10-K

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

xANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended March 31, 2014

or

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                  to

Commission File Number: 001-35172

NGL Energy Partners LP

(Exact Name of Registrant as Specified in Its Charter)

Delaware	27-3427920
(State or Other Jurisdiction of Incorporation or Organization)	(I.R.S. Employer Identification No.)

6120 South Yale Avenue Suite 805 Tulsa, Oklahoma	74136
(Address of Principal Executive Offices)	(Zip code)

(918) 481-1119

(Registrant’s Telephone Number, Including Area Code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class	Name of Each Exchange on Which Registered
Common Units Representing Limited Partner Interests	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act:  None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x  No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o  No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x  No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x  No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x	Accelerated filer o
Non-accelerated filer o	Smaller reporting company o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No x

The aggregate market value at September 30, 2013 of the Common Units held by non-affiliates of the registrant, based on the reported closing price of the Common Units on the New York Stock Exchange on such date ($30.84 per Common Unit) was $1,443,663,823. For purposes of this computation, all executive officers, directors and 10% owners of the registrant are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers, directors and 10% beneficial owners are affiliates.

At May 23, 2014, there were 74,706,160 common units and 5,919,346 subordinated units issued and outstanding.

TABLE OF CONTENTS

	PART I
Item 1.	Business	3
Item 1A.	Risk Factors	27
Item 1B.	Unresolved Staff Comments	49
Item 2.	Properties	49
Item 3.	Legal Proceedings	49
Item 4.	Mine Safety Disclosures	49
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	50
Item 6.	Selected Financial Data	51
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	85
Item 8.	Financial Statements and Supplementary Data	86
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	86
Item 9A.	Controls and Procedures	87
Item 9B.	Other Information	87
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	88
Item 11.	Executive Compensation	94
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	103
Item 13.	Certain Relationships and Related Transactions and Director Independence	105
Item 14.	Principal Accountant Fees and Services	109
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	110

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Forward-Looking Statements

This Annual Report on Form 10-K (“Annual Report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. When used in this Annual Report, words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will,” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may impact our consolidated financial position and results of operations are:

·the prices for crude oil, natural gas, natural gas liquids, refined products, ethanol, and biodiesel;

·energy prices generally;

·the price of propane relative to the price of alternative and competing fuels;

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

·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 basins in which we have water treatment facilities;

·the ability to obtain adequate supplies of propane and distillates for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane and distillates to market areas;

·actions taken by foreign oil and gas producing nations;

·the political and economic stability of petroleum 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;

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

·availability, price, and marketing of competitive 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 and on the treatment of flowback and produced water;

·hazards or operating risks incidental to the transporting and distributing of petroleum products that may not be fully covered by insurance;

·the maturity of the crude oil and natural gas liquids industries and competition from other marketers;

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·loss of key personnel;

·the ability to hire drivers;

·the ability to renew contracts with key customers;

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

·the ability to renew leases for general purpose and high pressure railcars;

·the ability to renew leases for underground natural gas liquids storage;

·the non-payment or nonperformance by our customers;

·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 at purchase prices that are accretive to our financial results;

·the ability to successfully integrate acquired assets and businesses;

·changes in the volume of crude oil 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 laws and regulations to which we are subject, 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, including our sales of crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel, our processing of wastewater, and transportation and risk management activities;

·the costs and effects of legal and administrative proceedings;

·the demand for refined products;

·any reduction or elimination of the Renewable Fuels Standard;

·the operational and financial success of our joint ventures; and

·changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our joint venture’s pipeline assets.

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this Annual Report. Except as required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks described under “Item 1A — Risk Factors.”

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PART I

References in this Annual Report to (i) “NGL Energy Partners LP,” “we,” “our,” “us” or similar terms refer to NGL Energy Partners LP and its operating subsidiaries, (ii) “NGL Energy Holdings LLC” or “general partner” refers to NGL Energy Holdings LLC, our general partner, (iii) “NGL Energy Operating LLC” or “operating company” refers to NGL Energy Operating LLC, the direct operating subsidiary of NGL Energy Partners LP, (iv) “NGL Supply” refers to NGL Supply, Inc. for periods prior to our formation and refers to NGL Supply, LLC, a wholly-owned subsidiary of NGL Energy Operating LLC, for periods after our formation, (v) “Hicksgas” refers to the combined assets and operations of Hicksgas Gifford, Inc., which we refer to as Gifford, and Hicksgas, LLC, a wholly-owned subsidiary of NGL Energy Operating LLC, which we refer to as Hicks LLC, (vi) the “NGL Energy GP Investor Group” refers to, collectively, the 36 individuals and entities that own all of the outstanding membership interests in our general partner, (vii) the “NGL Energy LP Investor Group” refers to, collectively, the 15 individuals and entities that owned all of our outstanding common units before the closing date of our initial public offering, and (viii) the “NGL Energy Investor Group” refers to, collectively, the NGL Energy GP Investor Group and the NGL Energy LP Investor Group.

We have presented various operational data in “Item 1 — Business” for the year ended March 31, 2014. Unless otherwise indicated, this data is as of March 31, 2014.

Item 1.Business

Overview

We are a Delaware limited partnership formed in September 2010 by several investors (“IEP Parties”). As part of our formation, we acquired and combined the assets and operations of NGL Supply, Inc., primarily a wholesale propane and terminaling business founded in 1967, and Hicksgas, LLC and Hicksgas Gifford, Inc., primarily a retail propane business founded in 1940. Subsequent to our formation, we significantly expanded our operations through numerous business combinations. At March 31, 2014, our primary businesses include:

·A crude oil logistics business, the assets of which include crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

·A water solutions business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons.

·Our liquids business, 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 services through its 22 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids business purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets.

·Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.

We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon, LLC (“Gavilon Energy”).

For more information regarding our operating segments, please see Note 13 to our consolidated financial statements included in this Annual Report.

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Initial Public Offering

On May 17, 2011, we completed our initial public offering (“IPO”) and listed our common units on the New York Stock Exchange under the symbol “NGL.” Upon the completion of our IPO, we had outstanding common units, subordinated units, a 0.1% general partner interest, and incentive distribution rights (“IDRs”). IDRs entitle the holder to specified increasing percentages of cash distributions as our per-unit cash distributions increase above specified levels.

Acquisitions Subsequent to Initial Public Offering

Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, including the following, among others:

·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.

·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. (“North American”), 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 (“Downeast”). 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 transaction 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.

·In July 2013, we completed a business combination whereby we acquired the assets of Crescent Terminals, LLC and the ownership interests in Cierra Marine, LP and its affiliated companies (collectively, “Crescent”), whereby we acquired four towboats, seven crude oil barges, and a crude oil terminal in South Texas.

·In July 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd. (“Big Lake”), whereby we acquired a water disposal facility in West Texas. We also entered into a development agreement that provides us the option to purchase disposal facilities that may be developed in the future. During March 2014, we purchased one additional facility under this development agreement.

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·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 water disposal operations and a water transportation business in Texas.

·In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), in which we acquired the ownership interests in water disposal facilities in Texas and the right to purchase one additional facility, which we exercised in March 2014.

·In December 2013, we acquired the ownership interests in Gavilon Energy. The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana and 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. This pipeline became operational in February 2014. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids.

Primary Service Areas

The following maps show the primary service areas of our businesses at various points in time, to illustrate the growth of our businesses:

Primary Service Areas at May 11, 2011

5

Primary Service Areas at March 31, 2012

Primary Service Areas at March 31, 2013

6

Primary Service Areas at March 31, 2014

7

Organizational Chart

The following chart provides a summarized view of our legal entity structure at March 31, 2014:

(1) Includes the operations of our crude oil logistics, refined products, and renewables businesses

(2) Includes the operations of our water solutions business

(3) Includes the operations of our liquids business

(4) Includes the operations of our retail propane business

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Our Business Strategies

Our principal business objective is to increase the quarterly distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business and its cash flows. We expect to achieve this objective by executing the following strategies:

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

·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 have acquired. We also believe that there are further organic growth opportunities within our existing businesses, particularly within our crude oil logistics and water solutions businesses.

·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 crude oil logistics platform, and enhance our geographic diversity in our water solutions segment. 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.

·Focus on consistent annual cash flows by adding operations that minimize commodity price risk and generate fee-based, cost-plus, or margin-based revenues. We believe that expanding our retail propane business with an emphasis on a high level of residential customers and a high level of company-owned tanks will result in strong customer retention rates and consistent operating margins. In our liquids and crude oil logistics segments, we intend to focus on back-to-back contracts which minimize commodity price exposure. In our water solutions segment, cash flows are typically supported by fee-based contracts, some of which include acreage dedications from producers or volume commitments.

·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 maintain sufficient liquidity to manage existing and future capital requirements.

·Maintain a disciplined cash distribution policy that complements our 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. We believe this strategy positions us to pursue future acquisitions and to execute upon our organic growth initiatives.

Our Competitive Strengths

We believe that we are well-positioned to successfully execute our business strategies and achieve our principal business objectives because of the following competitive strengths:

·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.

·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 producers in numerous geographic areas enhances our competitive position. 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.

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·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 contracted pipeline capacity, provide access to a wide range of customers and markets. We use this expansive network of transportation assets, together with our proprietary linear programming model, to deliver crude oil to the optimal markets.

·Our water processing facilities, which are strategically located near areas of growing crude oil and natural gas production. Our water processing facilities are located among the most prolific oil and gas producing basins in the United States, including the Permian, Niobrara, and Eagle Ford shale plays. In addition, we believe that the technological capabilities of our water processing 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 underground storage enable us to be a preferred purchaser and seller of natural gas liquids.

·Our high percentage of retail sales to residential customers, who are generally more stable purchasers of propane and distillatesand 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 segment.

Our Businesses

Crude Oil Logistics

Overview. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. Our operations are centered near areas of high crude oil production, such as the Bakken Shale Basin in North Dakota, the Niobrara Shale Basin in Colorado, the Mississippi Lime Basin in Oklahoma, the Permian Basin in Texas and New Mexico, the Eagle Ford Basin in Texas, and the Anadarko Basin in Oklahoma and Texas.

Operations. We transport crude oil using the following assets:

·300 owned trucks, 300 owned trailers, and 100 leased trucks operating primarily in the Mid-Continent, Permian Basin, Eagle Ford Basin, and Rocky Mountain regions;

·200 owned railcars and 700 leased railcars operating primarily in North Dakota, Oklahoma, Colorado, Wyoming, and Texas; and

·8 owned towboats, 19 owned barges, 5 leased towboats and 12 leased barges (including 1 leased storage barge) operating primarily in the inter-coastal waterways of the Gulf Coast and along the Mississippi and Arkansas river systems.

We contract for truck, rail, and barge transportation services from third parties and ship on common carrier pipelines. We own 60 pipeline injection facilities in Kansas, Oklahoma, North Dakota, New Mexico, Texas, and Montana. We lease six rail transload facilities and have throughput agreements at seven rail transload facilities in Colorado, Kansas, Louisiana, New Mexico, North Dakota, Oklahoma, and Texas.

We own seven storage terminal facilities, as summarized below:

	Storage Capacity
Location	(barrels)
Cushing, Oklahoma	4,140,000
Catoosa, Oklahoma	138,000
Port Aransas, Texas	120,000
Rio Hondo, Texas	80,000
Wheatland, Wyoming	80,000
Seadrift, Texas	25,000
Sunray, Texas	9,500

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We lease 3.85 million barrels of storage capacity in Cushing, Oklahoma.

We have two Gulf Coast terminal facilities that are under construction and are expected to be completed during the latter part of fiscal 2015 with a total expected storage capacity of 625,000 barrels. We also own a 50% interest in Glass Mountain, which owns a 210-mile crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline, which became operational in February 2014, has a capacity of 147,000 barrels per day.

Customers. Our customers include crude oil refiners and marketers. Approximately 60% of the revenues from our crude oil logistics segment during the year ended March 31, 2014 related to our ten largest customers of the segment. In addition to utilizing our assets to transport product we own, we also provide truck transportation, barge transportation, storage, and terminal throughput services to our customers.

Competition. We face significant competition, as many entities are engaged in the crude oil logistics business, some of which are larger and have greater financial resources than we do. The primary factors on which we compete are:

·price;

·availability of supply;

·level and quality of service;

·available space on common carrier pipelines;

·the availability of railcars;

·proprietary terminals;

·owned barges and towboats;

·obtaining and retaining customers; and

·the acquisition of businesses.

Supply. We obtain crude oil from a large base of suppliers, which consist primarily of crude oil producers. We currently purchase from 800 producers at 7,600 leases.

Pricing Policy. Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets, such as Cushing, Oklahoma. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives. We also seek to maximize margins on crude oil sales by combining crude oil of varying qualities (such as gravity, sulphur content, or mineral content).

Billing and Collection Procedures. As is customary in the crude oil industry, we generally receive payment from customers on a monthly basis. As a result, receivables from individual customers in our crude oil business are typically higher than the receivables from customers of our other segments. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our crude oil logistics customers. We believe the following procedures enhance our collection efforts with our crude oil logistics customers:

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

·we require certain customers to post letters of credit on a portion of our receivables;

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

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·we require our sales personnel to manage their customers’ receivable position and tie a portion of our sales personnel’s compensation to their ability to manage their accounts and minimize and collect past due balances.

Trade Names. Our crude oil logistics business operates primarily under the NGL — Crude Logistics trade name.

Water Solutions

Overview. Our water solutions segment generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. Our facilities are located near fields with high levels of crude oil and natural gas production, such as the Pinedale Anticline Basin in Wyoming, the DJ Basin in Colorado, and the Permian and Eagle Ford Basins in Texas.

Operations. We own 23 wastewater processing facilities. The location of the facilities and the processing capacities at which the facilities currently operate are summarized below.

	Processing
	Capacity
Location	(barrels per day)
Pinedale, Wyoming (A)(B)	60,000
Briggsdale, Colorado (C)(D)	34,000
Grover, Colorado (C)	25,000
Greeley, Colorado (B)	18,000
Platteville, Colorado (C)(E)	16,200
Kersey, Colorado (C)	14,000
LaSalle, Colorado (C)	5,900
Brighton, Colorado (C)	5,100
Big Lake, Texas (C)	30,000
Pecos, Texas (C)(F)	23,000
Carrizo Springs, Texas (B)	22,500
Charlotte, Texas (C)(F)	22,000
Cheapside, Texas (C)	22,000
Gillett, Texas (C)	22,000
Karnes City, Texas (C)	22,000
Artesia Wells, Texas (C)	20,000
Nixon, Texas (C)	20,000
Los Angeles, Texas (B)	20,000
Fowlerton, Texas (C)	18,000
Pearsall, Texas (B)	17,000
Cotulla, Texas (C)	16,500
Dilley Lea, Texas (B)	15,000
Andrews, Texas (C)	12,000

(A)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 20,000 barrels per day to process water to a discharge standard.

(B)These facilities are located on land we lease.

(C)These facilities are located on land we own.

(D)The processing capacity listed above for this facility includes a design capacity of 12,000 barrels per day to process water to a recycle standard.

(E)The processing capacity listed above for this facility includes a design capacity of 10,000 barrels per day to process water to a recycle standard.

(F)We purchased these facilities effective March 1, 2014.

Our customers bring wastewater generated by crude oil and natural gas exploration and production operations to our facilities for treatment. Once we take delivery of the water, the level of processing is determined by the ultimate disposition of the water.

Our facility in Wyoming has the assets and technology needed to treat the water more extensively. At this facility, the water is recycled, rather than being disposed of in an injection well. We either process the water to the point where it can be returned to

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producers to be re-used in future drilling operations, or we treat the water to a greater extent, such that it exceeds the standards for drinking water, and can be returned to the ecosystem.

Our facilities in Colorado dispose of wastewater primarily into deep underground formations via injection wells. Two of our facilities in Colorado have the assets and technology needed to treat the water to the point that we can sell the water back to producers for use in future drilling operations.

Our facilities in Texas dispose of wastewater into deep underground formations via injection wells. We also operate a wastewater transportation business in Texas, whereby we transport wastewater via truck to processing facilities owned by us and other parties. We operate this business with 70 owned trucks, 20 owned trailers, and 80 frac tanks.

Customers. The customers of our Wyoming and Colorado facilities consist primarily of large exploration and production companies who conduct drilling operations near our facilities. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume to our facility under multi-year contracts. Certain other customers, primarily those of our facilities in Colorado, have committed to deliver to our facilities all wastewater produced at all wells in a designated area under multi-year contracts. The customers of our facilities in Texas consist primarily of wastewater transportation companies, although one customer has committed to deliver 50,000 barrels per day to our facilities in Texas. During the year ended March 31, 2014, 37% of the revenues of the water solutions segment were generated from our two largest customers of the segment, and 73% of the revenues of the segment were generated from our ten largest customers of the segment.

Competition. We compete with other processors of wastewater to the extent that other processors have facilities geographically close to our facilities. Location is an important consideration for our customers, who seek to minimize the cost of transporting the wastewater to disposal facilities. Our facilities are strategically located near areas of significant crude oil and natural gas production.

Pricing Policy. We generally charge customers a processing fee per barrel of wastewater processed. Certain of our contracts require the customer to deliver a specified minimum volume of wastewater over a specified period of time. We also generate revenue from the sale of hydrocarbons we recover in the process of treating the wastewater, which we take into consideration in negotiating the processing fees with our customers.

Billing and Collection Procedures. Our water solutions customers consist of large oil and natural gas producers, and also include smaller water transportation companies. We typically invoice customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our water solutions customers. We believe the following procedures enhance our collection efforts with our water solutions customers:

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

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

·we require our sales personnel to manage their customers’ receivable position and tie a portion of our sales personnel’s compensation to their ability to manage their accounts and to minimize and collect past due balances.

Trade Names. Our water solutions business operates primarily under the NGL — Water Solutions trade name.

Technology. We hold multiple patents for processing technologies. We own a research and development center, which we use to optimize treatment processes and cost minimization.

Liquids

Overview. Our liquids segment provides natural gas liquids procurement, storage, transportation, and supply services to customers through assets owned by us and third parties. Our liquids business also supplies the majority of the propane for our retail propane business. We also sell butanes and natural gasolines to refiners and producers for use as blending stocks and diluent and assist refineries by managing their seasonal butane supply needs.

Operations. We procure natural gas liquids from refiners, gas processing plants, producers and other resellers for delivery to leased storage space, common carrier pipelines, railcar terminals, and direct to certain customers. Our customers take delivery by loading natural gas liquids into transport vehicles from common carrier pipeline terminals, private terminals, our terminals, directly from refineries and rail terminals, and by railcar.

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A portion of our wholesale propane gallons are presold to third-party retailers and wholesalers at a fixed price under back-to-back contracts. Back-to-back contracts, in which we balance our contractual portfolio by buying propane supply when we have a matching purchase commitment from our wholesale customers, protects our margins, and mitigates commodity price risk. Pre-sales also reduce the impact of warm weather because the customer is required to take delivery of the propane regardless of the weather. We generally require cash deposits from these customers. In addition, on a daily basis we have the ability to balance our inventory by buying or selling propane, butanes, and natural gasoline to refiners, resellers, and propane producers through pipeline inventory transfers at major storage hubs.

In order to secure consistent supply during the heating season, we are often required to purchase volumes of propane during the entire fiscal year. In order to mitigate storage costs and price risk, we may sell those volumes at a lesser margin than we earn in our other wholesale operations.

We purchase butane from refiners during the summer months, when refiners have a greater butane supply than they need, and sell butane to refiners during the winter blending season, when demand for butane is higher. We utilize a portion of our railcar fleet and a portion of our leased underground storage to store butane for this purpose.

We also transport customer-owned natural gas liquids on our leased railcars and charge the customers a transportation service fee. In addition, we sub-lease railcars to certain customers.

We also purchase and sell asphalt. We utilize leased railcars to move the asphalt from our suppliers to our customers.

We own 22 natural gas liquids terminals and we lease a fleet of railcars. These assets give us the opportunity to access wholesale markets throughout the United States, and to move product to locations where demand is highest. We utilize these terminals and railcars primarily in the service of our wholesale operations, although we also provide transportation, storage, and throughput services to other parties to a lesser extent.

The following chart lists our natural gas liquids terminals and their throughput capacity:

	Throughput Capacity
Facility	(in gallons per day)
Rosemount, Minnesota	1,441,000
Lebanon, Indiana	1,058,000
West Memphis, Arkansas	1,058,000
Dexter, Missouri	930,000
East St. Louis, Illinois	883,000
Jefferson City, Missouri	883,000
Hutchinson, Kansas	840,000
St. Catherines, Ontario, Canada	700,000
Janesville, Wisconsin	553,000
Light, Arkansas	524,400
Rixie, Arkansas	524,400
Winslow, Arizona	500,000
Albuquerque, New Mexico	408,000
Kingsland, Arkansas	405,000
Portland, Maine	360,000
West Springfield, Massachusetts	360,000
Vancouver, Washington	358,000
Green Bay, Wisconsin	310,000
Thackerville, Oklahoma	235,000
Ritzville, Washington	198,000
Sidney, Montana	180,000
Shelton, Washington	161,000

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We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouri are operated for us by a third party for a monthly fee under an operating and maintenance agreement that has a term that expires in 2017. The terminal in St. Catherines, Ontario, Canada is operated by a third party under a year-to-year agreement.

We own the terminal assets. We own the land on which 12 of the terminals are located and we either have easements or lease the land on which 10 of the terminals are located. The terminals in East St. Louis, Illinois and Jefferson City, Missouri have perpetual easements, and the terminal in St. Catherines, Ontario, Canada has a long-term lease that expires in 2022.

We own 4 railcars and lease 3,700 additional railcars, of which 600 railcars are subleased to a third party. These include high pressure and general purpose railcars.

We own 16 transloading units, which enable customers to transfer product from railcars to trucks. These transloading units can be moved to locations along a railroad where it is most convenient for customers to transfer their product.

We lease natural gas liquids storage space to accommodate the supply requirements and contractual needs of our retail and wholesale customers. We lease storage space for natural gas liquids in various storage hubs in Arizona, Canada, Kansas, Michigan, Mississippi, Missouri, New York and Texas.

The following chart shows our leased storage space at natural gas liquids storage facilities and interconnects to those facilities:

	Leased Storage Space
	(in gallons)
	Beginning		At
	April 1,		March 31,
Storage Facility	2014		2014	Storage Interconnects
Conway, Kansas		73,290,000	85,890,000	Connected to Enterprise Mid-America and NuStar Pipelines; Rail Facility
Borger, Texas		42,000,000	31,500,000	Connected to ConocoPhillips Blue Line Pipeline
Bushton, Kansas		10,500,000	12,600,000	Connected to ONEOK North System Pipeline
Mont Belvieu, Texas		3,150,000	2,940,000	Connected to Enterprise Texas Eastern Products Pipeline
Carthage, Missouri		7,560,000	7,560,000	Connected to Magellan Pipeline
Marysville, Michigan		4,200,000	15,750,000	Connected to Cochin Pipeline
Hattiesburg, Mississippi		6,930,000	7,350,000	Connected to Enterprise Dixie Pipeline; Rail Facility
Redwater, Alberta, Canada		7,938,000	9,055,200	Connected to Cochin Pipeline; Rail Facility
Regina, Saskatchewan, Canada		1,260,000	—	Connected to Cochin Pipeline; Rail Facility
Bath, New York		—	10,122,000	Rail Facility
Adamana, Arizona		1,398,600	1,680,000	Rail Facility
Corunna, Ontario, Canada		2,100,000	2,100,000	Rail Facility
Total		160,326,600	186,547,200

During the typical heating season from September 15 through March 15 each year, we have the right to utilize ConocoPhillips’ capacity as a shipper on the Blue Line pipeline to transport natural gas liquids from our leased storage space to our terminals in East St. Louis, Illinois and Jefferson City, Missouri. During the remainder of the year, we have access to available capacity on the Blue Line pipeline on the same basis as other shippers.

Customers. Our liquids business serves 900 customers in 45 states. Our liquids business serves national, regional and independent retail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. Our liquids business also supplies the majority of the propane for our retail propane business. We deliver the propane supply to our customers at terminals located on common carrier pipeline systems, rail terminals, refineries, and major United States propane storage hubs. For the year ended March 31, 2014, our ten largest liquids customers represented 35% of the total sales of our liquids business (exclusive of sales to our retail propane segment).

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Seasonality. Our liquids business is affected by the weather in a similar manner as our retail propane business. However, we are able to partially mitigate the effects of seasonality by pre-selling a portion of our wholesale volumes to retailers and wholesalers and requiring the customer to take delivery regardless of the weather.

Competition. Our liquids business faces significant competition. The primary factors on which we compete are:

·price;

·availability of supply;

·level and quality of service;

·available space on common carrier pipelines;

·storage availability;

·the availability of railcars;

·proprietary terminals;

·obtaining and retaining customers; and

·the acquisition of businesses.

Our competitors generally include other natural gas liquids wholesalers and companies involved in the natural gas liquids midstream industry (such as terminal and refinery operations), some of which have greater financial resources than we do.

Pricing Policy. In our natural gas liquids business, we offer our customers three categories of contracts for propane sourced from common carrier pipelines:

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

·rack barrel, which is a posted 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 use back-to-back contracts for many of our liquids segment sales to limit exposure to commodity price risk and protect our margins. We are able to match our supply and sales commitments by offering our customers purchase contracts with flexible price, location, storage, and ratable delivery. However, certain common carrier pipelines require us to keep minimum in-line inventory balances year round to conduct our daily business, and these volumes may not be matched with a purchase commitment.

We generally require deposits from our customers for fixed priced future delivery of propane if the delivery date is more than 30 days after the time of contractual agreement.

Billing and Collection Procedures. Our liquids segment customers consist of commercial accounts varying in size from local independent distributors to large regional and national retailers. These sales tend to be large volume transactions that can range from 10,000 gallons to as much as 1,000,000 gallons, and deliveries can occur over time periods extending from days to as long as a year. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our wholesale customers. We believe the following procedures enhance our collection efforts with our wholesale customers:

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

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·we require certain customers to post letters of credit 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 sales personnel to manage their wholesale customers’ receivable position and suspend sales to customers that have not paid previous invoices timely.

Trade Names. Our liquids business operates primarily under the NGL - Liquids, Centennial Energy, and Centennial Gas Liquids trade names.

Retail Propane

Overview. Our retail propane business consists of the retail marketing, sale and distribution of propane and distillates, including the sale and lease of propane tanks, equipment and supplies, to more than 290,000 residential, agricultural, commercial and industrial customers. We also sell propane to certain re-sellers. We purchase the majority of the propane sold in our retail propane business from our liquids business, which provides our retail propane business with a stable and secure supply of propane.

Operations. We market retail propane and distillates through our customer service locations. We sell propane primarily in rural areas, but we also have a number of customers in suburban areas where energy alternatives to propane such as natural gas are not generally available. We own or lease 92 customer service locations and 91 satellite distribution locations, with aggregate propane storage capacity of 10.7 million gallons and aggregate distillate storage capacity of 3.4 million gallons. Our customer service locations are staffed and operated to service a defined geographic market area and typically include a business office, product showroom, and secondary propane storage. Our satellite distribution locations, which are unmanned storage tanks, allow our customer service centers to serve an extended market area.

Our customer service locations in Illinois and Indiana also rent 15,000 water softeners and filters, primarily to residential customers in rural areas to treat well water or other problem water. We sell water conditioning equipment and treatment supplies as well. Although the water conditioning portion of our retail propane business is small, it generates steady year round revenues. The customer bases in Illinois and Indiana for retail propane and water conditioning have significant overlap, providing the opportunity to cross-sell both products between those customer bases.

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The following table shows the number of our customer service locations and satellite distribution locations by state:

	Number of Customer	Number of Satellite
	Service	Distribution
State	Locations	Locations
Illinois	23	19
Maine	17	10
Georgia	11	3
Massachusetts	10	8
Kansas	5	27
Indiana	4	5
Pennsylvania	4	3
Connecticut	3	2
North Carolina	3	1
Oregon	2	1
Washington	2	—
Mississippi	1	3
New Hampshire	1	1
Maryland	1	1
Rhode Island	1	1
Utah	1	1
Wyoming	1	1
Colorado	1	—
South Carolina	1	—
Delaware	—	1
New Jersey	—	1
Tennessee	—	1
Vermont	—	1
Total	92	91

We own 74 of our 92 customer service centers and 63 of our 91 satellite distribution locations, and we lease the remainder.

Tank ownership at customer locations is an important component to our operations and customer retention. At March 31, 2014, we owned the following propane storage tanks:

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

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

We also lease an additional 20 bulk storage tanks.

At March 31, 2014, we owned a fleet of 370 bulk delivery trucks, 40 semi-tractors, 40 propane transport trailers and 480 other service trucks.

Retail deliveries of propane are usually made to customers by means of our fleet of bulk delivery trucks. Propane is pumped from the bulk delivery truck, which holds 2,400 to 5,000 gallons, into a storage tank at the customer’s premises. The capacity of these storage tanks ranges from 30 to 1,000 gallons. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 25 gallons. These cylinders are typically picked up on a delivery route, refilled at our customer service locations, and then returned to the retail customer. Customers can also bring the cylinders to our customer service centers to be refilled.

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Approximately 73% of our residential customers receive their propane supply via our automatic route delivery program, which allows us to maximize our delivery efficiency. For these customers, our delivery forecasting software system utilizes a customer’s historical consumption patterns combined with current weather conditions to more accurately predict the optimal time to refill the customer’s tank. The delivery information is then uploaded to routing software to calculate the most cost effective delivery route. Our automatic delivery program promotes customer retention by providing an uninterrupted supply of propane and enables us to efficiently conduct route deliveries on a regular basis. Some of our purchase plans, such as level payment billing, fixed price, and price cap programs, further promote our automatic delivery program.

Customers. Our retail propane and distillate customers fall into three broad categories: residential, agricultural, and commercial and industrial. At March 31, 2014, our retail propane and distillate customers were comprised of:

·71% residential customers;

·28% commercial and industrial customers; and

·1% agricultural customers.

No single customer accounted for more than 1% of our retail propane volumes during the year ended March 31, 2014.

Seasonality. The retail propane and distillate business is largely seasonal due to the primary use of propane and distillates as heating fuels. In particular, residential and agricultural customers who use propane and distillates to heat homes and livestock buildings generally only need to purchase propane during the typical fall and winter heating season. Propane sales to agricultural customers who use propane for crop drying are also seasonal, although the impact on our retail propane volumes sold varies from year to year depending on the moisture content of the crop and the ambient temperature at the time of harvest. Propane and distillate sales to commercial and industrial customers, while affected by economic patterns, are not as seasonal as are sales to residential and agricultural customers.

Competition. Our retail propane business faces significant competition. The primary factors on which we compete are:

·price;

·availability of supply;

·level and quality of service;

·obtaining and retaining customers; and

·the acquisition of businesses.

Our competitors generally include other propane retailers and companies involved in the sale of natural gas, fuel oil and electricity, some of which have greater financial resources than we do. We compete with alternative energy sources and with other companies engaged in the retail propane distribution business. Competition with other retail propane distributors in the propane industry is highly fragmented and generally occurs on a local basis with other large full-service, multi state propane marketers, smaller local independent marketers and farm cooperatives. Our customer service locations generally have one to five competitors in their market area.

The competitive landscape of the markets that we serve has been fairly stable. Each customer service location operates in its own competitive environment, since retailers are located in close proximity to their customers due to delivery economics. Our customer service locations generally have an effective marketing radius of 25 to 65 miles, although in certain areas the marketing radius may be extended by satellite distribution locations.

The ability to compete effectively depends on the ability to provide superior customer service, which includes reliability of supply, quality equipment, well-trained service staff, efficient delivery, 24-hours-a-day service for emergency repairs and deliveries, multiple payment and purchase options and the ability to maintain competitive prices. Additionally, we believe that our safety programs, policies and procedures are more comprehensive than many of our smaller, independent competitors, which offers a higher level of service to our customers. We also believe that our overall service capabilities and customer responsiveness differentiate us from many of our competitors.

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Supply. Our retail propane segment purchases the majority of its propane from our liquids segment.

Pricing Policy. Our pricing policy is an essential element in the successful marketing of retail propane and distillates. We protect our margin by adjusting our retail propane pricing based on, among other things, prevailing supply costs, local market conditions, and input from management at our customer service locations. We rely on our regional management to set prices based on these factors. Our regional managers are advised regularly of any changes in the delivered cost of propane and distillates, potential supply disruptions, changes in industry inventory levels, and possible trends in the future cost of propane and distillates. We believe the market intelligence provided by our liquids business, combined with our propane and distillate pricing methods allows us to respond to changes in supply costs in a manner that protects our customer base and our margins.

Billing and Collection Procedures. In our retail propane business, our customer service locations are typically responsible for customer billing and account collection. We believe that this decentralized and more personal approach is beneficial because our local staff has more detailed knowledge of our customers, their needs, and their history than would an employee at a remote billing center. Our local staff often develops relationships with our customers that are beneficial in reducing payment time for a number of reasons:

·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.

Our retail propane customers must comply with our standards for extending credit, which typically includes submitting a credit application, supplying credit references, and undergoing a credit check with an appropriate credit agency.

Trade Names. We use a variety of trademarks and trade names that we own, including Hicksgas, Propane Central, Brantley Gas, Osterman, Pacer, Downeast Energy, Allied Propane, Lessig Oil and Propane, and Proflame, among others. We typically retain and continue to use the names of the companies that we acquire and believe that this helps maintain the local identification of these companies and contributes to their continued success. We regard our trademarks, trade names, and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products.

Refined Products

Overview. Our refined products marketing business purchases gasoline and diesel fuel primarily from eight suppliers and typically sells these products in back-to-back contracts to over 300 customers at a nationwide network of third-party owned terminaling and storage facilities. We lease 175,000 barrels of refined products storage on a third-party pipeline.

Customers. Our customers include convenience stores, petroleum-related transportation companies and railroad companies, among others. Approximately 41% of the revenues from our refined products segment during the year ended March 31, 2014 related to our ten largest customers of the segment.

Competition. We face significant competition, as many entities are engaged in the refined products business, some of which are larger and have greater financial resources than we do. The primary factors on which we compete are:

·price;

·availability of supply;

·level and quality of service;

·available space on common carrier pipelines;

·the availability of railcars;

·proprietary terminals; and

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·obtaining and retaining customers.

Supply. We obtain refined products primarily from eight suppliers, which consist primarily of large energy and petrochemicals companies.

Pricing Policy. Most of our contracts to purchase or sell refined products are at floating prices that are indexed to published rates in active markets. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives.

Billing and Collection Procedures. Our refined products customers consist primarily of large energy and petrochemicals companies. We typically invoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our refined products customers. We believe the following procedures enhance our collection efforts with our refined products customers:

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

·we require certain customers to post letters of credit on a portion of our receivables;

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

·we require our sales personnel to manage their customers’ receivable position and tie a portion of our sales personnel’s compensation to their ability to manage their accounts and minimize and collect past due balances.

Renewables

Overview. Our renewables business, including ethanol marketing and biodiesel marketing businesses, purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using 40 leased railcars operating primarily in Iowa, Oklahoma, Minnesota, Missouri, and Texas for sale to refiners and blenders. We also transport and market third-party owned ethanol for a service fee. In our ethanol business, we lease and sublease railcars. We lease 2.5 million gallons of biodiesel storage at a facility in Deer Park, Texas and have a terminaling agreement at a facility in Phoenix, Arizona, with a minimum monthly throughput requirement of one million gallons.

Customers. Our customers include crude oil refiners and blenders. Approximately 70% of the revenues from our renewables segment during the year ended March 31, 2014 related to our ten largest customers of the segment.

Competition. We face significant competition, as many entities are engaged in the renewables business, some of which are larger and have greater financial resources than we do. The primary factors on which we compete are:

·price;

·availability of supply;

·level and quality of service;

·available space on common carrier pipelines;

·the availability of railcars;

·proprietary terminals; and

·obtaining and retaining customers.

Supply. We obtain renewables from production facilities in the Midwest and in Houston, Texas.

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Pricing Policy. Most of our contracts to purchase or sell renewables are at floating prices that are indexed to published rates in active markets. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives.

Billing and Collection Procedures. Our renewables customers consist primarily of crude oil refiners and blenders. We typically invoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our refined products customers. We believe the following procedures enhance our collection efforts with our renewables customers:

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

·we require certain customers to post letters of credit on a portion of our receivables;

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

·we require our sales personnel to manage their customers’ receivable position and tie a portion of our sales personnel’s compensation to their ability to manage their accounts and minimize and collect past due balances.

Employees

At March 31, 2014, we had 2,500 full-time employees, of which 2,300 were operational and 200 were general and administrative. Fourteen of our employees at two of our locations are members of a labor union. We believe that our relations with our employees are satisfactory.

Government Regulation

Regulation of the Oil and Natural Gas Industries

Regulation of Oil and Natural Gas Exploration, Production and Sales. Sales of crude oil and natural gas liquids are not currently regulated and are transacted at market prices. In 1989, the United States Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. The Federal Energy Regulatory Commission (“FERC”), which has the authority under the Natural Gas Act to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all natural gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of natural gas in interstate commerce), however, could re-impose price controls in the future.

Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting, well location, methods of drilling, well operations, and conservation of resources. While these regulations do not directly apply to our business, they may affect the businesses of certain of our customers and suppliers and thereby indirectly affect our business.

Regulation of the Transportation and Storage of Natural Gas and Oil and Related Facilities. FERC regulates oil pipelines under the Interstate Commerce Act and natural gas pipeline and storage companies under the Natural Gas Act, and Natural Gas Policy Act of 1978 (the “NGPA”), as amended by the Energy Policy Act of 2005. While this regulation does not currently apply directly to our facilities, it may affect the price and availability of supply and thereby indirectly affect our business. Additionally, contracts we enter into for the transportation or storage of natural gas or oil are subject to FERC regulation including reporting or other requirements. In addition, the intrastate transportation and storage of oil and natural gas is subject to regulation by the state in which such facilities are located and such regulation can affect the availability and price of our supply and have both a direct and indirect effect on our business.

Anti-Market Manipulation Rules. We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, as amended by the Energy Policy Act of 2005, which authorizes FERC to impose fines of up to $1,000,000 per day per violation of the Natural Gas Act, the NGPA, or their implementing regulations. In addition, the Federal Trade Commission holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,000,000 per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The Commodity Futures Trading Commission is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the Commodity Futures Trading Commission has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The Commodity Futures

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Trading Commission also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per day per violation or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.

Maritime Transportation. The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels built and registered in the United States and owned and manned by United States citizens. Since we engage in maritime transportation through our barge fleet between locations in the United States, we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to insure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all United States-flagged vessels be manned by United States citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of United States-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by United States-flagged vessel owners. The United States Coast Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance costs for United States-flagged operators than for owners of vessels registered under foreign flags of convenience.

Environmental Regulation

General. Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. Accordingly, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

·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.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate.

The following is a discussion of the material environmental laws and regulations that relate to our business.

Hazardous Substances and Waste. We are subject to various federal, state, and local environmental, health and safety laws and regulations governing the storage, distribution and transportation of natural gas liquids and the operation of bulk storage LPG terminals, as well as laws and regulations governing environmental protection, including those addressing the discharge of materials into the environment or otherwise relating to protection of the environment or occupational health and safety. Generally, these laws (i) regulate air and water quality and impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) may result in the suspension or revocation of necessary permits, licenses and authorizations; (iv) impose substantial liabilities on us for pollution resulting from our operations; (v) require remedial measures to mitigate pollution from former or ongoing operations; (vi) and may result in the assessment of administrative, civil and criminal penalties for failure to comply with such laws. These laws include, among others, the Resource Conservation and Recovery Act (“RCRA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the Clean Air Act, the Occupational Safety and Health Act, the Homeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. For example, as a flammable substance, propane is subject to risk management plan requirements under section 112(r) of the Clean Air Act.

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CERCLA, also known as the “Superfund” law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. While propane is not a hazardous substance within the meaning of CERCLA, other chemicals used in or generated by our operations may be classified as hazardous. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict and joint and several liability for the costs of investigating and cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (“EPA”), most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of oil and natural gas, as well as petroleum-contaminated media, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. It is possible, however, that certain wastes now classified as non-hazardous could be classified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas wastes as “hazardous wastes.”  Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to implement remedial measures to prevent or mitigate future contamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations or financial condition.

Oil Pollution Prevention. Our operations involve the shipment of crude oil by barge through navigable waters of the United States. The Oil Pollution Prevention Act imposes liability for releases of oil from vessels or facilities into navigable waters. If a release of crude oil to navigable waters occurred during shipment or from a terminal, we could be subject to liability under the Oil Pollution Prevention Act. We are not currently aware of any facts, events, or conditions related to oil spills that could materially impact our operations or financial condition. In 1973, the EPA adopted oil pollution prevention regulations under the Clean Water Act. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. To be in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We maintain and implement such plans for our facilities.

Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations and, potentially, criminal enforcement actions. Furthermore, we may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.

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Water Discharges. The Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon or other constituent tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. We have discharge permits in place for a number of our facilities. These permits may require us to monitor and sample the storm water runoff from such facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Underground Injection Control.  Our underground injection operations are subject to the Safe Drinking Water Act, as well as analogous state laws and regulations, which establish requirements for permitting, testing, monitoring, record keeping, and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water.  Any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our permits, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties for property damages and personal injuries.

Hydraulic Fracturing. The underground injection of oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulic fracturing activities. However, a portion of our customers’ oil and natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process and our water solutions business treats and disposes of wastewater generated from natural gas production, including production utilizing hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of underground injection and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of the United States Congress. Congress will likely continue to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act’s Underground Injection Control Program and/or to require disclosure of chemicals used in the hydraulic fracturing process. Federal agencies, including the EPA and the United States Department of the Interior, have asserted their regulatory authority to, for example, study the potential impacts of hydraulic fracturing on the environment, and initiate rulemakings to compel disclosure of the chemicals used in hydraulic fracturing operations, and establish pretreatment standards for wastewater from hydraulic fracturing operations. In addition, several states, including Texas, Colorado and California, have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, which include additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and/or temporary or permanent bans on hydraulic fracturing. We expect that scrutiny of hydraulic fracturing activities will continue in the future.

Greenhouse Gas Regulation

There is a growing concern, both nationally and internationally, about climate change and the contribution of greenhouse gas emissions, most notably carbon dioxide, to global warming. In June 2009, the United States House of Representatives passed the ACES Act, also known as the Waxman Markey Bill. The ACES Act did not pass the United States Senate, however, and so was not enacted by the 111th Congress. The ACES Act would have established an economy-wide cap on emissions of greenhouse gases in the United States and would have required most sources of greenhouse gas emissions to obtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. More recently, the Climate Protection Act of 2013 was introduced in the United States Senate in February 2013. The Climate Protection Act of 2013 would introduce a carbon tax on all fossil fuels extracted, manufactured, produced in, or imported into the United States. The bill has not been advanced out of a United States Senate committee. The ultimate outcome of any possible future legislative initiatives is uncertain. In addition, several states have already adopted some legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs, although in recent years some states have scaled back their commitment to greenhouse gas initiatives.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allowed the EPA to adopt and implement regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has issued a number of regulations addressing greenhouse gas emissions under the Clean Air Act, including: the greenhouse gas reporting rule; greenhouse gas standards applicable to heavy-duty and light-duty vehicles; a rule requiring stationary sources to address greenhouse gas emissions in Prevention of Significant Deterioration and Title V permits; and new source performance standards for greenhouse gas emissions from new power plants. The EPA’s greenhouse gas permitting rule is currently being reviewed by the United States Supreme Court with a decision expected by June 2014. The outcome of the litigation is unknown. The EPA’s greenhouse gas regulations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations and also could adversely affect demand for the products that we transport, store, process, or otherwise handle in connection with our services.

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Some scientists have suggested climate change from greenhouse gases could increase the severity of extreme weather, such as increased hurricanes and floods, which could damage our facilities. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our natural gas liquids is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for our products and services. If there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, new climate change regulations may provide us with a competitive advantage over other sources of energy, such as fuel oil and coal.

The trend of more expansive and stringent environmental legislation and regulations, including greenhouse gas regulation, could continue, resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other governmental action is taken that restricts certain aspects of our business or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

Safety and Transportation

All states in which we operate have adopted fire safety codes that regulate the storage and distribution of propane and distillates. In some states, state agencies administer these laws. In others, municipalities administer them. We conduct training programs to help ensure that our operations comply with applicable governmental regulations. With respect to general operations, each state in which we operate adopts National Fire Protection Association (the “NFPA”), Pamphlet Nos. 54 and No. 58, or comparable regulations, which establish a set of rules and procedures governing the safe handling of propane, and Pamphlet Nos. 30, 30A, 31, 385 and 395 which establish rules and procedures governing the safe handling of distillates, such as fuel oil. We believe that the policies and procedures currently in effect at all of our facilities for the handling, storage and distribution of propane and distillates and related service and installation operations are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws.

With respect to the transportation of propane, distillates, crude oil, and water, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002.  Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the United States Department of Transportation (“DOT”).  Specifically, crude oil pipelines are subject to regulation by the DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the storage and transportation of hazardous liquids by and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. The Pipeline Safety Act of 1992 added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in high consequence areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, Congress required mandatory inspections for certain U.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management.

Railcar Regulation

We transport a significant portion of our natural gas liquids and crude oil via rail transportation, and we own and lease a fleet of railcars for this purpose. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies.

Occupational Health Regulations

The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Our marine vessel operations are also subject to safety and operational standards established and monitored by the United States Coast Guard. In general, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. However, these expenditures cannot be accurately estimated at this time, but we do not expect them to have a material adverse effect on our business.

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Available Information on our Website

Our website address is http://www.nglenergypartners.com. We make available on our website, free of charge, the periodic reports that we file with or furnish to the Securities and Exchange Commission (“SEC”), as well as all amendments to these reports, as soon as reasonably practicable after such reports are filed with or furnished to the SEC. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information related to issuers that file electronically with the SEC.

Item 1A.Risk Factors

We may not have sufficient cash to enable us to pay the minimum quarterly distribution to our unitholders following the establishment of cash reserves by our general partner and the payment of costs and expenses, including reimbursement of expenses to our general partner.

We may not have sufficient cash each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our common and subordinated units principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

·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.

In addition, the actual amount of cash we will have available for distribution also depends on other factors, some of which are beyond our control, including:

·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 indenture governing our outstanding 6.875% senior notes due 2021 (the “Indenture”) 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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The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we realize net income.

The amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we might make cash distributions during periods when we record net losses for financial accounting purposes and we might not make cash distributions during periods when we record net income for financial accounting purposes.

Our future financial performance and growth may be limited by our ability to successfully complete accretive acquisitions on economically acceptable terms.

Our ability to consummate acquisitions on economically acceptable terms may be limited by various factors, including, but not limited to:

·increased competition for attractive acquisitions;

·covenants in our Credit Agreement, Note Purchase Agreement and Indenture 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.

There can be no assurance that we will identify attractive acquisition candidates in the future, that we will be able to acquire such businesses on economically acceptable terms, that any acquisitions will not be dilutive to earnings and distributions or that any additional debt that we incur to finance an acquisition will not affect our ability to make distributions to unitholders. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

The propane industry is a mature industry. We anticipate only limited growth in total national demand for propane in the near future. Increased competition from alternative energy sources has limited growth in the propane industry, and year-to-year industry volumes are primarily impacted by fluctuations in weather and economic conditions. In addition, our retail propane business concentrates on sales to residential customers, but because of longstanding customer relationships that are typical in the retail residential propane industry, the inconvenience of switching tanks and suppliers, we may have difficulty in increasing our retail customer base other than through acquisitions. Therefore, while our business strategy includes expanding our existing retail propane operations through internal growth, our ability to grow within the retail propane business will depend principally on acquisitions.

We may be subject to substantial risks in connection with the integration and operation of acquired businesses, in particular those businesses with operations that are distinct and separate from our existing operations.

Any acquisitions we make in pursuit of our growth strategy are subject to potential risks, including, but not limited to:

·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;

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·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.

We undertake due diligence efforts in our assessment of acquisitions, but may be unable to identify or fully plan for all issues and risks attendant to a particular acquisition. Even when an issue or risk is identified, we may be unable to obtain adequate contractual protection from the seller. The realization of any of these risks could have a material adverse effect on the success of a particular acquisition or our financial condition, results of operations or future growth.

As part of our growth strategy, we may expand our operations into businesses that differ from our existing operations. Integration of new businesses is a complex, costly and time-consuming process and may involve assets with which we have limited operating experience. Failure to timely and successfully integrate acquired businesses into our existing operations may have a material adverse effect on our business, financial condition or results of operations. In addition to the risks set forth above, new businesses will subject us to additional business and operating risks, such as the acquisitions not being accretive to our unitholders as a result of decreased profitability, increased interest expense related to debt we incur to make such acquisitions or an inability to successfully integrate those operations into our overall business operation. The realization of any of these risks could have a material adverse effect on our financial condition or results of operations.

Debt we have incurred or will incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

Our level of debt could have important consequences to us, including the following:

·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.

Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic and weather conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our future indebtedness, we would be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms or at all. The agreements governing our indebtedness permit us to incur additional debt under certain circumstances, and we will likely need to incur additional debt in order to implement our growth strategy. We may experience adverse consequences from increased levels of debt.

Restrictions in our Credit Agreement, Note Purchase Agreement and Indenture could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and the value of our common units.

Our Credit Agreement, Note Purchase Agreement and Indenture limit our ability to, among other things:

·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;

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·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.

We are permitted to make distributions to our unitholders under our Credit Agreement, Note Purchase Agreement and Indenture as long as no default or event of default exists both immediately before and after giving effect to the declaration and payment of the distribution and the distribution does not exceed available cash for the applicable quarterly period. Our Credit Agreement, Note Purchase Agreement and Indenture also contain covenants requiring us to maintain certain financial ratios. Please read “Item 7 —Management’s Discussion and Analysis of Financial Condition and Results of Operations —Liquidity, Sources of Capital and Capital Resource Activities —Long-Term Debt.”

The provisions of our Credit Agreement, Note Purchase Agreement and Indenture may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our Credit Agreement could result in a covenant violation, default or an event of default that could enable our lenders, subject to the terms and conditions of our Credit Agreement, to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral we granted them to secure our debts. If the payment of our debt is accelerated, defaults under our other debt instruments, if any then exist, may be triggered, and our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our ability to make cash distributions at our intended levels.

Interest rates may increase in the future. As a result, interest rates on our existing and future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by our level of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make payments on our debt obligations and cash distributions at our intended levels.

Our business depends on the availability of supply of crude oil and natural gas liquids in the United States and Canada, which is dependent on the ability and willingness of other parties to explore for and produce crude oil and natural gas. Spending on crude oil and natural gas exploration and production may be adversely affected by industry and financial market conditions that are beyond our control including, without limitation, (1) prices for crude oil, condensate, and natural gas liquids, (2) crude oil and natural gas producers having success in their operations, (3) continued commercially viable areas in which to explore and produce crude oil and natural gas,  (4) the availability of liquids-rich natural gas needed to produce natural gas liquids, and (5) the availability of pipeline transportation and storage capacity.

Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business have been, and may continue to be, adversely affected by industry and financial market conditions and existing or new regulations, such as those related to environmental matters, that are beyond our control.

We depend on the ability and willingness of other entities to make operating and capital expenditures to explore for, develop, and produce oil and natural gas in the United States and Canada, and to extract natural gas liquids from natural gas as well as the availability of necessary pipeline transportation and storage capacity. Customers’ expectations of lower market prices for oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending, thereby reducing business opportunities and demand for our services and equipment. Actual market conditions and producers’ expectations of market conditions for crude oil, condensate and natural gas liquids may also cause producers to curtail spending, thereby reducing business opportunities and demand for our services.

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Industry conditions are influenced by numerous factors over which we have no control, such as the availability of commercially viable geographic areas in which to explore and produce oil and natural gas, the availability of liquids-rich natural gas needed to produce natural gas liquids, the supply of and demand for oil and natural gas, environmental restrictions on the exploration and production of oil and natural gas, such as existing and proposed regulation of hydraulic fracturing, domestic and worldwide economic conditions, political instability in oil and natural gas producing countries and merger and divestiture activity among our current or potential customers. The volatility of the oil and natural gas industry and the resulting impact on exploration and production activity could adversely impact the level of drilling activity. This reduction may cause a decline in business opportunities or the demand for our services, or adversely affect the price of our services. Reduced discovery rates of new oil and natural gas reserves in our market areas also may have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent existing production is not replaced.

The oil and natural gas production industry tends to run in cycles and may, at any time, cycle into a downturn; if that occurs again, the rate at which it returns to former levels, if ever, will be uncertain. Prior adverse changes in the global economic environment and capital markets and declines in prices for oil and natural gas have caused many customers to reduce capital budgets for future periods and have caused decreased demand for oil and natural gas. Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause customers to make additional reductions to capital budgets in the future even if commodity prices increase from current levels. These cuts in spending may curtail drilling programs and other discretionary spending, which could result in a reduction in business opportunities and demand for our services, the rates we can charge and our utilization. In addition, certain of our customers could become unable to pay their suppliers, including us. Any of these conditions or events could materially and adversely affect our operating results.

Our profitability could be negatively impacted by price and inventory risk related to our business.

The crude oil logistics, liquids, retail propane, refined products, and renewables businesses are “margin-based” businesses in which our realized margins depend on the differential of sales prices over our total supply costs. Our profitability is therefore sensitive to changes in product prices caused by changes in supply, pipeline transportation and storage capacity or other market conditions.

Generally, we attempt to maintain an inventory position that is substantially balanced between our purchases and sales, including our future delivery obligations. We attempt to obtain a certain margin for our purchases by selling our product to our customers, which include third-party consumers, other wholesalers and retailers, and others. However, market, weather or other conditions beyond our control may disrupt our expected supply of product, and we may be required to obtain supply at increased prices that cannot be passed through to our customers. In general, product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major storage points, creating the potential for sudden and drastic price fluctuations. Sudden and extended wholesale price increases could reduce our margins and could, if continued over an extended period of time, reduce demand by encouraging retail customers to conserve or convert to alternative energy sources. Conversely, a prolonged decline in product prices could potentially result in a reduction of the borrowing base under our working capital facility, and we could be required to liquidate inventory that we have already pre-sold.

We are affected by competition from other midstream, transportation, terminaling and storage and retail marketing companies, some of which are larger and more firmly established and may have greater marketing and development budgets and capital resources than we do.

We experience competition in all of our segments. In our liquids segment, we compete for natural gas supplies and also for customers for our services. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. Our natural gas liquids terminals compete with other terminaling and storage providers in the transportation and storage of natural gas liquids. Natural gas and natural gas liquids also compete with other forms of energy, including electricity, coal, fuel oil and renewable or alternative energy.

Our crude oil logistics segment faces significant competition for crude oil supplies and also for customers for our services. These operations also face competition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude oil terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

Our water solutions segment is in direct and indirect competition with other businesses, including disposal and other wastewater treatment businesses.

We face strong competition in the market for the sale of retail propane. Our competitors vary from retail propane companies who are larger and have substantially greater financial resources than we do to small retail propane distributors, rural electric cooperatives and fuel oil distributors who have entered the market due to a low barrier to entry. The actions of our retail marketing

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competitors, including the impact of imports, could lead to lower prices or reduced margins for the products we sell, which could have an adverse effect on our business or results of operations.

Our refined products and renewables segments also face significant competition for refined products and renewables supplies and also for customers for our services.

We can make no assurances that we will be able to compete successfully in each of our lines of business. If a competitor attempts to increase market share by reducing prices, we may lose customers, which would reduce our revenues.

Our business would be adversely affected if service at our principal storage facilities or on the common carrier pipelines we use is interrupted.

We use third-party common carrier pipelines to transport crude oil and natural gas liquids and we use third-party facilities to store natural gas liquids and ethanol. Any significant interruption in the service at these storage facilities or on the common carrier pipelines we use would adversely affect our ability to obtain propane.

Our business would be adversely affected if service on the railroads we use is interrupted.

We transport crude oil, natural gas liquids, ethanol, and biodiesel by railcar. We do not own or operate the railroads on which these cars are transported. Any disruptions in the operations of these railroads could adversely impact our ability to deliver product to our customers.

If we are unable to purchase product from our principal suppliers, our results of operations would be adversely affected.

If we are unable to purchase product from significant suppliers, our failure to obtain alternate sources of supply at competitive prices and on a timely basis would adversely affect our ability to satisfy customer demand, reduce our revenues and adversely affect our results of operations.

The fees charged to customers under our agreements with them for the transportation and marketing of crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel may not escalate sufficiently to cover increases in costs and the agreements may be suspended in some circumstances, which would affect our profitability.

Our costs may increase at a rate greater than the rate that the fees that we charge to customers increase pursuant to our contracts with them. Additionally, some customers’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of crude oil, condensate, and/or natural gas liquids are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities of our customers. If the escalation of fees is insufficient to cover increased costs or if any customer suspends or terminates its contracts with us, our profitability could be materially and adversely affected.

Our sales of crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel and related transportation and hedging activities, and our processing of wastewater, expose us to potential regulatory risks.

The Federal Trade Commission (“FTC”), the Federal Energy Regulatory Commission (“FERC”), and the Commodity Futures Trading Commission (“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of energy commodities, and any related transportation and/or hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Additionally, to the extent that we enter into transportation contracts with pipelines that are subject to the FERC regulation or we become subject to the FERC regulation ourselves (see —“Some of our operations could become subject to the jurisdiction of the FERC,” below), we will be obligated to comply with the FERC’s regulations and policies. Any failure on our part to comply with the FERC’s regulations and policies at that time could result in the imposition of civil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material and adverse effect on our business, results of operations and financial condition.

The intrastate transportation or storage of natural gas or crude oil is subject to regulation by the state in which the facilities and transactions occur and requires compliance with all such regulation. This state regulation can have a material and adverse effect on that portion of our business, results of operations and financial condition.

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The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) provides for statutory and regulatory requirements for derivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on exchanges and cash collateral will have to be posted. The Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end users and it includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and the parties to those transactions. Since the Dodd-Frank Act mandates the CFTC to promulgate rules to define these terms, we do not know the definitions the CFTC will actually adopt or how these definitions will apply to us. Although the CFTC established position limits on certain core futures and equivalent swaps contracts, with exceptions for certain bona fide hedging transactions, those limits were vacated by a federal district court on September 28, 2012, and will not go into effect until the CFTC prevails on appeal of this ruling, or issues and finalizes revised rules. Additionally, in December 2012, the CFTC published final rules regarding mandatory clearing of four classes of interest rate swaps and two classes of credit swaps and setting compliance dates of March 11, 2013, June 10, 2013, and, for end users of swaps, September 9, 2013. The full impact of the Dodd-Frank Act on our hedging activities is uncertain at this time. However, new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. The Dodd-Frank Act may also materially affect our customers and materially and adversely affect the demand for our services.

We are subject to the trucking safety regulations, which are likely to be amended, and made stricter, as part of the initiative known as Comprehensive, Safety, Analysis (“CSA”). If our current United States Department of Transportation (“DOT”) safety ratings are downgraded to “Unsatisfactory” or the equivalent in connection with this initiative, our business and results of our operations may be adversely affected.

As part of the CSA initiative, the Federal Motor Carrier Safety Administration (“FMCSA”) is expected to open a rulemaking docket for purposes of changing its safety rating methodology. Any new methodology adopted in the rulemaking is likely to link safety ratings more closely to roadside inspection and driver violation data gathered and analyzed from month to month under the agency’s new Safety Measurement System (“SMS”). This linkage could result in greater variability in safety ratings than the current system, in which a safety rating is based on relatively infrequent on-site compliance audits at a carrier’s place(s) of business. Preliminary studies by transportation consulting firms indicate that “Satisfactory” ratings (or any equivalent under a new SMS-based system) may become more difficult to achieve and maintain under such a system. If we ever receive an “Unsatisfactory” or equivalent rating, we may lose some of our customer contracts that require such a rating, which may materially and adversely affect our business prospects and results of operations.

Our business is subject to federal, state, provincial and local laws and regulations with respect to environmental, safety and other regulatory matters and the cost of compliance with, violation of or liabilities under, such laws and regulations could adversely affect our profitability.

Our operations, including those involving crude oil, condensate, natural gas liquids, and oil and gas produced wastewater, are subject to stringent federal, state, provincial and local laws and regulations relating to the protection of natural resources and the environment, health and safety, waste management, and transportation and disposal of such products and materials. We face inherent risks of incurring significant environmental costs and liabilities in the performance of our operations due to handling of wastewater and hydrocarbons, such as crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel. For instance, our wastewater treatment and transportation business carries with it environmental risks, including leakage from the treatment plants to surface or subsurface soils, surface water or groundwater, or accidental spills or releases during the transport of wastewater. Our crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel businesses carry similar risks of leakage and sudden or accidental spills of crude oil, condensate, natural gas liquids, and hydrocarbons. Liability under, or violation of, environmental laws and regulations could result in, among other things, the impairment or cancellation of operations, injunctions, fines and penalties, reputational damage, expenditures for remediation and liability for natural resource damages, property damage and personal injuries.

We use various modes of transportation to carry propane, distillates, crude oil and water, including trucks, railcars and barges, each of which is subject to regulation. With respect to transportation by truck, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002, which cover the security and transportation of hazardous materials and are administered by the DOT. We also own and lease a fleet of railcars, the operation of which is subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies. In response to recent train derailments occurring in the United States and Canada in 2013, United States regulators are implementing or considering new rules to address the safety risks of transporting crude oil by rail. On January 23, 2014, the National Transportation Safety Board issued a series of recommendations to address safety risks, and on February 25, 2014 the DOT issued an emergency order requiring all persons, prior to offering petroleum crude oil into transportation, to ensure such product

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is properly tested and classed. The introduction of these or other regulations that result in new requirements addressing the type, design, specifications or construction of railcars used to transport crude oil could result in severe transportation capacity constraints during the period in which new railcars are retrofitted or constructed to meet new specifications. Our barge transportation operations, which we acquired in 2012, are subject to the Jones Act, a federal law restricting marine transportation in the United States to vessels built and registered in the United States, and manned and owned by United States citizens, as well as rules and regulations of the United States Coast Guard. Non-compliance with any of these regulations could result in increased costs related to the transportation of our products and could have an adverse effect on our business.

In addition, under certain environmental laws, we could be subject to strict and/or joint and several liability for the investigation, removal or remediation of previously released materials. As a result, these laws could cause us to become liable for the conduct of others, such as prior owners or operators of our facilities, or for consequences of our or our predecessor’s actions, regardless of whether we were responsible for the release or if such actions were in compliance with all applicable laws at the time of those actions. Also, upon closure of certain facilities, such as at the end of their useful life, we have been and may be required to undertake environmental evaluations or cleanups.

Additionally, in order to conduct our operations, we must obtain and maintain numerous permits, approvals and other authorizations from various federal, state, provincial and local governmental authorities relating to wastewater handling, discharge and disposal, air emissions, transportation and other environmental matters. These authorizations subject us to terms and conditions which may be onerous or costly to comply with, and that may require costly operational modifications to attain and maintain compliance. The renewal, amendment or modification of these permits, approvals and other authorizations may involve the imposition of even more stringent and burdensome terms and conditions with attendant higher costs and more significant effects upon our operations.

Changes in environmental laws and regulations occur frequently. New laws or regulations, changes to existing laws or regulations, such as more stringent pollution control requirements or additional safety requirements, or more stringent interpretation or enforcement of existing laws and regulations, may unfavorably impact us, and could result in increased operating costs and have a material and adverse effect on our activities and profitability. For example, new or proposed laws or regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells may increase our costs for treatment of frac flow-back water (or affect our hydraulic fracturing customers’ ability to operate) and cause delays, interruption or termination of our water treatment operations, all of which could have a material and adverse effect on our operations and financial performance.

Furthermore, our customers in the oil and gas production industry are subject to certain environmental laws and regulations that may impose significant costs and liabilities on them, including as a result of changes in such laws and regulations causing them to become more stringent over time. For example, in April 2012, the EPA issued final rules that established new air emission controls for oil and gas production and gas processing operations. The final rule includes a 95% reduction in volatile organic compounds (“VOCs”) (which contribute to smog) emitted during the completion of new and modified hydraulically fractured wells. In August 2013, the EPA updated its 2012 air emission standards for crude oil and natural gas storage tanks to extend the compliance date and allow an alternate emissions limit of less than 4 tons per year without emission controls. Any significant increased costs or restrictions placed on our customers to comply with environmental laws and regulations could affect their production output significantly. Such an effect could materially and adversely affect our utilization and profitability, thus reducing demand for our midstream services. Such an effect on our customers could materially and adversely affect our utilization and profitability. The adoption or implementation of any new regulations imposing additional reporting obligations on greenhouse gas emissions, or limiting greenhouse gas emissions from our equipment and operations, could require us to incur significant costs.

Federal and state legislation and regulatory initiatives relating to our hydraulic fracturing customers could result in increased costs and additional operating restrictions or delays and could harm our business.

Hydraulic fracturing is a frequent practice in the oil and gas fields in which our water solutions segment operates. Hydraulic fracturing is an important and common process used to facilitate production of natural gas and other hydrocarbon condensates in shale formations, as well as tight conventional formations. The hydraulic fracturing process is typically regulated by state oil and gas authorities. This process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the fracturing process could adversely affect drinking water supplies. In addition, some have asserted that the fracturing process and/or the wastewater disposal process could result in increased seismic activity. New laws or regulations, or changes to existing laws or regulations in response to this perceived threat may unfavorably impact the oil and gas drilling industry. For instance, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices involving the use of diesel fuel under the Safe Drinking Water Act and its Underground Injection Control program. In February 2014, the EPA issued technical guidance for the permitting of the underground injection of diesel fuel for hydraulic fracturing activities. The EPA has also commenced a study of the potential environmental impact of hydraulic fracturing activities, the final results of which are expected in 2014. In addition, the United States

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Department of the Interior published a revised proposed rule on May 16, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. Also, legislation has been introduced, but not adopted, in Congress to provide for federal regulation of hydraulic fracturing. In addition, some states have adopted and other states are considering adopting regulations that could restrict or regulate hydraulic fracturing in certain circumstances. For example, some states have adopted legislation requiring the disclosure of hydraulic fracturing chemicals, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. We cannot predict whether any proposed federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require or prohibit. However, any restrictions on hydraulic fracturing could lead to operational delays or increased operating costs and regulatory burdens that could make it more difficult or costly to perform hydraulic fracturing which would negatively impact our customer base resulting in an adverse effect on our profitability.

Seasonal weather conditions and natural or man-made disasters could severely disrupt normal operations and have an adverse effect on our business, financial condition and results of operations.

We operate in various locations across the United States and Canada which may be adversely affected by seasonal weather conditions and natural or man-made disasters. During periods of heavy snow, ice, rain or extreme weather conditions such as high winds, tornados and hurricanes or after other natural disasters such as earthquakes or wildfires, we may be unable to move our trucks or railcars between locations and our facilities may be damaged, thereby reducing our ability to provide services and generate revenues. In addition, hurricanes or other severe weather in the Gulf Coast region could seriously disrupt the supply of products and cause serious shortages in various areas, including the areas in which we operate. These same conditions may cause serious damage or destruction to homes, business structures and the operations of customers. Such disruptions could potentially have a material adverse impact on our business, financial condition, results of operations and cash flows.

Risk management procedures cannot eliminate all commodity risk, basis risk, or risk of adverse market conditions which can adversely affect our financial condition and results of operations. In addition, any non-compliance with our risk policy could result in significant financial losses.

Pursuant to the requirements of our market risk policy, we attempt to lock in a margin for a portion of the commodities we purchase by selling such commodities for physical delivery to our customers, such as independent refiners or major oil companies, or by entering into future delivery obligations under contracts for forward sale. Through these transactions, we seek to maintain a position that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on the other hand. These policies and practices cannot, however, eliminate all risks. For example, any event that disrupts our anticipated physical supply of commodities could expose us to risk of loss resulting from the need to cover obligations required under contracts for forward sale. Additionally, we can provide no assurance that our processes and procedures will detect and/or prevent all violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of basis risk. In a backwardated market (when prices for future deliveries are lower than current prices), basis risk is created with respect to timing. In these instances, physical inventory generally loses value as price of such physical inventory declines over time. Basis risk cannot be entirely eliminated, and basis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our financial condition and results of operations.

The counterparties to our commodity derivative and physical purchase and sale contracts may not be able to perform their obligations to us, which could materially affect our cash flows and results of operations.

We encounter risk of counterparty non-performance in our businesses. Disruptions in the supply of product and in the oil and gas commodities sector overall for an extended or near term period of time could result in counterparty defaults on our derivative and physical purchase and sale contracts. This could impair our ability to obtain supply to fulfill our sales delivery commitments or obtain supply at reasonable prices, which could result in decreased gross margins and profitability, thereby impairing our ability to make payments on our debt obligations or distributions to our unitholders.

Our use of derivative financial instruments could have an adverse effect on our results of operations.

We have used derivative financial instruments as a means to protect against commodity price risk or interest rate risk and expect to continue to do so. We may, as a component of our overall business strategy, increase or decrease from time to time our use of such derivative financial instruments in the future. Our use of such derivative financial instruments could cause us to forego the economic benefits we would otherwise realize if commodity prices or interest rates were to change in our favor. In addition, although

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we monitor such activities in our risk management processes and procedures, such activities could result in losses, which could adversely affect our results of operations and impair our ability to make payments on our debt obligations or distributions to our unitholders.

Some of our operations could become subject to the jurisdiction of the FERC.

Any of our transportation services could in the future become subject to the jurisdiction of the FERC, which could adversely affect the terms of service, rates and revenues of such services. At the date of this Annual Report, our facilities do not fall under the FERC’s jurisdiction. Currently, the FERC regulates crude oil and natural gas pipelines, among other things. Intrastate transportation and gathering pipelines that do not provide interstate services are not subject to regulation by the FERC. However, the distinction between the FERC-regulated interstate pipeline transportation on the one hand and intrastate pipeline transportation on the other hand, is a fact-based determination. The classification and regulation of our crude oil pipelines are subject to change based on future determinations by the FERC, federal courts, Congress or regulatory commissions, courts or legislatures in the states in which we operate. Glass Mountain Pipeline, LLC (“Glass Mountain”), one of our joint ventures, owns a pipeline in Oklahoma that carries crude oil owned by us and by third parties. We believe that the pipeline segments on which Glass Mountain would provide service to third parties and the services it would provide to third parties on this pipeline system meet the traditional tests that the FERC has used to determine that the pipeline services provided are not in interstate commerce. However, we cannot provide assurance that the FERC will not in the future, either at the request of other entities or on its own initiative, determine that some or all of the pipeline and the services Glass Mountain will provide on that system are within its jurisdiction, or that such a determination would not adversely affect Glass Mountain’s or our results of operations. Further, if the FERC’s regulatory reach was expanded to our other facilities, or if we expand our operations into areas that are subject to the FERC’s regulation, we may have to commit substantial capital to comply with such regulations and such expenditures could have a material and adverse effect on our results of operations and cash flows.

Volumes of crude oil recovered during the wastewater treatment process can vary. Any significant reduction in residual crude oil content in wastewater we treat will affect our recovery of crude oil and, therefore, our profitability.

A significant portion of revenues in our water business is derived from sales of crude oil recovered during the wastewater treatment process. Our ability to recover sufficient volumes of crude oil is dependent upon the residual crude oil content in the wastewater we treat, which is, among other things, a function of water temperature. Generally, where water temperature is higher, residual crude oil content is lower. Thus, our crude oil recovery during the winter season is substantially higher than our recovery during the summer season. Additionally, residual crude oil content will decrease if, among other things, producers begin recovering higher levels of crude oil in produced wastewater prior to delivering such water to us for treatment. Any reduction in residual crude oil content in the wastewater we treat could materially and adversely affect our profitability.

Competition from alternative energy sources may cause us to lose customers, thereby negatively impacting our financial condition and results of operations.

Propane competes with other sources of energy, some of which are less costly for equivalent energy value. We compete for customers against suppliers of electricity, natural gas and fuel oil. Competition from alternative energy sources, including electricity and natural gas, has increased as a result of reduced regulation of many utilities. Electricity is a major competitor of propane, but propane has historically enjoyed a competitive price advantage over electricity. Except for some industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because such pipelines generally make it possible for the delivered cost of natural gas to be less expensive than the bulk delivery of propane. The expansion of natural gas into traditional propane markets has historically been inhibited by the capital cost required to expand distribution and pipeline systems; however, the gradual expansion of the nation’s natural gas distribution systems has resulted in natural gas being available in areas that previously depended on propane, which could cause us to lose customers, thereby reducing our revenues. Although propane is similar to fuel oil in some applications and market demand, propane and fuel oil compete to a lesser extent primarily because of the cost of converting from one to the other and due to the fact that both fuel oil and propane have generally developed their own distinct geographic markets.

We cannot predict the effect that development of alternative energy sources may have on our operations, including whether subsidies of alternative energy sources by local, state, and federal governments might be expanded, or what impact this might have on the supply of or the demand for crude oil, natural gas, and natural gas liquids.

Energy efficiency and new technology may reduce the demand for propane and adversely affect our operating results.

The national trend toward increased conservation and technological advances, such as installation of improved insulation and the development of more efficient furnaces and other heating devices, has adversely affected the demand for propane by retail customers. Future conservation measures or technological advances in heating, conservation, energy generation or other devices may

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reduce demand for propane. In addition, if the price of propane increases, some of our customers may increase their conservation efforts and thereby decrease their consumption of propane.

The majority of our retail propane operations are concentrated in the Northeast, Southeast, and Midwest, and localized warmer weather and/or economic downturns may adversely affect demand for propane in those regions, thereby affecting our financial condition and results of operations.

A substantial portion of our retail propane sales are to residential customers located in the Northeast, Southeast, and Midwest who rely heavily on propane for heating purposes. A significant percentage of our retail propane volume is attributable to sales during the peak heating season of October through March. Warmer weather may result in reduced sales volumes that could adversely impact our operating results and financial condition. In addition, adverse economic conditions in areas where our retail propane operations are concentrated may cause our residential customers to reduce their use of propane regardless of weather conditions. Localized warmer weather and/or economic downturns may have a significantly greater impact on our operating results and financial condition than if our retail propane business were less concentrated.

Reduced demand for refined products could have an adverse effect our results of operations.

Any sustained decrease in demand for refined products in the markets we serve could reduce our cash flow. Factors that could lead to a decrease in market demand include:

·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.

Recent attempts to reduce or eliminate the Renewable Fuels Standard, if successful, could unfavorably impact our results of operations.

The United States renewables industry is highly dependent on several federal and state incentives which promote the use of renewable fuels. Without these incentives, demand for and the price of renewable fuels could be negatively impacted which could have an adverse effect on our results of operations. The most significant of the federal and state incentives which benefit renewable products we market, such as ethanol and biodiesel, is the federal Renewable Fuels Standard (“RFS”). The RFS requires that an increasing amount of renewable fuels must be blended with petroleum-based fuels each year in the United States. However, the EPA has authority to waive the requirements of the RFS, in whole or in part, provided one of two conditions is met. The conditions are: (1) there is inadequate domestic renewable fuel supply; or (2) implementation of the requirement would severely harm the economy or environment of a state, region or the United States. Opponents of the RFS are seeking to force the EPA to reduce or eliminate the RFS. Further, several pieces of legislation have been introduced with the goal of significantly reducing or eliminating the RFS. While the outcome of these legislative efforts is uncertain, it is possible that the EPA could adjust the RFS requirements in the future. If the EPA were to adjust the RFS requirements in any material way, it could negatively impact demand for the renewable fuel products we market, which could unfavorably impact our results of operations.

A loss of one or more significant customers could materially or adversely affect our results of operations.

Approximately 37% of the revenues of our water solutions segment during the year ended March 31, 2014 were generated from our two largest customers of the segment. Approximately 60% of the revenues of our crude oil logistics segment during the year ended March 31, 2014 were generated from our ten largest customers of the segment. Approximately 35% of the revenues of our liquids segment were generated from our ten largest customers of the segment. Approximately 41% of the revenues of our refined products segment were generated from our ten largest customers of the segment. Approximately 70% of the revenues of our renewables segment were generated from our ten largest customers of the segment. For the year ended March 31, 2014, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. We expect to continue to depend on key customers to support our revenues for the foreseeable future. The loss of key customers, failure to renew contracts

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upon expiration, or a sustained decrease in demand by key customers could result in a substantial loss of revenues and could have a material and adverse effect on our results of operations.

Certain of our operations are conducted through joint ventures which have unique risks.

Certain of our operations are conducted through joint ventures. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Differences in views among the partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations. From time to time, our joint ventures may be involved in disputes or legal proceedings which may negatively affect our investments. Accordingly, any such occurrences could adversely affect our financial condition, operating results and cash flows.

Growing our business by constructing new transportation systems and facilities subjects us to construction risks and risks that supplies for such systems and facilities will not be available upon completion thereof.

One of the ways we intend to grow our business is through the construction of additions to our systems and/or the construction of new terminaling, transportation, and wastewater treatment facilities. The construction of such facilities requires the expenditure of significant amounts of capital, which may exceed our resources, and involves numerous regulatory, environmental, political and legal uncertainties. If we undertake these projects, we may not be able to complete them on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase upon the expenditure of funds on a particular project. For instance, if we build a new wastewater treatment facility, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until at least after completion of the project, if at all. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which anticipated production growth does not materialize or for which we are unable to acquire new customers. We may also rely on estimates of proved, probable or possible reserves in our decision to build new transportation systems and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved, probable or possible reserves. As a result, new facilities may not be able to attract enough product to achieve our expected investment return, which could materially and adversely affect our results of operations and financial condition.

Product liability claims and litigation could adversely affect our business and results of operations.

Our operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with combustible liquids. As a result, we are subject to product liability claims and lawsuits, including potential class actions, in the ordinary course of business. Any product liability claim brought against us, with or without merit, could be costly to defend and could result in an increase of our insurance premiums. Some claims brought against us might not be covered by our insurance policies. In addition, we have self-insured retention amounts which we would have to pay in full before obtaining any insurance proceeds to satisfy a judgment or settlement and we may have insufficient reserves on our balance sheet to satisfy such self-retention obligations. Furthermore, even where the claim is covered by our insurance, our insurance coverage might be inadequate and we would have to pay the amount of any settlement or judgment that is in excess of our policy limits. We may not be able to obtain insurance on terms acceptable to us or at all since insurance varies in cost and can be difficult to obtain. Our failure to maintain adequate insurance coverage or successfully defend against product liability claims could materially and adversely affect our business, results of operations, financial condition and cash flows.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk related to operational system flaws, and employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations sectors, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse effect on our business. In addition, cyber-attacks on our customer and employee data may result in a financial loss, including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which we rely could also suffer

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operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

We do not own all of the land on which our facilities are located, and instead lease certain facilities and equipment, and we, therefore, are subject to the possibility of increased costs to retain necessary land and equipment use which could disrupt our operations.

We do not own all of the land on which our facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased costs to retain necessary land use if we do not have valid rights-of-way or if our facilities are not properly located within the boundaries of such rights-of-way. Additionally, our loss of rights, through our inability to renew right-of-way contracts or otherwise, could materially and adversely affect our business, results of operations and financial condition.

Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods, including many of our railcars. Our inability to renew facility or equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material and adverse effect on our results of operations and cash flows.

We also must operate within the terms and conditions of permits and various rules and regulations from the United States Bureau of Land Management for the rights of way on which our pipelines are constructed and the Wyoming State Engineer’s Office for water well, disposal well and containment pits.

Difficulty in attracting and retaining qualified drivers could adversely affect our growth and profitability.

Maintaining a staff of qualified truck drivers is critical to the success of our operations. We have in the past experienced difficulty in attracting and retaining sufficient numbers of qualified drivers. In addition, due in part to current economic conditions, including the cost of fuel, insurance, and tractors and the DOT regulatory requirements, the available pool of qualified truck drivers has been declining. Regulatory requirements, including the FMCSA’s CSA initiative, and an improvement in the economy could reduce the number of eligible drivers or require us to pay more to attract and retain drivers. A shortage of qualified drivers and intense competition for drivers from other companies will create difficulties in increasing the number of our drivers for our anticipated expansion in our fleet of trucks. If we are unable to continue to attract and retain a sufficient number of qualified drivers, we could have difficulty meeting customer demands, any of which could materially and adversely affect our growth and profitability.

If we fail to maintain an effective system of internal controls, including internal controls over financial reporting, we may be unable to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We are also subject to the obligation under Section 404(a) of the Sarbanes Oxley Act of 2002 to annually review and report on our internal control over financial reporting, and to the obligation under Section 404(b) of the Sarbanes Oxley Act to engage our independent registered public accounting firm to attest to the effectiveness of our internal controls over financial reporting.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly traded partnership. Our efforts to maintain our internal controls may be unsuccessful, and we may be unable to maintain effective controls over financial reporting, including our disclosure controls. Any failure to maintain effective internal controls over financial reporting and disclosure controls could harm our operating results or cause us to fail to meet our reporting obligations. These risks may be heightened after a business combination, during the phase when we are implementing our internal control structure over the recently-acquired business.

Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm’s, conclusions about the effectiveness of internal controls in the future, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls could subject us to regulatory scrutiny and a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

An impairment of goodwill and intangible assets could reduce our earnings.

At March 31, 2014, we had reported goodwill and intangible assets of $1.8 billion. Such assets are subject to impairment reviews on an annual basis, or at an interim date if information indicates that such asset values have been impaired. Any impairment we would be required to record in our financial statements would result in a charge to our income, which would reduce our earnings.

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Our business requires extensive credit risk management that may not be adequate to protect against customer non-payment.

Our credit management procedures may not fully eliminate the risk of non-payment by our customers. We manage our credit risk exposure through credit analysis, credit approvals, establishing credit limits, requiring prepayments (partially or wholly), requiring product deliveries over defined time periods, and credit monitoring. While we believe our procedures are effective, we can provide no assurance that bad debt write-offs in the future may not be significant and any such non-payment problems could impact our results of operations and potentially limit our ability to make payments on our debt obligations or distributions to our unitholders.

Our terminaling operations depend on pipelines to transport crude oil and natural gas liquids.

We own 22 natural gas liquids terminals and seven crude oil terminals. These facilities depend on pipeline and storage systems that are owned and operated by third parties. Any interruption of service on the pipeline or lateral connections or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport product to and from our facilities and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities affect the utilization and value of our terminals. We have historically been able to pass through the costs of pipeline transportation to our customers. However, if competing pipelines do not have similar annual tariff increases or service fee adjustments, such increases could affect our ability to compete, thereby adversely affecting our revenues.

Our marketing operations depend on the availability of transportation and storage capacity.

Our product supply is transported and stored on facilities owned and operated by third parties. Any interruption of service on the pipeline or storage companies or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation affects the profitability of our operations.

The financial results of our natural gas liquids businesses are seasonal and generally lower in the first and second quarters of our fiscal year, which may require us to borrow money to make distributions to our unitholders during these quarters.

The natural gas liquids inventory we have pre-sold to customers is highest during summer months, and our cash receipts are lowest during summer months. As a result, our cash available for distribution for the summer is much lower than for the winter. With lower cash flow during the first and second fiscal quarters, we may be required to borrow money to pay distributions to our unitholders during these quarters. Any restrictions on our ability to borrow money could restrict our ability to pay the minimum quarterly distributions to our unitholders.

A significant increase in fuel prices may adversely affect our transportation costs.

Fuel is a significant operating expense for us in connection with the delivery of products to our customers. A significant increase in fuel prices will result in increased transportation costs to us. The price and supply of fuel is unpredictable and fluctuates based on events we cannot control, such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil producing countries and regions, regional production patterns and weather concerns. As a result, any increases in these prices may adversely affect our profitability and competitiveness.

Some of our operations cross the United States/Canada border and are subject to cross-border regulation.

Our cross-border activities subject us to regulatory matters, including import and export licenses, tariffs, Canadian and United States customs and tax issues and toxic substance certifications. Such regulations include the “Short Supply Controls” of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant administrative, civil and criminal penalties.

The risk of terrorism and political unrest in various energy producing regions may adversely affect the economy and the price and availability of products.

An act of terror in any of the major energy producing regions of the world could potentially result in disruptions in the supply of crude oil and natural gas, the major sources of propane, which could have a material impact on the availability and price of propane. Terrorist attacks in the areas of our operations could negatively impact our ability to transport propane to our locations. These risks could potentially negatively impact our results of operations.

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We depend on the leadership and involvement of key personnel for the success of our businesses.

We have certain key individuals in our senior management who we believe are critical to the success of our business. The loss of leadership and involvement of those key management personnel could potentially have a material adverse impact on our business and possibly on the market value of our units.

Risks Inherent in an Investment in Us

Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise be breaches of fiduciary duty.

Fiduciary duties owed to our unitholders by our general partner are prescribed by law and our partnership agreement. The Delaware Revised Uniform Limited Partnership Act (“Delaware LP Act”), provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

·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;

·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;

·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 totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us; and

·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.

By purchasing a common unit, a common unitholder will become bound by the provisions of our partnership agreement, including the provisions described above.

Our general partner and its affiliates have conflicts of interest with us and limited fiduciary duties to our unitholders, and they may favor their own interests to the detriment of us and our unitholders.

The NGL Energy GP Investor Group owns and controls our general partner and its 0.1% general partner interest in us. Although our general partner has certain fiduciary duties to manage us in a manner beneficial to us and our unitholders, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Furthermore, since certain executive officers and directors of our general partner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between the NGL Energy GP Investor Group and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders (see “— Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts the remedies available to our unitholders for actions taken by

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our general partner that might otherwise be breaches of fiduciary duty,” above). The risk to our unitholders due to such conflicts may arise because of the following factors, among others:

·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 and the ability of the subordinated units to convert to common units;

·our general partner determines which costs incurred by it are reimbursable by us;

·our general partner may cause us to borrow funds to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive 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 on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;

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

·our general partner intends to limit its liability regarding our contractual and other obligations;

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

·our general partner controls the enforcement of the obligations that it and its affiliates owe to us;

·our general partner decides whether to retain separate counsel, accountants or others to perform services for us; 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 incentive distribution rights 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.

In addition, certain members of the NGL Energy GP Investor Group and their affiliates currently hold interests in other companies in the energy and natural resource sectors. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, members of the NGL Energy GP Investor Group are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, they could potentially compete with us for acquisition opportunities and for new business or extensions of the existing services provided by us.

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have

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any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

Even if our unitholders are dissatisfied, they have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have limited ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by our general partner (which approval may be granted in its sole discretion) and persons who acquired such units with the prior approval of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without the consent of our unitholders.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of the NGL Energy GP Investor Group to transfer all or a portion of their ownership interest in our general partner to a third party. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.

The incentive distribution rights of our general partner may be transferred to a third party.

Prior to the first day of the first quarter beginning after the 10th anniversary of the closing date of our IPO, a transfer of incentive distribution rights (“IDRs”) by our general partner requires (except in certain limited circumstances) the consent of a majority of our outstanding common units (excluding common units held by our general partner and its affiliates). However, after the expiration of this period, our general partner may transfer its IDRs to a third party at any time without the consent of our unitholders. If our general partner transfers its IDRs to a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its IDRs.

Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it may assign to any of its affiliates or to us, but not the obligation, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price that is not less than their then-current market price, as calculated pursuant to the terms of our partnership agreement. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Our unitholders may also incur a tax liability upon a sale of their units.

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Cost reimbursements to our general partner may be substantial and could reduce our cash available to make quarterly distributions to our unitholders.

Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on our behalf, which will be determined by our general partner in its sole discretion in accordance with the terms of our partnership agreement. In determining the costs and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires it to act in good faith. These expenses will include all costs incurred by our general partner and its affiliates in managing and operating us. We are managed and operated by executive officers and directors of our general partner. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates, will reduce the amount of cash available for distribution to our unitholders.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

We expect that we will distribute all of our available cash to our unitholders and will rely primarily on external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, as well as reserves we have established to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or our Credit Agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

We may issue additional units without the approval of our unitholders, which would dilute the interests of existing unitholders.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. Our issuance of additional common units or other equity securities of equal or senior rank will have the following effects:

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

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

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

·the ratio of taxable income to distributions may increase;

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

·the market price of the common units may decline.

Our general partner, without the approval of our unitholders, may elect to cause us to issue common units while also maintaining its general partner interest in connection with a resetting of the target distribution levels related to its incentive distribution rights. This could result in lower distributions to our unitholders.

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its IDRs at the highest level to which it is entitled (48.1%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled

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their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the IDRs in the prior two quarters. We anticipate that our general partner would exercise this reset right to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its IDRs based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner interests to our general partner in connection with resetting the target distribution levels.

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

·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.

Our unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware LP Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interests nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware LP Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. We could lose our status as a partnership for a number of reasons, including not having enough “qualifying income.”  If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, a publicly traded partnership such as us will be treated as a corporation for federal income tax purposes unless, for each taxable year, 90% or more of its gross income is “qualifying income” under Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”). “Qualifying income” includes income and gains derived from the exploration, development, production, processing, transportation, storage and marketing of natural gas, natural gas products, and crude oil or other passive types of income such as certain interest and dividends and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. Although we do not believe based upon our current operations that we are treated as a corporation, we could be treated as a corporation for federal income tax purposes or otherwise subject to taxation as an entity if our gross income is not properly classified as qualifying income, there is a change in our business or there is a change in current law.

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If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of the United States Congress propose and consider substantive changes to the existing United States federal income tax laws that affect the tax treatment of publicly traded partnerships. Members of Congress have recently proposed substantive changes to the existing U.S. tax laws that would affect certain publicly traded partnerships, if such proposals are enacted into law. We are unable to predict whether any such change or other proposals will ultimately be enacted or will affect our tax treatment. Any modification to the income tax laws and interpretations thereof may or may not be applied retroactively and could, among other things, cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Moreover, such modifications and change in interpretations may affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. Although we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted, any such changes could negatively impact the value of an investment in our common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because we expect to be treated as a partnership for United States federal income tax purposes, our unitholders will be treated as partners to whom we will allocate taxable income that could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the

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units the unitholder sells will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sell units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

Tax-exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (known as IRAs), Keogh plans and other retirement plans and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-United States person, you should consult your tax advisor before investing in our common units.

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to tax returns of unitholders.

We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate level income taxes.

We conduct a portion of our operations through subsidiaries that are corporations for federal income tax purposes. We may elect to conduct additional operations in corporate form in the future. Our corporate subsidiaries will be subject to corporate level tax, which will reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that our corporate subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

We prorate our items of income, gain, loss and deduction for United States federal income tax purposes between transferors and transferees of our units each month based on the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based on the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The United States Treasury Department, however, has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Therefore, the use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to affect a short sale of units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by

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the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies and monthly conventions for United States federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of our unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties for failure to file a timely return if we are unable to determine that a technical termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

There are limits on the deductibility of our losses that may adversely affect our unitholders.

There are a number of limitations that may prevent unitholders from using their allocable share of our losses as a deduction against unrelated income. In cases where our unitholders are subject to the passive loss rules (generally, individuals and closely-held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years but not by losses from other passive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by a unitholder include the at-risk rules and the prohibition against loss allocations in excess of the unitholder’s tax basis in its units.

Purchasers of our common units may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

In addition to federal income taxes, holders of our common units are subject to other taxes, including foreign, state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own or control property now or in the future. Holders of our common units are required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions and may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in a number of states, most of which impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional states that impose a personal income tax.

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Item 1B.Unresolved Staff Comments

None.

Item 2.Properties

Overview. We believe that we have satisfactory title or valid rights to use all of our material properties. Although some of these properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements entered into in connection with acquisitions and other encumbrances, easements and restrictions, we do not believe that any of these burdens will materially interfere with our continued use of these properties in our business, taken as a whole. Our obligations under our credit facilities are secured by liens and mortgages on substantially all of our real and personal property.

Other than as described below, we believe that we have all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local governmental and regulatory authorities that relate to ownership of our properties or the operations of our business.

One of our facilities acquired in the High Sierra merger is operating with all but one of the required permits, as the State of Wyoming has not yet developed a process for issuing permits of this type. We believe that the permit will ultimately be granted, but we are unable to determine the timing of any action by the State of Wyoming.

Our corporate headquarters are in Tulsa, Oklahoma and are leased. We also lease corporate offices in Denver, Colorado and Houston, Texas.

For additional information regarding our properties and the reportable segments in which they are used, see “Item 1 — Business.”

Item 3.Legal Proceedings

We are involved from time to time in various legal proceedings and claims arising in the ordinary course of business. For information related to legal proceedings, please see the discussion under the caption “Legal Contingencies” in Note 10 to our audited consolidated financial statements in Part IV, Item 15 of this Annual Report, which information is incorporated by reference into this Item 3.

Item 4.Mine Safety Disclosures

Not Applicable.

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PART II

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

Market Information

Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “NGL.”  Our common units began trading on the NYSE on May 12, 2011. Prior to May 12, 2011, our common units were not listed on any exchange or traded in any public market.

At May 23, 2014, there were 239 common unitholders of record. This number does not include unitholders for whom common units may be held in “street name.”  We have also issued 5,919,346 subordinated units, for which there is no established public trading market. All of the subordinated units are held by the members of the NGL Energy LP Investor Group.

The following table sets forth, for the periods indicated, the high and low closing prices per common unit, as reported on the New York Stock Exchange Composite Transactions tape, and the amount of cash distributions paid per common unit.

	Price Range				Cash
2014 Fiscal Year	High		Low		Distribution
Fourth Quarter	$	37.72	$	33.45	$	0.5313
Third Quarter	34.50		30.43		0.5113
Second Quarter	33.73		28.21		0.4938
First Quarter	30.37		26.65		0.4775

	Price Range				Cash
2013 Fiscal Year	High		Low		Distribution
Fourth Quarter	$	26.90	$	22.64	$	0.4625
Third Quarter	25.16		21.26		0.4500
Second Quarter	26.67		22.11		0.4125
First Quarter	23.50		20.15		0.3625

Cash Distribution Policy

Available Cash

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. Available cash, for any quarter, generally consists of all cash on hand at the end of that quarter less the amount of cash reserves established by our general partner to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.

Minimum Quarterly Distribution

Our partnership agreement provides that, during the subordination period, the common units are entitled to distributions of available cash each quarter in an amount equal to the minimum quarterly distribution, which is $0.3375 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution.

The subordination period will end on the first business day after we have earned and paid the minimum quarterly distribution on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner interest for each of three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2014 which we expect to occur in August 2014. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the subordination period lapses or otherwise terminates, all

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remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

General Partner Interest

Our general partner is entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. Our general partner’s interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the IDRs) and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest.

Incentive Distribution Rights

Our general partner also currently holds incentive distribution rights (“IDRs”) which represent a variable interest in our distributions. IDRs entitle our general partner to receive increasing percentages, up to a maximum of 48.1%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of $0.388125 per unit per quarter. The maximum distribution of 48.1% includes distributions paid to our general partner on its 0.1% general partner interest and assumes that our general partner maintains its general partner interest at 0.1%. The maximum distribution of 48.1% does not include any distributions that our general partner may receive on common units or subordinated units that it owns.

Restrictions on the Payment of Distributions

As described in Note 8 to our consolidated financial statements included in this Annual Report, our Credit Agreement contains covenants limiting our ability to pay distributions if we are in default under the Credit Agreement and to pay distributions that are in excess of available cash, as defined in the Credit Agreement.

Sales of Unregistered Securities

During the fiscal year ended March 31, 2014, we completed three acquisitions in which we issued unregistered common units as part of the consideration for the acquisitions. All of these units were issued in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act, as the units were issued to the owners of businesses acquired in privately negotiated transactions not involving any public offering or solicitation. On July 1, 2013, we issued 175,211 common units to the sellers of Crescent Terminals, LLC and Cierra Marine, LP. On August 1, 2013, we issued 2,463,287 common units to the sellers of entities affiliated with Oilfield Water Lines, LP. On September 3, 2013, we issued 222,381 common units to the sellers of Coastal Plains Disposal #1, LLC.

On October 16, 2013, we completed the sale to a group of financial institutions, for which RBC Capital Markets, LLC acted as representative (collectively, the “Initial Purchasers”), of $450.0 million aggregate principal amount of 6.875% Senior Notes due 2021 (the “Unsecured Notes”) of the Partnership and its subsidiary NGL Energy Finance Corp. (collectively, the “Issuers”). The Initial Purchasers resold the Unsecured Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act, and to persons outside of the United States pursuant to Regulation S under the Securities Act. The Unsecured Notes were sold at par, and the Issuers received approximately $439.4 million of net proceeds from the sale of the Unsecured Notes.

On December 2, 2013, we issued and sold 8,110,848 common units in a private placement at a price of $29.59 per common unit for aggregate consideration of $240.0 million. This sale of common units was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof, as a transaction by an issuer not involving any public offering.

Securities Authorized for Issuance Under Equity Compensation Plans

In connection with the completion of our initial public offering, our general partner adopted the NGL Energy Partners LP Long-Term Incentive Plan. Please see “Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters — Securities Authorized for Issuance Under Equity Compensation Plan” which is incorporated by reference into this Item 5.

Item 6.Selected Financial Data

We were formed on September 8, 2010, but had no operations through September 30, 2010. In October 2010, we acquired the assets and operations of NGL Supply and Hicksgas. We do not have our own historical financial statements for periods prior to our

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formation. The following table shows selected historical financial and operating data for NGL Energy Partners LP and NGL Supply (the deemed acquirer for accounting purposes in our formation) for the periods and as of the dates indicated. The financial statements of NGL Supply became our historical financial statements for all periods prior to October 1, 2010. The following table should be read in conjunction with “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes included in this Annual Report.

The selected consolidated historical financial data (excluding volume information) at March 31, 2014 and 2013 and for each of the three years in the period ended March 31, 2014 are derived from our audited historical consolidated financial statements included in this Annual Report. The selected consolidated historical financial data (excluding volume information) at March 31, 2012 and 2011 and for the six months ended March 31, 2011 are derived from our financial records. The selected consolidated historical financial data (excluding volume information) at September 30, 2010 and for the six months then ended and at March 31, 2010 and for the year then ended are derived from the financial records of NGL Supply.

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	NGL Energy Partners LP								NGL Supply, Inc.
							Six Months Ended		Six Months Ended			Year Ended
	Year Ended March 31,						March 31,		September 30,			March 31,
	2014		2013		2012		2011		2010			2010
	(in thousands, except per unit data)
Income Statement Data (1)
Total revenues	$	9,699,274	$	4,417,767	$	1,310,473	$	622,232	$	316,943		$	735,506
Total cost of sales	9,132,699		4,039,110		1,217,023		583,032		310,908			708,215
Operating income (loss)	106,565		87,307		15,030		14,837		(3,795		)	6,661
Interest expense	58,854		32,994		7,620		2,482		372			668
Loss on early extinguishment of debt	—		5,769		—		—		—			—
Net income (loss) attributable to parent equity	47,655		47,940		7,876		12,679		(2,515		)	3,636
Basic and diluted earnings per common unit	0.51		0.96		0.32		1.16
Basic earnings (loss) per common share									(128.46		)	178.75
Diluted earnings (loss) per common share									(128.46		)	176.61
Cash Flows Data (1)
Cash flows from operating activities	$	85,236	$	132,634	$	90,329	$	34,009	$	(30,749	)	$	7,480
Cash distributions paid per common unit (subsequent to IPO)	2.01		1.69		0.85
Cash distributions per common unit (prior to IPO)					0.35		—
Cash distributions paid per common share									357.09			—
Capital expenditures:
Purchases of long-lived assets	165,148		72,475		7,544		1,440		280			582
Acquisitions of businesses, including additional consideration paid on prior period acquisitions	1,268,810		490,805		297,401		17,400		123			3,113
Balance Sheet Data - Period End (1)
Total assets	$	4,167,223	$	2,291,618	$	749,519	$	163,833	$	148,596		$	111,580
Total long-term obligations, exclusive of current maturities	1,639,578		742,641		199,389		65,936		18,940			8,851
Redeemable preferred stock	—		—		—		—		—			3,000
Total equity	1,531,853		889,418		405,329		47,353		36,811			46,403
Volume Information (1)
Retail propane and distillates sold (gallons)	197,326		173,232		79,886		34,932		3,747			15,514
Wholesale propane sold (gallons) (2)	1,190,106		912,625		659,921		372,504		226,330			623,510
Wholesale other products sold (gallons)	786,671		505,529		134,999		49,465		46,092			53,878
Crude oil sold (barrels)	46,107		24,373		—		—		—			—
Water delivered (barrels)	62,774		25,009		—		—		—			—
Refined products sold (gallons)	412,974		—		—		—		—			—
Renewables sold (gallons)	150,925		—		—		—		—			—

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

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

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

Overview

We are a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. As part of our formation, we acquired and combined the assets and operations of NGL Supply, which was primarily a wholesale propane and terminaling business that was founded in 1967, and Hicksgas, which was primarily a retail propane business that was founded in 1940. We completed an initial public offering (“IPO”) in May 2011. At the time of our IPO, we owned and operated retail propane and wholesale natural gas liquids businesses. Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, as described under Part I, Item 1, “Business — Acquisitions Subsequent to Initial Public Offering.”

At March 31, 2014, our primary businesses include:

·A crude oil logistics business, the assets of which include crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

·A water solutions business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons.

·Our liquids business, 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 services through its 22 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids business purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets.

·Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.

We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon Energy.

Crude Oil Logistics

Our crude oil logistics business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. We attempt to reduce our exposure to price fluctuations by using back-to-back contracts whenever possible. In addition, we enter into forward contracts, financial swaps, and commodity spread trades as economic hedges of our physical forward sales and purchase contracts with our customers and suppliers.

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Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets, such as Cushing, Oklahoma. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives. We utilize our transportation assets to move crude oil from the wellhead to the highest value market. The spread between crude oil prices in different markets can fluctuate widely, which may expand or limit our opportunity to generate margins by transporting crude oil to different markets. We also seek to maximize margins by blending crude oil of varying properties.

The range of low and high spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma and the prices at period end were as follows:

	Spot Price Per Barrel
					At Period
Year Ended:	Low		High		End
March 31, 2014	$	86.68	$	110.53	$	101.58
March 31, 2013	77.69		106.16		97.23

We believe volatility in commodity prices will continue, and our ability to adjust and manage this volatility may impact our financial results.

Water Solutions

Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. Our water processing facilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutions segment is the extent of exploration and production in the areas near our facilities, which is based upon producers’ expectations about the profitability of drilling new wells. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume of water to our facility under long-term contracts. The primary customers of our facilities in Colorado have committed to deliver to our facilities all wastewater produced at wells in a designated area. Most of the customers at our other facilities in Texas are not under volume commitments, other than one customer that has committed to deliver 50,000 barrels per day to our facilities.

Liquids

Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, petrochemical plants, and other participants in the wholesale markets. Our liquids segment owns 22 terminals and operates a fleet of owned and leased railcars and leases underground storage capacity. We attempt to reduce our exposure to the impact of price fluctuations by using back-to-back contracts and pre-sale agreements that allow us to lock in a margin on a percentage of our winter volumes. We also attempt to reduce our exposure to the impact of price fluctuations by entering into swap agreements whereby we agree to pay a floating rate and receive a fixed rate on a specified notional amount of product. We enter into these agreements as economic hedges against the potential decline in the value of a portion of our inventory.

Our wholesale business is a “cost-plus” business that is affected both by price fluctuations and volume variations. We establish our selling price based on a pass-through of our product supply, transportation, handling, storage and capital costs plus an acceptable margin. The margins we realize in our wholesale business are substantially less on a per gallon basis than our retail propane business.

Weather conditions and gasoline blending have a significant impact on the demand for propane and butane, and sales volumes and prices are typically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

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The range of low and high spot propane prices per gallon at Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, and the prices at period end were as follows:

	Conway, Kansas						Mt. Belvieu, Texas
	Spot Price				Spot Price		Spot Price				Spot Price
	Per Gallon				Per Gallon		Per Gallon				Per Gallon
Year Ended:	Low		High		At Period End		Low		High		At Period End
March 31, 2014	$	0.77	$	4.33	$	1.03	$	0.81	$	1.73	$	1.06
March 31, 2013	0.50		0.96		0.90		0.71		1.22		0.96
March 31, 2012	0.90		1.49		0.98		1.17		1.63		1.24

The range of low and high spot butane prices per gallon at Mt. Belvieu, Texas and the prices at period end were as follows:

	Spot Price Per Gallon
Year Ended:	Low		High		At Period End
March 31, 2014	$	1.08	$	1.64	$	1.26
March 31, 2013	1.14		1.93		1.45

We believe volatility in commodity prices will continue, and our ability to adjust and manage this volatility may impact our financial results.

Retail Propane

Our retail propane segment sells propane, distillates, and equipment and supplies to residential, agricultural, commercial, and industrial end users. Our retail propane segment purchases the majority of its propane from our liquids segment. Our retail propane segment generates margins based on the difference between the wholesale cost of product and the selling price of the product in the retail markets. These margins fluctuate over time due to supply and demand conditions. Weather conditions have a significant impact on our sales volumes and prices, as a significant portion of our sales are to residential customers who purchase propane and distillates for home heating purposes.

A significant factor affecting the profitability of our retail propane segment is our ability to maintain our realized product margin on a cents per gallon basis. Product margin is the differential between our sales prices and our total product costs, including transportation and storage. Historically, we have been successful in passing on price increases to our customers. We monitor propane prices daily and adjust our retail prices to maintain expected margins by passing on the wholesale costs to our customers. We believe that volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

In periods of significant propane price increases we have experienced, and expect to continue to experience, conservation of propane used by our customers that could result in a decline in our sales volumes, revenues and gross margins. In periods of decreasing propane costs, we have experienced an increase in our product margin. The retail propane business is weather-sensitive and subject to seasonal volume variations due to propane’s primary use as a heating source in residential and commercial buildings and for agricultural purposes. Typically, over 70% of our retail volume is sold during the peak heating season from October through March. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

Refined Products

Our refined products marketing business purchases gasoline and diesel fuel primarily from eight suppliers, and sells to over 300 customers. We purchase and sell these products at a nationwide network of third-party owned terminaling and storage facilities. We typically sell the product at the same time it is purchased in back-to-back transactions.

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Renewables

Our ethanol marketing business purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations to refiners and blenders. We also transport and market third-party owned ethanol for a service fee.

Our biodiesel marketing business purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product on leased railcars for sale to refiners and blenders. We lease biodiesel storage at facilities in Phoenix, Arizona and Deer Park, Texas.

Recent Developments

Acquisitions of businesses have had a significant impact on the comparability of our results of operations from fiscal 2012 through 2014. These transactions are described under Part I, Item 1, “Business — Acquisitions Subsequent to Initial Public Offering.”

Consolidated Results of Operations

The following table summarizes our historical consolidated statements of operations for the years ended March 31, 2014, 2013, and 2012:

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Total revenues	$	9,699,274		$	4,417,767		$	1,310,473
Total cost of sales	9,132,699			4,039,110			1,217,023
Operating and general and administrative expenses	339,256			222,497			63,309
Depreciation and amortization	120,754			68,853			15,111
Operating income	106,565			87,307			15,030
Earnings of unconsolidated entities	1,898			—			—
Interest expense	(58,854		)	(32,994		)	(7,620		)
Loss on early extinguishment of debt	—			(5,769		)	—
Other, net	86			1,521			1,055
Income before income taxes	49,695			50,065			8,465
Income tax provision	(937		)	(1,875		)	(601		)
Net income	48,758			48,190			7,864
Net (income) loss attributable to noncontrolling interests	(1,103		)	(250		)	12
Net income attributable to parent equity	$	47,655		$	47,940		$	7,876

See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, depreciation and amortization expense and operating income by segment below.

Interest Expense

See Note 8 to our consolidated financial statements included in this Annual Report for additional information on our long-term debt. The change in interest expense during the periods presented is due primarily to fluctuations in the average outstanding debt balance, and in the applicable interest rates, as summarized below:

	Revolving Credit Facilities				Senior Notes				Unsecured Notes
	Average				Average				Average
	Balance		Average		Balance				Balance
	Outstanding		Interest		Outstanding		Interest		Outstanding		Interest
Year Ended:	(in thousands)		Rate		(in thousands)		Rate		(in thousands)		Rate
March 31, 2014	$	588,375	3.04	%	$	250,000	6.65	%	$	205,890	6.88	%
March 31, 2013	405,114		3.56	%	195,890		6.65	%	—		—
March 31, 2012	125,859		4.48	%	—		—		—		—

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Interest expense also includes amortization of debt issuance costs, which represented $5.7 million of expense during the year ended March 31, 2014, $3.4 million of expense during the year ended March 31, 2013, and $1.3 million of expense during the year ended March 31, 2012. Interest expense also includes letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations assumed in business combinations.

On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations for the year ended March 31, 2013.

The increased levels of debt outstanding during the periods from fiscal 2012 through fiscal 2014 are due primarily to borrowings to finance acquisitions.

Income Tax Provision

We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return.

We have certain taxable corporate subsidiaries in the United States and Canada. In addition, our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales.

Noncontrolling Interests

We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated statements of operations represents the other owners’ share of the net income of these entities.

Non-GAAP Financial Measures

The following tables reconcile net income attributable to parent equity to EBITDA and Adjusted EBITDA, each of which are non-GAAP financial measures:

	Year Ended March 31,
	2014			2013		2012
	(in thousands)
Net income attributable to parent equity	$	47,655		$	47,940	$	7,876
Income tax provision	937			1,875		601
Interest expense	58,871			32,994		7,620
Loss on early extinguishment of debt	—			5,769		—
Depreciation and amortization	127,821			73,739		15,911
EBITDA	235,284			162,317		32,008
Unrealized (gain) loss on derivative contracts	(1,327		)	5,275		4,384
Loss (gain) on disposal or impairment of assets	3,597			187		(71		)
Share-based compensation expense	17,804			10,138		—
Adjusted EBITDA	$	255,358		$	177,917	$	36,321

We define EBITDA as net income (loss) attributable to parent equity, plus interest expense,loss on early extinguishment of debt, income taxes, and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding the unrealized gain or loss on derivative contracts, the gain or loss on the disposal or impairment of assets, and share-based compensation expense. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with accounting principles generally accepted in the United States (“GAAP”) as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other entities.

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For purposes of our Adjusted EBITDA calculation, we make a distinction between unrealized gains and losses on derivatives and realized gains and losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as unrealized gains or losses. When a derivative contract is settled, we reverse the previously-recorded unrealized gain or loss and record a realized gain or loss. The realized gain or loss is equal to the amount received or paid on the contract. We acquired Gavilon Energy in December 2013. We are still in the process of developing procedures to calculate realized and unrealized gains and losses for the Gavilon Energy operations in the same way we calculate them for our other operations. Accordingly, the unrealized gain and loss in the table above excludes any unrealized gains and losses related to Gavilon Energy.

The tables below reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported in our consolidated statements of operations and consolidated statements of cash flows:

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Reconciliation to consolidated statements of operations:
Depreciation and amortization per EBITDA table	$	127,821		$	73,739		$	15,911
Intangible asset amortization recorded to cost of sales	(6,172		)	(5,285		)	(800		)
Depreciation and amortization of unconsolidated entities	(1,638		)	—			—
Depreciation and amortization attributable to noncontrolling interests	743			399			—
Depreciation and amortization per consolidated statements of operations	$	120,754		$	68,853		$	15,111
Reconciliation to consolidated statements of cash flows:
Depreciation and amortization per EBITDA table	$	127,821		$	73,739		$	15,911
Amortization of debt issuance costs recorded to interest expense	5,727			3,375			1,277
Depreciation and amortization of unconsolidated entities	(1,638		)	—			—
Depreciation and amortization attributable to noncontrolling interests	743			399			—
Depreciation and amortization per consolidated statements of cash flows	$	132,653		$	77,513		$	17,188

Segment Operating Results

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of High Sierra in June 2012, Pecos in November 2012, Third Coast in December 2012, Crescent in July 2013, and Gavilon Energy in December 2013. We expanded our water solutions business through several acquisitions of water disposal and transportation businesses, including High Sierra in June 2012, Big Lake in July 2013, OWL in August 2013, and Coastal in September 2013. We expanded our liquids business through the acquisitions of SemStream in October 2011 and High Sierra in June 2012. We expanded our retail propane operations through the acquisitions of Osterman in October 2011, Pacer in January 2012, North American in February 2012, and Downeast in May 2012. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy.

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Volumes

The following table summarizes the volume of product sold and water delivered for the years ended March 31, 2014 and 2013. Volumes shown in the table below for our liquids segment include sales to our retail propane segment.

	Year Ended March 31,
Segment	2014	2013	Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	46,107	24,373	21,734
Water solutions
Water delivered (barrels)	62,774	25,009	37,765
Liquids
Propane sold (gallons)	1,190,106	912,625	277,481
Other products sold (gallons)	786,671	505,529	281,142
Retail propane
Propane sold (gallons)	162,361	144,379	17,982
Distillates sold (gallons)	34,965	28,853	6,112
Refined products
Refined products sold (gallons)	412,974	—	412,974
Renewables
Renewables sold (gallons)	150,925	—	150,925

Volumes sold by our crude oil logistics and water solutions segments were higher during the year ended March 31, 2014 than during the year ended March 31, 2013, due primarily to the expansion of our business through acquisitions.

Volumes sold by our liquids segment were higher during the year ended March 31, 2014 than during the year ended March 31, 2013, due to several factors. Market demand for propane was higher, due in part to colder weather conditions. Market demand for butane to be used in gasoline blending operations was also higher. Volumes also increased due to the expansion of our customer base. In addition, during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

Volumes sold by our retail propane segment during the year ended March 31, 2014 increased compared to the volumes sold during the year ended March 31, 2013, due primarily to colder weather conditions.

Our refined products and renewables segments began with the December 2013 acquisition of Gavilon Energy.

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Operating Income (Loss) by Segment

Our operating income (loss) by segment for the years ended March 31, 2014 and 2013 was as follows:

	Year Ended March 31,
Segment	2014			2013			Change
	(in thousands)
Crude oil logistics	$	678		$	34,236		$	(33,558	)
Water solutions	10,317			8,576			1,741
Liquids	71,888			30,336			41,552
Retail propane	61,285			46,869			14,416
Refined products	4,080			—			4,080
Renewables	2,434			—			2,434
Corporate and other	(44,117		)	(32,710		)	(11,407		)
Operating income	$	106,565		$	87,307		$	19,258

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,
	2014		2013		Change
	(in thousands)
Revenues:
Crude oil sales	$	4,559,923	$	2,322,706	$	2,237,217
Crude oil transportation and other	36,469		16,442		20,027
Total revenues (1)	4,596,392		2,339,148		2,257,244
Expenses:
Cost of sales	4,515,244		2,267,507		2,247,737
Operating expenses	53,872		25,484		28,388
General and administrative expenses	4,487		2,745		1,742
Depreciation and amortization expense	22,111		9,176		12,935
Total expenses	4,595,714		2,304,912		2,290,802
Segment operating income	$	678	$	34,236	$	(33,558	)

(1)Revenues include $37.8 million of intersegment sales during the year ended March 31, 2014 and $22.9 million of intersegment sales during the year ended March 31, 2013 that are eliminated in our consolidated statements of operations.

Revenues. Our crude oil logistics segment generated $4.6 billion of revenue from crude oil sales during the year ended March 31, 2014, selling 46.1 million barrels at an average price of $98.90 per barrel. During the year ended March 31, 2013, our crude oil logistics segment generated $2.3 billion of revenue from crude oil sales, selling 24.4 million barrels at an average price of $95.30 per barrel. The increase in volume during the year ended March 31, 2014 compared to the year ended March 31, 2013 was due in part to the fact that we did not own a crude oil logistics business for the full 12 months ended March 31, 2013, as we acquired this business in our June 19, 2012 merger with High Sierra. The increase in volume was also due to acquisitions of crude oil logistics businesses, including Gavilon Energy, Pecos, and Third Coast, among others. Of this increase, $1.0 billion was attributable to Gavilon Energy.

Crude oil transportation and other revenues of our crude oil logistics segment were $36.5 million during the year ended March 31, 2014, compared to $16.4 million of crude oil transportation and other revenues during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to acquisitions of crude oil logistics businesses, including Gavilon Energy, Pecos, and Third Coast.

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Cost of Sales. Our cost of crude oil sold was $4.5 billion during the year ended March 31, 2014, as we sold 46.1 million barrels at an average cost of $97.93 per barrel. Our cost of sales during the year ended March 31, 2014 was increased by $2.2 million of unrealized losses on derivatives. During the year ended March 31, 2013, our cost of crude oil was $2.3 billion, as we sold 24.4 million barrels at an average cost of $93.03 per barrel.

Operating Expenses. Our crude oil logistics segment incurred $53.9 million of operating expenses during the year ended March 31, 2014, compared to $25.5 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions, including Gavilon Energy, Pecos, and Third Coast. Of this increase, $10.1 million was attributable to Gavilon Energy.

General and Administrative Expenses. Our crude oil logistics segment incurred $4.5 million of general and administrative expenses during the year ended March 31, 2014, compared to $2.7 million of general and administrative expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions. Of this increase, $1.0 million was attributable to our acquisition of Gavilon Energy.

Depreciation and Amortization Expense. Our crude oil logistics segment incurred $22.1 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $9.2 million of depreciation and amortization expense during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions. Of this increase, $2.8 million was attributable to our acquisition of Gavilon Energy.

Operating Income. Our crude oil logistics segment generated $0.7 million of operating income during the year ended March 31, 2014, compared to $34.2 million of operating income during the year ended March 31, 2013. Acquisitions of businesses contributed to operating income during the year ended March 31, 2014, although this benefit was offset by several factors. These factors included a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets, and increased competition in the South Texas region from newly-constructed pipelines. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved. Operating income during the year ended March 31, 2014 was reduced by $3.0 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. We also recorded $0.5 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the Gavilon Energy acquisition.

Water Solutions

The following table summarizes the operating results of our water solutions segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,				Change
	2014		2013		Acquisitions (1)		Other
	(in thousands)
Revenues:
Water treatment and disposal	$	125,788	$	54,334	$	64,119	$	7,335
Water transportation	17,312		7,893		14,231		(4,812		)
Total revenues	143,100		62,227		78,350		2,523
Expenses:
Cost of sales	11,738		5,611		9,325		(3,198		)
Operating expenses	58,178		25,452		35,377		(2,651		)
General and administrative expenses	7,762		1,665		1,239		4,858
Depreciation and amortization expense	55,105		20,923		26,955		7,227
Total expenses	132,783		53,651		72,896		6,236
Segment operating income	$	10,317	$	8,576	$	5,454	$	(3,713	)

(1)Represents the change in revenues and expenses attributable to acquisitions subsequent to the merger with High Sierra. The cost of sales amount shown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities.

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Revenues. Our water solutions segment generated $125.8 million of treatment and disposal revenue during the year ended March 31, 2014, taking delivery of 62.8 million barrels of wastewater at an average revenue of $2.00 per barrel. During the year ended March 31, 2013, our water solutions segment generated $54.3 million of treatment and disposal revenue, taking delivery of 25.0 million barrels of wastewater at an average revenue of $2.17 per barrel. The increase in revenues was due primarily to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra and was due also to acquisitions during the year ended March 31, 2013, including Indigo, and acquisitions during the year ended March 31, 2014, including OWL, Big Lake and Coastal. The decrease in revenue per barrel was due primarily to the fact that the expansion of our water solutions business subsequent to our merger with High Sierra has been primarily in Texas, where the market rates for water disposal services are typically lower than in Wyoming or Colorado.

In our June 2012 merger with High Sierra, we acquired a water transportation business in Oklahoma. In our August 2013 acquisition of OWL, we acquired a water transportation business in Texas. Our water solutions segment generated $17.3 million of transportation revenues during the year ended March 31, 2014, compared to $7.9 million of transportation revenues during the year ended March 31, 2013. This increase was due primarily to the acquisition of OWL. This increase was partially offset by a decrease in water transportation revenues generated by the water solutions business acquired in the merger with High Sierra, which resulted primarily from a slowdown in production activities by a customer. During the three months ended December 31, 2013, we wound down our water transportation operations in Oklahoma, transferring certain of the assets to our business in Texas and selling the remaining assets.

Cost of Sales. The cost of sales for our water solutions segment was $11.7 million during the year ended March 31, 2014. Our cost of sales during the year ended March 31, 2014 was increased by $0.6 million of unrealized losses on derivatives. Because a portion of our processing revenue is generated from the sale of recovered hydrocarbons, we enter into derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbons we expect to recover. During the year ended March 31, 2013, the cost of sales for our water solutions segment was $5.6 million. Our cost of sales during the year ended March 31, 2013 was increased by $1.0 million of unrealized losses on derivatives. The increase in our cost of sales was due primarily to the expansion of our operations through acquisitions of water solutions businesses.

Operating Expenses. Our water solutions segment incurred $58.2 million of operating expenses during the year ended March 31, 2014, compared to $25.5 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due primarily to subsequent acquisitions of businesses. We incurred losses on disposal of property, plant and equipment of $2.0 million during the year ended March 31, 2014 as a result of property damage from lightning strikes at two of our facilities.

General and Administrative Expenses. Our water solutions segment incurred $7.8 million of general and administrative expenses during the year ended March 31, 2014, compared to $1.7 million of general and administrative expenses during the year ended March 31, 2013. This increase was due in part to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due to subsequent acquisitions of businesses.

Depreciation and Amortization Expense. Our water solutions segment incurred $55.1 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $20.9 million of depreciation and amortization expense during the year ended March 31, 2013. This increase was due in part to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due to subsequent acquisitions of businesses. The increase is also due in part to $2.1 million of amortization expense related to trade name intangible assets. During the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets.

Operating Income. Our water solutions segment generated $10.3 million of operating income during the year ended March 31, 2014, compared to operating income of $8.6 million during the year ended March 31, 2013. Exclusive of acquisitions during the year ended March 31, 2014, our operating income decreased by $3.7 million. Increases in revenues were offset by increases in operating expenses, including a $7.2 million increase in depreciation and amortization expense. The businesses acquired during the year ended March 31, 2014 generated operating income of $5.5 million, which included $27.0 million of depreciation and amortization expense, which consisted primarily of amortization expense on acquired customer relationship intangible assets.

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Liquids

The following table summarizes the operating results of our liquids segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,
	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	1,632,948	$	841,448	$	791,500
Other product sales	1,231,965		858,276		373,689
Other revenues	31,062		33,954		(2,892		)
Total revenues (1)	2,895,975		1,733,678		1,162,297
Expenses:
Cost of sales - propane	1,559,266		801,694		757,572
Cost of sales - other products	1,179,944		836,747		343,197
Cost of sales - other	24,439		20,950		3,489
Operating expenses	42,977		27,605		15,372
General and administrative expenses	6,443		5,261		1,182
Depreciation and amortization expense	11,018		11,085		(67		)
Total expenses	2,824,087		1,703,342		1,120,745
Segment operating income	$	71,888	$	30,336	$	41,552

(1)Revenues include $245.6 million of intersegment sales during the year ended March 31, 2014 and $128.9 million of intersegment sales during the year ended March 31, 2013 that are eliminated in our consolidated statements of operations.

Revenues. Our liquids segment generated $1.6 billion of wholesale propane sales revenue during the year ended March 31, 2014, selling 1.1 billion gallons at an average price of $1.37 per gallon. During the year ended March 31, 2013, our liquids segment generated $841.4 million of wholesale propane sales revenue, selling 912.6 million gallons at an average price of $0.92 per gallon. Approximately 221.2 million gallons of the increase in volumes was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the year ended March 31, 2013. The remaining increase in volume was due to several factors, including higher market demand, due in part to colder weather conditions, and the expansion of our customer base. In addition, during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

Our liquids segment generated $1.2 billion of other wholesale products sales revenue during the year ended March 31, 2014, selling 786.7 million gallons at an average price of $1.57 per gallon. During the year ended March 31, 2013, our liquids segment generated $858.3 million of other wholesale products sales revenue, selling 505.5 million gallons at an average price of $1.70 per gallon. Approximately 454.1 million gallons of the increase in volumes was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the year ended March 31, 2013. The remaining increase in volume was due to several factors, including higher market demand for butane to be used in gasoline blending operations, the expansion of our customer base, and an increased focus on the opportunity to more fully utilize our terminals to market butane.

Cost of Sales. Our cost of wholesale propane sales was $1.6 billion during the year ended March 31, 2014, as we sold 1.1 billion gallons at an average cost of $1.31 per gallon. Our cost of wholesale propane sales during the year ended March 31, 2014 was increased by $1.6 million of unrealized losses on derivatives. During the year ended March 31, 2013, our cost of wholesale propane sales was $801.7 million, as we sold 912.6 million gallons at an average cost of $0.88 per gallon. Our cost of wholesale propane sales during the year ended March 31, 2013 was reduced by $3.2 million of unrealized gains on derivatives.

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Declining wholesale propane prices during the first quarter of the prior fiscal year had an adverse effect on cost of sales during the year ended March 31, 2013. Our wholesale segment utilizes a weighted-average inventory costing method to calculate cost of sales. Propane prices decreased steadily during April and May 2012, as a result of which the replacement cost of propane was at times lower than the weighted-average cost, which had an adverse effect on margins. One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of falling prices, such as we experienced during the three months ended June 30, 2012, this can result in negative margins on these sales, which we recovered when delivering future volumes.

Our cost of sales of other products was $1.2 billion during the year ended March 31, 2014, as we sold 786.7 million gallons at an average cost of $1.50 per gallon. Our cost of sales of other products during the year ended March 31, 2014 was reduced by $5.8 million of unrealized gains on derivatives. During the year ended March 31, 2013, our cost of sales of other products was $836.7 million, as we sold 505.5 million gallons at an average cost of $1.66 per gallon. Our cost of sales of other products during the year ended March 31, 2013 was increased by $7.5 million of unrealized losses on derivatives.

Operating Expenses. Our liquids segment incurred $43.0 million of operating expenses during the year ended March 31, 2014, compared to $27.6 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to expanded operations. In addition, during the year ended March 31, 2014, we recorded an impairment of $5.3 million related to the property, plant and equipment of one of our terminals.

General and Administrative Expenses. Our liquids segment incurred $6.4 million of general and administrative expenses during the year ended March 31, 2014, compared to $5.3 million of general and administrative expenses during the year ended March 31, 2013. This increase was due primarily to expanded operations.

Depreciation and Amortization Expense. Our liquids segment incurred $11.0 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $11.1 million of depreciation and amortization expense during the year ended March 31, 2013.

Operating Income. Our liquids segment generated $71.9 million of operating income during the year ended March 31, 2014, compared to $30.3 million of operating income during the year ended March 31, 2013. The increase in operating income was due primarily to the expansion of our operations and to colder weather conditions. As a result of the cold weather conditions, the demand for natural gas liquids increased considerably during the recent winter, which had a favorable impact on our sales volumes. The demand also resulted in increases to the market prices for natural gas liquids, which had a favorable impact on product margins, as we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory. These increases were partially offset by increased operating expenses as a result of expanding our operations. During the year ended March 31, 2014, operating income was increased by $4.2 million of unrealized gains on derivatives. During the year ended March 31, 2013, operating income was reduced by $4.3 million of unrealized losses on derivatives.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,
	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	388,225	$	288,410	$	99,815
Distillate sales	127,672		106,192		21,480
Other revenues	35,918		35,856		62
Total revenues	551,815		430,458		121,357
Expenses:
Cost of sales - propane	233,110		155,118		77,992
Cost of sales - distillates	109,058		90,772		18,286
Cost of sales - other	11,531		12,688		(1,157		)
Operating expenses	96,936		88,651		8,285
General and administrative expenses	11,017		10,864		153
Depreciation and amortization expense	28,878		25,496		3,382
Total expenses	490,530		383,589		106,941
Segment operating income	$	61,285	$	46,869	$	14,416

Revenues. Our retail propane segment generated revenue of $388.2 million from propane sales during the year ended March 31, 2014, selling 162.4 million gallons at an average price of $2.39 per gallon. During the year ended March 31, 2013, our retail propane segment generated $288.4 million of revenue from propane sales, selling 144.4 million gallons at an average price of $2.00 per gallon. The increase in volumes and average sales prices during the year ended March 31, 2014 compared to the year ended March 31, 2013 was due primarily to market demand being higher as a result of colder weather conditions. Revenues also benefitted from the continued integration of previously-acquired businesses.

Our retail propane segment generated revenue of $127.7 million from distillate sales during the year ended March 31, 2014, selling 35.0 million gallons at an average price of $3.65 per gallon. During the year ended March 31, 2013, our retail propane segment generated $106.2 million of revenue from distillate sales, selling 28.9 million gallons at an average price of $3.68 per gallon. The increase in volumes was due primarily to colder weather conditions and to the acquisitions of smaller retailers.

Cost of Sales. Our cost of retail propane sales was $233.1 million during the year ended March 31, 2014, as we sold 162.4 million gallons at an average cost of $1.44 per gallon. During the year ended March 31, 2013, our cost of retail propane sales was $155.1 million, as we sold 144.4 million gallons at an average cost of $1.07 per gallon.

Our cost of distillate sales was $109.1 million during the year ended March 31, 2014, as we sold 35.0 million gallons at an average cost of $3.12 per gallon. During the year ended March 31, 2013, our cost of distillate sales was $90.8 million, as we sold 28.9 million gallons at an average cost of $3.15 per gallon.

Operating Expenses. Our retail propane segment incurred $96.9 million of operating expenses during the year ended March 31, 2014, compared to $88.7 million of operating expenses during the year ended March 31, 2013. This increase was due in part to the inclusion of Downeast in our results of operations for the full 12 months ended March 31, 2014, as compared to only 11 of the months in the 12-month period ended March 31, 2013.

General and Administrative Expenses. Our retail propane segment incurred $11.0 million of general and administrative expenses during the year ended March 31, 2014, compared to $10.9 million of general and administrative expenses during the year ended March 31, 2013. This increase was due primarily to acquisitions of smaller retailers.

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Depreciation and Amortization Expense. Our retail propane segment incurred $28.9 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $25.5 million of depreciation and amortization expense during the year ended March 31, 2013. This increase was due primarily to capital expenditures and acquisitions.

Operating Income. Our retail propane segment generated $61.3 million of operating income during the year ended March 31, 2014, compared to $46.9 million of operating income during the year ended March 31, 2013. The increase in operating income was due primarily to increased market demand due to colder weather conditions, partially offset by increased operating expenses.

Refined Products

The following table summarizes the operating results of our refined products segment for the year ended March 31, 2014 (in thousands). Our refined products segment began with our December 2013 acquisition of Gavilon Energy.

Revenues	$	1,180,895
Expenses:
Cost of sales	1,172,754
Operating expenses	3,887
General and administrative expenses	65
Depreciation and amortization expense	109
Total expenses	1,176,815
Segment operating income	$	4,080

Revenues. Our refined products segment generated $1.2 billion of revenue during the year ended March 31, 2014, selling 413.0 million gallons at an average price of $2.86 per gallon.

Cost of Sales. Our cost of sales was $1.2 billion during the year ended March 31, 2014, as we sold 413.0 million gallons at an average cost of $2.84 per gallon.

Operating Expenses. Our refined products segment incurred $3.9 million of operating expenses during the year ended March 31, 2014.

General and Administrative Expenses. Our refined products segment incurred $0.1 million of general and administrative expenses during the year ended March 31, 2014.

Depreciation and Amortization Expense. Our refined products segment incurred $0.1 million of depreciation and amortization expense during the year ended March 31, 2014.

Operating Income. Our refined products segment generated $4.1 million of operating income during the year ended March 31, 2014.

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Renewables

The following table summarizes the operating results of our renewables segment for the year ended March 31, 2014 (in thousands). Our renewables segment began with our December 2013 acquisition of Gavilon Energy.

Revenues	$	176,781
Expenses:
Cost of sales	171,422
Operating expenses	2,318
General and administrative expenses	91
Depreciation and amortization expense	516
Total expenses	174,347
Segment operating income	$	2,434

Revenues. Our renewables segment generated $176.8 million of revenue during the year ended March 31, 2014, selling 150.9 million gallons at an average price of $1.17 per gallon.

Cost of Sales. Our cost of sales was $171.4 million during the year ended March 31, 2014, as we sold 150.9 million gallons at an average cost of $1.14 per gallon.

Operating Expenses. Our renewables segment incurred $2.3 million of operating expenses during the year ended March 31, 2014.

General and Administrative Expenses. Our renewables segment incurred $0.1 million of general and administrative expenses during the year ended March 31, 2014.

Depreciation and Amortization Expense. Our renewables segment incurred $0.5 million of depreciation and amortization expense during the year ended March 31, 2014.

Operating Income. Our renewables segment generated $2.4 million of operating income during the year ended March 31, 2014.

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Corporate and Other

The operating loss within “corporate and other” includes the following components:

	Year Ended March 31,
	2014			2013			Change
	(in thousands)
Compressor leasing business	$	2,336		$	(1	)	$	2,337
Natural gas business	1,363			—			1,363
Equity-based compensation expense	(17,804		)	(10,138		)	(7,666		)
Acquisition expenses	(6,908		)	(5,602		)	(1,306		)
Other corporate expenses	(23,104		)	(16,969		)	(6,135		)
	$	(44,117	)	$	(32,710	)	$	(11,407	)

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

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.

The increase in equity-based compensation is due in part to the timing of award grants and is also due in part to an increase in the market value of our common units. The first restricted units were granted during fiscal 2013, and therefore were not in existence for the full fiscal year. The life-to-date expense for unvested units is adjusted based on the market value of the common units on the reporting date, and the value of the common units was higher at March 31, 2014 than at March 31, 2013.

The increase in other corporate expenses is due primarily to increases in compensation expense, due to the addition of new corporate employees to provide general and administrative services in support of the growth of our business.

Operating income during the year ended March 31, 2014 was reduced by $2.0 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. We also recorded $2.2 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the Gavilon Energy acquisition, $1.3 million of which is reported under “natural gas business” in the table above and the remainder of which is reported under “other corporate expenses” in the table above.

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Year Ended March 31, 2013

Compared to Year Ended March 31, 2012

Volumes Sold or Delivered

The following table summarizes the volume of product sold and water delivered for the years ended March 31, 2013 and 2012. Volumes shown in the table below for our liquids segment include sales to our retail propane segment.

	Year Ended		Change Resulting From
	March 31,		Retail	SemStream		High Sierra
Segment	2013	2012	Combinations (1)	Combination		Combinations (2)	Other
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)	24,373	—	—	—		24,373	—
Water solutions
Water delivered (barrels)	25,009	—	—	—		25,009	—
Liquids
Propane sold (gallons)	912,625	659,921	—	(3	)	140,632	112,072
Other products sold (gallons)	505,529	134,999	—	(3	)	320,283	50,247
Retail propane
Propane sold (gallons)	144,379	78,236	54,949	—		—	11,194
Distillates sold (gallons)	28,853	1,650	27,027	—		—	176

(1)This data includes the operations of Osterman (acquired in October 2011) from April 1, 2012 through September 30, 2012, Pacer (acquired in January 2012) from April 1, 2012 through December 31, 2012, North American (acquired in February 2012) from April 1, 2012 through January 31, 2013, Downeast (acquired in May 2012), and certain other smaller retail propane business acquired during fiscal 2013.

(2)This data includes the operations of High Sierra (acquired in June 2012), Pecos (acquired in November 2012), and other subsequent acquisitions of smaller crude oil and water solutions businesses.

(3)Although the SemStream combination enabled us to significantly expand our wholesale operations, it is not possible to determine which of the volumes sold subsequent to the combination were specifically attributable to the SemStream combination and which were attributable to our historical wholesale business.

As shown in the table above, the increases in volumes were driven primarily by acquisitions of businesses during fiscal 2012 and fiscal 2013. The remaining increase in volume of our retail propane business was due primarily to colder weather during the 2013-2014 winter season, which increased the demand for propane.

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Operating Income by Segment

Our operating income by segment is as follows:

	Year Ended March 31,
Segment	2013			2012			Change
	(in thousands)
Crude oil logistics	$	34,236		$	—		$	34,236
Water solutions	8,576			—			8,576
Liquids	30,336			9,735			20,601
Retail propane	46,869			9,616			37,253
Corporate and other	(32,710		)	(4,321		)	(28,389		)
Operating income	$	87,307		$	15,030		$	72,277

The operating loss within “corporate and other” increased $28.4 million during the year ended March 31, 2013 as compared to $4.3 million during the year ended March 31, 2012. This increase is due in part to $8.4 million of incremental expenses associated with the corporate activities of High Sierra. In addition, corporate general and administrative expense for the year ended March 31, 2013 includes $10.1 million of compensation expense related to certain restricted units granted pursuant to employee and director compensation programs. Corporate general and administrative expense for the year ended March 31, 2013 also includes costs related to acquisitions, including $3.7 million of expense related to the acquisition of High Sierra. The operations of our compressor leasing business are also included within “corporate and other.”

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the year ended March 31, 2013 (amounts in thousands). The operations of our crude oil logistics segment began with our June 19, 2012 combination with High Sierra.

Revenues:
Crude oil sales	$	2,322,706
Crude oil transportation and other	16,442
Total revenues (1)	2,339,148
Expenses:
Cost of sales	2,267,507
Operating expenses	25,484
General and administrative expenses	2,745
Depreciation and amortization expense	9,176
Total expenses	2,304,912
Segment operating income	$	34,236

(1)Revenues include $22.9 million of intersegment sales that are eliminated in our consolidated statement of operations.

Revenues. We generated revenue of $2.3 billion from crude oil sales during the year ended March 31, 2013, selling 24.4 million barrels at an average price of $95.30 per barrel. We also generated $16.4 million of revenue from the transportation of crude oil owned by other parties.

Cost of Sales. Our cost of crude oil sold was $2.3 billion during the year ended March 31, 2013. We sold 24.4 million barrels at an average cost of $93.03 per barrel. Our cost of sales during the year ended March 31, 2013 was increased by $9.8 million of realized losses on derivatives.

Other Operating Expenses. Our crude oil operations incurred $28.2 million of operating and general and administrative expenses during the year ended March 31, 2013. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $9.2 million during the year ended March 31, 2013.

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Water Solutions

The following table summarizes the operating results of our water solutions segment for the year ended March 31, 2013 (amounts in thousands). The operations of our water solutions segment began with our June 19, 2012 combination with High Sierra.

Revenues:
Water treatment and disposal	$	54,334
Water transportation	7,893
Total revenues	62,227
Expenses:
Cost of sales	5,611
Operating expenses	25,452
General and administrative expenses	1,665
Depreciation and amortization expense	20,923
Total expenses	53,651
Segment operating income	$	8,576

Revenues. Our water solutions segment generated $54.3 million of treatment and disposal revenue during the year ended March 31, 2013, taking delivery of 25.0 million barrels of wastewater at an average revenue of $2.17 per barrel. Our water transportation business generated $7.9 million of revenues.

Cost of Sales. The cost of sales for our water solutions segment was $5.6 million for the year ended March 31, 2013, an average cost of $0.22 per barrel delivered. Cost of sales was increased by unrealized losses of $1.0 million and realized losses of $0.8 million on derivatives. A portion of our processing revenue is generated from the sale of recovered hydrocarbons; we enter into these derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbons we expect to recover.

Other Operating Expenses. Our water solutions segment incurred $27.1 million of operating and general and administrative expenses during the year ended March 31, 2013. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $20.9 million during the year ended March 31, 2013.

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Liquids

The following table compares the operating results of our liquids segment for the years ended March 31, 2013 and 2012:

					Change Resulting From
	Year Ended March 31,				High Sierra
	2013		2012		Combination		Other
	(in thousands)
Revenues:
Propane sales	$	841,448	$	923,022	$	115,606	$	(197,180	)
Other product sales	858,276		251,627		563,211		43,438
Other revenues	33,954		2,462		19,053		12,439
Total revenues (1)	1,733,678		1,177,111		697,870		(141,303		)
Expenses:
Cost of sales - propane	801,694		904,082		109,851		(212,239		)
Cost of sales - other products	836,747		246,995		546,588		43,164
Costs of sales - other	20,950		1,776		8,637		10,537
Operating expenses	27,605		8,124		15,097		4,384
General and administrative expenses	5,261		2,738		1,693		830
Depreciation and amortization expense	11,085		3,661		3,101		4,323
Total expenses	1,703,342		1,167,376		684,967		(149,001		)
Segment operating income	$	30,336	$	9,735	$	12,903	$	7,698

(1)Revenues include $128.9 million of intersegment sales during the year ended March 31, 2013 and $66.0 million of intersegment sales during the year ended March 31, 2012 that are eliminated in our consolidated statements of operations.

Revenues. Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale propane sales decreased $197.2 million during the year ended March 31, 2013, as compared to $923.0 million during the year ended March 31, 2012. This resulted from a decrease in the average selling price of $0.46 per gallon, as compared to an average selling price per gallon of $1.40 in the prior year. This decrease in revenue was partially offset by an increase in volume sold of 112.1 million gallons, as compared to 659.9 million gallons sold in the prior year.

During the year ended March 31, 2013, the operations of High Sierra contributed revenues of $115.6 million from propane sales. These operations sold 140.6 million gallons of propane at an average price of $0.82 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale sales of other products increased $43.4 million during the year ended March 31, 2013, as compared to $251.6 million during the year ended March 31, 2012. This resulted from an increase in volume sold of 50.2 million gallons as compared to 135.0 million gallons in the prior year, partially offset by a decrease in the average selling price of $0.27 per gallon, as compared to $1.86 per gallon in the prior year.

During the year ended March 31, 2013, the operations of High Sierra contributed revenues of $563.2 million from sales of other products (primarily butane). These operations sold 320.3 million gallons of other products at an average price of $1.76 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, the increase in volume sold is due primarily to the November 2011 SemStream acquisition, which expanded the markets we are able to serve. We believe the decline in average selling prices is due primarily to a greater than normal supply in the marketplace, due in part to low demand as a result of mild weather.

Transportation and other revenues for the year ended March 31, 2013 relate primarily to fees charged for transporting customer-owned product by railcar.

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Cost of Sales. Exclusive of the operations acquired in our June 2012 merger with High Sierra, costs of wholesale propane sales decreased $212.2 million during the year ended March 31, 2013, as compared to $904.1 million during the year ended March 31, 2012. This resulted from a decrease in the average cost of $0.47 per gallon, as compared to an average cost per gallon of $1.37 in the prior year. This decrease in cost was partially offset by an increase in volume sold of 112.1 million gallons, as compared to 659.9 million gallons sold in the prior year. Cost of propane sales were reduced by $14.8 million during the year ended March 31, 2013 due to $11.6 million of realized gains and $3.2 million of unrealized gains on derivatives. These derivatives consisted primarily of propane swaps that we entered into as economic hedges against the potential decline in the market value of our propane inventories. Excluding gains on derivatives, our average cost of propane sold during the year ended March 31, 2013 was $0.92 cents per gallon.

During the year ended March 31, 2013, the cost of propane sales of the High Sierra operations were $109.9 million. These operations sold 140.6 million gallons of propane at an average price of $0.78 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, cost of wholesale sales of other products increased $43.2 million during the year ended March 31, 2013, as compared to $247.0 million during the year ended March 31, 2012. This resulted from an increase in volume sold of 50.2 million gallons as compared to 135.0 million gallons in the prior year, partially offset by a decrease in the average cost of $0.26 per gallon, as compared to $1.83 per gallon in the prior year. Cost of other products sales during the year ended March 31, 2013 was reduced by $0.2 million due to realized gains on derivatives.

During the year ended March 31, 2013, the cost of other products sales of the High Sierra operations was $546.6 million. These operations sold 320.3 million gallons of other products (primarily butane) at an average price of $1.71 per gallon. Costs of sales of other products during the year ended March 31, 2013 were increased by $7.5 million of unrealized losses and $0.3 million of realized losses on derivatives.

Other cost of sales for the year ended March 31, 2013 relate primarily to the cost of leasing railcars used in the transportation of customer-owned product.

Operating Expenses. Exclusive of the operations acquired in our June 2012 merger with High Sierra, operating expenses of our liquids segment increased $4.4 million during the year ended March 31, 2013 as compared to operating expenses of $8.1 million during the year ended March 31, 2012. The increase in operating expenses is due primarily to increased compensation and terminal operating expenses resulting from our SemStream combination. During the year ended March 31, 2013, our liquids segment incurred $15.1 million of operating expenses related to the operations of High Sierra.

General and Administrative Expenses. Exclusive of the operations acquired in our June 2012 merger with High Sierra, general and administrative expenses of our liquids segment increased $0.8 million during the year ended March 31, 2013 as compared to general and administrative expenses of $2.7 million during the year ended March 31, 2012. This increase is due primarily to increased compensation and related expenses resulting from our SemStream combination. During the year ended March 31, 2013, our liquids segment incurred $1.7 million of general and administrative expenses related to the operations of High Sierra.

Depreciation and Amortization Expense. Exclusive of the operations acquired in our June 2012 merger with High Sierra, depreciation and amortization expense of our liquids segment increased $4.3 million during the year ended March 31, 2013, as compared to depreciation and amortization expense of $3.7 million during the year ended March 31, 2012. This increase is due primarily to depreciation and amortization expense related to assets acquired in the SemStream combination, including depreciation of terminal assets and amortization of customer relationship intangible assets. During the year ended March 31, 2013, our liquids segment recorded $3.1 million of depreciation and amortization expense related to assets acquired in our merger with High Sierra.

Operating Income. Our liquids segment had operating income of $30.3 million during the year ended March 31, 2013 as compared to operating income of $9.7 million during the year ended March 31, 2012. The increased operating income is due in part to $12.9 million of operating income contributed by the operations acquired in the merger with High Sierra. Exclusive of these operations, operating income improved by $7.7 million, which was due to increased product margins, partially offset by increased expenses.

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Retail Propane

The following table compares the operating results of our retail propane segment for the years ended March 31, 2013 and 2012:

					Change Resulting From
	Year Ended March 31,				Retail
	2013		2012		Combinations (1)		Other
	(in thousands)
Revenues:
Propane sales	$	288,410	$	175,417	$	117,686	$	(4,693	)
Distillate sales	106,192		6,547		99,410		235
Other sales	35,856		17,370		20,752		(2,266		)
Total revenues	430,458		199,334		237,848		(6,724		)
Expenses:
Cost of sales - propane	155,118		117,722		63,080		(25,684		)
Cost of sales - distillates	90,772		5,728		84,933		111
Cost of sales - other	12,688		6,692		6,516		(520		)
Operating expenses	88,651		39,176		47,454		2,021
General and administrative expenses	10,864		8,950		5,409		(3,495		)
Depreciation and amortization expense	25,496		11,450		13,059		987
Total expenses	383,589		189,718		220,451		(26,580		)
Segment operating income	$	46,869	$	9,616	$	17,397	$	19,856

(1)This data includes the operations of Osterman (acquired in October 2011) from April 1, 2012 through September 30, 2012, Pacer (acquired in January 2012) from April 1, 2012 through December 31, 2012, North American (acquired in February 2012) from April 1, 2012 through January 31, 2013, Downeast (acquired in May 2012), and certain other smaller retail propane business acquired during fiscal 2013.

Revenues. Propane sales for the year ended March 31, 2013 increased $113.0 million as compared to propane sales of $175.4 million during the year ended March 31, 2012. The principal reason for the increase in propane sales was the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane sales were lower during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to a decline in the average price per gallon sold of $0.33 during the year ended March 31, 2013, as compared to an average price per gallon sold of $2.24 during the year ended March 31, 2012. Excluding the effect of these acquisitions, volumes sold during the year ended March 31, 2013 were higher than volumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder than that of fiscal 2012. The winter of fiscal 2012 was one of the warmest on record, and these warm weather conditions resulted in a decrease in the demand for propane.

Our acquired Osterman, Pacer, North American, and Downeast operations generated propane sales of $117.7 million during the year ended March 31, 2013, consisting of 54.9 million gallons sold at an average price of $2.14 per gallon. The average selling price per gallon for the acquired operations was higher than the average selling price for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further away from the primary areas of propane supply than are the markets served by our historical operations.

We generated $106.2 million of revenue from the sales of distillates during the year ended March 31, 2013, consisting of 28.9 million gallons sold at an average selling price of $3.68 per gallon.

Cost of Sales. Propane cost of sales for the year ended March 31, 2013 increased $37.4 million as compared to propane cost of sales of $117.7 million during the year ended March 31, 2012. This increase in propane cost of sales is due primarily to the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane cost of sales was lower during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to a decline in the average cost per gallon sold of $0.47 during the year ended March 31, 2013, as compared to an average price per gallon sold of $1.50 during the year ended March 31, 2012. Excluding the effect of these acquisitions, volumes sold during the year ended March 31, 2013 were

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higher than volumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder than that of fiscal 2012.

Our acquired Osterman, Pacer, North American, and Downeast operations had propane cost of sales of $63.1 million during the year ended March 31, 2013, consisting of 54.9 million gallons sold at an average cost of $1.15 per gallon. The average cost per gallon for the acquired operations was higher than the average cost for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further away from the primary areas of propane supply than are the markets served by our historical operations.

We had $90.8 million of cost of sales for distillates during the year ended March 31, 2013, consisting of 28.9 million gallons sold at an average cost of $3.15 per gallon.

Operating Expenses. Operating expenses of our retail propane segment increased $49.5 million during the year ended March 31, 2013 as compared to operating expenses of $39.2 million during the year ended March 31, 2012. This increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $47.5 million of operating expense during the year ended March 31, 2013.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased $1.9 million during the year ended March 31, 2013 as compared to general and administrative expenses of $9.0 million during the year ended March 31, 2012. The principal factor causing the increase is the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $5.4 million of general and administrative expense during the year ended March 31, 2013. General and administrative expense included $4.3 million of acquisition expenses during the year ended March 31, 2012.

Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased $14.0 million during the year ended March 31, 2013 as compared to depreciation and amortization expense of $11.5 million during the year ended March 31, 2012. The increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $13.1 million of depreciation and amortization expense during the year ended March 31, 2013.

Operating Income. Our retail propane segment had operating income of $46.9 million during the year ended March 31, 2013 compared to operating income of $9.6 million during the year ended March 31, 2012. The increased operating income is due in part to the acquired operations of Osterman, Pacer, North American, and Downeast. Excluding these acquired operations, our retail propane segment’s operating income was higher during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to improved margins on propane sales, and to increased sales volumes. During the year ended March 31, 2012, the winter was one of the warmest on record. As a result, demand for propane was low, which resulted in reduced sales volumes during fiscal 2012.

Seasonality

Seasonality impacts our liquids and retail propane segments. A large portion of our retail propane operation is in the residential market where propane is used primarily for heating. During the year ended March 31, 2014, 74% of our retail propane volume was sold during the peak heating season from October through March. Consequently, for these two segments, sales, operating profits and operating cash flows are generated mostly in the third and fourth quarters of each fiscal year. See “—Liquidity, Sources of Capital and Capital Resource Activities — Cash Flows.”

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. Our cash flows from operations are discussed below.

Our borrowing needs vary significantly during the year due to the seasonal nature of our business. Our greatest working capital borrowing needs generally occur during the period of June through December, when we are building our natural gas liquids inventories in anticipation of the heating season. Our working capital borrowing needs generally decline during the period of January through March, when the cash flows from our retail propane and liquids segments are the greatest.

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. Available cash, for any quarter, generally consists of all cash on hand at the end of that quarter less the amount of cash reserves established by our general partner to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.

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We believe that our anticipated cash flows from operations and the borrowing capacity under our Credit Agreement are sufficient to meet our liquidity needs. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital. Our ability to raise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances that we can raise additional capital to meet these needs (see Part I, Item 1A, “Risk Factors”). Commitments or expenditures, if any, we may make toward any acquisition projects are at our discretion.

We continue to pursue a strategy of growth through acquisitions. We expect to consider financing future acquisitions through a variety of sources, including the use of available capacity on our Revolving Credit Facility (as defined below), the issuance of equity to sellers of the businesses we acquire, private placements of common units or debt securities, and public offerings of common units or debt securities. Our ability to raise additional capital through the issuance of debt or equity securities will have a significant impact on our ability to continue to pursue our growth strategy.

Credit Agreement

On June 19, 2012, we entered into the Credit Agreement with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, “Revolving Credit Facility”).

The Working Capital Facility had a total capacity of $935.5 million for cash borrowings and letters of credit at March 31, 2014. At March 31, 2014, we had outstanding cash borrowings of $389.5 million and outstanding letters of credit of $270.6 million on the Working Capital Facility. The Expansion Capital Facility had a total capacity of $785.5 million for cash borrowings at March 31, 2014. At March 31, 2014, we had outstanding cash borrowings of $532.5 million on the Expansion Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time.

The commitments under the Credit Agreement expire on November 5, 2018. We have the right to pre-pay outstanding borrowings under the Credit Agreement without incurring any penalties, and pre-payments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At March 31, 2014, the interest rate in effect on outstanding LIBOR borrowings was 1.91%, calculated as the LIBOR rate of 0.16% plus a margin of 1.75%. At March 31, 2014, the interest rate in effect on letters of credit was 1.75%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At March 31, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

	Amount		Rate
Expansion Capital Facility —
LIBOR borrowings	$	532,500	1.91	%
Working Capital Facility —
LIBOR borrowings	358,000		1.91	%
Base rate borrowings	31,500		4.00	%

The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our “leverage ratio,” as defined in the Credit Agreement, cannot exceed 4.25 to 1.0 at any quarter end. At March 31, 2014, our leverage ratio was approximately 3 to 1. The Credit Agreement also specifies that our “interest coverage ratio,” as defined in the Credit Agreement, cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At March 31, 2014, our interest coverage ratio was approximately 7 to 1.

The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

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At March 31, 2014, we were in compliance with the covenants under the Credit Agreement.

Senior Notes

On June 19, 2012, we entered into the Note Purchase Agreement whereby we issued $250.0 million of Senior Notes in a private placement (the “Senior Notes”). The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The Senior Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which are described above.

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) non-payment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the Senior Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the Senior Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding Senior Notes of any series may declare all of the Senior Notes of such series to be due and payable immediately.

At March 31, 2014, we were in compliance with the covenants under the Note Purchase Agreement and the Senior Notes.

Unsecured Notes

On October 16, 2013, we issued $450.0 million of 6.875% senior unsecured notes (the “Unsecured Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $438.4 million, after the initial purchasers’ discount of $10.1 million and estimated offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

The Unsecured Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the Unsecured Notes prior to the maturity date, although we would be required to pay a premium for early redemption.

The purchase agreement and the indenture governing the Unsecured Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At March 31, 2014, we were in compliance with the covenants under the Unsecured Notes.

We also entered into a registration rights agreement whereby we have committed to exchange the Unsecured Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the Unsecured Notes on or before October 16, 2014. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the Unsecured Notes.

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Revolving Credit Balances

The following table summarizes Revolving Credit Facility borrowings:

	Average
	Daily		Lowest		Highest
	Balance		Balance		Balance
	(in thousands)
Year Ended March 31, 2014:
Expansion loans	$	392,822	$	—	$	546,000
Working capital loans	195,553		—		448,500
Year Ended March 31, 2013:
Expansion loans	$	351,355	$	254,000	$	451,000
Working capital loans	92,626		—		153,500

Business Combinations

Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, as described under Part I, Item 1, “Business — Acquisitions Subsequent to Initial Public Offering.”

Cash Flows

The following summarizes the sources (uses) of our cash flows:

	Year Ended March 31,
Cash Flows Provided by (Used in):	2014			2013			2012
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	243,303		$	146,395		$	20,459
Changes in operating assets and liabilities	(158,067		)	(13,761		)	69,870
Operating activities	$	85,236		$	132,634		$	90,329
Investing activities	(1,455,373		)	(546,621		)	(296,897		)
Financing activities	1,369,016			417,716			198,063

Operating Activities. The growth in our operating cash flows over the period from fiscal 2012 to fiscal 2014 was driven primarily by increased operating activity resulting from acquisitions. Changes in working capital due to changes in the timing of cash receipts and payments can have a significant impact on cash flows from operations. During fiscal 2013 and fiscal 2014, our cash outflows from investing activities included the purchase of working capital in business combinations, a portion of which has benefitted (or will benefit) cash flows from operations as the working capital is recovered. Our operating cash flows during the year ended March 31, 2012 included the sale of $30.3 million of inventory (net of purchases). This was due in part to our acquisition of assets from SemStream on November 1, 2011, in which we acquired $104.2 million of inventory. The cash paid to complete the SemStream transaction is included within cash outflows from investing activities.

Investing Activities. Our cash flows from investing activities are primarily impacted by our capital expenditures. In periods where we are engaged in significant acquisitions, we will generally realize negative cash flows in investing activities, which, depending on our cash flows from operating activities, may require us to increase the borrowings under our Revolving Credit Facility. During the year ended March 31, 2014, we completed a number of business combinations for which we paid $1.3 billion of cash, net of cash acquired, on a combined basis. Also during the year ended March 31, 2014, we paid $165.1 million for capital expenditures, which related primarily to water disposal and natural gas liquids terminal assets. Of this amount, $132.9 million represented expansion capital and $32.2 million represented maintenance capital. During the year ended March 31, 2014, we used $36.0 million of investing cash outflows from commodity derivatives and generated $24.7 million of investing cash inflows from the sale of long-lived assets.  During the year ended March 31, 2013, we completed our merger with High Sierra, for which we paid $239.3 million, net of cash

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acquired. Also during the year ended March 31, 2013, we completed 12 other acquisitions, for which we paid $251.5 million of cash, net of cash acquired, on a combined basis. Also during the year ended March 31, 2013, we paid $72.5 million for capital expenditures in addition to the acquisitions of businesses. Of this amount, $58.7 million represented expansion capital and $13.8 million represented maintenance capital. During the year ended March 31, 2013, we generated $11.6 million of investing cash inflows from commodity derivatives and $5.1 million of investing cash inflows from the sale of long-lived assets. During the year ended March 31, 2012, we completed four significant acquisitions and several smaller acquisitions. We paid a combined cash amount of $297.4 million to complete these acquisitions.

Financing Activities. Changes in our cash flow from financing activities include advances from and repayments on our revolving credit facilities, either to fund our operating or investing requirements. In periods where our cash flows from operating activities are reduced (such as during our first and second quarters), we may fund the cash flow deficits through our Working Capital Facility. During the year ended March 31, 2014, we borrowed $444.5 million on our Revolving Credit Facility (net of repayments) and issued $450.0 million of Unsecured Notes. During the year ended March 31, 2014, we paid $24.6 million of debt issuance costs. During the year ended March 31, 2013, we borrowed $263.5 million on our revolving credit facilities (net of repayments) and issued $250.0 million of Senior Notes. During the year ended March 31, 2013, we paid $20.2 million of debt issuance costs. During the year ended March 31, 2012, we borrowed $149.0 million on our revolving credit facilities (net of repayments), primarily to fund acquisitions.

Cash flows from financing activities include proceeds from sales of equity. During the year ended March 31, 2014, we completed three equity issuances for which we received net proceeds of $650.2 million on a combined basis.

Cash flows from financing activities also include distributions paid to owners. We expect our distributions to our partners to increase in future periods under the terms of our partnership agreement. Based on the number of common and subordinated units outstanding at March 31, 2014 (exclusive of unvested restricted units issued pursuant to employee compensation programs), if we made distributions equal to our minimum quarterly distribution of $0.3375 per unit ($1.35 annualized), total distributions would equal $26.8 million per quarter ($107.2 million per year). To the extent our cash flows from operating activities are not sufficient to finance our required distributions, we may be required to increase the borrowings under our Working Capital Facility.

The following table summarizes the distributions declared since our IPO:

					Amount Paid		Amount Paid
			Amount		To		To
Date Declared	Record Date	Date Paid	Per Unit		Limited Partners		General Partner
					(in thousands)		(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011	0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012	0.3500		7,735		10
April 18, 2012	April 30, 2012	May 15, 2012	0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012	0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012	0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013	0.4625		24,245		927
April 25, 2013	May 6, 2013	May 15, 2013	0.4775		25,605		1,189
July 25, 2013	August 5, 2013	August 14, 2013	0.4938		31,725		1,739
October 23, 2013	November 4, 2013	November 14, 2013	0.5113		35,908		2,491
January 23, 2014	February 4, 2014	February 14, 2014	0.5313		42,150		4,283
April 24, 2014	May 5, 2014	May 15, 2014	0.5513		43,737		5,754

On May 5, 2011, we made a distribution of $3.9 million from available cash to our general partner and common unitholders at March 31, 2011. Also in May 2011, we used $65.0 million of the proceeds from our IPO to repay advances under our previous credit facility.

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Contractual Obligations

The following table summarizes our contractual obligations at March 31, 2014 for our fiscal years ending thereafter:

			For the Years Ending March 31,								After March 31,
	Total		2015		2016		2017		2018		2018
	(in thousands)
Principal payments on long-term debt —
Expansion capital borrowings	$	532,500	$	—	$	—	$	—	$	—	$	532,500
Working capital borrowings	389,500		—		—		—		—		389,500
Senior Notes	250,000		—		—		—		25,000		225,000
Unsecured Notes	450,000		—		—		—		—		450,000
Other long-term debt	14,914		7,081		3,614		2,356		1,449		414
Interest payments on long-term debt —
Revolving credit facility(1)	114,936		24,986		24,986		24,986		24,986		14,992
Senior Notes	99,750		16,625		16,625		16,625		16,209		33,666
Unsecured Notes	247,500		30,938		30,938		30,938		30,938		123,748
Other long-term debt	814		372		213		123		82		24
Letters of credit	270,626		—		—		—		—		270,626
Future minimum lease payments under other noncancelable operating leases	428,030		133,170		93,454		64,209		49,802		87,395
Fixed-price commodity purchase commitments	39,117		39,117		—		—		—		—
Index-priced commodity purchase commitments(2)	982,850		982,706		144		—		—		—
Total contractual obligations	$	3,820,537	$	1,234,995	$	169,974	$	139,237	$	148,466	$	2,127,865
Natural gas liquids gallons under fixed-priced purchase commitments (thousands)(3)	31,111		31,111		—		—		—		—
Natural gas liquids gallons under index-priced purchase commitments (thousands)(3)	522,947		522,827		120		—		—		—
Crude oil barrels under index-priced purchase commitments (thousands)(3)	4,016		4,016		—		—		—		—

(1)The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at March 31, 2014. See Note 8 to our consolidated financial statements included in this Annual Report for additional information on our Credit Agreement.

(2)Index prices are based on a forward price curve at March 31, 2014. A theoretical change of $0.10 per gallon in the underlying commodity price at March 31, 2014 would result in a change of $52.3 million in the value of our index-based natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at March 31, 2014 would result in a change of approximately $8.0 million in the value of our index-based crude oil purchase commitments.

(3)At March 31, 2014, we had fixed-price and index-price sales contracts for 63.9 million and 272.5 million gallons of natural gas liquids, respectively. At March 31, 2014, we had index-price sales contracts for 7.1 million barrels of crude oil.

Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases described in Note 10 to our consolidated financial statements included in this Annual Report.

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Environmental Legislation

Please see “Item 1 — Business — Government Regulation — Greenhouse Gas Regulation” for a discussion of proposed environmental legislation and regulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure or outcome of any future legislation or regulations or the eventual cost we could incur in compliance.

Trends

Crude Oil Logistics

Crude oil prices fluctuate widely due to changes in supply and demand conditions. The opportunity to generate revenues in our crude oil logistics business is heavily influenced by the volume of crude oil being produced. Currently, production of crude oil in North America is high, but changes in the level of production could impact our ability to generate revenues in the future.

The spread between the prices of crude oil in different locations can also fluctuate widely. If these price differences are high, we are able to generate increased margins by transporting crude oil from lower-price markets to higher-price markets. During the year ended March 31, 2013, the spread between crude oil prices in the mid-continent region and crude oil prices in south Texas widened, which gave us the opportunity to generate favorable margins by transporting crude oil from one region to the other. During the year ended March 31, 2014, spreads narrowed considerably, which had a significant impact on our operations in the Rocky Mountain and South Texas regions. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved.

Water Solutions

Our opportunity to earn revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. Recently, production has been strong in most of these regions, but a future decline in the level of production could have an adverse impact on profitability.

During the year ended March 31, 2014, we completed three separate acquisitions of water solutions businesses with operations in Texas. As a result, the geographic mix of our water solutions segment has changed, and we expect a greater share of the revenues from this segment to be generated from our operations in the Permian and Eagle Ford Basins in Texas than in the past.

During the year ended March 31, 2014, the revenues of our water solutions segment were lower than our expectations and the operating expenses of our water solutions segment were higher than our expectations. This related primarily to our operations in the Eagle Ford Basin in Texas, which were obtained through several acquisitions during the year ended March 31, 2014. We have incurred higher than expected expenses, and have generated lower revenue than expected, in the process of bringing these operations up to the standards we have established for our water solutions business.

Liquids

The volumes we sell in our wholesale natural gas liquids business are heavily dependent on the demand for propane and butane, which is influenced by weather conditions. The margins we generate in our wholesale natural gas liquids business are influenced by changes in prices over the course of a year. During years when demand is higher during the winter months, we have the opportunity to utilize our storage assets to increase margins. Weather conditions during the recent winter season were colder than normal. As a result, the demand for natural gas liquids increased considerably, which had a favorable impact on our sales volumes. The demand has also resulted in increases to market prices for natural gas liquids. This has had a favorable impact on product margins, based on the fact that we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory.

Retail Propane

The volumes we sell in our retail propane business are heavily dependent on weather conditions, as cold weather significantly increases customer demand for propane. During times of lower propane prices, margins per gallon typically increase. During times of higher propane prices, margins per gallon typically decrease. Weather conditions during the recent winter season were colder than normal. As a result, the demand for natural gas liquids increased considerably, which had a favorable impact on our sales volumes. The demand also resulted in increases to market prices for natural gas liquids. This had a favorable impact on product margins, based on the fact that we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory. The sharp rise in prices may increase the collectability risk of accounts receivable, and the recent high

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prices may create downward pressure on future demand, as some customers may invest in making their homes more energy efficient or may take other steps to reduce their need for propane.

Renewables

The spread between the prices of ethanol in different locations can fluctuate widely. If these price differences are high, we are able to generate increased margins by transporting ethanol from lower-price markets to higher-price markets. During the last few months of the fiscal year ended March 31, 2014, the spread between ethanol prices in different markets widened, which gave us the opportunity to generate favorable margins by transporting ethanol from one region to the other. During April 2014, ethanol price spreads between regions narrowed considerably.

Recent Accounting Pronouncement

In April 2014, the Financial Accounting Standards Board issued an Accounting Standards Update that changes the criteria for reporting discontinued operations. Under the new standard, a disposal of part of an entity is not classified as a discontinued operation unless the disposal represents a strategic shift that will have a major effect on an entity’s operations and financial results. We adopted the new standard during the fiscal year ended March 31, 2014.

As described in Note 14 to our consolidated financial statements included elsewhere in this Annual Report, during the year ended March 31, 2014, we sold our compressor leasing business and wound down our natural gas marketing business. These actions do not represent a strategic shift that had a major effect on our operations, and do not meet the criteria under the new accounting standard for these businesses to be reported as discontinued operations.

Critical Accounting Policies

The preparation of financial statements and related disclosures in compliance with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Partnership’s operations and the use of estimates made by management. We have identified the following accounting policies that are most important to the portrayal of our financial condition and results of operations. Changes in these policies could have a material effect on the financial statements.

The application of these accounting policies necessarily requires subjective or complex judgments regarding estimates and projected outcomes of future events that could have a material effect on our financial statements.

Revenue Recognition

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record our terminaling, storage and service revenues at the time the service is performed and we record tank and other rentals over the term of the lease. Revenues for the wastewater disposal business are recognized upon receipt of the wastewater at our disposal facilities.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included in revenues in the consolidated statements of operations.

We enter into certain contracts whereby we agree to purchase product from a counterparty and to sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Impairment of Long-Lived Assets

Goodwill is subject to at least an annual assessment for impairment. We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant. To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. We completed the assessment of each of our reporting units and determined it was more likely than not that no impairment existed for the year ended March 31, 2014. The assessment of the value of our reporting units requires us to make certain assumptions relating to future operations. When evaluating operating performance, various factors are considered, such as current and changing economic conditions and the commodity price environment, among others. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge.

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We evaluate property, plant and equipment and amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value.

We evaluate equity method investments for impairment when we believe the current fair value may be less than the carrying amount. We record impairments of equity method investments if we believe the decline in value is other than temporary.

Asset Retirement Obligations

We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. We have recorded a liability of $2.3 million at March 31, 2014. This liability is related to the wastewater disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

In addition to the obligations described above, we may be obligated to remove facilities, or perform other remediation, upon retirement of certain assets. However, we do not believe the present value of such asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

Depreciation expense represents the systematic write-off of the cost of our property and equipment, net of residual or salvage value (if any), to the results of operations for the quarterly and annual periods during which the assets are used. We depreciate the majority of our property and equipment using the straight-line method, which results in our recording depreciation expense evenly over the estimated life of the individual asset. The estimate of depreciation expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. At the time we acquire and place our property and equipment in service, we develop assumptions about such lives and residual values that we believe are reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation expense amounts prospectively. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset, changes in technology that render an asset obsolete, or changes in expected salvage values.

Amortization of Intangible Assets

Amortization expense represents the systematic write-off of the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are used. We amortize the majority of these intangible assets using the straight-line method, which results in our recording amortization expense evenly over the estimated life of the individual asset. The estimate of amortization expense requires us to make assumptions regarding the useful economic lives of our assets. At the time we acquire intangible assets, we develop assumptions about the lives of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which could change our amortization expense amounts prospectively. Examples of such circumstances include changes in customer attrition rates and changes in laws and regulations that could limit the estimated economic life of an asset.

Business Combinations

We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using the “acquisition method,” in which the assets acquired and liabilities assumed are recorded at their estimated fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage and transportation contracts, and employee compensation commitments. The excess of purchase price over the net fair value of acquired assets over the assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Generally, we have up to one year from the acquisition date to finalize the identification and valuation of acquired assets and liabilities. The impact of subsequent changes to the identification of assets and liabilities may require retrospective adjustments to our previously-reported consolidated financial position and results of operations.

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Inventory

Our inventory consists primarily of crude oil, natural gas liquids, refined products, ethanol, and biodiesel. The market values of these commodities change on a daily basis as supply and demand conditions change. We value our inventory using the weighted-average cost and first-in first-out methods. At the end of each fiscal year, we also perform a “lower of cost or market” analysis; if the cost basis of the inventory would not be recoverable based on market prices at the end of the year, we reduce the book value of the inventory to the recoverable amount. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business to sell the inventory in retail markets. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost or market write-down if we expect the market values to recover by our fiscal year end of March 31. We are unable to control changes in the market value of these commodities and are unable to determine whether write-downs will be required in future periods. In addition, write-downs at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

Equity-Based Compensation

Our general partner has granted certain restricted common units to employees and directors under a long-term incentive plan. These units vest in tranches, subject to the continued service of the recipients.

We record the expense for the first tranche of each award on a straight-line basis over the period beginning with the grant date of the awards and ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previous tranche and ending with the vesting date of the tranche.

At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

We report unvested units as liabilities on our consolidated balance sheets. When units vest and are issued, we record an increase to equity.

Item 7A.Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

At March 31, 2014, a significant portion of our long-term debt is variable-rate debt. Changes in interest rates impact the interest payments of our variable-rate debt but generally do not impact the fair value of the liability. Conversely, changes in interest rates impact the fair value of the fixed-rate debt but do not impact its cash flows.

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31, 2014, we had $922.0 million of outstanding borrowings under our Revolving Credit Facility at a rate of 1.98%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.2 million on the $922.0 million of outstanding borrowings on the Revolving Credit Facility at March 31, 2014.

Commodity Price and Credit Risk

Our operations are subject to certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, propane, and other products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract.

As is customary in the crude oil industry, we generally receive payment from customers for sale of crude oil on a monthly basis. As a result, receivables from individual customers in our crude oil logistics business are generally higher than the receivables from customers in our other segments.

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to

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senior management and to marketing operations personnel. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, restrictions on product liftings, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. The principal counterparties associated with our operations at March 31, 2014 were retailers, resellers, energy marketers, producers, refiners, and dealers.

The natural gas liquids and crude oil industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential of sales prices over supply costs. As a result, our profitability may be impacted by changes in wholesale prices of natural gas liquids and crude oil. When there are sudden and sharp increases in the wholesale cost of natural gas liquids and crude oil, we may not be able to pass on these increases to our customers through retail or wholesale prices. Natural gas liquids and crude oil are commodities and the price we pay for them can fluctuate significantly in response to supply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost increases can significantly affect our realized margins. Sudden and extended wholesale price increases could reduce our gross margins and could, if continued over an extended period of time, reduce demand by encouraging end users to conserve or convert to alternative energy sources.

We engage in derivative financial and other risk management transactions, including various types of forward contracts and financial derivatives, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions, and to help ensure the availability of product during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. We may experience net unbalanced positions from time to time. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.

Although we use derivative commodity instruments to reduce the market price risk associated with forecasted transactions, we have not accounted for such derivative commodity instruments as hedges. We record the changes in fair value of these derivative commodity instruments within cost of sales. The following table summarizes the hypothetical impact on the fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):

	Increase
	(Decrease)
	To Fair Value
Crude oil (crude oil logistics segment)	$	(13,528	)
Crude oil (water solutions segment)	(6,365		)
Propane (liquids segment)	461
Other products (liquids segment)	2,410
Refined products (refined products segment)	5,690
Renewables (renewables segment)	1,776

Fair Value

We use observable market values for determining the fair value of our trading instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis.

Item 8.Financial Statements and Supplementary Data

Our consolidated financial statements beginning on page F-1 of this Annual Report, together with the report of Grant Thornton LLP, our independent registered public accounting firm, are incorporated by reference into this Item 8.

Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

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Item 9A.Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rule 13(a)-15(e) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), that are designed to provide reasonable assurance that information required to be disclosed in our filings and submissions under the Exchange Act is recorded, processed, summarized and reported within the periods specified in the rules and forms of the SEC and that such information is accumulated and communicated to our management, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure.

We completed an evaluation under the supervision and with participation of our management, including the principal executive officer and principal financial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures at March 31, 2014. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31, 2014, such disclosure controls and procedures were effective to provide the reasonable assurance described above.

Changes in Internal Control over Financial Reporting

Other than changes that have resulted or may result from our business combinations during the year ended March 31, 2014, as discussed below, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)—15(f) of the Exchange Act) during the three months ended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We acquired Gavilon Energy on December 2, 2013, as described in Note 4 to our consolidated financial statements included in this Annual Report. At this time, we continue to evaluate the business and internal controls and processes of Gavilon Energy and are making various changes to its operating and organizational structure based on our business plan. We are in the process of implementing our internal control structure over this acquired business. Our evaluation and integration efforts related to those operations have continued into fiscal 2015.

Management’s Report on Internal Control Over Financial Reporting

The management of the Partnership and subsidiaries is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rule 13(a)-15(f). Under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in 1992 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO framework.

As permitted by SEC rules, we have excluded the businesses of Gavilon Energy from our evaluation of the effectiveness of internal control over financial reporting for the year ended March 31, 2014 due to their size and complexity and the limited time available to complete the evaluation. The operations excluded from our evaluation represent 31% of our total assets at March 31, 2014, 30% of our total revenues for the year ended March 31, 2014, and 10% of our operating income for the year ended March 31, 2014.

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective at March 31, 2014.

Our internal control over financial reporting at March 31, 2014 has been audited by Grant Thornton LLP, an independent registered public accounting firm, as stated in their report, which appears in “Item 15 — Exhibits and Financial Statement Schedules” of this Annual Report.

Item 9B.Other Information

None.

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PART III

Item 10.Directors, Executive Officers and Corporate Governance

Board of Directors of our General Partner

NGL Energy Holdings LLC, our general partner, manages our operations and activities on our behalf through its directors and executive officers, which executive officers are also officers of our operating company. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. The NGL Energy GP Investor Group appoints all members to the board of directors of our general partner.

The board of directors of our general partner currently has eleven members. The board of directors of our general partner has determined that Mr. Kneale, Mr. Cropper, and Mr. Guderian satisfy the New York Stock Exchange (“NYSE”) and SEC independence requirements. The NYSE does not require a listed publicly traded limited partnership like us to have a majority of independent directors on the board of directors of our general partner. In addition, we are not required to have a nominating and corporate governance committee.

In evaluating director candidates, the NGL Energy GP Investor Group assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of the board of directors of our general partner to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. Our general partner has no minimum qualifications for director candidates. In general, however, the NGL Energy GP Investor Group reviews and evaluates both incumbent and potential new directors in an effort to achieve diversity of skills and experience among the directors of our general partner and in light of the following criteria:

·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.

Although our general partner does not have a formal policy in regard to the consideration of diversity in identifying director nominees, qualified candidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.

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Directors and Executive Officers

Directors of our general partner are appointed by the NGL Energy GP Investor Group and hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors of our general partner. The following table shows information regarding the current directors of our general partner and our executive officers.

Name	Age	Position with NGL Energy Holdings LLC
H. Michael Krimbill	60	Chief Executive Officer and Director
Atanas H. Atanasov	41	Chief Financial Officer and Treasurer
James J. Burke	58	President, NGL Energy Partners and Director
Shawn W. Coady	52	President and Chief Operating Officer, Retail Division and Director
Todd M. Coady	56	Vice President, Administration
David C. Kehoe	55	Executive Vice President, NGL - Crude Logistics
Patrice A. Lemon	53	Senior Vice President, Accounting
Vincent J. Osterman	57	President, Eastern Retail Propane Operations and Director
Kevin C. Clement	55	Director
Carlin G. Conner	46	Director
Stephen L. Cropper	64	Director
Bryan K. Guderian	54	Director
James C. Kneale	62	Director
John T. Raymond	43	Director
Patrick Wade	44	Director

H. Michael Krimbill. Mr. Krimbill has served as our Chief Executive Officer since October 2010 and as a member of the board of directors of our general partner since its formation in September 2010. From February 2007 through September 2010, Mr. Krimbill managed private investments. Mr. Krimbill was the President and Chief Financial Officer of Energy Transfer Partners, L.P. from 2004 until his resignation in January 2007. Mr. Krimbill joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as Vice President and Chief Financial Officer in 1990. Mr. Krimbill was President of Heritage Propane Partners, L.P. from 1999 to 2000 and President and Chief Executive Officer of Heritage Propane Partners, L.P. from 2000 to 2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners, L.P., from 2000 to January 2007. Mr. Krimbill is also currently a member of the board of directors of Pacific Commerce Bank.

Mr. Krimbill brings leadership, oversight and financial experience to the board. Mr. Krimbill provides expertise in managing and operating a publicly traded partnership, including substantial expertise in successfully acquiring and integrating propane and midstream businesses. Mr. Krimbill also brings financial expertise to the board, including through his prior service as a chief financial officer. As a director for other public companies, Mr. Krimbill also provides cross board experience.

Atanas H. Atanasov. Mr. Atanasov was appointed as our Chief Financial Officer in May 2013. Mr. Atanasov joined our management team in November 2011, and previously served as our Senior Vice President of Finance and Treasurer. Prior to joining NGL, Mr. Atanasov spent nine years at GE Capital, working in lending and leveraged equity. Prior to GE Capital, he was with The Williams Companies, Inc. Mr. Atanasov is a Certified Public Accountant and holds an M.B.A. from the University of Tulsa and a B.S. in Accounting from Oral Roberts University.

James J. Burke. Mr. Burke serves as the President of NGL Energy Partners and joined the board of directors of our general partner in 2012. Mr. Burke was one of High Sierra’s co-founders and served as Chairman of the High Sierra board and President and Chief Executive Officer of the High Sierra general partner since September 2010. From July 2004 to September 2010, Mr. Burke was the High Sierra general partner’s Managing Director. Mr. Burke, along with three other entrepreneurs, co-founded Petro Source Partners, LP, where he ran six business units throughout the United States and Canada for the company over a 17-year span. Prior to that, Mr. Burke served as Manager of Crude Oil Acquisitions at Asamera Oil (United States) Inc. from 1981 to 1984. Mr. Burke began his career as a Crude Oil Representative at Permian Corporation, where he worked from 1978 to 1981. Mr. Burke also serves as the Managing Director of Impact Energy Services, LLC. Mr. Burke received his B.S. from University of Colorado in 1978.

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Shawn W. Coady. Dr. Coady has served as our President and Chief Operating Officer, Retail Division, since April 2012 and previously served as our Co-President and Chief Operating Officer, Retail Division from October 2010 through April 2012. Dr. Coady has also served as a member of the board of directors of our general partner since its formation in September 2010. Dr. Coady has served as an officer of Hicks Oils & Hicksgas, Incorporated, or HOH, since March 1989. HOH contributed its propane and propane related assets to Hicks LLC, and the membership interests in Hicks LLC were contributed to us as part of our formation transactions. Dr. Coady was an executive officer of Bachtold Brothers, Incorporated, a family owned company, when it filed for Chapter 7 bankruptcy protection in October 2005. Dr. Coady was also the President of Gifford from March 1989 until the membership interests in Gifford were contributed to us as part of our formation transactions. Dr. Coady has served as a director and as a member of the executive committee of the Illinois Propane Gas Association since 2004. Dr. Coady has also served as the Illinois state director of the National Propane Gas Association since 2004. Dr. Coady has a B.A. in Chemistry from Emory University and an O.D. from the University of Houston. Dr. Coady is the brother of Mr. Coady.

Dr. Coady brings valuable management and operational experience to the board. Dr. Coady has over 25 years of experience in the retail propane industry, and provides expertise in both acquisition and organic growth strategies. Dr. Coady also provides insight into developments and trends in the propane industry through his leadership roles in national and state propane gas associations.

Todd M. Coady. Mr. Coady has served as our Vice President, Administration since April 2012 and previously served as our Co-President, Retail Division from October 2010 through April 2012. Mr. Coady has served as an officer of HOH since March 1989. HOH contributed its propane and propane related assets to Hicks LLC, and the membership interests in Hicks LLC were contributed to us as part of our formation transactions. Mr. Coady was also the Vice President of Gifford from March 1989 until the membership interests in Gifford were contributed to us as part of our formation transactions. Mr. Coady was an executive officer of Bachtold Brothers, Incorporated, a family owned company, when it filed for Chapter 7 bankruptcy protection in October 2005. Mr. Coady has a B.S. in Chemical Engineering from Cornell University and an M.B.A. from Rice University. Mr. Coady is the brother of Dr. Coady.

David C. Kehoe. Mr. Kehoe serves as the Executive Vice President of the NGL — Crude Logistics segment. Mr. Kehoe joined our management team through our June 2012 merger with High Sierra. Mr. Kehoe has served on High Sierra’s management team since 2007. Prior to that, Mr. Kehoe held various leadership positions with Petro Source Partners, LP from 1989 to 2007.

Patrice A. Lemon. Ms. Lemon has served as our Senior Vice President of Accounting since May 2012. Ms. Lemon previously served several roles in accounting and SEC reporting with Energy Transfer Partners, L.P. and Heritage Propane Partners, L.P. from March 2001 through May 2012. In March 2001, Ms. Lemon joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as the Manager of Financial Reporting. Ms. Lemon’s most recent role prior to joining NGL was the Director of Financial Reporting and Controller with Heritage Propane Partners, L.P. For ten years prior to joining Heritage Propane Partners, L.P., Ms. Lemon worked as an audit manager for a regional public accounting firm in Montana. Ms. Lemon received a B.A. in Accounting from Carroll College of Helena, Montana.

Vincent J. Osterman. Mr. Osterman has served as the President of Osterman Associated Companies, which contributed the assets of its propane operations to us on October 3, 2011, since August 1987. Mr. Osterman has served as President of our Eastern Retail Propane Operations and as a member of the board of directors of our general partner since October 2011. Mr. Osterman also serves as a director of the National Propane Gas Association, Propane Gas Association of New England, Energi Holdings, Inc., and the Board of Advisors of the Gaudette Insurance Agency.

With his long tenure as President of the Osterman Associated Companies, Mr. Osterman brings valuable executive and operational experience in the retail propane businesses to the board. Mr. Osterman also provides insight into developments and trends in the propane industry through his leadership roles in industry associations.

Kevin C. Clement. Mr. Clement joined the board of directors of our general partner in November 2011. Mr. Clement has served as the President of SemStream L.P., which is a wholly-owned subsidiary of SemGroup Corporation, since 2009. SemGroup Corporation has been an affiliate of NGL Energy Partners LP and its general partner since November 2011. Mr. Clement previously served as President and Chief Operating Officer of SemMaterials, which is also a wholly-owned subsidiary of SemGroup Corporation, from 2008 to 2010 and also previously served SemMaterials as Vice President of residual fuel from 2006 to 2008 and Vice President of asphalt supply and marketing from 2005 to 2006. Mr. Clement’s 31 years of experience in the energy industry includes officer positions over 24 years at Koch Industries while leading business unit divisions of NGL trading, United States refined products, asphalt and residual fuels. He is a graduate of Wichita State University’s W. Frank Barton School of Business with a B.A. in Marketing.

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Mr. Clement brings substantial executive and operational experience to the board. With his 31 years of experience in the energy industry and his familiarity with our midstream operations, Mr. Clement provides valuable insight into our business.

Carlin G. Conner. Mr. Conner joined the board of directors of our general partner in April 2014. Mr. Conner serves as President and Chief Executive Officer of SemGroup Corporation and Rose Rock Midstream GP, LLC. Mr. Conner previously served as managing director of Oiltanking GmbH, an independent worldwide storage provider of crude oil, refined petroleum products, liquid chemicals and gases, since 2012. Mr. Conner has served as a member of the board of directors of the general partner of Oiltanking Partners, L.P., a publicly traded master limited partnership engaged in independent terminaling, storage and transportation of crude oil, refined petroleum products and liquefied petroleum gas (“Oiltanking Partners”), since March 2011 and was elected chairman in July 2011 in connection with the completion of the initial public offering of Oiltanking Partners. Mr. Conner also served as President and Chief Executive Officer of Oiltanking Partner’s general partner from March 2011 to November 2012, and as President and Chief Executive Officer of Oiltanking Holding Americas, Inc., a wholly-owned subsidiary of Oiltanking GmbH, from July 2006 to November 2012. Previously, from 2003 to 2006, he worked at Oiltanking GmbH corporate headquarters in Hamburg, Germany, where he was responsible for international business development and was on the boards of several Oiltanking GmbH ventures. He joined Oiltanking Houston, L.P. in 2000. He began his career at GATX Terminals Corporation in various roles including operations and commercial management. Mr. Conner has more than 23 years of experience in the midstream industry.

Mr. Conner provides the Board more than 23 years of experience in the midstream industry and executive level experience gained through his services with Oiltanking GmbH and its affiliates. He also has substantial board experience related to management and oversight of a midstream publicly traded master limited partnership. His industry knowledge and board experience allow him to be a valuable contributor to the Board.

Stephen L. Cropper. Mr. Cropper joined the board of directors of our general partner in June 2011. Mr. Cropper held various positions during his 25-year career at The Williams Companies, Inc., including serving as the President and Chief Executive Officer of Williams Energy Services, a Williams operating unit involved in various energy-related businesses, until his retirement in 1998. Mr. Cropper served as a director of Energy Transfer Partners L.P. from 2000 through 2005. Since Mr. Cropper’s retirement from The Williams Companies, Inc. in 1998, he has been a consultant and private investor and also served as a director of Sunoco Logistics Partners, L.P., NRG Energy, Inc., and Berry Petroleum Company.

Mr. Cropper brings substantial experience in the energy business and in the marketing of energy products to the board. With his significant management and governance experience, Mr. Cropper provides important skills in identifying, assessing and addressing various business issues. As a director for other public companies, Mr. Cropper also provides cross board experience.

Bryan K. Guderian. Mr. Guderian joined the board of directors of our general partner in May 2012. Mr. Guderian has served as Senior Vice President of Operations of WPX Energy, Inc. since August 2011. Mr. Guderian previously served as Vice President of the Exploration & Production unit of The Williams Companies, Inc. from 1998 until August 2011, where he had responsibility for overseeing international operations. Mr. Guderian has served as a director of Apco Oil & Gas International Inc., since 2002 and as a director of Petrolera Entre Lomas S.A. since 2003.

Mr. Guderian brings considerable upstream experience to the board including executive, operational and financial expertise from 30 years of petroleum industry involvement, the majority of which has been focused in exploration and production.

James C. Kneale. Mr. Kneale joined the board of directors of our general partner in May 2011. Mr. Kneale served as President and Chief Operating Officer of ONEOK, Inc., from January 2007, and ONEOK Partners, L.P., from May 2008, until his retirement in January 2010. After joining ONEOK in 1981, Mr. Kneale served in various other roles, including Chief Financial Officer from 1999 through 2006. Mr. Kneale also served as a director of ONEOK Partners, L.P. from 2006 until his retirement in January 2010. Mr. Kneale is a former CPA and has a B.B.A. in Accounting in 1973 from West Texas A&M in Canyon, Texas.

Mr. Kneale brings extensive executive, financial and operational experience to the board. With nearly 30 years of experience in the natural liquids gas industry in numerous positions, Mr. Kneale provides valuable insight into our business and industry.

John T. Raymond. Mr. Raymond joined the board of directors of our general partner in August 2013. Mr. Raymond is the Founder and Majority Owner of The Energy & Minerals Group of which he has been a Managing Partner and the Chief Executive Officer since its September 2006 inception. Mr. Raymond has held executive leadership positions with various energy companies, including President and Chief Executive Officer of Plains Resources Inc. (the predecessor entity of Vulcan Energy Corporation), President and Chief Operating Officer of Plains Exploration and Production Company and was a Director of Plains All American Pipeline, LP.

Mr. Raymond is also currently a director of American Energy Ohio Holdings, LLC, Ferus Inc., Ferus Natural Gas Fuels Inc., Iron Ore Holdings, Lighthouse Oil & Gas GP, LLC, MarkWest Utica EMG, LLC, Medallion Midstream, LLC, Plains All American GP LLC and Tallgrass MLP GP LLC. Mr. Raymond manages various private investments through personally held Lynx Holdings,

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LLC. Mr. Raymond received a B.S.M. from the A.B. Freeman School of Business at Tulane University with dual concentrations in finance and accounting and currently sits on the Board of the Business School Council.

Patrick Wade. Mr. Wade has served as a member of the High Sierra board since November 2008 and a member of the board of directors of our general partner since 2012. Mr. Wade has twenty years of experience in the energy sector. In 2002, Mr. Wade co-founded Tiger Midstream Investments, a natural gas midstream development and investment company that was involved primarily in the United States Rockies. From 2005 to 2007, Mr. Wade was a Managing Director at Bear Energy LP, responsible for investments in natural gas midstream infrastructure, as well as contracting for a diverse portfolio of natural gas storage capacity. In 2008, Mr. Wade joined The Energy & Minerals Group (“EMG”), as a Managing Director in the Houston office. EMG is the management company for a series of specialized private equity funds.  EMG focuses on investing across various facets of the global natural resource industry including the upstream and midstream segments of the energy complex.  EMG has approximately $13.3 billion of regulatory assets under management (RAUM) and approximately $6.1 billion in commitments have been allocated across the energy sector since inception. EMG is the managing partner of EMG NGL HC LLC. Mr. Wade’s primary focus is making direct investments across the natural resources industry. In addition, Mr. Wade serves on the board of directors of Medallion Midstream, L.L.C. and Ferus Inc. Mr. Wade received his Bachelor’s degree from the University of Oklahoma in 1991 and his M.B.A. from the Jesse H. Jones School of Management at Rice University in 1995.

Mr. Wade brings extensive financial and industry experience to the board. With almost 20 years of experience in the energy sector, Mr. Wade provides valuable insight into our business.

Director Appointment Rights

The Limited Liability Company Agreement of NGL Energy Holdings LLC grants certain parties the right to designate a specified number of persons to serve on the board of directors. SemGroup Corporation has the right to designate two persons to serve on the board of directors, and has designated Carlin G. Conner and Kevin C. Clement. EMG NGL HC LLC has the right to designate two persons to serve on the board of directors, and has designated John Raymond and Patrick Wade. The Coady Group (which consists of certain entities controlled by Shawn W. Coady and Todd M. Coady) and the IEP Parties (which consists of certain entities controlled by H. Michael Krimbill, Bradley K. Atkinson, and another investor who is not a member of management of the Partnership) each have the right to designate one person to serve on the board of directors. The Coady Group has designated Shawn W. Coady and the IEP Parties have designated H. Michael Krimbill.

Board Leadership Structure and Role in Risk Oversight

The board of directors of our general partner believes that whether the offices of chairman of the board and chief executive officer are combined or separated should be decided by the board, from time to time, in its business judgment after considering relevant circumstances. The board of directors of our general partner currently does not have a chairman.

The board of directors and its committees regularly review material operational, financial, compensation and compliance risks with senior management. In particular, the audit committee is responsible for risk oversight with respect to financial and compliance risks and risks relating to our audit and independent registered public accounting firm.  Our compensation committee considers risk in connection with its design and evaluation of compensation programs for our senior management. Each committee regularly reports to the board of directors.

Audit Committee

The board of directors of our general partner has established an audit committee. The audit committee assists the board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to, among other things:

·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.

The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.

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Mr. Cropper, Mr. Guderian, and Mr. Kneale currently serve on the audit committee, and Mr. Kneale serves as the chairman. The board of directors of our general partner has determined that Mr. Kneale, an independent director, is as an “audit committee financial expert” as defined under SEC rules and that each member of the audit committee is financially literate. In compliance with the requirements of the NYSE, all of the members of the audit committee are independent directors, as defined in the applicable NYSE rules.

Compensation Committee

The board of directors of our general partner has established a compensation committee. The compensation committee’s responsibilities include the following, among others:

·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.

Mr. Conner, Mr. Cropper, and Mr. Kneale currently serve on the compensation committee. Mr. Cropper serves as the chairman. The board of directors has determined that Mr. Cropper and Mr. Kneale are independent directors under applicable NYSE and Exchange Act rules.  The NYSE does not require a listed publicly-traded limited partnership to have a compensation committee consisting entirely of independent directors. 

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of beneficial ownership and reports of changes in beneficial ownership of our common units and other equity securities with the SEC. Directors, officers and greater than 10% unitholders are required by SEC regulations to furnish to us copies of all Section 16(a) forms they file with the SEC.

To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations by our directors and officers, we believe that all reporting obligations of our general partner’s directors and officers and our greater than 10% unitholders under Section 16(a) were satisfied during the year ended March 31, 2014, except as described in the paragraph below.

SemStream, L.P., a wholly-owned subsidiary of SemGroup Corporation, transferred common units to SemGroup Corporation on June 6, 2013 and reported this on Form 4 on June 10, 2013. EMG NGL HC LLC sold common units on June 6, 2013 and reported this on Form 4 on June 10, 2013. On July 1, 2013, certain restricted common units that were granted pursuant to an incentive compensation plan vested. Upon vesting of these common units, certain officers elected to have the Partnership withhold a portion of the common units, in return for which the Partnership remitted withholding payments to taxing authorities on the officers’ behalf. The resultant changes in ownership of common units for Patrice A. Lemon, Atanas H. Atanasov, James J. Burke, Shawn W. Coady, Todd M. Coady, Jeffrey A. Herbers, and David C. Kehoe were reported on Form 4 on July 30, 2013. Atanas H. Atanasov received a grant of restricted common units pursuant to an incentive compensation plan on July 16, 2013, and reported this on Form 4 on July 30, 2013.

Corporate Governance

The board of directors of our general partner has adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers, or Code of Ethics, that applies to the chief executive officer, chief financial officer, chief accounting officer, controller and all other senior financial and accounting officers of our general partner. Amendments to or waivers from the Code of Ethics will be disclosed on our website. The board of directors of our general partner has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and the Partnership.

We make available free of charge, within the “Governance” section of our website at http://www.nglenergypartners.com/governance, and in print to any unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics and the charters of the audit committee and the compensation committee of the board of directors of our general partner. Requests for print copies may be directed to Investor Relations at investorinfo@nglep.com or to Investor Relations, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, OK 74136 or

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made by telephone at (918) 481-1119. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of the audit committee and/or the board of directors of our general partner, our independent directors meet in an executive session without participation by management or non-independent directors. Mr. Kneale presides over these executive sessions.

Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: Name of the Director(s), c/o Secretary, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, OK 74136. Communications are distributed to the board, committee, or director as appropriate, depending on the facts and circumstances outlined in the communication.

Item 11.Executive Compensation

Compensation Discussion and Analysis

The year “2014” in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2014.

Introduction

The board of directors of our general partner has responsibility and authority for compensation-related decisions for our executive officers. In November 2011, the board of directors formed a compensation committee to develop our compensation program, to determine the compensation of our Chief Executive Officer, and to make recommendations to the board of directors regarding the compensation of our other executive officers. Our executive officers are also officers of our operating companies and are compensated directly by our operating companies. While we reimburse our general partner and its affiliates for all expenses they incur on our behalf, our executive officers do not receive any additional compensation for the services they provide to our general partner.

Our “named executive officers” for fiscal 2014 were:

·H. Michael Krimbill — Chief Executive Officer

·Atanas H. Atanasov — Chief Financial Officer and Treasurer

·James J. Burke — President

·Shawn W. Coady — President and Chief Operating Officer, Retail Division

·David C. Kehoe — Executive Vice President, NGL Crude Logistics

Compensation Philosophy

Our compensation philosophy emphasizes pay-for-performance, focused primarily on the ability to increase sustainable quarterly distributions to our unitholders. Pay-for-performance is based on a combination of our performance and the individual executive officer’s contribution to our performance. We believe this pay-for-performance approach generally aligns the interests of our executive officers with the interests of our unitholders, and at the same time enables us to maintain a lower level of cash compensation expense in the event our operating and financial performance do not meet our expectations.

Our executive compensation program is designed to provide a total compensation package that allows us to:

·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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Factors Enhancing Alignment with Unitholder Interests

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

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

·50% of officers’ equity awards subject to achievement of above-median total unitholder return relative to our performance peer group

·No excise tax gross-ups

·Compensation committee engages an independent compensation adviser

Compensation Setting Process

Our compensation program for our named executive officers supports our philosophy of pay-for-performance.

·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 2014, 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 2014:

·PM&P did not provide any services to the Company 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 NGL Energy Partners during fiscal 2014 were less than 1% of PM&P’s total revenue;

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

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

·None of the PM&P consultants working on Company matters own Company stock.

The compensation committee continues to monitor the independence of its compensation consultant on a periodic basis. The compensation committee is considering the recommendations provided by PM&P and is in the process of designing the fiscal 2015 compensation program.

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Elements of Executive Compensation

As part of our pay-for-performance approach to executive compensation, the compensation of our executive officers includes a significant component of incentive compensation based on our performance. We use three primary elements of compensation in our executive compensation program:

			Objective Supported
Element	Primary Purpose	How Amount Determined	Attract & Retain	Motivate & Pay for Performance	Unitholder Alignment
Base Salary	·Fixed income to compensate executive officers for their level of responsibility, expertise and experience	·Based on competition in the marketplace for executive talent and abilities	X
Cash Bonus Awards	·Rewards achievement of specific annual financial and operational performance goals ·Recognizes individual contributions to our performance	·Based on the named executive officer’s relative contribution to achieving or exceeding annual goals	X	X	X
Long-Term Equity Incentive Awards	·Motivates and rewards the achievement of long-term performance goals, including increasing the market price of our common units and the quarterly distributions to our unitholders ·Provides a forfeitable long-term incentive to encourage executive retention	·Based on the named executive officer’s expected contribution to long-term performance goals	X	X	X

Base Salary

The compensation committee periodically reviews the base salaries of our named executive officers and may recommend adjustments as necessary. We do not make automatic annual adjustments to base salary.

·Mr. Krimbill’s 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.

·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 in July 2013 to $250,000.

·Mr. Burke and Mr. Kehoe’s base salaries, which became effective on June 19, 2012 when they joined our management team upon completion of our merger with High Sierra, were $353,000 and $293,000, respectively. The base salaries of Mr. Burke and Mr. Kehoe were increased in July 2013 to $375,000 and $340,000, respectively.

·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.

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Cash Bonus Awards

Neither the compensation committee nor the Board of Directors has yet approved bonuses to be paid to the named executive officers based on performance during fiscal 2014. For fiscal 2014, none of the named executive officers was subject to a formal bonus plan, and therefore annual bonus awards for fiscal 2014 performance, if any, would be discretionary.

During fiscal 2014, bonuses were paid to the named executive officers. These bonuses were approved by the Board of Directors in fiscal 2014 at the recommendation of the compensation committee, which determined the bonus amounts using recommendations provided by the Chief Executive Officer. The bonus amounts were determined based on the contributions of the individuals since the time they joined the Partnership through the date of the bonus and based on expectations of future performance. The amounts of these bonuses were as follows:

Atanas H. Atanasov	195,000
James J. Burke	450,000
Shawn W. Coady	200,000
David C. Kehoe	425,000

Also during fiscal 2014, the compensation committee approved a bonus of $475,000 to be paid to H. Michael Krimbill. The bonus amount was determined based on the contributions of Mr. Krimbill since the time the Partnership was formed through the date of the bonus and based on expectations of future performance.

The cash bonus program for fiscal 2015 is still under development, as further described in the “Fiscal 2015 Compensation Program” section below.

Long-Term Equity Incentive Awards

In May 2011, our general partner adopted the NGL Energy Partners LP 2011 Long-Term Incentive Plan (the “LTIP”) for the employees and directors of our general partner who perform services for us. The LTIP authorizes the grant of restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards.

On June 27 2013, Mr. Atanasov was granted 10,000 restricted units in recognition of his increased responsibilities.  The restricted units will vest in five equal annual installments, the first of which vests on July 1, 2014, subject to the continued service of Mr. Atanasov. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

Previously, the compensation committee granted awards of restricted units to certain of our named executive officers during fiscal year 2013. Initial grants under the LTIP were awarded in June 2012 upon formation of the award program. Additional grants were awarded in December 2012, primarily for officers and employees who joined the Partnership in the merger with High Sierra.  The fiscal year 2013 awards were designed to incentivize retention and to enhance unitholder alignment by rewarding the officer if the value of common units increases over time. These awards vest in tranches, subject to the continued service of the recipient. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

The long-term equity incentive award program for fiscal 2015 is still under development, as further described in the “Competitive Review and Fiscal 2015 Compensation Program” section below.

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Severance and Change in Control Benefits

We do not provide any severance or change of control benefits to our named executive officers. The board of directors has the option to accelerate the vesting of the restricted units in the event of a change in control of the Partnership, although it is not under any obligation to do so.

401(k) Plan

We have established a defined contribution 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred basis. The 401(k) plan permits all eligible employees, including our named executive officers, to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. We make an employer matching contribution equal to 50% of the employee’s contribution that is not in excess of 6% of the employee’s eligible compensation (subject to annual IRS contribution limits). Our matching contributions vest over 5 years.

Other Benefits

We do not maintain a defined benefit or pension plan for our executive officers, because we believe such plans primarily reward longevity rather than performance. We provide a basic benefits package available to substantially all full-time employees, which includes a 401(k) plan and medical, dental, disability and life insurance.

Competitive Review and Fiscal 2015 Compensation Program

During fiscal 2014, PM&P conducted a competitive review of our executive compensation program and provided input to the compensation committee regarding competitive compensation levels and compensation program design. In order to provide guidance to the compensation committee regarding competitive rates of compensation, PM&P collected pay data from the following sources:

·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

·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.

Compensation Peer Group Companies

AmeriGas Partners LP	Enbridge Energy Partners, L.P.	Crosstex Energy LP
Ferrellgas Partners LP	NuStar Energy L.P.	DCP Midstream Partners LP
Star Gas Partners, L.P.	Targa Resources Partners LP	Martin Midstream Partners LP
Suburban Propane Partners, L.P.	Buckeye Partners, L.P.	Regency Energy Partners LP
ONEOK Partners, L.P.	Genesis Energy LP	Boardwalk Pipeline Partners, LP
Kinder Morgan Energy Partners, L.P.	Crestwood Midstream Partners LP	Western Gas Partners LP
Williams Partners L.P.	Magellan Midstream Partners LP

PM&P defines “market” as the combination of survey data and peer group data.  The compensation committee is considering the recommendations provided by PM&P and is in the process of designing the fiscal 2015 compensation program.

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Employment Agreements

We do not have employment agreements with any of our named executive officers.

Deductibility of Compensation

We believe that the compensation paid to the named executive officers is generally fully deductible for federal income tax purposes. We are a limited partnership and we do not meet the definition of a “corporation” subject to deduction limitations under Section 162(m) of the Code. Nonetheless, the taxable compensation paid to each of our named executive officers in calendar 2013 was less than the Section 162(m) threshold of $1,000,000. Although the value of the restricted units granted during fiscal 2014 are reflected in the Summary Compensation Table below, the grant is subject to vesting conditions. The vesting of the award is a taxable event, but the granting of the award is not.

Compensation Committee Report

The compensation committee of the board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above with management. Based on this review and discussion, the compensation committee recommended to the board of directors of our general partner that the Compensation Discussion and Analysis be included in this annual report.

Members of the compensation committee:

Stephen L. Cropper (Chairman)

Carlin G. Conner

James C. Kneale

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Relation of Compensation Policies and Practices to Risk Management

Our compensation arrangements contain a number of design elements that serve to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. This includes using restricted unit grants as a significant element of the executive compensation, as the restricted units are designed to reward the executives based on the long-term performance of the Partnership. In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

Compensation Committee Interlocks and Insider Participation

Dr. Coady is a member of the board of directors and an executive officer of our general partner, and his brother, Mr. Coady, is an executive officer of our general partner. Dr. Coady and Mr. Coady also serve as officers and directors of HOH, a family owned company. Both Dr. Coady and Mr. Coady participate in the compensation setting process of the HOH board of directors.

Summary Compensation Table for 2014

The following table includes the compensation earned by our named executive officers for fiscal years 2012-2014.

				Restricted	All Other
				Unit	Compensation
	Fiscal	Salary	Bonus (1)	Awards (2)	(3)	Total
Name and Position	Year	($)	($)	($)	($)	($)
H. Michael Krimbill	2014	117,693	475,000	—	6,493	599,186
Chief Executive Officer	2013	82,849	—	—	2,492	85,341
	2012	110,769	—	—	2,700	113,469
Atanas H. Atanasov (4)	2014	232,500	195,000	259,696	7,038	694,234
Chief Financial Officer	2013	195,000	—	743,440	2,738	941,178
James J. Burke (5)	2014	367,385	450,000	—	24,651	842,036
President	2013	275,630	—	836,400	13,015	1,125,045
Shawn W. Coady	2014	300,000	200,000	—	19,630	519,630
President and Chief Operating Officer, Retail Division	2013 2012	238,462 285,587	— —	613,700 —	17,730 20,950	869,892 306,537
David C. Kehoe (5)	2014	323,731	425,000	—	15,932	764,663
Executive Vice President, NGL Crude Logistics	2013	228,781	—	836,400	13,490	1,078,671

(1)Amounts for fiscal 2014 include discretionary bonuses paid in 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. Amounts payable based on fiscal 2014 performance, if any, have not yet been determined, but are expected to be determined during the first or second quarters of fiscal 2015.

(2)The fair values of the restricted units shown in the table above were calculated based on the closing market prices of our limited partner 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 ASC 718.

(3)The amounts in this column include matching contributions to our 401(k) plan. Amounts for Mr. Burke and Mr. Kehoe each include $8,124 for club memberships. The fiscal 2014 amount for Mr. Burke includes $9,000 for a car allowance. Amounts in this column for Dr. Coady include matching contributions to our 401(k) plan of $8,750 for fiscal 2014. Amounts in this column for Dr. Coady also include the incremental cost of the use of a company car, including depreciation, maintenance, insurance, and fuel, of $10,880 for fiscal 2014.

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(4)Mr. Atanasov was not a named executive officer prior to fiscal 2013.

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

Restricted Unit Awards

During fiscal 2014, the board of directors granted an award of restricted units to Mr. Atanasov. The restricted units will vest in tranches, subject to his continued service. The restricted units may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

2014 Grants of Plan Based Awards Table

The number of restricted units granted to our named executive officers, and their grant date fair value, are summarized below:

			Grant Date Fair Value
		Total Number of	of Restricted Units
	Grant	Restricted Units	Awarded
Name	Date	Awarded	($)
H. Michael Krimbill	n/a	—	—
Atanas H. Atanasov	June 27, 2013	10,000	259,696
James J. Burke	n/a	—	—
Shawn W. Coady	n/a	—	—
David C. Kehoe	n/a	—	—

The fair value of the restricted units shown in the table above were calculated based on the closing market price of our limited partner units on the grant date, 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 at the grant date and assumptions that a market participant might make about future distribution growth.

We record in our consolidated financial statements the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through each reporting date using the estimated fair value of the awards at the reporting date.

Outstanding Equity Awards as of March 31, 2014

The number of unvested restricted units outstanding at March 31, 2014, and their fair values at March 31, 2014, are summarized below:

		Fair Value of Unvested
	Number of Restricted Units	Restricted Units
	That Have Not Yet Vested	as of March 31, 2014
Name	at March 31, 2014	($)
H. Michael Krimbill	—	—
Atanas H. Atanasov	32,000	1,200,960
James J. Burke	40,000	1,501,200
Shawn W. Coady	10,000	375,300
David C. Kehoe	40,000	1,501,200

The fair values of the restricted units shown in the table above were calculated based on the closing market price of our limited partner units at March 31, 2014 of $37.53. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.

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2014 Option Exercises and Stock Vested

On July 1, 2013, certain of the restricted units granted vested. The value of the awards on the vesting date shown in the table below was calculated based of the closing market price of $30.49 per unit on the vesting date.

	Number of Units Acquired	Value Realized on Vesting
Name	on Vesting	($)
H. Michael Krimbill	—	—
Atanas H. Atanasov	10,000	304,900
James J. Burke	10,000	304,900
Shawn W. Coady	10,000	304,900
David C. Kehoe	10,000	304,900

Upon vesting, certain of the named executive officers elected for us to remit payments to taxing authorities in lieu of issuing units. Mr. Atanasov elected to have 3,260 units withheld, Mr. Burke elected to have 3,181 units withheld, Dr. Coady elected to have 4,235 units withheld, and Mr. Kehoe elected to have 3,184 units withheld for this purpose.

Subsequent to vesting, these individuals received distributions of $1.54 on each of the vested units during the fiscal year ended March 31, 2014.

Potential Payments upon Termination or Change in Control

We do not provide any severance or change of control benefits to our executive officers. The board of directors has the option to accelerate the vesting of the restricted units in the event of a change in control of the Partnership, although it is not under any obligation to do so. If the board of directors were to exercise its discretion to accelerate the vesting of restricted units upon a change in control, the value of such units would be the same as reported in the “Outstanding Equity Awards as of March 31, 2014” table above.

Director Compensation

Officers or employees of our general partner and its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner or its affiliates receives the following compensation for his board service:

·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.

All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Each director is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

Director Compensation for Fiscal 2014

The following table sets forth the compensation earned during fiscal 2014 by each director who is not an officer or employee of our general partner:

	Fees Earned or	Restricted Unit
	Paid in Cash	Awards	Total
Name	($)	($)	($)
Stephen L. Cropper	65,000	—	65,000
Bryan K. Guderian	65,000	—	65,000
James C. Kneale	70,000	—	70,000

These directors did not receive any equity grants under the LTIP during fiscal 2014. During fiscal 2013, each of these directors received a grant of unvested units under the LTIP. These units vest in tranches, contingent on the continued service of the directors. During fiscal 2014, a tranche of 5,000 units vested for each director. Subsequent to the vesting, these individuals received distributions of $1.54 on each of the vested units.

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Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the beneficial ownership, as of May 23, 2014 of our units by:

·each person or group of persons known by us to be a beneficial owner of more than 5% of our outstanding 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.

							Percentage of
							Total Common
					Percentage of		and
	Common	Percentage of		Subordinated	Subordinated		Subordinated
	Units	Common Units		Units	Units		Units
	Beneficially	Beneficially		Beneficially	Beneficially		Beneficially
Beneficial Owners	Owned	Owned (1)		Owned	Owned (1)		Owned (1)
5% or greater unitholders (other than officers and directors):
SemGroup Corporation (2)	9,133,409	12.23	%	—	—		11.33	%
Oppenheimer Funds, Inc. (3)	8,559,178	11.46	%	—	—		10.62	%
Goldman Sachs Asset Management, L.P. (4)	4,938,229	6.61	%	—	—		6.12	%
Directors and officers:
Atanas H. Atanasov (5)	43,908	*		—	—		*
James J. Burke (6)	308,259	*		—	—		*
Kevin C. Clement	5,000	*		—	—		*
Shawn W. Coady (7)	1,326,370	1.78	%	1,125,351	19.01	%	3.04	%
Carlin G. Conner	—	—		—	—		—
Stephen L. Cropper	25,000	*		—	—		*
Bryan K. Guderian	20,000	*		—	—		*
David C. Kehoe (8)	315,823	*		—	—		*
James C. Kneale (9)	17,500	*		—	—		*
H. Michael Krimbill (10)	970,557	1.30	%	497,846	8.41	%	1.82	%
Vincent J. Osterman (11)	3,955,437	5.29	%	—	—		4.94	%
Patrick Wade	—	—		—	—		—
John T. Raymond (12)	2,176,634	2.91	%	—	—		2.70	%
All directors and executive officers as a group (15 persons) (13)	10,491,438	14.04	%	2,747,198	46.41	%	16.45	%

* Less than 1.0%

(1)Based on 74,706,160 common units and 5,919,346 subordinated units outstanding at May 23, 2014.

(2)The mailing address for SemGroup Corporation is 6120 S. Yale Avenue, Suite 700, Tulsa, OK 74136. Carlin G. Conner, a member of the board of directors of our general partner, serves as President and Chief Executive Officer, and as a Director of SemGroup Corporation. Kevin C. Clement, a member of the board of directors of our general partner, serves as President of SemStream, L.P. and SemGas, L.P., each a subsidiary of SemGroup

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Corporation. Each of Messrs. Conner and Clement disclaims beneficial ownership of these common units. SemGroup Corporation also owns an 11.78% interest in our general partner. The information related to SemGroup Corporation, including the number of common units held, is based upon its Form 4 filed with the SEC on June 10, 2013.

(3)The mailing address for OppenheimerFunds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281. OppenheimerFunds, Inc. reported shared voting and dispositive power with respect to all common units beneficially owned. The information related to OppenheimerFunds, Inc. is based on OppenheimerFunds, Inc.’s Form 13G filed with the SEC on April 10, 2014.

(4)The mailing address for Goldman Sachs Asset Management, L.P. is 200 West Street, New York, NY 10282. Goldman Sachs Asset Management, L.P. reported shared voting and dispositive power with respect to all common units beneficially owned. The information related to Goldman Sachs Asset Management, L.P. is based on Goldman Sachs Asset Management, L.P.’s Form 13G filed with the SEC on February 13, 2014.

(5)Atanas H. Atanasov also owns a 0.40% interest in our general partner.

(6)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)Shawn W. Coady owns 21,330 of these common units. SWC Family Partnership LP owns 1,195,040 of these common units and 1,125,351 of these subordinated units. SWC Family Partnership LP is solely owned by SWC General Partner, LLC, of which Shawn W. Coady is the sole partner. Shawn W. 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 110,000 of these common units. Shawn W. 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. Shawn W. 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)David C. Kehoe also owns a 0.75% interest in our general partner through DCK GP, LLC, of which he owns 100% of the membership interests.

(9)Of these common units, 12,500 are owned by the Suzanne and Jim Kneale Living Trust.

(10)Krim2010, LLC owns 407,002 of these common units and all of these subordinated units. Krimbill Enterprises LP, H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06% of Krim2010, LLC, respectively. H. Michael Krimbill exercises the sole voting and investment power for Krimbill Enterprises LP. 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. 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. 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.

(11)Vincent J. Osterman owns 30,000 of these common units. 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 (192,816 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 729,300 common units and shared voting and investment power (with his father, Ernest Osterman) over 3,281,137 common units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. Vincent J. Osterman also owns a 0.75% interest in our general partner through VE Properties XI LLC.

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(12)EMG NGL HC, LLC owns all of these 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 disdains 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 6.73% 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.

(13)The directors and executive officers of our general partner also collectively own a 68.00% interest in our general partner.

Unless otherwise noted, each of the individuals listed above is believed to have sole voting and investment power with respect to the units beneficially held by them. The mailing address for each of the officers and directors of our general partner listed above is 6120 South Yale Avenue, Suite 805, Tulsa, OK 74136.

Securities Authorized for Issuance Under Equity Compensation Plan

The following table sets forth information regarding the securities that may be issued under the NGL Energy Partners LP Long-Term Incentive Plan, or the LTIP, at March 31, 2014.

			Number of Securities
			Remaining Available for
	Number of Securities to be	Weighted-average	Future Issuances Under
	Issued upon Exercise of	Exercise Price of	Equity Compensation Plans
	Outstanding Options,	Outstanding Options,	(Excluding Securities
	Warrants and Rights	Warrants and Rights	Reflected in Column (a))
Plan Category	(a)	(b)	(c)(1)
Equity Compensation Plans Approved by Security Holders	—	—	—
Equity Compensation Plans Not Approved by Security Holders(2)	1,311,100	—	6,169,869
Total	1,311,100	—	6,169,869

(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 and subordinated units. The maximum number of common units deliverable under the LTIP automatically increases to 10% of the issued and outstanding common and subordinated 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.

Item 13.Certain Relationships and Related Transactions and Director Independence

Our directors, executive officers, and greater than 5% unitholders collectively own an aggregate of 33,122,254 common units and 2,747,198 subordinated units, representing an aggregate 44.52% limited partner interest in us. In addition, our general partner owns a 0.1% general partner interest in us and all of our incentive distribution rights.

Distributions and Payments to Our General Partner and Its Affiliates

Our general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. Our general partner determines the amount of these expenses. In addition, our general partner owns the 0.1% general partner interest and all of the IDRs. Our general partner is entitled to receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement.

The following table summarizes the distributions and payments made by us to the NGL Energy GP Investor Group and our general partner and its affiliates in connection with our formation and to be made by us to our directors, officers, and greater than 5% owners and our general partner in connection with our ongoing operation and any liquidation. These distributions and payments were determined by and among affiliated entities before our IPO and, consequently, are not the result of arm’s length negotiations.

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Formation Stage
The consideration received by the NGL Energy LP Investor Group and our general partner and its affiliates prior to or in connection with our IPO	·5,014,222 common units; (4,839,222 common units after giving effect to the redemption) ·5,919,346 subordinated units; ·a 0.1% general partner interest; and ·the IDRs.
Operation Stage
Distributions of available cash to our directors, officers, and greater than 5% owners and our general partner	We generally make cash distributions 99.9% to our unitholders pro rata, including our directors, officers, and greater than 5% owners as the holders of an aggregate 33,122,254 common units and 2,747,198 subordinated units, and 0.1% to our general partner. In addition, when distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner is entitled to increasing percentages of the distributions, up to 48.1% of the distributions above the highest target distribution level.
	Assuming we have sufficient available cash to pay the full minimum quarterly distribution on all of our outstanding units for four quarters, our general partner would receive an annual distribution of $0.1 million on its general partner interest and our directors, officers, and greater than 5% owners would receive an aggregate annual distribution of $48.5 million on their common and subordinated units.
	If our general partner elects to reset the target distribution levels, it will be entitled to receive common units and to maintain its general partner interest.
Payments to our general partner and its affiliates	Our general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. As the sole purpose of the general partner is to act as our general partner, we expect that substantially all of the expenses of our general partner will be incurred on our behalf and reimbursed by us or our subsidiaries. Our general partner will determine the amount of these expenses.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
Liquidation Stage
Liquidation	Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

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Related Party Transactions

SemGroup Corporation

SemGroup Corporation (“SemGroup”) holds ownership interests in us and in our general partner, and has the right to appoint two members to the board of directors of our general partner. We sell product to and purchase product from affiliates of SemGroup. These transactions are included within revenues and cost of sales in our consolidated statements of operations. The transactions with SemGroup are summarized below for the year ended March 31, 2014 (in thousands):

Sales to SemGroup	$	306,780
Purchases from SemGroup	445,951

WPX Energy, Inc.

Bryan Guderian is a member of our board of directors and an executive officer of WPX Energy, Inc. (“WPX”). Since our December 2013 acquisition of Gavilon Energy, we (through the prior Gavilon Energy operations) have purchased crude oil and natural gas from and sold crude oil and natural gas to WPX. These transactions are recorded within revenues and cost of sales in our consolidated statement of operations. The relationship between Gavilon Energy and WPX preceded our acquisition of Gavilon Energy.  These transactions were entered into in the ordinary course of business and in accordance with our normal procedures for purchases and sales of crude oil and natural gas. The transactions with WPX are summarized below for the year ended March 31, 2014 (in thousands):

Sales to WPX	$	101,303
Purchases from WPX	157,729

Other Transactions

Subsequent to our merger with High Sierra, we purchased goods and services from several entities that are partially owned by Mr. Burke, Mr. Kehoe and by other members of management. These transactions are summarized below for the year ended March 31, 2014:

				Mr. Kehoe’s		Mr. Burke’s
	Nature of	Amount		Ownership Interest		Ownership Interest
Entity	Purchases	Purchased		in Entity		in Entity
		(in thousands)
Cowhouse Partners, L.L.C.	Terminaling services and transportation services	$	605	27.5	%	—
Impact Energy Services LLC	Condensate purchases	191		—		50	%
Petro Source Consulting, LLC	Equipment	170		100	%	—
Fluid Services, LLC	Crude oil purchases and transportation services	1,097		20	%	—

Subsequent to our merger with High Sierra, we provided goods and services to an entity that is partially owned by Mr. Burke. These transactions are summarized below for the year ended March 31, 2014:

				Mr. Burke’s
	Nature of	Revenues		Ownership Interest
Entity	Services	Generated		in Entity
		(in thousands)
Impact Energy Services LLC	Condensate sales	$	525	50	%

We rent office space from VE III LLC and VE Properties V, which are entities that are owned by Vincent J. Osterman and his father. We paid rent of $142,784 during the year ended March 31, 2014 to these entities.

We purchase vehicles from Hicks Motor Sales, which is an entity owned by Shawn W. Coady and Todd M. Coady. We paid $696,900 during the year ended March 31, 2014 to this entity for vehicle purchases.

Todd Coady, an executive officer of the Partnership, is the brother of Shawn Coady, who also is an executive officer of the Partnership and a member of the board of directors. Todd Coady’s annual base compensation was $200,000 until July 1, 2013, when it was increased to $225,000. During fiscal 2014, Todd Coady was granted a cash bonus of $125,000. Todd Coady was also eligible to participate in the Partnership’s 401(k) plan, and he received $5,877 of employer matching contributions during the year ended March 31, 2014.

Timothy Osterman, an employee of the Partnership, is the son of Vincent J. Osterman, who is an executive officer of the Partnership and a member of the board of directors. Timothy Osterman’s base compensation during the year ended March 31, 2014 was $83,200. During fiscal 2014, Timothy Osterman was granted a cash bonus of $90,000. Timothy Osterman was also eligible to participate in the Partnership’s 401(k) plan, and he received $5,196 of employer matching contributions during the year ended March 31, 2014.

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Registration Rights Agreement

We have entered into a registration rights agreement (as amended, the “Registration Rights Agreement”) with certain third parties (the “registration rights parties”) pursuant to which we agreed to register for resale under the Securities Act common units, including any common units issued upon the conversion of subordinated units, owned by the parties to the Registration Rights Agreement. In connection with our initial public offering, we granted registration rights to the individuals and entities that owned all of our then-outstanding common units (collectively, the “NGL Energy LP Investor Group”), and subsequently, we have granted registration rights in connection with several acquisitions. We will not be required to register such common units if an exemption from the registration requirements of the Securities Act is available with respect to the number of common units desired to be sold. Subject to limitations specified in the Registration Rights Agreement, the registration rights of the registration rights parties include the following:

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 Securities and Exchange Commission 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 eight 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

Review, Approval or Ratification of Transactions with Related Parties

The board of directors of our general partner has adopted a Code of Business Conduct and Ethics that, among other things, sets forth our policies for the review, approval and ratification of transactions with related persons. The Code of Business Conduct and Ethics provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the Code of Business Conduct and Ethics provides that our officers will make all reasonable efforts to cancel or annul the transaction.

The Code of Business Conduct and Ethics provides that, in determining whether or not to recommend the initial approval or ratification of a related party transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, including (if applicable) but not limited to:

·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 Conduct and Business Ethics.

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Director Independence

The NYSE does not require a listed publicly traded partnership like us to have a majority of independent directors on the board of directors of our general partner. For a discussion of the independence of the board of directors of our general partner, please see “Item 10 — Directors, Executive Officers and Corporate Governance—Board of Directors of our General Partner.”

Item 14.Principal Accountant Fees and Services

We have engaged Grant Thornton LLP as our independent registered public accounting firm. The following table sets forth fees we have paid Grant Thornton LLP to audit our annual consolidated financial statements and for other services for the years ended March 31, 2014 and 2013:

	2014		2013
Audit fees(1)	$	2,531,229	$	1,861,979
Audit-related fees(2)	—		47,100
Tax fees(3)	—		66,711
All other fees	70,091		—
Total	$	2,601,320	$	1,975,790

(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.

(2)Includes audits of financial statements of businesses acquired under Rule 3-05 of Regulation S-X and of our 401(k) defined contribution plan.

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

Audit Committee Approval of Audit and Non-Audit Services

The audit committee of the board of directors of our general partner has adopted a pre-approval policy with respect to services which may be performed by Grant Thornton LLP. This policy lists specific audit-related services as well as any other services that Grant Thornton LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional audit committee authorization. The audit committee receives quarterly reports on the status of expenditures pursuant to the pre-approval policy. The audit committee reviews the policy at least annually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the audit committee prior to engagement.

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PART IV

Item 15.Exhibits and Financial Statement Schedules

(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.

Exhibit Number	Description
2.1	Contribution, Purchase and Sale Agreement dated as of September 30, 2010 by and among Hicks Oils & Hicksgas, Incorporated, Hicksgas Gifford, Inc., Gifford Holdings, Inc., NGL Supply, Inc., NGL Holdings, Inc., the other stockholders of NGL Supply, Inc., Krim2010, LLC, Infrastructure Capital Management, LLC, Atkinson Investors, LLC, Silverthorne Energy Holdings LLC and Silverthorne Energy Partners LP (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
2.2	Contribution and Sale Agreement, dated August 12, 2011, by and among the Partnership and the Sellers named therein (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 7, 2011)
2.3	Contribution and Sale Agreement dated August 31, 2011, by and among the Partnership, SemStream and the other parties thereto (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on November 4, 2011)
2.4	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Liberty Propane, L.L.C. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.5	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer-Enviro Propane, L.L.C. (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.6	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer-Pittman Propane, L.L.C. (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.7	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer-Portland Propane, L.L.C. (incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.8	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer Propane (Washington), L.L.C. (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.9	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer-Salida Propane, L.L.C. (incorporated by reference to Exhibit 2.6 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.10	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer-Utah Propane, L.L.C. (incorporated by reference to Exhibit 2.7 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.11	Asset Purchase Agreement, dated as of January 16, 2012, by and among NGL Energy Partners LP and North American Propane, Inc., EnergyUSA Propane, Inc., EUSA-Allied Acquisition Corp. and EUSA Heating & Air

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Exhibit Number	Description
	Conditioning Services, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on February 10, 2012)
2.12	Waiver and First Amendment to Asset Purchase Agreement dated as of January 31, 2012 by and among NGL Energy Partners LP and North American Propane, Inc., EnergyUSA Propane, Inc., EUSA-Allied Acquisition Corp. and EUSA Heating & Air Conditioning Services, Inc. (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K/A (File No. 001-35172) filed with the SEC on April 20, 2012)
2.13	Waiver and Second Amendment to Asset Purchase Agreement dated as of February 3, 2012 by and among NGL Energy Partners LP and North American Propane, Inc., EnergyUSA Propane, Inc., EUSA-Allied Acquisition Corp. and EUSA Heating & Air Conditioning Services, Inc. (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K/A (File No. 001-35172) filed with the SEC on April 20, 2012)
2.14	Agreement and Plan of Merger, dated as of May 18, 2012, by and among NGL Energy Partners LP, NGL Energy Holdings LLC, HSELP LLC, High Sierra Energy, LP and the High Sierra Energy GP, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 21, 2012)
2.15	Agreement and Plan of Merger, dated as of May 18, 2012, by and among NGL Energy Holdings LLC, HSEGP LLC and High Sierra Energy GP, LLC (incorporated by reference to Exhibit 2.2 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 21, 2012)
2.16	Equity Purchase Agreement, dated as of October 23, 2012, among Black Hawk Gathering, L.L.C. Midstream Operations L.L.C., Pecos Gathering & Marketing, L.L.C., Striker Oilfield Services, LLC, Transwest Leasing, LLC, the owners of the Pecos Entities, NGL Energy Partners LP and Gerald L. Jensen (incorporated by reference to Exhibit 2.1 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012)
2.17	Sale Agreement, dated as of December 31, 2012, among Third Coast Towing, LLC, Jeff Kirby, Jane Helm, James Rudellat and High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 7, 2013)
2.18	LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Pearsall SWD, LLC, OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.19	LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Karnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.20	LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.21	LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.22	LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWL Operating, LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)

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Exhibit Number	Description
2.23	Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP, Gavilon, LLC and Gavilon Energy Intermediate, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013)
3.1	Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
3.2	Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
3.3	Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011)
3.4	First Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 26, 2011)
3.5	Second Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
3.6	Third Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 26, 2012)
3.7	Fourth Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 2012)
3.8	Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
3.9	Certificate of Amendment to Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
3.10	Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on February 28, 2013)
3.11	Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of August 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
4.1	First Amended and Restated Registration Rights Agreement, dated October 3, 2011, by and among the Partnership, Hicks Oils & Hicksgas, Incorporated, NGL Holdings, Inc., Krim2010, LLC, Infrastructure Capital Management, LLC, Atkinson Investors, LLC, E. Osterman Propane, Inc. and the other holders party thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 7, 2011)
4.2	Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 by and among the Partnership and SemStream (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on November 4, 2011)
4.3	Amendment No. 2 and Joinder to First Amended and Restated Registration Rights Agreement, dated January 3, 2012, by and among NGL Energy Holdings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-Portland Propane, L.L.C., Pacer Propane (Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)

112

Exhibit Number	Description
4.4	Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGL Energy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 4, 2012)
4.5	Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and between NGL Energy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
4.6	Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and between NGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2012)
4.7	Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by and between NGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust and Nitor Trust (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 19, 2012)
4.8	Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by and among NGL Energy Partners LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
4.9	Call Agreement, dated as of November 1, 2012, among Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust, Nitor Trust and NGL Energy Partners LP (incorporated by reference to Exhibit 4.1 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012)
4.10	Call Agreement, dated as of December 31, 2012, among NGL Energy Partners LP, Jeff Kirby, Jane Helm and James Rudellat (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 7, 2013)
4.11	Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
4.12	Amendment No. 1 to Note Purchase Agreement, dated as of January 15, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18, 2013)
4.13	Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 9, 2013)
4.14	Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s 6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)
4.15	Amendment No. 4 to Note Purchase Agreement, dated as of November 5, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
4.16	Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30, 2013)

113

Exhibit Number	Description
4.17	Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
4.18	Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
4.19*	First Supplemental Indenture, dated as of December 2, 2013, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee
4.20*	Second Supplemental Indenture, dated as of April 22, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiary party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee
4.21	Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
4.22	Registration Rights Agreement, dated December 2, 2013, by and among NGL Energy Partners LP and the purchasers set forth on Schedule A thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013)
10.1	Agreement Relating to Redemption of Common Units in Connection with the Underwriters’ Option to Purchase Additional Common Units with Respect to the Initial Public Offering of NGL Energy Partners LP by and among NGL Energy Partners LP, NGL Energy Holdings LLC, and each of Atkinson Investors, LLC, Infrastructure Capital Management, LLC, Hicks Oils & Hicksgas, Incorporated, Krim2010, LLC, NGL Holdings, Inc., Stanley A. Bugh, David R. Eastin, Robert R. Foster, Craig S. Jones, Mark McGinty, Brian K. Pauling, Stanley D. Perry, Daniel Post, Sharra Straight and Stephen D. Tuttle, effective as of May 9, 2011 (incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-1 (File No. 333-172186) filed on May 9, 2011)
10.2	Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders party thereto and Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
10.3	Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012)
10.4	Amendment No. 1 to Credit Agreement, dated as of January 15, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18, 2013)
10.5	Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No 001-35172) filed on May 9, 2013)
10.6	Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, each subsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank Trust Company Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)
10.7	Amendment No. 4 to Credit Agreement, dated as of November 5, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)

114

Exhibit Number	Description
10.8	Amendment No. 5 to Credit Agreement, dated as of December 23, 2013, among NGL Energy Operating, LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank and Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30, 2013)
10.9	Facility Increase Agreement among NGL Energy Operating, LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 3, 2014)
10.10	Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed on Schedule A thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013)
10.11+	Letter Agreement among Silverthorne Energy Holdings LLC, Shawn W. Coady and Todd M. Coady dated October 14, 2010 (incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
10.12+	NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011)
10.13+	Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended June 30, 2012 filed with the SEC on August 14, 2012 )
12.1*	Computation of ratios of earnings to fixed charges.
21.1*	List of Subsidiaries of NGL Energy Partners LP
23.1*	Consent of Grant Thornton LLP
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document

*Exhibits filed with this report

**Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at March 31, 2014 and 2013, (ii) Consolidated Statements of Operations for

115

the years ended March 31, 2014, 2013, and 2012, (iii) Consolidated Statements of Comprehensive Income for the years ended March 31, 2014, 2013, and 2012, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2014, 2013, and 2012 and (v) Consolidated Statements of Cash Flows for the years ended March 31, 2014, 2013, and 2012.

+Management contracts or compensatory plans or arrangements.

116

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on May 30, 2014.

NGL ENERGY PARTNERS LP
By:	NGL Energy Holdings LLC,
	its general partner
	By:	/s/ H. Michael Krimbill
		H. Michael Krimbill
		Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ H. Michael Krimbill	Chief Executive Officer and Director	May 30, 2014
H. Michael Krimbill	(Principal Executive Officer)
/s/ Atanas H. Atanasov	Chief Financial Officer	May 30, 2014
Atanas H. Atanasov	(Principal Financial Officer)
/s/ Jeffrey A. Herbers	Chief Accounting Officer	May 30, 2014
Jeffrey A. Herbers	(Principal Accounting Officer)
/s/ James J. Burke	Director	May 30, 2014
James J. Burke
/s/ Shawn W. Coady	Director	May 30, 2014
Shawn W. Coady
/s/ Kevin C. Clement	Director	May 30, 2014
Kevin C. Clement
/s/ Carlin G. Conner	Director	May 30, 2014
Carlin G. Conner
/s/ Stephen L. Cropper	Director	May 30, 2014
Stephen L. Cropper
/s/ Bryan K. Guderian	Director	May 30, 2014
Bryan K. Guderian
/s/ James C. Kneale	Director	May 30, 2014
James C. Kneale
/s/ Vincent J. Osterman	Director	May 30, 2014
Vincent J. Osterman
/s/ John T. Raymond	Director	May 30, 2014
John T. Raymond
/s/ Patrick Wade	Director	May 30, 2014
Patrick Wade

117

INDEX TO FINANCIAL STATEMENTS

NGL ENERGY PARTNERS LP
Report of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets at March 31, 2014 and 2013	F-4
Consolidated Statements of Operations for the years ended March 31, 2014, 2013, and 2012	F-5
Consolidated Statements of Comprehensive Income for the years ended March 31, 2014, 2013, and 2012	F-6
Consolidated Statements of Changes in Equity for the years ended March 31, 2014, 2013, and 2012	F-7
Consolidated Statements of Cash Flows for the years ended March 31, 2014, 2013, and 2012	F-8
Notes to Consolidated Financial Statements	F-9

F-1

Report of Independent Registered Public Accounting Firm

Partners

NGL Energy Partners LP

We have audited the accompanying consolidated balance sheets of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of March 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended March 31, 2014. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NGL Energy Partners LP and subsidiaries as of March 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of March 31, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 30, 2014 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

May 30, 2014

F-2

Report of Independent Registered Public Accounting Firm

Partners

NGL Energy Partners LP

We have audited the internal control over financial reporting of NGL Energy Partners LP (a Delaware limited Partnership) and subsidiaries (the “Partnership”) as of March 31, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Partnership’s internal control over financial reporting based on our audit. Our audit of, and opinion on, the Partnership’s internal control over financial reporting does not include the internal control over financial reporting of Gavilon, LLC (“Gavilon”), a wholly-owned subsidiary, whose financial statements reflect total assets and revenues constituting 31 and 30 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended March 31, 2014. As indicated in Management’s Report, Gavilon was acquired during the year ended March 31, 2014. Management’s assertion on the effectiveness of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of Gavilon.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of March 31, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Partnership as of and for the year ended March 31, 2014, and our report dated May 30, 2014 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

May 30, 2014

F-3

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Balance Sheets

At March 31, 2014 and 2013

(U.S. Dollars in Thousands, except unit amounts)

	March 31,
	2014			2013
				(Note 2)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,440		$	11,561
Accounts receivable - trade, net of allowance for doubtful accounts of $2,822 and $1,760, respectively	900,904			562,757
Accounts receivable - affiliates	7,445			22,883
Inventories	310,160			126,895
Prepaid expenses and other current assets	80,350			37,891
Total current assets	1,309,299			761,987
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $109,564 and $50,127, respectively	829,346			526,437
GOODWILL	1,107,006			555,220
INTANGIBLE ASSETS, net of accumulated amortization of $116,728 and $44,155, respectively	714,956			441,432
INVESTMENTS IN UNCONSOLIDATED ENTITIES	189,821			—
OTHER NONCURRENT ASSETS	16,795			6,542
Total assets	$	4,167,223		$	2,291,618
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable - trade	$	740,211		$	536,055
Accounts payable - affiliates	76,846			6,900
Accrued expenses and other payables	141,690			85,606
Advance payments received from customers	29,965			22,372
Current maturities of long-term debt	7,080			8,626
Total current liabilities	995,792			659,559
LONG-TERM DEBT, net of current maturities	1,629,834			740,436
OTHER NONCURRENT LIABILITIES	9,744			2,205
COMMITMENTS AND CONTINGENCIES
EQUITY, per accompanying statement:
General partner, representing a 0.1% interest, 79,420 and 53,676 notional units at March 31, 2014 and 2013, respectively	(45,287		)	(50,497		)
Limited partners, representing a 99.9% interest -
Common units, 73,421,309 and 47,703,313 units issued and outstanding at March 31, 2014 and 2013, respectively	1,570,074			920,998
Subordinated units, 5,919,346 units issued and outstanding at March 31, 2014 and 2013	2,028			13,153
Accumulated other comprehensive income (loss)	(236		)	24
Noncontrolling interests	5,274			5,740
Total equity	1,531,853			889,418
Total liabilities and equity	$	4,167,223		$	2,291,618

The accompanying notes are an integral part of these consolidated financial statements.

F-4

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Operations

For the Years Ended March 31, 2014, 2013, and 2012

 (U.S. Dollars in Thousands, except unit and per unit amounts)

	Year Ended March 31,
	2014			2013			2012
REVENUES:
Crude oil logistics	$	4,558,545		$	2,316,288		$	—
Water solutions	143,100			62,227			—
Liquids	2,650,425			1,604,746			1,111,139
Retail propane	551,815			430,273			199,334
Refined products	1,180,895			—			—
Renewables	176,781			—			—
Other	437,713			4,233			—
Total Revenues	9,699,274			4,417,767			1,310,473
COST OF SALES:
Crude oil logistics	4,477,397			2,244,647			—
Water solutions	11,738			5,611			—
Liquids	2,518,099			1,530,459			1,086,881
Retail propane	354,676			258,393			130,142
Refined products	1,172,754			—			—
Renewables	171,422			—			—
Other	426,613			—			—
Total Cost of Sales	9,132,699			4,039,110			1,217,023
OPERATING COSTS AND EXPENSES:
Operating	259,396			169,799			47,300
General and administrative	79,860			52,698			16,009
Depreciation and amortization	120,754			68,853			15,111
Operating Income	106,565			87,307			15,030
OTHER INCOME (EXPENSE):
Earnings of unconsolidated entities	1,898			—			—
Interest expense	(58,854		)	(32,994		)	(7,620		)
Loss on early extinguishment of debt	—			(5,769		)	—
Other, net	86			1,521			1,055
Income Before Income Taxes	49,695			50,065			8,465
INCOME TAX PROVISION	(937		)	(1,875		)	(601		)
Net Income	48,758			48,190			7,864
NET INCOME ALLOCATED TO GENERAL PARTNER	(14,148		)	(2,917		)	(8		)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(1,103		)	(250		)	12
NET INCOME ALLOCATED TO LIMITED PARTNERS	$	33,507		$	45,023		$	7,868
BASIC AND DILUTED INCOME PER COMMON UNIT	$	0.51		$	0.96		$	0.32
BASIC AND DILUTED INCOME PER SUBORDINATED UNIT	$	0.32		$	0.93		$	0.58
BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING:
Common units	61,970,471			41,353,574			15,169,983
Subordinated units	5,919,346			5,919,346			5,175,384

The accompanying notes are an integral part of these consolidated financial statements.

F-5

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income

For the Years Ended March 31, 2014, 2013, and 2012

(U.S. Dollars in Thousands)

	Year Ended March 31,
	2014			2013			2012
Net income	$	48,758		$	48,190		$	7,864
Other comprehensive loss, net of tax	(260		)	(7		)	(25		)
Comprehensive income	$	48,498		$	48,183		$	7,839

The accompanying notes are an integral part of these consolidated financial statements.

F-6

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Changes in Equity

For the Years Ended March 31, 2014, 2013, and 2012

 (U.S. Dollars in Thousands, except unit and share amounts)

													Accumulated
				Limited Partners									Other
	General			Common					Subordinated				Comprehensive			Noncontrolling			Total
	Partner			Units		Amount			Units	Amount			Income			Interests			Equity
BALANCES, MARCH 31, 2011	$	72		10,933,568		$	47,225		—	$	—		$	56		$	—		$	47,353
Distribution to partners prior to initial public offering	(4		)	—		(3,846		)	—	—			—			—			(3,850		)
Conversion of common units to subordinated units	—			(5,919,346	)	(23,485		)	5,919,346	23,485			—			—			—
Sale of units in public offering, net	—			4,025,000		75,289			—	—			—			—			75,289
Repurchase of common units	—			(175,000	)	(3,418		)	—	—			—			—			(3,418		)
Units issued in business combinations, net of issuance costs	—			14,432,031		296,500			—	—			—			—			296,500
Contributions	386			—		—			—	—			—			440			826
Net income (loss)	8			—		6,472			—	1,396			—			(12		)	7,864
Distribution to partners subsequent to initial public offering	(20		)	—		(10,133		)	—	(5,057		)	—			—			(15,210		)
Other comprehensive loss	—			—		—			—	—			(25		)	—			(25		)
BALANCES, MARCH 31, 2012	442			23,296,253		384,604			5,919,346	19,824			31			428			405,329
Distributions	(1,778		)	—		(59,841		)	—	(9,989		)	—			(74		)	(71,682		)
Contributions	510			—		—			—	—			—			403			913
Units issued in business combinations, net of issuance costs	(52,588		)	24,250,258		550,873			—	—			—			4,733			503,018
Equity issued pursuant to incentive compensation plan	—			156,802		3,657			—	—			—			—			3,657
Net income	2,917			—		41,705			—	3,318			—			250			48,190
Other comprehensive loss	—			—		—			—	—			(7		)	—			(7		)
BALANCES, MARCH 31, 2013	(50,497		)	47,703,313		920,998			5,919,346	13,153			24			5,740			889,418
Distributions	(9,703		)	—		(123,467		)	—	(11,920		)	—			(840		)	(145,930		)
Contributions	765			—		—			—	—			—			2,060			2,825
Units issued in business combinations, net of issuance costs	—			2,860,879		80,591			—	—			—			—			80,591
Sales of units, net of issuance costs	—			22,560,848		650,155			—	—			—			—			650,155
Equity issued pursuant to incentive compensation plan	—			296,269		9,085			—	—			—			—			9,085
Disposal of noncontrolling interest	—			—		—			—	—			—			(2,789		)	(2,789		)
Net income	14,148			—		32,712			—	795			—			1,103			48,758
Other comprehensive loss	—			—		—			—	—			(260		)	—			(260		)
BALANCES, MARCH 31, 2014	$	(45,287	)	73,421,309		$	1,570,074		5,919,346	$	2,028		$	(236	)	$	5,274		$	1,531,853

The accompanying notes are an integral part of these consolidated financial statements.

F-7

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Cash Flows

For the Years Ended March 31, 2014, 2013, and 2012

 (U.S. Dollars in Thousands)

	Year Ended March 31,
	2014			2013			2012
OPERATING ACTIVITIES:
Net income	$	48,758		$	48,190		$	7,864
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization	132,653			77,513			17,188
Loss on early extinguishment of debt	—			5,769			—
Non-cash equity-based compensation expense	14,054			8,670			—
Loss (gain) on disposal or impairment of assets	3,597			187			(71		)
Provision for doubtful accounts	2,172			1,315			1,049
Commodity derivative (gain) loss	43,655			4,376			(5,974		)
Earnings of unconsolidated entities	(1,898		)	—			—
Other	312			375			403
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable - trade	21,388			2,562			(20,179		)
Accounts receivable - affiliates	18,002			(12,877		)	193
Inventories	(73,321		)	18,433			30,268
Prepaid expenses and other current assets	18,900			22,585			14,344
Accounts payable - trade	(146,152		)	(16,913		)	35,747
Accounts payable - affiliates	67,361			(6,813		)	4,549
Accrued expenses and other payables	(61,171		)	(9,689		)	366
Advance payments received from customers	(3,074		)	(11,049		)	4,582
Net cash provided by operating activities	85,236			132,634			90,329
INVESTING ACTIVITIES:
Purchases of long-lived assets	(165,148		)	(72,475		)	(7,544		)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(1,268,810		)	(490,805		)	(297,401		)
Cash flows from commodity derivatives	(35,956		)	11,579			6,464
Proceeds from sales of assets	24,660			5,080			1,238
Investments in unconsolidated entities	(11,515		)	—			—
Distributions of capital from unconsolidated entities	1,591			—			—
Other	(195		)	—			346
Net cash used in investing activities	(1,455,373		)	(546,621		)	(296,897		)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	2,545,500			1,227,975			478,900
Payments on revolving credit facilities	(2,101,000		)	(964,475		)	(329,900		)
Issuances of notes	450,000			250,000			—
Proceeds from borrowings on other long-term debt	880			653			—
Payments on other long-term debt	(8,819		)	(4,837		)	(1,278		)
Debt issuance costs	(24,595		)	(20,189		)	(2,380		)
Contributions	2,825			913			440
Distributions	(145,930		)	(71,682		)	(19,060		)
Proceeds from sale of common units, net of offering costs	650,155			(642		)	74,759
Repurchase of common units	—			—			(3,418		)
Net cash provided by financing activities	1,369,016			417,716			198,063
Net increase (decrease) in cash and cash equivalents	(1,121		)	3,729			(8,505		)
Cash and cash equivalents, beginning of period	11,561			7,832			16,337
Cash and cash equivalents, end of period	$	10,440		$	11,561		$	7,832

The accompanying notes are an integral part of these consolidated financial statements.

F-8

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 1 — Nature of Operations and Organization

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in September 2010 by several investors (“IEP Parties”). NGL Energy Holdings LLC serves as our general partner. At March 31, 2014, our operations include:

·A crude oil logistics business, the assets of which include crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

·A water solutions business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons.

·Our liquids business, 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 services through its 22 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids business purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets.

·Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.

We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon, LLC (“Gavilon Energy”).

Initial Public Offering

On May 17, 2011, we completed our initial public offering (“IPO”). We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. Our proceeds from the sale of 3,850,000 common units of $71.9 million, net of total offering costs of $9.0 million, were used to repay advances under our acquisition credit facility and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) from the underwriters’ exercise of their option to purchase additional common units from us were used to redeem 175,000 of the common units outstanding prior to our IPO. Upon the completion of our IPO and the underwriters’ exercise in full of their option to purchase additional common units from us and the redemption, we had outstanding 8,864,222 common units, 5,919,346 subordinated units, a 0.1% general partner interest, and incentive distribution rights (“IDRs”).

Acquisitions Subsequent to Initial Public Offering

Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, including the following, among others:

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

·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., whereby we acquired retail propane operations, primarily in the western United States.

F-9

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

·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 (“Downeast”). 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.

·In July 2013, we completed a business combination whereby we acquired the assets of Crescent Terminals, LLC and the ownership interests in Cierra Marine, LP and its affiliated companies (collectively, “Crescent”), whereby we acquired four towboats, seven crude oil barges, and a crude oil terminal in South Texas.

·In July 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd. (“Big Lake”), whereby we acquired a water disposal facility in West Texas. We also entered into a development agreement that provides us the option to purchase disposal facilities that may be developed in the future. During March 2014, we purchased one additional facility under this 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 water disposal operations and a water transportation business in Texas.

·In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), in which we acquired the ownership interests in water disposal facilities in Texas and the right to purchase one additional facility, which we exercised in March 2014.

·In December 2013, we acquired the ownership interests in Gavilon Energy. The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana and 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. This pipeline became operational in February 2014. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids.

Note 2 — Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include the accounts of the Partnership and its controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation.

We have made certain reclassifications to the prior period financial statements to conform with classification methods used in fiscal 2014. These reclassifications had no impact on previously-reported amounts of equity or net income. In addition, certain balances at March 31, 2013 were adjusted to reflect the final acquisition accounting for certain business combinations.

F-10

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amount of revenues and expenses during the period.

Critical estimates we make in the preparation of our consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations; the collectability of accounts receivable; the recoverability of inventories; useful lives and recoverability of property, plant and equipment and amortizable intangible assets; the impairment of goodwill; the fair value of derivative financial investments; and accruals for various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments and assets and liabilities acquired in business combinations. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

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

·Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and 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 and interest rate protection agreements. The majority of our fair value measurements related to our derivative financial instruments were categorized as Level 2 at March 31, 2014 and 2013 (see Note 12). We determine the fair value of all our derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing model 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. We did not have any fair value measurements categorized as Level 3 at March 31, 2014 or 2013.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability.

Derivative Financial Instruments

We record our derivative financial instrument contracts at fair value in the consolidated balance sheets, with changes in the fair value of our commodity derivative instruments included in our consolidated statements of operations in cost of sales. Contracts that qualify for the normal purchase or sale exemption and are designated as such are not accounted for as derivatives at market value and, accordingly, are recorded when the delivery occurs.

F-11

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

We have not designated any financial instruments as hedges for accounting purposes. All mark-to-market gains and losses on commodity derivative instruments that do not qualify as normal purchases or sales, whether cash transactions or non-cash mark-to-market adjustments, are reported within cost of sales in the consolidated statements of operations, regardless of whether the contract is physically or financially settled.

We utilize various commodity derivative financial instrument contracts to help reduce our exposure to variability in future commodity prices. We do not enter such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of the settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from non-performance by suppliers, customers, or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures that we review on an ongoing basis. We monitor market risk through a variety of techniques and attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures.

Revenue Recognition

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, storage, and service revenues at the time the service is performed, and we record tank and other rentals over the term of the lease. Revenues for the wastewater disposal business are recognized upon receipt of the wastewater at our disposal facilities.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included in revenues in the consolidated statements of operations.

We enter into certain contracts whereby we agree to purchase product from a counterparty and to sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Cost of Sales

We include in cost of sales all costs we incur to acquire products, including the costs of purchasing, terminaling, and transporting inventory prior to delivery to our customers. Cost of sales does not include any depreciation of our property, plant and equipment. Cost of sales does include amortization of certain contract-based intangible assets of $6.2 million, $5.3 million, and $0.8 million during the years ended March 31, 2014, 2013, and 2012, respectively.

Depreciation and Amortization

Depreciation and amortization in the consolidated statements of operations includes all depreciation of our property, plant and equipment and amortization of intangible assets other than debt issuance costs, for which the amortization is recorded to interest expense, and certain contract-based intangible assets, for which the amortization is recorded to cost of sales.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase. At times, certain account balances may exceed federally insured limits.

F-12

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Supplemental cash flow information is as follows:

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees	$	31,827	$	27,384	$	4,966
Income taxes paid	$	1,639	$	1,027	$	430

Cash flows from commodity derivative instruments are classified as cash flows from investing activities in the consolidated statements of cash flows.

Accounts Receivable and Concentration of Credit Risk

We operate in the United States and Canada. We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each customer’s creditworthiness as well as general economic conditions. The allowance for doubtful accounts is based on our assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. Accounts receivable are considered past due or delinquent based on contractual terms. We write off accounts receivable against the allowance for doubtful accounts when collection efforts have been exhausted.

We execute netting agreements with certain customers to mitigate our credit risk. Receivables and payables are reflected at a net balance to the extent a netting agreement is in place and we intend to settle on a net basis.

Our accounts receivable consist of the following:

	March 31, 2014				March 31, 2013
					Gross
	Gross		Allowance for		Receivable		Allowance for
Segment	Receivable		Doubtful Accounts		(Note 2)		Doubtful Accounts
	(in thousands)
Crude oil logistics	$	411,090	$	105	$	360,589	$	11
Water solutions	25,700		405		9,618		29
Liquids	192,529		617		144,267		76
Retail propane	75,606		1,667		49,233		1,644
Refined products	105,670		—		—		—
Renewables	54,466		—		—		—
Other	38,665		28		810		—
	$	903,726	$	2,822	$	564,517	$	1,760

Changes in the allowance for doubtful accounts are as follows:

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Allowance for doubtful accounts, beginning of period	$	1,760		$	818		$	161
Provision for doubtful accounts	2,172			1,315			1,049
Write off of uncollectible accounts	(1,110		)	(373		)	(392		)
Allowance for doubtful accounts, end of period	$	2,822		$	1,760		$	818

F-13

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

For the year ended March 31, 2014, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. At March 31, 2013, one customer of our crude oil logistics segment represented 10% of our consolidated accounts receivable balance.

Inventories

We value our inventory at the lower of cost or market, with cost determined using either the weighted average cost or the first in, first out (FIFO) methods, including the cost of transportation. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business for sale in the retail markets.

Inventories consist of the following:

	March 31,
	2014		2013
	(in thousands)
Crude oil	$	156,473	$	46,156
Natural gas liquids —
Propane	85,159		45,428
Butane and other	19,051		24,090
Refined products	23,209		—
Renewables	11,778		—
Other	14,490		11,221
	$	310,160	$	126,895

Investments in Unconsolidated Entities

As part of the December 2013 acquisition of Gavilon Energy, we acquired a 50% interest in Glass Mountain and an 11% interest in a limited liability company that owns an ethanol production facility. We account for these investments under the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our consolidated balance sheet; instead, our ownership interests are reported within “Investments in Unconsolidated Entities” on our consolidated balance sheet. We record our share of any income or loss generated by these entities as an increase to our equity method investments, and record any distributions we receive from these entities as reductions to our equity method investments.

F-14

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following:

	March 31,
			2013
	2014		(Note 4)
	(in thousands)
Accrued compensation and benefits	$	45,006	$	27,252
Derivative liabilities	42,214		12,701
Income and other tax liabilities	13,421		22,659
Product exchange liabilities	3,719		6,741
Other	37,330		16,253
	$	141,690	$	85,606

Property, Plant and Equipment

We record property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. As we dispose of assets, we remove the cost and related accumulated depreciation from the accounts, and any resulting gain or loss is included in other income. We compute depreciation expense using the straight-line method over the estimated useful lives of the assets (see Note 5).

We evaluate the carrying value of our property, plant and equipment for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group.

Intangible Assets

Our intangible assets include contracts and arrangements acquired in business combinations, including lease agreements, customer relationships, covenants not to compete, and trade names. In addition, we capitalize certain debt issuance costs incurred in our long-term debt arrangements. We amortize our intangible assets on a straight-line basis over the assets’ estimated useful lives (see Note 7). We amortize debt issuance costs over the terms of the related debt on a method that approximates the effective interest method.

We evaluate the carrying value of our amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group. When we cease to use an acquired trade name, we test the trade name for impairment using the “relief from royalty” method and we begin amortizing the trade name over its estimated useful life as a defensive asset.

Goodwill

Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Business combinations are accounted for using the “acquisition method” (see Note 4). We expect that substantially all of our goodwill at March 31, 2014 is deductible for income tax purposes.

Goodwill and intangible assets determined to have an indefinite useful life are not amortized, but instead are evaluated for impairment periodically. We evaluate goodwill and indefinite-lived intangible assets for impairment annually, or more often if events or circumstances indicate that the assets might be impaired. We perform the annual evaluation at January 1 of each year.

To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. If we conclude that it is more likely than not that the fair value of a reporting unit exceeds its carrying amount, we perform the following two-step goodwill impairment test:

·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.

F-15

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

·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.

Estimates and assumptions used to perform the impairment evaluation are inherently uncertain and can significantly affect the outcome of the analysis. The estimates and assumptions we used in the annual assessment for impairment of goodwill included market participant considerations and future forecasted operating results. Changes in operating results and other assumptions could materially affect these estimates. Based on our assessment of qualitative factors, we determined that the two-step impairment test was not required. Accordingly, we did not record any goodwill impairments during the years ended March 31, 2014, 2013, and 2012.

Product Exchanges

Quantities of products receivable or returnable under exchange agreements are reported within prepaid expenses and other current assets or within accrued expenses and other payables on the consolidated balance sheets. We estimate the value of product exchange assets and liabilities based on the weighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus or minus location differentials.

Advance Payments Received from Customers

We record customer advances on product purchases as a liability on the consolidated balance sheets.

Noncontrolling Interests

We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated statements of operations represents the other owners’ share of the net income (loss) of these entities.

Water Facility Development Agreement

In connection with one of our business combinations, we entered into a development agreement whereby we may acquire additional water disposal facilities in Texas. Under this agreement, the other party (the “Developer”) may develop facilities in a designated area. We then have the option to operate the facility for a period of up to 90 days, during which time we may elect to purchase the facility. If we elect to purchase the facility, the Developer may choose one of two options specified in the agreement for the calculation of the purchase price.

During the period between which we have begun operating the facility and we have decided whether to purchase the facility, we are entitled to a fee for operating the facility, which is forfeitable if we elect not to purchase the facility. We recognize revenue for these operator fees once they cease to be forfeitable. When we elect to purchase a facility, we account for the transaction as a business combination.

Business Combination Measurement Period

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination. As described in Note 4, certain of our acquisitions during the year ended March 31, 2014 are still within this measurement period, and as a result, the acquisition-date fair values we have recorded for the acquired assets and assumed liabilities are subject to change.

Also as described in Note 4, we made certain adjustments during the year ended March 31, 2014 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2013. We retrospectively adjusted the March 31, 2013 consolidated balance sheet for these adjustments. Due to the immateriality of these adjustments, we did not retrospectively adjust the consolidated statement of operations for the year ended March 31, 2013 for these measurement period adjustments.

Discontinued Operations

In April 2014, the Financial Accounting Standards Board issued an Accounting Standards Update that changes the criteria for reporting discontinued operations. Under the new standard, a disposal of part of an entity is not classified as a discontinued operation

F-16

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

unless the disposal represents a strategic shift that will have a major effect on an entity’s operations and financial results. We adopted the new standard during the fiscal year ended March 31, 2014.

As described in Note 14, during the year ended March 31, 2014, we sold our compressor leasing business and wound down our natural gas marketing business. These actions do not represent a strategic shift that had a major effect on our operations, and do not meet the criteria under the new accounting standard for these businesses to be reported as discontinued operations.

Note 3 — Earnings per Unit

Our earnings per common and subordinated unit were computed as follows:

	Year Ended March 31,
	2014			2013			2012
	(in thousands, except unit and per unit amounts)
Income attributable to parent equity	$	47,655		$	47,940		$	7,876
Income allocated to general partner (1)	(14,148		)	(2,917		)	(8		)
Income attributable to limited partners	$	33,507		$	45,023		$	7,868
Income allocated to:
Common unitholders	$	31,614		$	39,517		$	4,859
Subordinated unitholders	$	1,893		$	5,506		$	3,009
Weighted average common units outstanding	61,970,471			41,353,574			15,169,983
Weighted average subordinated units outstanding	5,919,346			5,919,346			5,175,384
Income per common unit - basic and diluted	$	0.51		$	0.96		$	0.32
Income per subordinated unit - basic and diluted	$	0.32		$	0.93		$	0.58

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

The restricted units described in Note 11 were antidilutive for the years ended March 31, 2014, 2013, and 2012.

Note 4 — Acquisitions

Year Ended March 31, 2014

Gavilon Energy

On December 2, 2013, we completed a business combination in which we acquired Gavilon Energy. We paid $832.4 million of cash, net of cash acquired, in exchange for these assets and operations. The acquisition agreement also contemplates a post-closing adjustment to the purchase price for certain working capital items. We incurred and charged to general and administrative expense $5.3 million of costs during the year ended March 31, 2014 related to the acquisition of Gavilon Energy.

The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana and a 50% interest in Glass Mountain, which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline became operational in February 2014. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in the acquisition of Gavilon Energy. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could

F-17

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending September 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	349,529
Accounts receivable - affiliates	2,564
Inventories	107,430
Prepaid expenses and other current assets	68,322
Property, plant and equipment:
Crude oil tanks and related equipment (3—40 years)	77,429
Vehicles (3 years)	791
Information technology equipment (3—7 years)	4,046
Buildings and leasehold improvements (3—40 years)	7,716
Land	6,427
Linefill and tank bottoms	15,230
Other (7 years)	170
Construction in process	7,190
Goodwill	359,169
Intangible assets:
Customer relationships (10—20 years)	101,600
Lease agreements (1—5 years)	8,700
Investments in unconsolidated entities	178,000
Other noncurrent assets	9,918
Accounts payable - trade	(342,792		)
Accounts payable - affiliates	(2,585		)
Accrued expenses and other payables	(70,999		)
Advance payments received from customers	(10,667		)
Other noncurrent liabilities	(44,740		)
Fair value of net assets acquired	$	832,448

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership, the opportunity to use the acquired business as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Our preliminary estimate of the fair value of investments in unconsolidated subsidiaries exceeds our share of the historical net book value of these subsidiaries’ net assets by approximately $70 million. This difference relates primarily to goodwill and customer relationships.

The acquisition method of accounting requires that executory contracts that are at unfavorable terms relative to current market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain crude oil storage lease commitments were at unfavorable terms relative to current market conditions, we recorded a liability of $12.9 million related to these lease commitments in the acquisition accounting, and we amortized $2.9 million of this balance through cost of sales during the period from the acquisition date through March 31, 2014. We will amortize the remainder of this liability over the term of the leases. The future amortization of this liability is shown below (in thousands):

Year Ending March 31,
2015	$	6,500
2016	3,260
2017	300

As described in Note 14, on March 31, 2014, we assigned all of the storage and transportation contracts of the natural gas marketing business to a third party.  Since these contracts were at unfavorable terms relative to current market conditions, we paid $44.8 million to assign these contracts. We recorded a liability of $50.8 million related to these storage and transportation contracts in the acquisition accounting, and we amortized $6.0 million of this balance through cost of sales during the period from the acquisition date through the date we assigned the contracts.

F-18

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

We recorded $3.2 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the acquisition of Gavilon Energy. In addition, certain personnel who were employees of Gavilon Energy are entitled to a bonus, half of which was payable upon successful completion of the business combination and the remainder of which is payable in December 2014. We are recording this as compensation expense over the vesting period. We recorded expense of $5.0 million during the year ended March 31, 2014 related to these bonuses, and we expect to record an additional expense of $6.6 million during the year ending March 31, 2015.

The operations of Gavilon Energy have been included in our consolidated statement of operations since Gavilon Energy was acquired on December 2, 2013. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $2.9 billion and operating income of $11.0 million that were generated by the operations of Gavilon Energy.

Oilfield Water Lines, LP

On August 2, 2013, we completed a business combination with entities affiliated with OWL, whereby we acquired water disposal and transportation assets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL. The acquisition agreements included a provision whereby the purchase price could have been increased if certain performance targets were achieved in the six months following the acquisition. These performance targets were not achieved, and therefore no increase to the purchase price was warranted. The acquisition agreements also contemplate a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense $0.8 million of costs related to the OWL acquisition during the year ended March 31, 2014.

We have completed the process of identifying and determining the fair value of the long-lived assets acquired in the acquisition of OWL. We have not yet finalized any post-closing payment for certain working capital items, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	7,268
Inventories	154
Prepaid expenses and other current assets	402
Property, plant and equipment:
Land	710
Water treatment facilities and equipment (3—30 years)	23,173
Vehicles (5—10 years)	8,157
Buildings and leasehold improvements (7—30 years)	2,198
Other (3—5 years)	53
Intangible assets:
Customer relationships (10 years)	110,000
Non-compete agreements (2.5 years)	2,000
Goodwill	89,699
Accounts payable - trade	(6,469		)
Accrued expenses and other payables	(992		)
Other noncurrent liabilities	(64		)
Fair value of net assets acquired	$	236,289

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	167,732
Value of common units issued	68,557
Total consideration paid	$	236,289

The customer relationships were valued using a variation of the income approach known as the excess earnings method. This methodology consists of deriving relevant cash flows to the underlying asset, and then deducting appropriate returns for other assets contributing to the generation of the relevant cash flows. This valuation methodology requires estimates of customer retention, which were based on our understanding of the level of competition in the region in which the assets operate. Our estimates of customer retention are also relevant to the determination of the estimated useful lives of the assets.

F-19

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

The operations of OWL have been included in our consolidated statement of operations since OWL was acquired on August 2, 2013. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $26.2 million and operating income of $0.9 million that was generated by the operations of OWL.

Other Water Solutions Acquisitions

During the year ended March 31, 2014, we completed four separate acquisitions of businesses to expand our water solutions operations in Texas. On a combined basis, we issued 222,381 common units, valued at $6.8 million, and paid $178.9 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $20.6 million and operating income of $7.1 million that was generated by the operations of these acquisitions. We incurred and charged to general and administrative expense $0.4 million of costs related to these acquisitions during the year ended March 31, 2014.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these four business combinations. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending September 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	2,391
Inventories	390
Prepaid expenses and other current assets	61
Property, plant and equipment:
Land	419
Vehicles (5—10 years)	90
Water treatment facilities and equipment (3—30 years)	24,933
Buildings and leasehold improvements (7—30 years)	3,036
Other (3—5 years)	13
Intangible assets:
Customer relationships (8—10 years)	72,000
Trade names (indefinite life)	3,325
Non-compete agreements (3 years)	260
Water facility development agreement (5 years)	14,000
Water facility option agreement	2,500
Goodwill	63,031
Accounts payable - trade	(382		)
Accrued expenses and other payables	(300		)
Other noncurrent liabilities	(114		)
Fair value of net assets acquired	$	185,653

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	178,867
Value of common units issued	6,786
Total consideration paid	$	185,653

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the

F-20

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

As part of one of these business combinations, we entered into an option agreement with the seller of the business whereby we had the option to purchase a salt water disposal facility that was under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this option agreement. On March 1, 2014, we purchased the saltwater disposal facility for additional cash consideration of $3.7 million. The assets associated with this facility are included in the data in the table above.

As part of one of these business combinations, we entered into a development agreement that provides us a first right of refusal to purchase disposal facilities that may be developed by the seller within a defined area in the Eagle Ford Basin through June 2018. On March 1, 2014, we purchased our first disposal facility pursuant to the development agreement for $21.0 million. The assets associated with this facility are included in the data in the table above. In addition, we have exercised our option to operate, for evaluation purposes, three additional disposal facilities developed by the seller. Pending the results of our evaluation, we have the right to purchase any or all of these facilities within the 90-day evaluation period.

Crude Oil Logistics Acquisitions

During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our crude oil logistics business in Texas and Oklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. The agreement for the acquisition of one of these businesses contemplates a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense during the year ended March 31, 2014 $0.1 million of costs related to these acquisitions.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these two business combinations. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	1,235
Inventories	1,021
Prepaid expenses and other current assets	54
Property, plant and equipment:
Vehicles (5—10 years)	2,977
Buildings and leasehold improvements (5—30 years)	280
Crude oil tanks and related equipment (2—30 years)	3,462
Barges and towboats (20 years)	20,065
Other (3—5 years)	53
Intangible assets:
Customer relationships (3 years)	6,300
Non-compete agreements (3 years)	35
Trade names (indefinite life)	530
Goodwill	37,867
Accounts payable - trade	(665		)
Accrued expenses and other payables	(124		)
Fair value of net assets acquired	$	73,090

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	67,842
Value of common units issued	5,248
Total consideration paid	$	73,090

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the

F-21

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Retail Propane and Liquids Acquisitions

During the year ended March 31, 2014, we completed four acquisitions of retail propane businesses and the acquisition of four natural gas liquids terminals. On a combined basis, we paid $21.9 million of cash to acquire these assets and operations. The agreements for certain of these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in certain of these business combinations, and as a result the estimates of fair value reflected at March 31, 2014 are subject to change.

Year Ended March 31, 2013

High Sierra Combination

On June 19, 2012, we completed a business combination with High Sierra, whereby we acquired all of the ownership interests in High Sierra. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. These common units were valued at $406.8 million using the closing price of our common units on the New York Stock Exchange (the “NYSE”) on the merger date. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner. We recorded the value of the 2,685,042 common units issued to our general partner at $8.0 million, which represents an estimate, in accordance with GAAP, of the fair value of the equity issued by our general partner to the former owners of High Sierra’s general partner. In accordance with the GAAP fair value model, this fair value was estimated based on assumptions of future distributions and a discount rate that a hypothetical buyer might use. Under this model, the potential for distribution growth resulting from the prospect of future acquisitions and capital expansion projects would not be considered in the fair value calculation. The difference between the estimated fair value of the general partner interests issued by our general partner of $8.0 million, calculated as described above, and the fair value of the common units issued to our general partner of $60.6 million, as calculated using the closing price of the common units on the NYSE, is reported as a reduction to equity. We incurred and charged to general and administrative expense during the years ended March 31, 2013 $3.7 million of costs related to the High Sierra transaction. We also incurred or accrued costs of $0.6 million related to the equity issuance that we charged to equity.

F-22

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

The fair values of the assets acquired and liabilities assumed in our acquisition of High Sierra are summarized below (in thousands):

Accounts receivable - trade	$	395,311
Accounts receivable - affiliates	7,724
Inventories	43,575
Derivative assets	10,646
Forward purchase and sale contracts	34,717
Prepaid expenses and other current assets	11,131
Property, plant and equipment:
Land	5,723
Vehicles (5—10 years)	22,507
Water treatment facilities and equipment (3—30 years)	64,057
Crude oil tanks and related equipment (2—15 years)	17,851
Buildings and leasehold improvements (5—30 years)	19,145
Information technology equipment (3 years)	5,541
Other (2—30 years)	11,010
Construction in progress	9,621
Intangible assets:
Customer relationships (5—17 years)	245,000
Lease contracts (1—10 years)	12,400
Trade names (indefinite)	13,000
Goodwill	220,884
Accounts payable - trade	(417,369			)
Accounts payable - affiliates	(9,014			)
Advance payments received from customers	(1,237			)
Accrued expenses and other payables	(35,611			)
Derivative liabilities	(5,726			)
Forward purchase and sale contracts	(18,680			)
Long-term debt	(2,537			)
Other noncurrent liabilities	(3,224			)
Noncontrolling interest in consolidated subsidiary	(2,400			)
Consideration paid, net of cash acquired	$		654,045

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	239,251
Value of common units issued, net of issurance costs	414,794
Total consideration paid	$	654,045

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

F-23

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Pecos Combination

On November 1, 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 marketing and logistics operations in Texas and New Mexico. We paid $132.4 million of cash (net of cash acquired) and assumed certain obligations with a value of $10.2 million under certain equipment financing facilities. Also on November 1, 2012, we entered into a call agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.6 million of costs related to the Pecos combination.

The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Pecos:

				Estimated at
				March 31,
	Final			2013			Change
	(in thousands)
Accounts receivable - trade	$	73,609		$	73,704		$	(95	)
Inventories	1,903			1,903			—
Prepaid expenses and other current assets	1,426			1,426			—
Property, plant and equipment:
Vehicles (5—10 years)	22,097			19,193			2,904
Buildings and leasehold improvements (5—30 years)	1,339			1,248			91
Crude oil tanks and related equipment (2—15 years)	1,099			913			186
Land	223			224			(1		)
Other (3—5 years)	36			177			(141		)
Intangible assets:
Customer relationships	—			8,000			(8,000		)
Trade names (indefinite life)	900			1,000			(100		)
Goodwill	91,747			86,661			5,086
Accounts payable - trade	(50,795		)	(50,808		)	13
Accrued expenses and other payables	(963		)	(1,020		)	57
Long-term debt	(10,234		)	(10,234		)	—
Fair value of net assets acquired	$	132,387		$	132,387		$	—

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	87,444
Value of common units issued	44,943
Total consideration paid	$	132,387

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Third Coast Combination

On December 31, 2012, we completed a business combination transaction whereby we acquired all of the membership interests in Third Coast Towing, LLC (“Third Coast”) for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. Also on December 31, 2012, we entered into a call agreement with the former owners of Third Coast pursuant to which the former owners of Third Coast agreed to purchase a minimum of $8.0 million or a maximum of $10.0 million of

F-24

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

common units from us. On January 11, 2013, the former owners of Third Coast purchased 344,680 common units from us for $8.0 million pursuant to this agreement.

During the year ended March 31, 2014, we completed the acquisition accounting for this business combination. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Third Coast:

				Estimated at
				March 31,
	Final			2013			Change
	(in thousands)
Accounts receivable - trade	$	2,195		$	2,248		$	(53	)
Inventories	140			140			—
Property, plant and equipment:
Barges and towboats (20 years)	17,711			12,883			4,828
Other	—			30			(30		)
Intangible assets:
Customer relationships (3 years)	3,000			4,000			(1,000		)
Trade names (indefinite life)	850			500			350
Goodwill	18,847			22,551			(3,704		)
Other noncurrent assets	2,733			2,733			—
Accounts payable - trade	(2,429		)	(2,048		)	(381		)
Accrued expenses and other payables	(164		)	(154		)	(10		)
Fair value of net assets acquired	$	42,883		$	42,883		$	—

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	35,000
Value of common units issued	7,883
Total consideration paid	$	42,883

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Other Crude Oil Logistics and Water Solutions Business Combinations

During the year ended March 31, 2013, we completed four separate acquisitions to expand the assets and operations of our crude oil logistics and water solutions businesses. On a combined basis, we paid $52.6 million in cash and assumed $1.3 million of long-term debt in the form of non-compete agreements. We also issued 516,978 common units, valued at $12.4 million, as partial consideration for one of these acquisitions. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.3 million of costs related to these acquisitions.

F-25

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

During the year ended March 31, 2014, we completed the acquisition accounting for these business combinations. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of these businesses:

				Estimated at
				March 31,
	Final			2013			Change
	(in thousands)
Accounts receivable - trade	$	2,676		$	2,660		$	16
Inventories	191			191			—
Prepaid expenses and other current assets	737			738			(1		)
Property, plant and equipment:
Land	218			191			27
Vehicles (5—10 years)	853			771			82
Water treatment facilities and equipment (3—30 years)	13,665			13,322			343
Buildings and leasehold improvements (5—30 years)	895			2,233			(1,338		)
Crude oil tanks and related equipment (2—15 years)	4,510			1,781			2,729
Other (3—5 years)	27			2			25
Construction in progress	490			693			(203		)
Intangible assets:
Customer relationships (5—10 years)	13,125			6,800			6,325
Non-compete agreements (3 years)	164			510			(346		)
Trade names (indefinite life)	2,100			500			1,600
Goodwill	34,451			43,822			(9,371		)
Accounts payable - trade	(3,374		)	(3,374		)	—
Accrued expenses and other payables	(1,914		)	(2,026		)	112
Notes payable	(1,340		)	(1,340		)	—
Other noncurrent liabilities	(156		)	(156		)	—
Noncontrolling interest	(2,333		)	(2,333		)	—
Fair value of net assets acquired	$	64,985		$	64,985		$	—

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	52,552
Value of common units issued	12,433
Total consideration paid	$	64,985

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

F-26

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Retail Propane Combinations During the Year Ended March 31, 2013

During the year ended March 31, 2013, we entered into six separate business combination agreements to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States. On a combined basis, we paid cash of $71.4 million and issued 850,676 common units, valued at $18.9 million, in exchange for these assets. We also assumed $6.6 million of long-term debt in the form of non-compete agreements. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.3 million related to these acquisitions. The fair values of the assets acquired and liabilities assumed in these six combinations are as follows (in thousands):

Accounts receivable - trade	$	8,715
Inventory	5,155
Other current assets	1,228
Property, plant and equipment:
Land	1,945
Retail propane equipment (5—20 years)	28,763
Vehicles (5 years)	11,344
Buildings and leasehold improvements (30 years)	7,052
Other	1,201
Intangible assets:
Customer relationships (10—15 years)	16,890
Trade names (indefinite)	2,924
Non-compete agreements (5 years)	1,387
Goodwill	21,983
Other non-current assets	784
Long-term debt, including current portion	(6,594		)
Other assumed liabilities	(12,511		)
Fair value of net assets acquired	$	90,266

Consideration paid consists of the following (in thousands):

Cash consideration paid	$	71,392
Value of common units issued	18,874
Total consideration	$	90,266

Goodwill represents the excess of the estimated consideration paid for the acquired businesses over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

F-27

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Pro Forma Results of Operations (Unaudited)

As described above, we completed a number of acquisitions during the years ended March 31, 2014 and 2013. The operations of each acquired business have been included in our consolidated results of operations since the date of acquisition of the business. The unaudited pro forma consolidated data presented below has been prepared as if the following acquisitions had been completed on April 1, 2012:

·High Sierra;

·Pecos;

·Third Coast;

·OWL; and

·Gavilon Energy.

The unaudited pro forma consolidated data presented below has also been prepared as if the following transactions, which are described in Notes 8 and 11 to these consolidated financial statements, had been completed on April 1, 2012:

·Our sale of common units in December 2013 in a private placement;

·The amendment of our Credit Agreement in November 2013;

·Our issuance of senior unsecured notes in October 2013;

·Our sale of common units in September 2013 in a public offering;

·The sale of common units in a public offering in July 2013;

·Our entry into the Credit Agreement in June 2012; and

·Our issuance of senior notes in June 2012.

	Year Ended March 31,
	2014			2013
	(in thousands, except per unit amounts)
Revenues	$	9,800,398		$	5,697,988
Net income (loss)	798			(72,171		)
Net loss attributable to limited partners	(14,446		)	(75,251		)
Basic and diluted loss per common unit	(0.18		)	(0.95		)
Basic and diluted loss per subordinated unit	(0.18		)	(0.95		)

The pro forma consolidated data in the table above was prepared by adding historical results of operations of acquired businesses to our historical results of operations and making certain pro forma adjustments. The pro forma information is not necessarily indicative of the results of operations that would have occurred if the transactions had occurred on April 1, 2012, nor is it necessarily indicative of future results of operations.

F-28

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Gavilon Energy historically conducted trading operations, whereas we operate as a logistics business. Gavilon Energy’s historical results of operations were subject to more volatility as a result of its trading operations than we would expect future results of operations to have under our business model. In the pro forma data in the table above, no pro forma effect was given to the change in business model from a trading business to a logistics business. Gavilon Energy historically recorded revenues net of product costs. In the pro forma table above, no pro forma effect was given to the fact that this accounting policy is different than our accounting policy.

The pro forma net loss for the year ended March 31, 2013 in the table above includes $4.8 million of expense related to the retirement of a liability associated with a business combination that OWL completed prior to our acquisition of OWL. This non-recurring expense is not excluded from the pro forma net loss, as it does not directly result from our acquisition of OWL.

The pro forma net loss for the year ended March 31, 2014 shown in the table above reflects depreciation and amortization expense estimates which are preliminary, as our identification of the assets and liabilities acquired, and the fair value determinations thereof, for the business combination with Gavilon Energy have not been completed.

The pro forma losses per unit have been computed based on earnings or losses allocated to the limited partners after deducting the total earnings allocated to the general partner. To calculate earnings attributable to the general partner, we have used historical distribution amounts. For purposes of this calculation, we have assumed that the common units outstanding at March 31, 2014 were outstanding during the full years presented above.

Year Ended March 31, 2012

Osterman

On October 3, 2011, we completed a business combination transaction with Osterman, whereby we acquired retail propane operations in the northeastern United States. We issued 4,000,000 common units and paid $94.9 million of cash, net of cash acquired, in exchange for the assets and operations of Osterman. The agreement also contemplated a post-closing payment of $4.8 million for certain specified working capital items, which was paid in November 2012. We valued the 4 million limited partner common units at $81.9 million based on the closing price of our common units on the closing date ($20.47 per unit). We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.8 million of costs incurred in connection with the Osterman transaction. We also incurred costs related to the equity issuance of $0.1 million that we charged to equity. The following table presents the final allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable - trade	$	9,350
Inventories	3,869
Prepaid expenses and other current assets	215
Property, plant and equipment:
Land	2,349
Retail propane equipment (15—20 years)	47,160
Vehicles (5—20 years)	7,699
Buildings and leasehold improvements (30 years)	3,829
Other (3—5 years)	732
Intangible assets:
Customer relationships (20 years)	54,500
Trade names (indefinite life)	8,500
Non-compete agreements (7 years)	700
Goodwill	52,267
Assumed liabilities	(9,654		)
Consideration paid, net of cash acquired	$	181,516

F-29

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Consideration paid consists of the following (in thousands):

Cash paid at closing, net of cash acquired	$	94,873
Fair value of common units issued at closing	81,880
Working capital payment (paid in November 2012)	4,763
Consideration paid, net of cash acquired	$	181,516

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

SemStream

On November 1, 2011, we completed a business combination with SemStream. We entered into this business combination in order to expand our liquids segment. SemStream contributed substantially all of its natural gas liquids business and assets to us in exchange for 8,932,031 of our limited partner common units and a cash payment of $91.0 million. We have valued the 8.9 million limited partner common units at $184.8 million, based on the closing price of our common units on the closing date ($21.07) reduced by the expected present value of distributions for certain units which were not eligible for full distributions until the quarter ending September 30, 2012. In addition, in exchange for a cash contribution, SemStream acquired a 7.5% interest in our general partner. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.7 million of costs related to the SemStream transaction. We also incurred costs of less than $0.1 million related to the equity issuance that we charged to equity.

The acquired assets included 12 natural gas liquids terminals in Arizona, Arkansas, Indiana, Minnesota, Missouri, Montana, Washington and Wisconsin, 12 million gallons of aboveground propane storage, 3.7 million barrels of underground leased storage for natural gas liquids and a rail fleet of 350 leased and 12 owned cars.

We have included the results of SemStream’s operations in our consolidated financial statements beginning November 1, 2011. The operations of SemStream are reflected in our liquids segment.

The following table presents the fair values of the assets acquired and liabilities assumed in the SemStream combination (in thousands):

Inventories	$	104,226
Derivative assets	3,578
Assets held for sale	3,000
Prepaid expenses and other current assets	9,833
Property, plant and equipment:
Land	3,470
Natural gas liquids terminal assets (20—30 years)	41,434
Vehicles and railcars (5 years)	470
Other (5 years)	3,326
Investment in capital lease	3,112
Intangible assets:
Customer relationships (8—15 years)	31,950
Lease contracts (1—4 years)	1,008
Goodwill	74,924
Assumed current liabilities	(4,591		)
Consideration paid	$	275,740

F-30

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired operations and the Partnership, the opportunity to use the acquired businesses as a platform to expand our wholesale marketing operations, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

Pacer Combination

On January 3, 2012, we completed a business combination with Pacer in order to expand our retail propane operations. The combination was funded with cash of $32.2 million and the issuance of 1.5 million common units. We valued the 1.5 million common units based on the closing price of our common units on the closing date. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.7 million of costs related to the Pacer transaction. We also incurred costs of $0.1 million related to the equity issuance that we charged to equity.

The assets contributed by Pacer consist of retail propane operations in Colorado, Illinois, Mississippi, Oregon, Utah and Washington. The contributed assets include 17 owned or leased customer service centers and satellite distribution locations. We have included the results of Pacer’s operations in our consolidated financial statements beginning January 3, 2012. The operations of Pacer are reported within our retail propane segment.

Consideration paid consists of the following (in thousands):

Cash	$	32,213
Common units	30,375
Consideration paid	$	62,588

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable - trade	$	4,389
Inventories	965
Prepaid expenses and other current assets	43
Property, plant and equipment:
Land	1,967
Retail propane equipment (15—20 years)	12,793
Vehicles (5 years)	3,090
Buildings and leasehold improvements (30 years)	409
Other (3—5 years)	59
Intangible assets:
Customer relationships (15 years)	23,560
Trade names (indefinite life)	2,410
Non-compete agreements	1,520
Goodwill	15,782
Assumed liabilities	(4,399		)
Consideration paid	$	62,588

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

F-31

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

North American Combination

On February 3, 2012, we completed a business combination with North American in order to expand our retail propane operations. The combination was funded with cash of $69.8 million. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $1.6 million of costs related to the North American acquisition.

The assets acquired from North American include retail propane and distillate operations in Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, Pennsylvania, and Rhode Island.

The following table presents the allocation of the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable - trade	$	10,338
Inventories	3,437
Prepaid expenses and other current assets	282
Property, plant and equipment:
Land	2,251
Retail propane equipment (15—20 years)	24,790
Natural gas liquids terminal assets (15—20 years)	1,044
Vehicles (5—15 years)	5,819
Buildings and leasehold improvements (30 years)	2,386
Other (3—5 years)	634
Intangible assets:
Customer relationships (10 years)	12,600
Trade names (10 years)	2,700
Non-compete agreements (3 years)	700
Goodwill	13,978
Assumed liabilities	(11,129		)
Consideration paid	$	69,830

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

Other Acquisitions

During the year ended March 31, 2012, we closed three additional acquisitions for cash payments of $6.4 million on a combined basis. We also assumed $0.6 million in long-term debt in the form of non-compete agreements. These operations have been included in our results of operations since the acquisition dates, and have not been material to our consolidated financial statements.

F-32

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 5 — Property, Plant and Equipment

Our property, plant and equipment consists of the following:

	March 31,
				2013
Description and Estimated Useful Lives	2014			(Note 2)
	(in thousands)
Natural gas liquids terminal assets (2—30 years)	$	75,141		$	63,637
Retail propane equipment (2—30 years)	160,758			152,802
Vehicles (3—25 years)	152,676			88,173
Water treatment facilities and equipment (3—30 years)	180,985			91,944
Crude oil tanks and related equipment (2—40 years)	106,125			22,577
Barges and towboats (5—40 years)	52,217			25,963
Information technology equipment (3—7 years)	20,768			12,169
Buildings and leasehold improvements (3—40 years)	60,004			48,975
Land	30,241			21,815
Linefill and tank bottoms	13,403			—
Other (5—30 years)	6,341			16,104
Construction in progress	80,251			32,405
	938,910			576,564
Less: Accumulated depreciation	(109,564		)	(50,127		)
Net property, plant and equipment	$	829,346		$	526,437

Depreciation expense was $59.9 million, $39.2 million and $10.6 million during the years ended March 31, 2014, 2013 and 2012, respectively. During the year ended March 31, 2014, we capitalized $0.7 million of interest expense.

Note 6 — Goodwill

The changes in the balance of goodwill were as follows:

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Beginning of period, as retrospectively adjusted (Note 2)	$	555,220	$	167,245	$	8,568
Acquisitions	551,786		387,975		158,677
End of period, as retrospectively adjusted (Note 2)	$	1,107,006	$	555,220	$	167,245

Goodwill by reportable segment is as follows:

	March 31,
	2014		2013
	(in thousands)
Crude oil logistics	$	606,383	$	246,345
Water solutions	262,203		109,470
Liquids	90,135		87,136
Retail propane	114,285		112,269
Refined products	22,000		—
Renewables	12,000		—
	$	1,107,006	$	555,220

F-33

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 7 — Intangible Assets

Our intangible assets consist of the following:

		March 31, 2014				March 31, 2013
						Gross Carrying
	Amortizable	Gross Carrying		Accumulated		Amount		Accumulated
	Lives	Amount		Amortization		(Note 2)		Amortization
				(in thousands)
Amortizable -
Customer relationships (1)	3–20 years	$	697,405	$	83,261	$	405,160	$	30,959
Water facility development agreement	5 years	14,000		2,100		—		—
Lease and other agreements	5–8 years	23,920		13,190		15,210		7,018
Non-compete agreements	2–7 years	14,161		6,388		11,509		2,871
Trade names	1–10 years	15,489		3,081		2,784		326
Debt issuance costs	5–10 years	44,089		8,708		19,494		2,981
Total amortizable		809,064		116,728		454,157		44,155
Non-amortizable -
Trade names		22,620				31,430
Total		$	831,684	$	116,728	$	485,587	$	44,155

(1)The weighted-average remaining amortization period for customer relationship intangible assets is approximately nine years.

Amortization expense was as follows:

	Year Ended March 31,
Recorded in	2014		2013		2012
	(in thousands)
Depreciation and amortization	$	60,855	$	29,657	$	4,538
Cost of sales	6,172		5,285		800
Interest expense	5,727		3,375		1,277
Loss on early extinguishment of debt	—		5,769		—
	$	72,754	$	44,086	$	6,615

Expected amortization of our intangible assets is as follows (in thousands):

Year Ending March 31,
2015	$	88,970
2016	83,449
2017	76,826
2018	72,857
2019	66,826
Thereafter	303,408
	$	692,336

F-34

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 8 — Long-Term Obligations

Our long-term debt consists of the following:

	March 31,
	2014		2013
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	532,500	$	441,500
Working capital loans	389,500		36,000
Senior notes	250,000		250,000
Unsecured notes	450,000		—
Other notes payable	14,914		21,562
	1,636,914		749,062
Less - current maturities	7,080		8,626
Long-term debt	$	1,629,834	$	740,436

Credit Agreement

On June 19, 2012, we entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”).

The Working Capital Facility had a total capacity of $935.5 million for cash borrowings and letters of credit at March 31, 2014. At March 31, 2014, we had outstanding cash borrowings of $389.5 million and outstanding letters of credit of $270.6 million on the Working Capital Facility. The Expansion Capital Facility had a total capacity of $785.5 million for cash borrowings at March 31, 2014. At March 31, 2014, we had outstanding cash borrowings of $532.5 million on the Expansion Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time.

The commitments under the Credit Agreement expire on November 5, 2018. We have the right to pre-pay outstanding borrowings under the Credit Agreement without incurring any penalties, and pre-payments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At March 31, 2014, the interest rate in effect on outstanding LIBOR borrowings was 1.91%, calculated as the LIBOR rate of 0.16% plus a margin of 1.75%. At March 31, 2014, the interest rate in effect on letters of credit was 1.75%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At March 31, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	532,500	1.91	%
Working capital facility —
LIBOR borrowings	358,000		1.91	%
Base rate borrowings	31,500		4.00	%

The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our “leverage ratio,” as defined in the Credit Agreement, cannot exceed 4.25 to 1.0 at any quarter end. At March 31, 2014, our leverage ratio was approximately 3 to 1. The Credit Agreement also specifies that our “interest coverage ratio,” as defined in the Credit Agreement,

F-35

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At March 31, 2014, our interest coverage ratio was approximately 7 to 1.

The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

At March 31, 2014, we were in compliance with the covenants under the Credit Agreement.

Senior Notes

On June 19, 2012, we entered into a note purchase agreement (as amended, the “Note Purchase Agreement”) whereby we issued $250.0 million of senior notes in a private placement (the “Senior Notes”). The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The Senior Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which are described above.

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) non-payment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the Senior Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the Senior Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding Senior Notes of any series may declare all of the Senior Notes of such series to be due and payable immediately.

At March 31, 2014, we were in compliance with the covenants under the Note Purchase Agreement and the Senior Notes.

Unsecured Notes

On October 16, 2013, we issued $450.0 million of 6.875% senior unsecured notes (the “Unsecured Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $438.4 million, after the initial purchasers’ discount of $10.1 million and estimated offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

The Unsecured Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the Unsecured Notes prior to the maturity date, although we would be required to pay a premium for early redemption.

The purchase agreement and the indenture governing the Unsecured Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

F-36

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

At March 31, 2014, we were in compliance with the covenants under the Unsecured Notes.

We also entered into a registration rights agreement whereby we have committed to exchange the Unsecured Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the Unsecured Notes on or before October 16, 2014. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the Unsecured Notes.

Other Notes Payable

We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing, which have interest rates ranging from 2.1% to 4.9% at March 31, 2014.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at March 31, 2014:

	Revolving						Other
	Credit		Senior		Unsecured		Notes
Year Ending March 31,	Facility		Notes		Notes		Payable		Total
					(in thousands)
2015	$	—	$	—	$	—	$	7,081	$	7,081
2016	—		—		—		3,614		3,614
2017	—		—		—		2,356		2,356
2018	—		25,000		—		1,449		26,449
2019	922,000		50,000		—		238		972,238
Thereafter	—		175,000		450,000		176		625,176
	$	922,000	$	250,000	$	450,000	$	14,914	$	1,636,914

Previous Credit Facilities

On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations for the year ended March 31, 2013.

Note 9 — Income Taxes

We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner’s basis in the Partnership.

We have certain taxable corporate subsidiaries in the United States and Canada. In addition, our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales.

A publicly traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income for each of the calendar years since our IPO.

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in the consolidated financial statements at March 31, 2014.

F-37

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 10 — Commitments and Contingencies

Legal Contingencies

We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our liabilities may change materially as circumstances develop.

Customer Dispute

A customer of our crude oil logistics segment has disputed the transportation rate schedule we used to bill the customer for services that we provided from November 2012 through February 2013, which was the same rate schedule that Pecos used to bill the customer from April 2011 through October 2012 (prior to our acquisition of Pecos). The customer has not paid $1.7 million of the amount we charged for services we provided from November 2012 through February 2013. In May 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. Later in May 2013, the customer filed an answer and counterclaim seeking to recover $5.5 million that it paid to Pecos prior to our acquisition of Pecos. We have not recorded revenue for the $1.7 million of unpaid fees charged from November 2012 through February 2013, pending resolution of the dispute.

During August 2013, the customer notified us that it intended to withhold payment of $3.3 million for services performed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer has not disputed the validity of the amounts billed for services performed during this time frame. Upon receiving this notification, we ceased providing services under this contract, and on November 5, 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. We are not able to reliably predict the outcome of this dispute at this time, but we do not believe the outcome will have a material adverse effect on our consolidated financial position or results of operations.

Canadian Fuel and Sales Taxes

The taxing authority of a province in Canada completed an audit of fuel and sales tax payments and alleged that an entity we acquired should have collected from customers and remitted to the taxing authority fuel and sales taxes on certain historical sales. We recorded in the acquisition accounting a liability of $0.8 million (net of receivables for expected recoveries from other parties). We now believe this matter is resolved, and we removed the liability from our consolidated balance sheet and recorded a corresponding reduction to cost of sales during the year ended March 31, 2014.

Environmental Matters

Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that significant costs will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

Asset Retirement Obligations

We have recorded a liability of $2.3 million at March 31, 2014 for asset retirement obligations. This liability is related to wastewater disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets. However, we do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

F-38

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, and equipment. Future minimum lease payments under contractual commitments at March 31, 2014 are as follows (in thousands):

Year Ending March 31,
2015	$	133,170
2016	93,454
2017	64,209
2018	49,802
2019	29,213
Thereafter	58,182
Total	$	428,030

Rental expense relating to operating leases was $98.3 million, $84.2 million, and $5.2 million during the years ended March 31, 2014, 2013, and 2012, respectively.

Sales and Purchase Contracts

We have entered into sales and purchase contracts for products to be delivered in future periods for which we expect the parties to physically settle the contracts with inventory. At March 31, 2014, we had the following such commitments outstanding:

	Volume	Value
	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)	31,111	$	39,117
Natural gas liquids floating-price purchase commitments (gallons)	522,947	618,293
Natural gas liquids fixed-price sale commitments (gallons)	63,944	77,682
Natural gas liquids floating-price sale commitments (gallons)	272,495	395,095
Crude oil fixed-price purchase commitments (barrels)	4,016	364,557
Crude oil fixed-price sale commitments (barrels)	3,574	324,765

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (described in Note 12) or inventory positions (described in Note 2).

Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value on our consolidated balance sheet and are not included in the data in the table above. These contracts are included in the derivative disclosures in Note 12, and represent $43.5 million of our prepaid expenses and other current assets and $34.6 million of our accrued expenses and other payables at March 31, 2014.

Note 11 — Equity

Partnership Equity

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest. Limited partner equity includes common and subordinated units. The common and subordinated units share equally in the allocation of income or loss. The principal difference between common and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

We expect the subordination period to end in August 2014. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

Our general partner is not obligated to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

F-39

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Initial Public Offering

On May 17, 2011, we completed our IPO. We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. Our proceeds from the sale of 3,850,000 common units of $71.9 million, net of total offering costs of $9.0 million, were used to repay advances under our acquisition credit facility and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) from the underwriters’ exercise of their option to purchase additional common units from us were used to redeem 175,000 of the common units outstanding prior to our IPO. Upon the completion of our IPO and the underwriters’ exercise in full of their option to purchase additional common units from us and the redemption, we had outstanding 8,864,222 common units, 5,919,346 subordinated units, a 0.1% general partner interest, and IDRs.

Common Units Issued in Business Combinations

As described in Note 4, we issued common units as partial consideration for several acquisitions. These are summarized below:

Osterman combination	4,000,000
SemStream combination	8,932,031
Pacer combination	1,500,000
Total - Year Ended March 31, 2012	14,432,031
High Sierra combination	20,703,510
Retail propane combinations	850,676
Crude oil logistics and water solutions combinations	516,978
Pecos combination	1,834,414
Third Coast combination	344,680
Total - Year Ended March 31, 2013	24,250,258
Water solutions combinations	222,381
Crude oil logistics combinations	175,211
OWL combination	2,463,287
Total - Year Ended March 31, 2014	2,860,879

In connection with the completion of certain of these transactions, we amended our Registration Rights Agreement, which provides for certain registration rights for certain holders of our common units.

Equity Issuances

On July 5, 2013, we completed a public offering of 10,350,000 common units. We received net proceeds of $287.5 million, after underwriting discounts and commissions of $12.0 million and offering costs of $0.7 million.

On September 25, 2013, we completed a public offering of 4,100,000 common units. We received net proceeds of $127.6 million, after underwriting discounts and commissions of $5.0 million and offering costs of $0.2 million.

On December 2, 2013, we issued and sold 8,110,848 of our common units in a private placement. We received net proceeds of $235.1 million, after offering costs of $4.9 million.

Distributions

Our general partner has adopted a cash distribution policy that will require us to pay a quarterly distribution to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as “available cash,” in the following manner:

·First, 99.9% to the holders of common units and 0.1% to the general partner, until each common unit has received the specified minimum quarterly distribution, plus any arrearages from prior quarters.

·Second, 99.9% to the holders of subordinated units and 0.1% to the general partner, until each subordinated unit has received the specified minimum quarterly distribution.

·Third, 99.9% to all unitholders, pro rata, and 0.1% to the general partner.

The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions paid to the limited partners. These distributions are referred to as “incentive distributions.”

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in

F-40

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest, assume our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its IDRs and there are no arrearages on common units.

					Marginal Percentage Interest In
	Total Quarterly				Distributions
	Distribution per Unit				Unitholders		General Partner
Minimum quarterly distribution				$ 0.337500	99.9	%	0.1	%
First target distribution	above	$ 0.337500	up to	$ 0.388125	99.9	%	0.1	%
Second target distribution	above	$ 0.388125	up to	$ 0.421875	86.9	%	13.1	%
Third target distribution	above	$ 0.421875	up to	$ 0.506250	76.9	%	23.1	%
Thereafter	above	$ 0.506250			51.9	%	48.1	%

On May 5, 2011, we made a distribution of $3.9 million from available cash to our general partner and common unitholders at March 31, 2011.

The following table summarizes the distributions declared subsequent to our IPO:

			Amount		Amount Paid to		Amount Paid to
Date Declared	Record Date	Date Paid	Per Unit		Limited Partners		General Partner
					(in thousands)		(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011	0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012	0.3500		7,735		10
April 18, 2012	April 30, 2012	May 15, 2012	0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012	0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012	0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013	0.4625		24,245		927
April 25, 2013	May 6, 2013	May 15, 2013	0.4775		25,605		1,189
July 25, 2013	August 5, 2013	August 14, 2013	0.4938		31,725		1,739
October 23, 2013	November 4, 2013	November 14, 2013	0.5113		35,908		2,491
January 23, 2014	February 4, 20143	February 14, 2014	0.5313		42,150		4,283
April 24, 2014	May 5, 2014	May 15, 2014	0.5513		43,737		5,754

F-41

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Several of our business combination agreements contained provisions that temporarily limited the distributions to which the newly-issued units were entitled. The following table summarizes the number of equivalent units that were not eligible to receive a distribution on each of the record dates:

	Equivalent
	Units Not
Record Date	Eligible
August 3, 2011	—
October 31, 2011	4,000,000
February 3, 2012	7,117,031
April 30, 2012	3,932,031
August 3, 2012	17,862,470
October 29, 2012	516,978
February 4, 2013	1,202,085
May 6, 2013	—
August 5, 2013	—
November 4, 2013	979,886
February 4, 2014	—
May 5, 2014	—

Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plan (“LTIP”) which allows for the issuance of equity-based compensation to employees and directors. The board of directors of our general partner has granted certain restricted units to employees and directors, which will vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

F-42

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

The following table summarizes the restricted unit activity during the years ended March 31, 2014 and 2013:

Unvested restricted units at March 31, 2012	—
Units granted	1,684,400
Units vested and issued	(156,802	)
Units withheld for employee taxes	(61,698	)
Units forfeited	(21,000	)
Unvested restricted units at March 31, 2013	1,444,900
Units granted	494,000
Units vested and issued	(296,269	)
Units withheld for employee taxes	(122,531	)
Units forfeited	(209,000	)
Unvested restricted units at March 31, 2014	1,311,100

The scheduled vesting of the awards is summarized below:

Vesting Date	Number of Awards
July 1, 2014	408,300
January 1, 2015	4,000
July 1, 2015	341,300
January 1, 2016	4,000
July 1, 2016	322,500
January 1, 2017	4,000
July 1, 2017	192,500
January 1, 2018	4,000
July 1, 2018	30,500
Total unvested units at March 31, 2014	1,311,100

We record the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through the reporting date using the estimated fair value of the awards at the reporting date. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth. We estimate that the future expense we will record on the unvested awards at March 31, 2014 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of 95,000 units. For purposes of this calculation, we have used the closing price of the common units on March 31, 2014, which was $37.53.

Year Ending March 31,
2015	$	14,393
2016	11,279
2017	7,429
2018	2,310
2019	229
Total	$	35,640

F-43

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Following is a rollforward of the liability related to equity-based compensation, which is reported within accrued expenses and other payables on our consolidated balance sheets (in thousands):

Balance at March 31, 2012	$	—
Expense recorded	10,138
Value of units vested and issued	(3,627		)
Taxes paid on behalf of participants	(1,468		)
Balance at March 31, 2013	5,043
Expense recorded	17,804
Value of units vested and issued	(9,085		)
Taxes paid on behalf of participants	(3,750		)
Balance at March 31, 2014	$	10,012

The weighted-average fair value of the awards at March 31, 2014 was $33.78, which was calculated as the closing price of the common units on March 31, 2014, adjusted 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 and assumptions that a market participant might make about future distribution growth.

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common and subordinated units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common and subordinated 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. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At March 31, 2014, 6.2 million units remain available for issuance under the LTIP.

Note 12 — Fair Value of Financial Instruments

Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values, due to their short-term nature. We believe the carrying amounts of our long-term debt instruments, including the Revolving Credit Facility and the Senior Notes, approximate their fair values, as we do not believe market conditions have changed materially since we entered into these debt agreements.

F-44

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Commodity Derivatives

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2014:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	4,990		$	(3,258	)
Level 2 measurements	49,605			(43,303		)
	54,595			(46,561		)
Netting of counterparty contracts(1)	(4,347		)	4,347
Cash collateral provided or held	456			—
Commodity contracts reported on consolidated balance sheet	$	50,704		$	(42,214	)

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

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2013:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	947		$	(3,324	)
Level 2 measurements	9,911			(13,280		)
	10,858			(16,604		)
Netting of counterparty contracts(1)	(3,503		)	3,503
Cash collateral provided or held	(1,760		)	400
Commodity contracts reported on consolidated balance sheet	$	5,595		$	(12,701	)

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

The commodity derivative assets (liabilities) are reported in the following accounts on the consolidated balance sheets:

	March 31,
	2014			2013
	(in thousands)
Prepaid expenses and other current assets	$	50,704		$	5,551
Other noncurrent assets	—			44
Accrued expenses and other payables	(42,214		)	(12,701		)
Net asset (liability)	$	8,490		$	(7,106	)

F-45

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

The following table sets forth our open commodity derivative contract positions at March 31, 2014 and 2013. We do not account for these derivatives as hedges.

Contracts	Settlement Period	Total  NotionalUnits(Barrels)		Fair Valueof Net Assets(Liabilities)
		(in thousands)
At March 31, 2014 -
Cross-commodity (1)	April 2014 – March 2015	140		$	(1,876	)
Crude oil fixed-price (2)	April 2014 – March 2015	(1,600	)	(2,796		)
Crude oil index (3)	April 2014 – December 2015	3,598		6,099
Propane fixed-price (4)	April 2014 – March 2015	60		1,753
Refined products fixed-price (5)	April 2014 – July 2014	732		560
Renewable products fixed-price (6)	April 2014 – July 2014	106		4,084
Other	April 2014	—		210
				8,034
Net cash collateral provided				456
Net value of commodity derivatives on consolidated balance sheet				$	8,490
At March 31, 2013 -
Cross-commodity (1)	April 2013 - March 2014	430		$	(10,208	)
Crude oil fixed-price (2)	April 2013 - March 2014	(144	)	1,033
Crude oil index (3)	April 2013 - June 2014	(91	)	153
Propane fixed-price (4)	April 2013 - March 2014	(282	)	3,197
Other	May 2013 - June 2013	8		79
				(5,746		)
Net cash collateral held				(1,360		)
Net value of commodity derivatives on consolidated balance sheet				$	(7,106	)

(1)Cross-commodity — Our operating segments may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. The contracts listed in this table as “Cross-commodity” represent derivatives we have entered into as economic hedges against the risk of one commodity price moving relative to another commodity price.

(2)Crude oil fixed-price — Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Crude oil fixed-price” represent derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding the inventory.

(3)Crude oil index — Our crude oil logistics segment may purchase or sell crude oil where the underlying contract pricing mechanisms are tied to different crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as “Crude oil index” represent derivatives we have entered into as an economic hedge against the risk of one crude oil index moving relative to another crude oil index.

(4)Propane fixed-price — Our liquids segment routinely purchases inventory during the warmer months and stores the inventory for sale in the colder months. The contracts listed in this table as “Propane fixed-price” represent derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

F-46

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

(5)Refined products fixed-price — Our refined products segment routinely purchases refined products inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Refined products fixed-price” represent derivatives we have entered into as an economic hedge against the risk that refined product prices will decline while we are holding the inventory.

(6)Renewable products fixed-price — Our renewables segment routinely purchases biodiesel and ethanol inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Renewable products fixed-price” represent derivatives we have entered into as an economic hedge against the risk that biodiesel or ethanol prices will decline while we are holding the inventory.

We recorded the following net gains (losses) from our commodity derivatives to cost of sales:

Year Ended March 31,
2014	$	(43,655	)
2013	(4,381		)
2012	5,676

Credit Risk

We maintain credit policies with regard to our counterparties on the derivative financial instruments that we believe minimize our overall credit risk, including an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty.

We may enter into industry standard master netting agreements and may enter into cash collateral agreements requiring the counterparty to deposit funds into a brokerage margin account. The netting agreements reduce our credit risk by providing for net settlement of any offsetting positive and negative exposures with counterparties. The cash collateral agreements reduce the level of our net counterparty credit risk because the amount of collateral represents additional funds that we may access to net settle positions due us, and the amount of collateral adjusts each day in response to changes in the market value of counterparty derivatives.

Our counterparties consist primarily of financial institutions and energy companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

As is customary in the crude oil industry, we generally receive payment from customers on a monthly basis. As a result, receivables from individual customers in our crude oil logistics are typically higher than the receivables from customers of our other segments.

Failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated statements of financial position and recognized in our net income.

Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31, 2014, we have $922.0 million of outstanding borrowings under our Revolving Credit Facility at a rate of 1.98%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.2 million on the $922.0 million of outstanding borrowings on the revolving credit facility at March 31, 2014.

Note 13 — Segments

Our reportable segments are based on the way in which our management structure is organized. Certain financial data related to our segments is shown below. Transactions between segments are recorded based on prices negotiated between the segments.

Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers, refiners, and producers. Our water solutions segment provides services for the transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. Our liquids segment supplies propane, butane, and other products, and provides natural gas liquids transportation, terminaling, and storage services to retailers, wholesalers, and refiners. Our retail propane segment sells propane and distillates to end users consisting of

F-47

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

residential, agricultural, commercial, and industrial customers, and to certain re-sellers. Our retail propane segment consists of two divisions, which are organized based on the location of the operations.

We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon Energy.

Items labeled “corporate and other” in the table below include the operations of a compressor leasing business that we acquired in our June 2012 merger with High Sierra and sold in February 2014, and the natural gas marketing operations that we acquired in our December 2013 acquisition of Gavilon Energy and began winding down during fiscal 2014. The “corporate and other” category also includes certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our consolidated financial statements.

Certain information related to the results of operations of each segment is shown in the tables below:

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Revenues:
Crude oil logistics -
Crude oil sales	$	4,559,923		$	2,322,706		$	—
Crude oil transportation and other	36,469			16,442			—
Water solutions -
Water treatment and disposal	125,788			54,334			—
Water transportation	17,312			7,893			—
Liquids -
Propane sales	1,632,948			841,448			923,022
Other product sales	1,231,965			858,276			251,627
Other revenues	31,062			33,954			2,462
Retail propane -
Propane sales	388,225			288,410			175,417
Distillate sales	127,672			106,192			6,547
Other revenues	35,918			35,856			17,370
Refined products	1,180,895			—			—
Renewables	176,781			—			—
Corporate and other	437,713			4,233			—
Eliminations of intersegment sales	(283,397		)	(151,977		)	(65,972		)
Total revenues	$	9,699,274		$	4,417,767		$	1,310,473

F-48

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Depreciation and amortization:
Crude oil logistics	$	22,111	$	9,176	$	—
Water solutions	55,105		20,923		—
Liquids	11,018		11,085		3,661
Retail propane	28,878		25,496		11,450
Refined products	109		—		—
Renewables	516		—		—
Corporate and other	3,017		2,173		—
Total depreciation and amortization	$	120,754	$	68,853	$	15,111

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Operating income (loss):
Crude oil logistics	$	678		$	34,236		$	—
Water solutions	10,317			8,576			—
Liquids	71,888			30,336			9,735
Retail propane	61,285			46,869			9,616
Refined products	4,080			—			—
Renewables	2,434			—			—
Corporate and other	(44,117		)	(32,710		)	(4,321		)
Total operating income	$	106,565		$	87,307		$	15,030

The table below shows additions to property, plant and equipment for each segment. This information has been prepared on the accrual basis, and includes property, plant and equipment acquired in acquisitions.

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Additions to property, plant and equipment, including acquisitions (accrual basis):
Crude oil logistics	$	204,642	$	89,860	$	—
Water solutions	100,877		137,116		—
Liquids	52,560		15,129		50,276
Retail propane	24,430		66,933		150,181
Refined products	719		—		—
Renewables	519		—		—
Corporate and other	7,242		17,858		—
Total	$	390,989	$	326,896	$	200,457

F-49

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

The following tables show long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets by segment:

	March 31,
			2013
	2014		(Note 2)
	(in thousands)
Total assets:
Crude oil logistics	$	1,723,812	$	801,351
Water solutions	875,714		466,412
Liquids	577,795		474,141
Retail propane	541,832		513,301
Refined products	157,581		—
Renewables	145,649		—
Corporate and other	144,840		36,413
Total	$	4,167,223	$	2,291,618
Long-lived assets, net:
Crude oil logistics	$	980,978	$	357,230
Water solutions	848,479		453,909
Liquids	274,846		238,192
Retail propane	438,324		441,762
Refined products	27,017		—
Renewables	33,703		—
Corporate and other	47,961		31,996
Total	$	2,651,308	$	1,523,089

Note 14 — Disposals and Impairments

We acquired Gavilon Energy in December 2013, which operated a natural gas marketing business. During March 2014, we assigned all of the storage and transportation contracts of the natural gas marketing business to a third party. Since these contracts were at unfavorable terms relative to current market conditions, we paid $44.8 million to assign these contracts. We recorded a liability of $50.8 million related to these storage and transportation contracts in the acquisition accounting, and we amortized $6.0 million of this balance through cost of sales during the period from the acquisition date through the date we assigned the contracts. We also assigned all forward purchase and sale contracts and all financial derivative contracts, and thereby wound down the natural gas business. Our consolidated statement of operations for the year ended March 31, 2014 includes $1.4 million of operating income related to the natural gas business, which is reported within “corporate and other” in the segment disclosures in Note 13.

We acquired High Sierra in June 2012, which operated a compressor leasing business. We sold the compressor leasing business in February 2014 for $10.8 million (net of the amount due to the owner of the noncontrolling interest in the business). We recorded a gain on the sale of the business of $4.4 million, $1.6 million of which was attributable to the disposal of the noncontrolling interest. We reported the gain as a reduction to operating expenses in our consolidated statement of operations. Our consolidated statement of operations for the year ended March 31, 2014 includes $2.3 million of operating income related to the compressor leasing business, which is reported within “corporate and other” in the segment disclosures in Note 13.

During the year ended March 31, 2014, we recorded an impairment of $5.3 million to the property, plant and equipment of one of our natural gas liquids terminals. This loss is reported within operating expenses of our liquids segment.

F-50

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

During the year ended March 31, 2014, two of our water solutions facilities experienced damage to their property, plant and equipment as a result of lightning strikes. We recorded a write-down to property, plant and equipment of $1.5 million related to these incidents, which is reported within operating expenses in our consolidated statement of operations.

Note 15 — Transactions with Affiliates

Since our business combination with SemStream on November 1, 2011, SemGroup Corporation (“SemGroup”) has held ownership interests in us and in our general partner, and has the right to appoint two members to the board of directors of our general partner. Subsequent to November 1, 2011, we have sold product to and purchased product from affiliates of SemGroup. These transactions are included within revenues and cost of sales in our consolidated statements of operations.

Certain members of our management own interests in entities with which we have purchased products and services from and have sold products and services. The majority of these purchases represent crude oil purchases and are reported within cost of sales in our consolidated statements of operations, although $8.2 million of these transactions during the year ended March 31, 2014 represented capital expenditures and were recorded as increases to property, plant and equipment. The majority of these sales represent sales of crude oil and have been recorded within revenues in our consolidated statement of operations.

These transactions are summarized in the table below:

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Sales to SemGroup	$	306,780	$	32,431	$	29,200
Purchases from SemGroup	445,951		60,425		23,800
Sales to entities affiliated with management	110,824		16,828		—
Purchases from entities affiliated with management	120,038		60,942		—

Receivables from affiliates consist of the following:

	March 31,
	2014		2013
	(in thousands)
Receivables from entities affiliated with management	$	142	$	22,883
Receivables from SemGroup	7,303		—
	$	7,445	$	22,883

Payables to affiliates consist of the following:

	March 31,
	2014		2013
	(in thousands)
Payables to SemGroup	$	76,192	$	4,601
Payables to entities affiliated with management	654		2,299
	$	76,846	$	6,900

F-51

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

We completed a merger with High Sierra Energy, LP and High Sierra Energy GP, LLC in June 2012. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner.

During the year ended March 31, 2014, we completed the acquisition of a crude oil logistics business owned by an employee. We paid $11.0 million of cash for this acquisition. During the year ended March 31, 2013, we completed two business combinations with entities in which members of our management owned interests. We paid $14.0 million of cash (net of cash acquired) on a combined basis for these two acquisitions. We also paid $5.0 million under a non-compete agreement to an employee.

Note 16 — Quarterly Financial Data (Unaudited)

Our summarized unaudited quarterly financial data is presented below. The computation of net income per common and subordinated unit is done separately by quarter and year. The total of net income per common and subordinated unit of the individual quarters may not equal the net income per common and subordinated unit for the year, due primarily to the income allocation between the general partner and limited partners and variations in the weighted average units outstanding used in computing such amounts.

Our retail propane segment’s business is seasonal due to weather conditions in our service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Our liquids segment is also subject to seasonal fluctuations, as demand for propane and butane is typically higher during the winter months. Our operating revenues from our other segments are less weather sensitive. Additionally, the acquisitions described in Note 4 impact the comparability of the quarterly information within the year, and year to year.

F-52

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements - Continued

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

	Quarter Ended										Year Ended
	June 30,			September 30,			December 31,		March 31,		March 31,
	2013			2013			2013		2014		2014
	(in thousands, except unit and per unit data)
Total revenues	$	1,385,957		$	1,593,937		$	2,743,445	$	3,975,935	$	9,699,274
Total cost of sales	$	1,303,076		$	1,488,850		$	2,576,029	$	3,764,744	$	9,132,699
Net income (loss)	$	(17,508	)	$	(932	)	$	24,052	$	43,146	$	48,758
Net income (loss) attributable to parent equity	$	(17,633	)	$	(941	)	$	23,898	$	42,331	$	47,655
Earnings (loss) per unit, basic and diluted -
Common units	$	(0.35	)	$	(0.05	)	$	0.27	$	0.46	$	0.51
Subordinated units	$	(0.46	)	$	(0.09	)	$	0.23	$	0.46	$	0.32
Weighted average common units outstanding - basic and diluted	47,703,313			58,909,389			67,941,726		73,421,309		61,970,471
Weighted average subordinated outstanding units - basic and diluted	5,919,346			5,919,346			5,919,346		5,919,346		5,919,346

	Quarter Ended									Year Ended
	June 30,			September 30,		December 31,		March 31,		March 31,
	2012			2012		2012		2013		2013
	(in thousands, except unit and per unit data)
Total revenues	$	326,436		$	1,135,510	$	1,338,208	$	1,617,613	$	4,417,767
Total cost of sales	$	298,985		$	1,053,690	$	1,204,545	$	1,481,890	$	4,039,110
Net income (loss)	$	(24,710	)	$	10,082	$	40,477	$	22,341	$	48,190
Net income (loss) attributable to parent equity	$	(24,650	)	$	10,073	$	40,176	$	22,341	$	47,940
Earnings (loss) per unit, basic and diluted -
Common units	$	(0.76	)	$	0.18	$	0.75	$	0.39	$	0.96
Subordinated units	$	(0.77	)	$	0.18	$	0.75	$	0.39	$	0.93
Weighted average common units outstanding - basic and diluted	26,529,133			44,831,836		46,364,381		47,665,015		41,353,574
Weighted average subordinated outstanding units - basic and diluted	5,919,346			5,919,346		5,919,346		5,919,346		5,919,346

F-53

INDEX TO EXHIBITS

Exhibit Number	Description
2.1	Contribution, Purchase and Sale Agreement dated as of September 30, 2010 by and among Hicks Oils & Hicksgas, Incorporated, Hicksgas Gifford, Inc., Gifford Holdings, Inc., NGL Supply, Inc., NGL Holdings, Inc., the other stockholders of NGL Supply, Inc., Krim2010, LLC, Infrastructure Capital Management, LLC, Atkinson Investors, LLC, Silverthorne Energy Holdings LLC and Silverthorne Energy Partners LP (incorporated by reference to Exhibit 2.1 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
2.2	Contribution and Sale Agreement, dated August 12, 2011, by and among the Partnership and the Sellers named therein (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 7, 2011)
2.3	Contribution and Sale Agreement dated August 31, 2011, by and among the Partnership, SemStream and the other parties thereto (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on November 4, 2011)
2.4	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Liberty Propane, L.L.C. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.5	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer-Enviro Propane, L.L.C. (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.6	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer-Pittman Propane, L.L.C. (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.7	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer-Portland Propane, L.L.C. (incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.8	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer Propane (Washington), L.L.C. (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.9	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer-Salida Propane, L.L.C. (incorporated by reference to Exhibit 2.6 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.10	Contribution and Sale Agreement, dated December 12, 2011, by and between NGL Energy Partners LP and Pacer-Utah Propane, L.L.C. (incorporated by reference to Exhibit 2.7 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
2.11	Asset Purchase Agreement, dated as of January 16, 2012, by and among NGL Energy Partners LP and North American Propane, Inc., EnergyUSA Propane, Inc., EUSA-Allied Acquisition Corp. and EUSA Heating & Air Conditioning Services, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on February 10, 2012)
2.12	Waiver and First Amendment to Asset Purchase Agreement dated as of January 31, 2012 by and among NGL Energy Partners LP and North American Propane, Inc., EnergyUSA Propane, Inc., EUSA-Allied Acquisition Corp. and EUSA Heating & Air Conditioning Services, Inc. (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K/A (File No. 001-35172) filed with the SEC on April 20, 2012)

Exhibit Number	Description
2.13	Waiver and Second Amendment to Asset Purchase Agreement dated as of February 3, 2012 by and among NGL Energy Partners LP and North American Propane, Inc., EnergyUSA Propane, Inc., EUSA-Allied Acquisition Corp. and EUSA Heating & Air Conditioning Services, Inc. (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K/A (File No. 001-35172) filed with the SEC on April 20, 2012)
2.14	Agreement and Plan of Merger, dated as of May 18, 2012, by and among NGL Energy Partners LP, NGL Energy Holdings LLC, HSELP LLC, High Sierra Energy, LP and the High Sierra Energy GP, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 21, 2012)
2.15	Agreement and Plan of Merger, dated as of May 18, 2012, by and among NGL Energy Holdings LLC, HSEGP LLC and High Sierra Energy GP, LLC (incorporated by reference to Exhibit 2.2 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 21, 2012)
2.16	Equity Purchase Agreement, dated as of October 23, 2012, among Black Hawk Gathering, L.L.C. Midstream Operations L.L.C., Pecos Gathering & Marketing, L.L.C., Striker Oilfield Services, LLC, Transwest Leasing, LLC, the owners of the Pecos Entities, NGL Energy Partners LP and Gerald L. Jensen (incorporated by reference to Exhibit 2.1 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012)
2.17	Sale Agreement, dated as of December 31, 2012, among Third Coast Towing, LLC, Jeff Kirby, Jane Helm, James Rudellat and High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 7, 2013)
2.18	LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Pearsall SWD, LLC, OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.19	LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Karnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.20	LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.21	LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.22	LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWL Operating, LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
2.23	Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP, Gavilon, LLC and Gavilon Energy Intermediate, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013)
3.1	Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
3.2	Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)

Exhibit Number	Description
3.3	Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011)
3.4	First Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 26, 2011)
3.5	Second Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
3.6	Third Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 26, 2012)
3.7	Fourth Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 2012)
3.8	Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
3.9	Certificate of Amendment to Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
3.10	Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on February 28, 2013)
3.11	Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of August 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
4.1	First Amended and Restated Registration Rights Agreement, dated October 3, 2011, by and among the Partnership, Hicks Oils & Hicksgas, Incorporated, NGL Holdings, Inc., Krim2010, LLC, Infrastructure Capital Management, LLC, Atkinson Investors, LLC, E. Osterman Propane, Inc. and the other holders party thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 7, 2011)
4.2	Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 by and among the Partnership and SemStream (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on November 4, 2011)
4.3	Amendment No. 2 and Joinder to First Amended and Restated Registration Rights Agreement, dated January 3, 2012, by and among NGL Energy Holdings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-Portland Propane, L.L.C., Pacer Propane (Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
4.4	Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGL Energy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 4, 2012)
4.5	Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and between NGL Energy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)

Exhibit Number	Description
4.6	Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and between NGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2012)
4.7	Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by and between NGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust and Nitor Trust (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 19, 2012)
4.8	Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by and among NGL Energy Partners LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
4.9	Call Agreement, dated as of November 1, 2012, among Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust, Nitor Trust and NGL Energy Partners LP (incorporated by reference to Exhibit 4.1 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012)
4.10	Call Agreement, dated as of December 31, 2012, among NGL Energy Partners LP, Jeff Kirby, Jane Helm and James Rudellat (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 7, 2013)
4.11	Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
4.12	Amendment No. 1 to Note Purchase Agreement, dated as of January 15, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18, 2013)
4.13	Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 9, 2013)
4.14	Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s 6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)
4.15	Amendment No. 4 to Note Purchase Agreement, dated as of November 5, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
4.16	Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30, 2013)
4.17	Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
4.18	Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
4.19*	First Supplemental Indenture, dated as of December 2, 2013, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee
4.20*	Second Supplemental Indenture, dated as of April 22, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiary party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee

Exhibit Number	Description
4.21	Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
4.22	Registration Rights Agreement, dated December 2, 2013, by and among NGL Energy Partners LP and the purchasers set forth on Schedule A thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013)
10.1	Agreement Relating to Redemption of Common Units in Connection with the Underwriters’ Option to Purchase Additional Common Units with Respect to the Initial Public Offering of NGL Energy Partners LP by and among NGL Energy Partners LP, NGL Energy Holdings LLC, and each of Atkinson Investors, LLC, Infrastructure Capital Management, LLC, Hicks Oils & Hicksgas, Incorporated, Krim2010, LLC, NGL Holdings, Inc., Stanley A. Bugh, David R. Eastin, Robert R. Foster, Craig S. Jones, Mark McGinty, Brian K. Pauling, Stanley D. Perry, Daniel Post, Sharra Straight and Stephen D. Tuttle, effective as of May 9, 2011 (incorporated by reference to Exhibit 10.9 to the Registration Statement on Form S-1 (File No. 333-172186) filed on May 9, 2011)
10.2	Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders party thereto and Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
10.3	Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012)
10.4	Amendment No. 1 to Credit Agreement, dated as of January 15, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18, 2013)
10.5	Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No 001-35172) filed on May 9, 2013)
10.6	Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, each subsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank Trust Company Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)
10.7	Amendment No. 4 to Credit Agreement, dated as of November 5, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
10.8	Amendment No. 5 to Credit Agreement, dated as of December 23, 2013, among NGL Energy Operating, LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank and Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30, 2013)
10.9	Facility Increase Agreement among NGL Energy Operating, LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 3, 2014)

Exhibit Number	Description
10.10	Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed on Schedule A thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013)
10.11+	Letter Agreement among Silverthorne Energy Holdings LLC, Shawn W. Coady and Todd M. Coady dated October 14, 2010 (incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
10.12+	NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011)
10.13+	Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended June 30, 2012 filed with the SEC on August 14, 2012 )
12.1*	Computation of ratios of earnings to fixed charges.
21.1*	List of Subsidiaries of NGL Energy Partners LP
23.1*	Consent of Grant Thornton LLP
31.1*	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
31.2*	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002
32.1*	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
32.2*	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes — Oxley Act of 2002
101.INS**	XBRL Instance Document
101.SCH**	XBRL Taxonomy Extension Schema Document
101.CAL**	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF**	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB**	XBRL Taxonomy Extension Label Linkbase Document
101.PRE**	XBRL Taxonomy Extension Presentation Linkbase Document

*Exhibits filed with this report

**Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at March 31, 2014 and 2013, (ii) Consolidated Statements of Operations for the years ended March 31, 2014, 2013, and 2012, (iii) Consolidated Statements of Comprehensive Income for the years ended March 31, 2014, 2013, and 2012, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2014, 2013, and 2012 and (v) Consolidated Statements of Cash Flows for the years ended March 31, 2014, 2013, and 2012.

+Management contracts or compensatory plans or arrangements.

EX-4.19

Exhibit 4.19

FIRST SUPPLEMENTAL INDENTURE

FIRST SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of December 2, 2013, among Gavilon, LLC, Gavilon Energy Holdings I, LLC, Gavilon Energy Holdings II, LLC, Gavilon Energy Holdings III, LLC, Gavilon Energy Holdings IV, LLC, Gavilon Energy Logistics, LLC, Gavilon Energy Transportation Holdco, LLC, Gavilon Energy Transport Services, LLC, Gavilon Midstream Energy, LLC, Gavilon Oil Tanks and Terminals, LLC, Gavilon Pipeline and Storage, LLC and Gavilon Shipping and Trading, LLC (collectively, the “Guaranteeing Subsidiaries”), each a subsidiary (or a permitted successor thereof) of NGL Energy Partners LP (“NGL LP”), a Delaware limited partnership, NGL LP, NGL Energy Finance Corp. (“Finance Corp.,” and, together with NGL LP, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 16, 2013 providing for the issuance of 6.875% Senior Notes due 2021 (the “Notes”);

WHEREAS, the Indenture provides that under certain circumstances each Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which each Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, each of the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1.CAPITALIZED TERMS.  Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2.AGREEMENT TO GUARANTEE.  Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof.

3.EXECUTION AND DELIVERY.  Each Guaranteeing Subsidiary agrees that the Note Guarantees shall remain in full force and effect notwithstanding any failure to endorse on each Note a notation of such Note Guarantee.

4.NO RECOURSE AGAINST OTHERS.  No past, present or future director, officer, partner, employee, incorporator, organizer, manager, unitholder or other owner of Capital Stock (as defined in the Indenture) of any Guaranteeing Subsidiary or agent thereof, as such,

shall have any liability for any obligations of the Issuers, the Guarantors, or any Guaranteeing Subsidiary or any other Subsidiary of an Issuer providing a Note Guarantee under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation.  Each Holder of the Notes by accepting a Note waives and releases all such liability.  The waiver and release are part of the consideration for issuance of the Notes.  Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

5.NEW YORK LAW TO GOVERN.  THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

6.COUNTERPARTS.  The parties may sign any number of copies of this Supplemental Indenture.  Each signed copy shall be an original, but all of them together represent the same agreement.

7.EFFECT OF HEADINGS.  The Section headings herein are for convenience only and shall not affect the construction hereof.

8.THE TRUSTEE.  The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers.

2

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARIES:
GAVILON, LLC
GAVILON ENERGY HOLDINGS I, LLC
GAVILON ENERGY HOLDINGS II, LLC
GAVILON ENERGY HOLDINGS III, LLC
GAVILON ENERGY HOLDINGS IV, LLC
GAVILON ENERGY LOGISTICS, LLC
GAVILON ENERGY TRANSPORTATION HOLDCO, LLC
GAVILON ENERGY TRANSPORT SERVICES, LLC
GAVILON MIDSTREAM ENERGY, LLC
GAVILON OIL TANKS AND TERMINALS, LLC
GAVILON PIPELINE AND STORAGE, LLC
GAVILON SHIPPING AND TRADING, LLC
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Chief Financial Officer and Treasurer
ISSUERS:
NGL ENERGY PARTNERS LP
By:	NGL Energy Holdings, LLC,
	its general partner
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Chief Financial Officer and Treasurer
NGL ENERGY FINANCE CORP.
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Senior Vice President, Chief Financial Officer and Secretary

[Signature Page to First Supplemental Indenture]

EXISTING GUARANTORS:
NGL ENERGY OPERATING LLC
NGL SUPPLY, LLC
HICKSGAS, LLC
NGL SUPPLY RETAIL, LLC
NGL SUPPLY WHOLESALE, LLC
NGL SUPPLY TERMINAL COMPANY, LLC
OSTERMAN PROPANE, LLC
NGL-NE REAL ESTATE, LLC
NGL-MA REAL ESTATE, LLC
NGL-MA, LLC
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Chief Financial Officer and Treasurer
COASTAL PLAINS DISPOSAL #1, L.L.C.
GREENSBURG OILFIELD, LLC
ANTICLINE DISPOSAL, LLC
HIGH SIERRA ENERGY MARKETING, LLC
CENTENNIAL ENERGY, LLC
CENTENNIAL GAS LIQUIDS ULC
HIGH SIERRA TRANSPORTATION, LLC
HIGH SIERRA CRUDE OIL & MARKETING, LLC
HIGH SIERRA WATER SERVICES, LLC
ANDREWS OIL BUYERS, INC.
THIRD COAST TOWING, LLC
HIGH SIERRA WATER-EAGLE FORD, LLC
PETRO SOURCE TERMINALS, LLC
PECOS GATHERING & MARKETING, L.L.C.
BLACK HAWK GATHERING, L.L.C.
MIDSTREAM OPERATIONS, LLC
HIGH SIERRA SERTCO, LLC
HIGH SIERRA ENERGY OPERATING, LLC
HIGH SIERRA COMPRESSION, LLC
HIGH SIERRA WATER HOLDINGS, LLC
HIGH SIERRA KARNES SWD, LLC
HIGH SIERRA NIXON SWD, LLC
HIGH SIERRA PEARSALL SWD, LLC
HIGH SIERRA CANADA HOLDINGS, LLC
HIGH SIERRA COTULLA SWD, LLC
HIGH SIERRA SWD OPERATOR, LLC
HIGH SIERRA SWD SHARED SERVICES, LLC
HIGH SIERRA WATER PERMIAN, LLC

[Signature Page to First Supplemental Indenture]

LOTUS OILFIELD SERVICES, L.L.C.
CC MARINE, LLC
CIERRA MARINE GP, LLC
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Chief Financial Officer
HIGH SIERRA ENERGY LP
By:	High Sierra Energy GP, LLC,
	its general partner
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Chief Financial Officer
CIERRA MARINE, L.P.
By:	Cierra Marine GP, LLC,
	its general partner
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Chief Financial Officer

[Signature Page to First Supplemental Indenture]

TRUSTEE:
U.S. BANK NATIONAL ASSOCIATION, as Trustee
By:	/s/ Israel Lugo
	Name: Israel Lugo
	Title: Vice President

[Signature Page to First Supplemental Indenture]

EX-4.20

Exhibit 4.20

SECOND SUPPLEMENTAL INDENTURE

SECOND SUPPLEMENTAL INDENTURE, dated as of April 22, 2014 (this “Supplemental Indenture”), among NGL Energy Partners LP, a Delaware limited partnership (“NGL LP”), NGL Energy Finance Corp., a Delaware corporation (“Finance Corp.,” and, together with NGL LP, the “Issuers”), NGL Crude Transportation, LLC, a Colorado limited liability company and a subsidiary of NGL LP (the “Guaranteeing Subsidiary”), the other Guarantors (as defined in the Indenture referred to herein), and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”).

W I T N E S S E T H

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee an indenture, dated as of October 16, 2013 (the “Original Indenture”), providing for the issuance by the Issuers of 6.875% Senior Notes due 2021 (the “Notes”);

WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the First Supplemental Indenture, dated as of December 2, 2013 (the “First Supplemental Indenture”), pursuant to which certain subsidiaries of NGL LP became Guarantors;

WHEREAS, the Original Indenture as amended and supplemented by the First Supplemental Indenture is referred to herein as the “Indenture”;

WHEREAS, the Indenture provides that, under certain circumstances, the Guaranteeing Subsidiary shall execute and deliver to the Trustee a supplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and the Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and

WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows:

1.CAPITALIZED TERMS.  Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture.

2.AGREEMENT TO GUARANTEE.  The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject to the conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof.

3.EXECUTION AND DELIVERY.  The Guaranteeing Subsidiary agrees that the Note Guarantees shall remain in full force and effect notwithstanding any failure to endorse on each Note a notation of such Note Guarantee.

4.NO RECOURSE AGAINST OTHERS.  No past, present or future director, officer, partner, employee, incorporator, organizer, manager, unitholder or other owner of Capital Stock (as defined in the Indenture) of any Guaranteeing Subsidiary or agent thereof, as such, shall have any liability for any obligations of the Issuers, the Guarantors, or any Guaranteeing Subsidiary or any other Subsidiary of an Issuer providing a Note Guarantee under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligations or their creation.  Each Holder of the Notes by accepting a Note waives and releases all such liability.  The waiver and release are part of the consideration for issuance of the Notes.  Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of the SEC that such a waiver is against public policy.

5.NEW YORK LAW TO GOVERN.  THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THIS SUPPLEMENTAL INDENTURE.

6.COUNTERPARTS.  The parties may sign any number of copies of this Supplemental Indenture.  Each signed copy shall be an original, but all of them together represent the same agreement.

7.EFFECT OF HEADINGS.  The Section headings herein are for convenience only and shall not affect the construction hereof.

8.THE TRUSTEE.  The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this Supplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary and the Issuers.

2

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

GUARANTEEING SUBSIDIARY:
NGL CRUDE TRANSPORTATION, LLC
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Chief Financial Officer and Treasurer
ISSUERS:
NGL ENERGY PARTNERS LP
By:	NGL Energy Holdings, LLC,
	its general partner
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Chief Financial Officer and Treasurer
NGL ENERGY FINANCE CORP.
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Senior Vice President, Chief Financial Officer and Secretary
EXISTING GUARANTORS:
NGL ENERGY OPERATING LLC
NGL LIQUIDS, LLC
(f/k/a NGL Supply, LLC)
HICKSGAS, LLC
NGL PROPANE, LLC
(f/k/a NGL Supply Retail, LLC)
NGL SUPPLY WHOLESALE, LLC
NGL SUPPLY TERMINAL COMPANY, LLC
OSTERMAN PROPANE, LLC
NGL-NE REAL ESTATE, LLC
NGL-MA REAL ESTATE, LLC
NGL-MA, LLC

(Signature Page to Second Supplemental Indenture)

NGL CRUDE LOGISTICS, LLC
(f/k/a Gavilon, LLC)
NGL ENERGY HOLDINGS II, LLC
(f/k/a Gavilon Energy Holdings II, LLC)
NGL ENERGY LOGISTICS, LLC
(f/k/a Gavilon Energy Logistics, LLC)
NGL CRUDE TERMINALS, LLC
(f/k/a Gavilon Midstream Energy, LLC)
NGL CRUDE CUSHING, LLC
(f/k/a Gavilon Oil Tanks and Terminals, LLC)
NGL CRUDE PIPELINES, LLC
(f/k/a Gavilon Pipeline and Storage, LLC)
NGL SHIPPING AND TRADING, LLC
(f/k/a Gavilon Shipping and Trading, LLC)
GREENSBURG OILFIELD, LLC
ANTICLINE DISPOSAL, LLC
HIGH SIERRA ENERGY MARKETING, LLC
CENTENNIAL ENERGY, LLC
CENTENNIAL GAS LIQUIDS ULC
HIGH SIERRA TRANSPORTATION, LLC
HIGH SIERRA CRUDE OIL & MARKETING, LLC
NGL WATER SOLUTIONS DJ, LLC
(f/k/a High Sierra Water Services, LLC)
ANDREWS OIL BUYERS, INC.
NGL MARINE, LLC
(f/k/a Third Coast Towing, LLC)
NGL WATER SOLUTIONS EAGLE FORD, LLC
(f/k/a High Sierra Water-Eagle Ford, LLC)
PETRO SOURCE TERMINALS, LLC
MIDSTREAM OPERATIONS, LLC
HIGH SIERRA SERTCO, LLC
HIGH SIERRA ENERGY OPERATING, LLC
HIGH SIERRA COMPRESSION, LLC
NGL WATER SOLUTIONS, LLC
(f/k/a High Sierra Water Holdings, LLC)
NGL CRUDE CANADA HOLDINGS, LLC
(f/k/a High Sierra Canada Holdings, LLC)
NGL WATER SOLUTIONS PERMIAN, LLC
(f/k/a High Sierra Water Permian, LLC)
LOTUS OILFIELD SERVICES, L.L.C.
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Chief Financial Officer and Treasurer

(Signature Page to Second Supplemental Indenture - Continued)

HIGH SIERRA ENERGY LP
By:	High Sierra Energy GP, LLC,
	its general partner
By:	/s/ Atanas H. Atanasov
	Name: Atanas H. Atanasov
	Title: Chief Financial Officer

(Signature Page to Second Supplemental Indenture - Continued)

TRUSTEE:
U.S. BANK NATIONAL ASSOCIATION, as Trustee
By:	/s/ Israel Lugo
	Name: Israel Lugo
	Title: Vice President

(Signature Page to Second Supplemental Indenture)

EX-12.1

Exhibit 12.1

NGL ENERGY PARTNERS LP AND SUBSIDIARIES AND NGL SUPPLY, INC.

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(In thousands, except ratio amounts)

	NGL Energy Partners LP										NGL Supply, Inc.
									Six Months		Six Months			Year
									Ended		Ended			Ended
	Year Ended March 31,								March 31,		September 30,			March 31,
	2014			2013			2012		2011		2010			2010
EARNINGS:
Income (loss) from continuing operations before income taxes	$	49,695		$	50,065		$	8,465	$	12,679	$	(3,977	)	$	6,108
Loss (income) from continuing operations before income taxes attributable to noncontrolling interests	(1,103		)	(250		)	12		—		45			6
Fixed charges	91,622			66,824			9,354		2,761		597			1,149
Total earnings (loss)	$	140,214		$	116,639		$	17,831	$	15,440	$	(3,335	)	$	7,263
FIXED CHARGES:
Interest expense	$	58,854		$	32,994		$	7,620	$	2,482	$	372		$	668
Loss on early extinguishment of debt	—			5,769			—		—		—			—
Portion of rental expense estimated to relate to interest (a)	32,768			28,061			1,734		279		225			481
Fixed charges	$	91,622		$	66,824		$	9,354	$	2,761	$	597		$	1,149
Ratio of earnings to fixed charges	1.53			1.75			1.91		5.59		(b)			6.32

(a)Represents one-third of the total operating lease rental expense, which is that portion estimated to represent interest.

(b)Due to NGL Supply, Inc.’s loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2010. NGL Supply, Inc. would have needed to generate an additional $3.9 million of earnings to achieve a ratio of 1:1.

EX-21.1

Exhibit 21.1

LIST OF SUBSIDIARIES OF NGL ENERGY PARTNERS LP

Subsidiary	Jurisdiction of Organization
NGL Energy Operating LLC	Delaware
Hicksgas, LLC	Delaware
NGL Supply, LLC	Delaware
NGL Gateway Terminals, Inc.	Ontario
NGL Supply Retail, LLC	Delaware
NGL Supply Terminal Company, LLC	Delaware
NGL Supply Wholesale, LLC	Delaware
Osterman Propane, LLC	Delaware
NGL-NE Real Estate, LLC	Delaware
NGL-MA Real Estate, LLC	Delaware
NGL-MA, LLC	Delaware
Atlantic Propane LLC (1)	Oklahoma
NGL Hutch, LLC	Delaware
High Sierra Energy GP, LLC	Colorado
High Sierra Energy, LP	Delaware
High Sierra Energy Shared Services, LLC	Colorado
High Sierra Energy Operating, LLC	Colorado
High Sierra Compression, LLC	Colorado
High Sierra SERTCO, LLC (2)	Colorado
High Sierra Energy Marketing, LLC	Colorado
Centennial Energy, LLC	Colorado
Centennial Gas Liquids, ULC	Alberta
High Sierra Crude Oil & Marketing, LLC	Colorado
Andrews Oil Buyers, Inc.	Texas
Petro Source Products, LLC	Texas
Petro Source Terminals, LLC	Texas
High Sierra Canada Holdings, LLC	Colorado
High Sierra Energy Canada ULC	Alberta
High Sierra Transportation, LLC	Colorado
High Sierra Marine, LLC	Texas
High Sierra Water Holdings, LLC	Colorado
High Sierra Water Services, LLC	Colorado
AntiCline Disposal, LLC	Wyoming
High Sierra Water Services Midcontinent, LLC	Oklahoma
High Sierra Water Permian, LLC	Colorado
Greensburg Oilfield, LLC	Colorado
High Sierra Water-Eagle Ford, LLC	Delaware
Indigo Injection #3-1, LLC (3)	Delaware
NGL Energy Finance Corp	Delaware
Gavilon, LLC	Delaware
Lotus Oilfield Services, LLC	Texas
NHG Investments, LLC	Colorado
E Energy Adams, LLC (4)	Nebraska
Gavilon Midstream Energy, LLC	Delaware
Gavilon Pipeline and Storage, LLC	Oklahoma
Gavilon Oil Tanks and Terminals, LLC	Oklahoma
Gavilon Energy Holdings II, LLC	Delaware
Glass Mountain Pipeline, LLC (5)	Delaware
NGL Shipping and Trading, LLC	Delaware
Gavilon Energy Logistics, LLC	Delaware

(1)NGL Energy Partners LP owns a 60% member interest in Atlantic Propane LLC.

(2)NGL Energy Partners LP owns an 80% member interest in High Sierra SERTCO, LLC.

(3)NGL Energy Partners LP owns a 75% member interest in Indigo Injection #3-1, LLC.

(4)NGL Energy Partners LP owns an 11% member interest in E Energy Adams, LLC.

(5)NGL Energy Partners LP owns a 50% member interest in Glass Mountain Pipeline, LLC.

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our reports dated May 30, 2014, with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of NGL Energy Partners LP on Form 10-K for the year ended March 31, 2014. We hereby consent to the incorporation by reference of said reports in the Registration Statements of NGL Energy Partners LP on Form S-8 (File No. 333-185068) and on Forms S-3 (File No. 333-189842 and File No. 333-194035).

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

May 30, 2014

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, H. Michael Krimbill, certify that:

1.I have reviewed this Annual Report on Form 10-K of NGL Energy Partners LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: May 30, 2014	/s/ H. Michael Krimbill
	H. Michael Krimbill
	Chief Executive Officer of
	NGL Energy Holdings LLC, the general partner of
	NGL Energy Partners LP

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Atanas H. Atanasov, certify that:

1.I have reviewed this Annual Report on Form 10-K of NGL Energy Partners LP;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Dated: May 30, 2014	/s/ Atanas H. Atanasov
	Atanas H. Atanasov
	Chief Financial Officer of
	NGL Energy Holdings LLC, the general partner of
	NGL Energy Partners LP

EX-32.1

EXHIBIT 32.1

CERTIFICATION

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Annual Report of NGL Energy Partners LP (the “Partnership”) on Form 10-K for the fiscal year ended March 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, H. Michael Krimbill, Chief Executive Officer of NGL Energy Holdings LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Dated: May 30, 2014	/s/ H. Michael Krimbill
	H. Michael Krimbill
	Chief Executive Officer of
	NGL Energy Holdings LLC, the
	general partner of the Partnership

This certification is being furnished solely pursuant to Section 906 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

EXHIBIT 32.2

CERTIFICATION

PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Annual Report of NGL Energy Partners LP (the “Partnership”) on Form 10-K for the fiscal year ended March 31, 2014 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Atanas H. Atanasov, Chief Financial Officer of NGL Energy Holdings LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (“Section 906”), that, to my knowledge:

1.The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Dated: May 30, 2014	/s/ Atanas H. Atanasov
	Atanas H. Atanasov
	Chief Financial Officer of
	NGL Energy Holdings LLC, the
	general partner of the Partnership

This certification is being furnished solely pursuant to Section 906 and is not being filed as part of the Report or as a separate disclosure document.

A signed original of this written statement required by Section 906 has been provided to the Partnership and will be retained by the Partnership and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Nature of Operations and Organization (Details 2)			1 Months Ended			1 Months Ended
	Mar. 31, 2014	Nov. 01, 2011 SemStream item	Jan. 31, 2012 Pacer item	Jul. 31, 2013 Crescent Terminals, LLC item	Mar. 31, 2014 Big Lake item	Aug. 31, 2013 Oilfield Water Lines LP item	Mar. 31, 2014 Coastal item	Dec. 02, 2013 Gavilon Energy Glass Mountain
Acquisitions Subsequent to Initial Public Offering
Number of acquired natural gas liquids terminals		12
Number of companies associated with the acquiree entity			7			7
Number of tow boats acquired				4
Number of crude oil barges acquired				7
Number of water disposal facilities acquired					1		1
Equity method ownership interest (as a percent)	50.00%							50.00%

XML

Acquisitions (Details 9) (USD $)	12 Months Ended				12 Months Ended							12 Months Ended										12 Months Ended				12 Months Ended							12 Months Ended					12 Months Ended					12 Months Ended					12 Months Ended					12 Months Ended
	Mar. 31, 2013 item	Mar. 31, 2014	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Vehicles Minimum	Mar. 31, 2014 Vehicles Maximum	Mar. 31, 2014 Water treatment facilities and equipment Minimum	Mar. 31, 2014 Water treatment facilities and equipment Maximum	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Jun. 19, 2012 Crude oil tanks and related equipment	Mar. 31, 2014 Crude oil tanks and related equipment Minimum	Mar. 31, 2014 Crude oil tanks and related equipment Maximum	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations item	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Change	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Trade names	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Trade names Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Trade names Change	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Customer relationships	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Customer relationships Minimum	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Customer relationships Maximum	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Customer relationships Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Customer relationships Change	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Non-compete agreements	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Non-compete agreements Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Non-compete agreements Change	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Land	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Land Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Land Change	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Vehicles	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Vehicles Minimum	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Vehicles Maximum	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Vehicles Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Vehicles Change	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Water treatment facilities and equipment	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Water treatment facilities and equipment Minimum	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Water treatment facilities and equipment Maximum	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Water treatment facilities and equipment Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Water treatment facilities and equipment Change	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Buildings and leasehold improvements	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Buildings and leasehold improvements Minimum	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Buildings and leasehold improvements Maximum	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Buildings and leasehold improvements Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Buildings and leasehold improvements Change	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Crude oil tanks and related equipment	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Crude oil tanks and related equipment Minimum	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Crude oil tanks and related equipment Maximum	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Crude oil tanks and related equipment Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Crude oil tanks and related equipment Change	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Other	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Other Minimum	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Other Maximum	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Other Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Other Change	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Construction in progress	Mar. 31, 2013 Other Crude Oil Logistics and Water Solutions Business Combinations Construction in progress Estimated at March 31, 2013	Mar. 31, 2014 Other Crude Oil Logistics and Water Solutions Business Combinations Construction in progress Change
Acquisitions
Number of business combination agreements	2														4
Liabilities assumed in the form of non-compete agreements															$ 1,300,000
Number of common units issued to acquire business (in shares)														516,978
General and administrative expense															300,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade														2,676,000		2,660,000	16,000
Inventories														191,000		191,000
Prepaid expenses and other current assets														737,000		738,000	(1,000)
Property, plant and equipment											17,851,000																		218,000	191,000	27,000	853,000			771,000	82,000	13,665,000			13,322,000	343,000	895,000			2,233,000	(1,338,000)	4,510,000			1,781,000	2,729,000	27,000			2,000	25,000	490,000	693,000	(203,000)
Useful life of property, plant and equipment					3 years	25 years	3 years	30 years	3 years	40 years		2 years	40 years																				5 years	10 years				3 years	30 years				5 years	30 years				2 years	15 years				3 years	5 years
Intangible assets																		2,100,000	500,000	1,600,000	13,125,000			6,800,000	6,325,000	164,000	510,000	(346,000)
Useful life of intangible assets																						5 years	10 years			3 years
Goodwill	555,220,000	1,107,006,000	167,245,000	8,568,000										34,451,000		43,822,000	(9,371,000)
Accounts payable - trade														(3,374,000)		(3,374,000)
Accrued expenses and other payables														(1,914,000)		(2,026,000)	112,000
Notes payable														(1,340,000)		(1,340,000)
Other noncurrent liabilities														(156,000)	(1,340,000)	(156,000)
Noncontrolling interest														(2,333,000)		(2,333,000)
Fair value of net assets acquired														64,985,000		64,985,000
Consideration paid for acquisition
Cash paid, net of cash acquired	14,000,000													52,552,000
Value of common units issued														12,433,000
Total consideration paid														$ 64,985,000

XML

Acquisitions (Details 3) (USD $)	3 Months Ended								12 Months Ended				12 Months Ended										12 Months Ended			0 Months Ended	12 Months Ended				12 Months Ended			12 Months Ended			12 Months Ended			12 Months Ended		0 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2014	Mar. 31, 2013 item	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Water facility development agreement item	Mar. 31, 2014 Vehicles Minimum	Mar. 31, 2014 Vehicles Maximum	Mar. 31, 2014 Water treatment facilities and equipment Minimum	Mar. 31, 2014 Water treatment facilities and equipment Maximum	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Mar. 31, 2014 Other Water Services item	Mar. 31, 2014 Other Water Services Customer relationships	Mar. 31, 2014 Other Water Services Trade names	Mar. 31, 2014 Other Water Services Non-compete agreements	Mar. 31, 2014 Other Water Services Water facility development agreement	Mar. 31, 2014 Other Water Services Water facility option agreement	Mar. 02, 2014 Other Water Services Water facility development agreement item	Mar. 31, 2014 Other Water Services Minimum Customer relationships	Mar. 31, 2014 Other Water Services Maximum Customer relationships	Mar. 31, 2014 Other Water Services Land	Mar. 31, 2014 Other Water Services Vehicles	Mar. 31, 2014 Other Water Services Vehicles Minimum	Mar. 31, 2014 Other Water Services Vehicles Maximum	Mar. 31, 2014 Other Water Services Water treatment facilities and equipment	Mar. 31, 2014 Other Water Services Water treatment facilities and equipment Minimum	Mar. 31, 2014 Other Water Services Water treatment facilities and equipment Maximum	Mar. 31, 2014 Other Water Services Buildings and leasehold improvements	Mar. 31, 2014 Other Water Services Buildings and leasehold improvements Minimum	Mar. 31, 2014 Other Water Services Buildings and leasehold improvements Maximum	Mar. 31, 2014 Other Water Services Other	Mar. 31, 2014 Other Water Services Other Minimum	Mar. 31, 2014 Other Water Services Other Maximum	Mar. 02, 2014 Saltwater disposal facility
Acquisitions
Number of business acquired										2										4
Number of common units issued to acquire business (in shares)																				222,381
General and administrative expense																				$ 400,000
Revenue, Net	3,975,935,000	2,743,445,000	1,593,937,000	1,385,957,000	1,617,613,000	1,338,208,000	1,135,510,000	326,436,000	9,699,274,000	4,417,767,000	1,310,473,000									20,600,000
Operating income									106,565,000	87,307,000	15,030,000									7,100,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade																				2,391,000
Inventories																				390,000
Prepaid expenses and other current assets																				61,000
Property, plant and equipment																													419,000	90,000			24,933,000			3,036,000			13,000
Useful life of property, plant and equipment														3 years	25 years	3 years	30 years	3 years	40 years												5 years	10 years		3 years	30 years		7 years	30 years		3 years	5 years
Intangible assets																					72,000,000	3,325,000	260,000	14,000,000	2,500,000
Useful life of intangible assets																							3 years	5 years			8 years	10 years
Goodwill	1,107,006,000				555,220,000				1,107,006,000	555,220,000	167,245,000	8,568,000								63,031,000
Accounts payable - trade																				(382,000)
Accrued expenses and other payables																				(300,000)
Other noncurrent liabilities																				(114,000)
Fair value of net assets acquired																				185,653,000
Consideration paid for acquisition
Cash paid, net of cash acquired										14,000,000										178,867,000																						3,700,000
Value of common units issued																				6,786,000
Total consideration paid																				$ 185,653,000						$ 21,000,000
Number of options specified in the agreement for the calculation of the purchase price													2													3
Maximum period for which the option is available to operate the facility													90 days													90 days

XML

Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended	1 Months Ended		4 Months Ended
	Mar. 31, 2014	Aug. 31, 2013 Pecos	May 30, 2013 Pecos	Feb. 28, 2013 Pecos
Legal contingencies
Amount not paid by customer for disputed transportation rate schedule				$ 1.7
Amount requested as refund by the customer			5.5
Payment intended to withheld by the customer		3.3
Amount of fuel taxes and sales taxes that should have been collected from customers and remitted to taxing authority	0.8
Asset retirement obligations
Asset retirement obligations	$ 2.3

XML

Acquisitions (Details 10) (USD $)	12 Months Ended				12 Months Ended									12 Months Ended					12 Months Ended					12 Months Ended
	Mar. 31, 2013 item	Mar. 31, 2014	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Retail propane equipment Minimum	Mar. 31, 2014 Retail propane equipment Maximum	Mar. 31, 2014 Vehicles Minimum	Mar. 31, 2014 Vehicles Maximum	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Mar. 31, 2013 Retail Propane Combinations item	Mar. 31, 2013 Retail Propane Combinations Trade names	Mar. 31, 2013 Retail Propane Combinations Customer relationships	Mar. 31, 2013 Retail Propane Combinations Customer relationships Minimum	Mar. 31, 2013 Retail Propane Combinations Customer relationships Maximum	Mar. 31, 2013 Retail Propane Combinations Non-compete agreements	Mar. 31, 2013 Retail Propane Combinations Land	Mar. 31, 2013 Retail Propane Combinations Retail propane equipment	Mar. 31, 2013 Retail Propane Combinations Retail propane equipment Minimum	Mar. 31, 2013 Retail Propane Combinations Retail propane equipment Maximum	Mar. 31, 2013 Retail Propane Combinations Vehicles	Mar. 31, 2013 Retail Propane Combinations Buildings and leasehold improvements	Mar. 31, 2013 Retail Propane Combinations Other	Mar. 31, 2013 Retail Propane Combinations Common units
Acquisitions
Number of business combination agreements	2										6
Number of common units issued to acquire business (in shares)																								850,676
Liabilities assumed in the form of non-compete agreements											$ 6,600,000
General and administrative expense											300,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade											8,715,000
Inventory											5,155,000
Other current assets											1,228,000
Property, plant and equipment																	1,945,000	28,763,000			11,344,000	7,052,000	1,201,000
Useful life of property, plant and equipment					2 years	30 years	3 years	25 years	3 years	40 years									5 years	20 years	5 years	30 years
Intangible assets												2,924,000	16,890,000			1,387,000
Useful life of intangible assets														10 years	15 years	5 years
Goodwill	555,220,000	1,107,006,000	167,245,000	8,568,000							21,983,000
Other non-current assets											784,000
Long-term debt											(6,594,000)
Other assumed liabilities											(12,511,000)
Fair value of net assets acquired											90,266,000
Consideration paid for acquisition
Cash paid, net of cash acquired	14,000,000										71,392,000
Value of common units issued																								18,874,000
Total consideration paid											$ 90,266,000

XML

Fair Value of Financial Instruments (Details 3) (USD $)	12 Months Ended
	Mar. 31, 2014
Revolving Credit Facility
Interest Rate Risk
Outstanding debt	$ 922,000,000
Interest rate (as a percent)	1.98%
Interest Rate Risk | Variable Rate Debt
Interest Rate Risk
Change in interest rate that would result in an increase or decrease of annual interest expense (as a percent)	0.125%
Increase or decrease in annual interest expense	$ 1,200,000

XML

Acquisitions (Details) (USD $)	3 Months Ended								12 Months Ended					12 Months Ended								0 Months Ended	12 Months Ended					12 Months Ended			12 Months Ended			12 Months Ended				12 Months Ended			12 Months Ended					12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2011	Jun. 19, 2012 Crude oil tanks and related equipment	Mar. 31, 2014 Crude oil tanks and related equipment Minimum	Mar. 31, 2014 Crude oil tanks and related equipment Maximum	Mar. 31, 2014 Vehicles Minimum	Mar. 31, 2014 Vehicles Maximum	Mar. 31, 2014 Information technology equipment Minimum	Mar. 31, 2014 Information technology equipment Maximum	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Dec. 02, 2013 Gavilon Energy	Mar. 31, 2014 Gavilon Energy	Mar. 31, 2014 Gavilon Energy Employee severance	Mar. 31, 2014 Gavilon Energy Crude oil storage lease commitments	Mar. 31, 2014 Gavilon Energy Storage and transportation contracts of natural gas	Mar. 31, 2014 Gavilon Energy Customer relationships	Mar. 31, 2014 Gavilon Energy Customer relationships Minimum	Mar. 31, 2014 Gavilon Energy Customer relationships Maximum	Mar. 31, 2014 Gavilon Energy Lease Agreements	Mar. 31, 2014 Gavilon Energy Lease Agreements Minimum	Mar. 31, 2014 Gavilon Energy Lease Agreements Maximum	Mar. 31, 2014 Gavilon Energy Crude oil tanks and related equipment	Mar. 31, 2014 Gavilon Energy Crude oil tanks and related equipment Minimum	Mar. 31, 2014 Gavilon Energy Crude oil tanks and related equipment Maximum	Mar. 31, 2014 Gavilon Energy Vehicles	Mar. 31, 2014 Gavilon Energy Information technology equipment	Mar. 31, 2014 Gavilon Energy Information technology equipment Minimum	Mar. 31, 2014 Gavilon Energy Information technology equipment Maximum	Mar. 31, 2014 Gavilon Energy Buildings and leasehold improvements	Mar. 31, 2014 Gavilon Energy Buildings and leasehold improvements Minimum	Mar. 31, 2014 Gavilon Energy Buildings and leasehold improvements Maximum	Mar. 31, 2014 Gavilon Energy Land	Mar. 31, 2014 Gavilon Energy Linefill and tank bottoms	Dec. 02, 2013 Gavilon Energy Linefill and tank bottoms	Mar. 31, 2014 Gavilon Energy Other	Mar. 31, 2014 Gavilon Energy Construction in process	Dec. 02, 2013 Gavilon Energy Construction in process	Dec. 02, 2013 Gavilon Energy Glass Mountain
Acquisitions
Cash paid, net of cash acquired										$ 14,000,000												$ 832,400,000
General and administrative expense																							5,300,000
Equity method ownership interest (as a percent)	50.00%								50.00%																																								50.00%
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade																							349,529,000
Accounts receivable - affiliates																							2,564,000
Inventories																							107,430,000
Prepaid expenses and other current assets																							68,322,000
Property, plant and equipment													17,851,000																				77,429,000			791,000	4,046,000			7,716,000			6,427,000	15,230,000		170,000	7,190,000
Useful life of property, plant and equipment														2 years	40 years	3 years	25 years	3 years	7 years	3 years	40 years													3 years	40 years	3 years		3 years	7 years		3 years	40 years				7 years
Goodwill	1,107,006,000				555,220,000				1,107,006,000	555,220,000	167,245,000	8,568,000											359,169,000																						29,000,000			29,000,000
Intangible assets																											101,600,000			8,700,000
Useful life of intangible assets																												10 years	20 years		1 year	5 years
Investments in unconsolidated entities																							178,000,000
Other noncurrent assets																							9,918,000
Accounts payable - trade																							(342,792,000)
Accounts payable - affiliates																							(2,585,000)
Accrued expenses and other payables																							(70,999,000)
Advance payments received from customers																							(10,667,000)
Other noncurrent liabilities																							(44,740,000)
Fair value of net assets acquired																							832,448,000
Excess of estimated fair value of investments in unconsolidated subsidiaries																							70,000,000
Employee severance expense																								3,200,000
Bonus expense recorded during the period																								5,000,000
Additional bonus expense expected																								6,600,000
Revenue, Net	3,975,935,000	2,743,445,000	1,593,937,000	1,385,957,000	1,617,613,000	1,338,208,000	1,135,510,000	326,436,000	9,699,274,000	4,417,767,000	1,310,473,000												2,900,000,000
Operating income									106,565,000	87,307,000	15,030,000												11,000,000
Liability recorded in the acquisition accounting																									12,900,000	50,800,000
Amortization of contract liabilities through cost of sales																									2,900,000	6,000,000
Future amortization
2015																									6,500,000
2016																									3,260,000
2017																									300,000
Payments for assignment of contracts																										$ 44,800,000

XML

Equity (Tables)

12 Months Ended

Mar. 31, 2014

Equity

Summary of common units issued as partial consideration for several acquisitions

Osterman combination	4,000,000
SemStream combination	8,932,031
Pacer combination	1,500,000
Total - Year Ended March 31, 2012	14,432,031
High Sierra combination	20,703,510
Retail propane combinations	850,676
Crude oil logistics and water solutions combinations	516,978
Pecos combination	1,834,414
Third Coast combination	344,680
Total - Year Ended March 31, 2013	24,250,258
Water solutions combinations	222,381
Crude oil logistics combinations	175,211
OWL combination	2,463,287
Total - Year Ended March 31, 2014	2,860,879

Schedule of equivalent units not eligible to receive distributions

	Equivalent
	Units Not
Record Date	Eligible
August 3, 2011	—
October 31, 2011	4,000,000
February 3, 2012	7,117,031
April 30, 2012	3,932,031
August 3, 2012	17,862,470
October 29, 2012	516,978
February 4, 2013	1,202,085
May 6, 2013	—
August 5, 2013	—
November 4, 2013	979,886
February 4, 2014	—
May 5, 2014	—

Schedule of restricted unit activity

Unvested restricted units at March 31, 2012	—
Units granted	1,684,400
Units vested and issued	(156,802	)
Units withheld for employee taxes	(61,698	)
Units forfeited	(21,000	)
Unvested restricted units at March 31, 2013	1,444,900
Units granted	494,000
Units vested and issued	(296,269	)
Units withheld for employee taxes	(122,531	)
Units forfeited	(209,000	)
Unvested restricted units at March 31, 2014	1,311,100

Summary of scheduled vesting of the awards

Vesting Date	Number of Awards
July 1, 2014	408,300
January 1, 2015	4,000
July 1, 2015	341,300
January 1, 2016	4,000
July 1, 2016	322,500
January 1, 2017	4,000
July 1, 2017	192,500
January 1, 2018	4,000
July 1, 2018	30,500
Total unvested units at March 31, 2014	1,311,100

Schedule of estimated share-based expense to be recorded on the awards granted

Year Ending March 31,
2015	$	14,393
2016	11,279
2017	7,429
2018	2,310
2019	229
Total	$	35,640

Schedule of rollforward of the liability related to equity-based compensation

Following is a rollforward of the liability related to equity-based compensation, which is reported within accrued expenses and other payables on our consolidated balance sheets (in thousands):

Balance at March 31, 2012	$	—
Expense recorded	10,138
Value of units vested and issued	(3,627		)
Taxes paid on behalf of participants	(1,468		)
Balance at March 31, 2013	5,043
Expense recorded	17,804
Value of units vested and issued	(9,085		)
Taxes paid on behalf of participants	(3,750		)
Balance at March 31, 2014	$	10,012

Partnership Equity

Schedule of percentage allocations of available cash from operating surplus between the unitholders and general partner

			Amount		Amount Paid to		Amount Paid to
Date Declared	Record Date	Date Paid	Per Unit		Limited Partners		General Partner
					(in thousands)		(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011	0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012	0.3500		7,735		10
April 18, 2012	April 30, 2012	May 15, 2012	0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012	0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012	0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013	0.4625		24,245		927
April 25, 2013	May 6, 2013	May 15, 2013	0.4775		25,605		1,189
July 25, 2013	August 5, 2013	August 14, 2013	0.4938		31,725		1,739
October 23, 2013	November 4, 2013	November 14, 2013	0.5113		35,908		2,491
January 23, 2014	February 4, 20143	February 14, 2014	0.5313		42,150		4,283
April 24, 2014	May 5, 2014	May 15, 2014	0.5513		43,737		5,754

Future Distribution Payments

Partnership Equity

Schedule of percentage allocations of available cash from operating surplus between the unitholders and general partner

					Marginal Percentage Interest In
	Total Quarterly				Distributions
	Distribution per Unit				Unitholders		General Partner
Minimum quarterly distribution				$ 0.337500	99.9	%	0.1	%
First target distribution	above	$ 0.337500	up to	$ 0.388125	99.9	%	0.1	%
Second target distribution	above	$ 0.388125	up to	$ 0.421875	86.9	%	13.1	%
Third target distribution	above	$ 0.421875	up to	$ 0.506250	76.9	%	23.1	%
Thereafter	above	$ 0.506250			51.9	%	48.1	%

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Segments (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Segment information
Revenues	$ 3,975,935	$ 2,743,445	$ 1,593,937	$ 1,385,957	$ 1,617,613	$ 1,338,208	$ 1,135,510	$ 326,436	$ 9,699,274	$ 4,417,767	$ 1,310,473
Depreciation and amortization									120,754	68,853	15,111
Operating income (loss)									106,565	87,307	15,030
Additions to property, plant and equipment including acquisitions (accrual basis)									390,989	326,896	200,457
Total assets	4,167,223				2,291,618				4,167,223	2,291,618
Long-lived assets, net	2,651,308				1,523,089				2,651,308	1,523,089
Crude oil logistics
Segment information
Depreciation and amortization									22,111	9,176
Operating income (loss)									678	34,236
Additions to property, plant and equipment including acquisitions (accrual basis)									204,642	89,860
Total assets	1,723,812				801,351				1,723,812	801,351
Long-lived assets, net	980,978				357,230				980,978	357,230
Water solutions
Segment information
Depreciation and amortization									55,105	20,923
Operating income (loss)									10,317	8,576
Additions to property, plant and equipment including acquisitions (accrual basis)									100,877	137,116
Total assets	875,714				466,412				875,714	466,412
Long-lived assets, net	848,479				453,909				848,479	453,909
Liquids
Segment information
Depreciation and amortization									11,018	11,085	3,661
Operating income (loss)									71,888	30,336	9,735
Additions to property, plant and equipment including acquisitions (accrual basis)									52,560	15,129	50,276
Total assets	577,795				474,141				577,795	474,141
Long-lived assets, net	274,846				238,192				274,846	238,192
Retail propane
Segment information
Number of operating divisions									2
Depreciation and amortization									28,878	25,496	11,450
Operating income (loss)									61,285	46,869	9,616
Additions to property, plant and equipment including acquisitions (accrual basis)									24,430	66,933	150,181
Total assets	541,832				513,301				541,832	513,301
Long-lived assets, net	438,324				441,762				438,324	441,762
Refined products
Segment information
Depreciation and amortization									109
Operating income (loss)									4,080
Additions to property, plant and equipment including acquisitions (accrual basis)									719
Total assets	157,581								157,581
Long-lived assets, net	27,017								27,017
Renewables
Segment information
Depreciation and amortization									516
Operating income (loss)									2,434
Additions to property, plant and equipment including acquisitions (accrual basis)									519
Total assets	145,649								145,649
Long-lived assets, net	33,703								33,703
Corporate and other
Segment information
Depreciation and amortization									3,017	2,173
Operating income (loss)									(44,117)	(32,710)	(4,321)
Additions to property, plant and equipment including acquisitions (accrual basis)									7,242	17,858
Total assets	144,840				36,413				144,840	36,413
Long-lived assets, net	47,961				31,996				47,961	31,996
Operating segment | Crude oil logistics | Crude oil sales
Segment information
Revenues									4,559,923	2,322,706
Operating segment | Crude oil logistics | Crude oil transportation and other
Segment information
Revenues									36,469	16,442
Operating segment | Water solutions | Water treatment and disposal
Segment information
Revenues									125,788	54,334
Operating segment | Water solutions | Water transportation
Segment information
Revenues									17,312	7,893
Operating segment | Liquids | Other revenues
Segment information
Revenues									31,062	33,954	2,462
Operating segment | Liquids | Propane sales
Segment information
Revenues									1,632,948	841,448	923,022
Operating segment | Liquids | Other product sales
Segment information
Revenues									1,231,965	858,276	251,627
Operating segment | Retail propane | Other revenues
Segment information
Revenues									35,918	35,856	17,370
Operating segment | Retail propane | Propane sales
Segment information
Revenues									388,225	288,410	175,417
Operating segment | Retail propane | Distillate sales
Segment information
Revenues									127,672	106,192	6,547
Operating segment | Refined products
Segment information
Revenues									1,180,895
Operating segment | Renewables
Segment information
Revenues									176,781
Operating segment | Corporate and other
Segment information
Revenues									437,713	4,233
Elimination of intersegment sales
Segment information
Revenues									$ (283,397)	$ (151,977)	$ (65,972)

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Equity (Details 2) (USD $)	12 Months Ended			0 Months Ended				12 Months Ended	0 Months Ended		12 Months Ended	0 Months Ended		12 Months Ended		0 Months Ended	12 Months Ended	0 Months Ended	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012	Dec. 02, 2013 Common units	Sep. 23, 2013 Common units	Jul. 05, 2013 Common units	Oct. 03, 2011 Osterman Common units	Mar. 31, 2012 Osterman Common units	Nov. 01, 2011 SemStream Common units	Jan. 03, 2012 Pacer Common units	Mar. 31, 2014 Crude oil logistics and water solutions	Nov. 12, 2012 Pecos Common units	Jan. 11, 2013 Third Coast Common units	Mar. 31, 2014 Water solutions	Mar. 31, 2014 Crude oil logistics	Aug. 02, 2013 OWL	Mar. 31, 2014 OWL	May 17, 2011 Common units	Mar. 31, 2014 Common units	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Mar. 31, 2012 Common units Osterman	Mar. 31, 2012 Common units SemStream	Mar. 31, 2012 Common units Pacer	Mar. 31, 2013 Common units High Sierra	Mar. 31, 2013 Common units Retail propane	Mar. 31, 2013 Common units Crude oil logistics and water solutions	Mar. 31, 2013 Common units Pecos	Mar. 31, 2013 Common units Third Coast
Common Units Issued in Business Combinations
Common units issued							4,000,000	4,000,000	8,932,031	1,500,000	516,978	1,834,414	344,680	222,381	175,211	2,463,287	2,463,287		2,860,879	24,250,258	14,432,031	4,000,000	8,932,031	1,500,000	20,703,510	850,676	516,978	1,834,414	344,680
Number of units sold in public offering					4,100,000	10,350,000												4,025,000
Proceeds from sale of units, after underwriting discounts and commissions and offering costs	$ 650,155,000	$ (642,000)	$ 74,759,000	$ 235,100,000	$ 127,600,000	$ 287,500,000
Underwriting discounts and commissions					5,000,000	12,000,000
Offering costs				$ 4,900,000	$ 200,000	$ 700,000
Number of units sold in private placement				8,110,848

XML

Acquisitions (Details 12) (USD $)	12 Months Ended				12 Months Ended						0 Months Ended	1 Months Ended	12 Months Ended		0 Months Ended				0 Months Ended			0 Months Ended				0 Months Ended			12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Retail propane equipment Minimum	Mar. 31, 2014 Retail propane equipment Maximum	Mar. 31, 2014 Vehicles Minimum	Mar. 31, 2014 Vehicles Maximum	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Oct. 03, 2011 Osterman	Nov. 30, 2012 Osterman	Mar. 31, 2012 Osterman	Oct. 03, 2011 Osterman Trade names	Oct. 03, 2011 Osterman Customer relationships	Oct. 03, 2011 Osterman Non-compete agreements	Oct. 03, 2011 Osterman Land	Oct. 03, 2011 Osterman Retail propane equipment	Oct. 03, 2011 Osterman Retail propane equipment Minimum	Oct. 03, 2011 Osterman Retail propane equipment Maximum	Oct. 03, 2011 Osterman Vehicles	Oct. 03, 2011 Osterman Vehicles Minimum	Oct. 03, 2011 Osterman Vehicles Maximum	Oct. 03, 2011 Osterman Buildings and leasehold improvements	Oct. 03, 2011 Osterman Other	Oct. 03, 2011 Osterman Other Minimum	Oct. 03, 2011 Osterman Other Maximum	Oct. 03, 2011 Osterman Common units	Mar. 31, 2012 Osterman Common units
Acquisitions
Number of common units issued to acquire business (in shares)																												4,000,000	4,000,000
Cash paid to acquire ownership interests, net of cash acquired	$ 1,268,810,000	$ 490,805,000	$ 297,401,000								$ 94,900,000
Working capital items, post-closing payment												4,800,000
Price per unit of units sold in initial public offering (in dollars per share)																												$ 20.47
General and administrative expense													800,000
Equity issuance costs													100,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade											9,350,000
Inventories											3,869,000
Prepaid expenses and other current assets											215,000
Property, plant and equipment																	2,349,000	47,160,000			7,699,000			3,829,000	732,000
Useful life of property, plant and equipment					2 years	30 years	3 years	25 years	3 years	40 years									15 years	20 years		5 years	20 years	30 years		3 years	5 years
Intangible assets														8,500,000	54,500,000	700,000
Useful life of intangible assets															20 years	7 years
Goodwill	1,107,006,000	555,220,000	167,245,000	8,568,000							52,267,000
Assumed liabilities											(9,654,000)
Fair value of net assets acquired											181,516,000
Consideration paid for acquisition
Cash paid to acquire ownership interests		14,000,000									94,873,000
Value of common units issued to acquire ownership interests											81,880,000
Working capital payment (paid in November 2012)											4,763,000
Total consideration paid											$ 181,516,000

XML

Fair Value of Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
Prepaid expenses and other current assets
Derivative assets (liabilities)
Net asset (liability)	$ 43,500
Accrued expenses and other payables
Derivative assets (liabilities)
Net asset (liability)	34,600
Commodity contracts
Derivative assets (liabilities)
Net asset (liability)	8,490	(7,106)
Commodity contracts | Prepaid expenses and other current assets
Derivative assets (liabilities)
Net asset (liability)	50,704	5,551
Commodity contracts | Other noncurrent assets
Derivative assets (liabilities)
Net asset (liability)		44
Commodity contracts | Accrued expenses and other payables
Derivative assets (liabilities)
Net asset (liability)	(42,214)	(12,701)
Recurring | Commodity contracts
Assets:
Derivative Assets	54,595	10,858
Liabilities:
Derivative Liabilities	(46,561)	(16,604)
Netting of counterparty contracts, assets	(4,347)	(3,503)
Netting of counterparty contracts, liabilities	4,347	3,503
Cash collateral provided or held, assets	456	(1,760)
Cash collateral provided or held, liabilities		400
Commodity contracts reported on consolidated balance sheet, assets	50,704	5,595
Commodity contracts reported on consolidated balance sheet, liabilities	(42,214)	(12,701)
Recurring | Level 1 | Commodity contracts
Assets:
Derivative Assets	4,990	947
Liabilities:
Derivative Liabilities	(3,258)	(3,324)
Recurring | Level 2 | Commodity contracts
Assets:
Derivative Assets	49,605	9,911
Liabilities:
Derivative Liabilities	$ (43,303)	$ (13,280)

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Transactions with Affiliates (Details) (USD $)	12 Months Ended		0 Months Ended	12 Months Ended						0 Months Ended
	Mar. 31, 2013 item	Mar. 31, 2014	Jun. 19, 2012 High Sierra Energy, LP	Mar. 31, 2014 Crude oil logistics business owned by an employee	Mar. 31, 2014 SemGroup item	Mar. 31, 2013 SemGroup	Mar. 31, 2012 SemGroup	Mar. 31, 2014 Entities affiliated with management	Mar. 31, 2013 Entities affiliated with management	Jun. 19, 2012 General Partner	Jun. 19, 2012 General Partner High Sierra Energy, LP
Transactions with Affiliates
Right to appoint number of members to the Board of Directors of the entity's general partner by related party					2
Increase in property, plant and equipment								$ 8,200,000
Sales to related party					306,780,000	32,431,000	29,200,000	110,824,000	16,828,000
Purchase from related parties					445,951,000	60,425,000	23,800,000	120,038,000	60,942,000
Receivables from affiliates	22,883,000	7,445,000			7,303,000			142,000	22,883,000
Payables to related parties	6,900,000	76,846,000			76,192,000	4,601,000		654,000	2,299,000
Cash paid	14,000,000		91,800,000	11,000,000							50,000,000
Cash acquired			5,000,000
Common units issued			18,018,468							2,685,042
Liabilities assumed in the form of non-compete agreements			97,400,000
Amount paid										50,000,000
Number of businesses acquired	2
Amount paid to employee for non compete agreement	$ 5,000,000

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Fair Value of Financial Instruments (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Derivative contract information
Fair Value of Net Assets (Liabilities)	$ 8,034	$ (5,746)
Net cash collateral provided (held)	456	(1,360)
Net fair value of commodity derivatives on consolidated balance sheet	8,490	(7,106)
Cross-commodity
Derivative contract information
Total Notional Units (Barrels)	140,000	430,000
Fair Value of Net Assets (Liabilities)	(1,876)	(10,208)
Crude oil fixed-price
Derivative contract information
Total Notional Units (Barrels)	(1,600,000)	(144,000)
Fair Value of Net Assets (Liabilities)	(2,796)	1,033
Crude oil index
Derivative contract information
Total Notional Units (Barrels)	3,598,000	(91,000)
Fair Value of Net Assets (Liabilities)	6,099	153
Propane fixed-price
Derivative contract information
Total Notional Units (Barrels)	60,000	(282,000)
Fair Value of Net Assets (Liabilities)	1,753	3,197
Refined products fixed-price
Derivative contract information
Total Notional Units (Barrels)	732,000
Fair Value of Net Assets (Liabilities)	560
Renewable Products
Derivative contract information
Total Notional Units (Barrels)	106,000
Fair Value of Net Assets (Liabilities)	4,084
Other
Derivative contract information
Total Notional Units (Barrels)		8,000
Fair Value of Net Assets (Liabilities)	1,122	79
Commodity contracts
Derivative contract information
Net gains (losses) on derivatives	(43,655)	(4,381)	5,676
Natural gas fixed-price
Derivative contract information
Fair Value of Net Assets (Liabilities)	$ 210

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Commitments and Contingencies (Details 2) (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Future minimum lease payments
2015	$ 133,170,000
2016	93,454,000
2017	64,209,000
2018	49,802,000
2019	29,213,000
Thereafter	58,182,000
Total	428,030,000
Rental expense	98,300,000	84,200,000	5,200,000
Prepaid expenses and other current assets
Sales and purchase contracts for natural gas liquids and crude oil
Net asset (liability)	43,500,000
Accrued expenses and other payables
Sales and purchase contracts for natural gas liquids and crude oil
Net asset (liability)	34,600,000
Natural gas liquids
Sales and purchase contracts for natural gas liquids and crude oil
Fixed-price purchase commitments (in gallons)	31,111,000
Floating-price purchase commitments (in gallons)	522,947,000
Fixed-price sale commitments (in gallons)	63,944,000
Floating-price sale commitments (in gallons)	272,495,000
Fixed-price purchase commitments	39,117,000
Floating-price purchase commitments	618,293,000
Fixed-price sale commitments	77,682,000
Floating-price sale commitments	395,095,000
Crude oil
Sales and purchase contracts for natural gas liquids and crude oil
Fixed-price purchase commitments (in barrels)	4,016,000
Fixed-price sale commitments (in barrels)	3,564,000
Fixed-price purchase commitments	364,557,000
Fixed-price sale commitments	$ 324,765,000

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Significant Accounting Policies (Tables)

12 Months Ended

Mar. 31, 2014

Significant Accounting Policies

Schedule of supplemental cash flow information

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees	$	31,827	$	27,384	$	4,966
Income taxes paid	$	1,639	$	1,027	$	430

Schedule of accounts receivable

	March 31, 2014				March 31, 2013
					Gross
	Gross		Allowance for		Receivable		Allowance for
Segment	Receivable		Doubtful Accounts		(Note 2)		Doubtful Accounts
	(in thousands)
Crude oil logistics	$	411,090	$	105	$	360,589	$	11
Water solutions	25,700		405		9,618		29
Liquids	192,529		617		144,267		76
Retail propane	75,606		1,667		49,233		1,644
Refined products	105,670		—		—		—
Renewables	54,466		—		—		—
Other	38,665		28		810		—
	$	903,726	$	2,822	$	564,517	$	1,760

Schedule of changes in the allowance for doubtful accounts

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Allowance for doubtful accounts, beginning of period	$	1,760		$	818		$	161
Provision for doubtful accounts	2,172			1,315			1,049
Write off of uncollectible accounts	(1,110		)	(373		)	(392		)
Allowance for doubtful accounts, end of period	$	2,822		$	1,760		$	818

Schedule of inventories

	March 31,
	2014		2013
	(in thousands)
Crude oil	$	156,473	$	46,156
Natural gas liquids —
Propane	85,159		45,428
Butane and other	19,051		24,090
Refined products	23,209		—
Renewables	11,778		—
Other	14,490		11,221
	$	310,160	$	126,895

Schedule of accrued expenses and other payables

	March 31,
			2013
	2014		(Note 4)
	(in thousands)
Accrued compensation and benefits	$	45,006	$	27,252
Derivative liabilities	42,214		12,701
Income and other tax liabilities	13,421		22,659
Product exchange liabilities	3,719		6,741
Other	37,330		16,253
	$	141,690	$	85,606

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Acquisitions (Details 5) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2013 item	Mar. 31, 2014 Retail propane item	Mar. 31, 2014 Retail propane and liquids	Mar. 31, 2014 Natural gas liquids terminals item
Acquisitions
Number of business combination agreements	2	4		4
Cash paid	$ 14,000		$ 21,900

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Significant Accounting Policies (Details 3) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Inventories
Crude oil	$ 156,473	$ 46,156
Natural gas liquids:
Propane	85,159	45,428
Butane and other	19,051	24,090
Refined products	23,209
Renewables	11,778
Other	14,490	11,221
Inventories	$ 310,160	$ 126,895
Consolidated total revenues | Customer concentration risk | Crude oil and natural gas liquids | Largest customer
Concentration of Credit Risk
Percentage of concentration risk	10.00%	10.00%
Consolidated accounts receivable | Customer concentration risk | Crude oil logistics
Concentration of Credit Risk
Number of customers or suppliers		1
Percentage of concentration risk		10.00%

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Equity (Details 4) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Rollforward of the liability related to equity-based compensation
Balance at the beginning of the period	$ 5,043
Expense recorded	17,804	10,138
Value of units vested and issued	(9,085)	(3,627)
Taxes paid on behalf of participants	(3,750)	(1,468)
Balance at the end of the period	10,012	5,043
Maximum number of shares that may be issued as a percentage of outstanding common and subordinated units	10.00%
Incremental amount that the maximum units deliverable may automatically increase under the plan, expressed as a percentage of issued and outstanding common and subordinated units	10.00%
Restricted units
Equity-Based Incentive Compensation
Distributions on restricted units during the vesting period	0
Unvested restricted units at the beginning of the period (in shares)	1,444,900
Units granted (in shares)	494,000	1,684,400
Units vested and issued (in shares)	(296,269)	(156,802)
Units withheld for employee taxes (in shares)	(122,531)	(61,698)
Units forfeited (in shares)	(209,000)	(21,000)
Unvested restricted units at the end of the period (in shares)	1,311,100	1,444,900
Number of awards vested	1,311,100
Estimate of forfeiture of unvested awards	95,000
Closing price (in dollars per share)	$ 37.53
Estimated stock-based compensation expense
2015	14,393
2016	11,279
2017	7,429
2018	2,310
2019	229
Total	$ 35,640
Rollforward of the liability related to equity-based compensation
Weighted-average grant date fair value of the awards (in dollars per share)	$ 33.78
Number of units available for issuance under the Long-Term Incentive Plan	6,200,000
Restricted units | July 1, 2014
Equity-Based Incentive Compensation
Number of awards vested	408,300
Restricted units | January 1, 2015
Equity-Based Incentive Compensation
Number of awards vested	4,000
Restricted units | July 1, 2015
Equity-Based Incentive Compensation
Number of awards vested	341,300
Restricted units | January 1, 2016
Equity-Based Incentive Compensation
Number of awards vested	4,000
Restricted units | July 1, 2016
Equity-Based Incentive Compensation
Number of awards vested	322,500
Restricted units | January 1, 2017
Equity-Based Incentive Compensation
Number of awards vested	4,000
Restricted units | July 1, 2017
Equity-Based Incentive Compensation
Number of awards vested	192,500
Restricted units | January 1, 2018
Equity-Based Incentive Compensation
Number of awards vested	4,000
Restricted units | July 1, 2018
Equity-Based Incentive Compensation
Number of awards vested	30,500

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Mar. 31, 2014

Quarterly Financial Data (Unaudited)

Schedule of summarized unaudited quarterly financial data

	Quarter Ended										Year Ended
	June 30,			September 30,			December 31,		March 31,		March 31,
	2013			2013			2013		2014		2014
	(in thousands, except unit and per unit data)
Total revenues	$	1,385,957		$	1,593,937		$	2,743,445	$	3,975,935	$	9,699,274
Total cost of sales	$	1,303,076		$	1,488,850		$	2,576,029	$	3,764,744	$	9,132,699
Net income (loss)	$	(17,508	)	$	(932	)	$	24,052	$	43,146	$	48,758
Net income (loss) attributable to parent equity	$	(17,633	)	$	(941	)	$	23,898	$	42,331	$	47,655
Earnings (loss) per unit, basic and diluted -
Common units	$	(0.35	)	$	(0.05	)	$	0.27	$	0.46	$	0.51
Subordinated units	$	(0.46	)	$	(0.09	)	$	0.23	$	0.46	$	0.32
Weighted average common units outstanding - basic and diluted	47,703,313			58,909,389			67,941,726		73,421,309		61,970,471
Weighted average subordinated outstanding units - basic and diluted	5,919,346			5,919,346			5,919,346		5,919,346		5,919,346

	Quarter Ended									Year Ended
	June 30,			September 30,		December 31,		March 31,		March 31,
	2012			2012		2012		2013		2013
	(in thousands, except unit and per unit data)
Total revenues	$	326,436		$	1,135,510	$	1,338,208	$	1,617,613	$	4,417,767
Total cost of sales	$	298,985		$	1,053,690	$	1,204,545	$	1,481,890	$	4,039,110
Net income (loss)	$	(24,710	)	$	10,082	$	40,477	$	22,341	$	48,190
Net income (loss) attributable to parent equity	$	(24,650	)	$	10,073	$	40,176	$	22,341	$	47,940
Earnings (loss) per unit, basic and diluted -
Common units	$	(0.76	)	$	0.18	$	0.75	$	0.39	$	0.96
Subordinated units	$	(0.77	)	$	0.18	$	0.75	$	0.39	$	0.93
Weighted average common units outstanding - basic and diluted	26,529,133			44,831,836		46,364,381		47,665,015		41,353,574
Weighted average subordinated outstanding units - basic and diluted	5,919,346			5,919,346		5,919,346		5,919,346		5,919,346

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Acquisitions (Details 7) (USD $)	12 Months Ended				12 Months Ended			12 Months Ended		0 Months Ended	12 Months Ended										12 Months Ended					12 Months Ended					12 Months Ended								12 Months Ended				0 Months Ended
	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Jun. 19, 2012 Crude oil tanks and related equipment	Mar. 31, 2014 Crude oil tanks and related equipment Minimum	Mar. 31, 2014 Crude oil tanks and related equipment Maximum	Nov. 01, 2012 Pecos	Mar. 31, 2014 Pecos	Mar. 31, 2013 Pecos	Mar. 31, 2013 Pecos Estimated at March 31, 2013	Mar. 31, 2014 Pecos Change	Mar. 31, 2014 Pecos Trade names	Mar. 31, 2013 Pecos Trade names Estimated at March 31, 2013	Mar. 31, 2014 Pecos Trade names Change	Mar. 31, 2013 Pecos Customer relationships Estimated at March 31, 2013	Mar. 31, 2014 Pecos Customer relationships Change	Mar. 31, 2014 Pecos Vehicles	Mar. 31, 2014 Pecos Vehicles Minimum	Mar. 31, 2014 Pecos Vehicles Maximum	Mar. 31, 2013 Pecos Vehicles Estimated at March 31, 2013	Mar. 31, 2014 Pecos Vehicles Change	Mar. 31, 2014 Pecos Buildings and leasehold improvements	Mar. 31, 2014 Pecos Buildings and leasehold improvements Minimum	Mar. 31, 2014 Pecos Buildings and leasehold improvements Maximum	Mar. 31, 2013 Pecos Buildings and leasehold improvements Estimated at March 31, 2013	Mar. 31, 2014 Pecos Buildings and leasehold improvements Change	Mar. 31, 2014 Pecos Crude oil tanks and related equipment	Mar. 31, 2014 Pecos Crude oil tanks and related equipment Minimum	Mar. 31, 2014 Pecos Crude oil tanks and related equipment Maximum	Mar. 31, 2013 Pecos Crude oil tanks and related equipment Estimated at March 31, 2013	Mar. 31, 2014 Pecos Crude oil tanks and related equipment Change	Mar. 31, 2014 Pecos Land	Mar. 31, 2013 Pecos Land Estimated at March 31, 2013	Mar. 31, 2014 Pecos Land Change	Mar. 31, 2014 Pecos Other	Mar. 31, 2014 Pecos Other Minimum	Mar. 31, 2014 Pecos Other Maximum	Mar. 31, 2013 Pecos Other Estimated at March 31, 2013	Mar. 31, 2014 Pecos Other Change	Nov. 12, 2012 Pecos Common units	Nov. 01, 2012 Pecos Common units Minimum	Nov. 01, 2012 Pecos Common units Maximum
Acquisitions
Amount of additional consideration payable										$ 10,200,000
Number of common units issued to acquire business (in shares)																																											1,834,414
General and administrative expense												600,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade											73,609,000		73,704,000	(95,000)
Inventories											1,903,000		1,903,000
Prepaid expenses and other current assets											1,426,000		1,426,000
Property, plant and equipment							17,851,000													22,097,000			19,193,000	2,904,000	1,339,000			1,248,000	91,000	1,099,000			913,000	186,000	223,000	224,000	(1,000)	36,000			177,000	(141,000)
Useful life of property, plant and equipment					3 years	40 years		2 years	40 years												5 years	10 years				5 years	30 years				2 years	15 years							3 years	5 years
Intangible assets															900,000	1,000,000	(100,000)	8,000,000	(8,000,000)
Goodwill	555,220,000	1,107,006,000	167,245,000	8,568,000							91,747,000		86,661,000	5,086,000
Accounts payable - trade											(50,795,000)		(50,808,000)	13,000
Accrued expenses and other payables											(963,000)		(1,020,000)	57,000
Long-term debt											(10,234,000)		(10,234,000)
Fair value of net assets acquired											132,387,000		132,387,000
Consideration paid for acquisition
Cash paid, net of cash acquired	14,000,000										87,444,000
Value of common units issued											44,943,000																																45,000,000	45,000,000	60,000,000
Total consideration paid											$ 132,387,000

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Long-Term Obligations (Details) (USD $)			12 Months Ended																12 Months Ended				12 Months Ended	0 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2014 Revolving Credit Facility	Mar. 31, 2014 Revolving Credit Facility Minimum	Mar. 31, 2014 Revolving Credit Facility Maximum	Mar. 31, 2014 Revolving Credit Facility Alternate base rate	Mar. 31, 2014 Revolving Credit Facility Alternate base rate Minimum	Mar. 31, 2014 Revolving Credit Facility Alternate base rate Maximum	Mar. 31, 2014 Revolving Credit Facility LIBOR rate	Mar. 31, 2014 Revolving Credit Facility LIBOR rate Minimum	Mar. 31, 2014 Revolving Credit Facility LIBOR rate Maximum	Mar. 31, 2014 Revolving Credit Facility Expansion Capital Facility	Mar. 31, 2013 Revolving Credit Facility Expansion Capital Facility	Mar. 31, 2014 Revolving Credit Facility Expansion Capital Facility LIBOR rate	Mar. 31, 2014 Revolving Credit Facility Working Capital Facility	Mar. 31, 2013 Revolving Credit Facility Working Capital Facility	Mar. 31, 2014 Revolving Credit Facility Working Capital Facility Alternate base rate	Mar. 31, 2014 Revolving Credit Facility Working Capital Facility LIBOR rate	Mar. 31, 2014 Revolving Credit Facility Letters of credit	Mar. 31, 2014 Senior Notes	Mar. 31, 2013 Senior Notes	Jun. 19, 2012 Senior Notes	Mar. 31, 2014 Senior Notes Minimum	Oct. 16, 2013 Unsecured Notes	Mar. 31, 2014 Unsecured Notes	Mar. 31, 2014 Other notes payable	Mar. 31, 2013 Other notes payable	Mar. 31, 2014 Other notes payable Minimum	Mar. 31, 2014 Other notes payable Maximum
Long-Term Debt
Total debt	$ 1,636,914,000	$ 749,062,000										$ 532,500,000	$ 441,500,000		$ 389,500,000	$ 36,000,000				$ 250,000,000	$ 250,000,000				$ 450,000,000	$ 14,914,000	$ 21,562,000
Less - current maturities	7,080,000	8,626,000
Long-term debt	1,629,834,000	740,436,000
Maximum borrowing capacity												785,500,000			935,500,000
Outstanding cash borrowings			922,000,000									532,500,000		532,500,000	389,500,000		31,500,000	358,000,000
Outstanding letters of credit															270,600,000
Variable interest rate base						base rate			LIBOR
Interest rate margin added to variable rate base (as a percent)							0.50%	1.50%	0.16%	1.50%	2.50%
Reference rate (as a percent)									1.75%										1.75%
Commitment fees charged on unused credit (as a percent)				0.38%	0.50%
Fixed interest rate (as a percent)																				6.65%				6.875%
Debt covenant terms, default trigger amount																							10,000,000
Percentage of aggregate principal amount held by trustee or holders to declare notes due and payable																							51.00%
Leverage ratio					4.25
Actual leverage ratio			3
Interest coverage ratio				2.75
Actual interest coverage ratio			7
Debt issued																						250,000,000		450,000,000
Repayments in semi-annual installments																				25,000,000
Interest rate (as a percent)			1.98%						1.91%					1.91%			4.00%	1.91%										2.10%	4.90%
Net proceeds after underwriting fees and estimated offering costs																								438,400,000
Initial purchase discount																								10,100,000
Estimated offering costs																								$ 1,500,000

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Acquisitions (Details 16) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2013 item	Mar. 31, 2012 Three separate acquisitions item
Acquisitions
Number of business combination agreements	2	3
Cash paid to acquire ownership interests	$ 14,000	$ 6,400
Long-term debt assumed		$ 600

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Acquisitions (Details 2) (USD $)	3 Months Ended								12 Months Ended				12 Months Ended						0 Months Ended	12 Months Ended					12 Months Ended			12 Months Ended			12 Months Ended			12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Water treatment facilities and equipment Minimum	Mar. 31, 2014 Water treatment facilities and equipment Maximum	Mar. 31, 2014 Vehicles Minimum	Mar. 31, 2014 Vehicles Maximum	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Aug. 02, 2013 Oilfield Water Lines LP	Mar. 31, 2014 Oilfield Water Lines LP	Mar. 31, 2014 Oilfield Water Lines LP Customer relationships	Mar. 31, 2014 Oilfield Water Lines LP Non-compete agreements	Mar. 31, 2014 Oilfield Water Lines LP Land	Mar. 31, 2014 Oilfield Water Lines LP Water treatment facilities and equipment	Mar. 31, 2014 Oilfield Water Lines LP Water treatment facilities and equipment Minimum	Mar. 31, 2014 Oilfield Water Lines LP Water treatment facilities and equipment Maximum	Mar. 31, 2014 Oilfield Water Lines LP Vehicles	Mar. 31, 2014 Oilfield Water Lines LP Vehicles Minimum	Mar. 31, 2014 Oilfield Water Lines LP Vehicles Maximum	Mar. 31, 2014 Oilfield Water Lines LP Buildings and leasehold improvements	Mar. 31, 2014 Oilfield Water Lines LP Buildings and leasehold improvements Minimum	Mar. 31, 2014 Oilfield Water Lines LP Buildings and leasehold improvements Maximum	Mar. 31, 2014 Oilfield Water Lines LP Other	Mar. 31, 2014 Oilfield Water Lines LP Other Minimum	Mar. 31, 2014 Oilfield Water Lines LP Other Maximum
Acquisitions
Number of common units issued to acquire business (in shares)																			2,463,287	2,463,287
Period of performance targets as basis for contingent consideration																				6 months
Potential increase in the purchase price																				$ 0
General and administrative expense																				800,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade																				7,268,000
Inventories																				154,000
Prepaid expenses and other current assets																				402,000
Property, plant and equipment																							710,000	23,173,000			8,157,000			2,198,000			53,000
Useful life of property, plant and equipment													3 years	30 years	3 years	25 years	3 years	40 years							3 years	30 years		5 years	10 years		7 years	30 years		3 years	5 years
Intangible assets																					110,000,000	2,000,000
Useful life of intangible assets																					10 years	2 years 6 months
Goodwill	1,107,006,000				555,220,000				1,107,006,000	555,220,000	167,245,000	8,568,000								89,699,000
Accounts payable - trade																				(6,469,000)
Accrued expenses and other payables																				(992,000)
Other noncurrent liabilities																				(64,000)
Fair value of net assets acquired																				236,289,000
Consideration paid for acquisition
Cash paid, net of cash acquired										14,000,000										167,732,000
Value of common units issued																				68,557,000
Total consideration paid																				236,289,000
Revenue, Net	3,975,935,000	2,743,445,000	1,593,937,000	1,385,957,000	1,617,613,000	1,338,208,000	1,135,510,000	326,436,000	9,699,274,000	4,417,767,000	1,310,473,000									26,200,000
Operating income									$ 106,565,000	$ 87,307,000	$ 15,030,000									$ 900,000

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Significant Accounting Policies

12 Months Ended

Mar. 31, 2014

Significant Accounting Policies

Significant Accounting Policies

Note 2 — Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include the accounts of the Partnership and its controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation.

We have made certain reclassifications to the prior period financial statements to conform with classification methods used in fiscal 2014. These reclassifications had no impact on previously-reported amounts of equity or net income. In addition, certain balances at March 31, 2013 were adjusted to reflect the final acquisition accounting for certain business combinations.

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amount of revenues and expenses during the period.

Critical estimates we make in the preparation of our consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations; the collectability of accounts receivable; the recoverability of inventories; useful lives and recoverability of property, plant and equipment and amortizable intangible assets; the impairment of goodwill; the fair value of derivative financial investments; and accruals for various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments and assets and liabilities acquired in business combinations. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

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

· Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and 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 and interest rate protection agreements. The majority of our fair value measurements related to our derivative financial instruments were categorized as Level 2 at March 31, 2014 and 2013 (see Note 12). We determine the fair value of all our derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing model 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. We did not have any fair value measurements categorized as Level 3 at March 31, 2014 or 2013.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability.

Derivative Financial Instruments

We record our derivative financial instrument contracts at fair value in the consolidated balance sheets, with changes in the fair value of our commodity derivative instruments included in our consolidated statements of operations in cost of sales. Contracts that qualify for the normal purchase or sale exemption and are designated as such are not accounted for as derivatives at market value and, accordingly, are recorded when the delivery occurs.

We have not designated any financial instruments as hedges for accounting purposes. All mark-to-market gains and losses on commodity derivative instruments that do not qualify as normal purchases or sales, whether cash transactions or non-cash mark-to-market adjustments, are reported within cost of sales in the consolidated statements of operations, regardless of whether the contract is physically or financially settled.

We utilize various commodity derivative financial instrument contracts to help reduce our exposure to variability in future commodity prices. We do not enter such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of the settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from non-performance by suppliers, customers, or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures that we review on an ongoing basis. We monitor market risk through a variety of techniques and attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures.

Revenue Recognition

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, storage, and service revenues at the time the service is performed, and we record tank and other rentals over the term of the lease. Revenues for the wastewater disposal business are recognized upon receipt of the wastewater at our disposal facilities.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included in revenues in the consolidated statements of operations.

We enter into certain contracts whereby we agree to purchase product from a counterparty and to sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Cost of Sales

We include in cost of sales all costs we incur to acquire products, including the costs of purchasing, terminaling, and transporting inventory prior to delivery to our customers. Cost of sales does not include any depreciation of our property, plant and equipment. Cost of sales does include amortization of certain contract-based intangible assets of $6.2 million, $5.3 million, and $0.8 million during the years ended March 31, 2014, 2013, and 2012, respectively.

Depreciation and Amortization

Depreciation and amortization in the consolidated statements of operations includes all depreciation of our property, plant and equipment and amortization of intangible assets other than debt issuance costs, for which the amortization is recorded to interest expense, and certain contract-based intangible assets, for which the amortization is recorded to cost of sales.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase. At times, certain account balances may exceed federally insured limits.

Supplemental cash flow information is as follows:

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees	$	31,827	$	27,384	$	4,966
Income taxes paid	$	1,639	$	1,027	$	430

Cash flows from commodity derivative instruments are classified as cash flows from investing activities in the consolidated statements of cash flows.

Accounts Receivable and Concentration of Credit Risk

We operate in the United States and Canada. We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each customer’s creditworthiness as well as general economic conditions. The allowance for doubtful accounts is based on our assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. Accounts receivable are considered past due or delinquent based on contractual terms. We write off accounts receivable against the allowance for doubtful accounts when collection efforts have been exhausted.

We execute netting agreements with certain customers to mitigate our credit risk. Receivables and payables are reflected at a net balance to the extent a netting agreement is in place and we intend to settle on a net basis.

Our accounts receivable consist of the following:

	March 31, 2014				March 31, 2013
					Gross
	Gross		Allowance for		Receivable		Allowance for
Segment	Receivable		Doubtful Accounts		(Note 2)		Doubtful Accounts
	(in thousands)
Crude oil logistics	$	411,090	$	105	$	360,589	$	11
Water solutions	25,700		405		9,618		29
Liquids	192,529		617		144,267		76
Retail propane	75,606		1,667		49,233		1,644
Refined products	105,670		—		—		—
Renewables	54,466		—		—		—
Other	38,665		28		810		—
	$	903,726	$	2,822	$	564,517	$	1,760

Changes in the allowance for doubtful accounts are as follows:

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Allowance for doubtful accounts, beginning of period	$	1,760		$	818		$	161
Provision for doubtful accounts	2,172			1,315			1,049
Write off of uncollectible accounts	(1,110		)	(373		)	(392		)
Allowance for doubtful accounts, end of period	$	2,822		$	1,760		$	818

For the year ended March 31, 2014, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. At March 31, 2013, one customer of our crude oil logistics segment represented 10% of our consolidated accounts receivable balance.

Inventories

We value our inventory at the lower of cost or market, with cost determined using either the weighted average cost or the first in, first out (FIFO) methods, including the cost of transportation. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business for sale in the retail markets.

Inventories consist of the following:

	March 31,
	2014		2013
	(in thousands)
Crude oil	$	156,473	$	46,156
Natural gas liquids —
Propane	85,159		45,428
Butane and other	19,051		24,090
Refined products	23,209		—
Renewables	11,778		—
Other	14,490		11,221
	$	310,160	$	126,895

Investments in Unconsolidated Entities

As part of the December 2013 acquisition of Gavilon Energy, we acquired a 50% interest in Glass Mountain and an 11% interest in a limited liability company that owns an ethanol production facility. We account for these investments under the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our consolidated balance sheet; instead, our ownership interests are reported within “Investments in Unconsolidated Entities” on our consolidated balance sheet. We record our share of any income or loss generated by these entities as an increase to our equity method investments, and record any distributions we receive from these entities as reductions to our equity method investments.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following:

	March 31,
			2013
	2014		(Note 4)
	(in thousands)
Accrued compensation and benefits	$	45,006	$	27,252
Derivative liabilities	42,214		12,701
Income and other tax liabilities	13,421		22,659
Product exchange liabilities	3,719		6,741
Other	37,330		16,253
	$	141,690	$	85,606

Property, Plant and Equipment

We record property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. As we dispose of assets, we remove the cost and related accumulated depreciation from the accounts, and any resulting gain or loss is included in other income. We compute depreciation expense using the straight-line method over the estimated useful lives of the assets (see Note 5).

We evaluate the carrying value of our property, plant and equipment for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group.

Intangible Assets

Our intangible assets include contracts and arrangements acquired in business combinations, including lease agreements, customer relationships, covenants not to compete, and trade names. In addition, we capitalize certain debt issuance costs incurred in our long-term debt arrangements. We amortize our intangible assets on a straight-line basis over the assets’ estimated useful lives (see Note 7). We amortize debt issuance costs over the terms of the related debt on a method that approximates the effective interest method.

We evaluate the carrying value of our amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group. When we cease to use an acquired trade name, we test the trade name for impairment using the “relief from royalty” method and we begin amortizing the trade name over its estimated useful life as a defensive asset.

Goodwill

Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Business combinations are accounted for using the “acquisition method” (see Note 4). We expect that substantially all of our goodwill at March 31, 2014 is deductible for income tax purposes.

Goodwill and intangible assets determined to have an indefinite useful life are not amortized, but instead are evaluated for impairment periodically. We evaluate goodwill and indefinite-lived intangible assets for impairment annually, or more often if events or circumstances indicate that the assets might be impaired. We perform the annual evaluation at January 1 of each year.

To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. If we conclude that it is more likely than not that the fair value of a reporting unit exceeds its carrying amount, we perform the following two-step goodwill impairment test:

· 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.

Estimates and assumptions used to perform the impairment evaluation are inherently uncertain and can significantly affect the outcome of the analysis. The estimates and assumptions we used in the annual assessment for impairment of goodwill included market participant considerations and future forecasted operating results. Changes in operating results and other assumptions could materially affect these estimates. Based on our assessment of qualitative factors, we determined that the two-step impairment test was not required. Accordingly, we did not record any goodwill impairments during the years ended March 31, 2014, 2013, and 2012.

Product Exchanges

Quantities of products receivable or returnable under exchange agreements are reported within prepaid expenses and other current assets or within accrued expenses and other payables on the consolidated balance sheets. We estimate the value of product exchange assets and liabilities based on the weighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus or minus location differentials.

Advance Payments Received from Customers

We record customer advances on product purchases as a liability on the consolidated balance sheets.

Noncontrolling Interests

We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated statements of operations represents the other owners’ share of the net income (loss) of these entities.

Water Facility Development Agreement

In connection with one of our business combinations, we entered into a development agreement whereby we may acquire additional water disposal facilities in Texas. Under this agreement, the other party (the “Developer”) may develop facilities in a designated area. We then have the option to operate the facility for a period of up to 90 days, during which time we may elect to purchase the facility. If we elect to purchase the facility, the Developer may choose one of two options specified in the agreement for the calculation of the purchase price.

During the period between which we have begun operating the facility and we have decided whether to purchase the facility, we are entitled to a fee for operating the facility, which is forfeitable if we elect not to purchase the facility. We recognize revenue for these operator fees once they cease to be forfeitable. When we elect to purchase a facility, we account for the transaction as a business combination.

Business Combination Measurement Period

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination. As described in Note 4, certain of our acquisitions during the year ended March 31, 2014 are still within this measurement period, and as a result, the acquisition-date fair values we have recorded for the acquired assets and assumed liabilities are subject to change.

Also as described in Note 4, we made certain adjustments during the year ended March 31, 2014 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2013. We retrospectively adjusted the March 31, 2013 consolidated balance sheet for these adjustments. Due to the immateriality of these adjustments, we did not retrospectively adjust the consolidated statement of operations for the year ended March 31, 2013 for these measurement period adjustments.

Discontinued Operations

In April 2014, the Financial Accounting Standards Board issued an Accounting Standards Update that changes the criteria for reporting discontinued operations. Under the new standard, a disposal of part of an entity is not classified as a discontinued operation unless the disposal represents a strategic shift that will have a major effect on an entity’s operations and financial results. We adopted the new standard during the fiscal year ended March 31, 2014.

As described in Note 14, during the year ended March 31, 2014, we sold our compressor leasing business and wound down our natural gas marketing business. These actions do not represent a strategic shift that had a major effect on our operations, and do not meet the criteria under the new accounting standard for these businesses to be reported as discontinued operations.

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Property, Plant and Equipment (Details) (USD $)	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Property, Plant and Equipment
Property, plant and equipment, gross	$ 938,910,000	$ 576,564,000
Less: Accumulated depreciation	(109,564,000)	(50,127,000)
Net property, plant and equipment	829,346,000	526,437,000
Depreciation expense	59,900,000	39,200,000	10,600,000
Interest expense capitalized	700,000
Natural gas liquids terminal assets
Property, Plant and Equipment
Property, plant and equipment, gross	75,141,000	63,637,000
Natural gas liquids terminal assets | Minimum
Property, Plant and Equipment
Useful life	2 years
Natural gas liquids terminal assets | Maximum
Property, Plant and Equipment
Useful life	30 years
Retail propane equipment
Property, Plant and Equipment
Property, plant and equipment, gross	160,758,000	152,802,000
Retail propane equipment | Minimum
Property, Plant and Equipment
Useful life	2 years
Retail propane equipment | Maximum
Property, Plant and Equipment
Useful life	30 years
Vehicles
Property, Plant and Equipment
Property, plant and equipment, gross	152,676,000	88,173,000
Vehicles | Minimum
Property, Plant and Equipment
Useful life	3 years
Vehicles | Maximum
Property, Plant and Equipment
Useful life	25 years
Water treatment facilities and equipment
Property, Plant and Equipment
Property, plant and equipment, gross	180,985,000	91,944,000
Water treatment facilities and equipment | Minimum
Property, Plant and Equipment
Useful life	3 years
Water treatment facilities and equipment | Maximum
Property, Plant and Equipment
Useful life	30 years
Crude oil tanks and related equipment
Property, Plant and Equipment
Property, plant and equipment, gross	106,125,000	22,577,000
Crude oil tanks and related equipment | Minimum
Property, Plant and Equipment
Useful life	2 years
Crude oil tanks and related equipment | Maximum
Property, Plant and Equipment
Useful life	40 years
Barges and towboats
Property, Plant and Equipment
Property, plant and equipment, gross	52,217,000	25,963,000
Barges and towboats | Minimum
Property, Plant and Equipment
Useful life	5 years
Barges and towboats | Maximum
Property, Plant and Equipment
Useful life	40 years
Information technology equipment
Property, Plant and Equipment
Property, plant and equipment, gross	20,768,000	12,169,000
Information technology equipment | Minimum
Property, Plant and Equipment
Useful life	3 years
Information technology equipment | Maximum
Property, Plant and Equipment
Useful life	7 years
Buildings and leasehold improvements
Property, Plant and Equipment
Property, plant and equipment, gross	60,004,000	48,975,000
Buildings and leasehold improvements | Minimum
Property, Plant and Equipment
Useful life	3 years
Buildings and leasehold improvements | Maximum
Property, Plant and Equipment
Useful life	40 years
Land
Property, Plant and Equipment
Property, plant and equipment, gross	30,241,000	21,815,000
Linefill and tank bottoms
Property, Plant and Equipment
Property, plant and equipment, gross	13,403,000
Other
Property, Plant and Equipment
Property, plant and equipment, gross	6,341,000	16,104,000
Other | Minimum
Property, Plant and Equipment
Useful life	5 years
Other | Maximum
Property, Plant and Equipment
Useful life	30 years
Construction in progress
Property, Plant and Equipment
Property, plant and equipment, gross	$ 80,251,000	$ 32,405,000

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Significant Accounting Policies (Details 4) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Dec. 02, 2013 Gavilon Energy Glass Mountain	Dec. 02, 2013 Gavilon Energy Limited liability company
Investments in Unconsolidated Entities
Equity method ownership interest (as a percent)	50.00%		50.00%	11.00%
Accrued Expenses and Other Payables
Accrued compensation and benefits	$ 45,006	$ 27,252
Derivative liabilities	42,214	12,701
Income and other tax liabilities	13,421	22,659
Product exchange liabilities	3,719	6,741
Other	37,330	16,253
Total accrued expenses and other payables	$ 141,690	$ 85,606

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Goodwill (Tables)

12 Months Ended

Mar. 31, 2014

Goodwill

Schedule of changes in the balance of goodwill

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Beginning of period, as retrospectively adjusted (Note 2)	$	555,220	$	167,245	$	8,568
Acquisitions	551,786		387,975		158,677
End of period, as retrospectively adjusted (Note 2)	$	1,107,006	$	555,220	$	167,245

Schedule of goodwill by reportable segment, including changes to goodwill

	March 31,
	2014		2013
	(in thousands)
Crude oil logistics	$	606,383	$	246,345
Water solutions	262,203		109,470
Liquids	90,135		87,136
Retail propane	114,285		112,269
Refined products	22,000		—
Renewables	12,000		—
	$	1,107,006	$	555,220

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Property, Plant and Equipment (Tables)

12 Months Ended

Mar. 31, 2014

Property, Plant and Equipment

Schedule of property, plant and equipment

	March 31,
				2013
Description and Estimated Useful Lives	2014			(Note 2)
	(in thousands)
Natural gas liquids terminal assets (2—30 years)	$	75,141		$	63,637
Retail propane equipment (2—30 years)	160,758			152,802
Vehicles (3—25 years)	152,676			88,173
Water treatment facilities and equipment (3—30 years)	180,985			91,944
Crude oil tanks and related equipment (2—40 years)	106,125			22,577
Barges and towboats (5—40 years)	52,217			25,963
Information technology equipment (3—7 years)	20,768			12,169
Buildings and leasehold improvements (3—40 years)	60,004			48,975
Land	30,241			21,815
Linefill and tank bottoms	13,403			—
Other (5—30 years)	6,341			16,104
Construction in progress	80,251			32,405
	938,910			576,564
Less: Accumulated depreciation	(109,564		)	(50,127		)
Net property, plant and equipment	$	829,346		$	526,437

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Acquisitions (Details 11) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
High Sierra, Pecos, Third Coast, OWL and Gavilon Energy acquisitions
Pro Forma Results of Operations
Revenues	$ 9,800,398	$ 5,697,988
Net income (loss)	798	(72,171)
High Sierra, Pecos, Third Coast, OWL and Gavilon Energy acquisitions | Common units
Pro Forma Results of Operations
Basic loss per unit (in dollars per share)	$ (0.18)	$ (0.95)
Diluted loss per unit (in dollars per share)	$ (0.18)	$ (0.95)
High Sierra, Pecos, Third Coast, OWL and Gavilon Energy acquisitions | Subordinated units
Pro Forma Results of Operations
Basic loss per unit (in dollars per share)	$ (0.18)	$ (0.95)
Diluted loss per unit (in dollars per share)	$ (0.18)	$ (0.95)
High Sierra, Pecos, Third Coast, OWL and Gavilon Energy acquisitions | Limited Partners
Pro Forma Results of Operations
Net income (loss)	(14,446)	(75,251)
OWL
Pro Forma Results of Operations
Expense related to retirement of liability		$ 4,800

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Significant Accounting Policies (Details 5) (Water facility development agreement)	12 Months Ended
	Mar. 31, 2014 item
Water facility development agreement
Water facility development agreement
Maximum period for which the option is available to operate the facility	90 days
Number of options specified in the agreement for the calculation of the purchase price	2

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Intangible Assets (Tables)

12 Months Ended

Mar. 31, 2014

Intangible Assets

Schedule of intangible assets

		March 31, 2014				March 31, 2013
						Gross Carrying
	Amortizable	Gross Carrying		Accumulated		Amount		Accumulated
	Lives	Amount		Amortization		(Note 2)		Amortization
				(in thousands)
Amortizable -
Customer relationships (1)	3–20 years	$	697,405	$	83,261	$	405,160	$	30,959
Water facility development agreement	5 years	14,000		2,100		—		—
Lease and other agreements	5–8 years	23,920		13,190		15,210		7,018
Non-compete agreements	2–7 years	14,161		6,388		11,509		2,871
Trade names	1–10 years	15,489		3,081		2,784		326
Debt issuance costs	5–10 years	44,089		8,708		19,494		2,981
Total amortizable		809,064		116,728		454,157		44,155
Non-amortizable -
Trade names		22,620				31,430
Total		$	831,684	$	116,728	$	485,587	$	44,155

(1) The weighted-average remaining amortization period for customer relationship intangible assets is approximately nine years.

Schedule of amortization expense

	Year Ended March 31,
Recorded in	2014		2013		2012
	(in thousands)
Depreciation and amortization	$	60,855	$	29,657	$	4,538
Cost of sales	6,172		5,285		800
Interest expense	5,727		3,375		1,277
Loss on early extinguishment of debt	—		5,769		—
	$	72,754	$	44,086	$	6,615

Schedule of expected amortization of intangible assets

Expected amortization of our intangible assets is as follows (in thousands):

Year Ending March 31,
2015	$	88,970
2016	83,449
2017	76,826
2018	72,857
2019	66,826
Thereafter	303,408
	$	692,336

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Long-Term Obligations (Tables)

12 Months Ended

Mar. 31, 2014

Long-Term Obligations

Schedule of long-term debt

	March 31,
	2014		2013
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	532,500	$	441,500
Working capital loans	389,500		36,000
Senior notes	250,000		250,000
Unsecured notes	450,000		—
Other notes payable	14,914		21,562
	1,636,914		749,062
Less - current maturities	7,080		8,626
Long-term debt	$	1,629,834	$	740,436

Schedule of outstanding borrowings and interest rates under Revolving Credit Facility

At March 31, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	532,500	1.91	%
Working capital facility —
LIBOR borrowings	358,000		1.91	%
Base rate borrowings	31,500		4.00	%

Schedule of maturities of long-term debt

	Revolving						Other
	Credit		Senior		Unsecured		Notes
Year Ending March 31,	Facility		Notes		Notes		Payable		Total
					(in thousands)
2015	$	—	$	—	$	—	$	7,081	$	7,081
2016	—		—		—		3,614		3,614
2017	—		—		—		2,356		2,356
2018	—		25,000		—		1,449		26,449
2019	922,000		50,000		—		238		972,238
Thereafter	—		175,000		450,000		176		625,176
	$	922,000	$	250,000	$	450,000	$	14,914	$	1,636,914

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Nature of Operations and Organization

12 Months Ended

Mar. 31, 2014

Nature of Operations and Organization

Nature of Operations and Organization

Note 1 — Nature of Operations and Organization

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in September 2010 by several investors (“IEP Parties”). NGL Energy Holdings LLC serves as our general partner. At March 31, 2014, our operations include:

· A crude oil logistics business, the assets of which include crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

· A water solutions business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons.

· Our liquids business, 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 services through its 22 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids business purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets.

· Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.

We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon, LLC (“Gavilon Energy”).

Initial Public Offering

On May 17, 2011, we completed our initial public offering (“IPO”). We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. Our proceeds from the sale of 3,850,000 common units of $71.9 million, net of total offering costs of $9.0 million, were used to repay advances under our acquisition credit facility and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) from the underwriters’ exercise of their option to purchase additional common units from us were used to redeem 175,000 of the common units outstanding prior to our IPO. Upon the completion of our IPO and the underwriters’ exercise in full of their option to purchase additional common units from us and the redemption, we had outstanding 8,864,222 common units, 5,919,346 subordinated units, a 0.1% general partner interest, and incentive distribution rights (“IDRs”).

Acquisitions Subsequent to Initial Public Offering

Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, including the following, among others:

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

· 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., 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 (“Downeast”). 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.

· In July 2013, we completed a business combination whereby we acquired the assets of Crescent Terminals, LLC and the ownership interests in Cierra Marine, LP and its affiliated companies (collectively, “Crescent”), whereby we acquired four towboats, seven crude oil barges, and a crude oil terminal in South Texas.

· In July 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd. (“Big Lake”), whereby we acquired a water disposal facility in West Texas. We also entered into a development agreement that provides us the option to purchase disposal facilities that may be developed in the future. During March 2014, we purchased one additional facility under this 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 water disposal operations and a water transportation business in Texas.

· In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), in which we acquired the ownership interests in water disposal facilities in Texas and the right to purchase one additional facility, which we exercised in March 2014.

· In December 2013, we acquired the ownership interests in Gavilon Energy. The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana and 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. This pipeline became operational in February 2014. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids.

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Commitments and Contingencies (Tables)

12 Months Ended

Mar. 31, 2014

Commitments and Contingencies

Schedule of future minimum lease payments under contractual commitments

Future minimum lease payments under contractual commitments at March 31, 2014 are as follows (in thousands):

Year Ending March 31,
2015	$	133,170
2016	93,454
2017	64,209
2018	49,802
2019	29,213
Thereafter	58,182
Total	$	428,030

Schedule of commitments outstanding

At March 31, 2014, we had the following such commitments outstanding:

	Volume	Value
	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)	31,111	$	39,117
Natural gas liquids floating-price purchase commitments (gallons)	522,947	618,293
Natural gas liquids fixed-price sale commitments (gallons)	63,944	77,682
Natural gas liquids floating-price sale commitments (gallons)	272,495	395,095
Crude oil fixed-price purchase commitments (barrels)	4,016	364,557
Crude oil fixed-price sale commitments (barrels)	3,574	324,765

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Significant Accounting Policies (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Amortization related to intangible assets
Amortization of contract-based intangible assets	$ 72,754	$ 44,086	$ 6,615
Cost of sales - wholesale supply and marketing
Amortization related to intangible assets
Amortization of contract-based intangible assets	6,172	5,285	800
Cost of sales - wholesale supply and marketing | Contract-based intangibles
Amortization related to intangible assets
Amortization of contract-based intangible assets	$ 6,200	$ 5,300	$ 800

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Acquisitions (Details 8) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended				12 Months Ended								12 Months Ended			12 Months Ended					0 Months Ended
	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Barges and towboats Minimum	Mar. 31, 2014 Barges and towboats Maximum	Mar. 31, 2014 Third Coast	Mar. 31, 2013 Third Coast Estimated at March 31, 2013	Mar. 31, 2014 Third Coast Change	Mar. 31, 2014 Third Coast Trade names	Mar. 31, 2013 Third Coast Trade names Estimated at March 31, 2013	Mar. 31, 2014 Third Coast Trade names Change	Mar. 31, 2014 Third Coast Customer relationships	Mar. 31, 2013 Third Coast Customer relationships Estimated at March 31, 2013	Mar. 31, 2014 Third Coast Customer relationships Change	Mar. 31, 2014 Third Coast Barges and towboats	Mar. 31, 2013 Third Coast Barges and towboats Estimated at March 31, 2013	Mar. 31, 2014 Third Coast Barges and towboats Change	Mar. 31, 2013 Third Coast Other Estimated at March 31, 2013	Mar. 31, 2014 Third Coast Other Change	Jan. 11, 2013 Third Coast Common units	Dec. 31, 2012 Third Coast Common units Minimum	Dec. 31, 2012 Third Coast Common units Maximum
Acquisitions
Number of common units issued to acquire business (in shares)																					344,680
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade							$ 2,195	$ 2,248	$ (53)
Inventories							140	140
Property, plant and equipment																17,711	12,883	4,828	30	(30)
Useful life of property, plant and equipment					5 years	40 years										20 years
Intangible assets										850	500	350	3,000	4,000	(1,000)
Useful life of intangible assets													3 years
Goodwill	555,220	1,107,006	167,245	8,568			18,847	22,551	(3,704)
Other noncurrent assets							2,733	2,733
Accounts payable - trade							(2,429)	(2,048)	(381)
Accrued expenses and other payables							(164)	(154)	(10)
Fair value of net assets acquired							42,883	42,883
Consideration paid for acquisition
Cash paid, net of cash acquired	14,000						35,000
Value of common units issued							7,883														8,000	8,000	10,000
Total consideration paid							$ 42,883

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Equity (Details) (USD $)	0 Months Ended	12 Months Ended
	May 17, 2011	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Partnership equity
General partner, interest (as a percent)	0.10%	0.10%	0.10%
Limited partners, interest (as a percent)		99.90%	99.90%
Initial Public Offering
Proceeds from sale of common units, net of offering costs		$ 650,155,000	$ (642,000)	$ 74,759,000
Common units
Initial Public Offering
Number of units sold in public offering	4,025,000
Price per unit of units sold in initial public offering (in dollars per share)	$ 21.00
Number of units repurchased	175,000
Units outstanding after completion of IPO	8,864,222	73,421,309	47,703,313
Common units | Repayment of advances under acquisition credit facility
Initial Public Offering
Number of units sold in public offering	3,850,000
Proceeds from sale of common units, net of offering costs	71,900,000
Offering costs	9,000,000
Common units | Redemption of common units
Initial Public Offering
Number of units sold in public offering	175,000
Proceeds from sale of common units, net of offering costs	$ 3,400,000
Subordinated units
Partnership Equity
Subordinated units, conversion ratio		1
Initial Public Offering
Units outstanding after completion of IPO	5,919,346	5,919,346	5,919,346

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013
CURRENT ASSETS:
Cash and cash equivalents	$ 10,440	$ 11,561
Accounts receivable - trade, net of allowance for doubtful accounts of $2,822 and $1,760, respectively	900,904	562,757
Accounts receivable - affiliates	7,445	22,883
Inventories	310,160	126,895
Prepaid expenses and other current assets	80,350	37,891
Total current assets	1,309,299	761,987
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $109,564 and $50,127, respectively	829,346	526,437
GOODWILL	1,107,006	555,220
INTANGIBLE ASSETS, net of accumulated amortization of $116,728 and $44,155, respectively	714,956	441,432
INVESTMENTS IN UNCONSOLIDATED ENTITIES	189,821
OTHER NONCURRENT ASSETS	16,795	6,542
Total assets	4,167,223	2,291,618
CURRENT LIABILITIES:
Accounts payable - trade	740,211	536,055
Accounts payable - affiliates	76,846	6,900
Accrued expenses and other payables	141,690	85,606
Advance payments received from customers	29,965	22,372
Current maturities of long-term debt	7,080	8,626
Total current liabilities	995,792	659,559
LONG-TERM DEBT, net of current maturities	1,629,834	740,436
OTHER NONCURRENT LIABILITIES	9,744	2,205
COMMITMENTS AND CONTINGENCIES
EQUITY, per accompanying statement:
General partner, representing a 0.1% interest, 79,420 and 53,676 notional units at March 31, 2014 and 2013, respectively	(45,287)	(50,497)
Limited partners, representing a 99.9% interest -
Accumulated other comprehensive income (loss)	(236)	24
Noncontrolling interests	5,274	5,740
Total equity	1,531,853	889,418
Total liabilities and equity	4,167,223	2,291,618
Common units
Limited partners, representing a 99.9% interest -
Limited partners, representing a 99.9% interest -	1,570,074	920,998
Subordinated units
Limited partners, representing a 99.9% interest -
Limited partners, representing a 99.9% interest -	$ 2,028	$ 13,153

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Earnings per Unit (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Earnings per unit
Income attributable to parent equity	$ 42,331	$ 23,898	$ (941)	$ (17,633)	$ 22,341	$ 40,176	$ 10,073	$ (24,650)	$ 47,655	$ 47,940	$ 7,876
Income allocated to general partner									(14,148)	(2,917)	(8)
NET INCOME ALLOCATED TO LIMITED PARTNERS									33,507	45,023	7,868
Common unitholders
Earnings per unit
NET INCOME ALLOCATED TO LIMITED PARTNERS									31,614	39,517	4,859
Weighted average units outstanding (in shares)	73,421,309	67,941,726	58,909,389	47,703,313	47,665,015	46,364,381	44,831,836	26,529,133	61,970,471	41,353,574	15,169,983
Basic and diluted income (loss) per unit (in dollars per share)									$ 0.51	$ 0.96	$ 0.32
Subordinated unitholders
Earnings per unit
NET INCOME ALLOCATED TO LIMITED PARTNERS									$ 1,893	$ 5,506	$ 3,009
Weighted average units outstanding (in shares)	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,175,384
Basic and diluted income (loss) per unit (in dollars per share)									$ 0.32	$ 0.93	$ 0.58

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Consolidated Statements of Changes in Equity (USD $) In Thousands, except Share data, unless otherwise specified	Total USD ($)	Common units	Accumulated Other Comprehensive Income USD ($)	Noncontrolling Interest USD ($)	General Partner USD ($)	Limited Partners Common units USD ($)	Limited Partners Subordinated units USD ($)
BALANCES at Mar. 31, 2011	$ 47,353		$ 56		$ 72	$ 47,225
BALANCES (in units) at Mar. 31, 2011						10,933,568
Increase (Decrease) in Partnership Capital
Distributions to partners prior to initial public offering	(3,850)				(4)	(3,846)
Conversion of common units to subordinated units						(23,485)	23,485
Conversion of common units to subordinated units (in units)						(5,919,346)	5,919,346
Sales of units, net of issuance costs	75,289					75,289
Sales of units, net of issuance costs (in units)						4,025,000
Repurchase of common units	(3,418)					(3,418)
Repurchase of common units (in units)						(175,000)
Contributions	826			440	386
Units issued in business combinations, net of issuance costs	296,500					296,500
Units issued in business combinations, net of issuance costs (in units)						14,432,031
Net income (loss)	7,864			(12)	8	6,472	1,396
Distribution to partners subsequent to initial public offering	(15,210)				(20)	(10,133)	(5,057)
Other comprehensive loss	(25)		(25)
BALANCES at Mar. 31, 2012	405,329		31	428	442	384,604	19,824
BALANCES (in units) at Mar. 31, 2012						23,296,253	5,919,346
Increase (Decrease) in Partnership Capital
Distributions	(71,682)			(74)	(1,778)	(59,841)	(9,989)
Contributions	913			403	510
Units issued in business combinations, net of issuance costs	503,018			4,733	(52,588)	550,873
Units issued in business combinations, net of issuance costs (in units)						24,250,258
Equity issued pursuant to incentive compensation plan	3,657					3,657
Equity issued pursuant to incentive compensation plan (in units)						156,802
Net income (loss)	48,190			250	2,917	41,705	3,318
Other comprehensive loss	(7)		(7)
BALANCES at Mar. 31, 2013	889,418		24	5,740	(50,497)	920,998	13,153
BALANCES (in units) at Mar. 31, 2013						47,703,313	5,919,346
Increase (Decrease) in Partnership Capital
Sales of units, net of issuance costs	650,155					650,155
Sales of units, net of issuance costs (in units)						22,560,848
Distributions	(145,930)			(840)	(9,703)	(123,467)	(11,920)
Contributions	2,825			2,060	765
Units issued in business combinations, net of issuance costs	80,591					80,591
Units issued in business combinations, net of issuance costs (in units)						2,860,879
Equity issued pursuant to incentive compensation plan	9,085					9,085
Equity issued pursuant to incentive compensation plan (in units)						296,269
Disposal of noncontrolling interest	(2,789)			(2,789)
Net income (loss)	48,758			1,103	14,148	32,712	795
Other comprehensive loss	(260)		(260)
BALANCES at Mar. 31, 2014	$ 1,531,853		$ (236)	$ 5,274	$ (45,287)	$ 1,570,074	$ 2,028
BALANCES (in units) at Mar. 31, 2014						73,421,309	5,919,346

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Acquisitions (Details 14) (USD $)	12 Months Ended				12 Months Ended						0 Months Ended	12 Months Ended		0 Months Ended				0 Months Ended					0 Months Ended
	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Retail propane equipment Minimum	Mar. 31, 2014 Retail propane equipment Maximum	Mar. 31, 2014 Vehicles Minimum	Mar. 31, 2014 Vehicles Maximum	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Jan. 03, 2012 Pacer Propane Holdings, L.P. item	Mar. 31, 2012 Pacer Propane Holdings, L.P.	Jan. 03, 2012 Pacer Propane Holdings, L.P. Trade names	Jan. 03, 2012 Pacer Propane Holdings, L.P. Customer relationships	Jan. 03, 2012 Pacer Propane Holdings, L.P. Non-compete agreements	Jan. 03, 2012 Pacer Propane Holdings, L.P. Land	Jan. 03, 2012 Pacer Propane Holdings, L.P. Retail propane equipment	Jan. 03, 2012 Pacer Propane Holdings, L.P. Retail propane equipment Minimum	Jan. 03, 2012 Pacer Propane Holdings, L.P. Retail propane equipment Maximum	Jan. 03, 2012 Pacer Propane Holdings, L.P. Vehicles	Jan. 03, 2012 Pacer Propane Holdings, L.P. Buildings and leasehold improvements	Jan. 03, 2012 Pacer Propane Holdings, L.P. Other	Jan. 03, 2012 Pacer Propane Holdings, L.P. Other Minimum	Jan. 03, 2012 Pacer Propane Holdings, L.P. Other Maximum	Jan. 03, 2012 Pacer Propane Holdings, L.P. Common units
Acquisitions
Cash paid to acquire ownership interests	$ 14,000,000										$ 32,213,000
Number of common units issued to acquire business (in shares)																									1,500,000
General and administrative expense												700,000
Equity issuance costs												100,000
Number of owned or leased customer service centers											17
Consideration paid for acquisition
Cash paid	14,000,000										32,213,000
Common units																									30,375,000
Total consideration paid											62,588,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade											4,389,000
Inventories											965,000
Prepaid expenses and other current assets											43,000
Property, plant and equipment																1,967,000	12,793,000			3,090,000	409,000	59,000
Useful life of property, plant and equipment					2 years	30 years	3 years	25 years	3 years	40 years								15 years	20 years	5 years	30 years		3 years	5 years
Intangible assets													2,410,000	23,560,000	1,520,000
Useful life of intangible assets														15 years
Goodwill	555,220,000	1,107,006,000	167,245,000	8,568,000							15,782,000
Assumed liabilities											(4,399,000)
Fair value of net assets acquired											$ 62,588,000

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Segments (Tables)

12 Months Ended

Mar. 31, 2014

Segments

Schedule of certain information related to the results of operations of each segment

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Revenues:
Crude oil logistics -
Crude oil sales	$	4,559,923		$	2,322,706		$	—
Crude oil transportation and other	36,469			16,442			—
Water solutions -
Water treatment and disposal	125,788			54,334			—
Water transportation	17,312			7,893			—
Liquids -
Propane sales	1,632,948			841,448			923,022
Other product sales	1,231,965			858,276			251,627
Other revenues	31,062			33,954			2,462
Retail propane -
Propane sales	388,225			288,410			175,417
Distillate sales	127,672			106,192			6,547
Other revenues	35,918			35,856			17,370
Refined products	1,180,895			—			—
Renewables	176,781			—			—
Corporate and other	437,713			4,233			—
Eliminations of intersegment sales	(283,397		)	(151,977		)	(65,972		)
Total revenues	$	9,699,274		$	4,417,767		$	1,310,473

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Depreciation and amortization:
Crude oil logistics	$	22,111	$	9,176	$	—
Water solutions	55,105		20,923		—
Liquids	11,018		11,085		3,661
Retail propane	28,878		25,496		11,450
Refined products	109		—		—
Renewables	516		—		—
Corporate and other	3,017		2,173		—
Total depreciation and amortization	$	120,754	$	68,853	$	15,111

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Operating income (loss):
Crude oil logistics	$	678		$	34,236		$	—
Water solutions	10,317			8,576			—
Liquids	71,888			30,336			9,735
Retail propane	61,285			46,869			9,616
Refined products	4,080			—			—
Renewables	2,434			—			—
Corporate and other	(44,117		)	(32,710		)	(4,321		)
Total operating income	$	106,565		$	87,307		$	15,030

Schedule of additions to property, plant and equipment for each segment

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Additions to property, plant and equipment, including acquisitions (accrual basis):
Crude oil logistics	$	204,642	$	89,860	$	—
Water solutions	100,877		137,116		—
Liquids	52,560		15,129		50,276
Retail propane	24,430		66,933		150,181
Refined products	719		—		—
Renewables	519		—		—
Corporate and other	7,242		17,858		—
Total	$	390,989	$	326,896	$	200,457

Schedule of long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets by segment

	March 31,
			2013
	2014		(Note 2)
	(in thousands)
Total assets:
Crude oil logistics	$	1,723,812	$	801,351
Water solutions	875,714		466,412
Liquids	577,795		474,141
Retail propane	541,832		513,301
Refined products	157,581		—
Renewables	145,649		—
Corporate and other	144,840		36,413
Total	$	4,167,223	$	2,291,618
Long-lived assets, net:
Crude oil logistics	$	980,978	$	357,230
Water solutions	848,479		453,909
Liquids	274,846		238,192
Retail propane	438,324		441,762
Refined products	27,017		—
Renewables	33,703		—
Corporate and other	47,961		31,996
Total	$	2,651,308	$	1,523,089

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Intangible Assets (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Amortizable
Gross Carrying Amount	$ 809,064	$ 454,157
Accumulated Amortization	116,728	44,155
Non-Amortizable
Gross carrying amount of intangible assets	831,684	485,587
Customer relationships
Amortizable
Gross Carrying Amount	697,405	405,160
Accumulated Amortization	83,261	30,959
Useful Lives	9 years
Customer relationships | Minimum
Amortizable
Useful Lives	3 years
Customer relationships | Maximum
Amortizable
Useful Lives	20 years
Water facility development agreement
Amortizable
Gross Carrying Amount	14,000
Accumulated Amortization	2,100
Useful Lives	5 years
Lease and other agreements
Amortizable
Gross Carrying Amount	23,920	15,210
Accumulated Amortization	13,190	7,018
Lease and other agreements | Minimum
Amortizable
Useful Lives	5 years
Lease and other agreements | Maximum
Amortizable
Useful Lives	8 years
Non-compete agreements
Amortizable
Gross Carrying Amount	14,161	11,509
Accumulated Amortization	6,388	2,871
Non-compete agreements | Minimum
Amortizable
Useful Lives	2 years
Non-compete agreements | Maximum
Amortizable
Useful Lives	7 years
Trade names
Amortizable
Gross Carrying Amount	15,489	2,784
Accumulated Amortization	3,081	326
Non-Amortizable
Gross Carrying Amount	22,620	31,430
Trade names | Minimum
Amortizable
Useful Lives	1 year
Trade names | Maximum
Amortizable
Useful Lives	10 years
Debt issuance costs
Amortizable
Gross Carrying Amount	44,089	19,494
Accumulated Amortization	$ 8,708	$ 2,981
Debt issuance costs | Minimum
Amortizable
Useful Lives	5 years
Debt issuance costs | Maximum
Amortizable
Useful Lives	10 years

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Transactions with Affiliates

12 Months Ended

Mar. 31, 2014

Transactions with Affiliates

Transactions with Affiliates

Note 15 — Transactions with Affiliates

Since our business combination with SemStream on November 1, 2011, SemGroup Corporation (“SemGroup”) has held ownership interests in us and in our general partner, and has the right to appoint two members to the board of directors of our general partner. Subsequent to November 1, 2011, we have sold product to and purchased product from affiliates of SemGroup. These transactions are included within revenues and cost of sales in our consolidated statements of operations.

Certain members of our management own interests in entities with which we have purchased products and services from and have sold products and services. The majority of these purchases represent crude oil purchases and are reported within cost of sales in our consolidated statements of operations, although $8.2 million of these transactions during the year ended March 31, 2014 represented capital expenditures and were recorded as increases to property, plant and equipment. The majority of these sales represent sales of crude oil and have been recorded within revenues in our consolidated statement of operations.

These transactions are summarized in the table below:

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Sales to SemGroup	$	306,780	$	32,431	$	29,200
Purchases from SemGroup	445,951		60,425		23,800
Sales to entities affiliated with management	110,824		16,828		—
Purchases from entities affiliated with management	120,038		60,942		—

Receivables from affiliates consist of the following:

	March 31,
	2014		2013
	(in thousands)
Receivables from entities affiliated with management	$	142	$	22,883
Receivables from SemGroup	7,303		—
	$	7,445	$	22,883

Payables to affiliates consist of the following:

	March 31,
	2014		2013
	(in thousands)
Payables to SemGroup	$	76,192	$	4,601
Payables to entities affiliated with management	654		2,299
	$	76,846	$	6,900

We completed a merger with High Sierra Energy, LP and High Sierra Energy GP, LLC in June 2012. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner.

During the year ended March 31, 2014, we completed the acquisition of a crude oil logistics business owned by an employee. We paid $11.0 million of cash for this acquisition. During the year ended March 31, 2013, we completed two business combinations with entities in which members of our management owned interests. We paid $14.0 million of cash (net of cash acquired) on a combined basis for these two acquisitions. We also paid $5.0 million under a non-compete agreement to an employee.

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Transactions with Affiliates (Tables)

12 Months Ended

Mar. 31, 2014

Transactions with Affiliates

Summary of purchase and sales transactions of products and services

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Sales to SemGroup	$	306,780	$	32,431	$	29,200
Purchases from SemGroup	445,951		60,425		23,800
Sales to entities affiliated with management	110,824		16,828		—
Purchases from entities affiliated with management	120,038		60,942		—

Schedule of receivables from affiliates

	March 31,
	2014		2013
	(in thousands)
Receivables from entities affiliated with management	$	142	$	22,883
Receivables from SemGroup	7,303		—
	$	7,445	$	22,883

Schedule of payables to affiliates

	March 31,
	2014		2013
	(in thousands)
Payables to SemGroup	$	76,192	$	4,601
Payables to entities affiliated with management	654		2,299
	$	76,846	$	6,900

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Significant Accounting Policies (Policies)

12 Months Ended

Mar. 31, 2014

Significant Accounting Policies

Basis of Presentation

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The accompanying consolidated financial statements include the accounts of the Partnership and its controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation.

We have made certain reclassifications to the prior period financial statements to conform with classification methods used in fiscal 2014. These reclassifications had no impact on previously-reported amounts of equity or net income. In addition, certain balances at March 31, 2013 were adjusted to reflect the final acquisition accounting for certain business combinations.

Use of Estimates

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amount of revenues and expenses during the period.

Critical estimates we make in the preparation of our consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations; the collectability of accounts receivable; the recoverability of inventories; useful lives and recoverability of property, plant and equipment and amortizable intangible assets; the impairment of goodwill; the fair value of derivative financial investments; and accruals for various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Fair Value Measurements

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments and assets and liabilities acquired in business combinations. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

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

· Level 2 — Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and 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 and interest rate protection agreements. The majority of our fair value measurements related to our derivative financial instruments were categorized as Level 2 at March 31, 2014 and 2013 (see Note 12). We determine the fair value of all our derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing model 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. We did not have any fair value measurements categorized as Level 3 at March 31, 2014 or 2013.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability.

Derivative Financial Instruments

Derivative Financial Instruments

We record our derivative financial instrument contracts at fair value in the consolidated balance sheets, with changes in the fair value of our commodity derivative instruments included in our consolidated statements of operations in cost of sales. Contracts that qualify for the normal purchase or sale exemption and are designated as such are not accounted for as derivatives at market value and, accordingly, are recorded when the delivery occurs.

We have not designated any financial instruments as hedges for accounting purposes. All mark-to-market gains and losses on commodity derivative instruments that do not qualify as normal purchases or sales, whether cash transactions or non-cash mark-to-market adjustments, are reported within cost of sales in the consolidated statements of operations, regardless of whether the contract is physically or financially settled.

We utilize various commodity derivative financial instrument contracts to help reduce our exposure to variability in future commodity prices. We do not enter such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of the settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from non-performance by suppliers, customers, or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures that we review on an ongoing basis. We monitor market risk through a variety of techniques and attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures.

Revenue Recognition

Revenue Recognition

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, storage, and service revenues at the time the service is performed, and we record tank and other rentals over the term of the lease. Revenues for the wastewater disposal business are recognized upon receipt of the wastewater at our disposal facilities.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. Amounts billed to customers for shipping and handling costs are included in revenues in the consolidated statements of operations.

We enter into certain contracts whereby we agree to purchase product from a counterparty and to sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Cost of Sales

Cost of Sales

We include in cost of sales all costs we incur to acquire products, including the costs of purchasing, terminaling, and transporting inventory prior to delivery to our customers. Cost of sales does not include any depreciation of our property, plant and equipment. Cost of sales does include amortization of certain contract-based intangible assets of $6.2 million, $5.3 million, and $0.8 million during the years ended March 31, 2014, 2013, and 2012, respectively.

Depreciation and Amortization

Depreciation and Amortization

Depreciation and amortization in the consolidated statements of operations includes all depreciation of our property, plant and equipment and amortization of intangible assets other than debt issuance costs, for which the amortization is recorded to interest expense, and certain contract-based intangible assets, for which the amortization is recorded to cost of sales.

Cash and Cash Equivalents

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase. At times, certain account balances may exceed federally insured limits.

Supplemental cash flow information is as follows:

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees	$	31,827	$	27,384	$	4,966
Income taxes paid	$	1,639	$	1,027	$	430

Cash flows from commodity derivative instruments are classified as cash flows from investing activities in the consolidated statements of cash flows.

Accounts Receivable and Concentration of Credit Risk

Accounts Receivable and Concentration of Credit Risk

We operate in the United States and Canada. We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each customer’s creditworthiness as well as general economic conditions. The allowance for doubtful accounts is based on our assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. Accounts receivable are considered past due or delinquent based on contractual terms. We write off accounts receivable against the allowance for doubtful accounts when collection efforts have been exhausted.

We execute netting agreements with certain customers to mitigate our credit risk. Receivables and payables are reflected at a net balance to the extent a netting agreement is in place and we intend to settle on a net basis.

Our accounts receivable consist of the following:

	March 31, 2014				March 31, 2013
					Gross
	Gross		Allowance for		Receivable		Allowance for
Segment	Receivable		Doubtful Accounts		(Note 2)		Doubtful Accounts
	(in thousands)
Crude oil logistics	$	411,090	$	105	$	360,589	$	11
Water solutions	25,700		405		9,618		29
Liquids	192,529		617		144,267		76
Retail propane	75,606		1,667		49,233		1,644
Refined products	105,670		—		—		—
Renewables	54,466		—		—		—
Other	38,665		28		810		—
	$	903,726	$	2,822	$	564,517	$	1,760

Changes in the allowance for doubtful accounts are as follows:

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Allowance for doubtful accounts, beginning of period	$	1,760		$	818		$	161
Provision for doubtful accounts	2,172			1,315			1,049
Write off of uncollectible accounts	(1,110		)	(373		)	(392		)
Allowance for doubtful accounts, end of period	$	2,822		$	1,760		$	818

For the year ended March 31, 2014, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. At March 31, 2013, one customer of our crude oil logistics segment represented 10% of our consolidated accounts receivable balance.

Inventories

Inventories

We value our inventory at the lower of cost or market, with cost determined using either the weighted average cost or the first in, first out (FIFO) methods, including the cost of transportation. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business for sale in the retail markets.

Inventories consist of the following:

	March 31,
	2014		2013
	(in thousands)
Crude oil	$	156,473	$	46,156
Natural gas liquids —
Propane	85,159		45,428
Butane and other	19,051		24,090
Refined products	23,209		—
Renewables	11,778		—
Other	14,490		11,221
	$	310,160	$	126,895

Investments in Unconsolidated Entities

Investments in Unconsolidated Entities

As part of the December 2013 acquisition of Gavilon Energy, we acquired a 50% interest in Glass Mountain and an 11% interest in a limited liability company that owns an ethanol production facility. We account for these investments under the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our consolidated balance sheet; instead, our ownership interests are reported within “Investments in Unconsolidated Entities” on our consolidated balance sheet. We record our share of any income or loss generated by these entities as an increase to our equity method investments, and record any distributions we receive from these entities as reductions to our equity method investments.

Accrued Expenses and Other Payables

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following:

	March 31,
			2013
	2014		(Note 4)
	(in thousands)
Accrued compensation and benefits	$	45,006	$	27,252
Derivative liabilities	42,214		12,701
Income and other tax liabilities	13,421		22,659
Product exchange liabilities	3,719		6,741
Other	37,330		16,253
	$	141,690	$	85,606

Property, Plant and Equipment

Property, Plant and Equipment

We record property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. As we dispose of assets, we remove the cost and related accumulated depreciation from the accounts, and any resulting gain or loss is included in other income. We compute depreciation expense using the straight-line method over the estimated useful lives of the assets (see Note 5).

We evaluate the carrying value of our property, plant and equipment for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group.

Intangible Assets

Intangible Assets

Our intangible assets include contracts and arrangements acquired in business combinations, including lease agreements, customer relationships, covenants not to compete, and trade names. In addition, we capitalize certain debt issuance costs incurred in our long-term debt arrangements. We amortize our intangible assets on a straight-line basis over the assets’ estimated useful lives (see Note 7). We amortize debt issuance costs over the terms of the related debt on a method that approximates the effective interest method.

We evaluate the carrying value of our amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group. When we cease to use an acquired trade name, we test the trade name for impairment using the “relief from royalty” method and we begin amortizing the trade name over its estimated useful life as a defensive asset.

Goodwill

Goodwill

Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Business combinations are accounted for using the “acquisition method” (see Note 4). We expect that substantially all of our goodwill at March 31, 2014 is deductible for income tax purposes.

Goodwill and intangible assets determined to have an indefinite useful life are not amortized, but instead are evaluated for impairment periodically. We evaluate goodwill and indefinite-lived intangible assets for impairment annually, or more often if events or circumstances indicate that the assets might be impaired. We perform the annual evaluation at January 1 of each year.

To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. If we conclude that it is more likely than not that the fair value of a reporting unit exceeds its carrying amount, we perform the following two-step goodwill impairment test:

· 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.

Estimates and assumptions used to perform the impairment evaluation are inherently uncertain and can significantly affect the outcome of the analysis. The estimates and assumptions we used in the annual assessment for impairment of goodwill included market participant considerations and future forecasted operating results. Changes in operating results and other assumptions could materially affect these estimates. Based on our assessment of qualitative factors, we determined that the two-step impairment test was not required. Accordingly, we did not record any goodwill impairments during the years ended March 31, 2014, 2013, and 2012.

Product Exchanges

Product Exchanges

Quantities of products receivable or returnable under exchange agreements are reported within prepaid expenses and other current assets or within accrued expenses and other payables on the consolidated balance sheets. We estimate the value of product exchange assets and liabilities based on the weighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus or minus location differentials.

Advance Payments Received from Customers

Advance Payments Received from Customers

We record customer advances on product purchases as a liability on the consolidated balance sheets.

Noncontrolling Interests

Noncontrolling Interests

We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated statements of operations represents the other owners’ share of the net income (loss) of these entities.

Water Facility Development Agreement

Water Facility Development Agreement

In connection with one of our business combinations, we entered into a development agreement whereby we may acquire additional water disposal facilities in Texas. Under this agreement, the other party (the “Developer”) may develop facilities in a designated area. We then have the option to operate the facility for a period of up to 90 days, during which time we may elect to purchase the facility. If we elect to purchase the facility, the Developer may choose one of two options specified in the agreement for the calculation of the purchase price.

During the period between which we have begun operating the facility and we have decided whether to purchase the facility, we are entitled to a fee for operating the facility, which is forfeitable if we elect not to purchase the facility. We recognize revenue for these operator fees once they cease to be forfeitable. When we elect to purchase a facility, we account for the transaction as a business combination.

Business Combination Measurement Period

Business Combination Measurement Period

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination. As described in Note 4, certain of our acquisitions during the year ended March 31, 2014 are still within this measurement period, and as a result, the acquisition-date fair values we have recorded for the acquired assets and assumed liabilities are subject to change.

Also as described in Note 4, we made certain adjustments during the year ended March 31, 2014 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2013. We retrospectively adjusted the March 31, 2013 consolidated balance sheet for these adjustments. Due to the immateriality of these adjustments, we did not retrospectively adjust the consolidated statement of operations for the year ended March 31, 2013 for these measurement period adjustments.

Discontinued Operations

Discontinued Operations

In April 2014, the Financial Accounting Standards Board issued an Accounting Standards Update that changes the criteria for reporting discontinued operations. Under the new standard, a disposal of part of an entity is not classified as a discontinued operation unless the disposal represents a strategic shift that will have a major effect on an entity’s operations and financial results. We adopted the new standard during the fiscal year ended March 31, 2014.

As described in Note 14, during the year ended March 31, 2014, we sold our compressor leasing business and wound down our natural gas marketing business. These actions do not represent a strategic shift that had a major effect on our operations, and do not meet the criteria under the new accounting standard for these businesses to be reported as discontinued operations.

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Long-Term Obligations (Details 2) (USD $)						0 Months Ended
	Mar. 31, 2014	Mar. 31, 2014 Revolving Credit Facility	Mar. 31, 2014 Senior Notes	Mar. 31, 2014 Unsecured Notes	Mar. 31, 2014 Other Notes Payable	Jun. 19, 2012 Previous revolving credit facility
Maturities
2015	$ 7,081,000				$ 7,081,000
2016	3,614,000				3,614,000
2017	2,356,000				2,356,000
2018	26,449,000		25,000,000		1,449,000
2019	972,238,000	922,000,000	50,000,000		238,000
Thereafter	625,176,000		175,000,000	450,000,000	176,000
Total long-term debt	1,636,914,000	922,000,000	250,000,000	450,000,000	14,914,000
Principal payment						$ 306,800,000

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Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
OPERATING ACTIVITIES:
Net income	$ 48,758	$ 48,190	$ 7,864
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization	132,653	77,513	17,188
Loss on early extinguishment of debt		5,769
Non-cash equity-based compensation expense	14,054	8,670
Loss (gain) on disposal or impairment of assets	3,597	187	(71)
Provision for doubtful accounts	2,172	1,315	1,049
Commodity derivative (gain) loss	43,655	4,376	(5,974)
Earnings of unconsolidated entities	(1,898)
Other	312	375	403
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable - trade	21,388	2,562	(20,179)
Accounts receivable - affiliates	18,002	(12,877)	193
Inventories	(73,321)	18,433	30,268
Prepaid expenses and other current assets	18,900	22,585	14,344
Accounts payable - trade	(146,152)	(16,913)	35,747
Accounts payable - affiliates	67,361	(6,813)	4,549
Accrued expenses and other payables	(61,171)	(9,689)	366
Advance payments received from customers	(3,074)	(11,049)	4,582
Net cash provided by operating activities	85,236	132,634	90,329
INVESTING ACTIVITIES:
Purchases of long-lived assets	(165,148)	(72,475)	(7,544)
Acquisitions of businesses, including acquired working capital, net of cash acquired	(1,268,810)	(490,805)	(297,401)
Cash flows from commodity derivatives	(35,956)	11,579	6,464
Proceeds from sales of assets	24,660	5,080	1,238
Investments in unconsolidated entities	(11,515)
Distributions of capital from unconsolidated entities	1,591
Other	(195)		346
Net cash used in investing activities	(1,455,373)	(546,621)	(296,897)
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities	2,545,500	1,227,975	478,900
Payments on revolving credit facilities	(2,101,000)	(964,475)	(329,900)
Issuances of notes	450,000	250,000
Proceeds from borrowings on other long-term debt	880	653
Payments on other long-term debt	(8,819)	(4,837)	(1,278)
Debt issuance costs	(24,595)	(20,189)	(2,380)
Contributions	2,825	913	440
Distributions	(145,930)	(71,682)	(19,060)
Proceeds from sale of common units, net of offering costs	650,155	(642)	74,759
Repurchase of common units			(3,418)
Net cash provided by financing activities	1,369,016	417,716	198,063
Net increase (decrease) in cash and cash equivalents	(1,121)	3,729	(8,505)
Cash and cash equivalents, beginning of period	11,561	7,832	16,337
Cash and cash equivalents, end of period	$ 10,440	$ 11,561	$ 7,832

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Accounts receivable - trade, allowance for doubtful accounts (in dollars)	$ 2,822	$ 1,760
PROPERTY, PLANT AND EQUIPMENT, accumulated depreciation (in dollars)	109,564	50,127
INTANGIBLE ASSETS, accumulated amortization (in dollars)	$ 116,728	$ 44,155
General partner, interest (as a percent)	0.10%	0.10%
General partner, notional units outstanding	79,420	53,676
Limited partners, interest (as a percent)	99.90%	99.90%
Common units
Units issued	73,421,309	47,703,313
Units outstanding	73,421,309	47,703,313
Subordinated units
Units issued	5,919,346	5,919,346
Units outstanding	5,919,346	5,919,346

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Commitments and Contingencies

12 Months Ended

Mar. 31, 2014

Commitments and Contingencies

Commitments and Contingencies

Note 10 — Commitments and Contingencies

Legal Contingencies

We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our liabilities may change materially as circumstances develop.

Customer Dispute

A customer of our crude oil logistics segment has disputed the transportation rate schedule we used to bill the customer for services that we provided from November 2012 through February 2013, which was the same rate schedule that Pecos used to bill the customer from April 2011 through October 2012 (prior to our acquisition of Pecos). The customer has not paid $1.7 million of the amount we charged for services we provided from November 2012 through February 2013. In May 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. Later in May 2013, the customer filed an answer and counterclaim seeking to recover $5.5 million that it paid to Pecos prior to our acquisition of Pecos. We have not recorded revenue for the $1.7 million of unpaid fees charged from November 2012 through February 2013, pending resolution of the dispute.

During August 2013, the customer notified us that it intended to withhold payment of $3.3 million for services performed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer has not disputed the validity of the amounts billed for services performed during this time frame. Upon receiving this notification, we ceased providing services under this contract, and on November 5, 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. We are not able to reliably predict the outcome of this dispute at this time, but we do not believe the outcome will have a material adverse effect on our consolidated financial position or results of operations.

Canadian Fuel and Sales Taxes

The taxing authority of a province in Canada completed an audit of fuel and sales tax payments and alleged that an entity we acquired should have collected from customers and remitted to the taxing authority fuel and sales taxes on certain historical sales. We recorded in the acquisition accounting a liability of $0.8 million (net of receivables for expected recoveries from other parties). We now believe this matter is resolved, and we removed the liability from our consolidated balance sheet and recorded a corresponding reduction to cost of sales during the year ended March 31, 2014.

Environmental Matters

Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that significant costs will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

Asset Retirement Obligations

We have recorded a liability of $2.3 million at March 31, 2014 for asset retirement obligations. This liability is related to wastewater disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets. However, we do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, and equipment. Future minimum lease payments under contractual commitments at March 31, 2014 are as follows (in thousands):

Year Ending March 31,
2015	$	133,170
2016	93,454
2017	64,209
2018	49,802
2019	29,213
Thereafter	58,182
Total	$	428,030

Rental expense relating to operating leases was $98.3 million, $84.2 million, and $5.2 million during the years ended March 31, 2014, 2013, and 2012, respectively.

Sales and Purchase Contracts

We have entered into sales and purchase contracts for products to be delivered in future periods for which we expect the parties to physically settle the contracts with inventory. At March 31, 2014, we had the following such commitments outstanding:

	Volume	Value
	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)	31,111	$	39,117
Natural gas liquids floating-price purchase commitments (gallons)	522,947	618,293
Natural gas liquids fixed-price sale commitments (gallons)	63,944	77,682
Natural gas liquids floating-price sale commitments (gallons)	272,495	395,095
Crude oil fixed-price purchase commitments (barrels)	4,016	364,557
Crude oil fixed-price sale commitments (barrels)	3,574	324,765

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (described in Note 12) or inventory positions (described in Note 2).

Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value on our consolidated balance sheet and are not included in the data in the table above. These contracts are included in the derivative disclosures in Note 12, and represent $43.5 million of our prepaid expenses and other current assets and $34.6 million of our accrued expenses and other payables at March 31, 2014.

XML

Document and Entity Information (USD $)	12 Months Ended
	Mar. 31, 2014	Sep. 30, 2013	May 23, 2014 Common units	May 23, 2014 Subordinated units
Entity Registrant Name	NGL Energy Partners LP
Entity Central Index Key	0001504461
Document Type	10-K
Document Period End Date	Mar. 31, 2014
Amendment Flag	false
Current Fiscal Year End Date	--03-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Public Float		$ 1,443,663,823
Entity Common Stock, Shares Outstanding			74,706,160	5,919,346
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY

XML

Equity

12 Months Ended

Mar. 31, 2014

Equity

Equity

Note 11 — Equity

Partnership Equity

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest. Limited partner equity includes common and subordinated units. The common and subordinated units share equally in the allocation of income or loss. The principal difference between common and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

We expect the subordination period to end in August 2014. When the subordination period ends, all remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

Our general partner is not obligated to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

Initial Public Offering

On May 17, 2011, we completed our IPO. We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. Our proceeds from the sale of 3,850,000 common units of $71.9 million, net of total offering costs of $9.0 million, were used to repay advances under our acquisition credit facility and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) from the underwriters’ exercise of their option to purchase additional common units from us were used to redeem 175,000 of the common units outstanding prior to our IPO. Upon the completion of our IPO and the underwriters’ exercise in full of their option to purchase additional common units from us and the redemption, we had outstanding 8,864,222 common units, 5,919,346 subordinated units, a 0.1% general partner interest, and IDRs.

Common Units Issued in Business Combinations

As described in Note 4, we issued common units as partial consideration for several acquisitions. These are summarized below:

Osterman combination	4,000,000
SemStream combination	8,932,031
Pacer combination	1,500,000
Total - Year Ended March 31, 2012	14,432,031
High Sierra combination	20,703,510
Retail propane combinations	850,676
Crude oil logistics and water solutions combinations	516,978
Pecos combination	1,834,414
Third Coast combination	344,680
Total - Year Ended March 31, 2013	24,250,258
Water solutions combinations	222,381
Crude oil logistics combinations	175,211
OWL combination	2,463,287
Total - Year Ended March 31, 2014	2,860,879

In connection with the completion of certain of these transactions, we amended our Registration Rights Agreement, which provides for certain registration rights for certain holders of our common units.

Equity Issuances

On July 5, 2013, we completed a public offering of 10,350,000 common units. We received net proceeds of $287.5 million, after underwriting discounts and commissions of $12.0 million and offering costs of $0.7 million.

On September 25, 2013, we completed a public offering of 4,100,000 common units. We received net proceeds of $127.6 million, after underwriting discounts and commissions of $5.0 million and offering costs of $0.2 million.

On December 2, 2013, we issued and sold 8,110,848 of our common units in a private placement. We received net proceeds of $235.1 million, after offering costs of $4.9 million.

Distributions

Our general partner has adopted a cash distribution policy that will require us to pay a quarterly distribution to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as “available cash,” in the following manner:

· First, 99.9% to the holders of common units and 0.1% to the general partner, until each common unit has received the specified minimum quarterly distribution, plus any arrearages from prior quarters.

· Second, 99.9% to the holders of subordinated units and 0.1% to the general partner, until each subordinated unit has received the specified minimum quarterly distribution.

· Third, 99.9% to all unitholders, pro rata, and 0.1% to the general partner.

The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions paid to the limited partners. These distributions are referred to as “incentive distributions.”

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest, assume our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its IDRs and there are no arrearages on common units.

					Marginal Percentage Interest In
	Total Quarterly				Distributions
	Distribution per Unit				Unitholders		General Partner
Minimum quarterly distribution				$ 0.337500	99.9	%	0.1	%
First target distribution	above	$ 0.337500	up to	$ 0.388125	99.9	%	0.1	%
Second target distribution	above	$ 0.388125	up to	$ 0.421875	86.9	%	13.1	%
Third target distribution	above	$ 0.421875	up to	$ 0.506250	76.9	%	23.1	%
Thereafter	above	$ 0.506250			51.9	%	48.1	%

On May 5, 2011, we made a distribution of $3.9 million from available cash to our general partner and common unitholders at March 31, 2011.

The following table summarizes the distributions declared subsequent to our IPO:

			Amount		Amount Paid to		Amount Paid to
Date Declared	Record Date	Date Paid	Per Unit		Limited Partners		General Partner
					(in thousands)		(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011	0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012	0.3500		7,735		10
April 18, 2012	April 30, 2012	May 15, 2012	0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012	0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012	0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013	0.4625		24,245		927
April 25, 2013	May 6, 2013	May 15, 2013	0.4775		25,605		1,189
July 25, 2013	August 5, 2013	August 14, 2013	0.4938		31,725		1,739
October 23, 2013	November 4, 2013	November 14, 2013	0.5113		35,908		2,491
January 23, 2014	February 4, 20143	February 14, 2014	0.5313		42,150		4,283
April 24, 2014	May 5, 2014	May 15, 2014	0.5513		43,737		5,754

Several of our business combination agreements contained provisions that temporarily limited the distributions to which the newly-issued units were entitled. The following table summarizes the number of equivalent units that were not eligible to receive a distribution on each of the record dates:

	Equivalent
	Units Not
Record Date	Eligible
August 3, 2011	—
October 31, 2011	4,000,000
February 3, 2012	7,117,031
April 30, 2012	3,932,031
August 3, 2012	17,862,470
October 29, 2012	516,978
February 4, 2013	1,202,085
May 6, 2013	—
August 5, 2013	—
November 4, 2013	979,886
February 4, 2014	—
May 5, 2014	—

Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plan (“LTIP”) which allows for the issuance of equity-based compensation to employees and directors. The board of directors of our general partner has granted certain restricted units to employees and directors, which will vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

The following table summarizes the restricted unit activity during the years ended March 31, 2014 and 2013:

Unvested restricted units at March 31, 2012	—
Units granted	1,684,400
Units vested and issued	(156,802	)
Units withheld for employee taxes	(61,698	)
Units forfeited	(21,000	)
Unvested restricted units at March 31, 2013	1,444,900
Units granted	494,000
Units vested and issued	(296,269	)
Units withheld for employee taxes	(122,531	)
Units forfeited	(209,000	)
Unvested restricted units at March 31, 2014	1,311,100

The scheduled vesting of the awards is summarized below:

Vesting Date	Number of Awards
July 1, 2014	408,300
January 1, 2015	4,000
July 1, 2015	341,300
January 1, 2016	4,000
July 1, 2016	322,500
January 1, 2017	4,000
July 1, 2017	192,500
January 1, 2018	4,000
July 1, 2018	30,500
Total unvested units at March 31, 2014	1,311,100

We record the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through the reporting date using the estimated fair value of the awards at the reporting date. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth. We estimate that the future expense we will record on the unvested awards at March 31, 2014 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of 95,000 units. For purposes of this calculation, we have used the closing price of the common units on March 31, 2014, which was $37.53.

Year Ending March 31,
2015	$	14,393
2016	11,279
2017	7,429
2018	2,310
2019	229
Total	$	35,640

Following is a rollforward of the liability related to equity-based compensation, which is reported within accrued expenses and other payables on our consolidated balance sheets (in thousands):

Balance at March 31, 2012	$	—
Expense recorded	10,138
Value of units vested and issued	(3,627		)
Taxes paid on behalf of participants	(1,468		)
Balance at March 31, 2013	5,043
Expense recorded	17,804
Value of units vested and issued	(9,085		)
Taxes paid on behalf of participants	(3,750		)
Balance at March 31, 2014	$	10,012

The weighted-average fair value of the awards at March 31, 2014 was $33.78, which was calculated as the closing price of the common units on March 31, 2014, adjusted 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 and assumptions that a market participant might make about future distribution growth.

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common and subordinated units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common and subordinated 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. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At March 31, 2014, 6.2 million units remain available for issuance under the LTIP.

XML

Disposals and Impairments (Details) (USD $)	12 Months Ended				1 Months Ended	12 Months Ended
	Mar. 31, 2014 Liquids item	Mar. 31, 2014 Water solutions	Mar. 31, 2014 Gavilon Energy Natural Gas Storage and Transportation Contracts	Mar. 31, 2014 Gavilon Energy Natural Gas Storage and Transportation Contracts Corporate and other	Feb. 28, 2014 High Sierra	Mar. 31, 2014 High Sierra Corporate and other
Disposals and Impairments
Payments for assignment of contracts			$ 44,800,000
Liability recorded in the acquisition accounting			50,800,000
Amortization of contract liabilities through cost of sales			6,000,000
Operating income				1,400,000		2,300,000
Proceeds from sale of business					10,800,000
Gain on sale of business					4,400,000
Gain on the sale of the business attributable to noncontrolling interest					1,600,000
Write down of property, plant and equipment	$ 5,300,000	$ 1,500,000
Number of natural gas liquids terminals	1
Number of water solutions facilities which experienced damage to property, plant and equipment		2

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Consolidated Statements of Operations (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
REVENUES:
Crude oil logistics	$ 4,558,545	$ 2,316,288
Water solutions	143,100	62,227
Liquids Revenue	2,650,425	1,604,746	1,111,139
Retail propane	551,815	430,273	199,334
Refined products	1,180,895
Renewables	176,781
Other	437,713	4,233
Total Revenues	9,699,274	4,417,767	1,310,473
COST OF SALES:
Crude oil logistics	4,477,397	2,244,647
Water solutions	11,738	5,611
Liquids	2,518,099	1,530,459	1,086,881
Retail propane	354,676	258,393	130,142
Refined products	1,172,754
Renewables	171,422
Other	426,613
Total Cost of Sales	9,132,699	4,039,110	1,217,023
OPERATING COSTS AND EXPENSES:
Operating	259,396	169,799	47,300
General and administrative	79,860	52,698	16,009
Depreciation and amortization	120,754	68,853	15,111
Operating Income	106,565	87,307	15,030
OTHER INCOME (EXPENSE):
Earnings of unconsolidated entities	1,898
Interest expense	(58,854)	(32,994)	(7,620)
Loss on early extinguishment of debt		(5,769)
Other, net	86	1,521	1,055
Income Before Income Taxes	49,695	50,065	8,465
INCOME TAX PROVISION	(937)	(1,875)	(601)
Net Income	48,758	48,190	7,864
NET INCOME ALLOCATED TO GENERAL PARTNER	(14,148)	(2,917)	(8)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS	(1,103)	(250)	12
NET INCOME ALLOCATED TO LIMITED PARTNERS	33,507	45,023	7,868
Common units
OTHER INCOME (EXPENSE):
NET INCOME ALLOCATED TO LIMITED PARTNERS	31,614	39,517	4,859
BASIC AND DILUTED INCOME PER COMMON UNIT (in dollars per unit)	$ 0.51	$ 0.96	$ 0.32
BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING:
BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING: (in shares)	61,970,471	41,353,574	15,169,983
Subordinated units
OTHER INCOME (EXPENSE):
NET INCOME ALLOCATED TO LIMITED PARTNERS	$ 1,893	$ 5,506	$ 3,009
BASIC AND DILUTED INCOME PER COMMON UNIT (in dollars per unit)	$ 0.32	$ 0.93	$ 0.58
BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING:
BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING: (in shares)	5,919,346	5,919,346	5,175,384

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Property, Plant and Equipment

12 Months Ended

Mar. 31, 2014

Property, Plant and Equipment

Property, Plant and Equipment

Note 5 — Property, Plant and Equipment

Our property, plant and equipment consists of the following:

	March 31,
				2013
Description and Estimated Useful Lives	2014			(Note 2)
	(in thousands)
Natural gas liquids terminal assets (2—30 years)	$	75,141		$	63,637
Retail propane equipment (2—30 years)	160,758			152,802
Vehicles (3—25 years)	152,676			88,173
Water treatment facilities and equipment (3—30 years)	180,985			91,944
Crude oil tanks and related equipment (2—40 years)	106,125			22,577
Barges and towboats (5—40 years)	52,217			25,963
Information technology equipment (3—7 years)	20,768			12,169
Buildings and leasehold improvements (3—40 years)	60,004			48,975
Land	30,241			21,815
Linefill and tank bottoms	13,403			—
Other (5—30 years)	6,341			16,104
Construction in progress	80,251			32,405
	938,910			576,564
Less: Accumulated depreciation	(109,564		)	(50,127		)
Net property, plant and equipment	$	829,346		$	526,437

Depreciation expense was $59.9 million, $39.2 million and $10.6 million during the years ended March 31, 2014, 2013 and 2012, respectively. During the year ended March 31, 2014, we capitalized $0.7 million of interest expense.

XML

Acquisitions

12 Months Ended

Mar. 31, 2014

Acquisitions

Acquisitions

Note 4 — Acquisitions

Year Ended March 31, 2014

Gavilon Energy

On December 2, 2013, we completed a business combination in which we acquired Gavilon Energy. We paid $832.4 million of cash, net of cash acquired, in exchange for these assets and operations. The acquisition agreement also contemplates a post-closing adjustment to the purchase price for certain working capital items. We incurred and charged to general and administrative expense $5.3 million of costs during the year ended March 31, 2014 related to the acquisition of Gavilon Energy.

The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana and a 50% interest in Glass Mountain, which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline became operational in February 2014. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in the acquisition of Gavilon Energy. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending September 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	349,529
Accounts receivable - affiliates	2,564
Inventories	107,430
Prepaid expenses and other current assets	68,322
Property, plant and equipment:
Crude oil tanks and related equipment (3—40 years)	77,429
Vehicles (3 years)	791
Information technology equipment (3—7 years)	4,046
Buildings and leasehold improvements (3—40 years)	7,716
Land	6,427
Linefill and tank bottoms	15,230
Other (7 years)	170
Construction in process	7,190
Goodwill	359,169
Intangible assets:
Customer relationships (10—20 years)	101,600
Lease agreements (1—5 years)	8,700
Investments in unconsolidated entities	178,000
Other noncurrent assets	9,918
Accounts payable - trade	(342,792		)
Accounts payable - affiliates	(2,585		)
Accrued expenses and other payables	(70,999		)
Advance payments received from customers	(10,667		)
Other noncurrent liabilities	(44,740		)
Fair value of net assets acquired	$	832,448

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership, the opportunity to use the acquired business as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Our preliminary estimate of the fair value of investments in unconsolidated subsidiaries exceeds our share of the historical net book value of these subsidiaries’ net assets by approximately $70 million. This difference relates primarily to goodwill and customer relationships.

The acquisition method of accounting requires that executory contracts that are at unfavorable terms relative to current market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain crude oil storage lease commitments were at unfavorable terms relative to current market conditions, we recorded a liability of $12.9 million related to these lease commitments in the acquisition accounting, and we amortized $2.9 million of this balance through cost of sales during the period from the acquisition date through March 31, 2014. We will amortize the remainder of this liability over the term of the leases. The future amortization of this liability is shown below (in thousands):

Year Ending March 31,
2015	$	6,500
2016	3,260
2017	300

As described in Note 14, on March 31, 2014, we assigned all of the storage and transportation contracts of the natural gas marketing business to a third party.  Since these contracts were at unfavorable terms relative to current market conditions, we paid $44.8 million to assign these contracts. We recorded a liability of $50.8 million related to these storage and transportation contracts in the acquisition accounting, and we amortized $6.0 million of this balance through cost of sales during the period from the acquisition date through the date we assigned the contracts.

We recorded $3.2 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the acquisition of Gavilon Energy. In addition, certain personnel who were employees of Gavilon Energy are entitled to a bonus, half of which was payable upon successful completion of the business combination and the remainder of which is payable in December 2014. We are recording this as compensation expense over the vesting period. We recorded expense of $5.0 million during the year ended March 31, 2014 related to these bonuses, and we expect to record an additional expense of $6.6 million during the year ending March 31, 2015.

The operations of Gavilon Energy have been included in our consolidated statement of operations since Gavilon Energy was acquired on December 2, 2013. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $2.9 billion and operating income of $11.0 million that were generated by the operations of Gavilon Energy.

Oilfield Water Lines, LP

On August 2, 2013, we completed a business combination with entities affiliated with OWL, whereby we acquired water disposal and transportation assets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL. The acquisition agreements included a provision whereby the purchase price could have been increased if certain performance targets were achieved in the six months following the acquisition. These performance targets were not achieved, and therefore no increase to the purchase price was warranted. The acquisition agreements also contemplate a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense $0.8 million of costs related to the OWL acquisition during the year ended March 31, 2014.

We have completed the process of identifying and determining the fair value of the long-lived assets acquired in the acquisition of OWL. We have not yet finalized any post-closing payment for certain working capital items, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	7,268
Inventories	154
Prepaid expenses and other current assets	402
Property, plant and equipment:
Land	710
Water treatment facilities and equipment (3—30 years)	23,173
Vehicles (5—10 years)	8,157
Buildings and leasehold improvements (7—30 years)	2,198
Other (3—5 years)	53
Intangible assets:
Customer relationships (10 years)	110,000
Non-compete agreements (2.5 years)	2,000
Goodwill	89,699
Accounts payable - trade	(6,469		)
Accrued expenses and other payables	(992		)
Other noncurrent liabilities	(64		)
Fair value of net assets acquired	$	236,289

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	167,732
Value of common units issued	68,557
Total consideration paid	$	236,289

The customer relationships were valued using a variation of the income approach known as the excess earnings method. This methodology consists of deriving relevant cash flows to the underlying asset, and then deducting appropriate returns for other assets contributing to the generation of the relevant cash flows. This valuation methodology requires estimates of customer retention, which were based on our understanding of the level of competition in the region in which the assets operate. Our estimates of customer retention are also relevant to the determination of the estimated useful lives of the assets.

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

The operations of OWL have been included in our consolidated statement of operations since OWL was acquired on August 2, 2013. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $26.2 million and operating income of $0.9 million that was generated by the operations of OWL.

Other Water Solutions Acquisitions

During the year ended March 31, 2014, we completed four separate acquisitions of businesses to expand our water solutions operations in Texas. On a combined basis, we issued 222,381 common units, valued at $6.8 million, and paid $178.9 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $20.6 million and operating income of $7.1 million that was generated by the operations of these acquisitions. We incurred and charged to general and administrative expense $0.4 million of costs related to these acquisitions during the year ended March 31, 2014.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these four business combinations. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending September 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	2,391
Inventories	390
Prepaid expenses and other current assets	61
Property, plant and equipment:
Land	419
Vehicles (5—10 years)	90
Water treatment facilities and equipment (3—30 years)	24,933
Buildings and leasehold improvements (7—30 years)	3,036
Other (3—5 years)	13
Intangible assets:
Customer relationships (8—10 years)	72,000
Trade names (indefinite life)	3,325
Non-compete agreements (3 years)	260
Water facility development agreement (5 years)	14,000
Water facility option agreement	2,500
Goodwill	63,031
Accounts payable - trade	(382		)
Accrued expenses and other payables	(300		)
Other noncurrent liabilities	(114		)
Fair value of net assets acquired	$	185,653

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	178,867
Value of common units issued	6,786
Total consideration paid	$	185,653

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

As part of one of these business combinations, we entered into an option agreement with the seller of the business whereby we had the option to purchase a salt water disposal facility that was under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this option agreement. On March 1, 2014, we purchased the saltwater disposal facility for additional cash consideration of $3.7 million. The assets associated with this facility are included in the data in the table above.

As part of one of these business combinations, we entered into a development agreement that provides us a first right of refusal to purchase disposal facilities that may be developed by the seller within a defined area in the Eagle Ford Basin through June 2018. On March 1, 2014, we purchased our first disposal facility pursuant to the development agreement for $21.0 million. The assets associated with this facility are included in the data in the table above. In addition, we have exercised our option to operate, for evaluation purposes, three additional disposal facilities developed by the seller. Pending the results of our evaluation, we have the right to purchase any or all of these facilities within the 90-day evaluation period.

Crude Oil Logistics Acquisitions

During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our crude oil logistics business in Texas and Oklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. The agreement for the acquisition of one of these businesses contemplates a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense during the year ended March 31, 2014 $0.1 million of costs related to these acquisitions.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these two business combinations. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	1,235
Inventories	1,021
Prepaid expenses and other current assets	54
Property, plant and equipment:
Vehicles (5—10 years)	2,977
Buildings and leasehold improvements (5—30 years)	280
Crude oil tanks and related equipment (2—30 years)	3,462
Barges and towboats (20 years)	20,065
Other (3—5 years)	53
Intangible assets:
Customer relationships (3 years)	6,300
Non-compete agreements (3 years)	35
Trade names (indefinite life)	530
Goodwill	37,867
Accounts payable - trade	(665		)
Accrued expenses and other payables	(124		)
Fair value of net assets acquired	$	73,090

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	67,842
Value of common units issued	5,248
Total consideration paid	$	73,090

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Retail Propane and Liquids Acquisitions

During the year ended March 31, 2014, we completed four acquisitions of retail propane businesses and the acquisition of four natural gas liquids terminals. On a combined basis, we paid $21.9 million of cash to acquire these assets and operations. The agreements for certain of these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in certain of these business combinations, and as a result the estimates of fair value reflected at March 31, 2014 are subject to change.

Year Ended March 31, 2013

High Sierra Combination

On June 19, 2012, we completed a business combination with High Sierra, whereby we acquired all of the ownership interests in High Sierra. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. These common units were valued at $406.8 million using the closing price of our common units on the New York Stock Exchange (the “NYSE”) on the merger date. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner. We recorded the value of the 2,685,042 common units issued to our general partner at $8.0 million, which represents an estimate, in accordance with GAAP, of the fair value of the equity issued by our general partner to the former owners of High Sierra’s general partner. In accordance with the GAAP fair value model, this fair value was estimated based on assumptions of future distributions and a discount rate that a hypothetical buyer might use. Under this model, the potential for distribution growth resulting from the prospect of future acquisitions and capital expansion projects would not be considered in the fair value calculation. The difference between the estimated fair value of the general partner interests issued by our general partner of $8.0 million, calculated as described above, and the fair value of the common units issued to our general partner of $60.6 million, as calculated using the closing price of the common units on the NYSE, is reported as a reduction to equity. We incurred and charged to general and administrative expense during the years ended March 31, 2013 $3.7 million of costs related to the High Sierra transaction. We also incurred or accrued costs of $0.6 million related to the equity issuance that we charged to equity.

The fair values of the assets acquired and liabilities assumed in our acquisition of High Sierra are summarized below (in thousands):

Accounts receivable - trade	$	395,311
Accounts receivable - affiliates	7,724
Inventories	43,575
Derivative assets	10,646
Forward purchase and sale contracts	34,717
Prepaid expenses and other current assets	11,131
Property, plant and equipment:
Land	5,723
Vehicles (5—10 years)	22,507
Water treatment facilities and equipment (3—30 years)	64,057
Crude oil tanks and related equipment (2—15 years)	17,851
Buildings and leasehold improvements (5—30 years)	19,145
Information technology equipment (3 years)	5,541
Other (2—30 years)	11,010
Construction in progress	9,621
Intangible assets:
Customer relationships (5—17 years)	245,000
Lease contracts (1—10 years)	12,400
Trade names (indefinite)	13,000
Goodwill	220,884
Accounts payable - trade	(417,369			)
Accounts payable - affiliates	(9,014			)
Advance payments received from customers	(1,237			)
Accrued expenses and other payables	(35,611			)
Derivative liabilities	(5,726			)
Forward purchase and sale contracts	(18,680			)
Long-term debt	(2,537			)
Other noncurrent liabilities	(3,224			)
Noncontrolling interest in consolidated subsidiary	(2,400			)
Consideration paid, net of cash acquired	$		654,045

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	239,251
Value of common units issued, net of issurance costs	414,794
Total consideration paid	$	654,045

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Pecos Combination

On November 1, 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 marketing and logistics operations in Texas and New Mexico. We paid $132.4 million of cash (net of cash acquired) and assumed certain obligations with a value of $10.2 million under certain equipment financing facilities. Also on November 1, 2012, we entered into a call agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.6 million of costs related to the Pecos combination.

The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Pecos:

				Estimated at
				March 31,
	Final			2013			Change
	(in thousands)
Accounts receivable - trade	$	73,609		$	73,704		$	(95	)
Inventories	1,903			1,903			—
Prepaid expenses and other current assets	1,426			1,426			—
Property, plant and equipment:
Vehicles (5—10 years)	22,097			19,193			2,904
Buildings and leasehold improvements (5—30 years)	1,339			1,248			91
Crude oil tanks and related equipment (2—15 years)	1,099			913			186
Land	223			224			(1		)
Other (3—5 years)	36			177			(141		)
Intangible assets:
Customer relationships	—			8,000			(8,000		)
Trade names (indefinite life)	900			1,000			(100		)
Goodwill	91,747			86,661			5,086
Accounts payable - trade	(50,795		)	(50,808		)	13
Accrued expenses and other payables	(963		)	(1,020		)	57
Long-term debt	(10,234		)	(10,234		)	—
Fair value of net assets acquired	$	132,387		$	132,387		$	—

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	87,444
Value of common units issued	44,943
Total consideration paid	$	132,387

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Third Coast Combination

On December 31, 2012, we completed a business combination transaction whereby we acquired all of the membership interests in Third Coast Towing, LLC (“Third Coast”) for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. Also on December 31, 2012, we entered into a call agreement with the former owners of Third Coast pursuant to which the former owners of Third Coast agreed to purchase a minimum of $8.0 million or a maximum of $10.0 million of common units from us. On January 11, 2013, the former owners of Third Coast purchased 344,680 common units from us for $8.0 million pursuant to this agreement.

During the year ended March 31, 2014, we completed the acquisition accounting for this business combination. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Third Coast:

				Estimated at
				March 31,
	Final			2013			Change
	(in thousands)
Accounts receivable - trade	$	2,195		$	2,248		$	(53	)
Inventories	140			140			—
Property, plant and equipment:
Barges and towboats (20 years)	17,711			12,883			4,828
Other	—			30			(30		)
Intangible assets:
Customer relationships (3 years)	3,000			4,000			(1,000		)
Trade names (indefinite life)	850			500			350
Goodwill	18,847			22,551			(3,704		)
Other noncurrent assets	2,733			2,733			—
Accounts payable - trade	(2,429		)	(2,048		)	(381		)
Accrued expenses and other payables	(164		)	(154		)	(10		)
Fair value of net assets acquired	$	42,883		$	42,883		$	—

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	35,000
Value of common units issued	7,883
Total consideration paid	$	42,883

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Other Crude Oil Logistics and Water Solutions Business Combinations

During the year ended March 31, 2013, we completed four separate acquisitions to expand the assets and operations of our crude oil logistics and water solutions businesses. On a combined basis, we paid $52.6 million in cash and assumed $1.3 million of long-term debt in the form of non-compete agreements. We also issued 516,978 common units, valued at $12.4 million, as partial consideration for one of these acquisitions. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.3 million of costs related to these acquisitions.

During the year ended March 31, 2014, we completed the acquisition accounting for these business combinations. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of these businesses:

				Estimated at
				March 31,
	Final			2013			Change
	(in thousands)
Accounts receivable - trade	$	2,676		$	2,660		$	16
Inventories	191			191			—
Prepaid expenses and other current assets	737			738			(1		)
Property, plant and equipment:
Land	218			191			27
Vehicles (5—10 years)	853			771			82
Water treatment facilities and equipment (3—30 years)	13,665			13,322			343
Buildings and leasehold improvements (5—30 years)	895			2,233			(1,338		)
Crude oil tanks and related equipment (2—15 years)	4,510			1,781			2,729
Other (3—5 years)	27			2			25
Construction in progress	490			693			(203		)
Intangible assets:
Customer relationships (5—10 years)	13,125			6,800			6,325
Non-compete agreements (3 years)	164			510			(346		)
Trade names (indefinite life)	2,100			500			1,600
Goodwill	34,451			43,822			(9,371		)
Accounts payable - trade	(3,374		)	(3,374		)	—
Accrued expenses and other payables	(1,914		)	(2,026		)	112
Notes payable	(1,340		)	(1,340		)	—
Other noncurrent liabilities	(156		)	(156		)	—
Noncontrolling interest	(2,333		)	(2,333		)	—
Fair value of net assets acquired	$	64,985		$	64,985		$	—

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	52,552
Value of common units issued	12,433
Total consideration paid	$	64,985

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Retail Propane Combinations During the Year Ended March 31, 2013

During the year ended March 31, 2013, we entered into six separate business combination agreements to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States. On a combined basis, we paid cash of $71.4 million and issued 850,676 common units, valued at $18.9 million, in exchange for these assets. We also assumed $6.6 million of long-term debt in the form of non-compete agreements. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.3 million related to these acquisitions. The fair values of the assets acquired and liabilities assumed in these six combinations are as follows (in thousands):

Accounts receivable - trade	$	8,715
Inventory	5,155
Other current assets	1,228
Property, plant and equipment:
Land	1,945
Retail propane equipment (5—20 years)	28,763
Vehicles (5 years)	11,344
Buildings and leasehold improvements (30 years)	7,052
Other	1,201
Intangible assets:
Customer relationships (10—15 years)	16,890
Trade names (indefinite)	2,924
Non-compete agreements (5 years)	1,387
Goodwill	21,983
Other non-current assets	784
Long-term debt, including current portion	(6,594		)
Other assumed liabilities	(12,511		)
Fair value of net assets acquired	$	90,266

Consideration paid consists of the following (in thousands):

Cash consideration paid	$	71,392
Value of common units issued	18,874
Total consideration	$	90,266

Goodwill represents the excess of the estimated consideration paid for the acquired businesses over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

Pro Forma Results of Operations (Unaudited)

As described above, we completed a number of acquisitions during the years ended March 31, 2014 and 2013. The operations of each acquired business have been included in our consolidated results of operations since the date of acquisition of the business. The unaudited pro forma consolidated data presented below has been prepared as if the following acquisitions had been completed on April 1, 2012:

· High Sierra;

· Pecos;

· Third Coast;

· OWL; and

· Gavilon Energy.

The unaudited pro forma consolidated data presented below has also been prepared as if the following transactions, which are described in Notes 8 and 11 to these consolidated financial statements, had been completed on April 1, 2012:

· Our sale of common units in December 2013 in a private placement;

· The amendment of our Credit Agreement in November 2013;

· Our issuance of senior unsecured notes in October 2013;

· Our sale of common units in September 2013 in a public offering;

· The sale of common units in a public offering in July 2013;

· Our entry into the Credit Agreement in June 2012; and

· Our issuance of senior notes in June 2012.

	Year Ended March 31,
	2014			2013
	(in thousands, except per unit amounts)
Revenues	$	9,800,398		$	5,697,988
Net income (loss)	798			(72,171		)
Net loss attributable to limited partners	(14,446		)	(75,251		)
Basic and diluted loss per common unit	(0.18		)	(0.95		)
Basic and diluted loss per subordinated unit	(0.18		)	(0.95		)

The pro forma consolidated data in the table above was prepared by adding historical results of operations of acquired businesses to our historical results of operations and making certain pro forma adjustments. The pro forma information is not necessarily indicative of the results of operations that would have occurred if the transactions had occurred on April 1, 2012, nor is it necessarily indicative of future results of operations.

Gavilon Energy historically conducted trading operations, whereas we operate as a logistics business. Gavilon Energy’s historical results of operations were subject to more volatility as a result of its trading operations than we would expect future results of operations to have under our business model. In the pro forma data in the table above, no pro forma effect was given to the change in business model from a trading business to a logistics business. Gavilon Energy historically recorded revenues net of product costs. In the pro forma table above, no pro forma effect was given to the fact that this accounting policy is different than our accounting policy.

The pro forma net loss for the year ended March 31, 2013 in the table above includes $4.8 million of expense related to the retirement of a liability associated with a business combination that OWL completed prior to our acquisition of OWL. This non-recurring expense is not excluded from the pro forma net loss, as it does not directly result from our acquisition of OWL.

The pro forma net loss for the year ended March 31, 2014 shown in the table above reflects depreciation and amortization expense estimates which are preliminary, as our identification of the assets and liabilities acquired, and the fair value determinations thereof, for the business combination with Gavilon Energy have not been completed.

The pro forma losses per unit have been computed based on earnings or losses allocated to the limited partners after deducting the total earnings allocated to the general partner. To calculate earnings attributable to the general partner, we have used historical distribution amounts. For purposes of this calculation, we have assumed that the common units outstanding at March 31, 2014 were outstanding during the full years presented above.

Year Ended March 31, 2012

Osterman

On October 3, 2011, we completed a business combination transaction with Osterman, whereby we acquired retail propane operations in the northeastern United States. We issued 4,000,000 common units and paid $94.9 million of cash, net of cash acquired, in exchange for the assets and operations of Osterman. The agreement also contemplated a post-closing payment of $4.8 million for certain specified working capital items, which was paid in November 2012. We valued the 4 million limited partner common units at $81.9 million based on the closing price of our common units on the closing date ($20.47 per unit). We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.8 million of costs incurred in connection with the Osterman transaction. We also incurred costs related to the equity issuance of $0.1 million that we charged to equity. The following table presents the final allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable - trade	$	9,350
Inventories	3,869
Prepaid expenses and other current assets	215
Property, plant and equipment:
Land	2,349
Retail propane equipment (15—20 years)	47,160
Vehicles (5—20 years)	7,699
Buildings and leasehold improvements (30 years)	3,829
Other (3—5 years)	732
Intangible assets:
Customer relationships (20 years)	54,500
Trade names (indefinite life)	8,500
Non-compete agreements (7 years)	700
Goodwill	52,267
Assumed liabilities	(9,654		)
Consideration paid, net of cash acquired	$	181,516

Consideration paid consists of the following (in thousands):

Cash paid at closing, net of cash acquired	$	94,873
Fair value of common units issued at closing	81,880
Working capital payment (paid in November 2012)	4,763
Consideration paid, net of cash acquired	$	181,516

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

SemStream

On November 1, 2011, we completed a business combination with SemStream. We entered into this business combination in order to expand our liquids segment. SemStream contributed substantially all of its natural gas liquids business and assets to us in exchange for 8,932,031 of our limited partner common units and a cash payment of $91.0 million. We have valued the 8.9 million limited partner common units at $184.8 million, based on the closing price of our common units on the closing date ($21.07) reduced by the expected present value of distributions for certain units which were not eligible for full distributions until the quarter ending September 30, 2012. In addition, in exchange for a cash contribution, SemStream acquired a 7.5% interest in our general partner. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.7 million of costs related to the SemStream transaction. We also incurred costs of less than $0.1 million related to the equity issuance that we charged to equity.

The acquired assets included 12 natural gas liquids terminals in Arizona, Arkansas, Indiana, Minnesota, Missouri, Montana, Washington and Wisconsin, 12 million gallons of aboveground propane storage, 3.7 million barrels of underground leased storage for natural gas liquids and a rail fleet of 350 leased and 12 owned cars.

We have included the results of SemStream’s operations in our consolidated financial statements beginning November 1, 2011. The operations of SemStream are reflected in our liquids segment.

The following table presents the fair values of the assets acquired and liabilities assumed in the SemStream combination (in thousands):

Inventories	$	104,226
Derivative assets	3,578
Assets held for sale	3,000
Prepaid expenses and other current assets	9,833
Property, plant and equipment:
Land	3,470
Natural gas liquids terminal assets (20—30 years)	41,434
Vehicles and railcars (5 years)	470
Other (5 years)	3,326
Investment in capital lease	3,112
Intangible assets:
Customer relationships (8—15 years)	31,950
Lease contracts (1—4 years)	1,008
Goodwill	74,924
Assumed current liabilities	(4,591		)
Consideration paid	$	275,740

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired operations and the Partnership, the opportunity to use the acquired businesses as a platform to expand our wholesale marketing operations, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

Pacer Combination

On January 3, 2012, we completed a business combination with Pacer in order to expand our retail propane operations. The combination was funded with cash of $32.2 million and the issuance of 1.5 million common units. We valued the 1.5 million common units based on the closing price of our common units on the closing date. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.7 million of costs related to the Pacer transaction. We also incurred costs of $0.1 million related to the equity issuance that we charged to equity.

The assets contributed by Pacer consist of retail propane operations in Colorado, Illinois, Mississippi, Oregon, Utah and Washington. The contributed assets include 17 owned or leased customer service centers and satellite distribution locations. We have included the results of Pacer’s operations in our consolidated financial statements beginning January 3, 2012. The operations of Pacer are reported within our retail propane segment.

Consideration paid consists of the following (in thousands):

Cash	$	32,213
Common units	30,375
Consideration paid	$	62,588

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable - trade	$	4,389
Inventories	965
Prepaid expenses and other current assets	43
Property, plant and equipment:
Land	1,967
Retail propane equipment (15—20 years)	12,793
Vehicles (5 years)	3,090
Buildings and leasehold improvements (30 years)	409
Other (3—5 years)	59
Intangible assets:
Customer relationships (15 years)	23,560
Trade names (indefinite life)	2,410
Non-compete agreements	1,520
Goodwill	15,782
Assumed liabilities	(4,399		)
Consideration paid	$	62,588

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

North American Combination

On February 3, 2012, we completed a business combination with North American in order to expand our retail propane operations. The combination was funded with cash of $69.8 million. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $1.6 million of costs related to the North American acquisition.

The assets acquired from North American include retail propane and distillate operations in Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, Pennsylvania, and Rhode Island.

The following table presents the allocation of the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable - trade	$	10,338
Inventories	3,437
Prepaid expenses and other current assets	282
Property, plant and equipment:
Land	2,251
Retail propane equipment (15—20 years)	24,790
Natural gas liquids terminal assets (15—20 years)	1,044
Vehicles (5—15 years)	5,819
Buildings and leasehold improvements (30 years)	2,386
Other (3—5 years)	634
Intangible assets:
Customer relationships (10 years)	12,600
Trade names (10 years)	2,700
Non-compete agreements (3 years)	700
Goodwill	13,978
Assumed liabilities	(11,129		)
Consideration paid	$	69,830

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

Other Acquisitions

During the year ended March 31, 2012, we closed three additional acquisitions for cash payments of $6.4 million on a combined basis. We also assumed $0.6 million in long-term debt in the form of non-compete agreements. These operations have been included in our results of operations since the acquisition dates, and have not been material to our consolidated financial statements.

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Quarterly Financial Data (Unaudited)

12 Months Ended

Mar. 31, 2014

Quarterly Financial Data (Unaudited)

Quarterly Financial Data (Unaudited)

Note 16 — Quarterly Financial Data (Unaudited)

Our summarized unaudited quarterly financial data is presented below. The computation of net income per common and subordinated unit is done separately by quarter and year. The total of net income per common and subordinated unit of the individual quarters may not equal the net income per common and subordinated unit for the year, due primarily to the income allocation between the general partner and limited partners and variations in the weighted average units outstanding used in computing such amounts.

Our retail propane segment’s business is seasonal due to weather conditions in our service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Our liquids segment is also subject to seasonal fluctuations, as demand for propane and butane is typically higher during the winter months. Our operating revenues from our other segments are less weather sensitive. Additionally, the acquisitions described in Note 4 impact the comparability of the quarterly information within the year, and year to year.

	Quarter Ended										Year Ended
	June 30,			September 30,			December 31,		March 31,		March 31,
	2013			2013			2013		2014		2014
	(in thousands, except unit and per unit data)
Total revenues	$	1,385,957		$	1,593,937		$	2,743,445	$	3,975,935	$	9,699,274
Total cost of sales	$	1,303,076		$	1,488,850		$	2,576,029	$	3,764,744	$	9,132,699
Net income (loss)	$	(17,508	)	$	(932	)	$	24,052	$	43,146	$	48,758
Net income (loss) attributable to parent equity	$	(17,633	)	$	(941	)	$	23,898	$	42,331	$	47,655
Earnings (loss) per unit, basic and diluted -
Common units	$	(0.35	)	$	(0.05	)	$	0.27	$	0.46	$	0.51
Subordinated units	$	(0.46	)	$	(0.09	)	$	0.23	$	0.46	$	0.32
Weighted average common units outstanding - basic and diluted	47,703,313			58,909,389			67,941,726		73,421,309		61,970,471
Weighted average subordinated outstanding units - basic and diluted	5,919,346			5,919,346			5,919,346		5,919,346		5,919,346

	Quarter Ended									Year Ended
	June 30,			September 30,		December 31,		March 31,		March 31,
	2012			2012		2012		2013		2013
	(in thousands, except unit and per unit data)
Total revenues	$	326,436		$	1,135,510	$	1,338,208	$	1,617,613	$	4,417,767
Total cost of sales	$	298,985		$	1,053,690	$	1,204,545	$	1,481,890	$	4,039,110
Net income (loss)	$	(24,710	)	$	10,082	$	40,477	$	22,341	$	48,190
Net income (loss) attributable to parent equity	$	(24,650	)	$	10,073	$	40,176	$	22,341	$	47,940
Earnings (loss) per unit, basic and diluted -
Common units	$	(0.76	)	$	0.18	$	0.75	$	0.39	$	0.96
Subordinated units	$	(0.77	)	$	0.18	$	0.75	$	0.39	$	0.93
Weighted average common units outstanding - basic and diluted	26,529,133			44,831,836		46,364,381		47,665,015		41,353,574
Weighted average subordinated outstanding units - basic and diluted	5,919,346			5,919,346		5,919,346		5,919,346		5,919,346

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Fair Value of Financial Instruments

12 Months Ended

Mar. 31, 2014

Fair Value of Financial Instruments

Fair Value of Financial Instruments

Note 12 — Fair Value of Financial Instruments

Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values, due to their short-term nature. We believe the carrying amounts of our long-term debt instruments, including the Revolving Credit Facility and the Senior Notes, approximate their fair values, as we do not believe market conditions have changed materially since we entered into these debt agreements.

Commodity Derivatives

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2014:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	4,990		$	(3,258	)
Level 2 measurements	49,605			(43,303		)
	54,595			(46,561		)
Netting of counterparty contracts(1)	(4,347		)	4,347
Cash collateral provided or held	456			—
Commodity contracts reported on consolidated balance sheet	$	50,704		$	(42,214	)

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

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2013:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	947		$	(3,324	)
Level 2 measurements	9,911			(13,280		)
	10,858			(16,604		)
Netting of counterparty contracts(1)	(3,503		)	3,503
Cash collateral provided or held	(1,760		)	400
Commodity contracts reported on consolidated balance sheet	$	5,595		$	(12,701	)

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

The commodity derivative assets (liabilities) are reported in the following accounts on the consolidated balance sheets:

	March 31,
	2014			2013
	(in thousands)
Prepaid expenses and other current assets	$	50,704		$	5,551
Other noncurrent assets	—			44
Accrued expenses and other payables	(42,214		)	(12,701		)
Net asset (liability)	$	8,490		$	(7,106	)

The following table sets forth our open commodity derivative contract positions at March 31, 2014 and 2013. We do not account for these derivatives as hedges.

Contracts	Settlement Period	Total  NotionalUnits(Barrels)		Fair Valueof Net Assets(Liabilities)
		(in thousands)
At March 31, 2014 -
Cross-commodity (1)	April 2014 – March 2015	140		$	(1,876	)
Crude oil fixed-price (2)	April 2014 – March 2015	(1,600	)	(2,796		)
Crude oil index (3)	April 2014 – December 2015	3,598		6,099
Propane fixed-price (4)	April 2014 – March 2015	60		1,753
Refined products fixed-price (5)	April 2014 – July 2014	732		560
Renewable products fixed-price (6)	April 2014 – July 2014	106		4,084
Other	April 2014	—		210
				8,034
Net cash collateral provided				456
Net value of commodity derivatives on consolidated balance sheet				$	8,490
At March 31, 2013 -
Cross-commodity (1)	April 2013 - March 2014	430		$	(10,208	)
Crude oil fixed-price (2)	April 2013 - March 2014	(144	)	1,033
Crude oil index (3)	April 2013 - June 2014	(91	)	153
Propane fixed-price (4)	April 2013 - March 2014	(282	)	3,197
Other	May 2013 - June 2013	8		79
				(5,746		)
Net cash collateral held				(1,360		)
Net value of commodity derivatives on consolidated balance sheet				$	(7,106	)

(1) Cross-commodity — Our operating segments may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. The contracts listed in this table as “Cross-commodity” represent derivatives we have entered into as economic hedges against the risk of one commodity price moving relative to another commodity price.

(2) Crude oil fixed-price — Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Crude oil fixed-price” represent derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding the inventory.

(3) Crude oil index — Our crude oil logistics segment may purchase or sell crude oil where the underlying contract pricing mechanisms are tied to different crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as “Crude oil index” represent derivatives we have entered into as an economic hedge against the risk of one crude oil index moving relative to another crude oil index.

(4) Propane fixed-price — Our liquids segment routinely purchases inventory during the warmer months and stores the inventory for sale in the colder months. The contracts listed in this table as “Propane fixed-price” represent derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

(5) Refined products fixed-price — Our refined products segment routinely purchases refined products inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Refined products fixed-price” represent derivatives we have entered into as an economic hedge against the risk that refined product prices will decline while we are holding the inventory.

(6) Renewable products fixed-price — Our renewables segment routinely purchases biodiesel and ethanol inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Renewable products fixed-price” represent derivatives we have entered into as an economic hedge against the risk that biodiesel or ethanol prices will decline while we are holding the inventory.

We recorded the following net gains (losses) from our commodity derivatives to cost of sales:

Year Ended March 31,
2014	$	(43,655	)
2013	(4,381		)
2012	5,676

Credit Risk

We maintain credit policies with regard to our counterparties on the derivative financial instruments that we believe minimize our overall credit risk, including an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty.

We may enter into industry standard master netting agreements and may enter into cash collateral agreements requiring the counterparty to deposit funds into a brokerage margin account. The netting agreements reduce our credit risk by providing for net settlement of any offsetting positive and negative exposures with counterparties. The cash collateral agreements reduce the level of our net counterparty credit risk because the amount of collateral represents additional funds that we may access to net settle positions due us, and the amount of collateral adjusts each day in response to changes in the market value of counterparty derivatives.

Our counterparties consist primarily of financial institutions and energy companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

As is customary in the crude oil industry, we generally receive payment from customers on a monthly basis. As a result, receivables from individual customers in our crude oil logistics are typically higher than the receivables from customers of our other segments.

Failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated statements of financial position and recognized in our net income.

Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31, 2014, we have $922.0 million of outstanding borrowings under our Revolving Credit Facility at a rate of 1.98%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.2 million on the $922.0 million of outstanding borrowings on the revolving credit facility at March 31, 2014.

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Long-Term Obligations

12 Months Ended

Mar. 31, 2014

Long-Term Obligations

Long-Term Obligations

Note 8 — Long-Term Obligations

Our long-term debt consists of the following:

	March 31,
	2014		2013
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	532,500	$	441,500
Working capital loans	389,500		36,000
Senior notes	250,000		250,000
Unsecured notes	450,000		—
Other notes payable	14,914		21,562
	1,636,914		749,062
Less - current maturities	7,080		8,626
Long-term debt	$	1,629,834	$	740,436

Credit Agreement

On June 19, 2012, we entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”).

The Working Capital Facility had a total capacity of $935.5 million for cash borrowings and letters of credit at March 31, 2014. At March 31, 2014, we had outstanding cash borrowings of $389.5 million and outstanding letters of credit of $270.6 million on the Working Capital Facility. The Expansion Capital Facility had a total capacity of $785.5 million for cash borrowings at March 31, 2014. At March 31, 2014, we had outstanding cash borrowings of $532.5 million on the Expansion Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time.

The commitments under the Credit Agreement expire on November 5, 2018. We have the right to pre-pay outstanding borrowings under the Credit Agreement without incurring any penalties, and pre-payments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At March 31, 2014, the interest rate in effect on outstanding LIBOR borrowings was 1.91%, calculated as the LIBOR rate of 0.16% plus a margin of 1.75%. At March 31, 2014, the interest rate in effect on letters of credit was 1.75%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At March 31, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	532,500	1.91	%
Working capital facility —
LIBOR borrowings	358,000		1.91	%
Base rate borrowings	31,500		4.00	%

The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our “leverage ratio,” as defined in the Credit Agreement, cannot exceed 4.25 to 1.0 at any quarter end. At March 31, 2014, our leverage ratio was approximately 3 to 1. The Credit Agreement also specifies that our “interest coverage ratio,” as defined in the Credit Agreement, cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At March 31, 2014, our interest coverage ratio was approximately 7 to 1.

The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

At March 31, 2014, we were in compliance with the covenants under the Credit Agreement.

Senior Notes

On June 19, 2012, we entered into a note purchase agreement (as amended, the “Note Purchase Agreement”) whereby we issued $250.0 million of senior notes in a private placement (the “Senior Notes”). The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The Senior Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which are described above.

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) non-payment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the Senior Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the Senior Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding Senior Notes of any series may declare all of the Senior Notes of such series to be due and payable immediately.

At March 31, 2014, we were in compliance with the covenants under the Note Purchase Agreement and the Senior Notes.

Unsecured Notes

On October 16, 2013, we issued $450.0 million of 6.875% senior unsecured notes (the “Unsecured Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $438.4 million, after the initial purchasers’ discount of $10.1 million and estimated offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

The Unsecured Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the Unsecured Notes prior to the maturity date, although we would be required to pay a premium for early redemption.

The purchase agreement and the indenture governing the Unsecured Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At March 31, 2014, we were in compliance with the covenants under the Unsecured Notes.

We also entered into a registration rights agreement whereby we have committed to exchange the Unsecured Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the Unsecured Notes on or before October 16, 2014. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the Unsecured Notes.

Other Notes Payable

We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing, which have interest rates ranging from 2.1% to 4.9% at March 31, 2014.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at March 31, 2014:

	Revolving						Other
	Credit		Senior		Unsecured		Notes
Year Ending March 31,	Facility		Notes		Notes		Payable		Total
					(in thousands)
2015	$	—	$	—	$	—	$	7,081	$	7,081
2016	—		—		—		3,614		3,614
2017	—		—		—		2,356		2,356
2018	—		25,000		—		1,449		26,449
2019	922,000		50,000		—		238		972,238
Thereafter	—		175,000		450,000		176		625,176
	$	922,000	$	250,000	$	450,000	$	14,914	$	1,636,914

Previous Credit Facilities

On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as “Loss on early extinguishment of debt” in our consolidated statement of operations for the year ended March 31, 2013.

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Acquisitions (Details 15) (USD $)	12 Months Ended				12 Months Ended								0 Months Ended			12 Months Ended					12 Months Ended			12 Months Ended			12 Months Ended				12 Months Ended
	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Retail propane equipment Minimum	Mar. 31, 2014 Retail propane equipment Maximum	Mar. 31, 2014 Natural gas liquids terminal assets Minimum	Mar. 31, 2014 Natural gas liquids terminal assets Maximum	Mar. 31, 2014 Vehicles Minimum	Mar. 31, 2014 Vehicles Maximum	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Feb. 03, 2012 North American	Mar. 31, 2014 North American	Mar. 31, 2012 North American	Mar. 31, 2014 North American Customer relationships	Mar. 31, 2014 North American Trade names	Mar. 31, 2014 North American Non-compete agreements	Mar. 31, 2014 North American Land	Mar. 31, 2014 North American Retail propane equipment	Mar. 31, 2014 North American Retail propane equipment Minimum	Mar. 31, 2014 North American Retail propane equipment Maximum	Mar. 31, 2014 North American Natural gas liquids terminal assets	Mar. 31, 2014 North American Natural gas liquids terminal assets Minimum	Mar. 31, 2014 North American Natural gas liquids terminal assets Maximum	Mar. 31, 2014 North American Vehicles	Mar. 31, 2014 North American Vehicles Minimum	Mar. 31, 2014 North American Vehicles Maximum	Mar. 31, 2014 North American Buildings and leasehold improvements	Mar. 31, 2014 North American Other	Mar. 31, 2014 North American Other Minimum	Mar. 31, 2014 North American Other Maximum
Acquisitions
Cash paid to acquire ownership interests	$ 14,000,000												$ 69,800,000
General and administrative expense															1,600,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade														10,338,000
Inventories														3,437,000
Prepaid expenses and other current assets														282,000
Property, plant and equipment																			2,251,000	24,790,000			1,044,000			5,819,000			2,386,000	634,000
Useful life of property, plant and equipment					2 years	30 years	2 years	30 years	3 years	25 years	3 years	40 years									15 years	20 years		15 years	20 years		5 years	15 years	30 years		3 years	5 years
Intangible assets																12,600,000	2,700,000	700,000
Useful life of intangible assets																10 years	10 years	3 years
Goodwill	555,220,000	1,107,006,000	167,245,000	8,568,000										13,978,000
Assumed liabilities														(11,129,000)
Fair value of net assets acquired														$ 69,830,000

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Goodwill

12 Months Ended

Mar. 31, 2014

Goodwill

Goodwill

Note 6 — Goodwill

The changes in the balance of goodwill were as follows:

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Beginning of period, as retrospectively adjusted (Note 2)	$	555,220	$	167,245	$	8,568
Acquisitions	551,786		387,975		158,677
End of period, as retrospectively adjusted (Note 2)	$	1,107,006	$	555,220	$	167,245

Goodwill by reportable segment is as follows:

	March 31,
	2014		2013
	(in thousands)
Crude oil logistics	$	606,383	$	246,345
Water solutions	262,203		109,470
Liquids	90,135		87,136
Retail propane	114,285		112,269
Refined products	22,000		—
Renewables	12,000		—
	$	1,107,006	$	555,220

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Intangible Assets

12 Months Ended

Mar. 31, 2014

Intangible Assets

Intangible Assets

Note 7 — Intangible Assets

Our intangible assets consist of the following:

		March 31, 2014				March 31, 2013
						Gross Carrying
	Amortizable	Gross Carrying		Accumulated		Amount		Accumulated
	Lives	Amount		Amortization		(Note 2)		Amortization
				(in thousands)
Amortizable -
Customer relationships (1)	3–20 years	$	697,405	$	83,261	$	405,160	$	30,959
Water facility development agreement	5 years	14,000		2,100		—		—
Lease and other agreements	5–8 years	23,920		13,190		15,210		7,018
Non-compete agreements	2–7 years	14,161		6,388		11,509		2,871
Trade names	1–10 years	15,489		3,081		2,784		326
Debt issuance costs	5–10 years	44,089		8,708		19,494		2,981
Total amortizable		809,064		116,728		454,157		44,155
Non-amortizable -
Trade names		22,620				31,430
Total		$	831,684	$	116,728	$	485,587	$	44,155

(1) The weighted-average remaining amortization period for customer relationship intangible assets is approximately nine years.

Amortization expense was as follows:

	Year Ended March 31,
Recorded in	2014		2013		2012
	(in thousands)
Depreciation and amortization	$	60,855	$	29,657	$	4,538
Cost of sales	6,172		5,285		800
Interest expense	5,727		3,375		1,277
Loss on early extinguishment of debt	—		5,769		—
	$	72,754	$	44,086	$	6,615

Expected amortization of our intangible assets is as follows (in thousands):

Year Ending March 31,
2015	$	88,970
2016	83,449
2017	76,826
2018	72,857
2019	66,826
Thereafter	303,408
	$	692,336

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Income Taxes

12 Months Ended

Mar. 31, 2014

Income Taxes

Income Taxes

Note 9 — Income Taxes

We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner’s basis in the Partnership.

We have certain taxable corporate subsidiaries in the United States and Canada. In addition, our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales.

A publicly traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income for each of the calendar years since our IPO.

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in the consolidated financial statements at March 31, 2014.

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Goodwill (Details 2) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2011
Goodwill by segment
Goodwill	$ 1,107,006	$ 555,220	$ 167,245	$ 8,568
Crude oil logistics
Goodwill by segment
Goodwill	606,383	246,345
Water solutions
Goodwill by segment
Goodwill	262,203	109,470
Liquids
Goodwill by segment
Goodwill	90,135	87,136
Retail propane
Goodwill by segment
Goodwill	114,285	112,269
Refined products
Goodwill by segment
Goodwill	22,000
Renewables
Goodwill by segment
Goodwill	$ 12,000

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Intangible Assets (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Amortization related to intangible assets
Amortization expense	$ 72,754	$ 44,086	$ 6,615
Future amortization expense of intangible assets
2015	88,970
2016	83,449
2017	76,826
2018	72,857
2019	66,826
Thereafter	303,408
Total	692,336
Depreciation and amortization
Amortization related to intangible assets
Amortization expense	60,855	29,657	4,538
Cost of sales
Amortization related to intangible assets
Amortization expense	6,172	5,285	800
Interest expense
Amortization related to intangible assets
Amortization expense	5,727	3,375	1,277
Loss on early extinguishment of debt
Amortization related to intangible assets
Amortization expense		$ 5,769

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Goodwill (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Goodwill
Goodwill at the beginning of the period	$ 555,220	$ 167,245	$ 8,568
Acquisitions	551,786	387,975	158,677
Goodwill at the end of the period	$ 1,107,006	$ 555,220	$ 167,245

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Mar. 31, 2014

Fair Value of Financial Instruments

Schedule of estimated fair value measurements of assets and liabilities

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2014:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	4,990		$	(3,258	)
Level 2 measurements	49,605			(43,303		)
	54,595			(46,561		)
Netting of counterparty contracts(1)	(4,347		)	4,347
Cash collateral provided or held	456			—
Commodity contracts reported on consolidated balance sheet	$	50,704		$	(42,214	)

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

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2013:

	Derivative			Derivative
	Assets			Liabilities
	(in thousands)
Level 1 measurements	$	947		$	(3,324	)
Level 2 measurements	9,911			(13,280		)
	10,858			(16,604		)
Netting of counterparty contracts(1)	(3,503		)	3,503
Cash collateral provided or held	(1,760		)	400
Commodity contracts reported on consolidated balance sheet	$	5,595		$	(12,701	)

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

Schedule of location of commodity derivative assets (liabilities) reported on the consolidated balance sheets

	March 31,
	2014			2013
	(in thousands)
Prepaid expenses and other current assets	$	50,704		$	5,551
Other noncurrent assets	—			44
Accrued expenses and other payables	(42,214		)	(12,701		)
Net asset (liability)	$	8,490		$	(7,106	)

Schedule of open commodity derivative contract positions

Contracts	Settlement Period	Total  NotionalUnits(Barrels)		Fair Valueof Net Assets(Liabilities)
		(in thousands)
At March 31, 2014 -
Cross-commodity (1)	April 2014 – March 2015	140		$	(1,876	)
Crude oil fixed-price (2)	April 2014 – March 2015	(1,600	)	(2,796		)
Crude oil index (3)	April 2014 – December 2015	3,598		6,099
Propane fixed-price (4)	April 2014 – March 2015	60		1,753
Refined products fixed-price (5)	April 2014 – July 2014	732		560
Renewable products fixed-price (6)	April 2014 – July 2014	106		4,084
Other	April 2014	—		210
				8,034
Net cash collateral provided				456
Net value of commodity derivatives on consolidated balance sheet				$	8,490
At March 31, 2013 -
Cross-commodity (1)	April 2013 - March 2014	430		$	(10,208	)
Crude oil fixed-price (2)	April 2013 - March 2014	(144	)	1,033
Crude oil index (3)	April 2013 - June 2014	(91	)	153
Propane fixed-price (4)	April 2013 - March 2014	(282	)	3,197
Other	May 2013 - June 2013	8		79
				(5,746		)
Net cash collateral held				(1,360		)
Net value of commodity derivatives on consolidated balance sheet				$	(7,106	)

(1) Cross-commodity — Our operating segments may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. The contracts listed in this table as “Cross-commodity” represent derivatives we have entered into as economic hedges against the risk of one commodity price moving relative to another commodity price.

(2) Crude oil fixed-price — Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Crude oil fixed-price” represent derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding the inventory.

(3) Crude oil index — Our crude oil logistics segment may purchase or sell crude oil where the underlying contract pricing mechanisms are tied to different crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as “Crude oil index” represent derivatives we have entered into as an economic hedge against the risk of one crude oil index moving relative to another crude oil index.

(4) Propane fixed-price — Our liquids segment routinely purchases inventory during the warmer months and stores the inventory for sale in the colder months. The contracts listed in this table as “Propane fixed-price” represent derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

(5) Refined products fixed-price — Our refined products segment routinely purchases refined products inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Refined products fixed-price” represent derivatives we have entered into as an economic hedge against the risk that refined product prices will decline while we are holding the inventory.

(6) Renewable products fixed-price — Our renewables segment routinely purchases biodiesel and ethanol inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “Renewable products fixed-price” represent derivatives we have entered into as an economic hedge against the risk that biodiesel or ethanol prices will decline while we are holding the inventory.

Schedule of net gains (losses) from entity's commodity derivatives to cost of sales

Year Ended March 31,
2014	$	(43,655	)
2013	(4,381		)
2012	5,676

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Acquisitions (Details 6) (USD $)	12 Months Ended				0 Months Ended		12 Months Ended					12 Months Ended						0 Months Ended	12 Months Ended	0 Months Ended			1 Months Ended			1 Months Ended				1 Months Ended			1 Months Ended					1 Months Ended					1 Months Ended			0 Months Ended
	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2012	Mar. 31, 2011	Jun. 19, 2012 General partner	Jun. 19, 2012 General partner Common units	Mar. 31, 2014 Vehicles Minimum	Mar. 31, 2014 Vehicles Maximum	Mar. 31, 2014 Water treatment facilities and equipment Minimum	Mar. 31, 2014 Water treatment facilities and equipment Maximum	Jun. 19, 2012 Crude oil tanks and related equipment	Mar. 31, 2014 Crude oil tanks and related equipment Minimum	Mar. 31, 2014 Crude oil tanks and related equipment Maximum	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Mar. 31, 2014 Information technology equipment Minimum	Mar. 31, 2014 Information technology equipment Maximum	Jun. 19, 2012 High Sierra	Mar. 31, 2013 High Sierra	Jun. 19, 2012 High Sierra Common units	Jun. 19, 2012 High Sierra Trade names	Jun. 19, 2012 High Sierra Customer relationships	Jun. 30, 2012 High Sierra Customer relationships Minimum	Jun. 30, 2012 High Sierra Customer relationships Maximum	Jun. 19, 2012 High Sierra Lease and other agreements	Jun. 30, 2012 High Sierra Lease and other agreements Minimum	Jun. 30, 2012 High Sierra Lease and other agreements Maximum	Jun. 19, 2012 High Sierra Land	Jun. 19, 2012 High Sierra Vehicles	Jun. 30, 2012 High Sierra Vehicles Minimum	Jun. 30, 2012 High Sierra Vehicles Maximum	Jun. 19, 2012 High Sierra Water treatment facilities and equipment	Jun. 30, 2012 High Sierra Water treatment facilities and equipment Minimum	Jun. 30, 2012 High Sierra Water treatment facilities and equipment Maximum	Jun. 30, 2012 High Sierra Crude oil tanks and related equipment Minimum	Jun. 30, 2012 High Sierra Crude oil tanks and related equipment Maximum	Jun. 19, 2012 High Sierra Buildings and leasehold improvements	Jun. 30, 2012 High Sierra Buildings and leasehold improvements Minimum	Jun. 30, 2012 High Sierra Buildings and leasehold improvements Maximum	Jun. 30, 2012 High Sierra Information technology equipment	Jun. 19, 2012 High Sierra Information technology equipment	Jun. 19, 2012 High Sierra Other equipment	Jun. 30, 2012 High Sierra Other equipment Minimum	Jun. 30, 2012 High Sierra Other equipment Maximum	Jun. 19, 2012 High Sierra Construction in progress	Jun. 19, 2012 High Sierra Energy, LP	Jun. 19, 2012 High Sierra Energy, LP Common units	Jun. 19, 2012 High Sierra Energy, LP General partner	Jun. 19, 2012 High Sierra Energy GP, LLC General partner
Acquisitions
Cash paid to acquire ownership interests	$ 14,000,000																	$ 239,251,000																												$ 91,800,000		$ 50,000,000	$ 50,000,000
Cash acquired																																														5,000,000
Number of common units issued to acquire business (in shares)																																															18,018,468
Value of common units issued using the closing price of units on the New York Stock Exchange on the merger date																																															406,800,000
Amount of additional consideration payable																																														97,400,000
Amount paid					50,000,000
Common units issued					2,685,042	2,685,042																																								18,018,468
Value of common units issued						8,000,000
Fair value of common units issued						60,600,000
General and administrative expense																			3,700,000
Equity issuance costs																			600,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade																		395,311,000
Inventories																		43,575,000
Accounts receivable - affiliates																		7,724,000
Derivative assets																		10,646,000
Forward purchase and sale contracts																		34,717,000
Prepaid expenses and other current assets																		11,131,000
Property, plant and equipment											17,851,000																	5,723,000	22,507,000			64,057,000					19,145,000				5,541,000	11,010,000			9,621,000
Useful life							3 years	25 years	3 years	30 years		2 years	40 years	3 years	40 years	3 years	7 years													5 years	10 years		3 years	30 years	2 years	15 years		5 years	30 years	3 years			2 years	30 years
Intangible assets																					13,000,000	245,000,000			12,400,000
Useful life of intangible assets																							5 years	17 years		1 year	10 years
Goodwill	555,220,000	1,107,006,000	167,245,000	8,568,000														220,884,000
Assumed liabilities:
Accounts payable - trade																		(417,369,000)
Accounts payable - affiliates																		(9,014,000)
Advance payments received from customers																		(1,237,000)
Accrued expenses and other payables																		(35,611,000)
Derivative liabilities																		(5,726,000)
Forward purchase and sale contracts																		(18,680,000)
Long-term debt																		(2,537,000)
Other noncurrent liabilities																		(3,224,000)
Noncontrolling interest in consolidated subsidiary																		(2,400,000)
Fair value of net assets acquired																		654,045,000
Consideration paid for acquisition
Cash paid, net of cash acquired	14,000,000																	239,251,000																												91,800,000		50,000,000	50,000,000
Value of common units issued																				414,794,000
Total consideration paid																		$ 654,045,000

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Disposals and Impairments

12 Months Ended

Mar. 31, 2014

Disposals and Impairments

Disposals and Impairments

Note 14 — Disposals and Impairments

We acquired Gavilon Energy in December 2013, which operated a natural gas marketing business. During March 2014, we assigned all of the storage and transportation contracts of the natural gas marketing business to a third party. Since these contracts were at unfavorable terms relative to current market conditions, we paid $44.8 million to assign these contracts. We recorded a liability of $50.8 million related to these storage and transportation contracts in the acquisition accounting, and we amortized $6.0 million of this balance through cost of sales during the period from the acquisition date through the date we assigned the contracts. We also assigned all forward purchase and sale contracts and all financial derivative contracts, and thereby wound down the natural gas business. Our consolidated statement of operations for the year ended March 31, 2014 includes $1.4 million of operating income related to the natural gas business, which is reported within “corporate and other” in the segment disclosures in Note 13.

We acquired High Sierra in June 2012, which operated a compressor leasing business. We sold the compressor leasing business in February 2014 for $10.8 million (net of the amount due to the owner of the noncontrolling interest in the business). We recorded a gain on the sale of the business of $4.4 million, $1.6 million of which was attributable to the disposal of the noncontrolling interest. We reported the gain as a reduction to operating expenses in our consolidated statement of operations. Our consolidated statement of operations for the year ended March 31, 2014 includes $2.3 million of operating income related to the compressor leasing business, which is reported within “corporate and other” in the segment disclosures in Note 13.

During the year ended March 31, 2014, we recorded an impairment of $5.3 million to the property, plant and equipment of one of our natural gas liquids terminals. This loss is reported within operating expenses of our liquids segment.

During the year ended March 31, 2014, two of our water solutions facilities experienced damage to their property, plant and equipment as a result of lightning strikes. We recorded a write-down to property, plant and equipment of $1.5 million related to these incidents, which is reported within operating expenses in our consolidated statement of operations.

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Earnings per Unit (Tables)

12 Months Ended

Mar. 31, 2014

Earnings per Unit

Schedule of earnings per common and subordinated unit

	Year Ended March 31,
	2014			2013			2012
	(in thousands, except unit and per unit amounts)
Income attributable to parent equity	$	47,655		$	47,940		$	7,876
Income allocated to general partner (1)	(14,148		)	(2,917		)	(8		)
Income attributable to limited partners	$	33,507		$	45,023		$	7,868
Income allocated to:
Common unitholders	$	31,614		$	39,517		$	4,859
Subordinated unitholders	$	1,893		$	5,506		$	3,009
Weighted average common units outstanding	61,970,471			41,353,574			15,169,983
Weighted average subordinated units outstanding	5,919,346			5,919,346			5,175,384
Income per common unit - basic and diluted	$	0.51		$	0.96		$	0.32
Income per subordinated unit - basic and diluted	$	0.32		$	0.93		$	0.58

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

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Acquisitions (Details 4) (USD $)	12 Months Ended				12 Months Ended					12 Months Ended					12 Months Ended		12 Months Ended			12 Months Ended			12 Months Ended				12 Months Ended
	Mar. 31, 2013 item	Mar. 31, 2014	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Vehicles Minimum	Mar. 31, 2014 Vehicles Maximum	Mar. 31, 2014 Buildings and leasehold improvements Minimum	Mar. 31, 2014 Buildings and leasehold improvements Maximum	Jun. 19, 2012 Crude oil tanks and related equipment	Mar. 31, 2014 Crude oil tanks and related equipment Minimum	Mar. 31, 2014 Crude oil tanks and related equipment Maximum	Mar. 31, 2014 Crude Oil Logistics item	Mar. 31, 2014 Crude Oil Logistics Customer relationships	Mar. 31, 2014 Crude Oil Logistics Trade names	Mar. 31, 2014 Crude Oil Logistics Non-compete agreements	Mar. 31, 2014 Crude Oil Logistics Vehicles	Mar. 31, 2014 Crude Oil Logistics Vehicles Minimum	Mar. 31, 2014 Crude Oil Logistics Vehicles Maximum	Mar. 31, 2014 Crude Oil Logistics Buildings and leasehold improvements	Mar. 31, 2014 Crude Oil Logistics Buildings and leasehold improvements Minimum	Mar. 31, 2014 Crude Oil Logistics Buildings and leasehold improvements Maximum	Mar. 31, 2014 Crude Oil Logistics Crude oil tanks and related equipment	Mar. 31, 2014 Crude Oil Logistics Crude oil tanks and related equipment Minimum	Mar. 31, 2014 Crude Oil Logistics Crude oil tanks and related equipment Maximum	Mar. 31, 2014 Crude Oil Logistics Barges and towboats	Mar. 31, 2014 Crude Oil Logistics Other	Mar. 31, 2014 Crude Oil Logistics Other Minimum	Mar. 31, 2014 Crude Oil Logistics Other Maximum
Acquisitions
Number of business combination agreements	2											2
Common units issued												175,211
General and administrative expense												$ 100,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable - trade												1,235,000
Inventories												1,021,000
Prepaid expenses and other current assets												54,000
Property, plant and equipment									17,851,000							2,977,000			280,000			3,462,000			20,065,000	53,000
Useful life of property, plant and equipment					3 years	25 years	3 years	40 years		2 years	40 years						5 years	10 years		5 years	30 years		2 years	30 years	20 years		3 years	5 years
Intangible assets													6,300,000	530,000	35,000
Useful life of intangible assets													3 years		3 years
Goodwill	555,220,000	1,107,006,000	167,245,000	8,568,000								37,867,000
Accounts payable - trade												(665,000)
Accrued expenses and other payables												(124,000)
Fair value of net assets acquired												73,090,000
Consideration paid for acquisition
Cash paid, net of cash acquired	14,000,000											67,842,000
Value of common units issued												5,248,000
Total consideration paid												$ 73,090,000

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Significant Accounting Policies (Details 2) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Supplemental cash flow information
Interest paid, exclusive of debt issuance costs and letter of credit fees	$ 31,827	$ 27,384	$ 4,966
Income taxes paid	1,639	1,027	430
Accounts receivable
Allowance for Doubtful Accounts	2,822	1,760
Changes in the allowance for doubtful accounts
Allowance for doubtful accounts, beginning of period	1,760
Provision for doubtful accounts	2,172	1,315	1,049
Allowance for doubtful accounts, end of period	2,822	1,760
Accounts Receivable - Trade:
Accounts receivable
Gross Receivable	903,726	564,517
Allowance for Doubtful Accounts	2,822	1,760	818
Changes in the allowance for doubtful accounts
Allowance for doubtful accounts, beginning of period	1,760	818	161
Provision for doubtful accounts	2,172	1,315	1,049
Write off of uncollectible accounts	(1,110)	(373)	(392)
Allowance for doubtful accounts, end of period	2,822	1,760	818
Accounts Receivable - Trade: | Crude oil logistics
Accounts receivable
Gross Receivable	411,090	360,589
Allowance for Doubtful Accounts	105	11
Changes in the allowance for doubtful accounts
Allowance for doubtful accounts, end of period	105	11
Accounts Receivable - Trade: | Water solutions
Accounts receivable
Gross Receivable	25,700	9,618
Allowance for Doubtful Accounts	405	29
Changes in the allowance for doubtful accounts
Allowance for doubtful accounts, end of period	405	29
Accounts Receivable - Trade: | Liquids
Accounts receivable
Gross Receivable	192,529	144,267
Allowance for Doubtful Accounts	617	76
Changes in the allowance for doubtful accounts
Allowance for doubtful accounts, end of period	617	76
Accounts Receivable - Trade: | Retail propane
Accounts receivable
Gross Receivable	75,606	49,233
Allowance for Doubtful Accounts	1,667	1,644
Changes in the allowance for doubtful accounts
Allowance for doubtful accounts, end of period	1,667	1,644
Accounts Receivable - Trade: | Refined products
Accounts receivable
Gross Receivable	105,670
Accounts Receivable - Trade: | Renewables
Accounts receivable
Gross Receivable	54,466
Accounts Receivable - Trade: | Other
Accounts receivable
Gross Receivable	38,665	810
Allowance for Doubtful Accounts	28
Changes in the allowance for doubtful accounts
Allowance for doubtful accounts, end of period	$ 28

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Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Net income	$ 48,758	$ 48,190	$ 7,864
Other comprehensive loss, net of tax	(260)	(7)	(25)
Comprehensive income	$ 48,498	$ 48,183	$ 7,839

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Earnings per Unit

12 Months Ended

Mar. 31, 2014

Earnings per Unit

Earnings per Unit

Note 3 — Earnings per Unit

Our earnings per common and subordinated unit were computed as follows:

	Year Ended March 31,
	2014			2013			2012
	(in thousands, except unit and per unit amounts)
Income attributable to parent equity	$	47,655		$	47,940		$	7,876
Income allocated to general partner (1)	(14,148		)	(2,917		)	(8		)
Income attributable to limited partners	$	33,507		$	45,023		$	7,868
Income allocated to:
Common unitholders	$	31,614		$	39,517		$	4,859
Subordinated unitholders	$	1,893		$	5,506		$	3,009
Weighted average common units outstanding	61,970,471			41,353,574			15,169,983
Weighted average subordinated units outstanding	5,919,346			5,919,346			5,175,384
Income per common unit - basic and diluted	$	0.51		$	0.96		$	0.32
Income per subordinated unit - basic and diluted	$	0.32		$	0.93		$	0.58

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

The restricted units described in Note 11 were antidilutive for the years ended March 31, 2014, 2013, and 2012.

XML

Acquisitions (Details 13) (USD $)	12 Months Ended				12 Months Ended			0 Months Ended		12 Months Ended		0 Months Ended			0 Months Ended				0 Months Ended
	Mar. 31, 2013	Mar. 31, 2014	Mar. 31, 2012	Mar. 31, 2011	Mar. 31, 2014 Natural gas liquids terminal assets Minimum	Mar. 31, 2014 Natural gas liquids terminal assets Maximum	Nov. 01, 2011 NGL Energy Holdings, LLC SemStream	Nov. 01, 2011 SemStream gal item bbl	Mar. 31, 2012 SemStream	Mar. 31, 2012 SemStream Maximum	Nov. 01, 2011 SemStream Customer relationships	Nov. 01, 2011 SemStream Customer relationships Minimum	Nov. 01, 2011 SemStream Customer relationships Maximum	Nov. 01, 2011 SemStream Lease contracts	Nov. 01, 2011 SemStream Lease contracts Minimum	Nov. 01, 2011 SemStream Lease contracts Maximum	Nov. 01, 2011 SemStream Land	Nov. 01, 2011 SemStream Natural gas liquids terminal assets	Nov. 01, 2011 SemStream Natural gas liquids terminal assets Minimum	Nov. 01, 2011 SemStream Natural gas liquids terminal assets Maximum	Nov. 01, 2011 SemStream Vehicles and railcars	Nov. 01, 2011 SemStream Other	Nov. 01, 2011 SemStream Common units
Acquisitions
Number of common units issued to acquire business (in shares)																							8,932,031
Cash paid to acquire ownership interests	$ 14,000,000							$ 91,000,000
Value of common units issued to acquire ownership interests																							184,800,000
Issue price of units (in dollars per unit)																							$ (21.07)
Ownership interest acquired in general partner (as a percent)							7.50%
General and administrative expense									700,000
Equity issuance costs										100,000
Number of acquired natural gas liquids terminals								12
Volume of acquired above ground propane storage (in gallons)								12,000,000
Volume of acquired underground leased storage (in barrels)								3,700,000
Number of owned rail cars								350
Number of leased rail cars								12
Estimated fair value of the assets acquired and liabilities assumed
Inventories								104,226,000
Derivative assets								3,578,000
Assets held for sale								3,000,000
Prepaid expenses and other current assets								9,833,000
Property, plant and equipment																	3,470,000	41,434,000			470,000	3,326,000
Useful life of property, plant and equipment					2 years	30 years													20 years	30 years	5 years	5 years
Investment in capital lease								3,112,000
Amortizable intangible assets											31,950,000			1,008,000
Useful life of intangible assets												8 years	15 years		1 year	4 years
Goodwill	555,220,000	1,107,006,000	167,245,000	8,568,000				74,924,000
Assumed current liabilities								(4,591,000)
Fair value of net assets acquired								$ 275,740,000

XML

Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Total revenues (in dollars)	$ 3,975,935	$ 2,743,445	$ 1,593,937	$ 1,385,957	$ 1,617,613	$ 1,338,208	$ 1,135,510	$ 326,436	$ 9,699,274	$ 4,417,767	$ 1,310,473
Total cost of sales	3,764,744	2,576,029	1,488,850	1,303,076	1,481,890	1,204,545	1,053,690	298,985	9,132,699	4,039,110	1,217,023
Net income (loss)	43,146	24,052	(932)	(17,508)	22,341	40,477	10,082	(24,710)	48,758	48,190	7,864
Net income (loss) attributable to parent equity (in dollars)	$ 42,331	$ 23,898	$ (941)	$ (17,633)	$ 22,341	$ 40,176	$ 10,073	$ (24,650)	$ 47,655	$ 47,940	$ 7,876
Common units
Earnings (loss) per unit, basic and diluted -
Earnings (loss) per unit, basic and diluted -	$ 0.46	$ 0.27	$ (0.05)	$ (0.35)	$ 0.39	$ 0.75	$ 0.18	$ (0.76)	$ 0.51	$ 0.96	$ 0.32
Weighted average units outstanding (in shares)	73,421,309	67,941,726	58,909,389	47,703,313	47,665,015	46,364,381	44,831,836	26,529,133	61,970,471	41,353,574	15,169,983
Subordinated units
Earnings (loss) per unit, basic and diluted -
Earnings (loss) per unit, basic and diluted -	$ 0.46	$ 0.23	$ (0.09)	$ (0.46)	$ 0.39	$ 0.75	$ 0.18	$ (0.77)	$ 0.32	$ 0.93	$ 0.58
Weighted average units outstanding (in shares)	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,175,384

XML

Income Taxes (Details)	12 Months Ended
	Mar. 31, 2014
Income Taxes
Minimum percentage of qualifying income of non-taxable subsidiaries	90.00%

XML

Acquisitions (Tables)

12 Months Ended

Mar. 31, 2014

Acquisitions

Schedule of future amortization of liability

The future amortization of this liability is shown below (in thousands):

Year Ending March 31,
2015	$	6,500
2016	3,260
2017	300

Schedule of pro forma earnings per unit based on the common and subordinated units outstanding

	Year Ended March 31,
	2014			2013
	(in thousands, except per unit amounts)
Revenues	$	9,800,398		$	5,697,988
Net income (loss)	798			(72,171		)
Net loss attributable to limited partners	(14,446		)	(75,251		)
Basic and diluted loss per common unit	(0.18		)	(0.95		)
Basic and diluted loss per subordinated unit	(0.18		)	(0.95		)

Gavilon Energy

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	349,529
Accounts receivable - affiliates	2,564
Inventories	107,430
Prepaid expenses and other current assets	68,322
Property, plant and equipment:
Crude oil tanks and related equipment (3—40 years)	77,429
Vehicles (3 years)	791
Information technology equipment (3—7 years)	4,046
Buildings and leasehold improvements (3—40 years)	7,716
Land	6,427
Linefill and tank bottoms	15,230
Other (7 years)	170
Construction in process	7,190
Goodwill	359,169
Intangible assets:
Customer relationships (10—20 years)	101,600
Lease agreements (1—5 years)	8,700
Investments in unconsolidated entities	178,000
Other noncurrent assets	9,918
Accounts payable - trade	(342,792		)
Accounts payable - affiliates	(2,585		)
Accrued expenses and other payables	(70,999		)
Advance payments received from customers	(10,667		)
Other noncurrent liabilities	(44,740		)
Fair value of net assets acquired	$	832,448

Oilfield Water Lines LP

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	7,268
Inventories	154
Prepaid expenses and other current assets	402
Property, plant and equipment:
Land	710
Water treatment facilities and equipment (3—30 years)	23,173
Vehicles (5—10 years)	8,157
Buildings and leasehold improvements (7—30 years)	2,198
Other (3—5 years)	53
Intangible assets:
Customer relationships (10 years)	110,000
Non-compete agreements (2.5 years)	2,000
Goodwill	89,699
Accounts payable - trade	(6,469		)
Accrued expenses and other payables	(992		)
Other noncurrent liabilities	(64		)
Fair value of net assets acquired	$	236,289

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	167,732
Value of common units issued	68,557
Total consideration paid	$	236,289

Other Water Solutions

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	2,391
Inventories	390
Prepaid expenses and other current assets	61
Property, plant and equipment:
Land	419
Vehicles (5—10 years)	90
Water treatment facilities and equipment (3—30 years)	24,933
Buildings and leasehold improvements (7—30 years)	3,036
Other (3—5 years)	13
Intangible assets:
Customer relationships (8—10 years)	72,000
Trade names (indefinite life)	3,325
Non-compete agreements (3 years)	260
Water facility development agreement (5 years)	14,000
Water facility option agreement	2,500
Goodwill	63,031
Accounts payable - trade	(382		)
Accrued expenses and other payables	(300		)
Other noncurrent liabilities	(114		)
Fair value of net assets acquired	$	185,653

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	178,867
Value of common units issued	6,786
Total consideration paid	$	185,653

Crude Oil Logistics

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):

Accounts receivable - trade	$	1,235
Inventories	1,021
Prepaid expenses and other current assets	54
Property, plant and equipment:
Vehicles (5—10 years)	2,977
Buildings and leasehold improvements (5—30 years)	280
Crude oil tanks and related equipment (2—30 years)	3,462
Barges and towboats (20 years)	20,065
Other (3—5 years)	53
Intangible assets:
Customer relationships (3 years)	6,300
Non-compete agreements (3 years)	35
Trade names (indefinite life)	530
Goodwill	37,867
Accounts payable - trade	(665		)
Accrued expenses and other payables	(124		)
Fair value of net assets acquired	$	73,090

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	67,842
Value of common units issued	5,248
Total consideration paid	$	73,090

High Sierra

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

The fair values of the assets acquired and liabilities assumed in our acquisition of High Sierra are summarized below (in thousands):

Accounts receivable - trade	$	395,311
Accounts receivable - affiliates	7,724
Inventories	43,575
Derivative assets	10,646
Forward purchase and sale contracts	34,717
Prepaid expenses and other current assets	11,131
Property, plant and equipment:
Land	5,723
Vehicles (5—10 years)	22,507
Water treatment facilities and equipment (3—30 years)	64,057
Crude oil tanks and related equipment (2—15 years)	17,851
Buildings and leasehold improvements (5—30 years)	19,145
Information technology equipment (3 years)	5,541
Other (2—30 years)	11,010
Construction in progress	9,621
Intangible assets:
Customer relationships (5—17 years)	245,000
Lease contracts (1—10 years)	12,400
Trade names (indefinite)	13,000
Goodwill	220,884
Accounts payable - trade	(417,369			)
Accounts payable - affiliates	(9,014			)
Advance payments received from customers	(1,237			)
Accrued expenses and other payables	(35,611			)
Derivative liabilities	(5,726			)
Forward purchase and sale contracts	(18,680			)
Long-term debt	(2,537			)
Other noncurrent liabilities	(3,224			)
Noncontrolling interest in consolidated subsidiary	(2,400			)
Consideration paid, net of cash acquired	$		654,045

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	239,251
Value of common units issued, net of issurance costs	414,794
Total consideration paid	$	654,045

Pecos

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

				Estimated at
				March 31,
	Final			2013			Change
	(in thousands)
Accounts receivable - trade	$	73,609		$	73,704		$	(95	)
Inventories	1,903			1,903			—
Prepaid expenses and other current assets	1,426			1,426			—
Property, plant and equipment:
Vehicles (5—10 years)	22,097			19,193			2,904
Buildings and leasehold improvements (5—30 years)	1,339			1,248			91
Crude oil tanks and related equipment (2—15 years)	1,099			913			186
Land	223			224			(1		)
Other (3—5 years)	36			177			(141		)
Intangible assets:
Customer relationships	—			8,000			(8,000		)
Trade names (indefinite life)	900			1,000			(100		)
Goodwill	91,747			86,661			5,086
Accounts payable - trade	(50,795		)	(50,808		)	13
Accrued expenses and other payables	(963		)	(1,020		)	57
Long-term debt	(10,234		)	(10,234		)	—
Fair value of net assets acquired	$	132,387		$	132,387		$	—

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	87,444
Value of common units issued	44,943
Total consideration paid	$	132,387

Third Coast

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

				Estimated at
				March 31,
	Final			2013			Change
	(in thousands)
Accounts receivable - trade	$	2,195		$	2,248		$	(53	)
Inventories	140			140			—
Property, plant and equipment:
Barges and towboats (20 years)	17,711			12,883			4,828
Other	—			30			(30		)
Intangible assets:
Customer relationships (3 years)	3,000			4,000			(1,000		)
Trade names (indefinite life)	850			500			350
Goodwill	18,847			22,551			(3,704		)
Other noncurrent assets	2,733			2,733			—
Accounts payable - trade	(2,429		)	(2,048		)	(381		)
Accrued expenses and other payables	(164		)	(154		)	(10		)
Fair value of net assets acquired	$	42,883		$	42,883		$	—

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	35,000
Value of common units issued	7,883
Total consideration paid	$	42,883

Other Crude Oil Logistics and Water Solutions

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

				Estimated at
				March 31,
	Final			2013			Change
	(in thousands)
Accounts receivable - trade	$	2,676		$	2,660		$	16
Inventories	191			191			—
Prepaid expenses and other current assets	737			738			(1		)
Property, plant and equipment:
Land	218			191			27
Vehicles (5—10 years)	853			771			82
Water treatment facilities and equipment (3—30 years)	13,665			13,322			343
Buildings and leasehold improvements (5—30 years)	895			2,233			(1,338		)
Crude oil tanks and related equipment (2—15 years)	4,510			1,781			2,729
Other (3—5 years)	27			2			25
Construction in progress	490			693			(203		)
Intangible assets:
Customer relationships (5—10 years)	13,125			6,800			6,325
Non-compete agreements (3 years)	164			510			(346		)
Trade names (indefinite life)	2,100			500			1,600
Goodwill	34,451			43,822			(9,371		)
Accounts payable - trade	(3,374		)	(3,374		)	—
Accrued expenses and other payables	(1,914		)	(2,026		)	112
Notes payable	(1,340		)	(1,340		)	—
Other noncurrent liabilities	(156		)	(156		)	—
Noncontrolling interest	(2,333		)	(2,333		)	—
Fair value of net assets acquired	$	64,985		$	64,985		$	—

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired	$	52,552
Value of common units issued	12,433
Total consideration paid	$	64,985

Retail Propane

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

The fair values of the assets acquired and liabilities assumed in these six combinations are as follows (in thousands):

Accounts receivable - trade	$	8,715
Inventory	5,155
Other current assets	1,228
Property, plant and equipment:
Land	1,945
Retail propane equipment (5—20 years)	28,763
Vehicles (5 years)	11,344
Buildings and leasehold improvements (30 years)	7,052
Other	1,201
Intangible assets:
Customer relationships (10—15 years)	16,890
Trade names (indefinite)	2,924
Non-compete agreements (5 years)	1,387
Goodwill	21,983
Other non-current assets	784
Long-term debt, including current portion	(6,594		)
Other assumed liabilities	(12,511		)
Fair value of net assets acquired	$	90,266

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

Cash consideration paid	$	71,392
Value of common units issued	18,874
Total consideration	$	90,266

Osterman

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

The following table presents the final allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable - trade	$	9,350
Inventories	3,869
Prepaid expenses and other current assets	215
Property, plant and equipment:
Land	2,349
Retail propane equipment (15—20 years)	47,160
Vehicles (5—20 years)	7,699
Buildings and leasehold improvements (30 years)	3,829
Other (3—5 years)	732
Intangible assets:
Customer relationships (20 years)	54,500
Trade names (indefinite life)	8,500
Non-compete agreements (7 years)	700
Goodwill	52,267
Assumed liabilities	(9,654		)
Consideration paid, net of cash acquired	$	181,516

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

Cash paid at closing, net of cash acquired	$	94,873
Fair value of common units issued at closing	81,880
Working capital payment (paid in November 2012)	4,763
Consideration paid, net of cash acquired	$	181,516

SemStream

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

The following table presents the fair values of the assets acquired and liabilities assumed in the SemStream combination (in thousands):

Inventories	$	104,226
Derivative assets	3,578
Assets held for sale	3,000
Prepaid expenses and other current assets	9,833
Property, plant and equipment:
Land	3,470
Natural gas liquids terminal assets (20—30 years)	41,434
Vehicles and railcars (5 years)	470
Other (5 years)	3,326
Investment in capital lease	3,112
Intangible assets:
Customer relationships (8—15 years)	31,950
Lease contracts (1—4 years)	1,008
Goodwill	74,924
Assumed current liabilities	(4,591		)
Consideration paid	$	275,740

Pacer

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable - trade	$	4,389
Inventories	965
Prepaid expenses and other current assets	43
Property, plant and equipment:
Land	1,967
Retail propane equipment (15—20 years)	12,793
Vehicles (5 years)	3,090
Buildings and leasehold improvements (30 years)	409
Other (3—5 years)	59
Intangible assets:
Customer relationships (15 years)	23,560
Trade names (indefinite life)	2,410
Non-compete agreements	1,520
Goodwill	15,782
Assumed liabilities	(4,399		)
Consideration paid	$	62,588

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

Cash	$	32,213
Common units	30,375
Consideration paid	$	62,588

North American

Acquisitions

Schedule of the fair value (and useful lives) of the assets acquired and liabilities assumed

The following table presents the allocation of the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (in thousands):

Accounts receivable - trade	$	10,338
Inventories	3,437
Prepaid expenses and other current assets	282
Property, plant and equipment:
Land	2,251
Retail propane equipment (15—20 years)	24,790
Natural gas liquids terminal assets (15—20 years)	1,044
Vehicles (5—15 years)	5,819
Buildings and leasehold improvements (30 years)	2,386
Other (3—5 years)	634
Intangible assets:
Customer relationships (10 years)	12,600
Trade names (10 years)	2,700
Non-compete agreements (3 years)	700
Goodwill	13,978
Assumed liabilities	(11,129		)
Consideration paid	$	69,830

XML

Equity (Details 3) (USD $) In Thousands, except Share data, unless otherwise specified	0 Months Ended																			12 Months Ended		0 Months Ended	12 Months Ended								0 Months Ended											12 Months Ended	0 Months Ended	12 Months Ended					0 Months Ended											12 Months Ended		0 Months Ended	12 Months Ended
	Jan. 23, 2014	Nov. 04, 2013	Oct. 23, 2013	Jul. 25, 2013	Apr. 25, 2013	Feb. 04, 2013	Jan. 24, 2013	Oct. 29, 2012	Oct. 17, 2012	Aug. 03, 2012	Jul. 24, 2012	Apr. 30, 2012	Apr. 18, 2012	Feb. 03, 2012	Jan. 24, 2012	Oct. 31, 2011	Oct. 21, 2011	Jul. 25, 2011	May 05, 2011	Mar. 31, 2014	Mar. 31, 2012	Apr. 24, 2014 Subsequent event	Mar. 31, 2014 Minimum	Mar. 31, 2014 First target distribution Minimum	Mar. 31, 2014 First target distribution Maximum	Mar. 31, 2014 Second target distribution Minimum	Mar. 31, 2014 Second target distribution Maximum	Mar. 31, 2014 Third target distribution Minimum	Mar. 31, 2014 Third target distribution Maximum	Mar. 31, 2014 Thereafter Minimum	Jan. 23, 2014 Limited Partners	Oct. 23, 2013 Limited Partners	Jul. 25, 2013 Limited Partners	Apr. 25, 2013 Limited Partners	Jan. 24, 2013 Limited Partners	Oct. 17, 2012 Limited Partners	Jul. 24, 2012 Limited Partners	Apr. 18, 2012 Limited Partners	Jan. 24, 2012 Limited Partners	Oct. 21, 2011 Limited Partners	Jul. 25, 2011 Limited Partners	Mar. 31, 2014 Limited Partners	Apr. 24, 2014 Limited Partners Subsequent event	Mar. 31, 2012 Limited Partners Common units	Mar. 31, 2014 Limited Partners First target distribution	Mar. 31, 2014 Limited Partners Second target distribution	Mar. 31, 2014 Limited Partners Third target distribution	Mar. 31, 2014 Limited Partners Thereafter	Jan. 23, 2014 General Partner	Oct. 23, 2013 General Partner	Jul. 25, 2013 General Partner	Apr. 25, 2013 General Partner	Jan. 24, 2013 General Partner	Oct. 17, 2012 General Partner	Jul. 24, 2012 General Partner	Apr. 18, 2012 General Partner	Jan. 24, 2012 General Partner	Oct. 21, 2011 General Partner	Jul. 25, 2011 General Partner	Mar. 31, 2014 General Partner	Mar. 31, 2012 General Partner	Apr. 24, 2014 General Partner Subsequent event	Mar. 31, 2014 General Partner First target distribution	Mar. 31, 2014 General Partner Second target distribution	Mar. 31, 2014 General Partner Third target distribution	Mar. 31, 2014 General Partner Thereafter
Distributions
First level cash distribution percentage to holders of common units																				99.90%
First level cash distribution percentage to general partner																				0.10%
Second level cash distribution percentage to holders of subordinated units																				99.90%
Second level cash distribution percentage to general partner																				0.10%
Third level cash distribution percentage to all unitholders on pro rata basis																				99.90%
Third level cash distribution percentage to general partner																				0.10%
Distributions
Total Quarterly Distribution per Unit (in dollars per unit)																							$ 0.337500	$ 0.337500	$ 0.388125	$ 0.388125	$ 0.421875	$ 0.421875	$ 0.506250	$ 0.506250
Marginal Percentage Interest In Distributions																																										99.90%			99.90%	86.90%	76.90%	51.90%												0.10%			0.10%	13.10%	23.10%	48.10%
Distributions to partners prior to initial public offering																			$ 3,900		$ 3,850																							$ 3,846																	$ 4
Amount per unit (in dollars per unit)	$ 0.5313		$ 0.5113	$ 0.4938	$ 0.4775		$ 0.4625		$ 0.4500		$ 0.4125		$ 0.3625		$ 0.3500		$ 0.3375	$ 0.1669				$ 0.5513
Amount Paid to Limited Partner																															42,150	35,908	31,725	25,605	24,245	22,846	13,574	9,165	7,735	4,990	2,467		43,737
Amount Paid to General Partner																																																	$ 4,283	$ 2,491	$ 1,739	$ 1,189	$ 927	$ 707	$ 134	$ 10	$ 10	$ 5	$ 3			$ 5,754
Number of equivalent units that were not eligible to receive a distribution		979,886				1,202,085		516,978		17,862,470		3,932,031		7,117,031		4,000,000

XML

Nature of Operations and Organization (Details) (USD $)	0 Months Ended	12 Months Ended
	May 17, 2011	Mar. 31, 2014	Mar. 31, 2013	Mar. 31, 2012
Organization and operations
Equity method ownership interest (as a percent)		50.00%
Initial Public Offering
Proceeds from sale of common units, net of offering costs		$ 650,155,000	$ (642,000)	$ 74,759,000
General partner interest (as a percent)	0.10%	0.10%	0.10%
Common units
Initial Public Offering
Number of units sold in public offering	4,025,000
Price per unit of units sold in initial public offering (in dollars per share)	$ 21.00
Number of units redeemed	175,000
Units outstanding after completion of IPO	8,864,222	73,421,309	47,703,313
Common units | Repayment of advances under acquisition credit facility
Initial Public Offering
Number of units sold in public offering	3,850,000
Proceeds from sale of common units, net of offering costs	71,900,000
Offering costs	9,000,000
Common units | Redemption of common units
Initial Public Offering
Number of units sold in public offering	175,000
Proceeds from sale of common units, net of offering costs	$ 3,400,000
Subordinated units
Initial Public Offering
Units outstanding after completion of IPO	5,919,346	5,919,346	5,919,346
Retail propane and distillate operations
Organization and operations
Number of owned terminals		22
Retail propane and distillate operations | Minimum
Organization and operations
Number of states in which entity operates		20

XML

Segments

12 Months Ended

Mar. 31, 2014

Segments

Segments

Note 13 — Segments

Our reportable segments are based on the way in which our management structure is organized. Certain financial data related to our segments is shown below. Transactions between segments are recorded based on prices negotiated between the segments.

Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers, refiners, and producers. Our water solutions segment provides services for the transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. Our liquids segment supplies propane, butane, and other products, and provides natural gas liquids transportation, terminaling, and storage services to retailers, wholesalers, and refiners. Our retail propane segment sells propane and distillates to end users consisting of residential, agricultural, commercial, and industrial customers, and to certain re-sellers. Our retail propane segment consists of two divisions, which are organized based on the location of the operations.

We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon Energy.

Items labeled “corporate and other” in the table below include the operations of a compressor leasing business that we acquired in our June 2012 merger with High Sierra and sold in February 2014, and the natural gas marketing operations that we acquired in our December 2013 acquisition of Gavilon Energy and began winding down during fiscal 2014. The “corporate and other” category also includes certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our consolidated financial statements.

Certain information related to the results of operations of each segment is shown in the tables below:

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Revenues:
Crude oil logistics -
Crude oil sales	$	4,559,923		$	2,322,706		$	—
Crude oil transportation and other	36,469			16,442			—
Water solutions -
Water treatment and disposal	125,788			54,334			—
Water transportation	17,312			7,893			—
Liquids -
Propane sales	1,632,948			841,448			923,022
Other product sales	1,231,965			858,276			251,627
Other revenues	31,062			33,954			2,462
Retail propane -
Propane sales	388,225			288,410			175,417
Distillate sales	127,672			106,192			6,547
Other revenues	35,918			35,856			17,370
Refined products	1,180,895			—			—
Renewables	176,781			—			—
Corporate and other	437,713			4,233			—
Eliminations of intersegment sales	(283,397		)	(151,977		)	(65,972		)
Total revenues	$	9,699,274		$	4,417,767		$	1,310,473

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Depreciation and amortization:
Crude oil logistics	$	22,111	$	9,176	$	—
Water solutions	55,105		20,923		—
Liquids	11,018		11,085		3,661
Retail propane	28,878		25,496		11,450
Refined products	109		—		—
Renewables	516		—		—
Corporate and other	3,017		2,173		—
Total depreciation and amortization	$	120,754	$	68,853	$	15,111

	Year Ended March 31,
	2014			2013			2012
	(in thousands)
Operating income (loss):
Crude oil logistics	$	678		$	34,236		$	—
Water solutions	10,317			8,576			—
Liquids	71,888			30,336			9,735
Retail propane	61,285			46,869			9,616
Refined products	4,080			—			—
Renewables	2,434			—			—
Corporate and other	(44,117		)	(32,710		)	(4,321		)
Total operating income	$	106,565		$	87,307		$	15,030

The table below shows additions to property, plant and equipment for each segment. This information has been prepared on the accrual basis, and includes property, plant and equipment acquired in acquisitions.

	Year Ended March 31,
	2014		2013		2012
	(in thousands)
Additions to property, plant and equipment, including acquisitions (accrual basis):
Crude oil logistics	$	204,642	$	89,860	$	—
Water solutions	100,877		137,116		—
Liquids	52,560		15,129		50,276
Retail propane	24,430		66,933		150,181
Refined products	719		—		—
Renewables	519		—		—
Corporate and other	7,242		17,858		—
Total	$	390,989	$	326,896	$	200,457

The following tables show long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets by segment:

	March 31,
			2013
	2014		(Note 2)
	(in thousands)
Total assets:
Crude oil logistics	$	1,723,812	$	801,351
Water solutions	875,714		466,412
Liquids	577,795		474,141
Retail propane	541,832		513,301
Refined products	157,581		—
Renewables	145,649		—
Corporate and other	144,840		36,413
Total	$	4,167,223	$	2,291,618
Long-lived assets, net:
Crude oil logistics	$	980,978	$	357,230
Water solutions	848,479		453,909
Liquids	274,846		238,192
Retail propane	438,324		441,762
Refined products	27,017		—
Renewables	33,703		—
Corporate and other	47,961		31,996
Total	$	2,651,308	$	1,523,089