflicts committee of the board of directors of our general partner;

•	how to exercise its voting rights with respect to the units it owns;

•	whether to exercise its registration rights;

•	whether to elect to reset target distribution levels;

•	whether to transfer the IDRs or any units it owns to a third party; and

•	whether or not to consent to any merger or consolidation of the partnership or amendment to the partnership agreement.

•

whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith, meaning that it subjectively believed that the decision was in our best interests, and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

•	our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as such decisions are made in good faith;

•

our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or their assignees resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, acted in bad faith or engaged in fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

•	our general partner will not be in breach of its obligations under the partnership agreement or its duties to us or our unitholders if a transaction with an affiliate or the resolution of a conflict of interest is:

i.	approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval;

ii.	approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner and its affiliates;

iii.	on terms no less favorable to us than those generally being provided to or available from unrelated third parties; or

iv.	fair and reasonable to us, taking into account the totality of the relationships among the parties involved, including other transactions that may be particularly favorable or advantageous to us.

---

---

---

•	our existing unitholders' proportionate ownership interest in us will decrease;

•	the amount of cash available for distribution on each unit may decrease;

•	because the amount payable to holders of IDRs is based on a percentage of the total cash available for distribution, the distributions to holders of IDRs will increase even if the per-unit distribution on common units remains the same;

•	the ratio of taxable income to distributions may increase;

•	the relative voting strength of each previously outstanding unit may be diminished; and

•	the market price of the common units may decline.

---

•	we were conducting business in a state but had not complied with that particular state's partnership statute; or

•	an investor's right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute control of our business.

---

---

---

---

---

---

•	Our cash distribution policy is subject to restrictions on distributions under our amended and restated revolving credit facility. Our amended and restated revolving credit facility contains financial tests and covenants that we must satisfy. Should we be unable to satisfy these restrictions, we may be prohibited from making cash distributions notwithstanding our stated cash distribution policy.

•

Our general partner has the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment or increase of those cash reserves could result in a reduction in cash distributions to you from the levels we currently anticipate pursuant to our stated distribution policy. Any determination to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

---

•

Although our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to distribute all of our available cash, may be amended. Following the subordination period, which ended on February 16, 2016, we can amend our partnership agreement with the consent of our general partner and the approval of a majority of the outstanding common units (including common units beneficially owned by Summit Investments). As of December 31, 2015, Summit Investments, which is the ultimate owner of our general partner, beneficially owned 5,444,731 common units and all of our 24,409,850 subordinated units, which converted to common units on a one-for-one basis on February 16, 2016. In addition, in connection with the Purchase Program, a subsidiary of Energy Capital Partners owned 2,184,186 common units as of February 16, 2016.

•	Even if our cash distribution policy is not modified or revoked, the amount of distributions we pay under our cash distribution policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement.

•	Under Delaware law, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

•

We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our cash available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase.

•	If and to the extent our cash available for distribution materially declines, we may elect to reduce our quarterly distribution rate to service or repay our debt or fund expansion capital expenditures.

---

---

---

---

•	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

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

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

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

•	the Piceance Basin, which is served by Grand River.

---

---

•	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.

---

---

•	the Marcellus Shale;

•	the Williston Basin;

•	the Barnett Shale; and

•	the Piceance Basin.

•	throughput volume,

•	revenues,

•	operation and maintenance expenses,

•	EBITDA,

•	adjusted EBITDA and segment adjusted EBITDA, and

•	distributable cash flow.

---

•	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.

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

---

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

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

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

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

•	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.

•	The consolidated financial statements reflect the results of operations of Bison Midstream and Polar and Divide since February 16, 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 Polar and Divide system commenced operations in May 2013.

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

---

---

•	the recognition in 2015 of previously deferred revenue at Grand River (see Note 7 to the consolidated financial statements).

•	an increase in gathering services and related fees for the Polar and Divide and Mountaineer 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.

•	overall growth at Red Rock Gathering 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.

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

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

•	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.

---

•	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.

•	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.

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

---

•	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.

•	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.

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

---

•	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.

---

•	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.

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

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

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

•	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.

---

•	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.

•	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.

---

---

•	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 anchor customer.

•	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.

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

•	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.

---

•	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.

---

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

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

•

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

•

The impact of purchase price adjustments reflects certain balances previously recognized in connection with the Predecessor's purchase accounting for the Legacy Grand River system that we wrote off during the fourth quarter of 2014. This write off was recognized in other income. See "Results of Operations—Piceance Basin" and Note 15 to the 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 8 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 15 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.

---

---

---

---

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

---

•	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.

•	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 $294.2 million on our revolving credit facility, all 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.

---

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

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

---

---

---

•	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.

---

•	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;

•	the effects of litigation;

•	changes in general economic conditions; and

•	certain factors discussed elsewhere in this report.

---

---

---

---

---

---

---

---

---

---

---

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

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

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

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

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

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

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

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

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

---

---

---

•	Level 1. Inputs represent quoted prices in active markets for identical assets or liabilities;

•

Level 2. Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly (for example, quoted market prices for similar assets or liabilities in active markets or quoted market prices for identical assets or liabilities in markets not considered to be active, inputs other than quoted prices that are observable for the asset or liability, or market-corroborated inputs); and

•	Level 3. Inputs that are not observable from objective sources, such as management’s internally developed assumptions used in pricing an asset or liability (for example, an internally developed present value of future cash flows model that underlies management's fair value measurement).

---

•	Fee-based arrangements. Under fee-based arrangements, we receive a fee or fees for one or more of the following services (i) natural gas gathering, treating, and/or processing and (ii) crude oil and/or produced water gathering.

•

Percent-of-proceeds arrangements. Under percent-of-proceeds arrangements, we generally purchase natural gas from producers at the wellhead, or other receipt points, gather the wellhead natural gas through our gathering system, treat the natural gas, process the natural gas and/or sell the natural gas to a third party for processing. We then remit to our producers an agreed-upon percentage of the actual proceeds received from sales of the residue natural gas and NGLs. Certain of these arrangements may also result in returning all or a portion of the residue natural gas and/or the NGLs to the producer, in lieu of returning sales proceeds. The margins earned are directly related to the volume of natural gas that flows through the system and the price at which we are able to sell the residue natural gas and NGLs.

---

---

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

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

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

•	the Piceance Basin, which is served by Grand River.

---

---

---

•	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 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.

---

---

---

---

---

•

To the extent that a customer's throughput volumes are less than its MVC for the applicable period and the customer makes a shortfall payment, it may be entitled to an offset in one or more subsequent periods to the extent that its throughput volumes in subsequent periods exceed its MVC for those periods. In such a situation, we would not receive gathering fees on throughput in excess of that customer's MVC (depending on the terms of the specific gas gathering agreement) to the extent that the customer had made a shortfall payment with respect to one or more preceding measurement periods (as applicable).

•

To the extent that a customer's throughput volumes exceed its MVC in the applicable contracted measurement period, it may be entitled to apply the excess throughput against its aggregate MVC, thereby reducing the period for which its annual MVC applies. As a result of this mechanism, the weighted-average remaining period for which our MVCs apply will be less than the weighted-average of the original stated contract terms of our MVCs.

•

To the extent that certain of our customers' throughput volumes exceed its MVC for the applicable period, there is a crediting mechanism that allows the customer to build a bank of credits that it can utilize in the future to reduce shortfall payments owed in subsequent periods, subject to expiration if there is no shortfall in subsequent periods. The period over which this credit bank can be applied to future shortfall payments varies, depending on the particular gas gathering agreement.

---

---

---

---

---

---

•	Polar and Divide for the period from February 16, 2013 to May 18, 2015;

•	Red Rock Gathering for the period from January 1, 2013 to March 18, 2014; and

•	Bison Midstream for the period from February 16, 2013 to June 4, 2013.

---

---

•	less the amount of cash reserves established by our general partner at the date of determination of available cash for that quarter to:

•	provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements);

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

•

provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions unless it determines that the establishment of reserves will not prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

•	plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

---

---

---

---

•	certain support expenses and capital expenditures on behalf of the contributed subsidiaries. These transactions were settled periodically through membership interests prior to the respective drop down;

•	interest expense that was related to capital projects for the contributed subsidiaries. As such, the associated interest expense was allocated to the respective contributed subsidiary's capital projects as a noncash contribution and capitalized into the basis of the asset; and

•	SMP Net Profits Interests accounted for as compensatory awards. As such, the annual expense associated with the SMP Net Profits was allocated to the respective contributed subsidiary and is reflected in general and administrative expenses in the statement of operations.

---

---

---

---

•	six-and-one-half (6.5) multiplied by the average adjusted EBITDA, as defined in the Contribution Agreement, of the 2016 Drop Down Assets for 2018 and 2019;

•	less the Initial Payment;

•	less all capital expenditures incurred for the 2016 Drop Down Assets between the Initial Close and December 31, 2019;

•	plus all adjusted EBITDA from the 2016 Drop Down Assets between the Initial Close and December 31, 2019.

•	The acquisition of the Bison Gas Gathering system and Mountaineer Midstream occurred on January 1, 2012. The pro forma results for Bison Midstream and Mountaineer Midstream were derived from revenues and net income in 2013.

---

•	Pro forma net income for the year ended December 31, 2013 has been adjusted to remove the impact of $2.5 million of nonrecurring transaction costs associated with the acquisitions of Bison Midstream and Mountaineer Midstream.

•	Pro forma adjustments in 2013 also reflect the impact of 4,661,547 common unit issuance and the general partner capital contribution to maintain its 2% general partner interest to fund the acquisition of Bison Midstream and Mountaineer Midstream.

•

Pro forma adjustments in 2013 also reflect the impact of $310.0 million of incremental borrowings on our revolving credit facility for the Bison Midstream and Mountaineer Midstream acquisitions and incremental depreciation and amortization expense associated with the acquired property, plant and equipment and contract intangibles as a result of the application of fair value accounting for Bison Midstream.

•	Pro forma adjustments for Polar and Divide are not required because the system was not in service prior to common control beginning in February 2013.

•	The acquisition of the Lonestar assets is immaterial for pro forma purposes and as such has not been reflected below.

---

---

---

---

---

---

•	transactions with affiliates;

•	entering into any hedging transactions that are not in compliance with Financial Accounting Standard 133;

•	the voluntary liquidation, wind-up or dissolution of us or any of our subsidiaries;

•	making any election that would result in us being classified as other than a partnership or a disregarded entity for U.S. federal income tax purposes;

•	filing or consenting to the filing of any bankruptcy, insolvency or reorganization petition for relief from debtors or protection from creditors naming us or any of our subsidiaries; and

•	effecting a material amendment to our general partner's limited liability company agreement.

---

---

---

---

---

•	Leonard W. Mallett, Executive Vice President and Chief Operations Officer (Mr. Mallett's employment commenced on December 1, 2015)

•	Rene L. Casadaban, former Senior Vice President and Chief Operating Officer (Mr. Casadaban's employment terminated on September 30, 2015)

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

---

•	an annual cash retainer of $70,000, and

•	an annual award of common units with a grant date fair value of approximately $80,000.

•	the chairman of the Audit Committee receives an additional annual retainer of $15,000;

---

•	the chairman of the Conflicts Committee receives an additional annual retainer of $10,000;

•	each independent member of any committee (other than the chairman) received an additional annual retainer of $5,000; and

•

in connection with the Polar and Divide Drop Down, in May 2015, we paid the members, other than the chairman, of the Conflicts Committee fees of $10,000 and the chairman of the Conflicts Committee fees of $15,000 each for the increased time and effort that they expended in connection with their service on the Conflicts Committee, which reviewed the transaction for fairness to the Partnership and its unitholders.

•	each person who is known to us to beneficially own 5% or more of such units to be outstanding (based solely on Schedules 13D and 13G filed with the SEC subsequent to December 31, 2015 and prior to February 17, 2016);

•	our general partner;

•	each of the directors and NEOs of our general partner; and

---

•	all of the directors and NEOs of our general partner as a group.

---

---

---

---

---

•	should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•	have been qualified by disclosures that were made to the other party in connection with the negotiation of the applicable agreement, which disclosures are not necessarily reflected in the agreement;

•	may apply standards of materiality in a way that is different from what may be viewed as material by others; and

•	were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement and are subject to more recent developments.

---

---

---

---