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•	fluctuations in natural gas, natural gas liquids ("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 and crude oil 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;

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our ability to acquire any assets owned by Summit Midstream Partners, LLC ("Summit Investments"), which is subject to a number of factors, including Summit Investments deciding, in its sole discretion, to offer us the right to acquire such assets, the ability to reach agreement on acceptable terms, the approval of the conflicts committee of our general partner's board of directors (if appropriate), 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;

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

•	the effects of litigation;

•	changes in general economic conditions; and

•	certain factors discussed elsewhere in this report.

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•	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;

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

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

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

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

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

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

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

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

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•	determination of the weighted-average cost of capital;

•	the selection of guideline public companies;

•	market multiples;

•	weighting of the income and market approaches;

•	growth rates;

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•	commodity prices; and

•	the expected levels of throughput volume gathered.

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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 and

•	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.

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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

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

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

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

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

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

•	Acquisitions from Summit Investments and third parties;

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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; and

•	Shifts in operating costs and inflation.

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

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

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

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

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

•	throughput volume,

•	revenues,

•	operation and maintenance expenses,

•	EBITDA,

•	adjusted EBITDA and segment adjusted EBITDA, and

•	distributable cash flow.

•	successful drilling activity within our areas of mutual interest;

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

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

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

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

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

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Natural gas, NGLs and condensate sales. Revenue earned from (i) the sale of physical natural gas and natural gas liquids purchased from our customers under percentage-of-proceeds and keep-whole arrangements with certain of our customers on the Bison Midstream and Red Rock gathering systems, (ii) the sale of natural gas we retain from our DFW Midstream customers and (iii) the sale of condensate we retain from our gathering services at Grand River.

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

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•	542 MMcf/d for the three months ended June 30, 2015, compared with 366 MMcf/d in the prior-year period and

•	545 MMcf/d for the six months ended June 30, 2015, compared with 326 MMcf/d in the prior-year period.

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

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the benefit of higher volume throughput was partially offset by a decline in compression services, which resulted from a shift in volume throughput mix to a larger percentage of previously compressed natural gas entering our gathering lines. As a result of this shift in volume throughput mix, the proportion of high-pressure gathering services increased, which, due to its lower rate relative to compression fees, negatively impacted gathering services and related fees as well as the average throughput rate per Mcf.

•	minimum revenue commitment payments related to the recently completed Zinnia Loop project, 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 decline in general and administrative expenses primarily as a result of our decision to discontinue allocating certain corporate general and administrative expenses beginning in the first quarter of 2015.

•	17 MMcf/d for the three months ended June 30, 2015, compared with 15 MMcf/d in the prior-year period and

•	18 MMcf/d for the six months ended June 30, 2015, compared with 14 MMcf/d in the prior-year period.

•	$2.48/Mcf during the three months ended June 30, 2015, compared with $3.71/Mcf in the prior-year period and

•	$2.64/Mcf during the six months ended June 30, 2015, compared with $4.09/Mcf in the prior-year period.

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

•	the previously mentioned decision to discontinue certain corporate general and administrative expense allocations.

•	a decrease in operation and maintenance expenses reflecting the impact of a decline in contract services and the first quarter 2014 water hydrate remediation effort.

•	54.3 Bbl/d for the three months ended June 30, 2015, compared with 30.1 Bbl/d in the prior-year period and

•	51.2 Bbl/d for the six months ended June 30, 2015, compared with 26.9 Bbl/d in the prior-year period.

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•	$1.79/Bbl during the three months ended June 30, 2015, compared with $1.72/Bbl in the prior-year period and

•	$1.79/Bbl during the six months ended June 30, 2015, compared with $1.54/Bbl in the prior-year period.

•	the impact of higher volume throughput on gathering services and related fees.

•	higher gathering rates associated with contract amendments in 2014.

•	an increase in operation and maintenance expenses largely as a result of system buildout.

•	the previously mentioned decision to discontinue certain corporate general and administrative expense allocations.

•	356 MMcf/d during the three months ended June 30, 2015, compared with 350 MMcf/d in the prior-year period and

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•	379 MMcf/d during the six months ended June 30, 2015, compared with 349 MMcf/d in the prior-year period.

•	$0.67/Mcf during the three months ended June 30, 2015, compared with $0.62/Mcf in the prior-year period and

•	$0.63/Mcf during the six months ended June 30, 2015, compared with $0.60/Mcf in the prior-year period.

•	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.

•	for the three-month period, an increase in gathering services and related fees due to increased rates.

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•	for the six-month period, an increase in gathering services and related fees due to increased rates and higher volumes in the first quarter of 2015.

•	a decline in operation and maintenance expense primarily due to lower electricity expense. 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.

•	a decline in third-party natural gas treating expenses for the six-month period, which we recognize in operation and maintenance. In February 2014, we commissioned a new 150 gallon per minute natural gas treating facility which allowed us to provide treating services to our customers rather than having to contract with a third-party service provider for such services.

•	adjustments due to the expiration of deferred revenue credits in April 2015.

•	the previously mentioned decision to discontinue certain corporate general and administrative expense allocations.

•	604 MMcf/d during the three months ended June 30, 2015, compared with 672 MMcf/d during the prior-year period and

•	610 MMcf/d during the six months ended June 30, 2015, compared with 667 MMcf/d during the prior-year period.

•	$0.41/Mcf during the three months ended June 30, 2015, compared with $0.40/Mcf during the prior-year period and

•	$0.42/Mcf during the six months ended June 30, 2015, compared with $0.39/Mcf during prior-year period.

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•	lower gathering services revenue from our anchor customer.

•	the previously mentioned decision to discontinue certain corporate general and administrative expense allocations.

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

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

•	a decline in operation and maintenance due to lower property taxes, partially offset by an increase in compressor parts.

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•	the previously mentioned decision to discontinue certain corporate general and administrative expense allocations.

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

•	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 due to lower property taxes.

•	lower gathering services revenue from our anchor customer.

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•	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 unaudited condensed 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.

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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.

•	Senior notes interest represents the net of interest expense accrued and paid during the period. See "Liquidity and Capital Resources—Long-Term Debt" and Note 7 to the consolidated financial statements included in the 2014 Annual Report.

•	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 Polar Midstream, Epping and Red Rock Gathering for the periods beginning with the date that common control began and ending on the date that the respective drop down closed. See Notes 1 and 15 to the unaudited condensed consolidated financial statements and Note 15 to the consolidated financial statements included in the 2014 Annual Report.

•	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;

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

•	Distributions declared in respect of both the first quarter of 2015 (paid in the second quarter of 2015) and fourth quarter of 2014 (paid in the first quarter of 2015).

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

•	Net borrowings of $140.0 million under our revolving credit facility, including $100.0 million to partially fund the Red Rock Drop Down; and

•	Distributions declared in respect of the first quarter of 2014 (paid in the second quarter of 2014) and fourth quarter of 2013 (paid in the first quarter of 2014).

•	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.

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•	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, whether as a result of human error or otherwise;

•	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;

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

•	other business risks affecting our cash levels.

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•	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 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.

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•	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.

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•	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 wells and/or third-party processing capacity.

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•	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.

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•	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.

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•	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.

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•	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;

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

•	implement preventive and mitigating actions.

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•

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.

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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.

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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.

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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 a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period, which is expected to end in February 2016 assuming we continue to have earned and paid at least $1.60 on each outstanding limited partner unit and the corresponding distribution on our general partner's 2.0% interest for each of the three consecutive, non-overlapping four-quarter periods ending on December 31, 2015.

•	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 subordinated 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.

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•	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 competitors of significant contracts or acquisitions;

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

•	general economic 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.

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•	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.

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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;

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•	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;

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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.

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

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

•	because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution will be borne by our common unitholders will increase;

•	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

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•	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.

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