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•	Part I, Item 1A - Risk Factors

•	Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations

•	Part II, Item 8 - Financial Statements and Supplementary Data

•	Part II, Item 9A - Controls and Procedures

•	Part IV, Item 15 - Exhibits, Financial Statement Schedules

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•	the prices of crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

•	energy prices generally;

•	the general level of crude oil, natural gas, and natural gas liquids production;

•	the general level of demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

•	the availability of supply of crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

•	the level of crude oil and natural gas drilling and production in producing areas where we have water treatment and disposal facilities;

•	the prices of propane and distillates relative to the prices of alternative and competing fuels;

•	the price of gasoline relative to the price of corn, which impacts the price of ethanol;

•	the ability to obtain adequate supplies of products if an interruption in supply or transportation occurs and the availability of capacity to transport products to market areas;

•	actions taken by foreign oil and gas producing nations;

•	the political and economic stability of foreign oil and gas producing nations;

•	the effect of weather conditions on supply and demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel;

•	the effect of natural disasters, lightning strikes, or other significant weather events;

•	the availability of local, intrastate and interstate transportation infrastructure with respect to our truck, railcar, and barge transportation services;

•	the availability, price, and marketing of competing fuels;

•	the impact of energy conservation efforts on product demand;

•	energy efficiencies and technological trends;

•	governmental regulation and taxation;

•	the impact of legislative and regulatory actions on hydraulic fracturing, waste water disposal and on the treatment of flowback and produced water;

•	hazards or operating risks related to transporting and distributing petroleum products that may not be fully covered by insurance;

•	the maturity of the crude oil, natural gas liquids, and refined products industries and competition from other marketers;

•	loss of key personnel;

•	the ability to renew contracts with key customers;

•	the ability to maintain or increase the margins we realize for our terminal, barging, trucking, water disposal, recycling, and discharge services;

•	the ability to renew leases for our leased equipment and storage facilities;

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•	the nonpayment or nonperformance by our counterparties;

•	the availability and cost of capital and our ability to access certain capital sources;

•	a deterioration of the credit and capital markets;

•	the ability to successfully identify and consummate strategic acquisitions, and integrate acquired assets and businesses;

•	changes in the volume of hydrocarbons recovered during the wastewater treatment process;

•	changes in the financial condition and results of operations of entities in which we own noncontrolling equity interests;

•	changes in applicable laws and regulations, including tax, environmental, transportation and employment regulations, or new interpretations by regulatory agencies concerning such laws and regulations and the impact of such laws and regulations (now existing or in the future) on our business operations;

•	the costs and effects of legal and administrative proceedings;

•	any reduction or the elimination of the federal Renewable Fuel Standard; and

•	changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our pipeline assets.

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Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals and pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests in two crude oil pipelines. Our crude oil logistics segment purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

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Our water solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities. Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck washouts. In addition, our water solutions segment sells the recycled water and recovered hydrocarbons that result from performing these services.

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Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling and storage services through its 19 owned terminals throughout the United States, its salt dome storage facility in Utah, and its leased storage and railcar transportation services through its fleet of leased railcars.

•	Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia.

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Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We purchase refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedule them for delivery at various locations. See “Dispositions ” below for a discussion of our interests in TransMontaigne Partners L.P. (“TLP”).

•	In October 2011, we completed a business combination with E. Osterman Propane, Inc., its affiliated companies, and members of the Osterman family (collectively, “Osterman”), whereby we acquired retail propane operations in the northeastern United States.

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•	In November 2011, we completed a business combination with SemStream, L.P. (“SemStream”), whereby we acquired SemStream’s wholesale natural gas liquids supply and marketing operations and its 12 natural gas liquids terminals.

•	In January 2012, we completed a business combination with seven companies associated with Pacer Propane Holding, L.P. (collectively, “Pacer”), whereby we acquired retail propane operations, primarily in the western United States.

•	In February 2012, we completed a business combination with North American Propane, Inc., whereby we acquired retail propane and distillate operations in the northeastern United States.

•	In May 2012, we acquired the retail propane and distillate operations of Downeast Energy Corp. These operations are primarily in the northeastern United States.

•	In June 2012, we completed a business combination with High Sierra Energy, LP and High Sierra Energy GP, LLC (collectively, “High Sierra”), whereby we acquired all of the ownership interests in High Sierra. High Sierra’s businesses include crude oil gathering, transportation and marketing; water treatment, disposal, and transportation; and natural gas liquids transportation and marketing.

•	In November 2012, we completed a business combination whereby we acquired Pecos Gathering & Marketing, L.L.C. and certain of its affiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texas and New Mexico.

•	In December 2012, we completed a business combination whereby we acquired all of the membership interests in Third Coast Towing, LLC (“Third Coast”). The business of Third Coast consists primarily of transporting crude oil via barge.

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In July 2013, we completed a business combination whereby we acquired the operating assets of Crescent Terminals, LLC, which operates a leased crude oil storage and dock facility in Port Aransas, Texas, and the ownership interests in Cierra Marine, LP and its affiliated companies (collectively, “Crescent”), whereby we acquired a fleet of four towboats and seven crude oil barges operating in the intercoastal waterways of Texas.

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In July 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd., whereby we acquired a water treatment and disposal facility in the Permian Basin in Texas. We also entered into a development agreement that requires us to purchase water solutions facilities developed by the other party to the agreement. During March 2014, we purchased one additional facility under this development agreement.

•	In August 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively, “OWL”). The businesses of OWL include four water treatment and disposal facilities in the Eagle Ford shale play in Texas.

•	In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), whereby we acquired the ownership interests in three water treatment and disposal facilities in the Eagle Ford shale play in Texas, and the option to acquire an additional facility, which we exercised in March 2014.

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In December 2013, we acquired the ownership interests in Gavilon, LLC (“Gavilon Energy”). The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas and Louisiana, a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma and became operational in February 2014, and an interest in an ethanol production facility in the Midwest. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids, and also include crude oil storage in Cushing, Oklahoma.

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In July 2014, we acquired TransMontaigne Inc. (“TransMontaigne”). As part of this transaction, we also purchased inventory from the previous owner of TransMontaigne. The operations of TransMontaigne include the marketing of refined products. As part of this transaction, we acquired the 2% general partner interest, the incentive distribution rights, a 19.7% limited partner interest in TLP, and assumed certain terminaling service

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•	In November 2014, we acquired two saltwater disposal facilities in the Bakken shale play in North Dakota.

•	In February 2015, we acquired Sawtooth NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility.

•	During the year ended March 31, 2015, we purchased 16 water treatment and disposal facilities under the development agreement discussed above.

•	During the year ended March 31, 2015, we acquired eight retail propane businesses.

•	In August 2015, we acquired four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the Delaware Basin of the Permian Basin in Texas.

•	In January 2016, we acquired a 57.125% interest in an existing produced water pipeline company operating in the Delaware Basin portion of West Texas.

•	During the year ended March 31, 2016, we purchased 15 water treatment and disposal facilities under the development agreement discussed above.

•	During the year ended March 31, 2016, we acquired six retail propane businesses.

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Focus on building a vertically integrated midstream master limited partnership providing multiple services to customers. We continue to enhance our ability to transport crude oil from the wellhead to refiners, refined products from refiners to customers, wastewater from the wellhead to treatment for disposal, recycle, or discharge, and natural gas liquids from processing plants to end users, including retail propane customers.

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Achieve organic growth by investing in new assets that increase volumes, enhance our operations, and generate attractive rates of return. We believe that there are accretive organic growth opportunities that originate from assets we own and operate. We have and expect to continue to invest within our existing businesses, particularly within our crude oil logistics, water solutions, and refined products businesses as we grow these businesses with highly accretive, fee-based organic growth opportunities.

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Deliver accretive growth through strategic acquisitions that complement our existing business model and expand our operations. We intend to continue to pursue acquisitions that build upon our vertically integrated business model, add scale to our current operating platforms, and enhance our geographic diversity in our businesses. We have established a successful track record of acquiring companies and assets at attractive prices and we continue to evaluate acquisition opportunities in order to capitalize on this strategy in the future.

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Focus on consistent annual cash flows by adding operations that minimize commodity price risk and generate fee-based, cost-plus, or margin-based revenues under multi-year contracts. We intend to focus on long-term fee-based contracts in addition to back-to-back contracts which minimize commodity price exposure. We continue to increase cash flows that are supported by certain fee-based, multi-year contracts, some of which include acreage dedications from producers or volume commitments. We also believe that expanding our retail propane business with an emphasis on a high level of residential customers with company-owned tanks will result in strong customer retention rates and consistent operating margins.

•	Maintain a disciplined capital structure characterized by low leverage. We target leverage levels that are consistent with those of investment grade companies. Through our disciplined approach to leverage, we expect to maintain sufficient liquidity to manage existing and future capital requirements and to take advantage of market opportunities.

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Maintain a disciplined cash distribution policy that complements our leverage, acquisition and organic growth strategies. We intend to use cash flows from our operations to make distributions to our unitholders and to use excess cash flows to finance organic growth and opportunistically repay indebtedness, including amounts outstanding under our Revolving Credit Facility (as hereinafter defined). We believe this strategy positions us to pursue future acquisitions and to execute upon our organic growth initiatives.

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Our vertically integrated and diversified operations, which help us generate more predictable and stable cash flows on a year-to-year basis. Our ability to provide multiple services to customers in numerous geographic areas enhances our competitive position. Our five businesses units are diversified by geography, customer-base and commodity sensitivities which we believe proves us with the ability to maintain cash flows throughout typical commodity cycles. By examples, our retail propane business sources propane through our liquids business which allows us to leverage the expertise of our liquids business to help improve our margins and profitability and enhance our cash flows. Furthermore, we believe that our liquids business provides us with valuable market intelligence that helps us identify potential acquisition opportunities. Our refined products and retail propane businesses benefit from lower energy prices driving increased customer demand, which can offset the downward pressure on our crude logistics and water businesses in a low price environment.

•	Our network of crude oil transportation assets, which allows us to serve customers over a wide geographic area and optimize sales. Our strategically deployed railcar fleet, towboats, barges, and trucks, and our owned and

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Our water processing facilities, which are strategically located near areas of high crude oil and natural gas production. Our water processing facilities are located among the most prolific crude oil and natural gas producing areas in the United States, including the Permian Basin, the DJ Basin, the Eagle Ford shale play, the Bakken shale play, and the Pinedale Anticline. In addition, we believe that the technological capabilities of our water solutions business can be quickly implemented at new facilities and locations.

•	Our network of natural gas liquids transportation, terminal, and storage assets, which allow us to provide multiple services over the continental United States. Our strategically located terminals, large railcar fleet, shipper status on common carrier pipelines, and substantial leased and owned underground storage enable us to be a preferred purchaser and seller of natural gas liquids.

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Our high percentage of retail sales to residential customers, who are generally more stable purchasers of propane and distillates and generate higher margins than other customers. Our high percentage of propane tank ownership, payment billing systems, and automatic delivery program have resulted in a strong record of customer retention and help us better predict our cash flows in the retail propane business.

•	Our access to refined products pipeline and terminal infrastructure. Our capacity allocations on third-party pipelines and our access to TLP’s refined products terminals give us the opportunity to serve customers over a large geographic area.

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Our seasoned management team with extensive midstream industry experience and a track record of acquiring, integrating, operating and growing successful businesses. Our management team has significant experience managing companies in the energy industry, including master limited partnerships. In addition, through decades of experience, our management team has developed strong business relationships with key industry participants throughout the United States. We believe that our management’s knowledge of the industry, relationships within the industry, and experience in identifying, evaluating and completing acquisitions provides us with opportunities to grow through strategic and accretive acquisitions that complement or expand our existing operations.

•	200 owned trucks and 270 owned trailers operating primarily in the Mid-Continent, Permian Basin, Eagle Ford shale play, and Rocky Mountain regions;

•	400 owned railcars and 600 leased railcars operating primarily in Colorado, New Mexico, North Dakota, Oklahoma, Wyoming, and West Texas; and

•	11 owned towboats and 24 owned barges operating primarily in the intercoastal waterways of the Gulf Coast and along the Mississippi and Arkansas river systems.

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•	price;

•	availability of supply;

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•	reliability of service;

•	logistics capabilities, including the availability of railcars, proprietary terminals, and owned pipelines, barges, railcars, trucks, and towboats;

•	long-term customer relationships; and

•	the acquisition of businesses.

•	we require certain customers to prepay or place deposits for our services;

•	we require certain customers to post letters of credit or other forms of surety on a portion of our receivables;

•	we review receivable aging analyses regularly to identify issues or trends that may develop; and

•	we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid invoices.

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(1)	This facility has a design capacity of 60,000 barrels per day to process water to a recycle standard which also includes a design capacity of 15,000 barrels per day to process water to a discharge standard.

(2)	Reflects the total processing capacity of facilities located on land we own at this location, which includes two facilities that have a combined design capacity of 20,000 barrels per day to process water to a recycle standard.

(3)	Certain facilities can dispose of both wastewater and solids such as tank bottoms and drilling fluids. We own a 50% interest in the disposal of solids.

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•	we require certain customers to prepay or place deposits for our services;

•	we require certain customers to post letters of credit or other forms of surety on a portion of our receivables;

•	we review receivable aging analyses regularly to identify issues or trends that may develop; and

•	we require our marketing personnel to manage their customers’ receivable position and suspend service to customers that have not timely paid invoices.

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(1)	We own a terminal in Superior, Montana with throughput of 120,000 gallons per day that we are currently subleasing through October 2017 with an option to extend or to purchase.

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•	price;

•	availability of supply;

•	reliability of service;

•	available space on common carrier pipelines;

•	storage availability;

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•	logistics capabilities, including the availability of railcars, and proprietary terminals;

•	long-term customer relationships; and

•	the acquisition of businesses.

•	customer pre-buys, which typically require deposits based on market pricing conditions;

•	market based, which can either be a posted price or an index to spot price at time of delivery; and

•	load package, a firm price agreement for customers seeking to purchase specific volumes delivered during a specific time period.

•	we require certain customers to prepay or place deposits for their purchases;

•	we require certain customers to post letters of credit or other forms of surety on a portion of our receivables;

•	we require certain customers to take delivery of their contracted volume ratably to help control the account balance rather than allowing them to take delivery of propane at their discretion;

•	we review receivable aging analyses regularly to identify issues or trends that may develop; and

•	we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid invoices.

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•	400 bulk storage tanks with capacities ranging from 2,000 to 90,000 gallons; and

•	over 300,000 stationary customer storage tanks with capacities ranging from 7 to 30,000 gallons.

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•	71% residential customers;

•	28% commercial and industrial customers; and

•	1% agricultural customers.

•	price;

•	availability of supply;

•	reliability of service;

•	long-term customer relationships; and

•	the acquisition of businesses.

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•	customers are billed on a timely basis;

•	customers tend to keep accounts receivable balances current when paying a local business and people they know;

•	many customers prefer the convenience of paying in person; and

•	billing issues may be handled more quickly because local personnel have current account information and detailed customer history available to them at all times to answer customer inquiries.

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•	price;

•	availability of supply;

•	reliability of service;

•	available space on common carrier pipelines;

•	storage availability;

•	logistics capabilities, including the availability of railcars, and proprietary terminals; and

•	long-term customer relationships.

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•	we require certain customers to prepay or place deposits for our services;

•	we require certain customers to post letters of credit or other forms of surety on a portion of our receivables;

•	we monitor individual customer receivables relative to previously-approved credit limits, and our automated rack delivery system gives us the option to discontinue providing product to customers when they exceed their credit limits;

•	we review receivable aging analyses regularly to identify issues or trends that may develop; and

•	we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid invoices.

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•	requiring the installation of pollution-control equipment or otherwise restricting the way we operate or imposing additional costs on our operations;

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

•	delaying construction or system modification or upgrades during permit issuance or renewal;

•	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.

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•	weather conditions in our operating areas;

•	the cost of crude oil, natural gas liquids, refined products, ethanol, and biodiesel that we buy for resale and whether we are able to pass along cost increases to our customers;

•	the volume of wastewater delivered to our processing facilities;

•	disruptions in the availability of crude oil and/or natural gas liquids supply;

•	our ability to renew leases for storage and railcars;

•	the effectiveness of our commodity price hedging strategy;

•	the level of competition from other energy providers; and

•	prevailing economic conditions.

•	the level of capital expenditures we make;

•	the cost of acquisitions, if any;

•	restrictions contained in our credit agreement (the “Credit Agreement”), the purchase agreement governing our outstanding 6.65% senior secured notes due 2022 (the “Note Purchase Agreement”), the indentures governing our outstanding 6.875% senior notes due 2021 and 5.125% senior notes due 2019 (collectively, the “Indentures”) and other debt service requirements;

•	fluctuations in working capital needs;

•	our ability to borrow funds and access capital markets;

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

•	other business risks discussed in this Annual Report that may affect our cash levels.

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•	increased competition for attractive acquisitions;

•	covenants in our Credit Agreement, Note Purchase Agreement and Indentures that limit the amount and types of indebtedness that we may incur to finance acquisitions and which may adversely affect our ability to make distributions to our unitholders;

•	lack of available cash or external capital or limitations on our ability to issue equity to pay for acquisitions; and

•	possible unwillingness of prospective sellers to accept our common units as consideration and the potential dilutive effect to our existing unitholders caused by an issuance of common units in an acquisition.

•	the inability to successfully integrate the operations of recently acquired businesses;

•	the assumption of known or unknown liabilities, including environmental liabilities;

•	limitations on rights to indemnity from the seller;

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

•	unforeseen difficulties operating in new geographic areas or in new business segments;

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

•	customer or key employee loss from the acquired businesses; and

•	a potential significant increase in our indebtedness and related interest expense.

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•	our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;

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

•	we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and

•	our flexibility in responding to changing business and economic conditions may be limited.

•	incur additional debt or issue letters of credit;

•	redeem or repurchase units;

•	make certain loans, investments and acquisitions;

•	incur certain liens or permit them to exist;

•	engage in sale and leaseback transactions;

•	enter into certain types of transactions with affiliates;

•	enter into agreements limiting subsidiary distributions;

•	change the nature of our business or enter into a substantially different business;

•	merge or consolidate with another company; and

•	transfer or otherwise dispose of assets.

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•	a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel;

•	higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;

•	an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;

•	an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products; and

•	the increased use of alternative fuel sources, such as battery-powered engines.

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limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;

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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the partnership;

•	provides that our general partner shall not have any liability to us or our unitholders for decisions made in its capacity as general partner so long as it acted in good faith, meaning our general partner subjectively believed that the decision was in, or not opposed to, the best interests of the partnership;

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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee and not involving a vote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the

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•	provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

•	our general partner is allowed to take into account the interests of parties other than us, such as members of the NGL Energy GP Investor Group, in resolving conflicts of interest;

•	neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us;

•	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 securities 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;

•	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 distributions;

•	our partnership agreement permits us to classify up to $20.0 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 to our general partner in respect of the general partner interest or the incentive distribution rights (“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;

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•	our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

•	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 common unitholders in certain situations.

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

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

•	the ratio of taxable income to distributions may increase;

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•	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

•	a unitholder’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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Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

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(1)	The acquisitions of businesses affect the comparability of this information.

(2)	On February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting.

(3)	Certain balance sheet data at March 31, 2015 was adjusted to reflect the final acquisition accounting for certain business combinations (see Note 2 to our consolidated financial statements included in this Annual Report).

(4)	Revised to reclassify debt issuance costs for our senior notes from intangible assets to long-term debt obligations for all balance sheet dates presented (see Note 2 to our consolidated financial statements included in this Annual Report).

(5)	Includes intercompany volumes sold to our retail propane segment.

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•	Crude Oil Logistics

•	Water Solutions

•	Liquids

•	Retail Propane

•	Refined Products and Renewables

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(1)	Prices are for the four months ended March 31, 2014 as we acquired Gavilon, LLC (“Gavilon Energy”) on December 2, 2013.

(1)	Prices are for the four months ended March 31, 2014 as we acquired Gavilon Energy on December 2, 2013.

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(1)

Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 11 to our consolidated financial statements included in this Annual Report on Form 10-K (“Annual Report”). Amounts reported in the table above include expense accruals for bonuses expected to be paid in common units, whereas the amounts reported in Note 11 to our consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.

(2)

During the years ended March 31, 2016, 2015 and 2014, we recorded $2.0 million, $7.4 million and $6.9 million, respectively, of expense related to legal and advisory costs associated with acquisitions. During the year ended March 31, 2015, we recorded $15.8 million of compensation expense associated with acquisitions (including certain bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon the successful completion of the sale of the business, and compensation expense related to termination benefits for certain TransMontaigne Inc. (“TransMontaigne”) employees). During the year ended March 31, 2014, we recorded $8.2 million of compensation expense associated with acquisitions (including certain bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon the successful completion of the sale of the business).

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(3)	Amount represents the non-cash valuation adjustment of contingent consideration liabilities, offset by the cash payments, related to royalty agreements acquired as part of acquisitions in our Water Solutions segment. Amount includes $3.0 million and $0.3 million for the years ended March 31, 2016 and 2015, respectively, related to the portion attributatble to noncontrolling interests.

(1)	Includes ten months of consolidated TLP interest expense.

(2)	Includes two months of TLP interest expense as an equity method investment.

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(1)	During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to the categories shown in the table above. These changes did not impact total revenues. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2)	Revenues include $9.7 million and $29.8 million of intersegment sales during the years ended March 31, 2016 and 2015, respectively, that are eliminated in our consolidated statements of operations.

(3)

In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to executing these commitments, the producers requested to be released from the commitments. We agreed to release the producers from their commitments in return for a cash payment in March 2015 and additional cash payments over the next five years. Upon execution of these agreements in March 2015, we recorded a gain of $31.6 million to other income in our consolidated statement of operations, net of certain project abandonment costs. Since this gain was reported in other income, it is not reflected in the table above.

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(1)	Includes realized and unrealized (gains) losses.

•	facilities we owned before March 31, 2014, which we refer to below as “existing facilities”; and

•	facilities we acquired or developed after March 31, 2014, which we refer to below as “recently acquired or developed facilities”.

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(1)	During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to railcar cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2)	Revenues include $80.6 million and $162.0 million of intersegment sales during the years ended March 31, 2016 and 2015, respectively, that are eliminated in our consolidated statements of operations.

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(1)	During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues and cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

(2)	Revenues include $0.9 million and $1.1 million of intersegment sales during the years ended March 31, 2016, and 2015, respectively, that are eliminated in our consolidated statement of operations.

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(1)	Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party and to a loan receivable from an equity method investee.

(2)	Represents another party’s share of the profits generated from a joint crude oil marketing arrangement.

(3)

In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to executing these commitments, the producers requested to be released from the commitments. We agreed to release the producers from their commitments in return for a cash payment in March 2015 and additional cash payments over the next five years. In addition, one of the producers committed to pay us a specified fee on each barrel

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(4)

During the year ended March 31, 2015, we settled two separate contractual disputes and recorded $5.5 million of proceeds to other income. Also during the year ended March 31, 2015, we offered to settle another contractual dispute, and recorded $1.2 million to other expense as an estimate of the probable loss. During the year ended March 31, 2016, we finalized the settlement of this contractual dispute and paid approximately $0.5 million at the date of settlement and committed to pay approximately $1.1 million in equal annual installments over a period of 11 years beginning on October 15, 2016 and ending in October 2026.

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(1)	Revenues include $29.8 million and $37.8 million of intersegment sales during the years ended March 31, 2015 and 2014, respectively, that are eliminated in our consolidated statements of operations.

(2)

In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to executing these commitments, the producers requested to be released from the commitments. We agreed to release the producers from their commitments in return for a cash payment in March 2015 and additional cash payments over the next five years. Upon execution of these agreements in March 2015, we recorded a gain of $31.6 million to other income in our consolidated statement of operations, net of certain project abandonment costs. Since this gain was reported in other income, it is not reflected in the table above.

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(1)	Includes realized and unrealized (gains) losses.

•	facilities we owned before March 31, 2013, which we refer to below as “existing facilities”; and

•	facilities we acquired or developed after March 31, 2013, which we refer to below as “recently acquired or developed facilities”.

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(1)	Revenues include $162.0 million and $245.6 million of intersegment sales during the years ended March 31, 2015 and 2014, respectively, that are eliminated in our consolidated statements of operations.

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(1)	Revenues include $1.1 million of intersegment sales during the year ended March 31, 2015 that are eliminated in our consolidated statement of operations.

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(1)	Operating income of our compressor leasing business during the year ended March 31, 2014 includes a $4.4 million gain from the sale of the business in February 2014.

(2)	We acquired the natural gas business in our December 2013 acquisition of Gavilon Energy. We subsequently wound down the natural gas business and, as of March 31, 2014, this business has no revenue-generating activity.

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(1)	Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party and to a loan receivable from an equity method investee.

(2)	Represents another party’s share of the profits generated from a joint crude oil marketing arrangement.

(3)

In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to executing these commitments, the producers requested to be released from the commitments. We agreed to release the producers from their commitments in return for a cash payment in March 2015 and additional cash payments over the next five years. In addition, one of the producers committed to pay us a specified fee on each barrel of crude oil it produces in a specified basin over a period of seven years. Upon execution of these agreements in March 2015, we recorded a gain of $31.6 million to other income, net of certain project abandonment costs.

(4)	During the year ended March 31, 2015, we settled two separate contractual disputes and recorded $5.5 million of proceeds to other income. Also during the year ended March 31, 2015, we offered to settle another contractual dispute, and recorded $1.2 million to other expense as an estimate of the probable loss.

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(1)	Includes expansion capital expenditures for TLP of $13.6 million and $3.7 million during the years ended March 31, 2016 and 2015, respectively.

(2)	Includes maintenance capital expenditures for TLP of $11.6 million and $9.8 million during the years ended March 31, 2016 and 2015, respectively.

•	a $726.3 million decrease in cash paid for acquisitions during the year ended March 31, 2016 as cash paid for acquisitions during the year ended March 31, 2015 included $580.7 million for the acquisition of TransMontaigne;

•	a $343.1 million increase due to proceeds received from the sale of the general partner interest in TLP during the year ended March 31, 2016;

•	a $310.0 million decrease for the purchase of the remaining equity interest in Grand Mesa during the year ended March 31, 2015;

•	a $59.6 million decrease related to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party; and

•	a $24.2 million decrease for the purchase of certain refined product pipeline capacity allocations from other shippers during the year ended March 31, 2015.

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•

an increase in capital expenditures from $203.8 million during the year ended March 31, 2015, $163.0 million of which was expansion capital (of this expansion capital, $3.7 million related to TLP) and $40.8 million of which was maintenance capital (of this maintenance capital, $9.8 million related to TLP), to $536.9 million during the year ended March 31, 2016, $494.9 million of which was expansion capital (of this expansion capital, $13.6 million related to TLP) and $42.0 million of which was maintenance capital (of this maintenance capital, $11.6 million related to TLP);

•	a $125.0 million increase due to the purchase of a 37.5% undivided interest in a crude oil pipeline from Colorado to Oklahoma (see “Recent Developments” above) during the year ended March 31, 2016; and

•	a $93.5 million decrease in cash flows from derivatives.

•	a $307.9 million decrease in cash paid for acquisitions during the year ended March 31, 2015; and

•	a $235.1 million increase in cash flows from derivatives.

•	a $310.0 million increase for the purchase of the remaining equity interest in Grand Mesa during the year ended March 31, 2015;

•	a $61.9 million increase related to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party;

•

an increase in capital expenditures from $165.1 million during the year ended March 31, 2014, $132.9 million of which was expansion capital and $32.2 million of which was maintenance capital, to $203.8 million during the year ended March 31, 2015, $163.0 million of which was expansion capital (of this expansion capital, $3.7 million related to TLP) and $40.8 million of which was maintenance capital (of this maintenance capital, $9.8 million related to TLP);

•	a $24.2 million increase for the purchase of certain refined product pipeline capacity allocations from other shippers during the year ended March 31, 2015; and

•	a $22.0 million increase in contributions to unconsolidated entities during the year ended March 31, 2015 due primarily to our investment in BOSTCO which we acquired as part of our July 2014 acquisition of TransMontaigne.

•	$541.1 million in proceeds received from the sale of our common units during the year ended March 31, 2015;

•	$400.0 million in proceeds received from the issuance of the 2019 Notes during the year ended March 31, 2015;

•	an $88.0 million increase in distributions paid to our partners and noncontrolling interest owners during the year ended March 31, 2016; and

•	$43.4 million in repurchases of a portion of our senior notes during the fourth quarter of fiscal year 2016.

•	a $123.8 million increase in distributions paid to our partners and noncontrolling interest owners during the year ended March 31, 2015;

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•	a $109.0 million decrease in the proceeds received from the sale of our common units during the year ended March 31, 2015 as more of our common units were issued during the year ended March 31, 2014 to fund acquisitions; and

•	a $50.0 million decrease in the proceeds received from debt issuances during the years ended March 31, 2015 and 2014.

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(1)	The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at March 31, 2016. See Note 8 to our consolidated financial statements included in this Annual Report for additional information on our Credit Agreement.

(2)	We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity.

(3)	At March 31, 2016, we had the following construction commitments:

•	As discussed above, in November 2015, we reached an agreement with Saddlehorn to jointly construct, own and operate the Joint Pipeline. At March 31, 2016, our share of the remaining total construction costs for the Joint Pipeline is approximately $39 million. We expect the Joint Pipeline to be operational beginning in the third quarter of fiscal year 2017.

•	As part of the Joint Pipeline project, we will have some assets connected to the Joint Pipeline. At March 31, 2016, the remaining costs for these assets are approximately $80.6 million. We expect these assets to be completed during the third quarter of fiscal year 2017.

•	In February 2015, we acquired Sawtooth, which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage

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•	experience in business, government, education, technology or public interests;

•	high-level managerial experience in large organizations;

•	breadth of knowledge regarding our business and industry;

•	specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law;

•	moral character and integrity;

•	commitment to our unitholders’ interests;

•	ability to provide insights and practical wisdom based on experience and expertise;

•	ability to read and understand financial statements; and

•	ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on partnership matters.

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•	retain and terminate our independent registered public accounting firm;

•	approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm; and

•	establish policies and procedures for the pre-approval of all non-audit services and tax services to be rendered by our independent registered public accounting firm.

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•	establishing the general partner’s compensation philosophy and objectives;

•	approving the compensation of the Chief Executive Officer;

•	making recommendations to the board of directors with respect to the compensation of other officers and directors; and

•	reviewing and making recommendations to the board of directors with respect to incentive compensation and equity-based plans.

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•	H. Michael Krimbill–Chief Executive Officer

•	Robert W. Karlovich III–Chief Financial Officer (effective February 22, 2016)

•	James J. Burke–President

•	Shawn W. Coady–President and Chief Operating Officer, Retail Division

•	Vincent J. Osterman–President, Eastern Retail Propane Operations

•	Atanas H. Atanasov–Chief Financial Officer and Treasurer (resigned effective February 5, 2016)

•	Attract and retain individuals with the background and skills necessary to successfully execute our business strategies;

•	Motivate those individuals to reach short-term and long-term goals in a way that aligns their interests with the interests of our unitholders; and

•	Reward success in reaching those goals.

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•	Entered into an agreement with Saddlehorn Pipeline Company, LLC to combine pipeline projects to transport crude oil from Weld County, Colorado to Cushing Oklahoma, of which we will own a 37.5% undivided interest in the pipeline; and

•	We sold our general partner interest in TLP for $350 million.

•	We paid no cash bonuses to our named executive officers during fiscal year 2016.

•	The salaries of most of our named executive officers remain below the median of our benchmark peer group. This enables us to grant more performance-based compensation to maintain competitive total compensation packages.

•	We introduced a new performance-based restricted unit program for which no payout will be made unless the return on our common units exceeds the median returns for a specified peer group over specified periods of time.

•	Majority of officer pay is at risk incentive compensation based on annual financial performance and growth in unitholder value;

•	Equity-based incentives are the largest single component of officer compensation;

•	Certain of the officers’ equity awards are subject to achievement of above-median total unitholder return relative to our performance peer group;

•	No excise tax gross-ups; and

•	Compensation committee engages an independent compensation adviser.

•	Role of Management: Our Chief Executive Officer also provides periodic recommendations to the compensation committee and the board of directors regarding the compensation of our other named executive officers.

•

Role of the Compensation Committee’s Consultant: In carrying out its responsibilities for establishing, implementing and monitoring the effectiveness of our executive compensation philosophy, plans and programs, our compensation committee has the authority to engage outside experts to assist in its deliberations. During fiscal year 2016, the compensation committee received compensation advice and data from Pearl Meyer & Partners (“PM&P”). PM&P conducted a competitive review of the principal components of compensation for our executives, including our named executive officers. PM&P also provided input on peer group selection (compensation and performance peers), and short and long-term incentive plan design. The compensation committee reviewed the services provided by PM&P and determined that they are independent in providing executive compensation consulting services. In making this determination, the compensation committee noted that during fiscal year 2016:

◦	PM&P did not provide any services to the Partnership or management other than compensation consulting services requested by or with the approval of the compensation committee;

◦	PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or human resource outsourcing;

◦	PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and procedures designed to ensure independence;

◦	Fees paid to PM&P by the Partnership during fiscal year 2016 were less than 1% of PM&P’s total revenue;

◦	None of the PM&P consultants working on Partnership matters had any business or personal relationship with compensation committee members;

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◦	None of the PM&P consultants working on Partnership matters (or any consultants at PM&P) had any business or personal relationship with any executive officer of the Partnership; and

◦	None of the PM&P consultants working on Partnership matters own Partnership interests.

•

Mr. Krimbill’s initial base salary of $120,000 was originally determined as part of the negotiations for our formation transactions. In setting the base salaries, the parties considered various factors, including the compensation needed to attract or retain the officers, the historical compensation of the officers, and each officer’s expected individual contribution to our performance. At the request of Mr. Krimbill, the parties agreed that he should receive a lower base salary than our other executive officers at the time because, as our Chief Executive Officer, a significant portion of his compensation should be performance-based, to further align his interests with the interests of our unitholders. In February 2012, the base salary of Mr. Krimbill was reduced to $60,000, based on our operating and financial performance as a result of an unusually warm winter. The base salary of Mr. Krimbill was restored to $120,000 effective November 12, 2012. Effective July 1, 2014, the Board of

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•	Mr. Karlovich’s base salary of $400,000 was negotiated prior to his joining our management team in February 2016.

•

Mr. Burke’s base salary of $353,000 became effective on June 19, 2012 when Mr. Burke joined our management team upon completion of our merger with High Sierra. Mr. Burke’s base salary was increased to $375,000 in July 2013 and to $384,000 in June 2014. Mr. Burke was given a lower salary increase than the other named executive officers, based on the fact that his salary is higher relative to the benchmark peer group than the other named executive officers (his current salary is close to the 50th percentile of the peer group).

•

Dr. Coady’s base salary of $300,000 was determined as part of the negotiations for our formation transactions. In February 2012, the base salary of Dr. Coady was reduced to $200,000 based on our operating and financial performance as a result of an unusually warm winter. The base salary of Dr. Coady was restored to $300,000 effective November 12, 2012. Dr. Coady’s base salary was increased to $315,000 in July 2014, in consideration of the fact that his salary was low relative to the benchmark peer group.

•	Mr. Osterman’s initial base salary of $125,000 was negotiated at the time Mr. Osterman joined our management team upon completion of our acquisition of Osterman Propane. Mr. Osterman’s salary was increased to $200,000 in January 2013 and to $250,000 in July 2013, in consideration of the fact that his salary was low relative to the benchmark peer group.

•	Mr. Atanasov’s base salary of $195,000 was negotiated prior to his joining our management team in November 2011. The base salary of Mr. Atanasov was increased to $250,000 in July 2013 and to $300,000 in July 2014, in consideration of the fact that his salary was low relative to the benchmark peer group.

(1)	Mr. Krimbill was granted 213,573 Service Awards on April 23, 2015.

(2)	Mr. Karlovich was granted 75,000 Service Awards on February 22, 2016.

(3)	Mr. Burke, Dr. Coady and Mr. Osterman were each granted 10,000 Service Awards on July 1, 2015 and 15,000 Service Awards on February 18, 2016.

(4)	Mr. Atanasov was granted 8,333 Service Awards on July 1, 2015 and forfeited all outstanding Service Awards upon his resignation from employment.

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•	Compensation surveys including data from published compensation surveys representative of other energy industry and broader general industry companies with revenues of between $1 billion and $6 billion; and

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•	Peer group data including pay data from 10-K and proxy filings for a group of 20 publicly traded midstream oil & gas partnerships of similar size and scope to us.

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(1)	Amounts for fiscal year 2014 include discretionary bonuses paid in fiscal year 2014 based on contributions of the individuals since the time they joined the Partnership through the date of the bonus and based on expectations of future performance.

(2)

The fair values of the restricted units shown in the table above were calculated based on the closing market prices of our common units on the grant dates, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution prior to the grant date and assumptions that a market participant might make about future distribution growth. This calculation of fair value is consistent with the provisions of Accounting Standards Codification 718 Stock Compensation. The following table summarizes these amounts:

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(3)

The amounts in this column include matching contributions to our 401(k) plan. Amounts for Mr. Burke include a club membership and a car allowance. Amounts for Dr. Coady include the incremental cost of the use of a company car, including depreciation, maintenance, insurance, and fuel. Amounts for Mr. Osterman include propane provided to him and to members of his family (valued for this purpose at the cost of the propane to NGL). The following table summarizes these amounts:

(4)	Mr. Burke joined our management team upon completion of our merger with High Sierra on June 19, 2012.

(5)	Mr. Osterman was not a named executive officer prior to fiscal year 2015.

(6)	Mr. Atanasov resigned as Chief Financial Officer effective February 5, 2016.

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(1)

Amounts reported in the (a) “Threshold” column reflect the threshold number of Performance Awards (at 50% of target) that may be earned (assuming a relative TUR at the 50th percentile), (b) “Target” column reflect the target number of performance awards, or 100%, that may be earned (assuming a relative TUR at the 75th percentile) and (c) “Maximum” column reflect 200% of the target performance awards that may be earned (assuming a relative TUR greater than the 90th percentile). The number of common units actually received by a named executive officer with respect to a Performance Award may vary based on the Partnership’s relative TUP as compared to the TUR of the performance peer group. The Performance Awards are described above under “Long-Term Equity Incentive Awards” in the Compensation Discussion and Analysis.

(2)	The disclosure reflects the aggregate grant date fair value of the Performance Awards, computed in accordance with FASB ASC Topic 718 based on probably achievement of the performance conditions, which is consistent with the estimate of aggregate compensation to be recognized over the service period, excluding the effect of estimated forfeitures.

(3)	The fair value of the restricted Service Award units shown in the table above were calculated based on the closing market price of our common units on the grant dates, with adjustments made to reflect the fact that restricted units are not entitled to distributions during the vesting period.

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(1)	Reflects Service Awards that have not vested and are held by each named executive officer.

(2)	Calculated based on the closing market price of our common units at March 31, 2016 of $7.52. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.

(3)	Reflects the target number of Performance Awards granted to each named executive officer that have not vested. Vesting of the Performance Awards are contingent upon our relative TUR as measured against the performance peer group and satisfaction of a continued service requirement.

(4)	Mr. Atanasov resigned effective February 5, 2016 resulting in the forfeiture of his Service Awards and Performance Awards. As a result, Mr. Atanasov did not have any outstanding equity awards as of March 31, 2016.

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•	an annual retainer of $60,000;

•	an annual retainer of $10,000 for the chairman of the audit committee; and

•	an annual retainer of $5,000 for each member of the audit committee other than the chairman.

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•	each person or group of persons known by us to be a beneficial owner of more than 5% of our outstanding common units;

•	each director of our general partner;

•	each named executive officer of our general partner; and

•	all directors and executive officers of our general partner as a group.

(1)	Based on 104,169,573 common units outstanding at May 23, 2016.

(2)	The mailing address for OppenheimerFunds, Inc. is 225 Liberty Street, New York, NY 10281. OppenheimerFunds, Inc. reported shared voting and dispositive power with respect to all common units beneficially owned. This information related to OppenheimerFunds, Inc. is based upon its Schedule 13G/A filed with the SEC on April 8, 2016.

(3)	The mailing address for Magnum NGL HoldCo LLC is 2603 Augusta, Suite 900, Houston, TX 77057. Magnum NGL HoldCo LLC reported shared voting and dispositive power with respect to all common units beneficially owned. This information related to Magnum NGL HoldCo LLC is based upon its Schedule 13G filed with the SEC on February 27, 2015.

(4)	The mailing address for ALPS Advisors, Inc. is 1290 Broadway, Suite 1100, Denver, CO 80203. ALPS Advisors, Inc. reported shared voting and dispositive power with respect to all common units beneficially owned. This information related to ALPS Advisors, Inc. is based upon its Schedule 13G filed with the SEC on February 3, 2016.

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(5)	The mailing address for Salient Capital Advisors, LLC is 4265 San Felipe, 8th Floor, Houston, TX 77027. Salient Capital Advisors, LLC reported shared voting and dispositive power with respect to all common units beneficially owned. This information related to Salient Capital Advisors, LLC is based upon its Schedule 13G filed with the SEC on January 12, 2016.

(6)

Mr. Burke owns 290,770 of these common units which includes 30,000 units that will vest on July 1, 2016, which were reported on Mr. Burke’s most recent Form 4, but does not include 15,000 unvested units which were reported on Mr. Burke’s most recent Form 4. Impact Development, LLC owns 33,872 of these common units. Impact Development, LLC is solely owned by James J. Burke, who may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. Impact Development, LLC also owns a 2.87% interest in our general partner.

(7)

Dr. Shawn W. Coady owns 52,019 of these common units which includes 30,000 units that will vest on July 1, 2016, which were reported on Dr. Coady’s most recent Form 4. SWC Family Partnership LP owns 2,320,391 of these common units. SWC Family Partnership LP is solely owned by SWC General Partner, LLC, of which Dr. Coady is the sole partner. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady Irrevocable Insurance Trust, which was established for the benefit of Shawn W. Coady’s children, owns 135,000 of these common units. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The Tara Nicole Coady Trust II, of which the reporting person is the trustee, owns 12,250 common units. The Colleen Blair Coady Trust, of which the reporting person is the trustee, owns 12,250 common units. Dr. Coady also owns a 12.27% interest in our general partner through Coady Enterprises, LLC, of which he owns 100% of the membership interests.

(8)

Mr. Collingsworth owns 44,500 of these common units which includes 5,000 units that will vest on July 1, 2016, which were reported on Mr. Collingsworth’s most recent Form 4, but does not include 5,000 unvested units which were reported on Mr. Collingworth’s most recent Form 4. Mr. Collingsworth holds 2,000 of these common units jointly with his spouse, Cindy Collingsworth. Cindy Collingsworth and her sister jointly own 2,250 of these common units.

(9)

Mr. Cropper owns 10,000 of these common units which includes 5,000 units that will vest on July 1, 2016, which were reported on Mr. Cropper’s most recent Form 4, but does not include 5,000 unvested units which were reported on Mr. Cropper’s most recent Form 4. The Donna L. Cropper Living Trust, of which Stephen L. Cropper and his spouse, Donna L. Cropper, are the trustees, owns 25,000 of these common units.

(10)	Mr. Kneale owns 5,000 of these common units which includes 5,000 units that will vest on July 1, 2016, which were reported on Mr. Kneale’s most recent Form 4, but does not include 5,000 unvested units which were reported on Mr. Kneale’s most recent Form 4. The Suzanne and Jim Kneale Living Trust, of whom Mr. Kneale and his wife are trustees, owns 27,000 of these common units.

(11)

Mr. H. Michael Krimbill owns 489,417 of these common units which includes 71,191 units that will vest on July 1, 2016, which were reported on Mr. Krimbill’s most recent Form 4, but does not include 71,191 unvested units which were reported on Mr. Krimbill’s most recent Form 4. Krim2010, LLC owns 904,484 of these common units. Krimbill Enterprises LP, H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06% of Krim2010, LLC, respectively. Krimbill Enterprises LP owns 120,000 of these common units. Krimbill Enterprises LP is controlled by H. Michael Krimbill via his ownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. KrimGP2010 LLC owns 363,555 of these common units. KrimGP2010 LLC is solely owned by H. Michael Krimbill. H. Michael Krimbill may be deemed to have sole voting and investment power over these units. H. Michael Krimbill also owns a 14.81% interest in our general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests and Krimbill Capital Group, LLC, which is owned 100% by the H. Michael Krimbill Revocable Trust.

(12)

Mr. Osterman owns 118,263 of these common units which includes 30,000 units that will vest on July 1, 2016, which were reported on Mr. Osterman’s most recent Form 4. The remaining common units are owned by AO Energy, Inc. (110,587 common units), E. Osterman, Inc. (394,350 common units), E. Osterman Gas Services, Inc. (301,700 common units), E. Osterman Propane, Inc. (669,300 common units), Milford Propane, Inc. (559,784 common units), Osterman Family Foundation (122,016 common units), Osterman Propane, Inc. (1,445,850 common units), Propane Gas, Inc. (36,450 common units) and Saveway Propane Gas Service, Inc. (214,600 common units). Each of these holding entities may be deemed to have sole voting and investment power over its own common units and Propane Gas, LLC, as sole shareholder of Propane Gas, Inc., may be deemed to have sole voting and investment power over those common units. Vincent J. Osterman is a director, executive officer and shareholder or member of each of these entities and may be deemed to have sole voting and investment power over 787,563 common units and shared voting and investment power

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(13)

EMG NGL HC, LLC owns all of the 176,634 common units. John T. Raymond is the Chief Executive Officer and Managing Partner of NGP MR GP LLC, the general partner of NGP MR, LP, the general partner of NGP Midstream & Resources, LLC, a member holding a majority interest in EMG NGL HC LLC. John T. Raymond may be deemed to have shared voting and investment power over these units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. EMG I NGL GP Holdings, LLC, an affiliate of EMG NGL HC LLC, owns a 5.73% interest in our general partner. EMG II NGL GP Holdings, LLC, an affiliate of EMG NGL HC LLC, owns a 5.36% interest in our general partner.

(14)	The directors and executive officers of our general partner also collectively own a 48.11% interest in our general partner.

(1)

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of our issued and outstanding common units. The maximum number of common units deliverable under the LTIP automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount.

(2)	Our general partner adopted the LTIP in connection with the completion of our initial public offering (“IPO”) in May 2011. The adoption of the LTIP did not require the approval of our unitholders.

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Demand Registration Rights. Certain registration rights parties deemed “Significant Holders” under the agreement may, to the extent that they continue to own more than 4% of our common units, require us to file a registration statement with the SEC registering the offer and sale of a specified number of common units, subject to limitations on the number of requests for registration that can be made in any twelve-month period as well as customary cutbacks at the discretion of the underwriters relating to a potential offering. All other registration rights parties are entitled to notice of a Significant Holder’s exercise of its demand registration rights and may include their common units in such registration. We can only be required to file a total of nine registration statements upon the Significant Holders’ exercise of these demand registration rights and are only required to effect demand registration if the aggregate proposed offering price to the public is at least $10.0 million.

•

Piggyback Registration Rights. If we propose to file a registration statement under the Securities Act to register our common units, the registration rights parties are entitled to notice of such registration and have the right to include their common units in the registration, subject to limitations that the underwriters relating to a potential offering may impose on the number of common units included in the registration. These counterparties also have the right to include their units in our future registrations, including secondary offerings of our common units.

•	Expenses of Registration. With specified exceptions, we are required to pay all expenses incidental to any registration of common units, excluding underwriting discounts and commissions.

•	whether there is an appropriate business justification for the transaction;

•	the benefits that accrue to the Partnership as a result of the transaction;

•	the terms available to unrelated third parties entering into similar transactions;

•	the impact of the transaction on a director’s independence (in the event the related party is a director, an immediate family member of a director or an entity in which a director is a partner, shareholder or executive officer);

•	the availability of other sources for comparable products or services;

•	whether it is a single transaction or a series of ongoing, related transactions; and

•	whether entering into the transaction would be consistent with the Code of Business Conduct and Ethics.

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(1)	Includes fees for audits of the Partnership’s financial statements, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and the preparation of letters to underwriters and other requesting parties.

(2)	Includes fees for tax services in connection with tax compliance and consultation on tax matters.

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(a)	The following documents are filed as part of this Annual Report:

1.	Financial Statements. Please see the accompanying Index to Financial Statements.

2.	Financial Statement Schedules. All schedules have been omitted because they are either not applicable, not required or the information required in such schedules appears in the financial statements or the related notes.

3.	Exhibits.

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*	Exhibits filed with this report.

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The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at March 31, 2016 and 2015, (ii) Consolidated Statements of Operations for the years ended March 31, 2016, 2015, and 2014, (iii) Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2016, 2015, and 2014, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2016, 2015, and 2014, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2016, 2015, and 2014, and (vi) Notes to Consolidated Financial Statements.

+	Management contracts or compensatory plans or arrangements.

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Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals and pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests in two crude oil pipelines. Our crude oil logistics segment purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

•

Our water solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities. Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck washouts. In addition, our water solutions segment sells the recycled water and recovered hydrocarbons that result from performing these services.

•

Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling and storage services through its 19 owned terminals throughout the United States, its salt dome storage facility in Utah, and its leased storage and railcar transportation services through its fleet of leased railcars.

•	Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia.

•	Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We purchase refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedule them for delivery at various locations. See Note 14 for a discussion of our interests in TransMontaigne Partners L.P. (“TLP”).

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•	Level 1—Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date.

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Level 2—Inputs (other than quoted prices included within Level 1) that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability, and (iv) inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts. We determine the fair value of all of our derivative financial instruments utilizing pricing models for similar instruments. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

•	Level 3—Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

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(1)	When we acquired Gavilon Energy, we recorded the investment in Glass Mountain, which owns a crude oil pipeline in Oklahoma, at fair value. Our investment in Glass Mountain exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $74.6 million at March 31, 2016. This difference relates primarily to goodwill and customer relationships.

(2)	On February 1, 2016, we deconsolidated TLP (see Note 1 and Note 14), and as a result, we recorded our equity method investment in TLP. On April 1, 2016, we sold all of the TLP common units that we held (see Note 19).

(3)	As part of the deconsolidation of TLP on February 1, 2016, our previous investments in BOSTCO and Frontera are no longer disclosed as investments in unconsolidated entities.

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(1)	Represents a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party.

(2)	Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At March 31, 2016, linefill consisted of 487,104 barrels of crude oil.

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(3)

Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks are removed from service. At March 31, 2016, tank bottoms held in third party terminals consisted of 366,212 barrels of refined products. Tank bottoms held in terminals we own are included within property, plant and equipment (see Note 5).

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In the first step of the goodwill impairment test, we compare the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amount of a reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of impairment loss, if any.

•	In the second step of the goodwill impairment test, we compare the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess.

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(1)	Net income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are described in Note 11.

(2)

All outstanding subordinated units converted to common units in August 2014. Since the subordinated units did not share in the distribution of cash generated after June 30, 2014, we did not allocate any income or loss after that date to the subordinated unitholders. During the three months ended June 30, 2014, 5,919,346 subordinated units were outstanding and the loss per subordinated unit was $(0.68). During the year ended March 31, 2014, 5,919,346 subordinated units were outstanding and income per subordinated unit was $0.32.

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(1)	Due to the deconsolidation of TLP in February 2016 (see Note 1), the tank bottoms for the TLP terminals were reclassified to noncurrent assets.

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(1)	Includes debt issuance costs related to revolving credit facilities. Debt issuance costs related to fixed-rate notes are reported as a reduction of the carrying amount of long-term debt.

(2)	See Note 16 for a discussion of acquired rights-of-way and easements along a planned pipeline route.

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(1)	Debt issuance costs related to revolving credit facilities are reported within intangible assets, rather than as a reduction of the carrying amount of long-term debt.

(2)	Due to the sale of the general partner interest in TLP, TLP was deconsolidated as of February 1, 2016 (see Note 1 and Note 14).

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(1)	Relates to commodity derivative assets and liabilities that are expected to be net settled on an exchange or through a netting arrangement with the counterparty.

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(1)	Cross-commodity - We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. These contracts are derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.

(2)	Commodity fixed-price - We may have fixed price physical purchases, including inventory, offset by floating price physical sales or floating price physical purchases offset by fixed price physical sales. These contracts are derivatives we have entered into as an economic hedge against the risk of mismatches between fixed and floating price physical obligations.

(3)	Commodity fixed-price - We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different indices. These indices may vary in the commodity grade or location, or in the timing of delivery within a given month. These contracts are derivatives we have entered into as an economic hedge against the risk of one index moving relative to another index.

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(1)	During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to the categories shown in the table above. These changes did not impact total revenues. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

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(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Since the parent received the proceeds from the issuance of the 2019 Notes and 2021 Notes, all activity has been reflected in the parent column.

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(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Since the parent received the proceeds from the issuance of the 2019 Notes and 2021 Notes, all activity has been reflected in the parent column.

(2)	The carrying value of long-term debt in the NGL Energy Partners LP (Parent) column has been reduced by $17.8 million of debt issuance costs.

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(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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(1)	The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.

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*	Exhibits filed with this report.

**

The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at March 31, 2016 and 2015, (ii) Consolidated Statements of Operations for the years ended March 31, 2016, 2015, and 2014, (iii) Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2016, 2015, and 2014, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2016, 2015, and 2014, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2016, 2015, and 2014, and (vi) Notes to Consolidated Financial Statements.

+	Management contracts or compensatory plans or arrangements.