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

•	Item 8. Financial Statements and Supplementary Data.

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•	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 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.

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•	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.

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•	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.

•	throughput volume,

•	revenues,

•	operation and maintenance expenses,

•	EBITDA,

•	adjusted EBITDA and segment adjusted EBITDA, and

•	distributable cash flow.

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•	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;

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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.

•	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.

•	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 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.

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•	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.

•	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.

•	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.

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•	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.

•	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.

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•	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.

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•	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.

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•	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

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•	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.

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•	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.

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•	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.

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•	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.

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•	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.

•	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.

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•	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.

•	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.

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

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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.

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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.

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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.

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•	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.

•	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.

•	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.

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•	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

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•	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.

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•	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.

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•	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;

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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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•	the effects of litigation;

•	changes in general economic conditions; and

•	certain factors discussed elsewhere in this report.

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

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

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

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

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

•	Niobrara Gathering and Processing ("Niobrara G&P"), an associated natural gas gathering and processing system operating in the Denver-Julesburg ("DJ") Basin, which includes the Niobrara shale formation in northeastern Colorado;

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

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

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

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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.

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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.

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•	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; and

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

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•	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.

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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).

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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.

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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.

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(i)	increased the borrowing capacity from $150.0 million to $250.0 million;

(ii)	extended the maturity date from March 2018 to February 2019;

(iii)	added a $100.0 million revolving credit facility accordion feature and a $400.0 million term loan accordion;

(iv)	reduced the leverage-based pricing grid by 0.75% from a range of 2.75% to 3.75% to a new range of 2.00% to 3.00% for LIBOR borrowings and from a range of 1.75% to 2.75% to a new range of 1.00% to 2.00% for alternate base rate borrowings;

(v)	changed the commitment fee from 0.50% to a leverage-based range of 0.30% to 0.50%; and

(vi)	increased the maximum total leverage ratio from 4.0 to 1.0 to 5.0 to 1.0 and from not more than 5.0 to 1.0 to 5.5 to 1.0 for up to 270 days following certain acquisitions, or material projects or, at its option, after a qualified notes offering (as defined in the SMP Holdings Credit Facility).

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•	the 2016 Drop Down Assets for the period from February 16, 2013 to March 3, 2016;

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

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•	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.

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•	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

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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.

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•	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.

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•	six-and-one-half (6.5) multiplied by the average Business Adjusted EBITDA, as defined below and in the Contribution Agreement, of the 2016 Drop Down Assets for 2018 and 2019, less the G&A Adjuster, as defined in the Contribution Agreement;

•	less the Initial Payment;

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

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•	plus all Business Adjusted EBITDA from the 2016 Drop Down Assets between Initial Close and December 31, 2019, less the Cumulative G&A Adjuster, as defined in the Contribution Agreement.

•	plus interest expense, income tax expense, and depreciation and amortization of the 2016 Drop Down Assets for such period;

•	plus any adjustments related to MVC shortfall payments, impairments and other noncash expenses or losses with respect to the 2016 Drop Down Assets for such period;

•	plus any Special Liability Expenses, as defined below and in the Contribution Agreement, for such period;

•	less interest income and income tax benefit of the 2016 Drop Down Assets for such period;

•	less adjustments related to any other noncash income or gains with respect to the 2016 Drop Down Assets for such period.

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•	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 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.

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Pro forma adjustments 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.

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Pro forma adjustments (other than an adjustment for interest expense as discussed below) for the 2016 Drop Down Assets are not required because the assets were not in service prior to common control beginning in February 2013. Interest expense was assumed based on the impact of $360.0 million of incremental borrowings on our revolving credit facility, partially offset by the pro forma derecognition of interest expense allocated to the 2016 Drop Down Assets from Summit Investments (see Note 9).

•	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.

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