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, 2013

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 o	Accelerated filer x
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 as of September 30, 2012 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 ($24.04 per Common Unit) was approximately $504,278,498. 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.

As of June 7, 2013, there were 49,147,964 common units and 5,919,346 subordinated units issued and outstanding.

TABLE OF CONTENTS

PART I
Item 1.	Business	3
Item 1A.	Risk Factors	22
Item 1B.	Unresolved Staff Comments	44
Item 2.	Properties	44
Item 3.	Legal Proceedings	45
Item 4.	Mine Safety Disclosures	45
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	47
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	50
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	84
Item 8.	Financial Statements and Supplementary Data	85
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	85
Item 9A.	Controls and Procedures	85
Item 9B.	Other Information	86
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	87
Item 11.	Executive Compensation	93
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	107
Item 14.	Principal Accountant Fees and Services	111
PART IV
Item 15.	Exhibits and Financial Statement Schedules	112

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Forward-Looking Statements

This 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,” “project,” “expect,” “plan,” “goal,” “forecast,” “estimate,” “intend,” “could,” “believe,” “may,” “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 have a direct bearing on our results of operations and financial condition are:

·the prices and market demand for crude oil and natural gas liquids;

·energy prices generally;

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

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

·the general level of demand for crude oil and natural gas liquids;

·the availability of supply of crude oil and natural gas liquids;

·the level of crude oil and natural gas production in producing basins in which we have water treatment facilities;

·the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane 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 demand for oil, natural gas and natural gas liquids;

·the effect of natural disasters or other significant weather events;

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

·availability and marketing of competitive fuels;

·the impact of energy conservation efforts;

·energy efficiencies and technological trends;

·governmental regulation and taxation;

·the impact of legislative and regulatory actions on hydraulic fracturing;

·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 propane industry and competition from other propane distributors;

·loss of key personnel;

·the ability to renew contracts with key customers;

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·the fees we charge and the margins we realize for our terminal services;

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

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

·the nonpayment 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 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, and natural gas liquids, our processing of wastewater, and transportation and hedging activities; and

·the costs and effects of legal and administrative proceedings.

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 32 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, 2013. The operational data does not include information related to assets we have acquired after March 31, 2013.

Item 1.Business

Overview

We are a Delaware limited partnership formed in September 2010 by several investors (the “IEP Parties”). As part of our formation, we acquired and combined the assets and operations of NGL Supply, primarily a wholesale propane and terminalling business founded in 1967, and Hicksgas, primarily a retail propane business founded in 1940. Subsequent to our formation, we significantly expanded our operations through numerous business combinations. We and our subsidiaries own and operate four primary businesses, which are summarized below:

·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 water services segment 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 natural gas liquids logistics segment purchases propane, butane, and other natural gas liquids from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets. Our natural gas liquids logistics segment owns 17 terminals, leases underground storage capacity, and operates a fleet of leased rail cars.

·Our retail propane segment sells propane, distillates, and equipment and supplies to residential, agricultural, commercial, and industrial end-users.

For more information regarding our operating segments, please see Note 14 to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

Formation Transactions

In October 2010, the following transactions, which we refer to as the formation transactions, occurred:

·Hicks Oils and Hicksgas, Incorporated (“HOH”) formed a wholly owned subsidiary, Hicksgas LLC, and contributed to it all of HOH’s propane and propane-related assets. The shareholders of Gifford contributed all of their shares of stock in Gifford to a newly formed holding company, Gifford Holdings, Inc.

·Our general partner made a cash capital contribution of approximately $58,800 to us in exchange for the continuation of its 0.1% general partner interest in us and incentive distribution rights and the IEP Parties (owner of a 32.53% interest in our general partner) made a cash capital contribution to us in the aggregate amount of approximately $11.0 million in exchange for an aggregate 18.67% limited partner interest in us.

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·NGL Supply and Gifford each converted into a limited liability company and the members of NGL Supply, Hicksgas, LLC and Gifford contributed 100% of their respective membership interests in those entities to us as capital contributions in exchange for (i) in the case of NGL Supply, a 43.27% limited partner interest in us, a cash distribution of approximately $40.0 million and our agreement to pay or cause to be paid approximately $27.9 million of existing indebtedness of NGL Supply, (ii) in the case of Hicksgas, LLC, a 37.96% limited partner interest in us, a cash distribution of approximately $1.6 million and our agreement to pay or cause to be paid approximately $6.5 million of existing indebtedness of HOH and (iii) in the case of Gifford, a cash payment of approximately $15.5 million.

·We made a capital contribution of 100% of the membership interests of each of NGL Supply, Hicksgas, LLC and Gifford to a wholly owned operating subsidiary. Gifford was merged into Hicksgas, LLC.

Initial Public Offering

On May 17, 2011, we completed our initial public offering and listed our common units on the New York Stock Exchange (“NYSE”) under the symbol “NGL.” We sold a total of 4,025,000 common units (including the exercise by the underwriters of their option to purchase additional common units from us) in our initial public offering at $21 per unit. Our proceeds from the sale of 3,850,000 common units of approximately $71.9 million, net of total offering costs of approximately $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 initial public offering.

Upon completion of our initial public offering 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, or IDRs. The public owned an approximately 27.2% limited partner interest in us and the NGL Energy LP Investor Group owned an approximately 72.7% limited partner interest in us. 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 initial public offering, we significantly expanded our operations through a number of business combinations, including the following:

·On October 3, 2011, we completed a business combination transaction 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. 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 we paid in November 2012.

·On November 1, 2011, we completed a business combination transaction 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. We issued 8,932,031 common units and paid $91.0 million in exchange for the assets and operations of SemStream, including working capital.

·On January 3, 2012, we completed a business combination transaction with seven companies associated with Pacer Propane Holding, L.P. (collectively, “Pacer”), whereby we acquired retail propane operations, primarily in the western United States. We issued 1,500,000 common units, valued at $30.4 million, and paid $32.2 million of cash in exchange for the assets and operations of Pacer, including working capital. We also assumed $2.7 million of long-term debt in the form of non-compete agreements.

·On February 3, 2012, we completed a business combination transaction with North American Propane, Inc. (“North American”), whereby we acquired retail propane and distillate operations in the northeastern United States. We paid $69.8 million of cash in exchange for the assets and operations of North American, including working capital.

·During the year ended March 31, 2012, we completed three separate business combination transactions to acquire retail propane operations. On a combined basis, we paid $6.4 million of cash for these assets and operations, including working capital. We also assumed $0.7 million of long-term debt in the form of non-compete agreements.

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·On June 19, 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. 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.

·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 purchasing and logistics operations in Texas and New Mexico. We paid cash of $132.4 million at closing (net of $2.2 million of cash acquired), subject to customary post-closing adjustments, 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 of Pecos purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement.

·On December 31, 2012, we completed a business combination transaction whereby we acquired all of the limited liability company 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. The agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. 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 call agreement.

·During the year ended March 31, 2013, we completed six separate business combination transactions to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States. On a combined basis, we paid $71.4 million of cash and issued 850,676 common units in exchange for these assets and operations, including working capital. We also assumed $6.6 million of long-term debt in the form of non-compete agreements.

·During year ended March 31, 2013, we completed four separate acquisitions to expand the assets and operations of our crude oil logistics and water services businesses. On a combined basis, we paid $52.6 million of 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. Certain of the acquisition agreements contemplate post-closing adjustment to the purchase price for certain specified working capital items.

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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 as of May 11, 2011

Primary Service Areas as of March 31, 2012

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Primary Service Areas as of March 31, 2013

Organizational Chart

The following chart provides a summarized view of our legal entity structure at March 31, 2013:

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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 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 services 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 services 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 natural gas liquids logistics and crude oil logistics segments, we intend to focus on back-to-back contracts which minimize commodity price exposure. In our water services segment, cash flows are typically supported by fee-based contracts, some of which include acreage dedications from producers or volume commitments. These contracts not only help minimize commodity price exposure but also provide a degree of certainty with respect to volumes and provide stable cash flows.

·      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 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. 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 natural gas liquids logistics business, which allows us to leverage the expertise of our natural gas liquids logistics business to help improve our margins and profitability and enhance our cash flows. Furthermore, we believe that our natural gas liquids logistics business provides us with valuable market intelligence that helps us identify potential acquisition opportunities.

·      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, tows, barges, and trucks 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 U.S., 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 rail car 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 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, and the Eagle Ford Basin in Texas.

Operations. We transport crude oil using the following assets:

·300 owned trucks and 270 owned trailers operating primarily in the Mid-Continent, Permian Basin, Eagle Ford, and Rocky Mountain regions;

·463 leased rail cars operating primarily in North Dakota, Oklahoma, Colorado, Wyoming, and Texas; and

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·Four towboats and ten barges operating primarily in the inter-coastal waterways of the Gulf Coast and along the Mississippi and Arkansas river systems.

We also contract for truck, rail, and barge transportation services from third parties and ship on common carrier pipelines. We own 42 pipeline injection facilities in Kansas, Oklahoma, North Dakota, New Mexico, Texas, and Montana. We also lease 12 rail transload facilities in Colorado, Kansas, North Dakota, Oklahoma, and Texas.

We also own four terminal facilities, as summarized below:

Location	Storage Capacity (barrels)
Catoosa, Oklahoma	138,000
Rio Hondo, Texas	80,000
Wheatland, Wyoming	80,000
Sunray, Texas	9,500

Customers. Our customers include crude oil refiners and marketers. Approximately 58% of the revenues from our crude oil logistics segment during the year ended March 31, 2013 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 rail cars;

·      proprietary terminals;

·      owned barges and tows;

·      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 purchase from approximately 500 producers at approximately 4,000 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 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

·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 High Sierra Transportation, High Sierra Crude Oil Marketing & Transportation, Pecos, Andrews Oil Buyers, Striker, and Third Coast Towing trade names.

Water Services

Overview. Our water services segment 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

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facilities are located near fields with high levels of 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 13 wastewater processing facilities. The location of the facilities and the processing capacities are summarized below:

	Processing
	Capacity
Location	(barrels per day)
Pinedale, Wyoming	60,000	(*)
Grover, Colorado	27,000
Kersey, Colorado	11,800
Cornish, Colorado	9,000
LaSalle, Colorado	5,500
Brighton, Colorado	6,500
Platteville, Colorado	4,500
Greeley, Colorado	3,800
Artesia Wells, Texas	16,000
Dilley Lea, Texas	14,000
Carrizo Springs, Texas	13,000
Andrews, Texas	10,000
Los Angeles, Texas	10,000

(*)The Pinedale, Wyoming facility has a capacity of 20,000 barrels per day to process water to a discharge standard and a capacity of 60,000 barrels per day to process water to a recycle standard.

We own the land on which 8 of the facilities are located and we lease the land on which 5 of the facilities are located.

Our customers bring wastewater generated by their oil and 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 the 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 the producers for use in future drilling operations. Our facilities in Texas dispose all of the water they process via injection wells.

We also operate a wastewater transportation business in Kansas and Oklahoma, whereby we transport wastewater via truck to processing facilities owned by other parties. We operate this business with approximately 90 owned trucks and approximately 70 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. 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. The customers of our facilities in Texas consist primarily of wastewater transportation companies. During the year ended March 31, 2013, approximately 43% of the revenues of the water services segment were generated from our two largest customers of the segment, and approximately 82% 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 oil and natural gas production. Most of the primary customers served by our facilities in Wyoming and Colorado are under multi-year contracts. Due to higher levels of competition, most of the customers served by our facilities in Texas are not under volume commitments.

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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 services customers consist primarily of large oil and natural gas producers, but also include smaller water transportation 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 water services customers. We believe the following procedures enhance our collection efforts with our water services 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 services business operates under the High Sierra Water Services, High Sierra Water Services — Eagle Ford, Tiburon Resources, Anticline Disposal, and Pure Flow trade names.

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

Natural Gas Liquids Logistics

Overview. Our natural gas liquids logistics segment provides natural gas liquids procurement, storage, transportation, and supply services to customers through assets owned by us and third parties. Our natural gas liquids logistics 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, rail car 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 rail car.

A portion of our wholesale propane gallons are presold to third party retailers and wholesalers at a fixed price under back-to-back contractual arrangements. Back-to-back arrangements, 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 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 rail car 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 rail cars and charge the customers a transportation service fee. In addition, we sub-lease rail cars to certain customers.

To a lesser extent, we also purchase and sell asphalt. We utilize leased rail cars to move the asphalt from our suppliers to our customers.

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We own 17 natural gas liquids terminals and we lease a fleet of rail cars. 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 rail cars 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
St. Catherines, Ontario, Canada	700,000
Janesville, Wisconsin	553,000
Light, Arkansas	524,400
Rixie, Arkansas	524,400
Winslow, Arizona	500,000
Kingsland, Arkansas	405,000
Portland, Maine	360,000
West Springfield, Massachusetts	360,000
Green Bay, Wisconsin	310,000
Ritzville, Washington	198,000
Sidney, Montana	180,000
Total	10,867,800

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 Phillips 66 for a monthly fee under an operating and maintenance agreement that has a term that expires in 2017. Our facility 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 11 of the terminals are located and we either have easements or lease the land on which 6 of the terminals are located. The terminals in Jefferson City, Missouri and East St. Louis, Illinois have perpetual easements, and the terminal in St. Catherines, Ontario, Canada has a long-term lease that expires in 2022.

We own 7 rail cars and lease 3,170 additional rail cars. These include high pressure and general purpose rail cars.

We own eleven transloading units, which enable customers to transfer product from rail cars 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 approximately 163 million gallons of storage space for natural gas liquids in various storage hubs in Arizona, Canada, Kansas, Michigan, Mississippi, Missouri, and Texas.

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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	As of
	April 1,	March 31,
Storage Facility	2013	2013	Storage Interconnects
Conway, Kansas	80,850,000	101,850,000	Connected to Enterprise Mid-America and NuStar Pipelines
Borger, Texas	31,500,000	31,500,000	Connected to ConocoPhillips Blue Line Pipeline
Bushton, Kansas	12,600,000	10,500,000	Connected to ONEOK North System Pipeline
Mont Belvieu, Texas	2,940,000	3,990,000	Connected to Enterprise Texas Eastern Products Pipeline
Carthage, Missouri	7,560,000	7,560,000	Connected to Mid-America Pipeline
Marysville, Michigan	15,750,000	4,200,000	Connected to Cochin Pipeline
Hattiesburg, Mississippi	3,150,000	3,150,000	Connected to Enterprise Dixie Pipeline
Redwater, Alberta, Canada	4,620,000	4,200,000	Connected to Cochin Pipeline
Adamana, Arizona	1,680,000	1,680,000	Rail facility
Corunna, Ontario, Canada	2,100,000	2,100,000	Rail facility
Total	162,750,000	170,730,000

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 natural gas liquids logistics business serves over 600 customers in 47 states. Our natural gas liquids logistics business serves national, regional and independent retail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. Our natural gas liquids logistics 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 U.S. propane storage hubs. For the year ended March 31, 2013, our ten largest natural gas liquids logistics customers represented approximately 42% of the total sales of our natural gas liquids logistics business (exclusive of sales to our retail segment).

Seasonality. Our natural gas liquids logistics 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 natural gas liquids logistics 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 rail cars;

·proprietary terminals;

·obtaining and retaining customers; and

·the acquisition of businesses.

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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 contractual agreements for a majority of our natural gas liquids logistics 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 natural gas liquids logistics 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 approximately 10,000 gallons to as much as 1,000,000 gallons, and deliveries can occur over time periods extending from days to as much 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;

·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 natural gas liquids logistics business operates primarily under the NGL Supply Wholesale, 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 270,000 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 natural gas liquids logistics business, which provides our retail propane business with a stable and secure supply of propane.

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Operations. We market retail propane through our customer service locations using the Hicksgas, Propane Central, Brantley, Osterman, Pacer, Downeast Energy, and Energy USA regional brand names, among others. 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 86 customer service locations and 94 satellite distribution locations, with aggregate above ground propane storage capacity of approximately 10.8 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 above ground storage tanks, allow our customer service centers to serve an extended market area.

Our customer service locations in Illinois and Indiana also rent approximately 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.

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	21
Maine	15	10
Georgia	11	3
Massachusetts	10	5
Kansas	5	30
Indiana	4	5
Connecticut	3	2
Pennsylvania	2	3
North Carolina	2	1
Oregon	2	1
Washington	2	—
Mississippi	1	3
New Hampshire	1	2
Maryland	1	1
Rhode Island	1	1
Utah	1	1
Wyoming	1	1
Colorado	1	—
Delaware	—	1
New Jersey	—	1
Tennessee	—	1
Vermont	—	1
Total	86	94

We own 63 of our 86 customer service centers and 64 of our 94 satellite distribution locations, and we lease the remainder.

Tank ownership at customer locations is an important component to our operations and customer retention. As of March 31, 2013, we owned the following propane storage tanks:

·approximately 420 bulk storage tanks with capacities ranging from 5,000 to 90,000 gallons; and

·approximately 296,000 stationary customer storage tanks with capacities ranging from 7 to 30,000 gallons.

We also leased an additional 21 bulk storage tanks.

As of March 31, 2013, we owned a fleet of approximately 350 bulk delivery trucks, 40 semi-tractors, 40 propane transport trailers and 500 other service trucks.

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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 approximately 30 to 1,000 gallons. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of five 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.

Approximately 58% 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 their 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 ensuring 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, 2013, our retail propane and distillate customers were comprised of approximately:

·68% residential customers;

·31% 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, 2013.

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 approximately 25 to 50 miles, although in certain areas the marketing radius may be extended by satellite distribution locations.

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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 ensures a higher level of service to our customers. We also believe that our overall service capabilities and customer responsiveness differentiate us from many of these smaller competitors.

Supply. Our retail propane segment purchases the majority of its propane from our natural gas liquids logistics 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 natural gas liquids logistics 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 feel paying locally helps support their community; 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, Osterman, Pacer, Downeast Energy, and Energy USA, 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.

Employees

As of March 31, 2013, we had 1,970 full-time employees, of which 1,835 were operational and 135 were general and administrative employees. Eighteen 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 U.S. 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 gas resellers subject to its regulation,

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except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to the resale of 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.

Anti-Market Manipulation Rules. We are subject to the anti-market manipulation provisions in the Natural Gas Act and the Natural Gas Policy Act of 1978 (the “NGPA”), as amended by the Energy Policy Act of 2005, which authorize 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 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 U.S. to vessels built and registered in the U.S. and owned and manned by U.S. citizens. Since we engage in maritime transportation through our barge fleet between locations in the U.S., 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 U.S.-flagged vessels be manned by U.S. citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by U.S. citizen seamen. This requirement significantly increases operating costs of U.S.-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 U.S.-flagged vessel owners. The U.S. 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 U.S.-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,

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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, or RCRA, the Comprehensive Environmental Response, Compensation and Liability Act, or 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.

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 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, the Resource Conservation and Recovery Act 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 propane and other natural gas liquids by barge through navigable waters of the U.S. The Oil Pollution Prevention Act imposes liability for releases of oil from vessels or facilities into navigable waters. If a release of propane or other natural gas liquids 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

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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 a number of 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.

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.

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’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process. 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 U.S. 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. In addition, several states, including Texas and Colorado, 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 U.S. House of Representatives passed the ACES Act, also known as the Waxman Markey Bill. The ACES Act did not pass the 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 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 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

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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 GHG 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 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 propane and other natural gas liquids that we transport, store, process, or otherwise handle in connection with our services.

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 propane and other 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, or 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, or DOT. We maintain various permits necessary to ensure that our operations comply with applicable regulations. The Natural Gas Safety Act of 1968 required the DOT to develop and enforce minimum safety regulations for the transportation of gases by pipeline. The DOT’s pipeline safety regulations apply to, among other things, a propane gas system which supplies 10 or more residential customers or 2 or more commercial customers from a single source, as well as a propane gas system, any portion of which is located in a public place. The code requires operators of all gas systems to provide training and written instructions for employees, establish written procedures to minimize the hazards resulting from gas pipeline emergencies, and conduct and keep records of inspections and testing. Operators are subject to the Pipeline Safety Improvement Act of 2002, which, among other things, protects employees from adverse employment actions if they provide information to their employers or to the federal government as to pipeline safety.

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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 U.S. 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.

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 and natural gas liquids 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 rail cars;

·the effectiveness of our commodity price hedging strategy;

·the level of competition from other energy providers; and

·prevailing economic conditions.

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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 revolving credit facility and note purchase agreement 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.

Because of all these factors, we may not have sufficient available cash each quarter to be able to pay the minimum quarterly distribution.

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 business depends on the availability of supply of 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 oil and natural gas. Spending on 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) oil and natural gas producers having success in their operations, (3) continued commercially viable areas in which to explore and produce oil and natural gas, and (4) the availability of liquids-rich natural gas needed to produce natural gas liquids.

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. 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.

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.

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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.

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 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.

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

The crude oil logistics, natural gas liquids logistics, and retail propane 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 the prices of crude oil and natural gas liquids caused by changes in supply 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 propane inventory that we have already pre-sold.

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We are affected by competition from other midstream, transportation, terminalling and storage and retail marketing companies.

We experience competition in all of our segments. In our natural gas liquids logistics 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 terminalling 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 oils 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 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 services segment is in direct and indirect competition with other businesses, including disposal and other wastewater treatment businesses, some of which are larger and more firmly established and may have greater marketing and development budgets and capital resources than we do.

We also 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 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.

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.

Historically, a substantial portion of our propane supply has originated from storage facilities at Borger, Texas; Conway and Bushton, Kansas; Mt. Belvieu, Texas; and Sarnia, Ontario, Canada and has been shipped to us or by us to our service areas through common carrier pipelines. 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 and natural gas liquids by rail car. 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 crude oil and natural gas liquids 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.

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

Approximately 43% of the revenues of our water services segment during the year ended March 31, 2013 were generated from our two largest customers of the segment. Approximately 58% of the revenues of our crude oil logistics segment during the year ended March 31, 2013 were generated from our ten largest customers of the segment. Approximately 42% of the revenues our natural gas liquids logistics segment were generated from our ten largest customers of the segment.  For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented approximately 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 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.

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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 revolving credit facility and note purchase agreement 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 and propane’s generally higher cost as compared to certain other energy sources, we may have difficulty in increasing our retail customer base other than through acquisitions. Therefore, while our business strategy includes expanding our existing operations through internal growth, our ability to grow within the industries in which we operate 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;

·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.

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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 revolving credit facility and note purchase agreement could adversely affect our business, financial condition, results of operations, ability to make distributions to unitholders and the value of our common units.

Our revolving credit facility and note purchase agreement 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;

·engage in sale and leaseback transactions;

·enter into certain types of transactions with affiliates;

·enter into agreements limiting subsidiary distributions;

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

·merge or consolidate with another company; and

·transfer or otherwise dispose of assets.

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We are permitted to make distributions to our unitholders under our revolving credit facility and note purchase agreement so 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 revolving credit facility and note purchase agreement 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 revolving credit facility and note purchase agreement 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 revolving credit facility 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 revolving credit facility, 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 cash distributions at our intended levels.

The fees charged to customers under our agreements with them for the transportation and marketing of crude oil, condensate and natural gas liquids 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 and natural gas liquids, 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 FERC regulation or we become subject to FERC regulation ourselves (see Risk Factor entitled “Some of our transportation services could become subject to the jurisdiction of the FERC,” below), we will be obligated to comply with FERC’s regulations and policies. Any failure on our part to comply with the FERC’s regulations and policies at that time, or with an interstate pipeline’s tariff, 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 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

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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 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, or “CSA.” If our current USDOT 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 or “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.

Difficulty in attracting and retaining qualified drivers in our crude oil logistics and water services businesses 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 U.S. Department of Transportation’s (“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.

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 and natural gas liquids. 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, and natural gas liquids 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.

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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 United States Department of Transportation, or 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. 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 affect 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 U.S. Environmental Protection Agency (“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. 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 GHG emissions, or limiting GHG 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 services 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. Some sections of the public have also asserted that the fracturing 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 recently asserted federal regulatory authority over certain hydraulic fracturing practices involving the use of diesel fuel. At the same

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time, the EPA has commenced a study of the potential environmental impact of hydraulic fracturing activities, the final results of which are expected in 2014. 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, Texas, Wyoming and other 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 rail cars 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 crude oil and natural gas liquids 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 our retail and wholesale customers. Such disruptions could potentially have a material adverse impact on our business, financial condition, results of operations and cash flows, which could impair our ability to make distributions to our unitholders.

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 rail cars. 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 U.S. 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.

Our risk policy 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 risk management 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

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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.

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 terminalling, 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 significant 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 effect on our business, results of operations, financial condition 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.

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 operational system flaws, employee tampering or manipulation of those systems will result in losses that are difficult to detect.

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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 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.

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.

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 primarily in our crude oil logistics and natural gas liquids logistics businesses. Disruptions in the supply of propane 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 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 distributions to our unitholders.

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.

Prior to our initial public offering, we were not required to file reports with the SEC. Upon the completion of our initial public offering, we became subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Effective March 31, 2012, we became 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. Effective March 31, 2013, we became subject 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.

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 would 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.

High Sierra has in the past identified material weaknesses in its internal control over financial reporting, and the identification of any material weaknesses in the future could affect our ability to ensure timely and accurate financial statements.

At the end of several periods during the last five years, High Sierra’s management identified material weaknesses in its internal control over financial reporting. The Public Company Accounting Oversight Board has defined a material weakness as a control deficiency, or combination of control deficiencies, that results in a reasonable possibility that a material misstatement of the annual or interim statements will not be prevented or detected on a timely basis. Accordingly, a material weakness increases the risk that reported financial information contains material errors. High Sierra has implemented procedures and controls to address these issues.

Although action has been taken to remediate the past material weaknesses in internal controls, these measures may not be sufficient to ensure that our internal controls are effective in the future. Any future material weaknesses, or any failure to effectively address a material weakness or other control deficiency or implement required new or improved controls, or difficulties encountered in their implementation, could limit our ability to obtain financing, harm our reputation or disrupt our ability to report key components of our results of operations and financial condition timely and accurately.

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

As of March 31, 2013, we had reported goodwill and intangible assets of approximately $1.0 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 under GAAP would result in a charge to our income, which would reduce our earnings.

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

The risk of nonpayment by customers is a concern in all of our operating segments, and our procedures may not fully eliminate this risk. We manage our credit risk exposure through credit analysis, credit approvals, establishing credit limits, requiring prepayments (partially or wholly), requiring propane 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 distributions to our unitholders.

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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 U.S. 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.

Some of our transportation services could become subject to the jurisdiction of the FERC.

Any of our transportation services could in the future become subject to the jurisdiction of FERC, which could adversely affect the terms of service, rates and revenues of such transportation services. Currently, FERC regulates oil and natural gas pipelines, among other things. As of the date of this Annual Report, our facilities do not fall under FERC’s jurisdiction. However, if FERC’s regulatory reach was expanded to our facilities, or if we expand our operations into areas that are subject to 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.

We could be required to provide linefill on certain of the pipelines on which we ship product. This could require the use of our working capital, which could potentially impact our ability to borrow additional amounts under our working capital facility to conduct our operations or to make distributions to our unitholders.

We have not historically been required to provide the linefill for certain pipelines on which we transport crude oil and natural gas liquids. “Linefill” is the pre-determined minimum level of product a common carrier could require us to maintain in its pipeline and storage in order to facilitate the operations of the facilities. If we were required to provide any portion of the linefill, we would have to purchase product that would have to remain in the pipeline for an extended period of time. Such a requirement would expose us to inventory and price risk and could negatively impact our working capital position, our liquidity, our availability under our working capital facility and our ability to make distributions to our unitholders.

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

We own 17 natural gas liquids terminals and four 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.

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.

The risk of terrorism and political unrest in various energy producing regions may adversely affect the economy and the supply of crude oil and the price and availability of propane, fuel oil and other refined fuels and natural gas.

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.

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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.

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, or the 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:

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

·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 our general partner that might otherwise be breaches of fiduciary duty.” 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;

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

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

·our general partner may cause us to borrow funds to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate the expiration of the subordination period;

·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 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

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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 tenth anniversary of the closing date of our initial public offering, a transfer of incentive distribution rights 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 incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights 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 incentive distribution rights.

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.

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

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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 revolving credit facility 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 incentive distribution rights at the highest level to which it is entitled (48.0%) 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 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 incentive distribution rights 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 incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its incentive distribution rights 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.

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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 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 Internal Revenue Service, or 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. “Qualifying income” includes income and gains derived from the exploration, development, production, processing, transportation, storage and marketing of natural gas and natural gas products or other passive types of income such as certain interest and dividends. 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.

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.

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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 U.S. Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect the tax treatment of publicly traded partnerships. 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 our unitholders will be treated as partners to whom we will allocate taxable income which 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 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.

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Tax-exempt entities and non-U.S. 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-U.S. 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-U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-U.S. persons will be required to file U.S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-U.S. 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 U.S. 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 U.S. 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 effect 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 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.

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We have adopted certain valuation methodologies and monthly conventions for U.S. 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 Internal Revenue 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 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.

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.

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

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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.

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 on Form 10-K, 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 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.

As of June 7, 2013, there were approximately 221 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
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

	Price Range				Cash
2012 Fiscal Year	High		Low		Distribution
Fourth Quarter	$	23.15	$	20.59	$	0.3500
Third Quarter	22.05		19.94		0.3375
Second Quarter	22.70		18.40		0.1669
First Quarter (May 12, 2011-June 30, 2011)	21.75		18.62		—

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. The distribution for the quarter ended June 30, 2011 was prorated for the period from the closing of our initial public offering on May 17, 2011 to the last day of the quarter on June 30, 2011. 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. Also, if we have earned and paid at least 150% of the minimum quarterly distribution on each outstanding common unit and subordinated unit, the corresponding distribution on the general partner interest and the related distribution on the incentive distribution rights for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminate automatically if the general

46

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 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, or 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 elsewhere in this Annual Report, our revolving credit facility contains covenants limiting our ability to pay distributions if we are in default under the revolving credit facility 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, 2013, we completed six 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(2) of the Securities Act of 1933, as amended, as the units were issued to the owners of businesses acquired in privately negotiated transactions not involving any public offering or solicitation. On May 1, 2012, we issued 750,000 common units to the sellers of Downeast Energy Corp. On June 19, 2012, we issued 20,703,510 common units to the sellers of High Sierra Energy. On July 18, 2012, we issued 100,676 common units to the sellers of a retail propane business. On October 1, 2012, we issued 516,978 common units to the sellers of certain entities operating salt water disposal wells and related assets. On November 12, 2012, we issued 1,834,414 common units and 10,000 restricted units (subject to vesting) to the sellers of Pecos Gathering & Marketing, L.L.C. and its affiliated companies. On January 11, 2013, we issued 344,680 common units to the sellers of Third Coast Towing, LLC.

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 formation. The following table shows selected historical financial and operating data for NGL Energy Partners LP and NGL Supply, Inc., (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 elsewhere in this annual report.

The selected consolidated historical financial data (excluding volume information) as of March 31, 2013 and 2012 and for the years then ended and as of March 31, 2011 and for the six months then ended are derived from our audited historical consolidated financial statements included elsewhere in this Annual Report on Form 10-K. The selected historical financial data (excluding volume

47

information) as of September 30, 2010 and for the six months then ended are derived from the audited historical consolidated financial statements of NGL Supply included elsewhere in this Annual Report on Form 10-K. The selected historical financial data as of March 31, 2010 and 2009 and for the fiscal years then ended are derived from NGL Supply’s financial records.

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	NGL Energy Partners LP						NGL Supply, Inc.
	Year Ended		Year Ended		Six Months Ended		Six Months Ended
	March 31,		March 31,		March 31,		September 30,			Year Ended March 31,
	2013		2012		2011		2010			2010		2009
	(in thousands, except per unit data)
Income Statement Data (1)
Total revenues	$	4,417,767	$	1,310,473	$	622,232	$	316,943		$	735,506	$	734,991
Total cost of sales	4,039,110		1,217,023		583,032		310,908			708,215		706,418
Operating income (loss)	87,307		15,030		14,837		(3,795		)	6,661		9,431
Interest expense	32,994		7,620		2,482		372			668		1,621
Loss on early extinguishment of debt	5,769		—		—		—			—		—
Net income or net income (loss) attributable to parent equity	47,940		7,876		12,679		(2,515		)	3,636		4,949
Basic and diluted earnings per common unit	0.96		0.32		1.16
Basic earnings (loss) per common share							(128.46		)	178.75		242.82
Diluted earnings (loss) per common share							(128.46		)	176.61		239.92
Cash Flows Data (1)
Cash flows from operating activities	$	132,231	$	90,329	$	34,009	$	(30,749	)	$	7,480	$	22,149
Cash distributions paid per common unit (subsequent to IPO)	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	72,475		7,544		1,440		280			582		577
Acquisitions of businesses, including additional consideration paid on prior period acquisitions	490,402		297,401		17,400		123			3,113		3,532
Balance Sheet Data - Period End(1)
Total assets	$	2,291,347	$	749,519	$	163,833	$	148,596		$	111,580	$	103,434
Total long-term obligations, exclusive of current maturities	742,641		199,389		65,936		18,940			8,851		9,245
Redeemable preferred stock	—		—		—		—			3,000		3,000
Total equity	889,418		405,329		47,353		36,811			46,403		42,691
Volume Information (1)
Retail propane and distillate sales (gallons)	173,232		79,886		34,932		3,747			15,514		14,033
Wholesale propane sales (gallons)(2)	912,625		659,921		372,504		226,330			623,510		510,255
Wholesale butane and other NGL sales (gallons)	632,695		134,999		49,465		46,092			53,878		58,523
Crude oil sold (barrels)	24,373		—		—		—			—		—
Wastewater delivered (barrels)	25,009		—		—		—			—		—

(1)The acquisitions of businesses subsequent to our initial public offering, the acquisition of Hicksgas at the time of our formation transactions, and certain acquisitions by NGL Supply in fiscal years 2009 and 2010 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

NGL Energy Partners LP (“we”, “our”, “us”, or the “Partnership”) is 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 in May 2011. At the time of our initial public offering, we owned and operated retail propane and wholesale natural gas liquids businesses. Subsequent to our initial public offering, we significantly expanded our operations through a number of business combinations, as described under Part I, Item I, “Businesses — Acquisitions Subsequent to Initial Public Offering.”

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As of March 31, 2013, our businesses include:

·A crude oil logistics business, the assets of which include crude oil terminals, pipeline injection stations, a fleet of trucks, a fleet of leased rail cars, and a fleet of barges and tow boats;

·A water services business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks;

·Our natural gas liquids logistics business, which supplies propane and other natural gas liquids to retailers, wholesalers, and refiners throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 17 terminals throughout the United States and rail car transportation services through its fleet of owned and predominantly leased rail cars; and

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

Crude Oil Logistics

Our crude oil transportation and marketing 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” contractual agreements 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. The operations of our crude oil logistics segment began with our June 2012 merger with High Sierra.

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 well head 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 to different markets. We also seek to maximize margins by blending crude oil of varying properties.

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

	Spot Price Per Barrel
					At Period
	Low		High		End
For the Year Ended March 31, 2013	$	77.69	$	106.16	$	97.23

Water Services

Our water services 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. The operations of our water services segment began with our June 2012 merger with High Sierra.

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 services 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. The customers of our other facilities are not under volume commitments.

Natural Gas Liquids Logistics

Our natural gas liquids logistics segment purchases propane, butane, and other natural gas liquids from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets. Our natural gas liquids logistics segment owns 17 terminals and operates a fleet of owned and leased rail cars and leases underground storage capacity. The margins we realize in our wholesale business are substantially lower on a per gallon basis than the margins we realize in our retail business. We attempt to reduce our exposure to the impact of price fluctuations by using “back-to-back” contractual agreements and “pre-sale” agreements that essentially 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 natural gas liquids logistics segment includes the operations that were previously reported in our wholesale marketing and supply and terminals segments. Our natural gas liquids logistics segment also includes the natural gas liquids operations we acquired in our June 2012 merger with High Sierra.

Through our natural gas liquids logistics segment, we distribute propane and other natural gas liquids to our retail operation and other propane retailers, refiners, wholesalers and other related businesses. 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 as a percentage of revenues or on a per gallon basis than our retail propane business.

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Propane prices continued to be volatile during our fiscal years 2011 through 2013. At Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, the range of low and high spot propane prices per gallon for the periods indicated and the prices as of 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
	Low		High		At Period End		Low		High		At Period End
For the Year Ended March 31, 2013	$	0.5038	$	0.9625	$	0.9013	$	0.7063	$	1.2175	$	0.9588
For the Year Ended March 31, 2012	0.9000		1.4900		0.9800		1.1650		1.6275		1.2363
For the Six Months Ended:
March 31, 2011	1.1175		1.5850		1.2763		1.1694		2.2850		1.3650
September 30, 2010	0.8813		1.1625		1.1625		0.9631		1.2000		1.2000

We purchase butane from refiners during the summer months, when refiners have a greater supply of butane than they need, and sell butane to refiners during the winter blending season, when demand for butane is higher.

The range of high and low spot butane prices per gallon at Mt. Belvieu, Texas for the year ended March 31, 2013 are shown below:

	Spot Price Per Gallon
	Low		High		At Period End
For the Year Ended March 31, 2013	$	1.1438	$	1.9313	$	1.4450

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 natural gas liquids logistics 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 or increase our realized gross margin on a cents per gallon basis. Gross 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 costs, we have experienced an increase in our gross 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. As a result, operating revenues are generally highest from October through March.

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We believe that the recent economic downturn has caused certain of our retail propane customers to conserve and thereby purchase less propane. Although we believe the economic downturn has not currently had a material impact on our cash collections, it is possible that a prolonged economic downturn could have a negative impact on our future cash collections.

Recent Developments

The formation transactions, our initial public offering, and the acquisitions subsequent to our initial public offering have had a significant impact on the comparability of our results of operations from fiscal 2011 through 2013. These transactions are summarized above under the heading “Overview.”

Consolidated Results of Operations

The following table summarizes our historical consolidated statements of operations for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and NGL Supply’s consolidated statement of operations for the six months ended September 30, 2010.

	NGL Energy Partners LP									NGL Supply, Inc.
	Year Ended			Year Ended			Six Months Ended			Six Months Ended
	March 31,			March 31,			March 31,			September 30,
	2013			2012			2011			2010
	(in thousands)
Revenues	$	4,417,767		$	1,310,473		$	622,232		$	316,943
Cost of sales	4,039,110			1,217,023			583,032			310,908
Operating and general and administrative expenses	222,497			63,309			20,922			8,441
Depreciation and amortization	68,853			15,111			3,441			1,389
Operating income (loss)	87,307			15,030			14,837			(3,795		)
Interest expense	(32,994		)	(7,620		)	(2,482		)	(372		)
Loss on early extinguishment of debt	(5,769		)	—			—			—
Interest and other income	1,521			1,055			324			190
Income (loss) before income taxes	50,065			8,465			12,679			(3,977		)
(Provision) benefit for income taxes	(1,875		)	(601		)	—			1,417
Net income (loss)	48,190			7,864			12,679			(2,560		)
Net (income) loss attributable to noncontrolling interests	(250		)	12			—			45
Net income (loss) attributable to parent equity	$	47,940		$	7,876		$	12,679		$	(2,515	)

All information herein related to the six months ended September 30, 2010 represents the results of operations of NGL Supply.

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

Set forth below is a discussion of significant changes in the non-segment related corporate other income and expenses during the respective periods.

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Interest Expense

The largest component of interest expense during fiscal 2011 through 2013 has been interest on revolving credit facilities and on senior notes that we issued in June 2012. See Note 8 to our consolidated financial statements as of March 31, 2013 included elsewhere in this Annual Report on Form 10-K 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
	Average				Average
	Balance		Average		Balance
	Outstanding		Interest		Outstanding		Interest
	(in thousands)		Rate		(in thousands)		Rate
Year Ended March 31, 2013	$	405,114	3.56	%	$	195,890	6.65	%
Year Ended March 31, 2012	125,859		4.48	%	—		—
Six Months Ended March 31, 2011	73,115		5.71	%	—		—
Six Months Ended September 30, 2010	13,767		4.63	%	—		—

Interest expense also includes amortization of debt issuance costs, which represented $3.4 million of expense during the year ended March 31, 2013, $1.3 million of expense during the year ended March 31, 2012, $0.6 million of expense during the six months ended March 31, 2011, and less than $0.1 million of expense during the six months ended September 30, 2010. 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 retired our revolving credit facility and replaced it with a new facility. Upon retirement of the old 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 2011 through fiscal 2013 are due primarily to borrowings to finance the acquisitions of businesses.

Interest and Other Income

Our non-operating other income consists of the following:

	NGL Energy Partners LP								NGL Supply, Inc.
	Year Ended			Year Ended		Six Months Ended			Six Months Ended
	March 31,			March 31,		March 31,			September 30,
	2013			2012		2011			2010
	(in thousands)
Interest income	$	1,261		$	765	$	221		$	66
Gain (loss) on sale of assets	(187		)	71		(16		)	124
Other	447			219		119			—
	$	1,521		$	1,055	$	324		$	190

Income Tax Provision

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

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We have two taxable corporate subsidiaries in the United States and three taxable corporate subsidiaries in Canada. The income tax provision reported in our consolidated statements of operations relates primarily to these subsidiaries.

Prior to September 30, 2010, NGL Supply was a taxable entity. NGL Supply’s income tax benefit of $1.4 million for the six months ended September 30, 2010 consisted primarily of U.S. federal deferred income taxes. This provision approximated the U.S. federal statutory rate of 35%.

See Note 9 to our consolidated financial statements included elsewhere in this annual report for additional description of income tax provisions.

Noncontrolling Interests

As of March 31, 2013, we have three consolidated subsidiaries in which outside parties own interests. Our ownership interests in these subsidiaries range from 60% to 80%. One of these subsidiaries was formed in March 2012, and the other two were acquired in June 2012 and October 2012, respectively. The noncontrolling interest shown in our consolidated statements of operations represents the other owners’ interests in these entities.

The noncontrolling interest shown in NGL Supply’s consolidated statements of operations represents the 30% interest in Gateway that NGL Supply did not own. We purchased this additional 30% interest in October 2010.

Non-GAAP Financial Measures

The following tables reconcile net income (loss) attributable to parent equity to our EBITDA and Adjusted EBITDA, each of which are non-GAAP financial measures, for the periods indicated:

	NGL Energy Partners LP								NGL Supply, Inc.
	Year Ended		Year Ended			Six Months Ended			Six Months Ended
	March 31,		March 31,			March 31,			September 30,
	2013		2012			2011			2010
EBITDA:
Net income (loss) attributable to parent equity	$	47,940	$	7,876		$	12,679		$	(2,515	)
Provision (benefit) for income taxes	1,875		601			—			(1,417		)
Interest expense	32,994		7,620			2,482			372
Loss on early extinguishment of debt	5,769		—			—			—
Depreciation and amortization	73,739		15,911			3,841			1,789
EBITDA	$	162,317	$	32,008		$	19,002		$	(1,771	)
Unrealized (gain) loss on derivative contracts	5,275		4,384			(1,357		)	200
Loss (gain) on sale of assets	187		(71		)	16			(124		)
Share-based compensation expense	10,138		—			—			—
Adjusted EBITDA	$	177,917	$	36,321		$	17,661		$	(1,695	)

We define EBITDA as net income (loss) attributable to parent equity, plus income taxes, interest expense 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 of assets and share-based compensation expenses. 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 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 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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Segment Operating Results

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our and NGL Supply’s historical results of operations for the periods presented due to the following reasons:

·In connection with our formation transactions, we also acquired the retail propane operations of Hicksgas. This acquisition was accounted for as a business combination, and the assets acquired and liabilities assumed were recorded in our consolidated financial statements at acquisition date fair value.

·During the fiscal years ended March 31, 2012 and 2013, we completed a number of acquisitions, as described under “Overview” above. We have significantly expanded our operations through these acquisitions.

·NGL Supply’s historical consolidated financial statements include U.S. federal and state income tax expense. Because we have elected to be treated as a partnership for tax purposes, we are generally not subject to U.S. federal income tax and certain state income taxes.

·As a result of our initial public offering, we incur incremental general and administrative expenses that are attributable to operating as a publicly traded partnership. These expenses include annual and quarterly reporting; tax return and Schedule K-1 preparation and distribution expenses; Sarbanes-Oxley compliance expenses; expenses associated with listing on the NYSE; independent auditor fees; legal fees; investor relations expenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation. These incremental general and administrative expenses are not reflected in the historical consolidated financial statements of NGL Supply.

After we completed the formation transactions, the financial statements of NGL Supply became our financial statements for all periods prior to October 1, 2010, the net equity (net book value) of NGL Supply became our equity and the net book value of all of the assets and liabilities of NGL Supply became the accounting basis for our assets and liabilities. There were no adjustments to the carryover basis of the assets and liabilities that we acquired from NGL Supply.

Our results of operations are also significantly impacted by seasonality, primarily due to the increase in volumes of propane sold by our retail propane and natural gas liquids logistics segments during the peak heating season of October through March. As a result of our business combination with NGL Supply and Hicksgas in October 2010 and the impact of seasonality, our results of operations for the six months ended March 31, 2011 are not indicative of the results we would anticipate for a full fiscal year, and are not comparable to the results of operations of NGL Supply for the six months ended September 30, 2010.

As described above, the consolidated statement of operations for the year ended March 31, 2011 is divided into two six-month periods. The financial statements for the first six months of that fiscal year were those of NGL Supply, and the financial statements for the last six months of that fiscal year are those of NGL Energy Partners LP. The following analysis compares operating income among the following periods:

·Year Ended March 31, 2013 Compared to Year Ended March 31, 2012;

·Year Ended March 31, 2012 Compared to Six Months Ended March 31, 2011;

·Six Months Ended March 31, 2012 Compared to Six Months Ended March 31, 2011;

·Six Months Ended September 30, 2011 (NGL Energy Partners LP) Compared to Six Months Ended September 30, 2010 (NGL Supply); and

·Six Months Ended March 31, 2011 (NGL Energy Partners LP) Compared to Six Months Ended September 30, 2010 (NGL Supply).

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Year Ended March 31, 2013 of NGL Energy Partners LP

Compared to Year Ended March 31, 2012 of NGL Energy Partners LP

Volumes Sold or Delivered

The following table summarizes the volume of product sold and wastewater delivered for the years ended March 31, 2013 and 2012. Gallons sold by our natural gas liquids logistics segment shown in the table below include sales to our retail 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 barrels sold	24,373	—	—	—		24,373	—
Water services
Barrels of water delivered	25,009	—	—	—		25,009	—
Natural gas liquids logistics
Propane gallons sold	912,625	659,921	—		(3)	140,632	112,072
Other natural gas liquids gallons sold	632,695	134,999	—		(3)	447,449	50,247
Retail propane
Propane gallons sold	144,379	78,236	54,949	—		—	11,194
Distillate gallons sold	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, the operations of North American (acquired in February 2012) from April 1, 2012 through January 31, 2013, the operations of Downeast (acquired in May 2012), and the operations of 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 services 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 most recent 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 services	8,576			—			8,576
Natural gas liquids logistics	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 approximately $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	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 $5.7 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 generated $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 Services

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

Revenues:
Water treatment and disposal	$	54,334
Water transportation	7,893
Total revenues (1)	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

(1)   Revenues include $17.2 million of intersegment sales that are eliminated in our consolidated statement of operations.

Revenues. Our water services 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 services 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 services segment generated $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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Natural Gas Liquids Logistics

The following table compares the operating results of our natural gas liquids logistics segment for the periods indicated:

	Year Ended				Change Resulting From
	March 31,				High Sierra
	2013		2012		Combination		Other
	(in thousands)
Revenues:
Propane sales	$	841,448	$	923,022	$	115,606	$	(197,180	)
Other natural gas liquids sales	858,276		251,627		563,211		43,438
Transportation and 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 NGLs	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)The revenues in this table include $128.9 million of sales to our retail propane segment during the year ended March 31, 2013 and $66.0 million of sales to our retail propane segment during the year ended March 31, 2012. These intercompany sales, along with a corresponding amount of cost of sales, are eliminated in our consolidated statement of operations.

Revenues. Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale propane sales decreased approximately $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 approximately 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 natural gas liquids increased approximately $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 approximately 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 natural gas liquids (primarily butane). These operations sold 447.4 million gallons of other natural gas liquids at an average price of $1.26 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.

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

Cost of Sales. Exclusive of the operations acquired in our June 2012 merger with High Sierra, costs of wholesale propane sales decreased approximately $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 approximately 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 natural gas liquids increased approximately $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 approximately 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 natural gas liquids sales during the year ended March 31, 2013 was reduced by approximately $0.2 million due to realized gains on derivatives.

During the year ended March 31, 2013, the cost of other natural gas liquids sales of the High Sierra operations was $546.6 million. These operations sold 447.4 million gallons of other natural gas liquids (primarily butane) at an average price of $1.22 per gallon. Costs of sales of other natural gas liquids 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 rail cars 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 natural gas liquids logistics segment increased approximately $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 natural gas liquids logistics 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 natural gas liquids logistics segment increased approximately $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 natural gas liquids logistics 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 natural gas liquids logistics segment increased approximately $4.3 million during the year ended March 31, 2013, as compared to depreciation and amortization expense of approximately $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 natural gas liquids logistics segment recorded $3.1 million of depreciation and amortization expense related to assets acquired in our merger with High Sierra.

Operating Income. Our natural gas liquids logistics segment had operating income of approximately $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 periods indicated:

	Year Ended				Change Resulting From
	March 31,				Retail
	2013		2012		Combinations(*)		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

(*)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, the operations of North American (acquired in February 2012) from April 1, 2012 through January 31, 2013, the operations of Downeast (acquired in May 2012), and the operations of certain other smaller retail propane business acquired during fiscal 2013.

Revenues. Propane sales for the year ended March 31, 2013 increased approximately $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 approximately 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 approximately $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 higher than volumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder

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than that of fiscal 2012.

Our acquired Osterman, Pacer, North American, and Downeast operations generated propane cost of sales of $63.1 million during the year ended March 31, 2013, consisting of approximately 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 generated $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 approximately $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 generated $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 approximately $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 generated $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 approximately $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 generated $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 approximately $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 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.

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Year Ended March 31, 2012 of NGL Energy Partners LP

Compared to Six Months Ended March 31, 2011 of NGL Energy Partners LP

The following table shows our operating income for the periods indicated (in thousands):

	Year Ended		Six Months Ended
	March 31,		March 31,
	2012		2011
Revenues	$	1,310,473	$	622,232
Expenses:
Cost of sales	1,217,023		583,032
Operating expenses	47,300		15,898
General and administrative expenses	16,009		5,024
Depreciation and amortization	15,111		3,441
Total expenses	1,295,443		607,395
Operating income	$	15,030	$	14,837

Revenues and Cost of Sales. Operating revenues and cost of sales were significantly higher during the year ended March 31, 2012 than during the six months ended March 31, 2011, due in part to the Osterman, SemStream, Pacer, and North American combinations. Three of these acquisitions significantly expanded our retail propane customer base. The SemStream combination significantly expanded our natural gas liquids logistics business, as the acquisition of SemStream’s terminals and leased rail cars gave us considerably more flexibility in the wholesale markets we can serve. In addition, the year ended March 31, 2012 included twelve months of activity, whereas the six months ended March 31, 2011 included only six months of activity.

Operating and General and Administrative Expenses. Operating and general and administrative expense was significantly higher during the year ended March 31, 2012 than during the six months ended March 31, 2011, due primarily to business combinations. In addition, the year ended March 31, 2012 included twelve months of activity, whereas the six months ended March 31, 2011 included only six months of activity.

Depreciation and Amortization. Depreciation and amortization expense was significantly higher during the year ended March 31, 2012 than during the six months ended March 31, 2011, due primarily to business combinations. In the business combination accounting, we recorded a significant amount of property, plant and equipment and customer relationship intangible assets. In addition, the year ended March 31, 2012 included twelve months of activity, whereas the six months ended March 31, 2011 included only six months of activity.

Due to the limitations inherent in comparing a twelve month period to a six month period, we have provided supplemental information below to compare the first and last six months of fiscal 2012 and 2011 to the corresponding periods in the prior years. Where possible, we have identified the changes from period to period that are attributable to acquisitions. This is not possible for the wholesale operations acquired in our business combination with SemStream; for product purchases and sales subsequent to the combination date, it is not possible to determine which of the transactions are attributable to our historical operations and which are attributable to the operations acquired from SemStream.

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Six Months Ended March 31, 2012 for NGL Energy Partners LP

Compared to Six Months Ended March 31, 2011 for NGL Energy Partners LP

Volumes Sold

The following table summarizes the volume of gallons sold by our retail propane and natural gas liquids logistics segments for the six months ended March 31, 2012 and the six months ended March 31, 2011, respectively. Gallons sold by our natural gas liquids logistics segment shown in the table below include sales to our retail segment.

	Six Months Ended		Change Resulting From
	March 31,	March 31,	Retail	SemStream		Other
	2012	2011	Combinations	Combination		Volume		Percentage
	(gallons in thousands)
Retail propane —
Propane	65,272	34,932	34,839	—		(4,499	)	(12.9	)%
Distillates	1,650	—	1,650	—		—		—
Natural gas liquids logistics —
Propane	447,755	372,504	—		(*)	75,251		20.2	%
Other NGLs	96,899	49,465	—		(*)	47,434		95.9	%

(*)  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 this combination and which were attributable to our historical wholesale business.

Operating income by segment

Our operating income by segment is as follows:

	Six Months Ended
	March 31,			March 31,
Segment	2012			2011			Change
	(in thousands)
Retail propane	$	15,908		$	7,362		$	8,546
Natural gas liquids logistics	11,128			9,590			1,538
Corporate general and adminstrative expenses	(1,795		)	(2,115		)	320
	$	25,241		$	14,837		$	10,404

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Retail Propane

The following table compares the operating results of our retail propane segment for the periods indicated:

	Six Months Ended				Change Resulting From
	March 31,		March 31,		Retail
	2012		2011		Combinations		Other
	(in thousands)
Revenues:
Propane sales	$	149,161	$	67,175	$	85,687	$	(3,701	)
Distillate sales	6,547		—		6,547		—
Service and rental income	6,575		2,981		3,339		255
Parts, fittings, appliance and other sales	4,974		2,657		1,693		624
Total revenues	167,257		72,813		97,266		(2,822		)
Expenses:
Cost of sales - propane	98,830		44,744		55,174		(1,088		)
Cost of sales - distillates	5,728		—		5,728		—
Cost of sales - other sales	4,270		2,241		1,790		239
Operating expenses	26,882		13,517		13,478		(113		)
General and administrative expenses	6,644		2,062		4,631		(49		)
Depreciation and amortization	8,995		2,887		6,081		27
Total expenses	151,349		65,451		86,882		(984		)
Segment operating income	$	15,908	$	7,362	$	10,384	$	(1,838	)

Revenues. Propane sales for the six months ended March 31, 2012 increased $82.0 million as compared to propane sales of $67.2 million for the six months ended March 31, 2011. The increase in propane sales is due primarily to the impact of our Osterman combination in October 2011, our Pacer combination in January 2012, and our North American combination in February 2012. Excluding the impact of these combinations, propane sales were lower during the six months ended March 31, 2012 as compared to the six months ended March 31, 2011, due primarily to a decline in volumes from 34.9 million gallons during the six months ended March 31, 2011 to 30.4 million gallons during the six months ended March 31, 2012. The decrease in volumes was due primarily to unusually warm weather during the heating season, which reduced demand. The decrease in volumes was partially offset by an increase in the average price per gallon from $1.92 during the six months ended March 31, 2011 to $2.08 during the six months ended March 31, 2012.

Our acquired Osterman, Pacer, and North American operations generated sales volumes of 34.8 million gallons at an average price of $2.46 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, farther away from the primary areas of propane supply than are the markets served by our historical operations.

Cost of Sales. Propane cost of sales for the six months ended March 31, 2012 increased $54.1 million as compared to propane cost of sales of $44.7 million for the six months ended March 31, 2011. The increase in propane cost of sales is due primarily to the impact of our Osterman combination in October 2011, our Pacer combination in January 2012, and our North American combination in February 2012. Excluding the impact of these combinations, propane cost of sales was lower during the six months ended March 31, 2012 as compared to the six months ended March 31, 2011, due primarily to a decline in volumes from 34.9 million gallons during the six months ended March 31, 2011 to 30.4 million gallons during the six months ended March 31, 2012. The decrease in volumes was due primarily to unusually warm weather during the heating season, which reduced demand. The decrease in volumes was partially offset by an increase in the average cost per gallon sold from $1.28 during the six months ended March 31, 2011 to $1.43 during the six months ended March 31, 2012.

Our acquired Osterman, Pacer, and North American operations generated sales volumes of 34.8 million gallons at an average cost of $1.58 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, farther away from the primary areas of propane supply than are the markets served by our historical operations.

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Operating Expenses. Operating expenses of our retail propane segment increased $13.4 million during the six months ended March 31, 2012 as compared to operating expenses of $13.5 million during the six months ended March 31, 2011. This increase is due primarily to our Osterman, Pacer, and North American combinations.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased $4.6 million during the six months ended March 31, 2012 as compared to general and administrative expenses of $2.1 million during the six months ended March 31, 2011. This increase is due primarily to our Osterman, Pacer, and North American combinations.

Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased $6.1 million during the six months ended March 31, 2012 as compared to depreciation and amortization expense of $2.9 million during the six months ended March 31, 2011. This increase is due primarily to the impact of depreciation and amortization on assets acquired in the Osterman combination in October 2011, our Pacer combination in January 2012, and our North American combination in February 2012.

Operating Income. Our retail propane segment had operating income of $15.9 million during the six months ended March 31, 2012 as compared to operating income of $7.4 million during the six months ended March 31, 2011, an increase of $8.5 million. The increased operating income is due primarily to the operations acquired in our business combinations during the six months ended March 31, 2012. Operating income from our historical retail operations was lower during the six months ended March 31, 2012 than in the corresponding period in the prior year, due primarily to lower volumes sold as a result of mild weather conditions during the winter heating season.

Natural Gas Liquids Logistics

The following table compares the operating results of our natural gas liquids logistics segment for the periods indicated:

	Six Months Ended
	March 31,		March 31,
	2012		2011		Change
	(in thousands)
Revenues:
Propane sales	$	611,781	$	477,774	$	134,007
Other natural gas liquids sales	174,921		90,746		84,175
Transportaion and other revenues	1,702		1,183		519
Total revenues (1)	788,404		569,703		218,701
Expenses:
Cost of sales	766,842		556,331		210,511
Operating expenses	6,026		2,381		3,645
General and adminstrative expenses	1,370		847		523
Depreciation and amortization expense	3,038		554		2,484
Total expenses	777,276		560,113		217,163
Segment operating income	$	11,128	$	9,590	$	1,538

(1)The revenues in this table include $46.1 million of sales to our retail propane segment during the six months ended March 31, 2012 and $20.3 million of sales to our retail propane segment during the six months ended March 31, 2011. These intercompany sales, along with a corresponding amount of cost of sales, are eliminated in our consolidated statement of operations.

Revenues. Total wholesale revenues increased $218.7 million during the six months ended March 31, 2012 as compared to wholesale revenues of $569.7 million during the six months ended March 31, 2011. This overall increase in wholesale revenues is due primarily to the impact of our SemStream combination and an increase in wholesale customer pre-buys as compared to the prior fiscal year. Sales of other natural gas liquids (including sales to affiliates) increased approximately $84.2 million as compared to the same period in fiscal 2011 primarily as a result of the impact of the SemStream combination and resulting acquisition of owned and leased rail cars, which have allowed us to significantly expand our marketing of such liquids.

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The increase in propane sales of $134.0 million consists of an increase of $102.8 million resulting from volume increases and an increase of $31.2 million resulting from an increase in average sales price from $1.28 per gallon during the six months ended March 31, 2011 to $1.37 per gallon during the six months ended March 31, 2012.

The increase in sales of other natural gas liquids (including sales to affiliates) of $84.2 million consists of an increase of $85.6 million resulting from volume increases, partially offset by a decrease of $1.5 million resulting from a decrease in the average sales price to $1.81 per gallon during the six months ended March 31, 2012, as compared to an average sales price of $1.83 per gallon during the six months ended March 31, 2011.

Cost of Sales. Total wholesale cost of sales increased $210.5 million during the six months ended March 31, 2012 as compared to total wholesale cost of sales of $556.3 million during the six months ended March 31, 2011. The increase in wholesale cost of sales consisted of an increase in the cost of propane of $129.5 million, an increase in the cost of other natural gas liquids of $80.5 million, and an increase in storage and handling costs of approximately $0.5 million.

The increased cost of propane was due to an increase in volume and an increase in the average product cost of propane from $1.25 per gallon (excluding storage and handling costs) during the six months ended March 31, 2011 to $1.33 per gallon during the six months ended March 31, 2012.

The increased cost of other natural gas liquids was due to the increase in volume sold, partially offset by a decrease in the average product cost of other natural gas liquids per gallon from $1.83 during the six months ended March 31, 2011 to $1.76 during the six months ended March 31, 2012.

The increase in storage and handling costs incurred during the six months ended March 31, 2012 was driven primarily by increases in volume.

The margin per gallon sold was unusually high during the fourth quarter of fiscal 2012, due primarily to sales in February and March under fixed price sale commitments we had entered into prior to the beginning of the heating season and to the impact of commodity derivative instruments. We entered into certain commodity swaps as economic hedges against the potential decline in the market value of our inventories. When commodity prices declined throughout the six months ended March 31, 2012, these commodity swaps increased in value.

Operating Expenses. Operating expenses of our natural gas liquids logistics segment increased $3.6 million during the six months ended March 31, 2012 as compared to operating expenses of $2.4 million during the six months ended March 31, 2011. This increase is due primarily to the increased compensation and related expenses resulting from our SemStream combination and the increase in our personnel related to that combination.

General and Administrative Expenses. General and administrative expenses of our natural gas liquids logistics segment increased $0.5 million during the six months ended March 31, 2012 as compared to general and administrative expenses of $0.8 million during the six months ended March 31, 2011. This increase in general and administrative expenses is due primarily to an increase in the number of employees as a result of the SemStream combination.

Depreciation and Amortization. Depreciation and amortization expense of the natural gas liquids logistics segment increased $2.5 million during the six months ended March 31, 2012 as compared to depreciation and amortization expense of $0.6 million during the six months ended March 31, 2011. This increase is due to the depreciation and amortization expense related to assets acquired in the SemStream combination.

Operating Income. Our natural gas liquids logistics segment had operating income of $11.1 million during the six months ended March 31, 2012 as compared to operating income of $9.6 million during the six months ended March 31, 2011. This increase in operating income of $1.5 million is due primarily to increased margins from product sales, partially offset by an increase in operating and general and administrative expenses from the SemStream combination.

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Six Months Ended September 30, 2011 for NGL Energy Partners LP

Compared to Six Months Ended September 30, 2010 for NGL Supply

Volumes Sold

The following table summarizes the volume of gallons sold by our retail propane and natural gas liquids segments for the six months ended September 30, 2011 and the six months ended September 30, 2010, respectively. Gallons sold by our natural gas liquids logistics segment shown in the table below include sales to our retail segment.

	Six Months Ended		Change Resulting From
	September 30,	September 30,	Acquisition	Other
	2011	2010	of Hicksgas	Volume		Percentage
	(gallons in thousands)
Retail propane	12,964	3,747	9,198	19		0.5	%
Natural gas liquids logistics	250,265	272,422	—	(22,157	)	(8.1	)%

Our retail propane sales volumes for the six months ended September 30, 2011 increased 9.2 million gallons as compared to sales of 3.7 million gallons during the six months ended September 30, 2010 due entirely to the impact of our Hicksgas acquisition in October 2010. Hicksgas had retail sales of 9.2 million gallons during the six months ended September 30, 2011. The increased sales of our pre-existing business during the six months ended September 30, 2011 were not significant.

Sales of our natural gas liquids logistics segment decreased 22.2 million gallons during the six months ended September 30, 2011 as compared to sales of 272.4 million gallons during the six months ended September 30, 2010. This decrease in sales is due primarily to a decrease in purchases for storage by our wholesale customers and a reduced level of liftings from storage by our pre-sale customers.

Operating income (loss) by segment

Our operating income (loss) by segment is as follows:

	Six Months Ended
	September 30,			September 30,
Segment	2011			2010			Change
	(in thousands)
Retail propane	$	(6,292	)	$	(2,569	)	$	(3,723	)
Natural gas liquids logistics	(1,393		)	865			(2,258		)
Corporate general and adminstrative expenses	(2,526		)	(2,091		)	(435		)
	$	(10,211	)	$	(3,795	)	$	(6,416	)

Corporate general and administrative increased $0.4 million during the six months ended September 30, 2011 compared to corporate general and administrative expenses of $2.1 million during the six months ended September 30, 2010. This increase is due to the costs of being a public company.

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Retail Propane

The following table compares the operating results of our retail propane segment for the periods indicated:

	Six Months Ended						Change Resulting From
	September 30,			September 30,			Acquisition of
	2011			2010			Hicksgas			Other
	(in thousands)
Revenues:
Propane sales	$	26,256		$	6,128		$	18,790		$	1,338
Service and rental income	2,701			484			2,228			(11		)
Parts, fittings, appliance and other sales	3,120			256			2,907			(43		)
Total revenues	32,077			6,868			23,925			1,284
Expenses:
Cost of sales - propane	18,892			4,489			13,324			1,079
Cost of sales - other sales	2,422			260			2,256			(94		)
Operating expenses	12,294			3,330			8,830			134
General and administrative expenses	2,306			488			1,337			481
Depreciation and amortization	2,455			870			1,565			20
Total expenses	38,369			9,437			27,312			1,620
Segment operating loss	$	(6,292	)	$	(2,569	)	$	(3,387	)	$	(336	)

Revenues. Propane sales for the six months ended September 30, 2011 increased $20.1 million as compared to propane sales of $6.1 million during the six months ended September 30, 2010. This increase is due primarily to the impact of our Hicksgas acquisition in October 2010. During the six months ended September 30, 2011, Hicksgas had total propane sales of $18.8 million, consisting of 9.2 million gallons sold at an average sales price of $2.04 per gallon. Excluding the impact of Hicksgas, propane sales of our pre-existing business increased $1.3 million during the six months ended September 30, 2011 as compared to the same period in 2010, due entirely to the impact of price increases.

Cost of Sales. Propane cost of sales for the six months ended September 30, 2011 increased $14.4 million as compared to propane cost of sales of $4.5 million during the six months ended September 30, 2010. This increase is due primarily to the impact of our Hicksgas acquisition in October 2010. During the six months ended September 30, 2011, Hicksgas’ average propane cost per gallon was $1.45. Excluding the impact of Hicksgas, the propane cost of sales of our pre-existing business increased $1.1 million during the six months ended September 30, 2011 as compared to the same period in 2010, due entirely to the effect of propane price increases. Overall, our propane cost per gallon averaged $1.46 during the six months ended September 30, 2011 compared to $1.20 per gallon during the six months ended September 30, 2010.

Operating Expenses. Operating expenses of our retail propane segment increased $9.0 million during the six months ended September 30, 2011 as compared to operating expenses of $3.3 million during the six months ended September 30, 2010. This increase is due primarily to the impact of our Hicksgas acquisition in October 2010. Hicksgas had operating expenses of $8.8 million during the six months ended September 30, 2011. The increase in operating expenses of our pre-existing business during the six months ended September 30, 2011 was not material.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased $1.8 million during the six months ended September 30, 2011 as compared to general and administrative expenses of $0.5 million during the six months ended September 30, 2010. This increase is due in part to the impact of our Hicksgas acquisition in October 2010. During the six months ended September 30, 2011, Hicksgas had general and administrative expenses of $1.3 million. In addition, the general and administrative expenses of our pre-existing business increased $0.5 million during the six months ended September 30, 2011 as compared to the same period in 2010. This increase is due to acquisition costs of $0.6 million expensed during the period related primarily to our Osterman acquisition.

Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased $1.6 million during the six months ended September 30, 2011 as compared to depreciation and amortization expense of $0.9 million during the six months ended September 30, 2010. This increase is due to the impact of our Hicksgas acquisition in October 2010. Hicksgas had depreciation and amortization expense of $1.6 million during the six months ended September 30, 2011.

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Operating Loss. Our retail propane segment had an operating loss of $6.3 million during the six months ended September 30, 2011 as compared to an operating loss of $2.6 million during the six months ended September 30, 2010, an increased loss of $3.7 million. The increased operating loss is due primarily to the impact of our Hicksgas acquisition in October 2010. Hicksgas had an operating loss of $3.4 million during the six months ended September 30, 2011. The operating loss of our pre-existing business increased approximately $0.3 million during the six months ended September 30, 2011 primarily as a result of expensing the acquisition costs related to our Osterman acquisition.

Natural Gas Liquids Logistics

The following table compares the operating results of our natural gas liquids logistics segment for the periods indicated:

	Six Months Ended
	September 30,			September 30,
	2011			2010		Change
				(in thousands)
Revenues:
Product sales	$	387,947		$	315,364	$	72,583
Storage revenues	760			959		(199		)
Total revenues (1)	388,707			316,323		72,384
Expenses:
Cost of sales	386,011			312,407		73,604
Operating expenses	2,098			1,901		197
General and adminstrative expenses	1,368			631		737
Depreciation and amortization expense	623			519		104
Total expenses	390,100			315,458		74,642
Segment operating income (loss)	$	(1,393	)	$	865	$	(2,258	)

(1)The revenues in this table include $19.9 million of sales to our retail propane segment during the six months ended September 30, 2011 and $6.2 million of sales to our retail propane segment during the six months ended September 30, 2010. These intercompany sales, along with a corresponding amount of cost of sales, are eliminated in our consolidated statement of operations.

Revenues. Product sales increased $72.6 million during the six months ended September 30, 2011 as compared to product sales of $315.4 million during the six months ended September 30, 2010. This increase is due to an increase in sales of $106.9 million as a result of increases in our average sales price, partially offset by a decrease in sales of $34.3 million as a result of a decrease in our sales volumes. Our average sales price during the six months ended September 30, 2011 was $1.55 per gallon, compared to $1.16 per gallon during the six months ended September 30, 2010. The increase in price is due to the overall increase in the spot price of propane during the respective periods.

Cost of Sales. Cost of sales increased $73.6 million during the six months ended September 30, 2011 as compared to cost of sales of $312.4 million during the six months ended September 30, 2010. This increase is due to an increase in cost of sales of $107.8 million as a result of the increase in the cost of propane, partially offset by a decrease in cost of sales of $34.2 million as a result of the decrease in sales volume. Our overall average cost of propane during the six months ended September 30, 2011 was $1.54 per gallon, compared to $1.15 per gallon during the six months ended September 30, 2010. The increase in propane cost is due to the overall increase in the spot price of propane during the respective periods.

Operating Expenses. Operating expenses of our natural gas liquids logistics segment increased $0.2 million during the six months ended September 30, 2011 as compared to operating expenses of $1.9 million during the six months ended September 30, 2010. This increase is due to increased compensation and insurance expenses resulting primarily from an increase in employees during the period.

General and Administrative Expenses. General and administrative expenses of our natural gas liquids logistics segment increased $0.7 million during the six months ended September 30, 2011 as compared to general and administrative expenses of $0.6

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million during the six months ended September 30, 2010. This increase is due primarily to an increase in compensation expense due to an increase in employees and to expensing acquisition costs of $0.4 million related to our acquisition of SemStream.

Operating Income (Loss). Our natural gas liquids logistics segment had an operating loss of $1.4 million during the six months ended September 30, 2011 as compared to operating income of $0.9 million during the six months ended September 30, 2010, a decrease in operating income of $2.3 million. This decrease is due primarily to a decrease in product margin of $1.0 million, increased operating expenses of $0.2 million and an increase in general and administrative expenses of $0.7 million.

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Six Months Ended March 31, 2011 for NGL Energy Partners LP

Compared to Six Months Ended September 30, 2010 for NGL Supply

Operating Revenues. Our operating revenues for the six months ended March 31, 2011 of $622.2 million exceeded the operating revenues of NGL Supply for the six months ended September 30, 2010 by approximately $305.3 million. This increase is due to the significant increase in volume of propane sales for both our retail propane and natural gas liquids logistics segments. This increase in volume is due to the combined impact of seasonality and the acquisition of Hicksgas. Propane prices also increased during the six months ended March 31, 2011 as compared to the prices during the six months ended September 30, 2010.

Cost of Sales. Our cost of sales for the six months ended March 31, 2011 of $583.0 million exceeded the cost of sales of NGL Supply for the six months ended September 30, 2010 by approximately $272.1 million. This increase is also due to the significant increase in volume of propane sales of our retail propane and natural gas liquids logistics segments as a result of the combined impact of seasonality and the acquisition of Hicksgas. Cost of sales also increased as a result of the increase in propane prices during the six months ended March 31, 2011 as compared to propane prices during the six months ended September 30, 2010.

Operating and General and Administrative Expenses. Our operating and general and administrative expenses for the six months ended March 31, 2011 totaled approximately $20.9 million as compared to total costs of $8.4 million for the six months ended September 30, 2010, an increase of approximately $12.5 million. The operations of Hicksgas resulted in an increase in operating and general and administrative expenses of $11.4 million during the six months ended March 31, 2011 as compared to the six months ended September 30, 2010. In addition, our costs during the six months ended March 31, 2011 increased as a result of costs incurred that were related to the acquisition of Hicksgas.

Depreciation and Amortization. Our depreciation and amortization expense for the six months ended March 31, 2011 totaled $3.4 million as compared to $1.4 million for the six months ended September 30, 2010. This increase is due primarily to the $2.0 million of depreciation and amortization expense of Hicksgas for the six months ended March 31, 2011.

Net Income (Loss). For the six months ended March 31, 2011, we realized net income of $12.7 million, compared to a net loss of $2.5 million for the six months ended September 30, 2010. This increase in net income is due primarily to the increased gross margin resulting from the seasonal impact of increased volumes of propane sales and the impact of the acquisition of Hicksgas.

Seasonality

Seasonality impacts our natural gas liquids logistics 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, 2013, approximately 74% of our retail propane volume was sold during the peak heating season from October through March. Consequently, sales, operating profits and positive operating cash flows are generated mostly in the third and fourth quarters of each fiscal year. We have historically realized operating losses and negative operating cash flows during our first and second fiscal quarters. 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 natural gas liquids logistics operations are the greatest.

Under our partnership agreement, we are required to make distributions in an amount equal to all of our available cash, if any, no more than 45 days after the end of each fiscal quarter to holders of record on the applicable record dates. Available cash generally means all cash on hand at the end of the respective fiscal quarter less the amount of cash reserves established by our general partner in its reasonable discretion for future cash requirements. These reserves are retained for the proper conduct of our business,

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debt principal and interest payments and for distributions to our unitholders during the next four quarters. Our general partner reviews the level of available cash on a quarterly basis based upon information provided by management.

We believe that our anticipated cash flows from operations and the borrowing capacity under our revolving credit agreement will be sufficient to meet our liquidity needs for the next 12 months. 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, 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.

Long-Term Debt

On June 19, 2012, we entered into a credit agreement (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”). Also on June 19, 2012, we entered into a note purchase agreement (the “Note Purchase Agreement”) whereby we issued $250 million of Senior Notes in a private placement (the “Senior Notes”). We used the proceeds from the issuance of the Senior Notes and borrowings under the Credit Agreement to repay existing debt and to fund the merger with High Sierra.

Credit Agreement

The Working Capital Facility had a total capacity of $242.5 million for cash borrowings and letters of credit at March 31, 2013. At March 31, 2013, we had outstanding cash borrowings of $36.0 million and outstanding letters of credit of $60.1 million on the Working Capital Facility, leaving a remaining capacity of $146.4 million at March 31, 2013. The Expansion Capital Facility had a total capacity of $527.5 million for cash borrowings at March 31, 2013. At March 31, 2013, we had outstanding cash borrowings of $441.5 million on the Expansion Capital Facility, leaving a remaining capacity of $86.0 million at March 31, 2013. 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. At March 31, 2013, the borrowing base provisions of the Credit Agreement did not have any impact on the capacity available under the Working Capital Facility.

During May 2013, we entered into an amendment to the Credit Agreement that increased the total capacity on the Working Capital Facility from $242.5 million to $325.0 million and increased the total capacity on the Expansion Capital Facility from $527.5 million to $725.0 million. We paid approximately $2.1 million of fees related to this amendment to the Credit Agreement.

The commitments under the Credit Agreement expire on June 19, 2017. 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 1.75% to 2.75% per annum or (ii) an adjusted LIBOR rate plus a margin of 2.75% to 3.75% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At March 31, 2013, the interest rate in effect on outstanding LIBOR borrowings was 3.21%, calculated as the LIBOR rate of 0.21% plus a margin of 3.0%. At March 31, 2013, interest rate in effect on outstanding base rate borrowings was 5.25%, calculated as the base rate of 3.25% plus a margin of 2.0%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. 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, 2013, our leverage ratio was approximately 3.0 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, 2013, our interest coverage ratio was approximately 7.0 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

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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, 2013, we were in compliance with all covenants under the Credit Agreement.

Senior Notes

The Senior Notes have an aggregate principal amount of $250 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 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 substantially the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which is 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 million, (iv) the rendering of a judgment for the payment of money in excess of $10 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, 2013, we were in compliance with all covenants under the Note Purchase Agreement.

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.

Balances Outstanding and Rates

At March 31, 2013, our outstanding borrowings and interest rates under our revolving credit facility were as follows (dollars in thousands):

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	441,500	3.21	%
Working capital facility —
LIBOR borrowings	20,000		3.21	%
Base rate borrowings	16,000		5.25	%

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The following table provides certain information on revolving credit facility borrowings during the year ended March 31, 2013 (dollars in thousands):

	Average						Average
	Daily		Lowest		Highest		Interest
	Balance		Balance		Balance		Rate
New credit facility (June 19, 2012 - March 31, 2013) —
Expansion loans	$	351,355	$	254,000	$	451,000	3.48	%
Working capital loans	92,626		—		153,500		3.77	%
Previous credit facility (April 1, 2012 - June 19, 2012) —
Acquisition loans	222,238		186,000		239,275		3.65	%
Working capital loans	42,700		22,000		67,500		4.07	%

Business Combinations

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

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Cash Flows

The following summarizes the sources and uses of our cash flows for the periods indicated:

	NGL Energy Partners LP									NGL Supply
	Year Ended			Year Ended			Six Months Ended			Six Months Ended
	March 31,			March 31,			March 31,			September 30,
Cash Flows Provided by (Used In):	2013			2012			2011			2010
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	146,395		$	20,459		$	15,905		$	(2,491	)
Changes in operating assets and liabilities	(14,164		)	69,870			18,104			(28,258		)
Operating activities	$	132,231		$	90,329		$	34,009		$	(30,749	)
Investing activities	(546,218		)	(296,897		)	(18,438		)	333
Financing activities	417,716			198,063			(3,170		)	10,161

Operating Activities. The growth in our operating cash flows over the period from fiscal 2011 — fiscal 2013 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, 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. The seasonality of our retail propane and natural gas liquids logistics business had a significant effect on our cash flows from operating activities during fiscal year 2011. As shown in the table above, cash flows from operations were significantly greater during the winter heating season of fiscal 2011 than during the first six months of the fiscal year.

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Investing Activities. Our cash flows from investing activities are primarily impacted by our capital expenditures and business combinations. In periods where we are engaged in significant acquisitions, we will generally realize negative cash flows from investing activities, which may require us to increase the borrowings under our acquisition or working capital facilities. During the year ended March 31, 2013, we completed thirteen acquisitions, for which we paid a combined cash amount of $490.4 million. 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, approximately $58.7 million represented expansion capital and approximately $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 historically have been due to advances from and repayments of 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 fund the cash flow deficits through our working capital facility. Cash flows required by our investing activities in excess of cash available through our operating activities have historically been funded by our acquisition credit facility. In the table above, we had positive cash flows from financing activities due to the increase in our debt levels to fund our negative cash flows from operating activities during the six months ended September 30, 2010. During the year ended March 31, 2012, we borrowed $149.0 million on our revolving credit facilities (net of repayments), primarily to fund acquisitions. 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, primarily to fund acquisitions. During the year ended March 31, 2013, we paid $20.2 million of debt issuance costs.

Cash flows from financing activities also include distributions paid to owners. NGL Supply made distributions to its preferred stockholder each year as required. NGL Supply also made a $7.0 million distribution to the owners of its common stock during the six months ended September 30, 2010 in advance of our formation transactions. We made a distribution of $40.0 million to the previous shareholders of NGL Supply during the six months ended March 31, 2011. Such distributions and the negative cash flows realized from our operating activities during the six months ended September 30, 2010 required us to increase our borrowings under our revolving credit facility. 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, 2013, if we made distributions equal to our minimum quarterly distribution of $0.3375 per unit ($1.35 annualized), total distributions would equal $18.1 million per quarter ($72.5 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 credit facility.

The following table summarizes the distributions declared since our initial public offering:

			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

On May 5, 2011, we made a distribution of $3.85 million from available cash to our general partner and common unitholders as of March 31, 2011. Also in May 2011, we used approximately $65.0 million of the proceeds from our initial public offering to repay advances under our previous credit facility.

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Contractual Obligations

The following table summarizes our contractual obligations as of March 31, 2013 for our fiscal years ending thereafter:

			For the Years Ending March 31,								After March 31,
	Total		2014		2015		2016		2017		2017
	(in thousands)
Debt principal payments —
Acquisition advances	$	441,500	$	—	$	—	$	—	$	—	$	441,500
Working capital advances	36,000		—		—		—		—		36,000
Senior Notes	250,000		—		—		—		—		250,000
Other long-term debt	21,562		8,626		6,456		3,088		2,091		1,301
Scheduled interest payments on revolving credit facility (1)	77,329		18,328		18,328		18,328		18,328		4,017
Scheduled interest payments on senior notes	116,375		16,625		16,625		16,625		16,625		49,875
Scheduled interest payments on other long-term debt	—		—		—		—		—		—
Standby letters of credit	60,082		—		—		—		—		60,082
Future minimum lease payments under noncancelable operating leases	211,438		55,065		38,283		31,297		29,005		57,788
Fixed price commodity purchase commitments (2)	380,205		312,435		39,252		28,518		—		—
Index priced commodity purchase commitments (2) (3)	604,584		586,324		18,260		—		—		—
Total contractual obligations	$	2,199,075	$	997,403	$	137,204	$	97,856	$	66,049	$	900,563
Natural gas liquids gallons under fixed-price purchase commitments (thousands)	84,159		84,159		—		—		—		—
Natural gas liquids gallons under index-price purchase commitments (thousands)	540,518		521,534		18,984		—		—		—
Crude oil barrels under fixed-price purchase commitments (thousands)	3,382		2,550		475		358		—		—

(1)The estimated interest payments on our revolving credit facility are based on principal and letters of credit outstanding at March 31, 2013. See Note 8 to our consolidated financial statements as of March 31, 2013 included elsewhere herein for additional information on our credit agreement. We are required to pay a commitment fee ranging from 0.38% to 0.50% on the average unused commitment.

(2)At March 31, 2013, we had fixed priced and index priced sales contracts for approximately 102.1 million and 262.1 million gallons of natural gas liquids, respectively.  At March 31, 2013, we had fixed-price sales contracts for approximately 5.6 million barrels of crude oil.

(3)Index prices are based on a forward price curve as of March 31, 2013. A theoretical change of $0.10 per gallon in the underlying commodity price at March 31, 2013 would result in a change of approximately $54.1 million in the value of our index-based purchase commitments.

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Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases described in Note 10 to the financial statements included elsewhere in this annual report.

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, market conditions are favorable, and production of crude oil in North America is high. Changes in the level of production could impact our ability to generate revenues in the future.

In addition, the spread between the prices of crude in different locations can also fluctuate widely. If these price differences are high, we are able to generate higher margins by transporting crude from lower-price markets to higher-price markets. During fiscal 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 from one region to the other. This spread has narrowed in recent months.

Water Services

Our opportunity to earn revenues in our water services 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 these regions. A future decline in the level of production could have an adverse impact on profitability.

Our facility in Wyoming and two of our facilities in Colorado have the capability to process wastewater to the point where it can be returned to the producer for use in future drilling operations. We typically generate higher margins from this activity than from our disposal operations. Under current conditions, it is generally more economical for our customers for us to dispose of the water than to sell it back to them after processing. Future changes in customer attitudes or in the regulatory climate could provide future opportunities for us to generate increased margins.

Natural Gas Liquids Logistics

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. During the most recent winter weather conditions were relatively mild, and the preceding winter was one of the warmest on record, which reduced demand and resulted in lower prices for natural gas liquids. 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.

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, such as we have experienced over the two most recent years, margins per gallon typically increase. During times of higher propane prices, such as we may experience in the future, margins per gallon typically decrease.

The retail propane and distillate business faces competition from the natural gas industry. As the natural gas infrastructure expands to new areas, customers who have access to natural gas for home heating purposes typically choose this over propane, as it is generally a

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lower-cost product. As a result, we expect a certain amount of continuing customer loss resulting from the expansion of the natural gas infrastructure.

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 critical 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 impact on the 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. Shipping and handling costs associated with product sales are included in operating expenses 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 the 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. We completed the assessment of each of our reporting units and determined no impairment existed for the year ended March 31, 2013. 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. To date, we have not recognized any impairment on assets we have acquired.

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 did not record any impairments of long-lived assets during the year ended March 31, 2013.

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. At March 31, 2013, we have recorded a liability of $1.5 million for obligations related to the retirement of pipeline injection facilities of our crude oil logistics business and the facilities of our water services business.

In addition to the pipeline injection facilities and the water processing facilities, we may be obligated by contractual or regulatory requirements to remove certain of our other assets, or perform other remediation of the sites where such assets are located, upon the retirement of those 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 financial position or results of operations.

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Depreciation 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.

The net book value of our property, plant and equipment was $516.9 million at March 31, 2013. We recorded depreciation expense of $39.2 million, $10.6 million, $2.8 million, and $1.0 million for the year ended March 31, 2013, the year ended March 31, 2012, the six months ended March 31, 2011, and the six months ended September 30, 2010, respectively.

For additional information regarding our property and equipment, see Note 5 of our March 31, 2013 consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

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.

The net book value of our amortizable intangible assets was $442.6 million at March 31, 2013. We recorded amortization expense of $44.1 million, $6.6 million, $1.6 million, and $0.8 million during the year ended March 31, 2013, the year ended March 31, 2012, the six months ended March 31, 2011, and the six months ended September 30, 2010, respectively.

For additional information regarding our intangible assets, see Note 7 of our March 31, 2013 consolidated financial statements included elsewhere in this annual report. For additional information on the valuation methodology for customer relationship intangible assets acquired in business combinations, see Note 4 of our March 31, 2013 consolidated financial statements included elsewhere in this Annual Report on Form 10-K.

Business Combinations

We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using a method known as 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 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 a retroactive adjustment to our previously reported financial position and results of operations.

Inventory

Our inventory consists primarily of propane, butane, and crude oil. The market value of these commodities changes on a daily basis as supply and demand conditions change. We value our inventory using the weighted-average cost and first-in first-out

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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 writedown 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 writedowns will be required in future periods. In addition, writedowns at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

Product Exchanges

In our natural gas liquids logistics business, we frequently have exchange transactions with suppliers or customers in which we will deliver product volumes to them, or receive product volumes from them to be delivered back to us or from us in future periods, generally in the short-term (referred to as “product exchanges”). The settlements of exchange volumes are generally done through in-kind arrangements whereby settlement volumes are delivered at no cost, with the exception of location or timing differentials. Such in-kind deliveries are ongoing and can take place over several months. 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, which we believe represents the value of the exchange volumes at such date. Changes in product prices could impact our estimates.

Item 7A.Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

As of March 31, 2013, 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. As of March 31, 2013, we had $477.5 million of outstanding borrowings under our revolving credit facility. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of approximately $0.6 million.

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 natural gas liquids 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.

We acquired a crude oil logistics business in our June 2012 merger with High Sierra. 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 business are generally higher than the receivables from customers in our other segments.

We take an active role in managing and controlling commodity price and credit risks and have established control procedures, which we review on an ongoing basis. Open commodity positions and market price changes are monitored daily and are reported to 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 as of March 31, 2013 and 2012 were retailers, resellers, energy marketers, producers, refiners and dealers.

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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 will 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, options, swaps and future contracts, 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 which we believe to be immaterial in amount. 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. In addition, we do not use such derivative commodity instruments for speculative or trading purposes. As of March 31, 2013, the fair value of our unsettled commodity derivative instruments was a net liability of $7.1 million. 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
Propane (Natural gas liquids logistics segment)	$	(1,119	)
Natural gas liquids (Natural gas liquids logistics segment)	(17,698		)
Heating oil (Retail segment)	33
Crude oil (Crude oil logistics segment)	(5,646		)
Crude oil (Water services segment)	(1,156		)

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 on Form 10-K, together with the reports 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.

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,

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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 as of March 31, 2013. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31, 2013, 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, 2013, 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, 2013 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

We closed several business combinations during the year ended March 31, 2013, as described in Note 4 to our consolidated financial statements included in this Annual Report on Form 10-K. At this time, we continue to evaluate the business and internal controls and processes of these acquired businesses and are making various changes to their operating and organizational structure based on our business plan. We are in the process of implementing our internal control structure over these acquired businesses. We expect that our evaluation and integration efforts related to those combined operations will continue into fiscal 2014, due to the magnitude of those businesses.

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 13a-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 High Sierra Energy, LP and High Sierra Energy GP, LLC and their subsidiaries, along with other businesses we acquired during the year ended March 31, 2013, from our evaluation of the effectiveness of internal control over financial reporting for the year ending March 31, 2013 due to their size and complexity and the limited time available to complete the evaluation. The operations excluded from our evaluation represent approximately 68% of our total assets at March 31, 2013, and approximately 73% of our total revenues for the year ended March 31, 2013.

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of March 31, 2013.

Our internal control over financial reporting as of March 31, 2013 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 on Form 10-K.

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 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 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 or 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	59	Chief Executive Officer and Director
Patrice Armbruster	52	Senior Vice President, Accounting
Atanas H. Atanasov	40	Chief Financial Officer
Bradley K. Atkinson	58	Vice President, Business Development
James J. Burke	57	Chief Executive Officer of High Sierra Energy and Director
Shawn W. Coady	51	President and Chief Operating Officer, Retail Division and Director
Todd M. Coady	55	Vice President, Administration
David C. Kehoe	54	Chief Operating Officer of High Sierra Energy
Vincent J. Osterman	56	President, Eastern Retail Propane Operations and Director
Sharra Straight	49	Vice President and Controller
Kevin C. Clement	54	Director
Stephen L. Cropper	63	Director
Bryan K. Guderian	53	Director
James C. Kneale	62	Director
Norman J. Szydlowski	62	Director
Patrick Wade	44	Director
William A. Zartler	48	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, as Vice President and Chief Financial Officer in 1990. Mr. Krimbill was President of Heritage from 1999 to 2000 and President and Chief Executive Officer of Heritage from 2000 to 2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners, 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.

Patrice Armbruster. Ms. Armbruster has served as our Senior Vice President of Accounting since May 2012. Ms. Armbruster previously served several roles in accounting and SEC reporting with Energy Transfer Partners, L.P. and Heritage Propane from March 2001 through May 2012. In March 2001, Ms. Armbruster joined Heritage Propane Partners, L.P. the predecessor of Energy Transfer Partners, as the manger of financial reporting. Her most recent role prior to coming to NGL was the Director of Financial Reporting and Controller with Heritage Propane. For 10 years prior to joining Heritage Propane Partners, L.P. Ms. Armbruster worked as an audit manager for a regional public accounting firm in Montana. Ms. Armbruster received a B.A. in Accounting from Carroll College of Helena, Montana.

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. 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. Mr. Atanasov is a Certified Public Accountant and holds a Masters of Business Administration from the University of Tulsa and a Bachelors of Science in Accounting from Oral Roberts University.

Bradley K. Atkinson. Mr. Atkinson has served as our Vice President, Business Development since October 2010. From April 2007 through September 2010, Mr. Atkinson managed private investments. Mr. Atkinson was previously an officer of Energy

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Transfer Partners, L.P., and its predecessor, Heritage Propane Partners, L.P., serving as the Vice President — Corporate Development from August 2000 to March 2007 and as the Vice President of Administration from April 1998 to July 2000. Prior to joining Energy Transfer Partners, Mr. Atkinson held various positions at Mapco, Inc. from 1986 to 1998, where he managed the acquisitions and business development for Thermogas as the Vice President of Administration for the retail propane division for eight years. Mr. Atkinson has a B.S.B.A. in Accounting from Pittsburg State University and an M.B.A. from Oklahoma State University.

James J. Burke. Mr. Burke serves as the Chief Executive Officer of our High Sierra subsidiary. He 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, he 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 (U.S.) 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.

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 20 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.

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.

David C. Kehoe. Mr. Kehoe serves as the Chief Operating Officer of our High Sierra subsidiary. Mr. Kehoe joined our management team through our June 2012 merger with High Sierra. He 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.

Sharra Straight. Ms. Straight has served as our Vice President and Comptroller since October 2010. Ms. Straight was the Vice President of Finance and Controller of NGL Supply from 2005 until the membership interests in NGL Supply were contributed to us as part of our formation transactions. Ms. Straight joined NGL Supply in 2002 as Controller and Director of Accounting. Ms. Straight began her career at Texaco Inc. in 1986. She was promoted to positions of increasing responsibility at Texaco during the

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1990s, becoming the Manager of NGL Financial Reporting and Planning in 2000. Ms. Straight has a B.S. in Accounting from Northeastern State University.

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, U.S. refined products, asphalt and residual fuels. He is a graduate of Wichita State University’s W. Frank Barton School of Business with a Bachelor’s of Business Administration in Marketing.

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.

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 his retirement from Williams in 1998, Mr. Cropper has been a consultant and private investor and also served as a director of Sunoco Logistics Partners, L.P. and of NRG Energy, Inc. He currently serves as a member of the board of directors of Berry Petroleum Company (NYSE: BRY), where he serves on the audit committee and the corporate governance and nominating committee.

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 December 2011. Mr. Guderian had responsibility for overseeing Williams’ international operations and has served as a director of Apco Oil & Gas International Inc., since 2002 and 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 serves on the Board of Directors of CEJA Corporation, which is a privately-held oil and gas company. 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.

Norman J. Szydlowski. Mr. Szydlowski joined the board of directors of our general partner in November 2011. Mr. Szydlowski has been a director and President and Chief Executive Officer of SemGroup Corporation since November 2009. SemGroup Corporation has been an affiliate of NGL Energy Partners LP and its general partner since November 2011. Mr. Szydlowski also serves as chairman of the board of directors, president and chief executive officer of SemGroup’s wholly-owned subsidiary Rose Rock Midstream GP, LLC, the general partner of Rose Rock Midstream, L.P. From January 2006 until January 2009, Mr. Szydlowski served as president and chief executive officer of Colonial Pipeline Company, an interstate common carrier of petroleum products. From 2004 to 2005, he served as a senior consultant to the Iraqi Ministry of Oil in Baghdad on behalf of the U.S. Department of Defense, where he led an advisory team in the rehabilitation, infrastructure security and development of future strategy of the Iraqi oil sector. From 2002 until 2004, he served as vice president of refining for Chevron Corporation (formerly

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ChevronTexaco), one of the world’s largest integrated energy companies. Mr. Szydlowski joined Chevron in 1981 and served in various capacities of increasing responsibility in sales, planning, supply chain management, refining and plant operations, transportation and construction engineering. Mr. Szydlowski graduated from Indiana University in Bloomington with a master’s degree in business administration. He also holds a Bachelor of Science degree in mechanical engineering from Kettering University.

Mr. Szydlowski brings to the board considerable management and leadership experience, most recently as president and chief executive officer of SemGroup Corporation and Colonial Pipeline Company, and extensive knowledge of the energy industry gained during his 31-year career.

Patrick Wade. Mr. Wade has served as a member of the High Sierra board since November 2008 and has nineteen 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 U.S. 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, as a Managing Director in the Houston office. The Energy & Minerals Group is a highly specialized private equity firm that focuses exclusively on investing across various facets of the global natural resource industry that are integral to the global economy. The Energy & Minerals Group has $6.2 billion of total investor commitments (including co-investments) with in excess of $3.1 billion deployed across the energy complex since inception. The Energy & Minerals Group 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.

William A. Zartler. Mr. Zartler has served as a member of the board of directors of our general partner since its formation in September 2010. Mr. Zartler was the Chairman of the Board of NGL Supply from 2004 until the membership interests in NGL Supply were contributed to us as part of our formation transactions. Mr. Zartler was a founder and managing partner of Denham Capital Management LP, an energy and commodities focused private equity firm, having been with the firm since its inception in 2004, and headed the firm’s Energy Infrastructure Group. Prior to joining Denham, Mr. Zartler was an entrepreneur and a founder of Solaris Energy Services. During March 2013, Mr. Zartler rejoined Solaris Energy Capital as a managing partner. Mr. Zartler has a B.S. in Mechanical Engineering from the University of Texas and an M.B.A. from Texas A&M University.

Mr. Zartler brings extensive financial and acquisition experience in the energy industry to the board. Mr. Zartler provides expertise in developing acquisition strategies and evaluating acquisition opportunities.

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 of the board of directors. SemStream, L.P. has the right to designate two persons to serve on the board, and has designated Norman J. Szydlowski and Kevin C. Clement. EMG HGL HC LLC has the right to designate two persons to serve on the board (provided that James J. Burke must be one of the designees as long as he is an officer of the Partnership), and has designated James J. Burke and Patrick Wade to serve on the board. NGL Holdings, Inc., 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. NGL Holdings, Inc. has designated William A. Zartler, 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 management of enterprise level risk may be defined as the process of identifying, managing and monitoring events that present opportunities and risks with respect to the creation of value for our unitholders. The board of directors of our general partner has delegated to management the primary responsibility for enterprise level risk management, while the board has retained responsibility for oversight of management in that regard. Management will offer an enterprise level risk assessment to the board at least once every year.

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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.

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. 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. Cropper, Mr. Kneale, Mr. Szydlowski, and Mr. Zartler currently serve on the compensation committee. Mr. Cropper serves as the chairman.

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.

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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, 2013, except as described in the paragraph below.

On January 1, 2013, certain restricted common units that were granted pursuant to an incentive compensation plan vested. Upon vesting of the 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 these officers were reported late, including for Patrice Armbruster (reported on Form 4 filed on April 26, 2013), Atanas H. Atanasov (reported on Form 4 filed on April 25, 2013), Todd M. Coady (reported on Form 4 filed on April 25, 2013), Shawn W. Coady (reported on Form 4 filed on April 29, 2013), Jeffrey A. Herbers (reported on Form 4 filed on April 25, 2013), and Brian K. Pauling (reported on Form 4 filed on April 26, 2013). EMG NGL HC LLC acquired common units on June 19, 2012 in connection with the Partnership’s merger with High Sierra; EMG NGL HC LLC reported the acquisition of these common units on Form 3 filed on May 7, 2013. NGL Holdings, Inc. acquired additional common units on June 19, 2012 in connection with the Partnership’s merger with High Sierra; NGL Holdings, Inc. reported the acquisition of these common units on Form 5 filed on May 28, 2013. Mr. Pauling sold common units on August 30, 2012, which were reported on Form 4 filed on November 21, 2012, and Mr. Pauling sold common units on February 22, 2013, which were reported on Form 4 filed on April 26, 2013.

Corporate Governance

The board of directors of our general partner has adopted a Code of Ethics for 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 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 board of directors of our general partner, all of our independent directors have the option to 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 “2013” in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2013.

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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 2013 were:

·H. Michael Krimbill — Chief Executive Officer and Chief Financial Officer

·Craig S. Jones — Former Chief Financial Officer (prior to retirement on August 31, 2012)

·James J. Burke — Chief Executive Officer, High Sierra Energy GP, LLC

·David C. Kehoe — Chief Operating Officer, High Sierra Energy GP, LLC

·Atanas H. Atanasov — Senior Vice President of Finance and Treasurer

During May 2013, Mr. Atanasov was appointed our Chief Financial Officer.

Our 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.

Compensation Setting Process

As we have developed as a publicly traded partnership, the compensation committee has designed a compensation program for our named executive officers. 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.

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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:

Element		Primary Purpose	How Amount Determined
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
Cash Bonus Awards	·	Rewards the achievement of specific annual financial and operational performance goals	Based on the named executive officer’s relative contribution to achieving or exceeding annual goals
	·	Recognizes individual contributions to our performance
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	Based on the named executive officer’s expected contribution to long-term performance goals
	·	Provides a forfeitable long-term incentive to encourage executive retention

The compensation committee determines the mix of compensation, both among short-term and long-term and cash and non-cash compensation, appropriate for each executive officer.

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.

The base salaries of Mr. Krimbill and Mr. Jones, which were effective as of January 1, 2011, were $120,000 and $250,000, respectively. The base salary amounts were 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 named executive officers 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 salaries of Mr. Krimbill and Mr. Jones were reduced to $60,000 and $200,000, respectively, 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.

The base salaries of Mr. Burke and Mr. Kehoe, which became effective on June 19, 2012 when they joined our management team upon completion of our merger with High Sierra, are $353,000 and $293,000, respectively. The base salaries of Mr. Burke and Mr. Kehoe are the same subsequent to the merger as they were before the merger. The base salary of Mr. Atanasov of $195,000 was negotiated prior to his joining our management team in November 2011.

Cash Bonus Awards

None of the named executive officers is subject to a formal bonus plan, and therefore annual bonus awards are discretionary. We did not make any bonus awards to our named executive officers for fiscal years 2012 and 2011, and have not yet made any bonus awards to our named executive officers for fiscal year 2013.

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Long-Term Equity Incentive Awards

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

During fiscal 2013, the compensation committee granted awards of restricted units to certain of our named executive officers, in order to incentivize retention and to reward the officers if the value of common units increases over time. The restricted units 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 scheduled vesting of the awards is summarized below:

									Grant Date
								Total	Fair Value
								Number of	of Restricted
		Number of Restricted Units Awarded Vesting On						Restricted	Units
		January 1,	July 1,	July 1,	July 1,	July 1,	July 1,	Units	Awarded
Name	Grant Date	2013	2013	2014	2015	2016	2017	Awarded	($)
H. Michael Krimbill	n/a	—	—	—	—	—	—	—	—
Craig S. Jones	n/a	—	—	—	—	—	—	—	—
James J. Burke	December 26, 2012	—	10,000	10,000	10,000	10,000	10,000	50,000	836,400
David C. Kehoe	December 26, 2012	—	10,000	10,000	10,000	10,000	10,000	50,000	836,400
Atanas H. Atanasov	June 15, 2012	5,000	5,000	5,000	5,000	5,000	—	25,000	463,900
	December 26, 2012	3,000	3,000	3,000	3,000	3,000	—	15,000	279,540

Our Chief Executive Officer made recommendations to the compensation committee regarding the number of common units that each of the named executive officer would receive. These recommendations were based on his judgment, considering the level of responsibility of each named executive officer and the expected contribution of each of the named executive officers to our long-term performance. After the compensation committee reviewed these recommendations, the compensation committee submitted them to the board of directors for their approval.

The first grants under the LTIP were awarded in June 2012, once the award program had been developed. A second round of grants was awarded in December 2012, primarily for officers and employees who joined in the Partnership in the merger with High Sierra. Mr. Atanasov was awarded an additional grant in December 2012, in recognition of an increase in his responsibilities between June 2012 and December 2012.

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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 applicable 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 and assumptions that a market participant might make about future distribution growth. This calculation of fair value is consistent with the provisions of the Financial Accounting Standards Board’s Accounting Standards Codification 718 (“ASC 718”)

Severance and Change in Control Benefits

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.

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.

Mr. Burke and Mr. Kehoe were participants in a separate defined contribution 401(k) plan, which was previously sponsored by High Sierra, until we merged this plan into our 401(k) plan on January 1, 2013. While this plan was in effect, Mr. Burke and Mr. Kehoe were eligible for employer matching contributions equal to 100% of the employee’s contribution that is not in excess of 1% of the employee’s eligible compensation, and for employer matching contributions of equal to 50% of the remaining employee’s contribution that was not in excess of 6% of the employee’s eligible compensation (subject to annual IRS contribution limits).

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.

Fiscal 2014 Compensation Program

During April 2013, our compensation committee engaged Pearl Meyer & Partners (“Pearl Meyer”) to serve as the compensation advisor to the compensation committee. Pearl Meyer will prepare a marketplace compensation analysis for 25 management positions, including those of the named executive officers. This analysis will provide context to assist the compensation committee in making decisions related to the compensation arrangements for these individuals. Pearl Meyer will also provide specific recommendations about the design of the compensation programs, including annual incentive plan design and long-term incentive plan design; however Pearl Meyer will not provide recommendations regarding the specific compensation of individual employees. Pearl Meyer may use peer company benchmarking or other tools to prepare their analysis and to develop their recommendations to the compensation committee. Once this process has been completed, the compensation committee may make recommendations to the board of directors that could result in changes to the compensation of our named executive officers during fiscal 2014.

Employment Agreements

We do not have employment agreements with any of our 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 2012 was substantially less than the Section 162(m) threshold of $1,000,000. Although the value of the restricted units granted during fiscal

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2013 are reflected in the Summary Compensation Table below, the grants are subject to vesting conditions. The vesting of the awards is a taxable event, but the granting of the awards 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)

James C. Kneale

Norman J. Szydlowski

William A. Zartler

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

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Summary Compensation Table for 2013

The following table includes the compensation earned by our named executive officers for fiscal years 2011-2013. Amounts for fiscal 2011 are for the period from October 1, 2010 (the date of our formation) through March 31, 2011.

				Restricted	All Other
				Unit	Compensation
	Fiscal	Salary	Bonus	Awards (1)	(2)	Total
Name and Position	Year	($)	($)	($)	($)	($)
H. Michael Krimbill	2013	82,849	—	—	2,492	85,341
Chief Executive Officer	2012	110,769	—	—	2,700	113,469
NGL Energy Partners LP	2011	54,538	—	—	—	54,538
Craig S. Jones (3)	2013	83,836	—	—	3,000	86,836
Chief Financial Officer	2012	242,308	—	—	7,904	250,212
NGL Energy Partners LP	2011	118,830	—	—	3,077	121,907
James J. Burke (4)	2013	275,630	—	836,400	13,015	1,125,045
Chief Executive Officer
High Sierra Energy GP, LLC
David C. Kehoe (4)	2013	228,781	—	836,400	13,490	1,078,671
Chief Operating Officer
High Sierra Energy GP, LLC
Atanas H. Atanasov (5)	2013	195,000	—	743,440	2,738	941,178
Senior Vice President of Finance
NGL Energy Partners LP

(1)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.

(2)The amounts in this column include matching contributions to our 401(k) plan. Amounts for Mr. Burke and Mr. Kehoe each include approximately $6,300 for club memberships.

(3)Mr. Jones retired during fiscal 2013, and Mr. Krimbill assumed the title of Chief Financial Officer.

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

(5)Mr. Atanasov was not a named executive officer prior to fiscal 2013.

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Restricted Unit Awards

During fiscal 2013, the board of directors granted awards of restricted units to certain of our named executive officers. The restricted units 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.

2013 Grants of Plan Based Awards Table

The number of restricted units granted to our named executive officers, and their grant date fair values, are summarized below:

			Grant Date
		Total	Fair Value
		Number of	of Restricted
		Restricted	Units
	Grant	Units	Awarded
Name	Date	Awarded	($)
H. Michael Krimbill	n/a	—	—
Craig S. Jones	n/a	—	—
James J. Burke	December 26, 2012	50,000	836,400
David C. Kehoe	December 26, 2012	50,000	836,400
Atanas H. Atanasov	June 15, 2012	25,000	463,900
	December 26, 2012	15,000	279,540

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 as of 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.

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Outstanding Equity Awards as of March 31, 2013

The number of unvested restricted units outstanding at March 31, 2013, and their fair values at March 31, 2013, are summarized below:

	Number of	Fair Value
	Restricted	of Unvested
	Units That	Restricted
	Have Not	Units as of
	Yet Vested	March 31,
	at March 31,	2013
Name	2013	($)
H. Michael Krimbill	—	—
Craig S. Jones	—	—
James J. Burke	50,000	1,345,000
David C. Kehoe	50,000	1,345,000
Atanas H. Atanasov	32,000	860,800

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, 2013 of $26.90. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.

2013 Option Exercises and Stock Vested

On January 1, 2013, 8,000 of the restricted units granted to Mr. Atanasov vested. These awards had a value of $186,560 on the vesting date, calculated based of the closing market price of $23.32 per unit.

	Number	Value
	of Units	Realized
	Acquired	on Vesting
Name	on Vesting	($)
H. Michael Krimbill	—	—
Craig S. Jones	—	—
James J. Burke	—	—
David C. Kehoe	—	—
Atanas H. Atanasov	8,000	186,560

Of the 8,000 units that vested, 5,168 units were issued to Mr. Atanasov, and we remitted payments to taxing authorities on Mr. Atanasov’s behalf in lieu of issuing the remaining 2,832 units. During February 2013, Mr. Atanasov received a distribution of $2,390 on the 5,168 vested units ($0.4625 per unit).

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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, 2013” 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 2013

The following table sets forth the compensation earned during fiscal 2013 by each director who is not an officer or employee of our general partner:

	Fees
	Earned or	Restricted
	Paid in	Unit
	Cash	Awards	Total
Name	($)	($)	($)
Stephen L. Cropper	65,000	306,850	371,850
Bryan K. Guderian	65,000	306,850	371,850
James C. Kneale	70,000	306,850	376,850

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 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 as of 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.

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The restricted units 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 provides information on the restricted units awarded to non-employee members of our board of directors:

							Number of	Fair Value
						Grant Date	Restricted	of Unvested
						Fair Value	Units That	Restricted
		Number of Restricted Units				of Restricted	Have Not	Units as of
		Awarded Vesting On				Units	Yet Vested	March 31,
	Grant	January 1,	July 1,	July 1,	Total	Awarded	at March 31,	2013
Name	Date	2013	2013	2014	Awards	($) (1)	2013	($) (2)
Stephen L. Cropper	June 15, 2012	5,000	5,000	5,000	15,000	306,850	10,000	269,000
Bryan K. Guderian	June 15, 2012	5,000	5,000	5,000	15,000	306,850	10,000	269,000
James C. Kneale	June 15, 2012	5,000	5,000	5,000	15,000	306,850	10,000	269,000

(1)The fair values of the restricted units shown in this column were calculated based on the closing market prices 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 as of the applicable 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.

(2)The fair values of the restricted units shown in the this column were calculated based on the closing market price of our limited partner units at March 31, 2013 of $26.90. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.

On January 1, 2013, 5,000 of the restricted units granted to each of the directors listed in the table above vested. These awards had a value of $116,600 for each of these directors on the vesting date, calculated based of the closing market price of $23.32 per unit. During February 2013, each of these directors received a distribution of $2,313 on the 5,000 vested units ($0.4625 per unit).

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 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.

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							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% of greater unitholders (other than officers and directors):
SemGroup Corporation (2)	9,133,409	18.58	%	—	—		16.59	%
EMG NGL HC LLC (3)	3,696,634	7.52	%	—	—		6.71	%
Ernest Osterman(4)	3,063,321	6.23	%	—	—		5.56	%
NGL Holdings, Inc.(5)	1,807,944	3.68	%	1,544,100	26.09	%	6.09	%
Directors and officers:
Atanas H. Atanasov (6)	37,168	*		—	—		*
James J. Burke (7)	311,440	*		—	—		*
Kevin C. Clement	5,000	*		—	—		*
Shawn W. Coady(8)	1,330,605	2.71	%	1,125,351	19.01	%	4.46	%
Stephen L. Cropper	25,000	*		—	—		*
Bryan K. Guderian	20,000	*		—	—		*
Craig S. Jones(9)	20,330	*		24,867	*		*
David C. Kehoe(10)	319,007	*		—	—		*
James C. Kneale(11)	17,500	*		—	—		*
H. Michael Krimbill(12)	970,557	1.97	%	497,846	8.41	%	2.67	%
Vincent J. Osterman(13)	3,762,621	7.66	%	—	—		6.83	%
Norman J. Szydlowski	—	—		—	—		—
Patrick Wade	—	—		—	—		—
William A. Zartler	—	—		—	—		—
All directors and executive officers as a group (14 persons)(14)	8,730,210	17.76	%	3,097,811	52.33	%	21.48	%

* Less than 1.0%

(1)Based on 49,147,964 common units and 5,919,346 subordinated units outstanding as of June 7, 2013.

(2)The mailing address for SemGroup Corporation is 6120 S. Yale Avenue, Suite 700, Tulsa, Oklahoma 74136. Norman J. Szydlowski, a member of the board of directors of our general partner, serves as director, President and Chief Executive Officer 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., a subsidiary of SemGroup Corporation. Each of Messrs. Szydlowski and Clement disclaims beneficial ownership of these common units. SemGroup Corporation also owns a 6.42% 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.

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(3)The mailing address for EMG NGL HC LLC is 2000 McKinney Avenue, Suite 1250, Dallas, Texas, 75201. NGP Midstream & Resources, L.P. owns a 65% interest in EMG NGL HC, LLC. NGP MR, L.P. is the general partner of NGP Midstream & Resources, L.P. The information related to NGP MR, L.P., NGP Midstream & Resources, L.P., and EMG NGL HC LLC is based upon EMG NGL HC LLC’s Form 4 filed with the SEC on June 10, 2013. EMG NGL HC LLC also owns a 6.73% interest in our general partner.

(4)The mailing address for Ernest Osterman is One Memorial Square, P.O. Box 67, Whitinsville, Massachusetts 01588. These units are owned directly by AO Energy, Inc. (110,587 common units), E. Osterman, Inc. (394,350 common units), E. Osterman Gas Service, Inc. (301,700 common units), Milford Propane, Inc. (559,784 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. Ernest Osterman is a director, executive officer and shareholder or member of each of these entities and may be deemed to have shared voting and investment power (with his son, Vincent J. Osterman) over 3,063,321 common units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. The preceding information related to Ernest Osterman, including the number of common units held, is based upon his Schedule 13D filed with the SEC on October 13, 2011.

(5)The mailing address for NGL Holdings, Inc. is c/o Denham Capital Management LP, 200 Clarendon St., 25th Floor, Boston, Massachusetts 02116. William A. Zartler, a member of the board of directors of our general partner, is the sole director of NGL Holdings, Inc., and as such, has sole voting and investment power over these units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. NGL Holdings, Inc. is 100% owned by Denham Commodity Partners Fund II LP, which is managed by its general partner, Denham Commodity Partners GP II LP, which is owned by the employees of Denham Capital Management LP and is controlled by its general partner, Denham GP II LLC, which is in turn owned by Stuart D. Porter. Denham Capital Management LP, of which William A. Zartler is a founder and managing partner, acts as the investment advisor for Denham Commodity Partners Fund II LP and is controlled by its general partner, Denham Capital Management GP LLC, which is in turn controlled by Stuart D. Porter. NGL Holdings, Inc. also owns a 14.16% interest in our general partner and Denham Commodity Partners GP II LP owns a 3.23% interest in our general partner. The information related to Mr. Porter and the Denham entities, including the number of units held, is based upon NGL Holdings, Inc.’s Schedule 13G filed with the SEC on February 13, 2013.

(6)Atanas H. Atanasov also owns a 0.07% interest in our general partner.

(7)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 2.62% interest in our general partner.

(8)Shawn W. Coady owns 25,565 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.

(9)Craig S. Jones also owns a 0.28% interest in our general partner.

(10)David C. Kehoe also owns a 0.50% interest in our general partner through DCK GP, LLC.

(11)Of these common units, 7,500 are owned by the Suzanne and Jim Kneale Living Trust.

(12)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

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except to the extent of his pecuniary interest therein. H. Michael Krimbill also owns an 11.59% interest in our general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests. KrimGP2010 LLC owns 363,555 of these 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.

(13)Vincent J. Osterman owns 30,000 of these common units. The remaining common units are owned directly by AO Energy, Inc. (110,587 common units), E. Osterman, Inc. (394,350 common units), E. Osterman Gas Service, Inc. (301,700 common units), E. Osterman Propane, Inc. (669,300 common units), Milford Propane, Inc. (559,784 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 699,300 common units and shared voting and investment power (with his father, Ernest Osterman) over 3,063,321 common units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. Vincent J. Osterman also owns a 0.5% interest in our general partner through VE Properties XI LLC.

(14)The directors and executive officers of our general partner also collectively own a 51.09% 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, Suite 805, Tulsa, Oklahoma 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, as of March 31, 2013.

			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)	1,444,900	—	3,760,539
Total	1,444,900	—	3,760,539

(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 in May 2011. The adoption of the LTIP did not require the approval of our unitholders.

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Item 13.Certain Relationships and Related Transactions and Director Independence

Our directors, executive officers, and greater than 5% unitholders collectively own an aggregate of 23,368,197 common units and 4,641,911 subordinated units, representing an aggregate 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 incentive distribution rights. 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 initial public offering and, consequently, are not the result of arm’s length negotiations.

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 initial public offering	· 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 incentive distribution rights.

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 23,368,197 common units and 4,641,911 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 approximately $0.1 million on its general partner interest and our directors, officers, and greater than 5% owners would receive an aggregate annual distribution of approximately $37.8 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.

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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 incentive distribution rights 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.

Related Party Transactions

SemGroup Corporation

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 had the right to appoint two members to the Board of Directors of our general partner. Subsequent to November 1, 2011, our natural gas liquids logistics segment has sold natural gas liquids to and purchased natural gas liquids from affiliates of SemGroup. These transactions are included within revenues and cost of sales of our natural gas liquids logistics business in our consolidated statements of operations. We also made payments to SemGroup for certain administrative and operational services. These transactions are reported within operating and general and administrative expenses in our consolidated statements of operations. The transactions with  SemGroup are summarized below by fiscal year (in thousands):

	2013	2012
Product sales to SemGroup	32,431	29,200
Product purchases from SemGroup	60,425	23,800
Payments to SemGroup for services	256	700

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Acquisitions

Subsequent to our merger with High Sierra, David Kehoe joined our management team as an executive officer. During the year ended March 31, 2013, we completed two acquisitions of the operations of entities partially owned by Mr. Kehoe and by other members of management. These acquisitions are summarized below:

				Mr. Kehoe’s
	Acquisition	Purchase		Ownership Interest
Selling Entity	Date	Price		in Selling Entity
Cowhouse Partners, L.L.C.	August 31, 2012	$	7.3 million	27.5	%
Key Pipeline Services, Inc.	December 28, 2012	$	6.7 million	46.5	%

Other Transactions

Subsequent to our merger with High Sierra, we purchased goods and services from several entities that are partially owned by James Burke, Mr. Kehoe and by other members of management. These transactions are summarized below:

				Mr. Kehoe’s		Mr. Burke’s
		Fiscal 2013		Ownership		Ownership
	Nature of	Expense		Interest		Interest
Entity	Services	(in thousands)		in Entity		in Entity
Cowhouse Partners, L.L.C.	Terminalling services	$	494	27.5	%	—
Impact Energy Services LLC	Crude oil purchases	648		—		50.0	%
Key Pipeline Services, Inc.	Terminalling services	115		46.5	%	—
Key Pipelines, LTD	Terminalling services	643		46.5	%	—
Fluid Services, LLC	Crude oil purchases and transportation services	528		20.0	%	—
Fluid Disposal Services, LLC	Waste disposal services	751		20.0	%	—

Subsequent to our merger with High Sierra, we provided goods and services to an entity that is partially owned by Mr. Kehoe and by other members of management. These transactions are summarized below:

				Mr. Kehoe’s
	Nature of	Fiscal 2013		Ownership Interest
Entity	Services	Expense		in Entity
Cowhouse Partners, L.L.C.	Transition services	$	504	27.5	%

We rent office space from VE III LLC and VE Properties V, which are entitles that are owned by Vincent Osterman and his father. We paid rent of approximately $143,000 during the year ended March 31, 2013 to these entitles.

Timothy Osterman, an employee of the Partnership, is the son of Vincent Osterman, who is an executive officer of the Partnership and a member of the board of directors. Timothy Osterman’s base compensation during the fiscal year ended March 31, 2013 was $83,200. During fiscal 2013, Timothy Osterman was granted 15,000 restricted units, which vested (or will vest) in five tranches of 3,000 units on each of January 1, 2013, July 1, 2013, July 1, 2014, July 1, 2015, and July 1, 2016, subject to his continued employment. No distributions will accrue to or be paid on the restricted units during the vesting period. The fair value of these restricted units was $278,340 on June 15, 2012, which was the date the units were granted. The fair value of these restricted units was calculated based on the closing market price of our limited partner units on the grant date, with an adjustment 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 and assumptions that a market participant might make about future distribution growth. Timothy Osterman was also eligible to participate in the Partnership’s 401(k) plan, and he received $2,496 of employer matching contributions during the year ended March 31, 2013.

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Transition Services Agreement

We entered into a Transition Services Agreement with SemStream on November 1, 2011 pursuant to which SemStream agreed to provide us with certain administrative and operational transition services related to the assets that we acquired from SemStream. We paid approximately $0.1 million to SemStream for the transition services during the year ended March 31, 2013. The Transition Services Agreement expired on April 30, 2012, although SemStream continues to provide certain operational services.

Registration Rights Agreement

We entered into a registration rights agreement, which was effective upon the effectiveness of the registration statement on Form S-1 (File No. 333-172186) that we filed with the SEC in connection with our initial public offering, pursuant to which we agreed to register for resale under the Securities Act of 1933, as amended, or the Securities Act, common units, including any common units issued upon the conversion of subordinated units, owned by members of the NGL Energy LP Investor Group or their permitted assignees. 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.

Pursuant to the registration rights agreement, at any time following the date that was 180 days after the completion of our initial public offering, NGL Holdings, Inc., Hicks Oils & Hicksgas, Incorporated or the IEP Parties (KrimGP2010, LLC, Infrastructure Capital Management, LLC and Atkinson Investors, LLC, collectively), to the extent that they continue to own more than 4% of our common units, may require us to file a registration statement with the SEC registering the offer and sale of a specified number of common units, subject to limitations on the number of requests for registration that can be made in any twelve month period as well as customary cutbacks at the discretion of the underwriter. In addition, the registration rights agreement provides that members of the NGL Energy LP Investor Group may have their common units included in any registration statement filed by us for an offering of common units for cash, subject to customary cutbacks at the discretion of the underwriter. We are obligated to pay all expenses incidental to any registration of common units, excluding underwriting discounts and commissions.

We amended and restated the registration rights agreement on October 3, 2011 to, among other things, provide for certain registration rights for the common units issued to the entities affiliated with Ernest Osterman and Vincent J. Osterman in connection with the closing of the Osterman transaction. We further amended the amended and restated registration rights agreement on November 1, 2011, January 3, 2012, May 1, 2012, June 19, 2012, October 1, 2012 and November 13, 2012  to provide for certain registration rights for the common units issued to the following in connection with the closing of certain acquisitions: SemStream, Pacer, Downeast, EMG NGL HC LLC (a former High Sierra unitholder), Enstone, and the sellers of Pecos and its affiliated companies.

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);

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·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.

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 fiscal year ended March 31, 2013 and 2012:

	2013		2012
Audit fees (1)	$	1,861,979	$	909,655
Audit-related fees (2)	47,100		272,044
Tax fees (3)	66,711		—
All other fees	—		—
Total	$	1,975,790	$	1,181,699

(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 a 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)

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Exhibit
Number	Description
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)
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)
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)

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Exhibit
Number	Description
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)
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)
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	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)
4.9	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)

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Exhibit
Number	Description
4.10	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)
4.11	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)
4.12	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)
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	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)
10.7	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)
10.8	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

115

Exhibit
Number	Description
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 Schema Document
101.CAL**	XBRL Calculation Linkbase Document
101.DEF**	XBRL Definition Linkbase Document
101.LAB**	XBRL Label Linkbase Document
101.PRE**	XBRL 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 as of March 31, 2013 and March 31, 2012, (ii) Consolidated Statements of Operations for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010, (iii) Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010, (iv) Consolidated Statements of Changes in Equity for years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010 and (v) Consolidated Statements of Cash Flows for years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010.

+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 June 13, 2013.

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	June 13, 2013
H. Michael Krimbill	(Principal Executive Officer)
/s/ Atanas H. Atanasov	Chief Financial Officer	June 13, 2013
Atanas H. Atanasov	(Principal Financial Officer)
/s/ Jeffrey A. Herbers	Chief Accounting Officer	June 13, 2013
Jeffrey A. Herbers	(Principal Accounting Officer)
/s/ James J. Burke	Director	June 13, 2013
James J. Burke
/s/ Shawn W. Coady	Director	June 13, 2013
Shawn W. Coady
/s/ Kevin C. Clement	Director	June 13, 2013
Kevin C. Clement
/s/ Stephen L. Cropper	Director	June 13, 2013
Stephen L. Cropper
/s/ Bryan K. Guderian	Director	June 13, 2013
Bryan K. Guderian
/s/ James C. Kneale	Director	June 13, 2013
James C. Kneale
/s/ Vincent J. Osterman	Director	June 13, 2013
Vincent J. Osterman
/s/ Norman J. Szydlowski	Director	June 13, 2013
Norman J. Szydlowski
/s/ Patrick Wade	Director	June 13, 2013
Patrick Wade
/s/ William A. Zartler	Director	June 13, 2013
William A. Zartler

117

INDEX TO FINANCIAL STATEMENTS

NGL ENERGY PARTNERS LP AND NGL SUPPLY, INC.
Reports of Independent Registered Public Accounting Firm	F-2
Consolidated Balance Sheets as of March 31, 2013 and 2012	F-5
Consolidated Statements of Operations for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010	F-6
Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010	F-7
Consolidated Statements of Changes in Equity for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010	F-8
Consolidated Statements of Cash Flows for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011and September 30, 2010	F-9
Notes to Consolidated Financial Statements	F-10

F-1

Report of Independent Registered Public Accounting Firm

Board of Directors and 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, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the two years ended March 31, 2013 and the six month period ended March 31, 2011. 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, 2013 and 2012, and the results of their operations and their cash flows for each of the two years ended March 31, 2013 and the six month period ended March 31, 2011 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, 2013, based on criteria established in 1992 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated June 13, 2013 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

June 13, 2013

F-2

Report of Independent Registered Public Accounting Firm

Partners
NGL Energy Partners LP

We have audited the accompanying consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for the six month period ended September 30, 2010 of NGL Supply, Inc. (an Oklahoma corporation) and subsidiaries. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

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 the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of NGL Supply, Inc. and subsidiaries for the six month period ended September 30, 2010, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

June 29, 2011

F-3

Report of Independent Registered Public Accounting Firm

Board of Directors and 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, 2013, based on criteria established in 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 High Sierra Energy, LP, and High Sierra Energy GP, LLC, and their subsidiaries, along with other businesses acquired during the year ended March 31, 2013 (“the acquired companies”), whose financial statements in the aggregate reflect total assets and revenues constituting approximately 68 and 73 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended March 31, 2013. As indicated in Management’s Report, the acquired companies were acquired during the year ended March 31, 2013, and therefore, management’s assertion on the effectiveness of the Partnership’s internal control over financial reporting excluded internal control over financial reporting of the acquired companies.

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, 2013, based on criteria established in 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, 2013, and our report dated June 13, 2013 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

June 13, 2013

F-4

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Balance Sheets
March 31, 2013 and 2012

(U.S. Dollars in Thousands, except unit amounts)

	March 31,			March 31,
	2013			2012
				(Note 4)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,561		$	7,832
Accounts receivable, net of allowance for doubtful accounts of $1,760 and $818, respectively	562,889			84,004
Accounts receivable - affiliates	22,883			2,282
Inventories	126,895			94,504
Prepaid expenses and other current assets	37,891			10,002
Total current assets	762,119			198,624
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $50,127 and $12,843, respectively	516,937			231,394
GOODWILL	563,146			167,245
INTANGIBLE ASSETS, net of accumulated amortization of $44,155 and $8,174, respectively	442,603			149,490
OTHER NONCURRENT ASSETS	6,542			2,766
Total assets	$	2,291,347		$	749,519
LIABILITIES AND PARTNERS’ EQUITY
CURRENT LIABILITIES:
Trade accounts payable	$	535,687		$	81,369
Accrued expenses and other payables	85,703			14,143
Advance payments received from customers	22,372			20,293
Accounts payable - affiliates	6,900			9,462
Current maturities of long-term debt	8,626			19,534
Total current liabilities	659,288			144,801
LONG-TERM DEBT, net of current maturities	740,436			199,177
OTHER NONCURRENT LIABILITIES	2,205			212
COMMITMENTS AND CONTINGENCIES
PARTNERS’ EQUITY, per accompanying statement:
General partner, representing a 0.1% interest, 53,676 and 29,245 notional units at March 31, 2013 and 2012, respectively	(50,497		)	442
Limited partners, representing a 99.9% interest -
Common units, 47,703,313 and 23,296,253 units issued and outstanding at March 31, 2013 and 2012, respectively	920,998			384,604
Subordinated units, 5,919,346 units issued and outstanding at March 31, 2013 and 2012	13,153			19,824
Accumulated other comprehensive income -
Foreign currency translation	24			31
Noncontrolling interest	5,740			428
Total partners’ equity	889,418			405,329
Total liabilities and partners’ equity	$	2,291,347		$	749,519

The accompanying notes are an integral part of these consolidated financial statements.

F-5

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Consolidated Statements of Operations

For the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

(U.S. Dollars in Thousands, except unit, per unit, share, and per share amounts)

	NGL Energy Partners LP									NGL Supply, Inc.
							Six Months			Six Months
	Year Ended			Year Ended			Ended			Ended
	March 31,			March 31,			March 31,			September 30,
	2013			2012			2011			2010
REVENUES:
Crude oil logistics	$	2,316,288		$	—		$	—		$	—
Water services	62,227			—			—			—
Natural gas liquids logistics	1,604,746			1,111,139			549,419			310,075
Retail propane	430,273			199,334			72,813			6,868
Other	4,233			—			—			—
Total Revenues	4,417,767			1,310,473			622,232			316,943
COST OF SALES:
Crude oil logistics		2,244,647			—			—			—
Water services	5,611			—			—			—
Natural gas liquids logistics	1,530,459			1,086,881			536,047			306,159
Retail propane	258,393			130,142			46,985			4,749
Total Cost of Sales	4,039,110			1,217,023			583,032			310,908
OPERATING COSTS AND EXPENSES:
Operating	169,799			47,300			15,898			5,231
General and administrative	52,698			16,009			5,024			3,210
Depreciation and amortization	68,853			15,111			3,441			1,389
Operating Income (Loss)	87,307			15,030			14,837			(3,795		)
OTHER INCOME (EXPENSE):
Interest income	1,261			765			221			66
Interest expense	(32,994		)	(7,620		)	(2,482		)	(372		)
Loss on early extinguishment of debt	(5,769		)	—			—			—
Other, net	260			290			103			124
Income (Loss) Before Income Taxes	50,065			8,465			12,679			(3,977		)
INCOME TAX (PROVISION) BENEFIT	(1,875		)	(601		)	—			1,417
Net Income (Loss)	48,190			7,864			12,679			(2,560		)
NET INCOME ALLOCATED TO GENERAL PARTNER	(2,917		)	(8		)	(13		)	—
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST	(250		)	12			—			45
NET INCOME (LOSS) ATTRIBUTABLE TO PARENT EQUITY ALLOCATED TO LIMITED PARTNERS	$	45,023		$	7,868		$	12,666		$	(2,515	)
BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT:
Common units	$	0.96		$	0.32		$	1.16
Subordinated units	$	0.93		$	0.58		$	—
BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING:
Common units	41,353,574			15,169,983			10,933,568
Subordinated units	5,919,346			5,175,384			—
BASIC AND DILUTED LOSS PER COMMON SHARE										$	(128.46	)
BASIC AND DILUTED WEIGHTED AVERAGE COMMON SHARES OUTSTANDING										19,711

The accompanying notes are an integral part of these consolidated financial statements.

F-6

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Consolidated Statements of Comprehensive Income (Loss)

For the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

(U.S. Dollars in Thousands)

	NGL Energy Partners LP								NGL Supply, Inc.
							Six Months		Six Months
	Year Ended			Year Ended			Ended		Ended
	March 31,			March 31,			March 31,		September 30,
	2013			2012			2011		2010
Net income (loss)	$	48,190		$	7,864		$	12,679	$	(2,560	)
Other comprehensive income (loss), net of tax:
Change in foreign currency translation adjustment	(7		)	(25		)	56		(15		)
Comprehensive income (loss)	$	48,183		$	7,839		$	12,735	$	(2,575	)

The accompanying notes are an integral part of these consolidated financial statements.

F-7

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Consolidated Statements of Changes in Equity

For the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

(U.S. Dollars in Thousands, except unit and share amounts)

													Accumulated			Receivable
							Additional						Other			From Exercise
	Class A Common Stock						Paid-in			Retained			Comprehensive			of Stock			Noncontrolling			Total
	Shares			Amount			Capital			Earnings			Income			Options			Interest			Equity
NGL SUPPLY, INC.
BALANCES, MARCH 31, 2010	19,603			$	196		$	36,039		$	9,859		$	84		$	—		$	225		$	46,403
Exercise of stock options	650			7			1,423			—			—			(1,430		)	—			—
Net loss	—			—			—			(2,515		)	—			—			(45		)	(2,560		)
Foreign currency translation adjustment	—			—			—			—			(15		)	—			—			(15		)
Dividends -
Preferred	—			—			—			(17		)	—			—			—			(17		)
Common	—			—			—			(7,000		)	—			—			—			(7,000		)
BALANCES, SEPTEMBER 30, 2010	20,253			$	203		$	37,462		$	327		$	69		$	(1,430	)	$	180		$	36,811
																Accumulated
				Limited Partners												Other
	General			Common						Subordinated						Comprehensive			Noncontrolling			Total
	Partner			Units			Amount			Units			Amount			Income			Interest			Equity
NGL ENERGY PARTNERS LP
Six Months Ended March 31, 2011:
Combination transaction with NGL Supply (Notes 1 & 2)	$	—		4,735,328			$	1,252		—			$	—		$	—		$	—		$	1,252
Acquisition of HOH & Gifford (Notes 1 & 4)	—			4,154,757			22,326			—			—			—			—			22,326
Sale of units at formation	—			2,043,483			10,981			—			—			—			—			10,981
General partner contribution	59			—			—			—			—			—			—			59
Net income	13			—			12,666			—			—			—			—			12,679
Foreign currency translation adjustment	—			—			—			—			—			56			—			56
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
General partner contributions	386			—			—			—			—			—			—			386
Contributions from noncontrolling interest owners	—			—			—			—			—			—			440			440
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		)
Foreign currency translation adjustment	—			—			—			—			—			(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 (Note 4)	(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
Foreign currency translation adjustment	—			—			—			—			—			(7		)	—			(7		)
BALANCES, MARCH 31, 2013	$	(50,497	)	47,703,313			$	920,998		5,919,346			$	13,153		$	24		$	5,740		$	889,418

The accompanying notes are an integral part of these consolidated financial statements.

F-8

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Consolidated Statements of Cash Flows

For the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

(U.S. Dollars in Thousands)

	NGL Energy Partners LP									NGL Supply, Inc.
	Year			Year			Six Months			Six Months
	Ended			Ended			Ended			Ended
	March 31,			March 31,			March 31,			September 30,
	2013			2012			2011			2010
OPERATING ACTIVITIES:
Net income (loss)	$	48,190		$	7,864		$	12,679		$	(2,560	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization, including debt issuance cost amortization	77,513			17,188			4,406			1,825
Loss on early extinguishment of debt	5,769			—			—			—
Non-cash equity-based compensation	8,670			—			—			—
(Gain) loss on sale of assets	187			(71		)	16			(124		)
Provision for doubtful accounts	1,315			1,049			269			3
(Gain) loss on commodity derivative financial instruments	4,376			(5,974		)	(1,468		)	(226		)
Other	375			403			3			(1,409		)
Changes in operating assets and liabilities, net of acquisitions -
Accounts receivable	2,430			(20,179		)	(813		)	203
Inventories	18,433			30,268			60,413			(59,598		)
Product exchanges, net	1,816			4,775			(16,329		)	18,688
Other current assets	20,769			9,569			3,697			(1,023		)
Trade accounts payable	(17,281		)	35,747			2,835			(3,741		)
Accrued expenses and other payables	(9,592		)	366			(1,209		)	(2,699		)
Accounts receivable/payable - affiliates, net	(19,690		)	4,742			—			—
Advance payments received from customers	(11,049		)	4,582			(30,490		)	19,912
Net cash provided by (used in) operating activities	132,231			90,329			34,009			(30,749		)
INVESTING ACTIVITIES:
Purchases of long-lived assets	(72,475		)	(7,544		)	(1,440		)	(280		)
Acquisitions of businesses, including acquired working capital	(490,402		)	(297,401		)	(17,400		)	(123		)
Net cash flows on non-hedge commodity derivative financial instruments	11,579			6,464			111			426
Proceeds from sales of assets	5,080			1,238			291			185
Other	—			346			—			125
Net cash provided by (used in) investing activities	(546,218		)	(296,897		)	(18,438		)	333
FINANCING ACTIVITIES:
Issuance of senior notes	250,000			—			—			—
Proceeds from borrowings under revolving credit facilities	1,227,975			478,900			149,500			34,490
Payments on revolving credit facilities	(964,475		)	(329,900		)	(112,381		)	(13,590		)
Proceeds from borrowings under other long-term debt	653			—			—			—
Payments on other long-term debt	(4,837		)	(1,278		)	(5,902		)	(722		)
Debt issuance costs	(20,189		)	(2,380		)	(4,928		)	—
Distributions to partners	(71,682		)	(19,060		)	—			—
Contributions	913			440			11,040			—
Proceeds from sale of common units, net of offering costs	(642		)	74,759			—			—
Collection of NGL Supply stock option receivables	—			—			1,430			—
Deferred offering costs	—			—			(1,929		)	—
Distributions to shareholders of NGL Supply	—			—			(40,000		)	—
Common stock dividends	—			—			—			(7,000		)
Other	—			—			—			(17		)
Redemption of preferred stock	—			—			—			(3,000		)
Repurchase of common units	—			(3,418		)	—			—
Net cash provided by (used in) financing activities	417,716			198,063			(3,170		)	10,161
EFFECT OF EXCHANGE RATE CHANGES ON CASH	—			—			(47		)	—
Net increase (decrease) in cash and cash equivalents	3,729			(8,505		)	12,354			(20,255		)
Cash and cash equivalents, beginning of period	7,832			16,337			3,983			24,238
Cash and cash equivalents, end of period	$	11,561		$	7,832		$	16,337		$	3,983

The accompanying notes are an integral part of these consolidated financial statements.

F-9

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 (the “IEP Parties”). NGL Energy Holdings LLC serves as our general partner. We had no operations prior to September 30, 2010.

Formation Transactions

In October 2010, we acquired retail and wholesale natural gas liquids businesses that were historically owned by NGL Supply, Inc. (“NGL Supply”), Hicks Oils and Hicksgas, Incorporated (“HOH”), and Hicksgas Gifford, Inc. (“Gifford”). The acquisitions were effected through the following transactions, which we refer to as the formation transactions:

·HOH formed a wholly owned subsidiary, Hicksgas, LLC, and contributed to it all of HOH’s propane and propane-related assets. The shareholders of Gifford contributed all of their shares of stock in Gifford to a newly formed holding company, Gifford Holdings, Inc.

·Our general partner made a cash capital contribution of approximately $58,800 to us in exchange for the continuation of its 0.1% general partner interest in us and incentive distribution rights and the IEP Parties (owner of a 32.53% interest in our general partner) made a cash capital contribution to us in the aggregate amount of approximately $11.0 million in exchange for an aggregate 18.67% limited partner interest in us.

·NGL Supply and Gifford each converted into a limited liability company and the members of NGL Supply, Hicksgas, LLC and Gifford contributed 100% of their respective membership interests in those entities to us as capital contributions in exchange for (i) in the case of NGL Supply, a 43.27% limited partner interest in us, a cash distribution of approximately $40.0 million and our agreement to pay or cause to be paid approximately $27.9 million of existing indebtedness of NGL Supply, (ii) in the case of Hicksgas, LLC, a 37.96% limited partner interest in us, a cash distribution of approximately $1.6 million and our agreement to pay or cause to be paid approximately $6.5 million of existing indebtedness of HOH, and (iii) in the case of Gifford, a cash payment of approximately $15.5 million.

·We made a capital contribution of 100% of the membership interests of each of NGL Supply, Hicksgas, LLC and Gifford to a wholly owned operating subsidiary. Gifford was merged into Hicksgas, LLC.

NGL Supply was organized on July 1, 1985 as a successor to a company founded in 1967, and is a diversified, vertically integrated provider of propane services including retail propane distribution; wholesale supply and marketing of propane and other natural gas liquids; and midstream operations which consist of natural gas liquids terminal operations and services.

The formation transactions described above were accounted for as a business combination with NGL Supply designated as the acquirer. Hicksgas, LLC and Gifford were determined to be acquirees. Accordingly, NGL Supply was accounted for on the basis of historical cost, and our assets and liabilities were recorded at the historical net book values of NGL Supply. The assets and liabilities of Hicksgas, LLC and Gifford were recorded at their estimated fair values on the transaction date.

NGL Supply began its retail propane operations during its fiscal year ended March 31, 2008 through the acquisition of retail operations in Kansas and Georgia, and expanded its retail operations through additional acquisitions during fiscal 2008 through 2010. As discussed above and in Note 4, we acquired Hicksgas LLC and Gifford in connection with our formation transactions. Hicksgas LLC and Gifford are both in the retail propane business with operations in Indiana and Illinois.

Initial Public Offering

On May 11, 2011, we completed an initial public offering (“IPO”). We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. We used the proceeds from the sale of 3,850,000 common units of $71.9 million, net of offering costs of approximately $9.0 million, to repay debt and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) were used to purchase 175,000 of the common units outstanding prior to our initial public offering. Upon the completion of our IPO, our limited partner equity consisted of 8,864,222 common units and 5,919,346 subordinated units.

F-10

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Acquisitions Subsequent to Initial Public Offering

Subsequent to our initial public offering, we significantly expanded our operations through a number of business combinations, including the following:

·On October 3, 2011, we completed a business combination transaction 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. 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 we paid in November 2012.

·On November 1, 2011, we completed a business combination transaction 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. We issued 8,932,031 common units and paid $91.0 million in exchange for the assets and operations of SemStream, including working capital.

·On January 3, 2012, we completed a business combination transaction with seven companies associated with Pacer Propane Holding, L.P. (collectively, “Pacer”), whereby we acquired retail propane operations, primarily in the western United States. We issued 1,500,000 common units, valued at $30.4 million, and paid $32.2 million of cash in exchange for the assets and operations of Pacer, including working capital. We also assumed $2.7 million of long-term debt in the form of non-compete agreements.

·On February 3, 2012, we completed a business combination transaction with North American Propane, Inc. (“North American”), whereby we acquired retail propane and distillate operations in the northeastern United States. We paid $69.8 million of cash in exchange for the assets and operations of North American, including working capital.

·During the year ended March 31, 2012, we completed three separate business combination transactions to acquire retail propane operations. On a combined basis, we paid $6.4 million of cash for these assets and operations, including working capital. We also assumed $0.7 million of long-term debt in the form of non-compete agreements.

·On June 19, 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. 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.

·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 purchasing and logistics operations in Texas and New Mexico. We paid cash of $132.4 million at closing (net of $2.2 million of cash acquired), subject to customary post-closing adjustments, 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 of Pecos purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement.

·On December 31, 2012, we completed a business combination transaction whereby we acquired all of the limited liability company 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. The agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. 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

F-11

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 call agreement.

·During the year ended March 31, 2013, we completed six separate business combination transactions to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States. On a combined basis, we paid $71.4 million of cash and issued 850,676 common units in exchange for these assets and operations, including working capital. We also assumed $6.6 million of long-term debt in the form of non-compete agreements.

·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 services businesses. On a combined basis, we paid $52.6 million of 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. Certain of the acquisition agreements contemplate post-closing adjustment to the purchase price for certain specified working capital items.

Businesses as of March 31, 2013

As of March 31, 2013, our businesses include:

·A crude oil logistics business, the assets of which include crude oil terminals, pipeline injection stations, a fleet of trucks, a fleet of leased rail cars, and a fleet of barges and tow boats. 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. The operations of our crude oil logistics segment began with our June 2012 merger with High Sierra.

·A water services business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water services 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. The operations of our water services segment began with our June 2012 merger with High Sierra.

·Our natural gas liquids logistics business, which supplies natural gas liquids to retailers, wholesalers, and refiners throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 17 terminals throughout the United States and rail car transportation services through its fleet of owned and predominantly leased rail cars. Our natural gas liquids logistics segment purchases propane, butane, and other natural gas liquids from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets. Our natural gas liquids logistics segment includes the operations that were previously reported in our wholesale marketing and supply and terminals segments. Our natural gas liquids logistics segment also includes the natural gas liquids operations we acquired in our June 2012 merger with High Sierra.

·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.

Note 2 - Summary of 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”). We were formed on September 8, 2010 with a capitalization of $1,000 by our general partner and had no operations or additional capitalizations through September 30, 2010. Accordingly, we are presenting our financial statements for periods subsequent to September 30, 2010. As described above, NGL Supply was deemed to be the acquiring entity in our formation transactions. Therefore, our financial statements for the six months ended September 30, 2010 represent the historical financial statements of NGL Supply. We recorded the assets acquired and liabilities assumed from NGL Supply at their historical net book values.

F-12

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

The accompanying consolidated financial statements include the accounts of the Partnership and its controlled subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

We have made certain reclassifications to the prior period financial statements to conform with classification methods used in fiscal 2013. These reclassifications had no impact on previously-reported amounts of total assets, liabilities, partners’ equity, or net income. In addition, as described in Note 4, certain balances as of March 31, 2012 were adjusted to reflect the final acquisition accounting for certain business combinations.

Estimates

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of our assets, liabilities, revenues, expenses and costs. These estimates are based on our knowledge of current events, historical experience, and various other assumptions that we believe to be reasonable under the circumstances.

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 should be 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, 2013 and 2012 (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, 2013 or 2012.

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

F-13

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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. Changes in the value of our interest rate swap agreements are recorded in our consolidated statements of operations in interest expense. Contracts that qualify for the normal purchase or sale exemption 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 realized or unrealized, are reported in the consolidated statement 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. Shipping and handling costs associated with product sales are included in operating expenses 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 the 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 in the amount of $5.3 million during the year ended March 31, 2013, $0.8 million during the year ended March 31, 2012, and $0.4 million during each of the six months ended March 31, 2011 and September 30, 2010. We also include in cost of sales the costs paid to the third parties who operate our terminal facilities under operating and maintenance agreements.

F-14

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Advertising Costs

We expense advertising costs as incurred. We recorded advertising expense of $1.1 million for the year ended March 31, 2013, $0.8 million for the year ended March 31, 2012, $0.3 million for the six months ended March 31, 2011, and $0.1 million for the six months ended September 30, 2010.

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.

Interest Income

Interest income consists primarily of fees charged to retail customers for late payment on accounts receivable.

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 during the indicated periods:

	NGL Energy Partners LP						NGL Supply
	Year		Year		Six Months		Six Months
	Ended		Ended		Ended		Ended
	March 31,		March 31,		March 31,		September 30,
	2013		2012		2011		2010
	(in thousands)
Interest paid	$	27,384	$	4,966	$	2,063	$	335
Income taxes paid	$	1,027	$	430	$	—	$	220

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

F-15

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 as of the dates indicated:

	March 31, 2013				March 31, 2012
	Gross		Allowance for		Gross		Allowance for
Segment	Receivable		Doubtful Accounts		Receivable		Doubtful Accounts
	(in thousands)
Crude oil logistics	$	360,721	$	11	$	—	$	—
Water services	9,618		29		—		—
Natural gas liquids logistics	144,267		76		52,640		113
Retail Propane	49,233		1,644		32,182		705
Other	810		—		—		—
	$	564,649	$	1,760	$	84,822	$	818

Changes in the allowance for doubtful accounts are as follows during the periods indicated:

	NGL Energy Partners LP									NGL Supply
	Year			Year			Six Months			Six Months
	Ended			Ended			Ended			Ended
	March 31,			March 31,			March 31,			September 30,
	2013			2012			2011			2010
	(in thousands)
Allowance for doubtful accounts, beginning of period	$	818		$	161		$	—		$	235
Bad debt provision	1,315			1,049			269			3
Write off of uncollectible accounts	(373		)	(392		)	(108		)	(64		)
Allowance for doubtful accounts, end of period	$	1,760		$	818		$	161		$	174

For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented approximately 10% of our consolidated total revenues. For the year ended March 31, 2012, no single customer accounted for more than 10% of our consolidated total revenues. For the six months ended March 31, 2011, we had one customer of our wholesale supply and marketing segment who represented approximately 10% of total consolidated revenues. In the six months ended September 30, 2010, two customers of our natural gas liquids logistics segment accounted for 28% of total consolidated revenues. As of March 31, 2013, one customer of our crude oil logistics segment represented approximately 10% of our consolidated accounts receivable balance. As of March 31, 2012, one customer of our wholesale supply and marketing segment represented approximately 21% of our consolidated accounts receivable balance.

Inventories

Our inventories include propane, normal butane, natural gasoline, isobutane, transmix, distillates, appliances, and parts and supplies. 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. We monitor inventory values for potential lower of cost or market adjustments and will record such adjustments at fiscal year-end, or on an interim basis if we believe the decline in market value will not be recovered by year end. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer inventory from our wholesale business to our retail business for sale in the retail markets.

F-16

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Our inventories as of March 31, 2013 and 2012 consisted of the following:

	2013		2012
	(in thousands)
Crude oil	$	46,156	$	—
Propane	45,428		78,993
Other natural gas liquids	24,090		9,259
Other	11,221		6,252
Total	$	126,895	$	94,504

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 less than its carrying value. In that event, we would recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group. No impairments of property, plant and equipment were recorded for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010.

Intangible Assets

Our identifiable intangible assets consist of debt issuance costs and significant contracts and arrangements acquired in business combinations, including lease agreements, customer relationships, covenants not to compete, and trade names. We capitalize acquired intangible assets if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of our intent to do so. 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’ 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.

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, 2013 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 as of 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 step 1 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-17

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

·In step 2 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 the results of these evaluations, we did not record any goodwill impairments during the years ended March 31, 2013 and 2012 or the six months ended March 31, 2011 and September 30, 2010.

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.

Asset Retirement Obligations

We record the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, which is typically at the time the assets are placed into service. After the initial measurement, we recognize changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.

Advance Payments Received from Customers

We record customer advances on product purchases as a liability on the consolidated balance sheets.

Noncontrolling Interests

As of March 31, 2013, we have three consolidated subsidiaries in which outside parties own interests. Our ownership interests in these subsidiaries range from 60% to 80%. One of these subsidiaries was formed in March 2012, and the other two were acquired in June 2012 and October 2012, respectively. The noncontrolling interest shown in our consolidated statements of operations for the years ended March 31, 2013 and 2012 represents the other owners’ interests in these entities.

The net loss attributable to noncontrolling interest shown in the consolidated statement of operations of NGL Supply for the six months ended September 30, 2010 reflects a 30% interest in a consolidated subsidiary that was owned by unrelated parties at the time. We currently own 100% of this subsidiary.

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 fiscal year ended March 31, 2013 are still within this measurement period, and as a result, the acquisition date values we have recorded for the acquired assets and assumed liabilities are subject to change.

F-18

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Note 3 - Earnings per Limited Partner Unit or Common Share

The earnings per limited partner unit of NGL Energy Partners LP were computed as follows for the periods indicated:

	Year			Year			Six Months
	Ended			Ended			Ended
	March 31,			March 31,			March 31,
	2013			2012			2011
	(U.S. Dollars in thousands, except unit and per unit amounts)
Basic and diluted earnings per common or subordinated unit:
Net income attributable to parent equity	$	47,940		$	7,876		$	12,679
Less - income allocated to general partner (*)	(2,917		)	(8		)	(13		)
Net income attributable to limited partners	$	45,023		$	7,868		$	12,666
Net income allocated to:
Common unitholders	$	39,517		$	4,859		$	12,666
Subordinated unitholders	$	5,506		$	3,009		$	—
Weighted average common units outstanding	41,353,574			15,169,983			10,933,568
Weighted average subordinated units outstanding	5,919,346			5,175,384			—
Earnings per unit - basic and diluted:
Common unitholders	$	0.96		$	0.32		$	1.16
Subordinated unitholders	$	0.93		$	0.58		$	—

(*)The income allocated to the general partner for the year ended March 31, 2013 includes distributions to which it is entitled as the holder of incentive distribution rights (described in Note 11).

The restricted units described in Note 11 were antidilutive for the year ended March 31, 2013.

The loss per share of common stock of NGL Supply was computed as follows for the six months ended September 30, 2010 (in thousands, except share and per share amounts):

Net loss attributable to parent equity	$	(2,515	)
Less - preferred stock dividends	(17		)
Net loss attributable to common shareholders	$	(2,532	)
Weighted average common shares outstanding	19,711
Basic and diluted loss per common share	$	(128.46	)

F-19

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Note 4 - Acquisitions

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 approximately $3.7 million of costs related to the High Sierra transaction. We also incurred or accrued costs of approximately $0.6 million related to the equity issuance that we charged to equity.

We have included the results of High Sierra’s operations in our consolidated financial statements beginning on June 19, 2012. During the year ended March 31, 2013, our consolidated statement of operations includes operating income of approximately $46.6 million generated by the operations of High Sierra and by the operations of the subsequent acquisitions of crude oil logistics and water services businesses. The following table summarizes the revenues and cost of sales contributed by High Sierra’s operations and the operations of the subsequent acquisitions of crude oil logistics and water services businesses (in thousands):

	Revenues		Cost of Sales
Crude oil logistics	$	2,316,288	$	2,244,647
Natural gas liquids logistics	696,424		663,630
Water services	62,227		5,611
Other	4,233		—
Total	$	3,079,172	$	2,913,888

F-20

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

The fair values of the assets acquired and liabilities assumed in our acquisition of High Sierra are summarized below (in thousands):

Accounts receivable	$	395,311
Inventory	43,575
Receivables from affiliates	7,724
Derivative assets	10,646
Forward purchase and sale contracts	34,717
Other current assets	11,131
Property, plant and equipment:
Land	5,910
Transportation vehicles and equipment (5 - 10 years)	20,968
Facilities and equipment (2 - 30 years)	103,574
Buildings and improvements (5 - 30 years)	9,691
Information technology equipment and software (3 - 5 years)	4,099
Construction in progress	11,213
Intangible assets:
Customer relationships (5 - 17 years)	245,000
Lease contracts (1 - 10 years)	12,400
Trade names (indefinite)	13,000
Goodwill	220,884
Assumed liabilities:
Accounts payable	(417,369		)
Accrued expenses and other current liabilities	(35,611		)
Payables to affiliates	(9,014		)
Advance payments received from customers	(1,237		)
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

The consideration paid consists of the following:

Cash paid, net of cash acquired	$	239,251
Value of common units issued, net of issuance costs	414,794
Total consideration paid	$	654,045

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.

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.

The fair value of accounts receivable is approximately $0.6 million lower than the contract value, to give effect to estimated uncollectable accounts.

Pecos Combination

On November 1, 2012, we completed a business combination whereby we acquired Pecos. The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texas and New Mexico. We paid cash of $132.4 million at closing (net of $2.2 million of cash acquired), subject to customary post-closing adjustments, 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

F-21

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 approximately $0.6 million of costs related to the Pecos combination.

We are in the process of identifying and determining the fair value of the assets and liabilities acquired in the combination with Pecos. The estimates of fair value reflected as of March 31, 2013 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 ended September 30, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Accounts receivable	$	73,704
Inventory	1,903
Other current assets	1,425
Property, plant and equipment:
Vehicles and related equipment (5 - 10 years)	19,193
Other	2,562
Customer relationships (5 years)	8,000
Trade names (indefinite life)	1,000
Goodwill	86,661
Accounts payable and accrued liabilities	(51,827		)
Long-term debt	(10,234		)
Total consideration paid	$	132,387

The consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired and cash received pursuant to Call Agreement	$	87,444
Value of common units issued pursuant to Call Agreement	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 for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. The agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. 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. We incurred and charged to general and administrative expense during the year ended March 31, 2013 approximately $0.3 million of costs related to the Third Coast combination.

F-22

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

We are in the process of identifying and determining the fair value of the assets and liabilities acquired in the combination with Third Coast. The estimates of fair value reflected as of March 31, 2013 are subject to change. We currently expect to complete this process prior to finalizing our financial statements for the quarter ended December 31, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Accounts receivable	$	2,248
Other current assets	140
Property, plant and equipment:
Barges and tow boats (20 years)	12,883
Other (3 - 5 years)	30
Customer relationships (5 years)	4,000
Trade names (indefinite life)	500
Goodwill	22,551
Other noncurrent assets	2,733
Assumed liabilities	(2,202		)
Consideration paid	$	42,883

The consideration paid consists of the following (in thousands):

Cash paid, net of cash received pursuant to call agreement	$	35,000
Value of common units issued pursuant to call agreement	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 Services 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 services 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. Certain of the agreements contemplate post-closing adjustments to the purchase price for certain specified working capital items. We incurred and charged to general and administrative expense during the year ended March 31, 2013 approximately $0.3 million of costs related to these acquisitions.

F-23

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

We are currently in the process of identifying and determining the fair value of the assets and liabilities acquired in this combination. The estimates of fair value reflected as of March 31, 2013 are subject to change. We currently expect to complete this process prior to finalizing our financial statements for the quarter ended September 30, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Accounts receivable	$	2,660
Inventory	191
Other current assets	738
Property, plant and equipment:
Disposal wells and related equipment (3 - 30 years)	13,322
Other (5 - 30 years)	5,671
Customer relationships (5 - 15 years)	6,800
Non-compete agreements (3 - 5 years)	510
Trade names (indefinite life)	500
Goodwill	43,822
Current liabilities	(5,400		)
Notes payable	(1,340		)
Other noncurrent liabilities	(156		)
Noncontrolling interest	(2,333		)
Consideration paid	$	64,985

The 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-24

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Retail 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 approximately $0.3 million related to these acquisitions. We are in the process of identifying the fair value of the assets acquired and liabilities assumed in certain of the combinations. The estimates of fair value reflected as of March 31, 2013 for certain of these acquisitions are subject to change, although such changes are not likely to be material. Our estimates of the fair value of the assets acquired and liabilities assumed in these six combinations are as follows (in thousands):

Accounts receivable	$	8,715
Inventory	5,155
Other current assets	1,228
Property, plant and equipment:
Land	1,945
Tanks and other retail propane equipment (5-20 years)	28,763
Vehicles (5 years)	11,344
Buildings (30 years)	7,052
Other equipment	1,201
Intangible assets:
Customer relationships (10-15 years)	16,890
Tradenames (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.

The retail combinations completed during the year ended March 31, 2013 contributed approximately $124.3 million of revenue and approximately $86.6 million of cost of sales to our consolidated statement of operations for the year ended March 31, 2013.

F-25

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Pro Forma Results of Operations (Unaudited)

The operations of High Sierra have been included in our consolidated statement of operations since High Sierra was acquired on June 19, 2012. The operations of Pecos have been included in our consolidated statement of operations since Pecos was acquired on November 1, 2012. The operations of Third Coast have been included in our consolidated statement of operations since Third Coast was acquired on December 31, 2012. The following unaudited pro forma consolidated data below are presented as if the High Sierra, Pecos, and Third Coast acquisitions had been completed on April 1, 2011 (in thousands, except per unit amounts). The pro forma earnings per unit are based on the common and subordinated units outstanding as of March 31, 2013.

	Years Ended March 31,
	2013		2012
Revenues	$	5,430,449	$	4,789,040
Income from continuing operations	56,366		15,720
Limited partners’ interest in income from continuing operations	53,442		15,704
Basic and diluted earnings from continuing operations per common unit	1.00		0.29
Basic and diluted earnings from continuing operations per subordinated unit	1.00		0.29

The pro forma consolidated data in the table above was prepared by adding the historical results of operations of High Sierra, Pecos, and Third Coast to our historical results of operations and making certain pro forma adjustments. The pro forma adjustments include: (i) replacing the historical depreciation and amortization expense of High Sierra, Pecos, and Third Coast with pro forma depreciation and amortization expense, calculated using the estimated fair values of long-lived assets recorded in the acquisition accounting; (ii) replacing the historical interest expense of High Sierra, Pecos, and Third Coast with pro forma interest expense; and (iii) excluding professional fees and other expenses incurred by us and by the acquirees that were directly related to the acquisitions. In order to calculate pro forma earnings per unit in the table above, we assumed that: (i) the same number of limited partner units outstanding at March 31, 2013 had been outstanding throughout the periods shown in the table, and (ii) all of the common units were eligible for distributions related to the periods shown in the table. The pro forma information is not necessarily indicative of the results of operations that would have occurred if the acquisitions had been completed on April 1, 2011, nor is it necessarily indicative of the future results of the combined operations.

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 approximately $772,000 of costs incurred in connection with the Osterman transaction. We also incurred costs related to the equity issuance of approximately $127,000 that we charged to equity. We have included the results of Osterman’s operations in our consolidated financial statements beginning October 3, 2011.

F-26

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

During the year ended March 31, 2013 we completed the acquisition accounting for this transaction. 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):

				Estimated
				Allocation
				as of
	Final			March 31,
	Allocation			2012			Revision
Accounts receivable	$	9,350		$	5,584		$	3,766
Inventory	3,869			3,898			(29		)
Other current assets	215			212			3
Property, plant and equipment:
Land	2,349			4,500			(2,151		)
Tanks and other retail propane equipment (15-20 years)	47,160			55,000			(7,840		)
Vehicles (5-20 years)	7,699			12,000			(4,301		)
Buildings (30 years)	3,829			6,500			(2,671		)
Other equipment (3-5 years)	732			1,520			(788		)
Intangible assets:
Customer relationships (20 years)	54,500			62,479			(7,979		)
Tradenames (indefinite life)	8,500			5,000			3,500
Non-compete agreements (7 years)	700			—			700
Goodwill	52,267			30,405			21,862
Assumed liabilities	(9,654		)	(5,431		)	(4,223		)
Consideration paid, net of cash acquired	$	181,516		$	181,667		$	(151	)

Consideration paid consists of the following (in thousands):

			Estimated
			Allocation
			as of
	Final		March 31,
	Allocation		2012		Revision
Cash paid at closing, net of cash acquired	$	94,873	$	96,000	$	(1,127	)
Fair value of common units issued at closing	81,880		81,880		—
Working capital payment (paid in November 2012)	4,763		3,787		976
Consideration paid, net of cash acquired	$	181,516	$	181,667	$	(151	)

We have adjusted the March 31, 2012 balances reported in these consolidated financial statements to reflect the final acquisition accounting. These revisions did not have a material impact on the consolidated statements of operations.

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-27

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 natural gas liquids logistics operations. 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 approximately $91.0 million. We have valued the 8.9 million limited partner common units at approximately $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 approximately $736,000 of costs related to the SemStream transaction. We also incurred costs of approximately $43,000 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 above ground propane storage, 3.7 million barrels of underground leased storage for natural gas liquids and a rail fleet of approximately 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 natural gas liquids logistics segment.

The following table presents the fair values of the assets acquired and liabilities assumed in the SemStream combination (in thousands):

Propane and other natural gas liquids inventory	$	104,226
Derivative financial instruments	3,578
Assets held for sale	3,000
Prepaids and other current assets	9,833
Property, plant and equipment:
Land	3,470
Tanks and terminals (20-30 years)	41,434
Vehicles and rail cars (5 years)	470
Other (5 years)	3,326
Investment in capital lease	3,112
Amortizable intangible assets:
Customer relationships (8-15 years)	31,950
Rail car leases (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.

F-28

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 approximately $710,000 of costs related to the Pacer transaction. We also incurred costs of approximately $64,000 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.

The consideration paid in the Pacer combination consisted of the following (in thousands):

Cash	$	32,213
Common units	30,375
	$	62,588

During the year ended March 31, 2013, we completed the acquisition accounting for this transaction. 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):

					Estimated
					Allocation
					as of
		Final			March 31,
		Allocation			2012			Revision
	Accounts receivable	$	4,389		$	4,389		$	—
	Inventory	965			965			—
	Other current assets	43			43			—
	Property, plant and equipment:
	Land	1,967			1,400			567
	Tanks and other retail propane equipment (15 - 20 years)	12,793			11,200			1,593
	Vehicles (5 years)	3,090			5,000			(1,910		)
	Buildings (30 years)	409			2,300			(1,891		)
	Other equipment (3-5 years)	59			200			(141		)
	Intangible assets:
	Customer relationships (15 years)	23,560			21,980			1,580
	Tradenames (indefinite life)	2,410			1,000			1,410
	Noncompete agreements	1,520			—			1,520
	Goodwill	15,782			18,460			(2,678		)
	Assumed Liabilities	(4,399		)	(4,349		)	(50		)
	Consideration paid	$	62,588		$	62,588		$	—
We have adjusted the March 31, 2012 balances reported in these consolidated financial statements to reflect the final acquisition accounting. These revisions did not have a material impact on the consolidated statements of operations.

F-29

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 approximately $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. We have included the results of North American’s operations in our consolidated financial statements beginning on February 3, 2012.

During the year ended March 31, 2013, we completed the acquisition accounting for this transaction. The following table presents the final allocation of the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (in thousands):

				Estimated
				Allocation
				as of
	Final			March 31,
	Allocation			2012			Revision
Accounts receivable	$	10,338		$	10,338		$	—
Inventory	3,437			3,437			—
Other current assets	282			282			—
Property, plant and equipment:
Land	2,251			2,600			(349		)
Tanks and other retail propane equipment (15-20 years)	24,790			27,100			(2,310		)
Terminal assets (15-20 years)	1,044			—			1,044
Vehicles (5-15 years)	5,819			9,000			(3,181		)
Buildings (30 years)	2,386			2,200			186
Other equipment (3-5 years)	634			500			134
Intangible assets:
Customer relationships (10 years)	12,600			9,800			2,800
Tradenames (10 years)	2,700			1,000			1,700
Noncompete agreements (3 years)	700			—			700
Goodwill	13,978			14,702			(724		)
Assumed liabilities	(11,129		)	(11,129		)	—
Consideration paid	$	69,830		$	69,830		$	—

We have adjusted the March 31, 2012 balances reported in these consolidated financial statements to reflect the final acquisition accounting. These revisions did not have a material impact on the consolidated statements of operations.

F-30

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 approximately $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.

Six Months Ended March 31, 2011

As discussed in Note 1, we purchased the retail propane operations of Hicksgas LLC and Gifford in October 2010 as part of our formation transactions. The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their estimated fair values, in the acquisition of the retail propane businesses of Hicksgas LLC and Gifford described above (in thousands):

Accounts receivable	$	5,669
Inventory	6,182
Prepaid expenses and other current assets	2,600
	14,451
Property, plant, and equipment:
Land	2,666
Tanks and other retail propane equipment (15 year life)	23,016
Vehicles (5 year life)	6,599
Buildings (30 year life)	7,053
Office equipment (5 year life)	523
Amortizable intangible assets:
Customer relationships (15 year life)	2,170
Non-compete agreements (5 year life)	550
Tradenames (indefinite-life intangible asset)	830
Goodwill (retail propane segment)	3,716
Total assets acquired	61,574
Accounts payable	1,837
Customer advances and deposits	12,089
Accrued and other current liabilities	2,152
	16,078
Long-term debt	5,768
Other long-term liabilities	274
Total liabilities assumed	22,120
Net assets acquired	$	39,454

F-31

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Goodwill was warranted because these acquisitions enhanced our retail propane operations. We expect all of the goodwill acquired to be tax deductible. We do not believe that the acquired intangible assets will have any significant residual value at the end of their useful life.

The total acquisition cost was $39.5 million, consisting of cash of approximately $17.2 million and the issuance of 4,154,757 common units valued at $22.3 million. The units issued to the shareholders of Hicksgas LLC in the formation transaction were valued at $5.37 per unit, the price paid by unrelated parties for the common units they acquired near the transaction date.

The operations of Hicksgas LLC and Gifford have been included in our statements of operations since acquisition in October 2010. For convenience, and because the impact was not significant, we have accounted for the acquisition as it if occurred on October 1, 2010.

Note 5 - Property, Plant and Equipment

Property, plant and equipment consists of the following at March 31, 2013 and 2012:

				2012
Description and Depreciable Life	2013			(Note 4)
	(in thousands)
Natural gas liquids terminal assets (30 years)	$	63,637		$	62,024
Retail propane equipment (5-20 years)	152,802			119,972
Vehicles (5-10 years)	85,200			26,372
Water treatment facilities and equipment (3-30 years)	91,601			—
Crude oil tanks and loading facilities (2-30 years)	21,308			—
Barges and towboats (20 years)	21,135			—
Information technology equipment (3-5 years)	12,169			4,347
Buildings and leasehold improvements (5-30 years)	48,394			14,651
Land	21,604			13,084
Other (3-10 years)	17,288			3,108
Construction in progress	31,926			679
	567,064			244,237
Less: Accumulated depreciation	(50,127		)	(12,843		)
Property, plant and equipment, net	$	516,937		$	231,394

Depreciation expense was as follows for the periods indicated:

NGL Energy Partners LP						NGL Supply
Year		Year		Six Months		Six Months
Ended		Ended		Ended		Ended
March 31,		March 31,		March 31,		September 30,
2013		2012		2011		2010
(in thousands)
$	39,196	$	10,573	$	2,848	$	998

F-32

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Note 6 - Goodwill

Changes to goodwill were as follows for the periods indicated:

	NGL Energy Partners LP						NGL Supply
	Year		Year		Six Months		Six Months
	Ended		Ended		Ended		Ended
	March 31,		March 31,		March 31,		September 30,
	2013		2012		2011		2010
	(in thousands)
Beginning of period, as retrospectively adjusted (Note 4)	$	167,245	$	8,568	$	4,580	$	4,457
Goodwill from acquisitions, including additional consideration paid for previous acquisitions	395,901		158,677		3,988		123
End of period, as retrospectively adjusted (Note 4)	$	563,146	$	167,245	$	8,568	$	4,580
Goodwill by segment at end of period:
Crude oil logistics	$	244,073	$	—	$	—	$	—
Water services	119,668		—		—		—
Retail propane	112,269		90,287		6,534		2,546
Natural gas liquids logistics	87,136		76,958		2,034		2,034

Note 7 - Intangible Assets

Intangible assets consist of the following:

		March 31, 2013				March 31, 2012
						(Note 4)
		Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Amortizable Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable -
Customer relationships	5-20 years*	$	407,835	$	30,959	$	128,071	$	3,868
Lease and other agreements	1-8 years	15,210		7,018		2,810		1,545
Non-compete agreements	2-7 years	11,855		2,871		5,033		919
Trade names	3-10 years	2,784		326		2,700		—
Debt issuance costs	5-10 years	19,494		2,981		7,310		1,842
Total amortizable		457,178		44,155		145,924		8,174
Non-amortizable -
Trade names	Indefinite	29,580		—		11,740		—
Total		$	486,758	$	44,155	$	157,664	$	8,174

*  The weighted-average amortization period for customer relationship intangible assets is approximately 11 years.

F-33

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Amortization expense was as follows for the periods indicated:

	NGL Energy Partners LP						NGL Supply
	Year		Year		Six Months		Six Months
	Ended		Ended		Ended		Ended
	March 31,		March 31,		March 31,		September 30,
Recorded in	2013		2012		2011		2010
	(in thousands)
Depreciation and amortization	$	29,657	$	4,538	$	593	$	391
Interest expense	3,375		1,277		565		36
Loss on early extinguishment of debt	5,769		—		—		—
Cost of sales - natural gas liquids logistics	5,285		800		400		400
	$	44,086	$	6,615	$	1,558	$	827

Future amortization expense of our intangible assets is estimated to be as follows (in thousands):

Year Ending March 31,
2014	$	44,485
2015	43,137
2016	41,396
2017	39,567
2018	34,234
Thereafter	210,204
	$	413,023

Note 8 - Long-Term Obligations

We have the following long-term debt:

	March 31,
	2013		2012
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	441,500	$	—
Working capital loans	36,000		—
Previous revolving credit facility —
Acquisition loans	—		186,000
Working capital loans	—		28,000
Senior notes	250,000		—
Other notes payable	21,562		4,711
	749,062		218,711
Less current maturities	8,626		19,534
Long-term debt	$	740,436	$	199,177

F-34

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

On June 19, 2012, we entered into a credit agreement (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”). Also on June 19, 2012, we entered into a note purchase agreement (the “Note Purchase Agreement”) whereby we issued $250 million of Senior Notes in a private placement (the “Senior Notes”). We used the proceeds from the issuance of the Senior Notes and borrowings under the Credit Agreement to repay existing debt and to fund the merger with High Sierra.

Credit Agreement

The Working Capital Facility had a total capacity of $242.5 million for cash borrowings and letters of credit at March 31, 2013. At March 31, 2013, we had outstanding cash borrowings of $36.0 million and outstanding letters of credit of $60.1 million on the Working Capital Facility, leaving a remaining capacity of $146.4 million at March 31, 2013. The Expansion Capital Facility had a total capacity of $527.5 million for cash borrowings at March 31, 2013. At March 31, 2013, we had outstanding cash borrowings of $441.5 million on the Expansion Capital Facility, leaving a remaining capacity of $86.0 million at March 31, 2013. 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. At March 31, 2013, the borrowing base provisions of the Credit Agreement did not have any impact on the capacity available under the Working Capital Facility.

During May 2013, we entered into an amendment to the Credit Agreement that increased the total capacity on the Working Capital Facility from $242.5 million to $325.0 million and increased the total capacity on the Expansion Capital Facility from $527.5 million to $725.0 million. We paid approximately $2.1 million of fees related to this amendment to the Credit Agreement.

The commitments under the Credit Agreement expire on June 19, 2017. 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 1.75% to 2.75% per annum or (ii) an adjusted LIBOR rate plus a margin of 2.75% to 3.75% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At March 31, 2013, the interest rate in effect on outstanding LIBOR borrowings was 3.21%, calculated as the LIBOR rate of 0.21% plus a margin of 3.0%. At March 31, 2013, interest rate in effect on outstanding base rate borrowings was 5.25%, calculated as the base rate of 3.25% plus a margin of 2.0%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. 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, 2013, our leverage ratio was approximately 3.0 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, 2013, our interest coverage ratio was approximately 7.0 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, 2013, we were in compliance with all covenants under the Credit Agreement.

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.

F-35

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 is 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 million, (iv) the rendering of a judgment for the payment of money in excess of $10 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, 2013, we were in compliance with all covenants under the Note Purchase Agreement.

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.

Balances Outstanding and Rates

At March 31, 2013, our outstanding borrowings and interest rates under our revolving credit facility were as follows (dollars in thousands):

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	441,500	3.21	%
Working capital facility —
LIBOR borrowings	20,000		3.21	%
Base rate borrowings	16,000		5.25	%

F-36

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Other Notes Payable

We have executed various non-interest bearing notes, payable primarily related to acquisitions described in Note 4. We also acquired certain notes payable in our acquisition of Pecos that relate to equipment financing; the interest rates on these notes payable range from 2.6% to 4.9% at March 31, 2013. 

Debt Maturity Schedule

The future maturities of our long-term debt are as follows as of March 31, 2013 (in thousands):

	Revolving				Other
	Credit		Senior		Notes
Year ending March 31,	Facility		Notes		Payable		Total
2014	$	—	$	—	$	8,626	$	8,626
2015	—		—		6,456		6,456
2016	—		—		3,088		3,088
2017	—		—		2,091		2,091
2018	477,500		25,000		1,182		503,682
Thereafter	—		225,000		119		225,119
	$	477,500	$	250,000	$	21,562	$	749,062

Note 9 - Income Taxes

NGL Energy Partners LP

We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay U.S. 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 two taxable corporate subsidiaries in the United States and three taxable corporate subsidiaries in Canada. The income tax provision reported in our consolidated statements of operations relates primarily to these subsidiaries.

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 both of the calendar years since our initial public offering.

NGL Supply

NGL Supply’s income tax benefit of $1.4 million for the six months ended September 30, 2010 consisted primarily of U.S. federal deferred income taxes. This provision approximated the U.S. federal statutory rate of 35%.

Uncertain Tax Positions

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 positions 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. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. We had no material uncertain tax positions that required recognition in the consolidated financial statements at March 31, 2013 or 2012. Any interest or penalties would be recognized as a component of income tax expense. We consider NGL Supply’s open tax years to be 2008 through 2010; however, we are not responsible for any tax obligation related to such open tax years.

F-37

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 consolidated liabilities may change materially as circumstances develop.

In September 2010, Pemex Exploracion y Produccion (“Pemex”) filed a lawsuit in the United States District Court for the Southern District of Texas against a number of defendants, including High Sierra. Pemex alleged that High Sierra and the other defendants purchased condensate from a source that had acquired the condensate illegally from Pemex. We do not believe that High Sierra had knowledge at the time of the purchases of the condensate that such condensate was allegedly sold illegally to High Sierra and others. During March 2013, we settled this litigation for $3.1 million, which we recorded as a liability in the final accounting for our acquisition of High Sierra.

In May 2010, two lawsuits were filed in Kansas and Oklahoma by numerous oil and gas producers (the “Associated Producers”), asserting that they were entitled to enforce lien rights on crude oil purchased by High Sierra and other defendants. These cases were subsequently transferred to the United States Bankruptcy Court for the District of Delaware. During March 2013, we settled this litigation for an insignificant amount.

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 $2.2 million of the amount we charged for services subsequent to our acquisition of Pecos. 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 $2.2 million of unpaid fees charged subsequent to our acquisition of Pecos, pending resolution of the dispute. 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 recently completed an audit of fuel and sales tax payments, and concluded that High Sierra should have collected from customers and remitted to the taxing authority approximately $14.9 million of fuel taxes and sales taxes on certain historical sales. High Sierra had not collected and remitted fuel and sales taxes on these transactions, as High Sierra believed the transactions were exempt from these taxes. We are in the process of gathering information to support High Sierra’s position that the transactions were exempt from the taxes, which we believe could substantially reduce the amount of the tax assessed. If we are unsuccessful in demonstrating that these transactions were exempt, we would be required to remit payment to the taxing authority; however, we expect we would be able to recover these payments from the customers pursuant to the terms of our contracts with the customers. Although the outcome of this matter is not certain at this time, we do not believe the ultimate resolution of this matter will have a material adverse effect on our consolidated financial position or results of operations. We recorded in the acquisition accounting for the merger with High Sierra a liability of $14.9 million, which is the full amount assessed, and a receivable of $14.1 million, which represents the amount we would expect to recover from the customers in the event we are ultimately required to pay the taxes assessed.

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

F-38

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 an asset retirement obligation liability of $1.5 million at March 31, 2013. This liability is related to the wastewater disposal assets and crude oil pipeline injection facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned.

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 non-cancelable operating lease agreements for product storage, office space, vehicles, real estate, and equipment. Future minimum lease payments under contractual commitments as of March 31, 2013 are as follows (in thousands):

Year Ending March 31,
2014	$	55,065
2015	38,283
2016	31,297
2017	29,005
2018	21,520
Thereafter	36,268
Total	$	211,438

Rental expense relating to operating leases was as follows for the periods indicated (in thousands):

Year ended March 31, 2013	$	51,354
Year ended March 31, 2012	5,202
Six months ended March 31, 2011	838
Six months ended September 30, 2010	676

Sales and Purchase Contracts

We have entered into sales and purchase contracts for natural gas liquids (including propane, butane, and ethane) and crude oil to be delivered in future periods. These contracts require that the parties physically settle the transactions with inventory. At March 31, 2013, we had the following such commitments outstanding:

	Volume	Value
	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)	84,159	$	76,386
Natural gas liquids floating-price purchase commitments (gallons)	540,518	604,584
Natural gas liquids fixed-price sale commitments (gallons)	102,071	100,246
Natural gas liquids floating-price sale commitments (gallons)	262,143	339,757
Crude oil fixed-price purchase commitments (barrels)	3,382	303,819
Crude oil fixed-price sale commitments (barrels)	5,642	504,505

F-39

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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.

Certain of the forward purchase and sale contracts shown in the table above were acquired in the June 2012 merger with High Sierra. We recorded these contracts at their estimated fair values at the merger date, and we are amortizing these assets and liabilities to cost of sales over the remaining terms of the contracts. At March 31, 2013, the unamortized balances included in our consolidated balance sheet were as follows (in thousands):

Current assets	$	3,124
Current liabilities	(586		)
Net assets	$	2,538

The following table summarizes the amortization expense (income) we have recorded, and the amortization expense (income) we expect to record, to cost of sales related to the forward purchase and sale contracts acquired in the merger with High Sierra (in thousands):

	Natural Gas Liquids		Crude Oil
	Logistics Segment		Logistics Segment			Total
Year ended March 31, 2013	$	14,587	$	(1,089	)	$	13,498
Year ending March 31, 2014	2,701		(163		)	2,538
Total expense (income)	$	17,288	$	(1,252	)	$	16,036

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.

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. Also, if we have earned and paid at least 150% of the minimum quarterly distribution on each outstanding common unit and subordinated unit, the corresponding distribution on the general partner interest and the related distribution on the incentive distribution rights for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. 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 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-40

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Conversion of Common Units to Subordinated Units

In addition, on May 11, 2011 we converted 5,919,346 of our common units to subordinated units. The unaudited pro forma impact of this unit conversion on our limited partner equity as of March 31, 2011 and earnings per unit information for the six months ended March 31, 2011, assuming the conversion occurred on October 1, 2010, is as follows:

	Historical			Unaudited Pro Forma
	Units	Amount		Units	Amount
	(U.S. Dollars in thousands, except per unit amounts)
Limited Partner Equity —
Common units	10,933,568	$	47,225	5,014,222	$	21,658
Subordinated units	—	—		5,919,346	25,567
	10,933,568	$	47,225	10,933,568	$	47,225
Earnings per unit, basic and diluted —
Common units		$	1.16		$	1.16
Subordinated units		$	—		$	1.16

Initial Public Offering

On May 11, 2011, we sold a total of 4,025,000 common units in our initial public offering (IPO) at $21.00 per unit. Our proceeds from the sale of 3,850,000 common units of $71.9 million, net of offering costs of approximately $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) were used to purchase 175,000 of the common units outstanding prior to our initial public offering.

Upon the completion of our IPO, our limited partner equity consisted of 8,864,222 common units and 5,919,346 subordinated units.

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
Water services combination	516,978
Pecos combination	1,834,414
Third Coast combination	344,680
Total - year ended March 31, 2013	24,250,258

In connection with the completion of these transactions, we amended our Registration Rights Agreement, which provides for certain registration rights for certain holders of our common units.

F-41

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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.”  Our minimum quarterly distribution is $0.3375 per unit ($1.35 per unit on an annual basis).

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 incentive distribution rights and there are no arrearages on common units.

							Marginal Percentage Interest In
	Total Quarterly						Distributions
	Distribution per Unit						Unitholders		General Partner
Minimum quarterly distribution					$	0.3375	99.9	%	0.1	%
First target distribution	above	$	0.3375	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	$	0.50625	76.9	%	23.1	%
Thereafter	above	$	0.50625				51.9	%	48.1	%

There were no distributions during the six months ended March 31, 2011. Subsequent to March 31, 2011 and prior to our initial public offering, a distribution of $3.85 million ($0.35 per common unit) was declared for the unitholders as of March 31, 2011. The distribution was paid on May 5, 2011.

The following table summarizes the distributions declared subsequent to our initial public offering:

			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

F-42

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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	—

Equity-Based Incentive Compensation

Our general partner has adopted the NGL Energy Partners LP 2011 Long-Term Incentive Plan for the employees and directors of our general partner and its affiliates who perform services for us. The Long-Term Incentive Plan allows for the issuance of restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards, as discussed below. The number of common units that may be delivered pursuant to awards under the plan 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 will not be considered to be delivered under the Long-Term Incentive Plan. 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 will again be available for new awards under the Long-Term Incentive Plan. Common units to be delivered pursuant to awards under the Long-Term Incentive Plan may be newly issued common units, common units acquired by us in the open market, common units acquired by us from any other person, or any combination of the foregoing. If we issue new common units with respect to an award under the Long-Term Incentive Plan, the total number of common units outstanding will increase.

During the year ended March 31, 2013, the Board of Directors of our general partner 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 year ended March 31, 2013:

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

F-43

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

The scheduled vesting of the awards is summarized below:

Vesting Date	Number of Awards
July 1, 2013	377,300
July 1, 2014	360,800
July 1, 2015	272,300
July 1, 2016	263,500
July 1, 2017	169,000
July 1, 2018	2,000
Total unvested units at March 31, 2013	1,444,900

For the 218,500 awards that vested on January 1, 2013, we issued 156,802 common units to the recipients and we recorded an increase to equity of $3.7 million. We withheld 61,698 common units, in return for which we paid $1.4 million of withholding taxes on behalf of the recipients.

The weighted-average fair value of the awards was $23.01 at March 31, 2013, which was calculated as the closing price of the common units on March 31, 2013, 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.

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. We recorded $10.1 million of expense related to these awards during the year ended March 31, 2013. We account for these as liability awards; the balance in accrued expenses and other payables on our consolidated balance sheet at March 31, 2013 includes $5.0 million related to these awards. We estimate that the expense we will record on the unvested awards as of March 31, 2013 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of approximately 71,000 units. For purposes of this calculation, we have used the closing price of the common units on March 31, 2013.

Year ending March 31,
2014	$	12,168
2015	7,516
2016	6,559
2017	4,613
2018	1,040
2019	15
Total	$	31,911

As of March 31, 2013, 3,760,539 units remain available for issuance under the Long-Term Incentive Plan.

F-44

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Equity of NGL Supply

As of March 31, 2010, NGL Supply’s authorized capital consisted of 1,000 shares of preferred stock (discussed below) and 100,000 shares of Class A common stock, $10 par value per share. During the six months ended September 30, 2010, 650 outstanding stock options were exercised for a total consideration of $1.4 million, which was paid in October 2010.

The changes in net equity of NGL Supply for the period of September 30, 2010 to October 14, 2010 were as follows (in thousands):

Net equity at September 30, 2010	$	36,811
Collection of stock option receivable	1,430
Net tax obligations of NGL Supply not assumed by the Partnership	3,120
Distribution to previous shareholders	(40,000		)
Other	(109		)
Net carrying value of assets and liabilities contributed by NGL Supply	$	1,252

Redeemable Preferred Stock

NGL Supply had 1,000 shares of its Series A Preferred Stock outstanding at March 31, 2010. The preferred shares were redeemable at $3,000 per share plus dividends in arrears at the option of the shareholder with 30 days notice. These preferred shares have been separately classified in the consolidated statement of changes in equity at their purchased amount which is also the redeemable cost at March 31, 2010. On May 17, 2010, NGL Supply redeemed all of the preferred stock at the stated value plus accrued dividends for approximately $3.0 million.

Common Stock Dividends

On June 30, 2010, NGL Supply paid a dividend to the owners of its common stock of $7.0 million.

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. The carrying amounts of our debt obligations reasonably approximate their fair values at March 31, 2013, as most of our debt is subject to terms that were recently negotiated.

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, 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	(3,503		)	3,503
Cash collateral provided or held	(1,760		)	400
Commodity contracts reported on consolidated balance sheet	$	5,595		$	(12,701	)

F-45

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2012:

	Derivative		Derivative
	Assets		Liabilities
	(in thousands)
Level 1 measurements	$	—	$	—
Level 2 measurements	—		(36		)
	—		(36		)
Netting of counterparty contracts	—		—
Cash collateral provided or held	—		—
Commodity contracts reported on consolidated balance sheet	$	—	$	(36	)

The commodity derivative assets (liabilities) are reported in the following accounts on the consolidated balance sheets:

	March 31,			March 31,
	2013			2012
	(in thousands)
Prepaid expenses and other current assets	$	5,551		$	—
Other noncurrent assets	44			—
Accrued expenses and other payables	(12,701		)	(36		)
Net liability	$	(7,106	)	$	(36	)

F-46

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

The following table sets forth our open commodity derivative contract positions at March 31, 2013 and 2012. We do not account for these derivatives as hedges.

Contracts	Settlement Period	Total Notional Units (Barrels)		Fair Value of Net Assets (Liabilities)
		(in thousands)
As of March 31, 2013 -
Propane swaps (1)	April 2013 - March 2014	(282	)	$	3,197
Heating oil calls and futures (2)	May 2013 - June 2013	8		79
Crude swaps (3)	April 2013 - June 2014	(91	)	153
Crude - butane spreads (4)	April 2013 - March 2014	(1,116	)	(7,651		)
Crude forwards (5)	April 2013 - March 2014	(144	)	1,033
Butane forwards (6)	April 2013 - March 2014	1,546		(2,557		)
				(5,746		)
Net cash collateral held				(1,360		)
Net fair value of commodity derivatives on consolidated balance sheet				$	(7,106	)
As of March 31, 2012 -
Propane swaps	April 2012 - March 2013	(460	)	$	(36	)

(1)Propane swaps — Our natural gas liquids logistics 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 swaps” represent financial derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

(2)Heating oil calls and futures — Our retail segment offers our customers the opportunity to purchase a specified volume of heating oil at a fixed price. The contracts listed in this table as “heating oil calls and futures” represent financial derivatives we have entered into as an economic hedge against the risk that heating oil prices will rise between the time we entered into the fixed price sale commitment with the customers and the time we will the purchase heating oil to sell to the customers.

(3)Crude swaps — Our crude oil logistics segment routinely enters into crude oil purchase and sale contracts that are priced based on a crude oil index. 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 swaps” represent hedges against the risk that changes in the different index prices would reduce the margins between the purchase and the sale transactions.

(4)Crude-butane spreads — Our natural gas liquids logistics segment enters into forward contracts to sell butane at a price that will be calculated as a specified percentage of a crude oil index at the delivery date. The contracts listed in this table as “crude — butane spreads” represent financial derivatives we have entered into as economic hedges against the risk that the spread between butane prices and crude prices will narrow between the time we entered into the butane forward sale contracts and the expected delivery dates.

(5)Crude forwards — 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 forwards” represent financial derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding inventory.

(6)Butane forwards — Our natural gas liquids logistics segment routinely purchases butane inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “butane forwards” represent

F-47

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

financial derivatives we have entered into as an economic hedge against the risk that butane prices will decline while we are holding inventory.

We recorded the following net gains (losses) from our commodity and interest rate derivatives during the periods indicated:

	NGL Energy Partners LP								NGL Supply
	Year			Year			Six Months		Six Months
	Ended			Ended			Ended		Ended
	March 31,			March 31,			March 31,		September 30,
	2013			2012			2011		2010
	(in thousands)
Commodity contracts -
Unrealized gain (loss)	$	(5,275	)	$	(4,384	)	$	1,357	$	(200	)
Realized gain	899			10,351			111		426
Interest rate swaps	(5		)	(291		)	224		—
Total	$	(4,381	)	$	5,676		$	1,692	$	226

The commodity contract gains and losses are included in cost of sales in the consolidated statements of operations.

Interest Rate Swap Agreement

We have entered into an interest rate swap agreement to hedge the risk of interest rate fluctuations on our long-term debt. This agreement converts a portion of our revolving credit facility floating rate debt into fixed rate debt on a notional amount of $8.5 million and ends on December 31, 2013. The notional amounts of derivative instruments do not represent actual amounts exchanged between the parties, but instead represent amounts on which the contracts are based. The floating interest rate payments under these swaps are based on three-month LIBOR rates. We do not account for this agreement as a hedge. We recorded a liability of less than $0.1 million at March 31, 2013 and a liability of $0.1 million at March 31, 2012 related to this agreement.

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.

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.

We acquired a crude oil logistics business in our June 2012 merger with High Sierra. 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 business are generally higher than the receivables from customers in 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

The interest rate on our revolving credit facility floats based on market indices. At March 31, 2013, we have $461.5 million of debt on our revolving credit facility at a rate of 3.21% and $16.0 million of debt on our revolving credit facility at a rate of 5.25%. A change of 0.125% in the interest rate would result in a change to annual interest expense of approximately $0.6 million on the revolving debt balance of $477.5 million. We believe that the interest rates of the revolving credit facility are consistent with current market rates, and that the book value of the debt approximates fair value.

F-48

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

Note 13 - Employee Benefit Plan

We sponsor a 401(k) defined contribution plan for the benefit of our employees. For the years ended March 31, 2013 and 2012, and the six months ended March 31, 2011 and September 30, 2010, we made contributions to the plan totaling $1.9 million, $0.5 million, $0.2 million and $0.1 million, respectively.

Note 14 - Segment Information

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. These operations began with our June 2012 merger with High Sierra.

Our water services segment provides services for the transportation, treatment, and disposal of wastewater generated from oil and natural gas production, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. These operations began with our June 2012 merger with High Sierra.

Our natural gas liquids logistics segment supplies propane and other natural gas liquids, and provides natural gas liquids transportation, terminalling, and storage services to retailers, wholesalers, and refiners. This segment includes our historical natural gas liquids operations and the natural gas liquids operations acquired in the June 2012 merger with High Sierra. We previously reported our natural gas liquids operations in two segments, referred to as our “wholesale marketing and supply” and “midstream” segments. The data in the table below has been presented under our new structure for all periods, with the amounts previously reported in the wholesale marketing and supply and midstream segments reported on a combined basis within the natural gas liquids logistics segment.

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.

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 also include 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.

F-49

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

	NGL Energy Partners LP									NGL Supply
	Year			Year			Six Months			Six Months
	Ended			Ended			Ended			Ended
	March 31,			March 31,			March 31,			September 30,
	2013			2012			2011			2010
	(in thousands)
Revenues:
Crude oil logistics	$	2,339,148		$	—		$	—		$	—
Water services	62,227			—			—			—
Natural gas liquids logistics -
Propane sales	841,448			923,022			477,774			243,908
Other natural gas liquids sales	858,276			251,627			90,746			71,456
Storage revenues and other	33,954			2,462			1,183			959
Retail propane -
Propane sales	288,410			175,417			67,175			6,128
Distillate sales	106,192			6,547			—			—
Other retail sales	35,856			17,370			5,638			740
Other	4,233			—			—			—
Eliminations of intersegment sales	(151,977		)	(65,972		)	(20,284		)	(6,248		)
Total revenues	$	4,417,767		$	1,310,473		$	622,232		$	316,943
Depreciation and amortization:
Crude oil logistics	$	9,176		$	—		$	—		$	—
Water services	20,923			—			—			—
Natural gas liquids logistics	11,085			3,661			554			519
Retail propane	25,496			11,450			2,887			870
Other	2,173			—			—			—
Total depreciation and amortization	$	68,853		$	15,111		$	3,441		$	1,389
Operating income (loss):
Crude oil logistics	$	34,236		$	—		$	—		$	—
Water services	8,576			—			—			—
Natural gas liquids logistics	30,336			9,735			9,590			865
Retail propane	46,869			9,616			7,362			(2,569		)
Corporate and other	(32,710		)	(4,321		)	(2,115		)	(2,091		)
Total operating income (loss)	$	87,307		$	15,030		$	14,837		$	(3,795	)
Other items not allocated by segment:
Interest income	1,261			765			221			66
Interest expense	(32,994		)	(7,620		)	(2,482		)	(372		)
Loss on early extinguishment of debt	(5,769		)	—			—			—
Other income (expense), net	260			290			103			124
Income tax (provision) benefit	(1,875		)	(601		)	—			1,417
Net income (loss)	$	48,190		$	7,864		$	12,679		$	(2,560	)
Additions to property, plant and equipment, including acquisitions (accrual basis):
Crude oil logistics	$	89,860		$	—		$	—		$	—
Water services	137,116			—			—			—
Natural gas liquids logistics	15,129			50,276			290			15
Retail propane	66,933			150,181			41,152			386
Corporate and other	17,858			—			—			—
Total	$	326,896		$	200,457		$	41,442		$	401

	March 31,		March 31,
	2013		2012
	(in thousands)
Year-End Information:
Total assets:
Crude oil logistics	$	801,030	$	—
Water services	466,462		—
Natural gas liquids logistics	474,141		325,173
Retail propane	513,301		417,639
Corporate	36,413		6,707
Total	$	2,291,347	$	749,519
Long-lived assets, net of depreciation and amortization, including goodwill and intangibles:
Crude oil logistics	$	356,750	$	—
Water services	453,986		—
Natural gas liquids logistics	238,192		176,419
Retail propane	441,762		366,242
Corporate	31,996		5,468
Total	$	1,522,686	$	548,129

F-50

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

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 had the right to appoint two members to the Board of Directors of our general partner. Subsequent to November 1, 2011, our natural gas liquids logistics segment has sold natural gas liquids to and purchased natural gas liquids from affiliates of SemGroup. These transactions are included within revenues and cost of sales of our natural gas liquids logistics business in our consolidated statements of operations. We also made payments to SemGroup for certain administrative and operational services. These transactions are reported within operating and general and administrative expenses in our consolidated statements of operations.

Certain members of management of High Sierra who joined our management team upon completion of the June 19, 2012 merger with High Sierra own interests in several entities. Subsequent to this business combination with High Sierra, we have purchased products and services from and have sold products and services to these entities. The majority of these transactions relate to crude oil purchases and crude oil transportation services and are reported within cost of sales in our consolidated statements of operations, although approximately $3.1 million of these transactions during the year ended March 31, 2013 represented capital expenditures and were recorded as increases to property, plant and equipment. Product sales to these entities have been recorded within revenues in our consolidated statement of operations. In addition, our retail operations purchased goods and services from certain entities owned by our executive officers and their family members.

These transactions are summarized in the table below for the years ended March 31, 2013 and 2012 (in thousands):

	2013		2012
Product sales to SemGroup	$	32,431	$	29,200
Product purchases from SemGroup	60,425		23,800
Payments to SemGroup for services	256		700
Sales to entities affiliated with High Sierra management	16,828		—
Purchases from entities affiliated with High Sierra management	60,942		—
Purchases from entities affiliated with retail segment management	273		300

In addition to the amounts shown in the table above, we completed two business combinations during the year ended March 31, 2013 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.

Receivables from affiliates at March 31, 2013 and 2012 consist of the following (in thousands):

	2013		2012
Receivables from sales of product to SemGroup	$	—	$	1,878
Receivables from entities affiliated with High Sierra management	22,787		—
Other	96		404
	$	22,883	$	2,282

Payables to related parties at March 31, 2013 and 2012 consist of the following (in thousands):

F-51

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

	2013		2012
Working capital settlement for Osterman combination	$	—	$	4,763
Payables to SemGroup	4,601		4,699
Payables to entities affiliated with High Sierra management	2,299
	$	6,900	$	9,462

As described in Note 1, we completed a merger with High Sierra Energy, LP and High Sierra Energy GP, LLC in June 2012, which involved certain transactions with our general partner. 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.

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 natural gas liquids logistics 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

AND NGL SUPPLY, INC.

Notes to Consolidated Financial Statements - Continued

As of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012

and the Six Months Ended March 31, 2011 and September 30, 2010

	Quarter Ended									Year Ended
	June 30,			September 30,		December 31,		March 31,		March 31,
	2012			2012		2012		2013		2013
	(dollars 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) to parent equity	(24,650		)	10,073		40,176		22,341		47,940
Earnings (loss) per unit, basic and diluted -
Common	$	(0.76	)	$	0.18	$	0.75	$	0.39	$	0.96
Subordinated	$	(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

	Quarter Ended										Year Ended
	June 30,			September 30,			December 31,		March 31,		March 31,
	2011			2011			2011		2012		2012
	(dollars in thousands, except unit and per unit data)
Total revenues	$	190,845		$	210,041		$	470,649	$	438,938	$	1,310,473
Total cost of sales	185,973			201,454			439,790		389,806		1,217,023
Net income (loss)	(6,773		)	(5,395		)	6,090		13,942		7,864
Net income (loss) to parent equity	(6,773		)	(5,395		)	6,090		13,954		7,876
Earnings (loss) per unit, basic and diluted -
Common	$	(0.53	)	$	(0.36	)	$	0.24	$	0.47	$	0.32
Subordinated	$	(0.53	)	$	(0.36	)	$	0.28	$	0.53	$	0.58
Weighted average common units outstanding - basic and diluted	9,883,342			8,864,222			18,699,590		23,263,386		15,169,983
Weighted average subordinated outstanding units - basic and diluted	2,927,149			5,199,346			5,919,346		5,919,346		5,175,384

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)
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)

Exhibit Number	Description
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)
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)
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	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)
4.9	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)
4.10	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)
4.11	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)
4.12	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)

Exhibit Number	Description
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	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)
10.7	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)
10.8	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

Exhibit Number	Description
101.SCH**	XBRL Schema Document
101.CAL**	XBRL Calculation Linkbase Document
101.DEF**	XBRL Definition Linkbase Document
101.LAB**	XBRL Label Linkbase Document
101.PRE**	XBRL 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 as of March 31, 2013 and March 31, 2012, (ii) Consolidated Statements of Operations for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010, (iii) Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010, (iv) Consolidated Statements of Changes in Equity for years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010 and (v) Consolidated Statements of Cash Flows for years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010.

+Management contracts or compensatory plans or arrangements.

EX-12.1

Exhibit 12.1

NGL ENERGY PARTNERS LP AND SUBSIDIARIES AND NGL SUPPLY, INC.

RATIO OF EARNINGS TO FIXED CHARGES

(In thousands, except ratio amounts)

	NGL Energy Partners LP							NGL Supply, Inc.
	Year					Six Months		Six Months
	Ended			Year Ended		Ended		Ended			Year Ended		Year Ended
	March 31,			March 31,		March 31,		September 30,			March 31,		March 31,
	2013			2012		2011		2010			2010		2009
EARNINGS:
Income (loss) from continuing operations before income taxes	$	50,065		$	8,465	$	12,679	$	(3,977	)	$	6,108	$	8,124
Loss (income) from continuing operations before income taxes attributable to noncontrolling interests	(250		)	12				45			6		80
Fixed charges	55,881			9,354		2,761		597			1,149		2,135
Total earnings	$	105,696		$	17,831	15,440		(3,335		)	7,263		10,339
FIXED CHARGES:
Interest expense	$	32,994		$	7,620	$	2,482	$	372		$	668	$	1,621
Loss on early extinguishment of debt	5,769			—		—		—			—		—
Portion of rental expense estimated to relate to interest (1)	17,118			1,734		279		225			481		514
Total fixed charges	$	55,881		$	9,354	$	2,761	$	597		$	1,149	$	2,135
Ratio of earnings to fixed charges	1.89			1.91		5.59		(2		)	6.32		4.84

(1)Represents one-third of the total operating lease rental expense, which is that portion estimated to represent interest.

(2)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
Rocket Supply, Inc.	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
Black Hawk Gathering, LLC	Texas
Pecos Gathering & Marketing, LLC	Texas
Midstream Operations, LLC	Texas
High Sierra Canada Holdings, LLC	Colorado
High Sierra Energy Canada ULC	Alberta
High Sierra Storage, LLC	Colorado
High Sierra Transportation, LLC	Colorado
Third Coast Towing, 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

(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

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our reports dated June 13, 2013, with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of NGL Energy Partners LP and subsidiaries on Form 10-K for the year ended March 31, 2013. We have also issued our report dated June 29, 2011, with respect to the consolidated financial statements of NGL Supply, Inc. for the six month period ended September 30, 2010. We hereby consent to the incorporation by reference of said reports in the Registration Statement of NGL Energy Partners LP on Form S-8 (File No. 333-185068, effective November 20, 2012).

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma

June 13, 2013

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.

Date: June 13, 2013	/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.

Date: June 13, 2013	/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, 2013 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: June 13, 2013	/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, 2013 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: June 13, 2013	/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

Fair Value of Financial Instruments (Details 2) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended		6 Months Ended		12 Months Ended									6 Months Ended	12 Months Ended		6 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply	Mar. 31, 2011 Interest rate swaps	Mar. 31, 2013 Interest rate swaps	Mar. 31, 2012 Interest rate swaps	Mar. 31, 2013 Propane Swaps bbl	Mar. 31, 2012 Propane Swaps bbl	Mar. 31, 2013 Heating oil calls and futures bbl	Mar. 31, 2013 Crude swaps bbl	Mar. 31, 2013 Crude - butane spreads bbl	Mar. 31, 2013 Crude Forwards bbl	Mar. 31, 2013 Butane Forwards bbl	Mar. 31, 2011 Commodity contracts	Mar. 31, 2013 Commodity contracts	Mar. 31, 2012 Commodity contracts	Sep. 30, 2010 Commodity contracts NGL Supply
Derivative contract information
Total Notional Units (Barrels)								(282,000)	(460,000)	8,000	(91,000)	(1,116,000)	(144,000)	1,546,000
Fair Value of Net Assets (Liabilities)		$ (5,746)						$ 3,197	$ (36)	$ 79	$ 153	$ (7,651)	$ 1,033	$ (2,557)
Net cash collateral held		(1,360)
Net fair value of commodity derivatives on consolidated balance sheet		(7,106)
Net gains (losses) derivatives
Unrealized gain (loss)															1,357	(5,275)	(4,384)	(200)
Realized gain															111	899	10,351	426
Total	$ 1,692	$ (4,381)	$ 5,676	$ 226	$ 224	$ (5)	$ (291)

XML

Employee Benefit Plan (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended	12 Months Ended		6 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply, Inc.
Employee Benefit Plan
Contributions to the 401(k) defined contribution plan	$ 0.2	$ 1.9	$ 0.5	$ 0.1

XML

Commitments and Contingencies

12 Months Ended

Mar. 31, 2013

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 consolidated liabilities may change materially as circumstances develop.

In September 2010, Pemex Exploracion y Produccion (“Pemex”) filed a lawsuit in the United States District Court for the Southern District of Texas against a number of defendants, including High Sierra. Pemex alleged that High Sierra and the other defendants purchased condensate from a source that had acquired the condensate illegally from Pemex. We do not believe that High Sierra had knowledge at the time of the purchases of the condensate that such condensate was allegedly sold illegally to High Sierra and others. During March 2013, we settled this litigation for $3.1 million, which we recorded as a liability in the final accounting for our acquisition of High Sierra.

In May 2010, two lawsuits were filed in Kansas and Oklahoma by numerous oil and gas producers (the “Associated Producers”), asserting that they were entitled to enforce lien rights on crude oil purchased by High Sierra and other defendants. These cases were subsequently transferred to the United States Bankruptcy Court for the District of Delaware. During March 2013, we settled this litigation for an insignificant amount.

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 $2.2 million of the amount we charged for services subsequent to our acquisition of Pecos. 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 $2.2 million of unpaid fees charged subsequent to our acquisition of Pecos, pending resolution of the dispute. 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 recently completed an audit of fuel and sales tax payments, and concluded that High Sierra should have collected from customers and remitted to the taxing authority approximately $14.9 million of fuel taxes and sales taxes on certain historical sales. High Sierra had not collected and remitted fuel and sales taxes on these transactions, as High Sierra believed the transactions were exempt from these taxes. We are in the process of gathering information to support High Sierra’s position that the transactions were exempt from the taxes, which we believe could substantially reduce the amount of the tax assessed. If we are unsuccessful in demonstrating that these transactions were exempt, we would be required to remit payment to the taxing authority; however, we expect we would be able to recover these payments from the customers pursuant to the terms of our contracts with the customers. Although the outcome of this matter is not certain at this time, we do not believe the ultimate resolution of this matter will have a material adverse effect on our consolidated financial position or results of operations. We recorded in the acquisition accounting for the merger with High Sierra a liability of $14.9 million, which is the full amount assessed, and a receivable of $14.1 million, which represents the amount we would expect to recover from the customers in the event we are ultimately required to pay the taxes assessed.

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 an asset retirement obligation liability of $1.5 million at March 31, 2013. This liability is related to the wastewater disposal assets and crude oil pipeline injection facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned.

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 non-cancelable operating lease agreements for product storage, office space, vehicles, real estate, and equipment. Future minimum lease payments under contractual commitments as of March 31, 2013 are as follows (in thousands):

Year Ending March 31,
2014	$	55,065
2015	38,283
2016	31,297
2017	29,005
2018	21,520
Thereafter	36,268
Total	$	211,438

Rental expense relating to operating leases was as follows for the periods indicated (in thousands):

Year ended March 31, 2013	$	51,354
Year ended March 31, 2012	5,202
Six months ended March 31, 2011	838
Six months ended September 30, 2010	676

Sales and Purchase Contracts

We have entered into sales and purchase contracts for natural gas liquids (including propane, butane, and ethane) and crude oil to be delivered in future periods. These contracts require that the parties physically settle the transactions with inventory. At March 31, 2013, we had the following such commitments outstanding:

	Volume	Value
	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)	84,159	$	76,386
Natural gas liquids floating-price purchase commitments (gallons)	540,518	604,584
Natural gas liquids fixed-price sale commitments (gallons)	102,071	100,246
Natural gas liquids floating-price sale commitments (gallons)	262,143	339,757
Crude oil fixed-price purchase commitments (barrels)	3,382	303,819
Crude oil fixed-price sale commitments (barrels)	5,642	504,505

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.

Certain of the forward purchase and sale contracts shown in the table above were acquired in the June 2012 merger with High Sierra. We recorded these contracts at their estimated fair values at the merger date, and we are amortizing these assets and liabilities to cost of sales over the remaining terms of the contracts. At March 31, 2013, the unamortized balances included in our consolidated balance sheet were as follows (in thousands):

Current assets	$	3,124
Current liabilities	(586		)
Net assets	$	2,538

The following table summarizes the amortization expense (income) we have recorded, and the amortization expense (income) we expect to record, to cost of sales related to the forward purchase and sale contracts acquired in the merger with High Sierra (in thousands):

	Natural Gas Liquids		Crude Oil
	Logistics Segment		Logistics Segment			Total
Year ended March 31, 2013	$	14,587	$	(1,089	)	$	13,498
Year ending March 31, 2014	2,701		(163		)	2,538
Total expense (income)	$	17,288	$	(1,252	)	$	16,036

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Acquisitions (Details 6) (High Sierra, Pecos, and Third Coast acquistions, USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Pro Forma Results of Operations
Revenues	$ 5,430,449	$ 4,789,040
Income from continuing operations	56,366	15,720
Common units
Pro Forma Results of Operations
Basic earnings (FROM CONTINUING OPERATIONS) (in dollars per unit)	$ 1.00	$ 0.29
Diluted earnings (FROM CONTINUING OPERATIONS) (in dollars per unit)	$ 1.00	$ 0.29
Subordinated units
Pro Forma Results of Operations
Basic earnings (FROM CONTINUING OPERATIONS) (in dollars per unit)	$ 1.00	$ 0.29
Diluted earnings (FROM CONTINUING OPERATIONS) (in dollars per unit)	$ 1.00	$ 0.29
Limited Partners
Pro Forma Results of Operations
Income from continuing operations	$ 53,442	$ 15,704

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Consolidated Statements of Operations (USD $) In Thousands, except Share data, unless otherwise specified	6 Months Ended	12 Months Ended		6 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply, Inc.
REVENUES:
Crude oil logistics		$ 2,316,288
Water services		62,227
Natural gas liquids logistics	549,419	1,604,746	1,111,139	310,075
Retail propane	72,813	430,273	199,334	6,868
Other		4,233
Total Revenues	622,232	4,417,767	1,310,473	316,943
COST OF SALES:
Crude oil logistics		2,244,647
Water services		5,611
Natural gas liquids logistics	536,047	1,530,459	1,086,881	306,159
Retail propane	46,985	258,393	130,142	4,749
Total Cost of Sales	583,032	4,039,110	1,217,023	310,908
OPERATING COSTS AND EXPENSES:
Operating	15,898	169,799	47,300	5,231
General and administrative	5,024	52,698	16,009	3,210
Depreciation and amortization	3,441	68,853	15,111	1,389
Operating Income (Loss)	14,837	87,307	15,030	(3,795)
OTHER INCOME (EXPENSE):
Interest income	221	1,261	765	66
Interest expense	(2,482)	(32,994)	(7,620)	(372)
Loss on early extinguishment of debt		(5,769)
Other, net	103	260	290	124
Income (Loss) Before Income Taxes	12,679	50,065	8,465	(3,977)
INCOME TAX (PROVISION) BENEFIT		(1,875)	(601)	1,417
Net Income (Loss)	12,679	48,190	7,864	2,560
NET INCOME ALLOCATED TO GENERAL PARTNER	(13)	(2,917)	(8)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTEREST		(250)	12	45
NET INCOME (LOSS) ATTRIBUTABLE TO PARENT EQUITY ALLOCATED TO LIMITED PARTNERS	$ 12,666	$ 45,023	$ 7,868	$ (2,515)
BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING:
BASIC AND DILUTED LOSS PER COMMON SHARE (in dollars per share)				$ (128.46)
BASIC AND DILUTED WEIGHTED AVERAGE COMMON SHARES OUTSTANDING (in shares)				19,711

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Earnings per Limited Partner Unit or Common Share

12 Months Ended

Mar. 31, 2013

Earnings per Limited Partner Unit or Common Share

Earnings per Limited Partner Unit or Common Share

Note 3 - Earnings per Limited Partner Unit or Common Share

The earnings per limited partner unit of NGL Energy Partners LP were computed as follows for the periods indicated:

	Year			Year			Six Months
	Ended			Ended			Ended
	March 31,			March 31,			March 31,
	2013			2012			2011
	(U.S. Dollars in thousands, except unit and per unit amounts)
Basic and diluted earnings per common or subordinated unit:
Net income attributable to parent equity	$	47,940		$	7,876		$	12,679
Less - income allocated to general partner (*)	(2,917		)	(8		)	(13		)
Net income attributable to limited partners	$	45,023		$	7,868		$	12,666
Net income allocated to:
Common unitholders	$	39,517		$	4,859		$	12,666
Subordinated unitholders	$	5,506		$	3,009		$	—
Weighted average common units outstanding	41,353,574			15,169,983			10,933,568
Weighted average subordinated units outstanding	5,919,346			5,175,384			—
Earnings per unit - basic and diluted:
Common unitholders	$	0.96		$	0.32		$	1.16
Subordinated unitholders	$	0.93		$	0.58		$	—

(*) The income allocated to the general partner for the year ended March 31, 2013 includes distributions to which it is entitled as the holder of incentive distribution rights (described in Note 11).

The restricted units described in Note 11 were antidilutive for the year ended March 31, 2013.

The loss per share of common stock of NGL Supply was computed as follows for the six months ended September 30, 2010 (in thousands, except share and per share amounts):

Net loss attributable to parent equity	$	(2,515	)
Less - preferred stock dividends	(17		)
Net loss attributable to common shareholders	$	(2,532	)
Weighted average common shares outstanding	19,711
Basic and diluted loss per common share	$	(128.46	)

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Mar. 31, 2013

Summary of 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”). We were formed on September 8, 2010 with a capitalization of $1,000 by our general partner and had no operations or additional capitalizations through September 30, 2010. Accordingly, we are presenting our financial statements for periods subsequent to September 30, 2010. As described above, NGL Supply was deemed to be the acquiring entity in our formation transactions. Therefore, our financial statements for the six months ended September 30, 2010 represent the historical financial statements of NGL Supply. We recorded the assets acquired and liabilities assumed from NGL Supply at their historical net book values.

The accompanying consolidated financial statements include the accounts of the Partnership and its controlled subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

We have made certain reclassifications to the prior period financial statements to conform with classification methods used in fiscal 2013. These reclassifications had no impact on previously-reported amounts of total assets, liabilities, partners’ equity, or net income. In addition, as described in Note 4, certain balances as of March 31, 2012 were adjusted to reflect the final acquisition accounting for certain business combinations.

Estimates

Estimates

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of our assets, liabilities, revenues, expenses and costs. These estimates are based on our knowledge of current events, historical experience, and various other assumptions that we believe to be reasonable under the circumstances.

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 should be 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, 2013 and 2012 (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, 2013 or 2012.

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. Changes in the value of our interest rate swap agreements are recorded in our consolidated statements of operations in interest expense. Contracts that qualify for the normal purchase or sale exemption 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 realized or unrealized, are reported in the consolidated statement 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. Shipping and handling costs associated with product sales are included in operating expenses 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 the 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 in the amount of $5.3 million during the year ended March 31, 2013, $0.8 million during the year ended March 31, 2012, and $0.4 million during each of the six months ended March 31, 2011 and September 30, 2010. We also include in cost of sales the costs paid to the third parties who operate our terminal facilities under operating and maintenance agreements.

Advertising Costs

Advertising Costs

We expense advertising costs as incurred. We recorded advertising expense of $1.1 million for the year ended March 31, 2013, $0.8 million for the year ended March 31, 2012, $0.3 million for the six months ended March 31, 2011, and $0.1 million for the six months ended September 30, 2010.

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.

Interest Income

Interest Income

Interest income consists primarily of fees charged to retail customers for late payment on accounts receivable.

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 during the indicated periods:

	NGL Energy Partners LP						NGL Supply
	Year		Year		Six Months		Six Months
	Ended		Ended		Ended		Ended
	March 31,		March 31,		March 31,		September 30,
	2013		2012		2011		2010
	(in thousands)
Interest paid	$	27,384	$	4,966	$	2,063	$	335
Income taxes paid	$	1,027	$	430	$	—	$	220

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 as of the dates indicated:

	March 31, 2013				March 31, 2012
	Gross		Allowance for		Gross		Allowance for
Segment	Receivable		Doubtful Accounts		Receivable		Doubtful Accounts
	(in thousands)
Crude oil logistics	$	360,721	$	11	$	—	$	—
Water services	9,618		29		—		—
Natural gas liquids logistics	144,267		76		52,640		113
Retail Propane	49,233		1,644		32,182		705
Other	810		—		—		—
	$	564,649	$	1,760	$	84,822	$	818

Changes in the allowance for doubtful accounts are as follows during the periods indicated:

	NGL Energy Partners LP									NGL Supply
	Year			Year			Six Months			Six Months
	Ended			Ended			Ended			Ended
	March 31,			March 31,			March 31,			September 30,
	2013			2012			2011			2010
	(in thousands)
Allowance for doubtful accounts, beginning of period	$	818		$	161		$	—		$	235
Bad debt provision	1,315			1,049			269			3
Write off of uncollectible accounts	(373		)	(392		)	(108		)	(64		)
Allowance for doubtful accounts, end of period	$	1,760		$	818		$	161		$	174

For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented approximately 10% of our consolidated total revenues. For the year ended March 31, 2012, no single customer accounted for more than 10% of our consolidated total revenues. For the six months ended March 31, 2011, we had one customer of our wholesale supply and marketing segment who represented approximately 10% of total consolidated revenues. In the six months ended September 30, 2010, two customers of our natural gas liquids logistics segment accounted for 28% of total consolidated revenues. As of March 31, 2013, one customer of our crude oil logistics segment represented approximately 10% of our consolidated accounts receivable balance. As of March 31, 2012, one customer of our wholesale supply and marketing segment represented approximately 21% of our consolidated accounts receivable balance.

Inventories

Inventories

Our inventories include propane, normal butane, natural gasoline, isobutane, transmix, distillates, appliances, and parts and supplies. 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. We monitor inventory values for potential lower of cost or market adjustments and will record such adjustments at fiscal year-end, or on an interim basis if we believe the decline in market value will not be recovered by year end. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer inventory from our wholesale business to our retail business for sale in the retail markets.

Our inventories as of March 31, 2013 and 2012 consisted of the following:

	2013		2012
	(in thousands)
Crude oil	$	46,156	$	—
Propane	45,428		78,993
Other natural gas liquids	24,090		9,259
Other	11,221		6,252
Total	$	126,895	$	94,504

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 less than its carrying value. In that event, we would recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group. No impairments of property, plant and equipment were recorded for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010.

Intangible Assets

Intangible Assets

Our identifiable intangible assets consist of debt issuance costs and significant contracts and arrangements acquired in business combinations, including lease agreements, customer relationships, covenants not to compete, and trade names. We capitalize acquired intangible assets if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of our intent to do so. 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’ 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.

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, 2013 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 as of 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 step 1 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 step 2 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 the results of these evaluations, we did not record any goodwill impairments during the years ended March 31, 2013 and 2012 or the six months ended March 31, 2011 and September 30, 2010.

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.

Asset Retirement Obligations

Asset Retirement Obligations

We record the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, which is typically at the time the assets are placed into service. After the initial measurement, we recognize changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.

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

As of March 31, 2013, we have three consolidated subsidiaries in which outside parties own interests. Our ownership interests in these subsidiaries range from 60% to 80%. One of these subsidiaries was formed in March 2012, and the other two were acquired in June 2012 and October 2012, respectively. The noncontrolling interest shown in our consolidated statements of operations for the years ended March 31, 2013 and 2012 represents the other owners’ interests in these entities.

The net loss attributable to noncontrolling interest shown in the consolidated statement of operations of NGL Supply for the six months ended September 30, 2010 reflects a 30% interest in a consolidated subsidiary that was owned by unrelated parties at the time. We currently own 100% of this subsidiary.

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Income Taxes (Details) (USD $)	12 Months Ended		6 Months Ended
	Mar. 31, 2013 item	Mar. 31, 2012	Sep. 30, 2010 NGL Supply
Income Taxes
Minimum percentage of qualifying income of non-taxable subsidiaries	90.00%
Number of taxable corporate subsidiaries in United States	2
Number of Canadian subsidiaries	3
Income Taxes
Income tax benefit	$ (1,875,000)	$ (601,000)	$ 1,417,000
U.S. federal statutory rate (as a percent)			35.00%
Uncertain tax positions	$ 0	$ 0

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Acquisitions (Details 9) (USD $)		12 Months Ended											12 Months Ended				12 Months Ended					12 Months Ended																			0 Months Ended	12 Months Ended
	Mar. 31, 2013	Mar. 31, 2013 Vehicles Minimum	Mar. 31, 2012 Vehicles Minimum	Mar. 31, 2013 Vehicles Maximum	Mar. 31, 2012 Vehicles Maximum	Mar. 31, 2012 Buildings Minimum	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Mar. 31, 2012 Pacer	Mar. 31, 2013 Pacer	Jan. 03, 2012 Pacer item	Mar. 31, 2013 Pacer Trade names	Mar. 31, 2013 Pacer Customer relationships	Mar. 31, 2013 Pacer Non-compete agreements	Mar. 31, 2013 Pacer Land	Mar. 31, 2013 Pacer Tanks and other retail propane equipment	Mar. 31, 2013 Pacer Tanks and other retail propane equipment Minimum	Mar. 31, 2013 Pacer Tanks and other retail propane equipment Maximum	Mar. 31, 2013 Pacer Vehicles	Mar. 31, 2013 Pacer Buildings	Mar. 31, 2013 Pacer Other	Mar. 31, 2013 Pacer Other Minimum	Mar. 31, 2013 Pacer Other Maximum	Mar. 31, 2012 Pacer Estimated Allocation as of March 31, 2012	Mar. 31, 2012 Pacer Estimated Allocation as of March 31, 2012 Trade names	Mar. 31, 2012 Pacer Estimated Allocation as of March 31, 2012 Customer relationships	Mar. 31, 2012 Pacer Estimated Allocation as of March 31, 2012 Land	Mar. 31, 2012 Pacer Estimated Allocation as of March 31, 2012 Tanks and other retail propane equipment	Mar. 31, 2012 Pacer Estimated Allocation as of March 31, 2012 Vehicles	Mar. 31, 2012 Pacer Estimated Allocation as of March 31, 2012 Buildings	Mar. 31, 2012 Pacer Estimated Allocation as of March 31, 2012 Other	Mar. 31, 2013 Pacer Revision	Mar. 31, 2013 Pacer Revision Trade names	Mar. 31, 2013 Pacer Revision Customer relationships	Mar. 31, 2013 Pacer Revision Non-compete agreements	Mar. 31, 2013 Pacer Revision Land	Mar. 31, 2013 Pacer Revision Tanks and other retail propane equipment	Mar. 31, 2013 Pacer Revision Vehicles	Mar. 31, 2013 Pacer Revision Buildings	Mar. 31, 2013 Pacer Revision Other	Jan. 03, 2012 Pacer Common units	Mar. 31, 2012 Pacer Common units
Acquisitions
Cash paid to acquire ownership interests	$ 14,000,000										$ 32,213,000
Number of common units issued to acquire ownership interests (in shares)							24,250,258	14,432,031																																	1,500,000	1,500,000
General and administrative expense									710,000
Equity issuance costs									64,000
Number of owned or leased customer service centers											17
Consideration paid for acquisition
Cash	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										4,389,000														4,389,000
Inventory										965,000														965,000
Other current assets										43,000														43,000
Property, plant and equipment															1,967,000	12,793,000			3,090,000	409,000	59,000						1,400,000	11,200,000	5,000,000	2,300,000	200,000					567,000	1,593,000	(1,910,000)	(1,891,000)	(141,000)
Useful life of property, plant and equipment		5 years	5 years	10 years	10 years	5 years											15 years	20 years	5 years	30 years		3 years	5 years
Intangible assets												2,410,000	23,560,000	1,520,000											1,000,000	21,980,000							1,410,000	1,580,000	1,520,000
Useful life of intangible assets													15 years
Goodwill										15,782,000														18,460,000								(2,678,000)
Assumed liabilities										(4,399,000)														(4,349,000)								(50,000)
Consideration paid, net of cash acquired										$ 62,588,000														$ 62,588,000

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Equity

12 Months Ended

Mar. 31, 2013

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.

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. Also, if we have earned and paid at least 150% of the minimum quarterly distribution on each outstanding common unit and subordinated unit, the corresponding distribution on the general partner interest and the related distribution on the incentive distribution rights for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. 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 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.

Conversion of Common Units to Subordinated Units

In addition, on May 11, 2011 we converted 5,919,346 of our common units to subordinated units. The unaudited pro forma impact of this unit conversion on our limited partner equity as of March 31, 2011 and earnings per unit information for the six months ended March 31, 2011, assuming the conversion occurred on October 1, 2010, is as follows:

	Historical			Unaudited Pro Forma
	Units	Amount		Units	Amount
	(U.S. Dollars in thousands, except per unit amounts)
Limited Partner Equity —
Common units	10,933,568	$	47,225	5,014,222	$	21,658
Subordinated units	—	—		5,919,346	25,567
	10,933,568	$	47,225	10,933,568	$	47,225
Earnings per unit, basic and diluted —
Common units		$	1.16		$	1.16
Subordinated units		$	—		$	1.16

Initial Public Offering

On May 11, 2011, we sold a total of 4,025,000 common units in our initial public offering (IPO) at $21.00 per unit. Our proceeds from the sale of 3,850,000 common units of $71.9 million, net of offering costs of approximately $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) were used to purchase 175,000 of the common units outstanding prior to our initial public offering.

Upon the completion of our IPO, our limited partner equity consisted of 8,864,222 common units and 5,919,346 subordinated units.

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
Water services combination	516,978
Pecos combination	1,834,414
Third Coast combination	344,680
Total - year ended March 31, 2013	24,250,258

In connection with the completion of these transactions, we amended our Registration Rights Agreement, which provides for certain registration rights for certain holders of our common units.

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.”  Our minimum quarterly distribution is $0.3375 per unit ($1.35 per unit on an annual basis).

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 incentive distribution rights and there are no arrearages on common units.

							Marginal Percentage Interest In
	Total Quarterly						Distributions
	Distribution per Unit						Unitholders		General Partner
Minimum quarterly distribution					$	0.3375	99.9	%	0.1	%
First target distribution	above	$	0.3375	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	$	0.50625	76.9	%	23.1	%
Thereafter	above	$	0.50625				51.9	%	48.1	%

There were no distributions during the six months ended March 31, 2011. Subsequent to March 31, 2011 and prior to our initial public offering, a distribution of $3.85 million ($0.35 per common unit) was declared for the unitholders as of March 31, 2011. The distribution was paid on May 5, 2011.

The following table summarizes the distributions declared subsequent to our initial public offering:

			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

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	—

Equity-Based Incentive Compensation

Our general partner has adopted the NGL Energy Partners LP 2011 Long-Term Incentive Plan for the employees and directors of our general partner and its affiliates who perform services for us. The Long-Term Incentive Plan allows for the issuance of restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards, as discussed below. The number of common units that may be delivered pursuant to awards under the plan 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 will not be considered to be delivered under the Long-Term Incentive Plan. 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 will again be available for new awards under the Long-Term Incentive Plan. Common units to be delivered pursuant to awards under the Long-Term Incentive Plan may be newly issued common units, common units acquired by us in the open market, common units acquired by us from any other person, or any combination of the foregoing. If we issue new common units with respect to an award under the Long-Term Incentive Plan, the total number of common units outstanding will increase.

During the year ended March 31, 2013, the Board of Directors of our general partner 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 year ended March 31, 2013:

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

The scheduled vesting of the awards is summarized below:

Vesting Date	Number of Awards
July 1, 2013	377,300
July 1, 2014	360,800
July 1, 2015	272,300
July 1, 2016	263,500
July 1, 2017	169,000
July 1, 2018	2,000
Total unvested units at March 31, 2013	1,444,900

For the 218,500 awards that vested on January 1, 2013, we issued 156,802 common units to the recipients and we recorded an increase to equity of $3.7 million. We withheld 61,698 common units, in return for which we paid $1.4 million of withholding taxes on behalf of the recipients.

The weighted-average fair value of the awards was $23.01 at March 31, 2013, which was calculated as the closing price of the common units on March 31, 2013, 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.

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. We recorded $10.1 million of expense related to these awards during the year ended March 31, 2013. We account for these as liability awards; the balance in accrued expenses and other payables on our consolidated balance sheet at March 31, 2013 includes $5.0 million related to these awards. We estimate that the expense we will record on the unvested awards as of March 31, 2013 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of approximately 71,000 units. For purposes of this calculation, we have used the closing price of the common units on March 31, 2013.

Year ending March 31,
2014	$	12,168
2015	7,516
2016	6,559
2017	4,613
2018	1,040
2019	15
Total	$	31,911

As of March 31, 2013, 3,760,539 units remain available for issuance under the Long-Term Incentive Plan.

Equity of NGL Supply

As of March 31, 2010, NGL Supply’s authorized capital consisted of 1,000 shares of preferred stock (discussed below) and 100,000 shares of Class A common stock, $10 par value per share. During the six months ended September 30, 2010, 650 outstanding stock options were exercised for a total consideration of $1.4 million, which was paid in October 2010.

The changes in net equity of NGL Supply for the period of September 30, 2010 to October 14, 2010 were as follows (in thousands):

Net equity at September 30, 2010	$	36,811
Collection of stock option receivable	1,430
Net tax obligations of NGL Supply not assumed by the Partnership	3,120
Distribution to previous shareholders	(40,000		)
Other	(109		)
Net carrying value of assets and liabilities contributed by NGL Supply	$	1,252

Redeemable Preferred Stock

NGL Supply had 1,000 shares of its Series A Preferred Stock outstanding at March 31, 2010. The preferred shares were redeemable at $3,000 per share plus dividends in arrears at the option of the shareholder with 30 days notice. These preferred shares have been separately classified in the consolidated statement of changes in equity at their purchased amount which is also the redeemable cost at March 31, 2010. On May 17, 2010, NGL Supply redeemed all of the preferred stock at the stated value plus accrued dividends for approximately $3.0 million.

Common Stock Dividends

On June 30, 2010, NGL Supply paid a dividend to the owners of its common stock of $7.0 million.

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Acquisitions (Details) (USD $)	3 Months Ended								6 Months Ended	12 Months Ended								0 Months Ended	1 Months Ended	12 Months Ended				1 Months Ended			1 Months Ended				1 Months Ended			1 Months Ended			1 Months Ended			1 Months Ended				12 Months Ended				0 Months Ended	1 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 INFORMATION TECHNOLOGY Minimum	Mar. 31, 2012 INFORMATION TECHNOLOGY Minimum	Mar. 31, 2013 INFORMATION TECHNOLOGY Maximum	Mar. 31, 2012 INFORMATION TECHNOLOGY Maximum	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Jun. 19, 2012 General partner	Jun. 30, 2012 General partner Common units	Mar. 31, 2013 High Sierra	Jun. 19, 2012 High Sierra	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 contracts	Jun. 30, 2012 High Sierra Lease contracts Minimum	Jun. 30, 2012 High Sierra Lease contracts Maximum	Jun. 19, 2012 High Sierra Land	Jun. 19, 2012 High Sierra Transportation vehicles and equipment	Jun. 30, 2012 High Sierra Transportation vehicles and equipment Minimum	Jun. 30, 2012 High Sierra Transportation vehicles and equipment Maximum	Jun. 19, 2012 High Sierra Facilities and equipment	Jun. 30, 2012 High Sierra Facilities and equipment Minimum	Jun. 30, 2012 High Sierra Facilities and equipment Maximum	Jun. 19, 2012 High Sierra Buildings and improvements	Jun. 30, 2012 High Sierra Buildings and improvements Minimum	Jun. 30, 2012 High Sierra Buildings and improvements Maximum	Jun. 19, 2012 High Sierra EQUIPMENT AND SOFTWARE	Jun. 30, 2012 High Sierra EQUIPMENT AND SOFTWARE Minimum	Jun. 30, 2012 High Sierra EQUIPMENT AND SOFTWARE Maximum	Jun. 30, 2012 High Sierra INFORMATION TECHNOLOGY	Jun. 19, 2012 High Sierra Construction in progress	Mar. 31, 2013 High Sierra Crude oil logistics	Mar. 31, 2013 High Sierra Natural gas liquids logistics	Mar. 31, 2013 High Sierra Water services	Mar. 31, 2013 High Sierra Other	Jun. 19, 2012 High Sierra Energy, LP	Jun. 30, 2012 High Sierra Energy, LP Common units	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, net of cash acquired									$ 17,400,000	$ 490,402,000	$ 297,401,000
Cash acquired																																																5,000,000
Number of common units issued to acquire ownership interests (in shares)																24,250,258	14,432,031																																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	5,000,000									5,000,000																																						97,400,000
Cash paid to acquire ownership interests	14,000,000									14,000,000										239,251																												91,800,000			50,000,000	50,000,000
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
Operating income									14,837,000	87,307,000	15,030,000									46,600,000
Revenues	1,617,613,000	1,338,208,000	1,135,510,000	326,436,000	438,938,000	470,649,000	210,041,000	190,845,000	622,232,000	4,417,767,000	1,310,473,000									3,079,172,000																								2,316,288,000	696,424,000	62,227,000	4,233,000
Cost of sales	1,481,890,000	1,204,545,000	1,053,690,000	298,985,000	389,806,000	439,790,000	201,454,000	185,973,000	583,032,000	4,039,110,000	1,217,023,000									2,913,888,000																								2,244,647,000	663,630,000	5,611,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable																					395,311,000
Inventory																					43,575,000
Receivables from affiliates																					7,724,000
Derivative assets																					10,646,000
Forward purchase and sale contracts																					34,717,000
Other current assets																					11,131,000
Property, plant and equipment																													5,910,000	20,968,000			103,574,000			9,691,000			4,099,000				11,213,000
Useful life of property, plant and equipment												3 years	3 years	5 years	5 years																5 years	10 years		2 years	30 years		5 years	30 years		3 years	5 years	5 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																					220,884,000
Assumed liabilities:
Accounts payable																					(417,369,000)
Accrued expenses and other current liabilities																					(35,611,000)
Payables to affiliates																					(9,014,000)
Advance payments received from customers																					(1,237,000)
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)
Consideration paid, net of cash acquired																					654,045,000
Estimated uncollectable accounts for fair value of accounts receivable																				$ 600,000

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Transactions with Affiliates (Details) (USD $)	12 Months Ended		0 Months Ended		12 Months Ended					12 Months Ended	0 Months Ended		12 Months Ended
	Mar. 31, 2013 item	Mar. 31, 2012	Jun. 19, 2012 High Sierra Energy, LP	Mar. 31, 2013 High Sierra	Mar. 31, 2013 SemGroup item	Mar. 31, 2012 SemGroup	Mar. 31, 2013 Other	Mar. 31, 2012 Other	Mar. 31, 2012 Osterman	Mar. 31, 2013 High Sierra Management	Jun. 19, 2012 General Partner	Jun. 19, 2012 General Partner High Sierra Energy, LP	Mar. 31, 2013 Retail segment management	Mar. 31, 2012 Retail segment management
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										$ 3,100,000
Sales to related party					32,431,000	29,200,000				16,828,000
Purchase from related parties					60,425,000	23,800,000				60,942,000			273,000	300,000
Payments to SemGroup for services					256,000	700,000
Number of business combination transactions	2
Cash paid	14,000,000		91,800,000	239,251								50,000,000
Liabilities assumed in the form of non-compete agreements	5,000,000		97,400,000
Receivables from affiliates	22,883,000	2,282,000				1,878,000	96,000	404,000		22,787,000
Payables to related parties	6,900,000	9,462,000			4,601,000	4,699,000			4,763,000	2,299,000
Cash acquired			5,000,000
Common units issued			18,018,468								2,685,042
Amount paid											$ 50,000,000

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Acquisitions (Details 10) (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	Mar. 31, 2013 Vehicles Minimum	Mar. 31, 2012 Vehicles Minimum	Mar. 31, 2013 Vehicles Maximum	Mar. 31, 2012 Vehicles Maximum	Mar. 31, 2012 Buildings Minimum	Mar. 31, 2013 North American	Mar. 31, 2012 North American	Feb. 03, 2012 North American	Mar. 31, 2012 North American Estimated Allocation	Mar. 31, 2013 North American Revision	Mar. 31, 2013 North American Customer relationships	Mar. 31, 2012 North American Customer relationships Estimated Allocation	Mar. 31, 2013 North American Customer relationships Revision	Mar. 31, 2013 North American Trade names	Mar. 31, 2012 North American Trade names Estimated Allocation	Mar. 31, 2013 North American Trade names Revision	Mar. 31, 2013 North American Non-compete agreements	Mar. 31, 2013 North American Non-compete agreements Revision	Mar. 31, 2013 North American Land	Mar. 31, 2012 North American Land Estimated Allocation	Mar. 31, 2013 North American Land Revision	Mar. 31, 2013 North American Tanks and other retail propane equipment	Mar. 31, 2012 North American Tanks and other retail propane equipment Estimated Allocation	Mar. 31, 2013 North American Tanks and other retail propane equipment Revision	Mar. 31, 2013 North American Tanks and other retail propane equipment Minimum	Mar. 31, 2013 North American Tanks and other retail propane equipment Maximum	Mar. 31, 2013 North American Terminal assets	Mar. 31, 2013 North American Terminal assets Revision	Mar. 31, 2013 North American Terminal assets Minimum	Mar. 31, 2013 North American Terminal assets Maximum	Mar. 31, 2013 North American Vehicles	Mar. 31, 2012 North American Vehicles Estimated Allocation	Mar. 31, 2013 North American Vehicles Revision	Mar. 31, 2013 North American Vehicles Minimum	Mar. 31, 2013 North American Vehicles Maximum	Mar. 31, 2013 North American Buildings	Mar. 31, 2012 North American Buildings Estimated Allocation	Mar. 31, 2013 North American Buildings Revision	Mar. 31, 2013 North American Other equipment	Mar. 31, 2012 North American Other equipment Estimated Allocation	Mar. 31, 2013 North American Other equipment Revision	Mar. 31, 2013 North American Other equipment Minimum	Mar. 31, 2013 North American Other equipment 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							10,338,000			10,338,000
Inventory							3,437,000			3,437,000
Other current assets							282,000			282,000
Property, plant and equipment																				2,251,000	2,600,000	(349,000)	24,790,000	27,100,000	(2,310,000)			1,044,000	1,044,000			5,819,000	9,000,000	(3,181,000)			2,386,000	2,200,000	186,000	634,000	500,000	134,000
Useful life of property, plant and equipment		5 years	5 years	10 years	10 years	5 years																				15 years	20 years			15 years	20 years				5 years	15 years	30 years						3 years	5 years
Intangible assets												12,600,000	9,800,000	2,800,000	2,700,000	1,000,000	1,700,000	700,000	700,000
Useful life of intangible assets												10 years			10 years			3 years
Goodwill							13,978,000			14,702,000	(724,000)
Assumed liabilities							(11,129,000)			(11,129,000)
Consideration paid, net of cash acquired							$ 69,830,000			$ 69,830,000

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Nature of Operations and Organization (Details) (USD $)	6 Months Ended	12 Months Ended		0 Months Ended							0 Months Ended		1 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	May 11, 2011 Common units	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Mar. 31, 2011 Common units	Mar. 31, 2013 Subordinated units	Mar. 31, 2012 Subordinated units	May 11, 2011 Subordinated units	May 11, 2011 Repayment of debt Common units	May 11, 2011 Purchase of common units Common units	Oct. 31, 2010 IEP Parties	Oct. 31, 2010 NGL Supply	Oct. 31, 2010 Hicksgas LLC	Oct. 31, 2010 Gifford	Oct. 31, 2010 General partner	Oct. 31, 2010 Limited partner IEP Parties	Oct. 31, 2010 Limited partner NGL Supply	Oct. 31, 2010 Limited partner Hicksgas LLC	Oct. 31, 2010 Limited partner Gifford
Nature of Operations and Organization
Cash capital contribution	$ 11,040,000	$ 913,000	$ 440,000														$ 58,800	$ 11,000,000
General partner interest (as a percent)		0.10%	0.10%														0.10%
Ownership interest in general partner (as a percent)													32.53%
Limited partner interest (as a percent)		99.90%	99.90%															18.67%	43.27%	37.96%
Percentage of membership interest contributed as capital																			100.00%	100.00%	100.00%
Cash distribution	40,000,000																		40,000,000	1,600,000	15,500,000
Debt assumed in exchange of membership interest																			27,900,000	6,500,000
Percentage of membership interest of third parties contributed to subsidiary														100.00%	100.00%	100.00%
Initial Public Offering
Number of units sold in initial public offering				4,025,000							3,850,000	175,000
Price per unit of units sold in initial public offering (in dollars per share)				$ 21.00
Proceeds from sale of common units, net of offering costs		(642,000)	74,759,000								71,900,000	3,400,000
Offerings costs											$ 9,000,000
Number of units repurchased				175,000
Units outstanding after completion of IPO	10,933,568			8,864,222	47,703,313	23,296,253	10,933,568	5,919,346	5,919,346	5,919,346

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Acquisitions (Tables)

12 Months Ended

Mar. 31, 2013

Pro Forma Results of Operations

Schedule of unaudited pro forma consolidated results of operations

The following unaudited pro forma consolidated data below are presented as if the High Sierra, Pecos, and Third Coast acquisitions had been completed on April 1, 2011 (in thousands, except per unit amounts). The pro forma earnings per unit are based on the common and subordinated units outstanding as of March 31, 2013.

	Years Ended March 31,
	2013		2012
Revenues	$	5,430,449	$	4,789,040
Income from continuing operations	56,366		15,720
Limited partners’ interest in income from continuing operations	53,442		15,704
Basic and diluted earnings from continuing operations per common unit	1.00		0.29
Basic and diluted earnings from continuing operations per subordinated unit	1.00		0.29

High Sierra

Pro Forma Results of Operations

Summary of the revenues and cost of sales included in consolidated statement of operations

The following table summarizes the revenues and cost of sales contributed by High Sierra’s operations and the operations of the subsequent acquisitions of crude oil logistics and water services businesses (in thousands):

	Revenues		Cost of Sales
Crude oil logistics	$	2,316,288	$	2,244,647
Natural gas liquids logistics	696,424		663,630
Water services	62,227		5,611
Other	4,233		—
Total	$	3,079,172	$	2,913,888

Schedule of the fair value 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	$	395,311
Inventory	43,575
Receivables from affiliates	7,724
Derivative assets	10,646
Forward purchase and sale contracts	34,717
Other current assets	11,131
Property, plant and equipment:
Land	5,910
Transportation vehicles and equipment (5 - 10 years)	20,968
Facilities and equipment (2 - 30 years)	103,574
Buildings and improvements (5 - 30 years)	9,691
Information technology equipment and software (3 - 5 years)	4,099
Construction in progress	11,213
Intangible assets:
Customer relationships (5 - 17 years)	245,000
Lease contracts (1 - 10 years)	12,400
Trade names (indefinite)	13,000
Goodwill	220,884
Assumed liabilities:
Accounts payable	(417,369		)
Accrued expenses and other current liabilities	(35,611		)
Payables to affiliates	(9,014		)
Advance payments received from customers	(1,237		)
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

Cash paid, net of cash acquired	$	239,251
Value of common units issued, net of issuance costs	414,794
Total consideration paid	$	654,045

Pecos

Pro Forma Results of Operations

Schedule of the fair value of the assets acquired and liabilities assumed

We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Accounts receivable	$	73,704
Inventory	1,903
Other current assets	1,425
Property, plant and equipment:
Vehicles and related equipment (5 - 10 years)	19,193
Other	2,562
Customer relationships (5 years)	8,000
Trade names (indefinite life)	1,000
Goodwill	86,661
Accounts payable and accrued liabilities	(51,827		)
Long-term debt	(10,234		)
Total consideration paid	$	132,387

Schedule of consideration paid

The consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired and cash received pursuant to Call Agreement	$	87,444
Value of common units issued pursuant to Call Agreement	44,943
Total consideration paid	$	132,387

Third Coast

Pro Forma Results of Operations

Schedule of the fair value of the assets acquired and liabilities assumed

We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Accounts receivable	$	2,248
Other current assets	140
Property, plant and equipment:
Barges and tow boats (20 years)	12,883
Other (3 - 5 years)	30
Customer relationships (5 years)	4,000
Trade names (indefinite life)	500
Goodwill	22,551
Other noncurrent assets	2,733
Assumed liabilities	(2,202		)
Consideration paid	$	42,883

Schedule of consideration paid

The consideration paid consists of the following (in thousands):

Cash paid, net of cash received pursuant to call agreement	$	35,000
Value of common units issued pursuant to call agreement	7,883
Total consideration paid	$	42,883

Other Crude Oil Logistics and Water Services Business Combinations

Pro Forma Results of Operations

Schedule of the fair value of the assets acquired and liabilities assumed

We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Accounts receivable	$	2,660
Inventory	191
Other current assets	738
Property, plant and equipment:
Disposal wells and related equipment (3 - 30 years)	13,322
Other (5 - 30 years)	5,671
Customer relationships (5 - 15 years)	6,800
Non-compete agreements (3 - 5 years)	510
Trade names (indefinite life)	500
Goodwill	43,822
Current liabilities	(5,400		)
Notes payable	(1,340		)
Other noncurrent liabilities	(156		)
Noncontrolling interest	(2,333		)
Consideration paid	$	64,985

Schedule of consideration paid

The 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 combinations

Pro Forma Results of Operations

Schedule of the fair value of the assets acquired and liabilities assumed

Our estimates of the fair value of the assets acquired and liabilities assumed in these six combinations are as follows (in thousands):

Accounts receivable	$	8,715
Inventory	5,155
Other current assets	1,228
Property, plant and equipment:
Land	1,945
Tanks and other retail propane equipment (5-20 years)	28,763
Vehicles (5 years)	11,344
Buildings (30 years)	7,052
Other equipment	1,201
Intangible assets:
Customer relationships (10-15 years)	16,890
Tradenames (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

Pro Forma Results of Operations

Schedule of the fair value 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):

				Estimated
				Allocation
				as of
	Final			March 31,
	Allocation			2012			Revision
Accounts receivable	$	9,350		$	5,584		$	3,766
Inventory	3,869			3,898			(29		)
Other current assets	215			212			3
Property, plant and equipment:
Land	2,349			4,500			(2,151		)
Tanks and other retail propane equipment (15-20 years)	47,160			55,000			(7,840		)
Vehicles (5-20 years)	7,699			12,000			(4,301		)
Buildings (30 years)	3,829			6,500			(2,671		)
Other equipment (3-5 years)	732			1,520			(788		)
Intangible assets:
Customer relationships (20 years)	54,500			62,479			(7,979		)
Tradenames (indefinite life)	8,500			5,000			3,500
Non-compete agreements (7 years)	700			—			700
Goodwill	52,267			30,405			21,862
Assumed liabilities	(9,654		)	(5,431		)	(4,223		)
Consideration paid, net of cash acquired	$	181,516		$	181,667		$	(151	)

Schedule of consideration paid

Consideration paid consists of the following (in thousands):

			Estimated
			Allocation
			as of
	Final		March 31,
	Allocation		2012		Revision
Cash paid at closing, net of cash acquired	$	94,873	$	96,000	$	(1,127	)
Fair value of common units issued at closing	81,880		81,880		—
Working capital payment (paid in November 2012)	4,763		3,787		976
Consideration paid, net of cash acquired	$	181,516	$	181,667	$	(151	)

SemStream

Pro Forma Results of Operations

Schedule of the fair value 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):

Propane and other natural gas liquids inventory	$	104,226
Derivative financial instruments	3,578
Assets held for sale	3,000
Prepaids and other current assets	9,833
Property, plant and equipment:
Land	3,470
Tanks and terminals (20-30 years)	41,434
Vehicles and rail cars (5 years)	470
Other (5 years)	3,326
Investment in capital lease	3,112
Amortizable intangible assets:
Customer relationships (8-15 years)	31,950
Rail car leases (1-4 years)	1,008
Goodwill	74,924
Assumed current liabilities	(4,591		)
Consideration paid	$	275,740

Pacer

Pro Forma Results of Operations

Schedule of the fair value 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):

				Estimated
				Allocation
				as of
	Final			March 31,
	Allocation			2012			Revision
Accounts receivable	$	4,389		$	4,389		$	—
Inventory	965			965			—
Other current assets	43			43			—
Property, plant and equipment:
Land	1,967			1,400			567
Tanks and other retail propane equipment (15 - 20 years)	12,793			11,200			1,593
Vehicles (5 years)	3,090			5,000			(1,910		)
Buildings (30 years)	409			2,300			(1,891		)
Other equipment (3-5 years)	59			200			(141		)
Intangible assets:
Customer relationships (15 years)	23,560			21,980			1,580
Tradenames (indefinite life)	2,410			1,000			1,410
Noncompete agreements	1,520			—			1,520
Goodwill	15,782			18,460			(2,678		)
Assumed Liabilities	(4,399		)	(4,349		)	(50		)
Consideration paid	$	62,588		$	62,588		$	—

Schedule of consideration paid

The consideration paid in the Pacer combination consisted of the following (in thousands):

Cash	$	32,213
Common units	30,375
	$	62,588

North American

Pro Forma Results of Operations

Schedule of the fair value of the assets acquired and liabilities assumed

The following table presents the final allocation of the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (in thousands):

				Estimated
				Allocation
				as of
	Final			March 31,
	Allocation			2012			Revision
Accounts receivable	$	10,338		$	10,338		$	—
Inventory	3,437			3,437			—
Other current assets	282			282			—
Property, plant and equipment:
Land	2,251			2,600			(349		)
Tanks and other retail propane equipment (15-20 years)	24,790			27,100			(2,310		)
Terminal assets (15-20 years)	1,044			—			1,044
Vehicles (5-15 years)	5,819			9,000			(3,181		)
Buildings (30 years)	2,386			2,200			186
Other equipment (3-5 years)	634			500			134
Intangible assets:
Customer relationships (10 years)	12,600			9,800			2,800
Tradenames (10 years)	2,700			1,000			1,700
Noncompete agreements (3 years)	700			—			700
Goodwill	13,978			14,702			(724		)
Assumed liabilities	(11,129		)	(11,129		)	—
Consideration paid	$	69,830		$	69,830		$	—

Hicksgas LLC and Gifford

Pro Forma Results of Operations

Schedule of the fair value 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 estimated fair values, in the acquisition of the retail propane businesses of Hicksgas LLC and Gifford described above (in thousands):

Accounts receivable	$	5,669
Inventory	6,182
Prepaid expenses and other current assets	2,600
	14,451
Property, plant, and equipment:
Land	2,666
Tanks and other retail propane equipment (15 year life)	23,016
Vehicles (5 year life)	6,599
Buildings (30 year life)	7,053
Office equipment (5 year life)	523
Amortizable intangible assets:
Customer relationships (15 year life)	2,170
Non-compete agreements (5 year life)	550
Tradenames (indefinite-life intangible asset)	830
Goodwill (retail propane segment)	3,716
Total assets acquired	61,574
Accounts payable	1,837
Customer advances and deposits	12,089
Accrued and other current liabilities	2,152
	16,078
Long-term debt	5,768
Other long-term liabilities	274
Total liabilities assumed	22,120
Net assets acquired	$	39,454

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Earnings per Limited Partner Unit or Common Share (Tables)

12 Months Ended

Mar. 31, 2013

Earnings per limited partner unit or common share

Schedule of earnings per common or subordinated unit

	Year			Year			Six Months
	Ended			Ended			Ended
	March 31,			March 31,			March 31,
	2013			2012			2011
	(U.S. Dollars in thousands, except unit and per unit amounts)
Basic and diluted earnings per common or subordinated unit:
Net income attributable to parent equity	$	47,940		$	7,876		$	12,679
Less - income allocated to general partner (*)	(2,917		)	(8		)	(13		)
Net income attributable to limited partners	$	45,023		$	7,868		$	12,666
Net income allocated to:
Common unitholders	$	39,517		$	4,859		$	12,666
Subordinated unitholders	$	5,506		$	3,009		$	—
Weighted average common units outstanding	41,353,574			15,169,983			10,933,568
Weighted average subordinated units outstanding	5,919,346			5,175,384			—
Earnings per unit - basic and diluted:
Common unitholders	$	0.96		$	0.32		$	1.16
Subordinated unitholders	$	0.93		$	0.58		$	—

(*) The income allocated to the general partner for the year ended March 31, 2013 includes distributions to which it is entitled as the holder of incentive distribution rights (described in Note 11).

NGL Supply

Earnings per limited partner unit or common share

Schedule of earnings per common or subordinated unit

The loss per share of common stock of NGL Supply was computed as follows for the six months ended September 30, 2010 (in thousands, except share and per share amounts):

Net loss attributable to parent equity	$	(2,515	)
Less - preferred stock dividends	(17		)
Net loss attributable to common shareholders	$	(2,532	)
Weighted average common shares outstanding	19,711
Basic and diluted loss per common share	$	(128.46	)

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Earnings per Limited Partner Unit or Common Share (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								6 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012
Basic and diluted earnings per common or subordinated unit:
Net income attributable to parent equity	$ 22,341	$ 40,176	$ 10,073	$ (24,650)	$ 13,954	$ 6,090	$ (5,395)	$ (6,773)	$ 12,679	$ 47,940	$ 7,876
Less - income allocated to general partner									(13)	(2,917)	(8)
NET INCOME (LOSS) ATTRIBUTABLE TO PARENT EQUITY ALLOCATED TO LIMITED PARTNERS									12,666	45,023	7,868
Common unitholders
Basic and diluted earnings per common or subordinated unit:
NET INCOME (LOSS) ATTRIBUTABLE TO PARENT EQUITY ALLOCATED TO LIMITED PARTNERS									12,666	39,517	4,859
Weighted average units outstanding (in shares)	47,665,015	46,364,381	44,831,836	26,529,133	23,263,386	18,699,590	8,864,222	9,883,342	10,933,568	41,353,574	15,169,983
Earnings per unit - basic and diluted:
Earnings per unit - basic and diluted (in dollars per share)									$ 1.16	$ 0.96	$ 0.32
Subordinated unitholders
Basic and diluted earnings per common or subordinated unit:
NET INCOME (LOSS) ATTRIBUTABLE TO PARENT EQUITY ALLOCATED TO LIMITED PARTNERS										$ 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	5,199,346	2,927,149		5,919,346	5,175,384
Earnings per unit - basic and diluted:
Earnings per unit - basic and diluted (in dollars per share)										$ 0.93	$ 0.58

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Mar. 31, 2013

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, 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	(3,503		)	3,503
Cash collateral provided or held	(1,760		)	400
Commodity contracts reported on consolidated balance sheet	$	5,595		$	(12,701	)

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2012:

	Derivative		Derivative
	Assets		Liabilities
	(in thousands)
Level 1 measurements	$	—	$	—
Level 2 measurements	—		(36		)
	—		(36		)
Netting of counterparty contracts	—		—
Cash collateral provided or held	—		—
Commodity contracts reported on consolidated balance sheet	$	—	$	(36	)

Schedule of location of commodity derivative assets (liabilities) reported on the consolidated balance sheets

	March 31,			March 31,
	2013			2012
	(in thousands)
Prepaid expenses and other current assets	$	5,551		$	—
Other noncurrent assets	44			—
Accrued expenses and other payables	(12,701		)	(36		)
Net liability	$	(7,106	)	$	(36	)

Schedule of open commodity derivative contract positions

Contracts	Settlement Period	Total Notional Units (Barrels)		Fair Value of Net Assets (Liabilities)
		(in thousands)
As of March 31, 2013 -
Propane swaps (1)	April 2013 - March 2014	(282	)	$	3,197
Heating oil calls and futures (2)	May 2013 - June 2013	8		79
Crude swaps (3)	April 2013 - June 2014	(91	)	153
Crude - butane spreads (4)	April 2013 - March 2014	(1,116	)	(7,651		)
Crude forwards (5)	April 2013 - March 2014	(144	)	1,033
Butane forwards (6)	April 2013 - March 2014	1,546		(2,557		)
				(5,746		)
Net cash collateral held				(1,360		)
Net fair value of commodity derivatives on consolidated balance sheet				$	(7,106	)
As of March 31, 2012 -
Propane swaps	April 2012 - March 2013	(460	)	$	(36	)

(1) Propane swaps — Our natural gas liquids logistics 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 swaps” represent financial derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

(2) Heating oil calls and futures — Our retail segment offers our customers the opportunity to purchase a specified volume of heating oil at a fixed price. The contracts listed in this table as “heating oil calls and futures” represent financial derivatives we have entered into as an economic hedge against the risk that heating oil prices will rise between the time we entered into the fixed price sale commitment with the customers and the time we will the purchase heating oil to sell to the customers.

(3) Crude swaps — Our crude oil logistics segment routinely enters into crude oil purchase and sale contracts that are priced based on a crude oil index. 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 swaps” represent hedges against the risk that changes in the different index prices would reduce the margins between the purchase and the sale transactions.

(4) Crude-butane spreads — Our natural gas liquids logistics segment enters into forward contracts to sell butane at a price that will be calculated as a specified percentage of a crude oil index at the delivery date. The contracts listed in this table as “crude — butane spreads” represent financial derivatives we have entered into as economic hedges against the risk that the spread between butane prices and crude prices will narrow between the time we entered into the butane forward sale contracts and the expected delivery dates.

(5) Crude forwards — 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 forwards” represent financial derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding inventory.

(6) Butane forwards — Our natural gas liquids logistics segment routinely purchases butane inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “butane forwards” represent financial derivatives we have entered into as an economic hedge against the risk that butane prices will decline while we are holding inventory.

Schedule of net gains (losses) from commodity and interest rate derivatives

	NGL Energy Partners LP								NGL Supply
	Year			Year			Six Months		Six Months
	Ended			Ended			Ended		Ended
	March 31,			March 31,			March 31,		September 30,
	2013			2012			2011		2010
	(in thousands)
Commodity contracts -
Unrealized gain (loss)	$	(5,275	)	$	(4,384	)	$	1,357	$	(200	)
Realized gain	899			10,351			111		426
Interest rate swaps	(5		)	(291		)	224		—
Total	$	(4,381	)	$	5,676		$	1,692	$	226

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Summary of Significant Accounting Policies (Details) (USD $)	6 Months Ended		12 Months Ended
	Mar. 31, 2011	Sep. 30, 2010	Mar. 31, 2013	Mar. 31, 2012	Sep. 08, 2010
Basis of Presentation
Capital contribution by general partner					$ 1,000
Amortization related to intangible assets
Amortization of contract-based intangible assets	1,558,000		44,086,000	6,615,000
Advertising Costs
Advertising expense	300,000	100,000	1,100,000	800,000
Cost of sales - wholesale supply and marketing
Amortization related to intangible assets
Amortization of contract-based intangible assets	400,000		5,285,000	800,000
Cost of sales - wholesale supply and marketing | Contract-based intangibles
Amortization related to intangible assets
Amortization of contract-based intangible assets	$ 400,000	$ 400,000	$ 5,300,000	$ 800,000

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Acquisitions (Details 2) (USD $)		12 Months Ended		0 Months Ended			12 Months Ended		12 Months Ended			0 Months Ended								1 Months Ended			1 Months Ended
	Mar. 31, 2013	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Nov. 02, 2012 Pecos	Mar. 31, 2013 Pecos	Mar. 31, 2013 Pecos Trade names	Mar. 31, 2013 Pecos Customer relationships	Mar. 31, 2013 Pecos Vehicles and related equipment	Mar. 31, 2013 Pecos Vehicles and related equipment Minimum	Mar. 31, 2013 Pecos Vehicles and related equipment Maximum	Mar. 31, 2013 Pecos Other	Nov. 12, 2012 Pecos Call agreement Common units	Nov. 02, 2011 Pecos Call agreement Common units Minimum	Nov. 02, 2012 Pecos Call agreement Common units Maximum	Nov. 02, 2011 Pecos Call agreement Common units Maximum	Mar. 31, 2013 High Sierra	Jun. 19, 2012 High Sierra	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 Vehicles and related equipment	Jun. 30, 2012 High Sierra Vehicles and related equipment Minimum	Jun. 30, 2012 High Sierra Vehicles and related equipment Maximum
Acquisitions
Cash acquired				$ 2,200,000
Amount of additional consideration payable	5,000,000			10,200,000
Number of common units issued to acquire ownership interests (in shares)		24,250,258	14,432,031									1,834,414
General and administrative expense					600,000											3,700,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable					73,704,000												395,311,000
Inventory					1,903,000												43,575,000
Other current assets					1,425,000												11,131,000
Property, plant and equipment								19,193,000			2,562,000											20,968,000
Useful life of property, plant and equipment									5 years	10 years													5 years	10 years
Intangible assets						1,000,000	8,000,000											13,000,000	245,000,000
Useful life of intangible assets							5 years													5 years	17 years
Goodwill					86,661,000												220,884,000
Accounts payable and accrued liabilities					(51,827,000)
Long-term debt					(10,234,000)												(2,537,000)
Consideration paid, net of cash acquired					132,387,000												654,045,000
Consideration paid for acquisition
Cash paid, net of cash received pursuant to call agreement	14,000,000			132,400,000	87,444,000											239,251
Value of common units issued pursuant to call agreement					44,943,000							45,000,000	45,000,000	60,000,000	60,000,000	414,794
Total consideration paid					$ 132,387,000											$ 654,045

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Long-Term Obligations (Tables)

12 Months Ended

Mar. 31, 2013

Long-Term Obligations

Schedule of long-term debt

	March 31,
	2013		2012
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	441,500	$	—
Working capital loans	36,000		—
Previous revolving credit facility —
Acquisition loans	—		186,000
Working capital loans	—		28,000
Senior notes	250,000		—
Other notes payable	21,562		4,711
	749,062		218,711
Less current maturities	8,626		19,534
Long-term debt	$	740,436	$	199,177

Schedule of outstanding borrowings and interest rates under revolving credit facility

At March 31, 2013, our outstanding borrowings and interest rates under our revolving credit facility were as follows (dollars in thousands):

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	441,500	3.21	%
Working capital facility —
LIBOR borrowings	20,000		3.21	%
Base rate borrowings	16,000		5.25	%

Schedule of future maturities of long-term debt

The future maturities of our long-term debt are as follows as of March 31, 2013 (in thousands):

	Revolving				Other
	Credit		Senior		Notes
Year ending March 31,	Facility		Notes		Payable		Total
2014	$	—	$	—	$	8,626	$	8,626
2015	—		—		6,456		6,456
2016	—		—		3,088		3,088
2017	—		—		2,091		2,091
2018	477,500		25,000		1,182		503,682
Thereafter	—		225,000		119		225,119
	$	477,500	$	250,000	$	21,562	$	749,062

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Intangible Assets (Details 2) (USD $)	6 Months Ended	12 Months Ended		6 Months Ended		12 Months Ended		6 Months Ended		12 Months Ended		6 Months Ended	12 Months Ended	6 Months Ended	12 Months Ended		6 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply	Mar. 31, 2011 Depreciation and amortization	Mar. 31, 2013 Depreciation and amortization	Mar. 31, 2012 Depreciation and amortization	Sep. 30, 2010 Depreciation and amortization NGL Supply	Mar. 31, 2011 Interest expense	Mar. 31, 2013 Interest expense	Mar. 31, 2012 Interest expense	Sep. 30, 2010 Interest expense NGL Supply	Mar. 31, 2013 Loss on early extinguishment of debt	Mar. 31, 2011 Cost of sales - natural gas liquids logistics	Mar. 31, 2013 Cost of sales - natural gas liquids logistics	Mar. 31, 2012 Cost of sales - natural gas liquids logistics	Sep. 30, 2010 Cost of sales - natural gas liquids logistics NGL Supply
Amortization related to intangible assets
Amortization expense	$ 1,558,000	$ 44,086,000	$ 6,615,000	$ 827,000	$ 593,000	$ 29,657,000	$ 4,538,000	$ 391,000	$ 565,000	$ 3,375,000	$ 1,277,000	$ 36,000	$ 5,769,000	$ 400,000	$ 5,285,000	$ 800,000	$ 400,000
Future amortization expense of intangible assets
2014		44,485,000
2015		43,137,000
2016		41,396,000
2017		39,567,000
2018		34,234,000
Thereafter		210,204,000
Total		$ 413,023,000

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Equity (Details 3) (USD $) In Thousands, except Share data, unless otherwise specified	0 Months Ended														12 Months Ended
	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	Mar. 31, 2013	Mar. 31, 2012
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 general partner															0.10%
Distributions
Distributions to partners prior to initial public offering																$ 3,850
Distribution declared per unit (in dollars per unit)																$ 0.35
Amount per unit (in dollars per unit)	$ 0.4775		$ 0.4625		$ 0.4500		$ 0.4125		$ 0.3625		$ 0.3500		$ 0.3375	$ 0.1669
Number of equivalent units that were not eligible to receive a distribution		1,202,085		516,978		17,862,470		3,932,031		7,117,031		4,000,000
Minimum
Distributions
Total Quarterly Distribution per Unit (in dollars per unit)															0.3375
First target distribution | Minimum
Distributions
Total Quarterly Distribution per Unit (in dollars per unit)															0.3375
First target distribution | Maximum
Distributions
Total Quarterly Distribution per Unit (in dollars per unit)															0.388125
Second target distribution | Minimum
Distributions
Total Quarterly Distribution per Unit (in dollars per unit)															0.388125
Second target distribution | Maximum
Distributions
Total Quarterly Distribution per Unit (in dollars per unit)															0.421875
Third target distribution | Minimum
Distributions
Total Quarterly Distribution per Unit (in dollars per unit)															0.421875
Third target distribution | Maximum
Distributions
Total Quarterly Distribution per Unit (in dollars per unit)															0.50625
Thereafter | Minimum
Distributions
Total Quarterly Distribution per Unit (in dollars per unit)															0.50625
Limited Partners
Distributions
Marginal Percentage Interest In Distributions															99.90%
Amount Paid to Limited Partners	25,605		24,245		22,846		13,574		9,165		7,735		4,990	2,467
Limited Partners | First target distribution
Distributions
Marginal Percentage Interest In Distributions															99.90%
Limited Partners | Second target distribution
Distributions
Marginal Percentage Interest In Distributions															86.90%
Limited Partners | Third target distribution
Distributions
Marginal Percentage Interest In Distributions															76.90%
Limited Partners | Thereafter
Distributions
Marginal Percentage Interest In Distributions															51.90%
General Partner
Distributions
Marginal Percentage Interest In Distributions															0.10%
Distributions to partners prior to initial public offering																4
Amount Paid to General Partner	$ 1,189		$ 927		$ 707		$ 134		$ 10		$ 10		$ 5	$ 3
General Partner | Minimum
Distributions
Annual incentive distributions to general partner (in dollars per unit)															1.35
Total Quarterly Distribution per Unit (in dollars per unit)															0.3375
General Partner | First target distribution
Distributions
Marginal Percentage Interest In Distributions															0.10%
General Partner | Second target distribution
Distributions
Marginal Percentage Interest In Distributions															13.10%
General Partner | Third target distribution
Distributions
Marginal Percentage Interest In Distributions															23.10%
General Partner | Thereafter
Distributions
Marginal Percentage Interest In Distributions															48.10%

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Intangible Assets (Details) (USD $) In Thousands, unless otherwise specified	12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Amortizable
Gross Carrying Amount	457,178	145,924
Accumulated Amortization	44,155	8,174
Non-amortizable
Gross Carrying Amount of trade names	29,580	11,740
Gross carrying amount of intangible assets	486,758	157,664
Customer relationships
Amortizable
Gross Carrying Amount	407,835	128,071
Accumulated Amortization	30,959	3,868
Customer relationships | Minimum
Intangible assets
AMORTIZABLE Lives	5 years	5 years
Customer relationships | Maximum
Intangible assets
AMORTIZABLE Lives	20 years	20 years
Customer relationships | Weighted average
Intangible assets
AMORTIZABLE Lives	11 years
Lease and other agreements
Amortizable
Gross Carrying Amount	15,210	2,810
Accumulated Amortization	7,018	1,545
Lease and other agreements | Minimum
Intangible assets
AMORTIZABLE Lives	1 year	1 year
Lease and other agreements | Maximum
Intangible assets
AMORTIZABLE Lives	8 years	8 years
Non-compete agreements
Amortizable
Gross Carrying Amount	11,855	5,033
Accumulated Amortization	2,871	919
Non-compete agreements | Minimum
Intangible assets
AMORTIZABLE Lives	2 years	2 years
Non-compete agreements | Maximum
Intangible assets
AMORTIZABLE Lives	7 years	7 years
Trade names
Amortizable
Gross Carrying Amount	2,784	2,700
Accumulated Amortization	326
Trade names | Minimum
Intangible assets
AMORTIZABLE Lives	3 years	3 years
Trade names | Maximum
Intangible assets
AMORTIZABLE Lives	10 years	10 years
Debt issuance costs
Amortizable
Gross Carrying Amount	19,494	7,310
Accumulated Amortization	2,981	1,842
Debt issuance costs | Minimum
Intangible assets
AMORTIZABLE Lives	5 years	5 years
Debt issuance costs | Maximum
Intangible assets
AMORTIZABLE Lives	10 years	10 years

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Summary of Significant Accounting Policies (Details 4) (USD $) In Thousands, unless otherwise specified			12 Months Ended	6 Months Ended		12 Months Ended		6 Months Ended	12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Consolidated total revenues Customer concentration risk Crude oil and natural gas liquids Largest customer	Mar. 31, 2011 Consolidated total revenues Customer concentration risk Wholesale supply and marketing item	Sep. 30, 2010 Consolidated total revenues Customer concentration risk Natural gas liquids logistics NGL Supply item	Mar. 31, 2012 Consolidated accounts receivable Customer concentration risk Wholesale supply and marketing item	Mar. 31, 2013 Consolidated accounts receivable Customer concentration risk Crude oil logistics item	Sep. 30, 2010 Cost of sales Supplier concentration risk NGL Supply item	Mar. 31, 2010 Cost of sales Supplier concentration risk NGL Supply item
Concentration of Credit Risk
Number of customers or suppliers				1	2	1	1	3	3
Percentage of concentration risk			10.00%	10.00%	28.00%	21.00%	10.00%
Inventories
Crude oil	$ 46,156
Propane	45,428	78,993
Other natural gas liquids	24,090	9,259
Other	11,221	6,252
Total	$ 126,895	$ 94,504

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Commitments and Contingencies (Details 2) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply	Mar. 31, 2013 Natural gas liquids gal	Mar. 31, 2013 Crude oil bbl
Future minimum lease payments
2014		$ 55,065
2015		38,283
2016		31,297
2017		29,005
2018		21,520
Thereafter		36,268
Total		211,438
Sales and purchase contracts for natural gas liquids and crude oil
Rental expense	838	51,354	5,202	676
Fixed-price purchase commitments (in gallons)					84,159,000	3,382,000
Floating-price purchase commitments (in gallons)					540,518,000
Fixed-price sale commitments (in gallons)					102,071,000	5,642,000
Floating-price sale commitments (in gallons)					262,143,000
Fixed-price purchase commitments					76,386	303,819
Floating-price purchase commitments					604,584
Fixed-price sale commitments					100,246	504,505
Floating-price sale commitments					339,757
Amortization expense (income) recorded in cost of sales related to the forward purchase and sale contract assets and liabilities		13,498			14,587	(1,089)
Amortization expense (income) expected to be recorded in cost of sales related to the forward purchase and sale contract assets and liabilities ending next year		2,538			2,701	(163)
Amortization expense (income) included and expected to be recorded in cost of sales related to the forward purchase and sale contract assets and liabilities		16,036			17,288	(1,252)
Unamortized balances recorded in consolidated balance sheet
Current assets		3,124
Current liabilities		(586)
Net assets		$ 2,538

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Mar. 31, 2013

Summary of Significant Accounting Policies

Schedule of supplemental cash flow information

	NGL Energy Partners LP						NGL Supply
	Year		Year		Six Months		Six Months
	Ended		Ended		Ended		Ended
	March 31,		March 31,		March 31,		September 30,
	2013		2012		2011		2010
	(in thousands)
Interest paid	$	27,384	$	4,966	$	2,063	$	335
Income taxes paid	$	1,027	$	430	$	—	$	220

Schedule of accounts receivable

	March 31, 2013				March 31, 2012
	Gross		Allowance for		Gross		Allowance for
Segment	Receivable		Doubtful Accounts		Receivable		Doubtful Accounts
	(in thousands)
Crude oil logistics	$	360,721	$	11	$	—	$	—
Water services	9,618		29		—		—
Natural gas liquids logistics	144,267		76		52,640		113
Retail Propane	49,233		1,644		32,182		705
Other	810		—		—		—
	$	564,649	$	1,760	$	84,822	$	818

Schedule of changes in the allowance for doubtful accounts

	NGL Energy Partners LP									NGL Supply
	Year			Year			Six Months			Six Months
	Ended			Ended			Ended			Ended
	March 31,			March 31,			March 31,			September 30,
	2013			2012			2011			2010
	(in thousands)
Allowance for doubtful accounts, beginning of period	$	818		$	161		$	—		$	235
Bad debt provision	1,315			1,049			269			3
Write off of uncollectible accounts	(373		)	(392		)	(108		)	(64		)
Allowance for doubtful accounts, end of period	$	1,760		$	818		$	161		$	174

Schedule of inventories

	2013		2012
	(in thousands)
Crude oil	$	46,156	$	—
Propane	45,428		78,993
Other natural gas liquids	24,090		9,259
Other	11,221		6,252
Total	$	126,895	$	94,504

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Consolidated Statements of Changes in Equity (USD $) In Thousands, except Share data, unless otherwise specified	Total	Accumulated Other Comprehensive Income	Noncontrolling Interest	General Partner	Limited Partners Common units	Limited Partners Subordinated units	NGL Supply, Inc.	NGL Supply, Inc. Class A Common Stock	NGL Supply, Inc. Additional Paid-in Capital	NGL Supply, Inc. Retained Earnings	NGL Supply, Inc. Accumulated Other Comprehensive Income	NGL Supply, Inc. Receivable From Exercise of Stock Options	NGL Supply, Inc. Noncontrolling Interest
BALANCES at Mar. 31, 2010							$ 46,403	$ 196	$ 36,039	$ 9,859	$ 84		$ 225
BALANCES (in units) at Mar. 31, 2010								19,603
Increase (Decrease) in Stockholders' Equity
Exercise of stock options								7	1,423			(1,430)
Exercise of stock options, (in shares)							650	650
Net income										(2,515)			(45)
Foreign currency translation adjustment							(15)				(15)
Dividends -
Preferred stock dividends							(17)			(17)
Common stock dividends							(7,000)			(7,000)
Increase (Decrease) in Partnership Capital
Net income (loss)							2,560
BALANCES at Sep. 30, 2010							36,811	203	37,462	327	69	(1,430)	180
BALANCES (in units) at Sep. 30, 2010								20,253
Increase (Decrease) in Stockholders' Equity
Exercise of stock options							1,430
BALANCES at Oct. 14, 2010							1,252
BALANCES at Sep. 30, 2010
Increase (Decrease) in Stockholders' Equity
Foreign currency translation adjustment	56	56
Increase (Decrease) in Partnership Capital
Combination transaction with NGL Supply (Notes 1 & 2)	1,252				1,252
Combination transaction with NGL Supply (Notes 1 and 2) (in units)					4,735,328
Acquisition of HOH & Gifford (Notes 1 & 4)	22,326				22,326
Units issued in business combinations (in units)					4,154,757
Sale of units at formation	10,981				10,981
Sale of units at formation (in units)					2,043,483
Contributions	59			59
Net income (loss)	12,679			13	12,666
BALANCES at Mar. 31, 2011	47,353	56		72	47,225
BALANCES (in units) at Mar. 31, 2011					10,933,568
Increase (Decrease) in Stockholders' Equity
Foreign currency translation adjustment	(25)	(25)
Increase (Decrease) in Partnership Capital
Units issued in business combinations, net of issuance costs (Note 4)	296,500				296,500
Units issued in business combinations (in units)					14,432,031
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
Sale of units in public offering, net	75,289				75,289
Sale of units in public offering, net (in units)					4,025,000
Repurchase of common units	(3,418)				(3,418)
Repurchase of common units (in units)					(175,000)
Contributions	386			386
Contributions from noncontrolling interest owners	440		440
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)
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 Stockholders' Equity
Foreign currency translation adjustment	(7)	(7)
Increase (Decrease) in Partnership Capital
Units issued in business combinations, net of issuance costs (Note 4)	503,018		4,733	(52,588)	550,873
Units issued in business combinations (in units)					24,250,258
Distributions to partners	(71,682)		(74)	(1,778)	(59,841)	(9,989)
Contributions	913		403	510
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
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

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Nature of Operations and Organization

12 Months Ended

Mar. 31, 2013

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 (the “IEP Parties”). NGL Energy Holdings LLC serves as our general partner. We had no operations prior to September 30, 2010.

Formation Transactions

In October 2010, we acquired retail and wholesale natural gas liquids businesses that were historically owned by NGL Supply, Inc. (“NGL Supply”), Hicks Oils and Hicksgas, Incorporated (“HOH”), and Hicksgas Gifford, Inc. (“Gifford”). The acquisitions were effected through the following transactions, which we refer to as the formation transactions:

· HOH formed a wholly owned subsidiary, Hicksgas, LLC, and contributed to it all of HOH’s propane and propane-related assets. The shareholders of Gifford contributed all of their shares of stock in Gifford to a newly formed holding company, Gifford Holdings, Inc.

· Our general partner made a cash capital contribution of approximately $58,800 to us in exchange for the continuation of its 0.1% general partner interest in us and incentive distribution rights and the IEP Parties (owner of a 32.53% interest in our general partner) made a cash capital contribution to us in the aggregate amount of approximately $11.0 million in exchange for an aggregate 18.67% limited partner interest in us.

· NGL Supply and Gifford each converted into a limited liability company and the members of NGL Supply, Hicksgas, LLC and Gifford contributed 100% of their respective membership interests in those entities to us as capital contributions in exchange for (i) in the case of NGL Supply, a 43.27% limited partner interest in us, a cash distribution of approximately $40.0 million and our agreement to pay or cause to be paid approximately $27.9 million of existing indebtedness of NGL Supply, (ii) in the case of Hicksgas, LLC, a 37.96% limited partner interest in us, a cash distribution of approximately $1.6 million and our agreement to pay or cause to be paid approximately $6.5 million of existing indebtedness of HOH, and (iii) in the case of Gifford, a cash payment of approximately $15.5 million.

· We made a capital contribution of 100% of the membership interests of each of NGL Supply, Hicksgas, LLC and Gifford to a wholly owned operating subsidiary. Gifford was merged into Hicksgas, LLC.

NGL Supply was organized on July 1, 1985 as a successor to a company founded in 1967, and is a diversified, vertically integrated provider of propane services including retail propane distribution; wholesale supply and marketing of propane and other natural gas liquids; and midstream operations which consist of natural gas liquids terminal operations and services.

The formation transactions described above were accounted for as a business combination with NGL Supply designated as the acquirer. Hicksgas, LLC and Gifford were determined to be acquirees. Accordingly, NGL Supply was accounted for on the basis of historical cost, and our assets and liabilities were recorded at the historical net book values of NGL Supply. The assets and liabilities of Hicksgas, LLC and Gifford were recorded at their estimated fair values on the transaction date.

NGL Supply began its retail propane operations during its fiscal year ended March 31, 2008 through the acquisition of retail operations in Kansas and Georgia, and expanded its retail operations through additional acquisitions during fiscal 2008 through 2010. As discussed above and in Note 4, we acquired Hicksgas LLC and Gifford in connection with our formation transactions. Hicksgas LLC and Gifford are both in the retail propane business with operations in Indiana and Illinois.

Initial Public Offering

On May 11, 2011, we completed an initial public offering (“IPO”). We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. We used the proceeds from the sale of 3,850,000 common units of $71.9 million, net of offering costs of approximately $9.0 million, to repay debt and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) were used to purchase 175,000 of the common units outstanding prior to our initial public offering. Upon the completion of our IPO, our limited partner equity consisted of 8,864,222 common units and 5,919,346 subordinated units.

Acquisitions Subsequent to Initial Public Offering

Subsequent to our initial public offering, we significantly expanded our operations through a number of business combinations, including the following:

· On October 3, 2011, we completed a business combination transaction 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. 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 we paid in November 2012.

· On November 1, 2011, we completed a business combination transaction 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. We issued 8,932,031 common units and paid $91.0 million in exchange for the assets and operations of SemStream, including working capital.

· On January 3, 2012, we completed a business combination transaction with seven companies associated with Pacer Propane Holding, L.P. (collectively, “Pacer”), whereby we acquired retail propane operations, primarily in the western United States. We issued 1,500,000 common units, valued at $30.4 million, and paid $32.2 million of cash in exchange for the assets and operations of Pacer, including working capital. We also assumed $2.7 million of long-term debt in the form of non-compete agreements.

· On February 3, 2012, we completed a business combination transaction with North American Propane, Inc. (“North American”), whereby we acquired retail propane and distillate operations in the northeastern United States. We paid $69.8 million of cash in exchange for the assets and operations of North American, including working capital.

· During the year ended March 31, 2012, we completed three separate business combination transactions to acquire retail propane operations. On a combined basis, we paid $6.4 million of cash for these assets and operations, including working capital. We also assumed $0.7 million of long-term debt in the form of non-compete agreements.

· On June 19, 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. 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.

· 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 purchasing and logistics operations in Texas and New Mexico. We paid cash of $132.4 million at closing (net of $2.2 million of cash acquired), subject to customary post-closing adjustments, 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 of Pecos purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement.

· On December 31, 2012, we completed a business combination transaction whereby we acquired all of the limited liability company 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. The agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. 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 call agreement.

· During the year ended March 31, 2013, we completed six separate business combination transactions to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States. On a combined basis, we paid $71.4 million of cash and issued 850,676 common units in exchange for these assets and operations, including working capital. We also assumed $6.6 million of long-term debt in the form of non-compete agreements.

· 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 services businesses. On a combined basis, we paid $52.6 million of 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. Certain of the acquisition agreements contemplate post-closing adjustment to the purchase price for certain specified working capital items.

Businesses as of March 31, 2013

As of March 31, 2013, our businesses include:

· A crude oil logistics business, the assets of which include crude oil terminals, pipeline injection stations, a fleet of trucks, a fleet of leased rail cars, and a fleet of barges and tow boats. 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. The operations of our crude oil logistics segment began with our June 2012 merger with High Sierra.

· A water services business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water services 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. The operations of our water services segment began with our June 2012 merger with High Sierra.

· Our natural gas liquids logistics business, which supplies natural gas liquids to retailers, wholesalers, and refiners throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 17 terminals throughout the United States and rail car transportation services through its fleet of owned and predominantly leased rail cars. Our natural gas liquids logistics segment purchases propane, butane, and other natural gas liquids from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets. Our natural gas liquids logistics segment includes the operations that were previously reported in our wholesale marketing and supply and terminals segments. Our natural gas liquids logistics segment also includes the natural gas liquids operations we acquired in our June 2012 merger with High Sierra.

· 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.

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Acquisitions

12 Months Ended

Mar. 31, 2013

Acquisitions

Acquisitions

Note 4 - Acquisitions

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 approximately $3.7 million of costs related to the High Sierra transaction. We also incurred or accrued costs of approximately $0.6 million related to the equity issuance that we charged to equity.

We have included the results of High Sierra’s operations in our consolidated financial statements beginning on June 19, 2012. During the year ended March 31, 2013, our consolidated statement of operations includes operating income of approximately $46.6 million generated by the operations of High Sierra and by the operations of the subsequent acquisitions of crude oil logistics and water services businesses. The following table summarizes the revenues and cost of sales contributed by High Sierra’s operations and the operations of the subsequent acquisitions of crude oil logistics and water services businesses (in thousands):

	Revenues		Cost of Sales
Crude oil logistics	$	2,316,288	$	2,244,647
Natural gas liquids logistics	696,424		663,630
Water services	62,227		5,611
Other	4,233		—
Total	$	3,079,172	$	2,913,888

The fair values of the assets acquired and liabilities assumed in our acquisition of High Sierra are summarized below (in thousands):

Accounts receivable	$	395,311
Inventory	43,575
Receivables from affiliates	7,724
Derivative assets	10,646
Forward purchase and sale contracts	34,717
Other current assets	11,131
Property, plant and equipment:
Land	5,910
Transportation vehicles and equipment (5 - 10 years)	20,968
Facilities and equipment (2 - 30 years)	103,574
Buildings and improvements (5 - 30 years)	9,691
Information technology equipment and software (3 - 5 years)	4,099
Construction in progress	11,213
Intangible assets:
Customer relationships (5 - 17 years)	245,000
Lease contracts (1 - 10 years)	12,400
Trade names (indefinite)	13,000
Goodwill	220,884
Assumed liabilities:
Accounts payable	(417,369		)
Accrued expenses and other current liabilities	(35,611		)
Payables to affiliates	(9,014		)
Advance payments received from customers	(1,237		)
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

The consideration paid consists of the following:

Cash paid, net of cash acquired	$	239,251
Value of common units issued, net of issuance costs	414,794
Total consideration paid	$	654,045

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.

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.

The fair value of accounts receivable is approximately $0.6 million lower than the contract value, to give effect to estimated uncollectable accounts.

Pecos Combination

On November 1, 2012, we completed a business combination whereby we acquired Pecos. The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texas and New Mexico. We paid cash of $132.4 million at closing (net of $2.2 million of cash acquired), subject to customary post-closing adjustments, 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 approximately $0.6 million of costs related to the Pecos combination.

We are in the process of identifying and determining the fair value of the assets and liabilities acquired in the combination with Pecos. The estimates of fair value reflected as of March 31, 2013 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 ended September 30, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Accounts receivable	$	73,704
Inventory	1,903
Other current assets	1,425
Property, plant and equipment:
Vehicles and related equipment (5 - 10 years)	19,193
Other	2,562
Customer relationships (5 years)	8,000
Trade names (indefinite life)	1,000
Goodwill	86,661
Accounts payable and accrued liabilities	(51,827		)
Long-term debt	(10,234		)
Total consideration paid	$	132,387

The consideration paid consists of the following (in thousands):

Cash paid, net of cash acquired and cash received pursuant to Call Agreement	$	87,444
Value of common units issued pursuant to Call Agreement	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 for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. The agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. 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. We incurred and charged to general and administrative expense during the year ended March 31, 2013 approximately $0.3 million of costs related to the Third Coast combination.

We are in the process of identifying and determining the fair value of the assets and liabilities acquired in the combination with Third Coast. The estimates of fair value reflected as of March 31, 2013 are subject to change. We currently expect to complete this process prior to finalizing our financial statements for the quarter ended December 31, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Accounts receivable	$	2,248
Other current assets	140
Property, plant and equipment:
Barges and tow boats (20 years)	12,883
Other (3 - 5 years)	30
Customer relationships (5 years)	4,000
Trade names (indefinite life)	500
Goodwill	22,551
Other noncurrent assets	2,733
Assumed liabilities	(2,202		)
Consideration paid	$	42,883

The consideration paid consists of the following (in thousands):

Cash paid, net of cash received pursuant to call agreement	$	35,000
Value of common units issued pursuant to call agreement	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 Services 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 services 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. Certain of the agreements contemplate post-closing adjustments to the purchase price for certain specified working capital items. We incurred and charged to general and administrative expense during the year ended March 31, 2013 approximately $0.3 million of costs related to these acquisitions.

We are currently in the process of identifying and determining the fair value of the assets and liabilities acquired in this combination. The estimates of fair value reflected as of March 31, 2013 are subject to change. We currently expect to complete this process prior to finalizing our financial statements for the quarter ended September 30, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (in thousands):

Accounts receivable	$	2,660
Inventory	191
Other current assets	738
Property, plant and equipment:
Disposal wells and related equipment (3 - 30 years)	13,322
Other (5 - 30 years)	5,671
Customer relationships (5 - 15 years)	6,800
Non-compete agreements (3 - 5 years)	510
Trade names (indefinite life)	500
Goodwill	43,822
Current liabilities	(5,400		)
Notes payable	(1,340		)
Other noncurrent liabilities	(156		)
Noncontrolling interest	(2,333		)
Consideration paid	$	64,985

The 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 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 approximately $0.3 million related to these acquisitions. We are in the process of identifying the fair value of the assets acquired and liabilities assumed in certain of the combinations. The estimates of fair value reflected as of March 31, 2013 for certain of these acquisitions are subject to change, although such changes are not likely to be material. Our estimates of the fair value of the assets acquired and liabilities assumed in these six combinations are as follows (in thousands):

Accounts receivable	$	8,715
Inventory	5,155
Other current assets	1,228
Property, plant and equipment:
Land	1,945
Tanks and other retail propane equipment (5-20 years)	28,763
Vehicles (5 years)	11,344
Buildings (30 years)	7,052
Other equipment	1,201
Intangible assets:
Customer relationships (10-15 years)	16,890
Tradenames (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.

The retail combinations completed during the year ended March 31, 2013 contributed approximately $124.3 million of revenue and approximately $86.6 million of cost of sales to our consolidated statement of operations for the year ended March 31, 2013.

Pro Forma Results of Operations (Unaudited)

The operations of High Sierra have been included in our consolidated statement of operations since High Sierra was acquired on June 19, 2012. The operations of Pecos have been included in our consolidated statement of operations since Pecos was acquired on November 1, 2012. The operations of Third Coast have been included in our consolidated statement of operations since Third Coast was acquired on December 31, 2012. The following unaudited pro forma consolidated data below are presented as if the High Sierra, Pecos, and Third Coast acquisitions had been completed on April 1, 2011 (in thousands, except per unit amounts). The pro forma earnings per unit are based on the common and subordinated units outstanding as of March 31, 2013.

	Years Ended March 31,
	2013		2012
Revenues	$	5,430,449	$	4,789,040
Income from continuing operations	56,366		15,720
Limited partners’ interest in income from continuing operations	53,442		15,704
Basic and diluted earnings from continuing operations per common unit	1.00		0.29
Basic and diluted earnings from continuing operations per subordinated unit	1.00		0.29

The pro forma consolidated data in the table above was prepared by adding the historical results of operations of High Sierra, Pecos, and Third Coast to our historical results of operations and making certain pro forma adjustments. The pro forma adjustments include: (i) replacing the historical depreciation and amortization expense of High Sierra, Pecos, and Third Coast with pro forma depreciation and amortization expense, calculated using the estimated fair values of long-lived assets recorded in the acquisition accounting; (ii) replacing the historical interest expense of High Sierra, Pecos, and Third Coast with pro forma interest expense; and (iii) excluding professional fees and other expenses incurred by us and by the acquirees that were directly related to the acquisitions. In order to calculate pro forma earnings per unit in the table above, we assumed that: (i) the same number of limited partner units outstanding at March 31, 2013 had been outstanding throughout the periods shown in the table, and (ii) all of the common units were eligible for distributions related to the periods shown in the table. The pro forma information is not necessarily indicative of the results of operations that would have occurred if the acquisitions had been completed on April 1, 2011, nor is it necessarily indicative of the future results of the combined operations.

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 approximately $772,000 of costs incurred in connection with the Osterman transaction. We also incurred costs related to the equity issuance of approximately $127,000 that we charged to equity. We have included the results of Osterman’s operations in our consolidated financial statements beginning October 3, 2011.

During the year ended March 31, 2013 we completed the acquisition accounting for this transaction. 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):

				Estimated
				Allocation
				as of
	Final			March 31,
	Allocation			2012			Revision
Accounts receivable	$	9,350		$	5,584		$	3,766
Inventory	3,869			3,898			(29		)
Other current assets	215			212			3
Property, plant and equipment:
Land	2,349			4,500			(2,151		)
Tanks and other retail propane equipment (15-20 years)	47,160			55,000			(7,840		)
Vehicles (5-20 years)	7,699			12,000			(4,301		)
Buildings (30 years)	3,829			6,500			(2,671		)
Other equipment (3-5 years)	732			1,520			(788		)
Intangible assets:
Customer relationships (20 years)	54,500			62,479			(7,979		)
Tradenames (indefinite life)	8,500			5,000			3,500
Non-compete agreements (7 years)	700			—			700
Goodwill	52,267			30,405			21,862
Assumed liabilities	(9,654		)	(5,431		)	(4,223		)
Consideration paid, net of cash acquired	$	181,516		$	181,667		$	(151	)

Consideration paid consists of the following (in thousands):

			Estimated
			Allocation
			as of
	Final		March 31,
	Allocation		2012		Revision
Cash paid at closing, net of cash acquired	$	94,873	$	96,000	$	(1,127	)
Fair value of common units issued at closing	81,880		81,880		—
Working capital payment (paid in November 2012)	4,763		3,787		976
Consideration paid, net of cash acquired	$	181,516	$	181,667	$	(151	)

We have adjusted the March 31, 2012 balances reported in these consolidated financial statements to reflect the final acquisition accounting. These revisions did not have a material impact on the consolidated statements of operations.

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 natural gas liquids logistics operations. 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 approximately $91.0 million. We have valued the 8.9 million limited partner common units at approximately $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 approximately $736,000 of costs related to the SemStream transaction. We also incurred costs of approximately $43,000 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 above ground propane storage, 3.7 million barrels of underground leased storage for natural gas liquids and a rail fleet of approximately 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 natural gas liquids logistics segment.

The following table presents the fair values of the assets acquired and liabilities assumed in the SemStream combination (in thousands):

Propane and other natural gas liquids inventory	$	104,226
Derivative financial instruments	3,578
Assets held for sale	3,000
Prepaids and other current assets	9,833
Property, plant and equipment:
Land	3,470
Tanks and terminals (20-30 years)	41,434
Vehicles and rail cars (5 years)	470
Other (5 years)	3,326
Investment in capital lease	3,112
Amortizable intangible assets:
Customer relationships (8-15 years)	31,950
Rail car leases (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 approximately $710,000 of costs related to the Pacer transaction. We also incurred costs of approximately $64,000 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.

The consideration paid in the Pacer combination consisted of the following (in thousands):

Cash	$	32,213
Common units	30,375
	$	62,588

During the year ended March 31, 2013, we completed the acquisition accounting for this transaction. 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):

					Estimated
					Allocation
					as of
		Final			March 31,
		Allocation			2012			Revision
	Accounts receivable	$	4,389		$	4,389		$	—
	Inventory	965			965			—
	Other current assets	43			43			—
	Property, plant and equipment:
	Land	1,967			1,400			567
	Tanks and other retail propane equipment (15 - 20 years)	12,793			11,200			1,593
	Vehicles (5 years)	3,090			5,000			(1,910		)
	Buildings (30 years)	409			2,300			(1,891		)
	Other equipment (3-5 years)	59			200			(141		)
	Intangible assets:
	Customer relationships (15 years)	23,560			21,980			1,580
	Tradenames (indefinite life)	2,410			1,000			1,410
	Noncompete agreements	1,520			—			1,520
	Goodwill	15,782			18,460			(2,678		)
	Assumed Liabilities	(4,399		)	(4,349		)	(50		)
	Consideration paid	$	62,588		$	62,588		$	—
We have adjusted the March 31, 2012 balances reported in these consolidated financial statements to reflect the final acquisition accounting. These revisions did not have a material impact on the consolidated statements of operations.

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 approximately $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. We have included the results of North American’s operations in our consolidated financial statements beginning on February 3, 2012.

During the year ended March 31, 2013, we completed the acquisition accounting for this transaction. The following table presents the final allocation of the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (in thousands):

				Estimated
				Allocation
				as of
	Final			March 31,
	Allocation			2012			Revision
Accounts receivable	$	10,338		$	10,338		$	—
Inventory	3,437			3,437			—
Other current assets	282			282			—
Property, plant and equipment:
Land	2,251			2,600			(349		)
Tanks and other retail propane equipment (15-20 years)	24,790			27,100			(2,310		)
Terminal assets (15-20 years)	1,044			—			1,044
Vehicles (5-15 years)	5,819			9,000			(3,181		)
Buildings (30 years)	2,386			2,200			186
Other equipment (3-5 years)	634			500			134
Intangible assets:
Customer relationships (10 years)	12,600			9,800			2,800
Tradenames (10 years)	2,700			1,000			1,700
Noncompete agreements (3 years)	700			—			700
Goodwill	13,978			14,702			(724		)
Assumed liabilities	(11,129		)	(11,129		)	—
Consideration paid	$	69,830		$	69,830		$	—

We have adjusted the March 31, 2012 balances reported in these consolidated financial statements to reflect the final acquisition accounting. These revisions did not have a material impact on the consolidated statements of operations.

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 approximately $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.

Six Months Ended March 31, 2011

As discussed in Note 1, we purchased the retail propane operations of Hicksgas LLC and Gifford in October 2010 as part of our formation transactions. The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their estimated fair values, in the acquisition of the retail propane businesses of Hicksgas LLC and Gifford described above (in thousands):

Accounts receivable	$	5,669
Inventory	6,182
Prepaid expenses and other current assets	2,600
	14,451
Property, plant, and equipment:
Land	2,666
Tanks and other retail propane equipment (15 year life)	23,016
Vehicles (5 year life)	6,599
Buildings (30 year life)	7,053
Office equipment (5 year life)	523
Amortizable intangible assets:
Customer relationships (15 year life)	2,170
Non-compete agreements (5 year life)	550
Tradenames (indefinite-life intangible asset)	830
Goodwill (retail propane segment)	3,716
Total assets acquired	61,574
Accounts payable	1,837
Customer advances and deposits	12,089
Accrued and other current liabilities	2,152
	16,078
Long-term debt	5,768
Other long-term liabilities	274
Total liabilities assumed	22,120
Net assets acquired	$	39,454

Goodwill was warranted because these acquisitions enhanced our retail propane operations. We expect all of the goodwill acquired to be tax deductible. We do not believe that the acquired intangible assets will have any significant residual value at the end of their useful life.

The total acquisition cost was $39.5 million, consisting of cash of approximately $17.2 million and the issuance of 4,154,757 common units valued at $22.3 million. The units issued to the shareholders of Hicksgas LLC in the formation transaction were valued at $5.37 per unit, the price paid by unrelated parties for the common units they acquired near the transaction date.

The operations of Hicksgas LLC and Gifford have been included in our statements of operations since acquisition in October 2010. For convenience, and because the impact was not significant, we have accounted for the acquisition as it if occurred on October 1, 2010.

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Equity (Details 4) (USD $)	0 Months Ended	12 Months Ended
	Jan. 02, 2013	Mar. 31, 2013
Equity-Based Incentive Compensation
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%
Common units
Estimated stock-based compensation expense
Number of common units issued for awards that vested	156,802
Increase in equity on issue of awards that vested	3,700,000
Number of common units withheld to pay withholding taxes	61,698
Amount of withholding taxes paid on behalf of recipient	1,400,000
Restricted units
Equity-Based Incentive Compensation
Units granted (in shares)		1,684,400
Units vested and issued (in shares)		(156,802)
Units withheld for employee taxes (in shares)		(61,698)
Units forfeited (in shares)		(21,000)
Unvested restricted units at the end of the period (in shares)		1,444,900
Distributions on restricted units during the vesting period		0
Number of awards vested	218,500	1,444,900
Weighted-average grant date fair value of the awards (in dollars per share)		$ 23.01
General and Administrative Expense recorded related to awards related to awards		10,100,000
Expenses related to awards accounted as liability awards, included in other current liabilities		5,000,000
Estimate of forfeiture of unvested awards		71,000
Estimated stock-based compensation expense
2014		12,168,000
2015		7,516,000
2016		6,559,000
2017		4,613,000
2018		1,040,000
2019		15,000
Total		$ 31,911,000
Number of units available for issuance under the Long-Term Incentive Plan		3,760,539
Restricted units | July 1, 2013
Equity-Based Incentive Compensation
Number of awards vested		377,300
Restricted units | July 1, 2014
Equity-Based Incentive Compensation
Number of awards vested		360,800
Restricted units | July 1, 2015
Equity-Based Incentive Compensation
Number of awards vested		272,300
Restricted units | July 1, 2016
Equity-Based Incentive Compensation
Number of awards vested		263,500
Restricted units | July 1, 2017
Equity-Based Incentive Compensation
Number of awards vested		169,000
Restricted units | July 1, 2018
Equity-Based Incentive Compensation
Number of awards vested		2,000

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Summary of Significant Accounting Policies

12 Months Ended

Mar. 31, 2013

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Note 2 - Summary of 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”). We were formed on September 8, 2010 with a capitalization of $1,000 by our general partner and had no operations or additional capitalizations through September 30, 2010. Accordingly, we are presenting our financial statements for periods subsequent to September 30, 2010. As described above, NGL Supply was deemed to be the acquiring entity in our formation transactions. Therefore, our financial statements for the six months ended September 30, 2010 represent the historical financial statements of NGL Supply. We recorded the assets acquired and liabilities assumed from NGL Supply at their historical net book values.

The accompanying consolidated financial statements include the accounts of the Partnership and its controlled subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.

We have made certain reclassifications to the prior period financial statements to conform with classification methods used in fiscal 2013. These reclassifications had no impact on previously-reported amounts of total assets, liabilities, partners’ equity, or net income. In addition, as described in Note 4, certain balances as of March 31, 2012 were adjusted to reflect the final acquisition accounting for certain business combinations.

Estimates

The preparation of financial statements in accordance with GAAP requires us to make estimates and assumptions that affect the reported amounts of our assets, liabilities, revenues, expenses and costs. These estimates are based on our knowledge of current events, historical experience, and various other assumptions that we believe to be reasonable under the circumstances.

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 should be 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, 2013 and 2012 (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, 2013 or 2012.

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. Changes in the value of our interest rate swap agreements are recorded in our consolidated statements of operations in interest expense. Contracts that qualify for the normal purchase or sale exemption 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 realized or unrealized, are reported in the consolidated statement 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. Shipping and handling costs associated with product sales are included in operating expenses 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 the 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 in the amount of $5.3 million during the year ended March 31, 2013, $0.8 million during the year ended March 31, 2012, and $0.4 million during each of the six months ended March 31, 2011 and September 30, 2010. We also include in cost of sales the costs paid to the third parties who operate our terminal facilities under operating and maintenance agreements.

Advertising Costs

We expense advertising costs as incurred. We recorded advertising expense of $1.1 million for the year ended March 31, 2013, $0.8 million for the year ended March 31, 2012, $0.3 million for the six months ended March 31, 2011, and $0.1 million for the six months ended September 30, 2010.

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.

Interest Income

Interest income consists primarily of fees charged to retail customers for late payment on accounts receivable.

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 during the indicated periods:

	NGL Energy Partners LP						NGL Supply
	Year		Year		Six Months		Six Months
	Ended		Ended		Ended		Ended
	March 31,		March 31,		March 31,		September 30,
	2013		2012		2011		2010
	(in thousands)
Interest paid	$	27,384	$	4,966	$	2,063	$	335
Income taxes paid	$	1,027	$	430	$	—	$	220

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 as of the dates indicated:

	March 31, 2013				March 31, 2012
	Gross		Allowance for		Gross		Allowance for
Segment	Receivable		Doubtful Accounts		Receivable		Doubtful Accounts
	(in thousands)
Crude oil logistics	$	360,721	$	11	$	—	$	—
Water services	9,618		29		—		—
Natural gas liquids logistics	144,267		76		52,640		113
Retail Propane	49,233		1,644		32,182		705
Other	810		—		—		—
	$	564,649	$	1,760	$	84,822	$	818

Changes in the allowance for doubtful accounts are as follows during the periods indicated:

	NGL Energy Partners LP									NGL Supply
	Year			Year			Six Months			Six Months
	Ended			Ended			Ended			Ended
	March 31,			March 31,			March 31,			September 30,
	2013			2012			2011			2010
	(in thousands)
Allowance for doubtful accounts, beginning of period	$	818		$	161		$	—		$	235
Bad debt provision	1,315			1,049			269			3
Write off of uncollectible accounts	(373		)	(392		)	(108		)	(64		)
Allowance for doubtful accounts, end of period	$	1,760		$	818		$	161		$	174

For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented approximately 10% of our consolidated total revenues. For the year ended March 31, 2012, no single customer accounted for more than 10% of our consolidated total revenues. For the six months ended March 31, 2011, we had one customer of our wholesale supply and marketing segment who represented approximately 10% of total consolidated revenues. In the six months ended September 30, 2010, two customers of our natural gas liquids logistics segment accounted for 28% of total consolidated revenues. As of March 31, 2013, one customer of our crude oil logistics segment represented approximately 10% of our consolidated accounts receivable balance. As of March 31, 2012, one customer of our wholesale supply and marketing segment represented approximately 21% of our consolidated accounts receivable balance.

Inventories

Our inventories include propane, normal butane, natural gasoline, isobutane, transmix, distillates, appliances, and parts and supplies. 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. We monitor inventory values for potential lower of cost or market adjustments and will record such adjustments at fiscal year-end, or on an interim basis if we believe the decline in market value will not be recovered by year end. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer inventory from our wholesale business to our retail business for sale in the retail markets.

Our inventories as of March 31, 2013 and 2012 consisted of the following:

	2013		2012
	(in thousands)
Crude oil	$	46,156	$	—
Propane	45,428		78,993
Other natural gas liquids	24,090		9,259
Other	11,221		6,252
Total	$	126,895	$	94,504

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 less than its carrying value. In that event, we would recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group. No impairments of property, plant and equipment were recorded for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010.

Intangible Assets

Our identifiable intangible assets consist of debt issuance costs and significant contracts and arrangements acquired in business combinations, including lease agreements, customer relationships, covenants not to compete, and trade names. We capitalize acquired intangible assets if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of our intent to do so. 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’ 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.

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, 2013 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 as of 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 step 1 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 step 2 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 the results of these evaluations, we did not record any goodwill impairments during the years ended March 31, 2013 and 2012 or the six months ended March 31, 2011 and September 30, 2010.

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.

Asset Retirement Obligations

We record the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, which is typically at the time the assets are placed into service. After the initial measurement, we recognize changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.

Advance Payments Received from Customers

We record customer advances on product purchases as a liability on the consolidated balance sheets.

Noncontrolling Interests

As of March 31, 2013, we have three consolidated subsidiaries in which outside parties own interests. Our ownership interests in these subsidiaries range from 60% to 80%. One of these subsidiaries was formed in March 2012, and the other two were acquired in June 2012 and October 2012, respectively. The noncontrolling interest shown in our consolidated statements of operations for the years ended March 31, 2013 and 2012 represents the other owners’ interests in these entities.

The net loss attributable to noncontrolling interest shown in the consolidated statement of operations of NGL Supply for the six months ended September 30, 2010 reflects a 30% interest in a consolidated subsidiary that was owned by unrelated parties at the time. We currently own 100% of this subsidiary.

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 fiscal year ended March 31, 2013 are still within this measurement period, and as a result, the acquisition date values we have recorded for the acquired assets and assumed liabilities are subject to change.

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Summary of Significant Accounting Policies (Details 2) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended		6 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply
Supplemental cash flow information
Interest paid	$ 2,063	$ 27,384	$ 4,966	$ 335
Income taxes paid		$ 1,027	$ 430	$ 220

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Property, Plant and Equipment (Tables)

12 Months Ended

Mar. 31, 2013

Property, Plant and Equipment

Schedule of property, plant and equipment

Property, plant and equipment consists of the following at March 31, 2013 and 2012:

				2012
Description and Depreciable Life	2013			(Note 4)
	(in thousands)
Natural gas liquids terminal assets (30 years)	$	63,637		$	62,024
Retail propane equipment (5-20 years)	152,802			119,972
Vehicles (5-10 years)	85,200			26,372
Water treatment facilities and equipment (3-30 years)	91,601			—
Crude oil tanks and loading facilities (2-30 years)	21,308			—
Barges and towboats (20 years)	21,135			—
Information technology equipment (3-5 years)	12,169			4,347
Buildings and leasehold improvements (5-30 years)	48,394			14,651
Land	21,604			13,084
Other (3-10 years)	17,288			3,108
Construction in progress	31,926			679
	567,064			244,237
Less: Accumulated depreciation	(50,127		)	(12,843		)
Property, plant and equipment, net	$	516,937		$	231,394

Schedule of depreciation expense

NGL Energy Partners LP						NGL Supply
Year		Year		Six Months		Six Months
Ended		Ended		Ended		Ended
March 31,		March 31,		March 31,		September 30,
2013		2012		2011		2010
(in thousands)
$	39,196	$	10,573	$	2,848	$	998

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Commitments and Contingencies (Tables)

12 Months Ended

Mar. 31, 2013

Commitments and Contingencies

Schedule of future minimum lease payments under contractual commitments

Future minimum lease payments under contractual commitments as of March 31, 2013 are as follows (in thousands):

Year Ending March 31,
2014	$	55,065
2015	38,283
2016	31,297
2017	29,005
2018	21,520
Thereafter	36,268
Total	$	211,438

Schedule of rental expense relating to operating leases

Rental expense relating to operating leases was as follows for the periods indicated (in thousands):

Year ended March 31, 2013	$	51,354
Year ended March 31, 2012	5,202
Six months ended March 31, 2011	838
Six months ended September 30, 2010	676

Schedule of commitments outstanding

At March 31, 2013, we had the following such commitments outstanding:

	Volume	Value
	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)	84,159	$	76,386
Natural gas liquids floating-price purchase commitments (gallons)	540,518	604,584
Natural gas liquids fixed-price sale commitments (gallons)	102,071	100,246
Natural gas liquids floating-price sale commitments (gallons)	262,143	339,757
Crude oil fixed-price purchase commitments (barrels)	3,382	303,819
Crude oil fixed-price sale commitments (barrels)	5,642	504,505

Schedule of unamortized balances included in the entity's consolidated balance sheet

At March 31, 2013, the unamortized balances included in our consolidated balance sheet were as follows (in thousands):

Current assets	$	3,124
Current liabilities	(586		)
Net assets	$	2,538

Schedule of recorded and expected to be record amortization expense (income) to cost of sales related to the forward purchase and sale contracts

The following table summarizes the amortization expense (income) we have recorded, and the amortization expense (income) we expect to record, to cost of sales related to the forward purchase and sale contracts acquired in the merger with High Sierra (in thousands):

	Natural Gas Liquids		Crude Oil
	Logistics Segment		Logistics Segment			Total
Year ended March 31, 2013	$	14,587	$	(1,089	)	$	13,498
Year ending March 31, 2014	2,701		(163		)	2,538
Total expense (income)	$	17,288	$	(1,252	)	$	16,036

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Equity (Details 2) (Common units)	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, 2013	Mar. 31, 2012	Oct. 03, 2011 Osterman	Mar. 31, 2012 Osterman	Mar. 31, 2012 SemStream	Nov. 01, 2011 SemStream	Jan. 03, 2012 Pacer	Mar. 31, 2012 Pacer	Mar. 31, 2013 High Sierra	Mar. 31, 2013 Retail propane	Mar. 31, 2013 Water services	Nov. 12, 2012 Pecos	Mar. 31, 2013 Pecos	Jan. 11, 2013 Third Coast	Mar. 31, 2013 Third Coast
Common Units Issued in Business Combinations
Common units issued	24,250,258	14,432,031	4,000,000	4,000,000	8,932,031	8,932,031	1,500,000	1,500,000	20,703,510	850,676	516,978	1,834,414	1,834,414	344,680	344,680

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Quarterly Financial Data (Unaudited) (Tables)

12 Months Ended

Mar. 31, 2013

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,
	2012			2012		2012		2013		2013
	(dollars 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) to parent equity	(24,650		)	10,073		40,176		22,341		47,940
Earnings (loss) per unit, basic and diluted -
Common	$	(0.76	)	$	0.18	$	0.75	$	0.39	$	0.96
Subordinated	$	(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

	Quarter Ended										Year Ended
	June 30,			September 30,			December 31,		March 31,		March 31,
	2011			2011			2011		2012		2012
	(dollars in thousands, except unit and per unit data)
Total revenues	$	190,845		$	210,041		$	470,649	$	438,938	$	1,310,473
Total cost of sales	185,973			201,454			439,790		389,806		1,217,023
Net income (loss)	(6,773		)	(5,395		)	6,090		13,942		7,864
Net income (loss) to parent equity	(6,773		)	(5,395		)	6,090		13,954		7,876
Earnings (loss) per unit, basic and diluted -
Common	$	(0.53	)	$	(0.36	)	$	0.24	$	0.47	$	0.32
Subordinated	$	(0.53	)	$	(0.36	)	$	0.28	$	0.53	$	0.58
Weighted average common units outstanding - basic and diluted	9,883,342			8,864,222			18,699,590		23,263,386		15,169,983
Weighted average subordinated outstanding units - basic and diluted	2,927,149			5,199,346			5,919,346		5,919,346		5,175,384

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Equity (Details) (USD $)	0 Months Ended	3 Months Ended								6 Months Ended	12 Months Ended
	May 11, 2011	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012
Partnership equity
General partner, interest (as a percent)											0.10%	0.10%
Limited partners, interest (as a percent)											99.90%	99.90%
Limited Partner Equity
Units										10,933,568
Amount										$ 47,225,000
Initial Public Offering
Proceeds from sale of common units, net of offering costs											(642,000)	74,759,000
Units outstanding after completion of IPO										10,933,568
Unaudited Pro Forma
Limited Partner Equity
Units										10,933,568
Amount										47,225,000
Initial Public Offering
Units outstanding after completion of IPO										10,933,568
Common units
Limited Partner Equity
Units	8,864,222	47,703,313				23,296,253				10,933,568	47,703,313	23,296,253
Amount		920,998,000				384,604,000				47,225,000	920,998,000	384,604,000
Earnings per unit, basic and diluted
BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT: (in dollars per unit)		$ 0.39	$ 0.75	$ 0.18	$ (0.76)	$ 0.47	$ 0.24	$ (0.36)	$ (0.53)	$ 1.16	$ 0.96	$ 0.32
Initial Public Offering
Number of units sold in initial 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	47,703,313				23,296,253				10,933,568	47,703,313	23,296,253
Common units | Repayment of debt
Initial Public Offering
Number of units sold in initial public offering	3,850,000
Proceeds from sale of common units, net of offering costs	71,900,000
Offerings costs	9,000,000
Common units | Purchase of common units
Initial Public Offering
Number of units sold in initial public offering	175,000
Proceeds from sale of common units, net of offering costs	3,400,000
Common units | Unaudited Pro Forma
Limited Partner Equity
Units										5,014,222
Amount										21,658,000
Earnings per unit, basic and diluted
BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT: (in dollars per unit)										$ 1.16
Initial Public Offering
Units outstanding after completion of IPO										5,014,222
Subordinated units
Partnership Equity
Number of consecutive, non-overlapping four-quarter periods to determine termination of subordination period											3
Number of non-overlapping quarters											4
Number of quarters during which quarterly distributions are earned or paid to determine termination of subordination period											4
Subordinated units, conversion ratio											1
Common units converted to subordinated units	5,919,346
Limited Partner Equity
Units	5,919,346	5,919,346				5,919,346					5,919,346	5,919,346
Amount		13,153,000				19,824,000					13,153,000	19,824,000
Earnings per unit, basic and diluted
BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT: (in dollars per unit)		$ 0.39	$ 0.75	$ 0.18	$ (0.77)	$ 0.53	$ 0.28	$ (0.36)	$ (0.53)		$ 0.93	$ 0.58
Initial Public Offering
Units outstanding after completion of IPO	5,919,346	5,919,346				5,919,346					5,919,346	5,919,346
Subordinated units | Minimum
Partnership Equity
Percentage of quarterly distribution earned and paid to determine termination of subordination period											150.00%
Subordinated units | Unaudited Pro Forma
Limited Partner Equity
Units										5,919,346
Amount										$ 25,567,000
Earnings per unit, basic and diluted
BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT: (in dollars per unit)										$ 1.16
Initial Public Offering
Units outstanding after completion of IPO										5,919,346

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Acquisitions (Details 8) (USD $)		12 Months Ended			12 Months Ended			0 Months Ended			0 Months Ended				0 Months Ended					12 Months Ended
	Mar. 31, 2013	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Nov. 01, 2011 NGL Energy Holdings, LLC SemStream	Mar. 31, 2012 SemStream	Nov. 01, 2011 SemStream item bbl gal	Nov. 01, 2011 SemStream Customer relationships	Nov. 01, 2011 SemStream Customer relationships Minimum	Nov. 01, 2011 SemStream Customer relationships Maximum	Nov. 01, 2011 SemStream Rail car leases	Nov. 01, 2011 SemStream Rail car leases Minimum	Nov. 01, 2011 SemStream Rail car leases Maximum	Nov. 01, 2011 SemStream Land	Nov. 01, 2011 SemStream Tanks and terminals	Nov. 01, 2011 SemStream Tanks and terminals Minimum	Nov. 01, 2011 SemStream Tanks and terminals Maximum	Nov. 01, 2011 SemStream Vehicles and rail cars	Nov. 01, 2011 SemStream Other	Nov. 01, 2011 SemStream Common units	Mar. 31, 2012 SemStream Common units
Acquisitions
Number of common units issued to acquire ownership interests (in shares)		24,250,258	14,432,031																8,932,031	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					736,000
Equity issuance costs					43,000
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
Propane and other natural gas liquids inventory						104,226,000
Derivative financial instruments						3,578,000
Assets held for sale						3,000,000
Prepaids 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															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						74,924,000
Assumed current liabilities						(4,591,000)
Consideration paid, net of cash acquired						$ 275,740,000

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Acquisitions (Details 3) (USD $)		12 Months Ended							12 Months Ended			12 Months Ended				0 Months Ended
	Mar. 31, 2013	Mar. 31, 2013 Barges and tow boats	Mar. 31, 2012 Barges and tow boats	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Mar. 31, 2013 Third Coast	Dec. 31, 2012 Third Coast	Mar. 31, 2013 Third Coast Trade names	Mar. 31, 2013 Third Coast Customer relationships	Mar. 31, 2013 Third Coast Barges and tow boats	Mar. 31, 2013 Third Coast Other	Mar. 31, 2013 Third Coast Other Minimum	Mar. 31, 2013 Third Coast Other Maximum	Mar. 31, 2013 Third Coast Common units	Jan. 11, 2013 Third Coast Common units	Jan. 11, 2013 Third Coast Call agreement Common units	Dec. 31, 2012 Third Coast Call agreement Common units	Dec. 31, 2012 Third Coast Call agreement Common units Minimum	Dec. 31, 2012 Third Coast Call agreement Common units Maximum
Acquisitions
Number of common units issued to acquire ownership interests (in shares)				24,250,258	14,432,031									344,680		344,680
General and administrative expense						$ 300,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable							2,248,000
Other current assets							140,000
Property, plant and equipment										12,883,000	30,000
Useful life of property, plant and equipment		20 years	20 years							20 years		3 years	5 years
Intangible assets								500,000	4,000,000
Useful life of intangible assets									5 years
Goodwill							22,551,000
Other noncurrent assets							2,733,000
Assumed liabilities							(2,202,000)
Consideration paid, net of cash acquired							42,883,000
Consideration paid for acquisition
Cash paid, net of cash received pursuant to call agreement	14,000,000					35,000,000	35,000,000
Value of common units issued pursuant to call agreement														7,883,000	8,000,000		8,000,000	8,000,000	10,000,000
Total consideration paid						$ 42,883,000

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Summary of Significant Accounting Policies (Details 6)	5 Months Ended	12 Months Ended
	Oct. 31, 2012 item	Mar. 31, 2012 item	Mar. 31, 2013 Minimum	Mar. 31, 2013 Maximum	Sep. 30, 2010 NGL Supply	Mar. 31, 2013 Consolidated subsidiary formerly owned by unrelated parties of the predecessor entity
Noncontrolling Interests
Number of consolidated subsidiaries owned, formed, or acquired	2	1
Ownership interests (as a percent)			60.00%	80.00%
Ownership interests by unrelated parties (as a percent)					30.00%	100.00%

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Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Mar. 31, 2013 Subordinated units	Mar. 31, 2012 Subordinated units
Accounts receivable - trade, allowance for doubtful accounts (in dollars)	$ 1,760	$ 818
PROPERTY, PLANT AND EQUIPMENT, accumulated depreciation (in dollars)	50,127	12,843
INTANGIBLE ASSETS, accumulated amortization (in dollars)	$ 44,155	$ 8,174
General partner, interest (as a percent)	0.10%	0.10%
General partner, notional units outstanding	53,676	29,245
Limited partners, interest (as a percent)	99.90%	99.90%
Units outstanding			47,703,313	23,296,253	5,919,346	5,919,346
Units issued			47,703,313	23,296,253	5,919,346	5,919,346

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Intangible Assets

12 Months Ended

Mar. 31, 2013

Intangible Assets

Intangible Assets

Note 7 - Intangible Assets

Intangible assets consist of the following:

		March 31, 2013				March 31, 2012
						(Note 4)
		Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Amortizable Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable -
Customer relationships	5-20 years*	$	407,835	$	30,959	$	128,071	$	3,868
Lease and other agreements	1-8 years	15,210		7,018		2,810		1,545
Non-compete agreements	2-7 years	11,855		2,871		5,033		919
Trade names	3-10 years	2,784		326		2,700		—
Debt issuance costs	5-10 years	19,494		2,981		7,310		1,842
Total amortizable		457,178		44,155		145,924		8,174
Non-amortizable -
Trade names	Indefinite	29,580		—		11,740		—
Total		$	486,758	$	44,155	$	157,664	$	8,174

*  The weighted-average amortization period for customer relationship intangible assets is approximately 11 years.

Amortization expense was as follows for the periods indicated:

	NGL Energy Partners LP						NGL Supply
	Year		Year		Six Months		Six Months
	Ended		Ended		Ended		Ended
	March 31,		March 31,		March 31,		September 30,
Recorded in	2013		2012		2011		2010
	(in thousands)
Depreciation and amortization	$	29,657	$	4,538	$	593	$	391
Interest expense	3,375		1,277		565		36
Loss on early extinguishment of debt	5,769		—		—		—
Cost of sales - natural gas liquids logistics	5,285		800		400		400
	$	44,086	$	6,615	$	1,558	$	827

Future amortization expense of our intangible assets is estimated to be as follows (in thousands):

Year Ending March 31,
2014	$	44,485
2015	43,137
2016	41,396
2017	39,567
2018	34,234
Thereafter	210,204
	$	413,023

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Consolidated Statements of Comprehensive Income (Loss) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended		6 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply, Inc.
Net income (loss)	$ 12,679	$ 48,190	$ 7,864	$ 2,560
Other comprehensive income (loss), net of tax:
Change in foreign currency translation adjustment	56	(7)	(25)	(15)
Comprehensive income (loss)	$ 12,735	$ 48,183	$ 7,839	$ (2,575)

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Acquisitions (Details 11) (USD $)	12 Months Ended
	Mar. 31, 2013 item	Mar. 31, 2012 Other acquisitions item
Acquisitions
Number of business combination agreements	2	3
Cash paid to acquire ownership interests	$ 14,000,000	$ 6,400,000
Long-term debt assumed		$ 600,000

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Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Mar. 31, 2012
CURRENT ASSETS:
Cash and cash equivalents	$ 11,561	$ 7,832
Accounts receivable, net of allowance for doubtful accounts of $1,760 and $818, respectively	562,889	84,004
Accounts receivable - affiliates	22,883	2,282
Inventories	126,895	94,504
Prepaid expenses and other current assets	37,891	10,002
Total current assets	762,119	198,624
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $50,127 and $12,843, respectively	516,937	231,394
GOODWILL	563,146	167,245
INTANGIBLE ASSETS, net of accumulated amortization of $44,155 and $8,174, respectively	442,603	149,490
OTHER NONCURRENT ASSETS	6,542	2,766
Total assets	2,291,347	749,519
CURRENT LIABILITIES:
Trade accounts payable	535,687	81,369
Accrued expenses and other payables	85,703	14,143
Advance payments received from customers	22,372	20,293
Accounts payable - affiliates	6,900	9,462
Current maturities of long-term debt	8,626	19,534
Total current liabilities	659,288	144,801
LONG-TERM DEBT, net of current maturities	740,436	199,177
OTHER NONCURRENT LIABILITIES	2,205	212
COMMITMENTS AND CONTINGENCIES
PARTNERS' EQUITY, per accompanying statement:
General partner, representing a 0.1% interest, 53,676 and 29,245 notional units at March 31, 2013 and 2012, respectively	(50,497)	442
Accumulated other comprehensive income -
Foreign currency translation	24	31
Noncontrolling interest	5,740	428
Total partners' equity	889,418	405,329
Total liabilities and partners' equity	2,291,347	749,519
Common units
Limited partners, representing a 99.9% interest -
Limited partners, representing a 99.9% interest -	920,998	384,604
Subordinated units
Limited partners, representing a 99.9% interest -
Limited partners, representing a 99.9% interest -	$ 13,153	$ 19,824

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Acquisitions (Details 4) (USD $)	12 Months Ended							12 Months Ended			12 Months Ended			12 Months Ended			12 Months Ended		9 Months Ended	12 Months Ended
	Mar. 31, 2013 item	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations item	Dec. 31, 2012 Other Crude Oil Logistics and Water Services Business Combinations	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Trade names	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Customer relationships	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Customer relationships Minimum	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Customer relationships Maximum	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Non-compete agreements	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Non-compete agreements Minimum	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Non-compete agreements Maximum	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Disposal wells and related equipment	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Disposal wells and related equipment Minimum	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Disposal wells and related equipment Maximum	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Other	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Other Minimum	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Other Maximum	Dec. 31, 2012 Other Crude Oil Logistics and Water Services Business Combinations Common units	Mar. 31, 2013 Other Crude Oil Logistics and Water Services Business Combinations Common units
Acquisitions
Number of business combination agreements	2			4
Liabilities assumed in form of non-compete agreements	$ 5,000,000			$ 1,300,000	$ 1,300,000
Number of common units issued to acquire ownership interests (in shares)		24,250,258	14,432,031																516,978	516,978
General and administrative expense				300,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable				2,660,000
Inventory				191,000
Other current assets				738,000
Property, plant and equipment													13,322,000			5,671,000
Useful life of property, plant and equipment														3 years	30 years		5 years	30 years
Intangible assets						500,000	6,800,000			510,000
Useful life of intangible assets								5 years	15 years		3 years	5 years
Goodwill				43,822,000
Current liabilities				(5,400,000)
Notes payable				(1,340,000)
Other noncurrent liabilities				(156,000)
Noncontrolling interest				(2,333,000)
Consideration paid, net of cash acquired				64,985,000
Consideration paid for acquisition
Cash paid	14,000,000			52,552,000
Value of common units issued																				12,433,000
Total consideration paid				$ 64,985,000

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Segment Information (Details) (USD $) In Thousands, unless otherwise specified	3 Months Ended								6 Months Ended	12 Months Ended				1 Months Ended	6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended				6 Months Ended	12 Months Ended			6 Months Ended	12 Months Ended		6 Months Ended		12 Months Ended		6 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Crude oil logistics	Mar. 31, 2013 Water services	Jun. 30, 2012 Natural gas liquids logistics item	Mar. 31, 2011 Natural gas liquids logistics	Mar. 31, 2013 Natural gas liquids logistics	Mar. 31, 2012 Natural gas liquids logistics	Mar. 31, 2011 Natural gas liquids logistics Propane sales	Mar. 31, 2013 Natural gas liquids logistics Propane sales	Mar. 31, 2012 Natural gas liquids logistics Propane sales	Mar. 31, 2011 Natural gas liquids logistics Other natural gas liquids sales	Mar. 31, 2013 Natural gas liquids logistics Other natural gas liquids sales	Mar. 31, 2012 Natural gas liquids logistics Other natural gas liquids sales	Mar. 31, 2011 Natural gas liquids logistics Storage revenues and other	Mar. 31, 2013 Natural gas liquids logistics Storage revenues and other	Mar. 31, 2012 Natural gas liquids logistics Storage revenues and other	Mar. 31, 2011 Retail propane	Mar. 31, 2013 Retail propane item	Mar. 31, 2012 Retail propane	Mar. 31, 2011 Retail propane Propane sales	Mar. 31, 2013 Retail propane Propane sales	Mar. 31, 2012 Retail propane Propane sales	Mar. 31, 2013 Retail propane Distillate sales	Mar. 31, 2012 Retail propane Distillate sales	Mar. 31, 2011 Retail propane Other retail sales	Mar. 31, 2013 Retail propane Other retail sales	Mar. 31, 2012 Retail propane Other retail sales	Mar. 31, 2013 Other	Mar. 31, 2011 Elimination of intersegment sales	Mar. 31, 2013 Elimination of intersegment sales	Mar. 31, 2012 Elimination of intersegment sales	Mar. 31, 2011 Corporate and other	Sep. 30, 2010 Corporate and other	Mar. 31, 2013 Corporate and other	Mar. 31, 2012 Corporate and other	Sep. 30, 2010 NGL Supply	Sep. 30, 2010 NGL Supply Natural gas liquids logistics	Sep. 30, 2010 NGL Supply Natural gas liquids logistics Propane sales	Sep. 30, 2010 NGL Supply Natural gas liquids logistics Other natural gas liquids sales	Sep. 30, 2010 NGL Supply Natural gas liquids logistics Storage revenues and other	Sep. 30, 2010 NGL Supply Retail propane	Sep. 30, 2010 NGL Supply Retail propane Propane sales	Sep. 30, 2010 NGL Supply Retail propane Other retail sales	Sep. 30, 2010 NGL Supply Elimination of intersegment sales
Segment information
Reportable Segments														2
Number of operating divisions																												2
Revenues									$ 622,232	$ 4,417,767	$ 1,310,473	$ 2,339,148	$ 62,227					$ 477,774	$ 841,448	$ 923,022	$ 90,746	$ 858,276	$ 251,627	$ 1,183	$ 33,954	$ 2,462				$ 67,175	$ 288,410	$ 175,417	$ 106,192	$ 6,547	$ 5,638	$ 35,856	$ 17,370	$ 4,233	$ (20,284)	$ (151,977)	$ (65,972)					$ 316,943		$ 243,908	$ 71,456	$ 959		$ 6,128	$ 740	$ (6,248)
Depreciation and amortization									3,441	68,853	15,111	9,176	20,923		554	11,085	3,661										2,887	25,496	11,450									2,173								1,389	519				870
Operating income (loss)									14,837	87,307	15,030	34,236	8,576		9,590	30,336	9,735										7,362	46,869	9,616													(2,115)	(2,091)	(32,710)	(4,321)	(3,795)	865				(2,569)
Interest income									221	1,261	765																																			66
Interest expense									(2,482)	(32,994)	(7,620)																																			(372)
Loss on early extinguishment of debt										(5,769)
Other income (expense), net									103	260	290																																			124
INCOME TAX (PROVISION) BENEFIT										(1,875)	(601)																																			1,417
Net Income (Loss)	22,341	40,477	10,082	(24,710)	13,942	6,090	(5,395)	(6,773)	12,679	48,190	7,864																																			2,560
Additions to property, plant and equipment including acquisitions (accrual basis)									41,442	326,896	200,457	89,860	137,116		290	15,129	50,276										41,152	66,933	150,181															17,858		401	15				386
Total assets	2,291,347				749,519					2,291,347	749,519	801,030	466,462			474,141	325,173											513,301	417,639															36,413	6,707
Long-lived assets, net of depreciation and amortization, including goodwill and intangibles	$ 1,522,686				$ 548,129					$ 1,522,686	$ 548,129	$ 356,750	$ 453,986			$ 238,192	$ 176,419											$ 441,762	$ 366,242															$ 31,996	$ 5,468

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Fair Value of Financial Instruments (Details) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Mar. 31, 2012
Interest rate swaps
Liabilities:
Derivative Liabilities		$ 100
Interest rate swaps | Maximum
Liabilities:
Derivative Liabilities	100
Commodity contracts
Derivative assets (liabilities)
Net LIABILITY	(7,106)	(36)
Commodity contracts | Prepaid expenses and other current assets
Derivative assets (liabilities)
Net LIABILITY	5,551
Commodity contracts | Other noncurrent assets
Derivative assets (liabilities)
Net LIABILITY	44
Commodity contracts | Accrued expenses and other payables
Derivative assets (liabilities)
Net LIABILITY	(12,701)	(36)
Recurring | Commodity contracts
Assets:
Derivative Assets	10,858
Liabilities:
Derivative Liabilities	(16,604)	(36)
Netting of counterparty contracts, assets	(3,503)
Netting of counterparty contracts, liabilities	3,503
Cash collateral provided or held, assets	(1,760)
Cash collateral provided or held, liabilities	400
Commodity contracts reported on consolidated balance sheet, assets	5,595
Commodity contracts reported on consolidated balance sheet, liabilities	(12,701)	(36)
Recurring | Level 1 | Commodity contracts
Assets:
Derivative Assets	947
Liabilities:
Derivative Liabilities	(3,324)
Recurring | Level 2 | Commodity contracts
Assets:
Derivative Assets	9,911
Liabilities:
Derivative Liabilities	$ (13,280)	$ (36)

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Goodwill (Tables)

12 Months Ended

Mar. 31, 2013

Goodwill

Schedule of goodwill by reportable segment, including changes to goodwill

	NGL Energy Partners LP						NGL Supply
	Year		Year		Six Months		Six Months
	Ended		Ended		Ended		Ended
	March 31,		March 31,		March 31,		September 30,
	2013		2012		2011		2010
	(in thousands)
Beginning of period, as retrospectively adjusted (Note 4)	$	167,245	$	8,568	$	4,580	$	4,457
Goodwill from acquisitions, including additional consideration paid for previous acquisitions	395,901		158,677		3,988		123
End of period, as retrospectively adjusted (Note 4)	$	563,146	$	167,245	$	8,568	$	4,580
Goodwill by segment at end of period:
Crude oil logistics	$	244,073	$	—	$	—	$	—
Water services	119,668		—		—		—
Retail propane	112,269		90,287		6,534		2,546
Natural gas liquids logistics	87,136		76,958		2,034		2,034

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Quarterly Financial Data (Unaudited)

12 Months Ended

Mar. 31, 2013

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 natural gas liquids logistics 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,
	2012			2012		2012		2013		2013
	(dollars 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) to parent equity	(24,650		)	10,073		40,176		22,341		47,940
Earnings (loss) per unit, basic and diluted -
Common	$	(0.76	)	$	0.18	$	0.75	$	0.39	$	0.96
Subordinated	$	(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

	Quarter Ended										Year Ended
	June 30,			September 30,			December 31,		March 31,		March 31,
	2011			2011			2011		2012		2012
	(dollars in thousands, except unit and per unit data)
Total revenues	$	190,845		$	210,041		$	470,649	$	438,938	$	1,310,473
Total cost of sales	185,973			201,454			439,790		389,806		1,217,023
Net income (loss)	(6,773		)	(5,395		)	6,090		13,942		7,864
Net income (loss) to parent equity	(6,773		)	(5,395		)	6,090		13,954		7,876
Earnings (loss) per unit, basic and diluted -
Common	$	(0.53	)	$	(0.36	)	$	0.24	$	0.47	$	0.32
Subordinated	$	(0.53	)	$	(0.36	)	$	0.28	$	0.53	$	0.58
Weighted average common units outstanding - basic and diluted	9,883,342			8,864,222			18,699,590		23,263,386		15,169,983
Weighted average subordinated outstanding units - basic and diluted	2,927,149			5,199,346			5,919,346		5,919,346		5,175,384

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Summary of Significant Accounting Policies (Details 5) (USD $)	6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply	Mar. 31, 2010 NGL Supply
Property, Plant and Equipment
Impairments of property, plant and equipment	$ 0	$ 0	$ 0	$ 0
Goodwill impairments	$ 0	$ 0	$ 0		$ 0

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Fair Value of Financial Instruments (Details 3) (USD $)	12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012
Revolving credit facility
Interest Rate Risk
Outstanding debt	$ 477,500,000
Revolving credit facility | LIBOR option
Interest Rate Risk
Outstanding debt	461,500,000
Interest rate (as a percent)	3.21%
Revolving credit facility | Base Rate
Interest Rate Risk
Outstanding debt	16,000,000
Interest rate (as a percent)	5.25%
Interest Rate Risk | Variable Rate Debt
Interest Rate Risk
Change in interest rate that would result in a change of annual interest expense (as a percent)	0.125%
Change in annual interest expense	600,000
Interest rate swaps
Interest Rate Risk
Notional amount	8,500,000
Derivative Liabilities		$ 100,000
Reference rate for variable interest rate	three-month LIBOR

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Acquisitions (Details 7) (USD $)	6 Months Ended	12 Months Ended									0 Months Ended	1 Months Ended	12 Months Ended			12 Months Ended				12 Months Ended			12 Months Ended				12 Months Ended																			0 Months Ended	12 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2013 Vehicles Minimum	Mar. 31, 2012 Vehicles Minimum	Mar. 31, 2013 Vehicles Maximum	Mar. 31, 2012 Vehicles Maximum	Mar. 31, 2012 Buildings Minimum	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Oct. 03, 2011 Osterman	Nov. 30, 2012 Osterman	Mar. 31, 2012 Osterman	Mar. 31, 2013 Osterman	Mar. 31, 2013 Osterman Trade names	Mar. 31, 2013 Osterman Customer relationships	Mar. 31, 2013 Osterman Non-compete agreements	Mar. 31, 2013 Osterman Land	Mar. 31, 2013 Osterman Tanks and other retail propane equipment	Mar. 31, 2013 Osterman Tanks and other retail propane equipment Minimum	Mar. 31, 2013 Osterman Tanks and other retail propane equipment Maximum	Mar. 31, 2013 Osterman Vehicles	Mar. 31, 2013 Osterman Vehicles Minimum	Mar. 31, 2013 Osterman Vehicles Maximum	Mar. 31, 2013 Osterman Buildings	Mar. 31, 2013 Osterman Other	Mar. 31, 2013 Osterman Other Minimum	Mar. 31, 2013 Osterman Other Maximum	Mar. 31, 2012 Osterman Estimated Allocation as of March 31, 2012	Mar. 31, 2012 Osterman Estimated Allocation as of March 31, 2012 Trade names	Mar. 31, 2012 Osterman Estimated Allocation as of March 31, 2012 Customer relationships	Mar. 31, 2012 Osterman Estimated Allocation as of March 31, 2012 Land	Mar. 31, 2012 Osterman Estimated Allocation as of March 31, 2012 Tanks and other retail propane equipment	Mar. 31, 2012 Osterman Estimated Allocation as of March 31, 2012 Vehicles	Mar. 31, 2012 Osterman Estimated Allocation as of March 31, 2012 Buildings	Mar. 31, 2012 Osterman Estimated Allocation as of March 31, 2012 Other	Mar. 31, 2013 Osterman Revision	Mar. 31, 2013 Osterman Revision Trade names	Mar. 31, 2013 Osterman Revision Customer relationships	Mar. 31, 2013 Osterman Revision Non-compete agreements	Mar. 31, 2013 Osterman Revision Land	Mar. 31, 2013 Osterman Revision Tanks and other retail propane equipment	Mar. 31, 2013 Osterman Revision Vehicles	Mar. 31, 2013 Osterman Revision Buildings	Mar. 31, 2013 Osterman Revision Other	Oct. 03, 2011 Osterman Common units	Mar. 31, 2012 Osterman Common units	Mar. 31, 2013 Osterman Common units	Mar. 31, 2012 Osterman Common units Estimated Allocation as of March 31, 2012
Acquisitions
Number of common units issued to acquire ownership interests (in shares)									24,250,258	14,432,031																																				4,000,000	4,000,000
Cash paid to acquire ownership interests, net of cash acquired	$ 17,400,000	$ 490,402,000	$ 297,401,000								$ 94,900,000
Working capital items, post-closing payment												4,800,000
Issue price of units (in dollars per unit)																																														$ 20.47
General and administrative expense													772,000
Equity issuance costs													127,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable														9,350,000															5,584,000								3,766,000
Inventory														3,869,000															3,898,000								(29,000)
Other current assets														215,000															212,000								3,000
Property, plant and equipment																		2,349,000	47,160,000			7,699,000			3,829,000	732,000						4,500,000	55,000,000	12,000,000	6,500,000	1,520,000					(2,151,000)	(7,840,000)	(4,301,000)	(2,671,000)	(788,000)
Useful life of property, plant and equipment				5 years	5 years	10 years	10 years	5 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													5,000,000	62,479,000							3,500,000	(7,979,000)	700,000
Useful life of intangible assets																20 years	7 years
Goodwill														52,267,000															30,405,000								21,862,000
Assumed liabilities														(9,654,000)															(5,431,000)								(4,223,000)
Consideration paid, net of cash acquired														181,516,000															181,667,000								(151,000)
Consideration paid for acquisition
Cash paid to acquire ownership interests		14,000,000												94,873,000															96,000,000								(1,127,000)
Value of common units issued to acquire ownership interests																																																81,880,000	81,880,000
Working capital payment (paid in November 2012)		5,000,000												4,763,000															3,787,000								976,000
Total consideration paid														$ 181,516,000															$ 181,667,000								$ (151,000)

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Long-Term Obligations (Details) (USD $)			12 Months Ended							12 Months Ended										1 Months Ended			1 Months Ended	12 Months Ended
	Mar. 31, 2013	Mar. 31, 2012	May 31, 2013 Revolving credit facility	Mar. 31, 2013 Revolving credit facility	Mar. 31, 2013 Revolving credit facility Minimum	Mar. 31, 2013 Revolving credit facility Maximum	Mar. 31, 2013 Revolving credit facility LIBOR option	Mar. 31, 2013 Revolving credit facility LIBOR option Minimum	Mar. 31, 2013 Revolving credit facility LIBOR option Maximum	Mar. 31, 2013 Revolving credit facility Alternate base rate	Mar. 31, 2013 Revolving credit facility Alternate base rate Minimum	Mar. 31, 2013 Revolving credit facility Alternate base rate Maximum	May 31, 2013 Revolving credit facility Working capital facility	Mar. 31, 2013 Revolving credit facility Working capital facility	Mar. 31, 2013 Revolving credit facility Working capital facility LIBOR option	Mar. 31, 2013 Revolving credit facility Working capital facility Alternate base rate	May 31, 2013 Revolving credit facility Expansion Capital Facility	Mar. 31, 2013 Revolving credit facility Expansion Capital Facility	Mar. 31, 2013 Revolving credit facility Expansion Capital Facility LIBOR option	Jun. 30, 2012 Previous revolving credit facility	Mar. 31, 2012 Previous revolving credit facility Working capital facility	Mar. 31, 2012 Previous revolving credit facility Acquisition facility	Jun. 30, 2012 Senior Notes	Mar. 31, 2013 Senior Notes	Mar. 31, 2013 Senior Notes Minimum	Mar. 31, 2013 Other notes payable	Mar. 31, 2012 Other notes payable	Mar. 31, 2013 Other notes payable Minimum	Mar. 31, 2013 Other notes payable Maximum
Long-Term Debt
Total debt	$ 749,062,000	$ 218,711,000												$ 36,000,000				$ 441,500,000			$ 28,000,000	$ 186,000,000		$ 250,000,000		$ 21,562,000	$ 4,711,000
Less - current maturities	8,626,000	19,534,000
Long-term debt	740,436,000	199,177,000
Debt issued																							250,000,000
Maximum borrowing capacity													325,000,000	242,500,000			725,000,000	527,500,000
Fees paid related to amendment of agreement			2,100,000
Outstanding cash borrowings				477,500,000			461,500,000			16,000,000				36,000,000	20,000,000	16,000,000		441,500,000	441,500,000
Outstanding letters of credit														60,100,000
Remaining borrowing capacity														146,400,000				86,000,000
Variable interest rate base							LIBOR			base rate
Interest rate margin added to variable rate base							3.00%	2.75%	3.75%	2.00%	1.75%	2.75%
Reference rate (as a percent)							0.21%			3.25%
Commitment fees charged on unused credit (as a percent)					0.38%	0.50%
Fixed interest rate (as a percent)																								6.65%
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%
Principal payment																				306,800,000
Leverage ratio						4.25
Actual leverage ratio				3.0
Interest coverage ratio					2.75
Actual interest coverage ratio				7.0
Repayments in semi-annual installments																								$ 25,000,000
Interest rate (as a percent)							3.21%			5.25%					3.21%	5.25%			3.21%									2.60%	4.90%

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Nature of Operations and Organization (Details 2) (USD $)	6 Months Ended	12 Months Ended				0 Months Ended			0 Months Ended	1 Months Ended		0 Months Ended	12 Months Ended		12 Months Ended		1 Months Ended		0 Months Ended	12 Months Ended		12 Months Ended			12 Months Ended	0 Months Ended				0 Months Ended	12 Months Ended						0 Months Ended	12 Months Ended			12 Months Ended		12 Months Ended
	Mar. 31, 2011	Mar. 31, 2013 item	Mar. 31, 2012	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Jun. 19, 2012 General partner Common units	Mar. 31, 2013 Retail propane and distillate operations item	Mar. 31, 2013 Retail propane and distillate operations Minimum item	Oct. 03, 2011 Osterman	Nov. 30, 2012 Osterman	Mar. 31, 2013 Osterman	Oct. 03, 2011 Osterman Common units	Mar. 31, 2012 Osterman Common units	Nov. 01, 2011 SemStream item	Mar. 31, 2012 SemStream Common units	Nov. 01, 2011 SemStream Common units	Jan. 31, 2012 Pacer item	Jan. 03, 2012 Pacer	Jan. 03, 2012 Pacer Common units	Mar. 31, 2012 Pacer Common units	Feb. 03, 2012 North American	Mar. 31, 2013 Retail and distillate operations acquisitions item	Mar. 31, 2013 Retail and distillate operations acquisitions Common units	Mar. 31, 2013 High Sierra	Mar. 31, 2013 High Sierra Common units	Jun. 19, 2012 High Sierra Energy, LP	Jun. 19, 2012 High Sierra Energy, LP Common units	Nov. 02, 2012 Pecos	Mar. 31, 2013 Pecos	Nov. 12, 2012 Pecos Common units	Mar. 31, 2013 Pecos Common units	Nov. 12, 2012 Pecos Common units Call agreement	Nov. 02, 2012 Pecos Common units Call agreement Minimum	Nov. 02, 2012 Pecos Common units Call agreement Maximum	Mar. 31, 2013 Third Coast	Dec. 31, 2012 Third Coast	Jan. 11, 2013 Third Coast Common units	Mar. 31, 2013 Third Coast Common units	Dec. 31, 2012 Third Coast Common units Call agreement Minimum	Dec. 31, 2012 Third Coast Common units Call agreement Maximum	Mar. 31, 2013 Acquisitions to expand assets and operations of the entity's crude oil item	Dec. 31, 2012 Acquisitions to expand assets and operations of the entity's crude oil	Mar. 31, 2013 Acquisitions to expand assets and operations of the entity's crude oil Common units	Mar. 31, 2012 Retail propane operations item
Acquisitions Subsequent to Initial Public Offering
Number of common units issued to acquire ownership interests (in shares)				24,250,258	14,432,031							4,000,000	4,000,000		8,932,031	8,932,031			1,500,000	1,500,000			850,676		20,703,510		18,018,468			1,834,414	1,834,414						344,680	344,680					516,978
Cash paid to acquire ownership interests, net of cash acquired	$ 17,400,000	$ 490,402,000	$ 297,401,000						$ 94,900,000
Payment for specified working capital										4,800,000
Cash paid		14,000,000									94,873,000			91,000,000				32,213,000			69,800,000	71,392,000		239,251		91,800,000		132,400,000	87,444,000						35,000,000	35,000,000					52,552,000			6,400,000
Cash acquired																										5,000,000		2,200,000
Liabilities assumed in the form of non-compete agreements		5,000,000									4,763,000							2,700,000				6,600,000				97,400,000		10,200,000													1,300,000	1,300,000		700,000
Number of acquired natural gas liquids terminals														12
Number of companies associated with acquiree entity																	7
Value of common units issued to acquire ownership interests																		30,400,000
Number of business combination transactions		2																				6																			4			3
Amount paid						50,000,000
Common units issued						2,685,042																				18,018,468
Value of common units issued as consideration for acquisition																$ 184,800,000			$ 30,375,000					$ 414,794					$ 44,943,000		$ 44,943,000	$ 45,000,000	$ 45,000,000	$ 60,000,000			$ 8,000,000		$ 8,000,000	$ 10,000,000			$ 12,400,000
Number of states in which entity operates								20
Number of owned terminals							17

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Segment Information (Tables)

12 Months Ended

Mar. 31, 2013

Segment Information

Schedule of segments and their respective financial information

	NGL Energy Partners LP									NGL Supply
	Year			Year			Six Months			Six Months
	Ended			Ended			Ended			Ended
	March 31,			March 31,			March 31,			September 30,
	2013			2012			2011			2010
	(in thousands)
Revenues:
Crude oil logistics	$	2,339,148		$	—		$	—		$	—
Water services	62,227			—			—			—
Natural gas liquids logistics -
Propane sales	841,448			923,022			477,774			243,908
Other natural gas liquids sales	858,276			251,627			90,746			71,456
Storage revenues and other	33,954			2,462			1,183			959
Retail propane -
Propane sales	288,410			175,417			67,175			6,128
Distillate sales	106,192			6,547			—			—
Other retail sales	35,856			17,370			5,638			740
Other	4,233			—			—			—
Eliminations of intersegment sales	(151,977		)	(65,972		)	(20,284		)	(6,248		)
Total revenues	$	4,417,767		$	1,310,473		$	622,232		$	316,943
Depreciation and amortization:
Crude oil logistics	$	9,176		$	—		$	—		$	—
Water services	20,923			—			—			—
Natural gas liquids logistics	11,085			3,661			554			519
Retail propane	25,496			11,450			2,887			870
Other	2,173			—			—			—
Total depreciation and amortization	$	68,853		$	15,111		$	3,441		$	1,389
Operating income (loss):
Crude oil logistics	$	34,236		$	—		$	—		$	—
Water services	8,576			—			—			—
Natural gas liquids logistics	30,336			9,735			9,590			865
Retail propane	46,869			9,616			7,362			(2,569		)
Corporate and other	(32,710		)	(4,321		)	(2,115		)	(2,091		)
Total operating income (loss)	$	87,307		$	15,030		$	14,837		$	(3,795	)
Other items not allocated by segment:
Interest income	1,261			765			221			66
Interest expense	(32,994		)	(7,620		)	(2,482		)	(372		)
Loss on early extinguishment of debt	(5,769		)	—			—			—
Other income (expense), net	260			290			103			124
Income tax (provision) benefit	(1,875		)	(601		)	—			1,417
Net income (loss)	$	48,190		$	7,864		$	12,679		$	(2,560	)
Additions to property, plant and equipment, including acquisitions (accrual basis):
Crude oil logistics	$	89,860		$	—		$	—		$	—
Water services	137,116			—			—			—
Natural gas liquids logistics	15,129			50,276			290			15
Retail propane	66,933			150,181			41,152			386
Corporate and other	17,858			—			—			—
Total	$	326,896		$	200,457		$	41,442		$	401

	March 31,		March 31,
	2013		2012
	(in thousands)
Year-End Information:
Total assets:
Crude oil logistics	$	801,030	$	—
Water services	466,462		—
Natural gas liquids logistics	474,141		325,173
Retail propane	513,301		417,639
Corporate	36,413		6,707
Total	$	2,291,347	$	749,519
Long-lived assets, net of depreciation and amortization, including goodwill and intangibles:
Crude oil logistics	$	356,750	$	—
Water services	453,986		—
Natural gas liquids logistics	238,192		176,419
Retail propane	441,762		366,242
Corporate	31,996		5,468
Total	$	1,522,686	$	548,129

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Transactions with Affiliates (Tables)

12 Months Ended

Mar. 31, 2013

Transactions with Affiliates

Summary of purchase and sales transactions of products and services

These transactions are summarized in the table below for the years ended March 31, 2013 and 2012 (in thousands):

	2013		2012
Product sales to SemGroup	$	32,431	$	29,200
Product purchases from SemGroup	60,425		23,800
Payments to SemGroup for services	256		700
Sales to entities affiliated with High Sierra management	16,828		—
Purchases from entities affiliated with High Sierra management	60,942		—
Purchases from entities affiliated with retail segment management	273		300

Schedule of receivables from affiliates

Receivables from affiliates at March 31, 2013 and 2012 consist of the following (in thousands):

	2013		2012
Receivables from sales of product to SemGroup	$	—	$	1,878
Receivables from entities affiliated with High Sierra management	22,787		—
Other	96		404
	$	22,883	$	2,282

Schedule of payables to affiliates

Payables to related parties at March 31, 2013 and 2012 consist of the following (in thousands):

	2013		2012
Working capital settlement for Osterman combination	$	—	$	4,763
Payables to SemGroup	4,601		4,699
Payables to entities affiliated with High Sierra management	2,299
	$	6,900	$	9,462

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Goodwill

12 Months Ended

Mar. 31, 2013

Goodwill

Goodwill

Note 6 - Goodwill

Changes to goodwill were as follows for the periods indicated:

	NGL Energy Partners LP						NGL Supply
	Year		Year		Six Months		Six Months
	Ended		Ended		Ended		Ended
	March 31,		March 31,		March 31,		September 30,
	2013		2012		2011		2010
	(in thousands)
Beginning of period, as retrospectively adjusted (Note 4)	$	167,245	$	8,568	$	4,580	$	4,457
Goodwill from acquisitions, including additional consideration paid for previous acquisitions	395,901		158,677		3,988		123
End of period, as retrospectively adjusted (Note 4)	$	563,146	$	167,245	$	8,568	$	4,580
Goodwill by segment at end of period:
Crude oil logistics	$	244,073	$	—	$	—	$	—
Water services	119,668		—		—		—
Retail propane	112,269		90,287		6,534		2,546
Natural gas liquids logistics	87,136		76,958		2,034		2,034

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Goodwill (Details 2) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2011	Sep. 30, 2010	Sep. 30, 2010 NGL Supply	Mar. 31, 2010 NGL Supply	Mar. 31, 2013 Crude oil logistics	Mar. 31, 2013 Water services	Mar. 31, 2013 Retail propane	Mar. 31, 2012 Retail propane	Mar. 31, 2011 Retail propane	Sep. 30, 2010 Retail propane NGL Supply	Mar. 31, 2013 Natural gas liquids logistics	Mar. 31, 2012 Natural gas liquids logistics	Mar. 31, 2011 Natural gas liquids logistics	Sep. 30, 2010 Natural gas liquids logistics NGL Supply
Goodwill by segment
Goodwill	$ 563,146	$ 167,245	$ 8,568	$ 4,580	$ 4,580	$ 4,457	$ 244,073	$ 119,668	$ 112,269	$ 90,287	$ 6,534	$ 2,546	$ 87,136	$ 76,958	$ 2,034	$ 2,034

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Intangible Assets (Tables)

12 Months Ended

Mar. 31, 2013

Intangible Assets

Schedule of intangible assets

		March 31, 2013				March 31, 2012
						(Note 4)
		Gross Carrying		Accumulated		Gross Carrying		Accumulated
	Amortizable Lives	Amount		Amortization		Amount		Amortization
		(in thousands)
Amortizable -
Customer relationships	5-20 years*	$	407,835	$	30,959	$	128,071	$	3,868
Lease and other agreements	1-8 years	15,210		7,018		2,810		1,545
Non-compete agreements	2-7 years	11,855		2,871		5,033		919
Trade names	3-10 years	2,784		326		2,700		—
Debt issuance costs	5-10 years	19,494		2,981		7,310		1,842
Total amortizable		457,178		44,155		145,924		8,174
Non-amortizable -
Trade names	Indefinite	29,580		—		11,740		—
Total		$	486,758	$	44,155	$	157,664	$	8,174

*  The weighted-average amortization period for customer relationship intangible assets is approximately 11 years.

Schedule of amortization expense

	NGL Energy Partners LP						NGL Supply
	Year		Year		Six Months		Six Months
	Ended		Ended		Ended		Ended
	March 31,		March 31,		March 31,		September 30,
Recorded in	2013		2012		2011		2010
	(in thousands)
Depreciation and amortization	$	29,657	$	4,538	$	593	$	391
Interest expense	3,375		1,277		565		36
Loss on early extinguishment of debt	5,769		—		—		—
Cost of sales - natural gas liquids logistics	5,285		800		400		400
	$	44,086	$	6,615	$	1,558	$	827

Schedule of future amortization expense of intangible assets

Future amortization expense of our intangible assets is estimated to be as follows (in thousands):

Year Ending March 31,
2014	$	44,485
2015	43,137
2016	41,396
2017	39,567
2018	34,234
Thereafter	210,204
	$	413,023

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Summary of Significant Accounting Policies (Details 3) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended		6 Months Ended	12 Months Ended									6 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Mar. 31, 2011 Accounts Receivable - Trade:	Mar. 31, 2013 Accounts Receivable - Trade:	Mar. 31, 2012 Accounts Receivable - Trade:	Mar. 31, 2013 Accounts Receivable - Trade: Crude oil logistics	Mar. 31, 2013 Accounts Receivable - Trade: Water services	Mar. 31, 2013 Accounts Receivable - Trade: Natural gas liquids logistics	Mar. 31, 2012 Accounts Receivable - Trade: Natural gas liquids logistics	Mar. 31, 2013 Accounts Receivable - Trade: Retail propane	Mar. 31, 2012 Accounts Receivable - Trade: Retail propane	Mar. 31, 2013 Accounts Receivable - Trade: Other	Sep. 30, 2010 NGL Supply	Sep. 30, 2010 NGL Supply Accounts Receivable - Trade:
Accounts receivable
Gross Receivable					$ 564,649	$ 84,822	$ 360,721	$ 9,618	$ 144,267	$ 52,640	$ 49,233	$ 32,182	$ 810
Allowance for Doubtful Accounts		1,760	818	161	1,760	818	11	29	76	113	1,644	705			174
Changes in the allowance for doubtful accounts
Allowance for doubtful accounts, beginning of period		818			818	161	11	29	76	113	1,644	705			235
Bad debt provision	269	1,315	1,049	269	1,315	1,049								3	3
Write off of uncollectible accounts				(108)	(373)	(392)									(64)
Allowance for doubtful accounts, end of period		$ 1,760	$ 818	$ 161	$ 1,760	$ 818	$ 11	$ 29	$ 76	$ 113	$ 1,644	$ 705			$ 174

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Income Taxes

12 Months Ended

Mar. 31, 2013

Income Taxes

Income Taxes

Note 9 - Income Taxes

NGL Energy Partners LP

We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay U.S. 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 two taxable corporate subsidiaries in the United States and three taxable corporate subsidiaries in Canada. The income tax provision reported in our consolidated statements of operations relates primarily to these subsidiaries.

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 both of the calendar years since our initial public offering.

NGL Supply

NGL Supply’s income tax benefit of $1.4 million for the six months ended September 30, 2010 consisted primarily of U.S. federal deferred income taxes. This provision approximated the U.S. federal statutory rate of 35%.

Uncertain Tax Positions

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 positions 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. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount of benefit that is greater than 50 percent likely of being realized upon settlement. We had no material uncertain tax positions that required recognition in the consolidated financial statements at March 31, 2013 or 2012. Any interest or penalties would be recognized as a component of income tax expense. We consider NGL Supply’s open tax years to be 2008 through 2010; however, we are not responsible for any tax obligation related to such open tax years.

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Equity (Details 5) (NGL Supply, Inc., USD $)	0 Months Ended		1 Months Ended	6 Months Ended	12 Months Ended
	Oct. 14, 2010	May 17, 2010	Jun. 30, 2010	Sep. 30, 2010	Mar. 31, 2010
NGL Supply, Inc.
Equity
Redeemable preferred stock authorized (in shares)					1,000
Class A common stock authorized (in shares)					100,000
Par value of Class A common stock (in dollars per share)					$ 10
Stock options exercised (in shares)				650
Total consideration of stock options exercised				$ 1,400,000
Changes in net equity
BALANCES	36,811,000			46,403,000
Collection of stock options receivable	1,430,000
Net tax obligations of NGL Supply not assumed by the Partnership	3,120,000
Distribution to previous shareholders	(40,000,000)
Other	(109,000)
BALANCES	1,252,000			36,811,000	46,403,000
Redeemable Preferred Stock
Series A Preferred Stock outstanding					1,000
Redemption price per share (in dollars per share)					$ 3,000
Period of notice required for redemption of preferred shares					30 days
Accrued dividend of preferred stock		3,000,000
Common Stock Dividends
Common stock dividend paid			$ 7,000,000	$ 7,000,000

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Property, Plant and Equipment

12 Months Ended

Mar. 31, 2013

Property, Plant and Equipment

Property, Plant and Equipment

Note 5 - Property, Plant and Equipment

Property, plant and equipment consists of the following at March 31, 2013 and 2012:

				2012
Description and Depreciable Life	2013			(Note 4)
	(in thousands)
Natural gas liquids terminal assets (30 years)	$	63,637		$	62,024
Retail propane equipment (5-20 years)	152,802			119,972
Vehicles (5-10 years)	85,200			26,372
Water treatment facilities and equipment (3-30 years)	91,601			—
Crude oil tanks and loading facilities (2-30 years)	21,308			—
Barges and towboats (20 years)	21,135			—
Information technology equipment (3-5 years)	12,169			4,347
Buildings and leasehold improvements (5-30 years)	48,394			14,651
Land	21,604			13,084
Other (3-10 years)	17,288			3,108
Construction in progress	31,926			679
	567,064			244,237
Less: Accumulated depreciation	(50,127		)	(12,843		)
Property, plant and equipment, net	$	516,937		$	231,394

Depreciation expense was as follows for the periods indicated:

NGL Energy Partners LP						NGL Supply
Year		Year		Six Months		Six Months
Ended		Ended		Ended		Ended
March 31,		March 31,		March 31,		September 30,
2013		2012		2011		2010
(in thousands)
$	39,196	$	10,573	$	2,848	$	998

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Consolidated Statements of Cash Flows (USD $)	6 Months Ended	12 Months Ended		6 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply, Inc.
OPERATING ACTIVITIES:
Net income (loss)	$ 12,679,000	$ 48,190,000	$ 7,864,000	$ 2,560,000
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization, including debt issuance cost amortization	4,406,000	77,513,000	17,188,000	1,825,000
Loss on early extinguishment of debt		5,769,000
Non-cash equity-based compensation		8,670,000
(Gain) loss on sale of assets	16,000	187,000	(71,000)	(124,000)
Provision for doubtful accounts	269,000	1,315,000	1,049,000	3,000
(Gain) loss on commodity derivative financial instruments	(1,468,000)	4,376,000	(5,974,000)	(226,000)
Other	3,000	375,000	403,000	(1,409,000)
Changes in operating assets and liabilities, net of acquisitions -
Accounts receivable	(813,000)	2,430,000	(20,179,000)	203,000
Inventories	60,413,000	18,433,000	30,268,000	(59,598,000)
Product exchanges, net	(16,329,000)	1,816,000	4,775,000	18,688,000
Other current assets	3,697,000	20,769,000	9,569,000	(1,023,000)
Trade accounts payable	2,835,000	(17,281,000)	35,747,000	(3,741,000)
Accrued expenses and other payables	(1,209,000)	(9,592,000)	366,000	(2,699,000)
Accounts receivable/payable - affiliates, net		(19,690,000)	4,742,000
Advance payments received from customers	(30,490,000)	(11,049,000)	4,582,000	19,912,000
Net cash provided by (used in) operating activities	34,009,000	132,231,000	90,329,000	(30,749,000)
INVESTING ACTIVITIES:
Purchases of long-lived assets	(1,440,000)	(72,475,000)	(7,544,000)	(280,000)
Acquisitions of businesses, including acquired working capital	(17,400,000)	(490,402,000)	(297,401,000)	(123,000)
Net cash flows on non-hedge commodity derivative financial instruments	111,000	11,579,000	6,464,000	426,000
Proceeds from sales of assets	291,000	5,080,000	1,238,000	185,000
Other			346,000	125,000
Net cash provided by (used in) investing activities	(18,438,000)	(546,218,000)	(296,897,000)	333,000
FINANCING ACTIVITIES:
Issuance of senior notes		250,000,000
Proceeds from borrowings under revolving credit facilities	149,500,000	1,227,975,000	478,900,000	34,490,000
Payments on revolving credit facilities	(112,381,000)	(964,475,000)	(329,900,000)	(13,590,000)
Proceeds from borrowings under other long-term debt		653,000
Payments on other long-term debt	(5,902,000)	(4,837,000)	(1,278,000)	(722,000)
Debt issuance costs	(4,928,000)	(20,189,000)	(2,380,000)
Distributions to partners		(71,682,000)	(19,060,000)
Contributions	11,040,000	913,000	440,000
Proceeds from sale of common units, net of offering costs		(642,000)	74,759,000
Collection of NGL Supply stock option receivables	1,430,000
Deferred offering costs	(1,929,000)
Distributions to shareholders of NGL Supply	(40,000,000)
Common stock dividends				(7,000,000)
Other				(17,000)
Redemption of preferred stock				(3,000,000)
Repurchase of common units			(3,418,000)
Net cash provided by (used in) financing activities	(3,170,000)	417,716,000	198,063,000	10,161,000
EFFECT OF EXCHANGE RATE CHANGES ON CASH	(47,000)
Net increase (decrease) in cash and cash equivalents	12,354,000	3,729,000	(8,505,000)	(20,255,000)
Cash and cash equivalents, beginning of period	3,983,000	7,832,000	16,337,000	24,238,000
Cash and cash equivalents, end of period	$ 16,337,000	$ 11,561,000	$ 7,832,000	$ 3,983,000

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Acquisitions (Details 5) (USD $)	3 Months Ended								6 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Mar. 31, 2013 item	Mar. 31, 2012
Acquisitions
Number of business combination agreements										2
Liabilities assumed in the form of non-compete agreements	$ 5,000,000									$ 5,000,000
Consideration paid for acquisition
Cash paid to acquire ownership interests	14,000,000									14,000,000
Cost of sales contributed by retail combinations	1,481,890,000	1,204,545,000	1,053,690,000	298,985,000	389,806,000	439,790,000	201,454,000	185,973,000	583,032,000	4,039,110,000	1,217,023,000
Vehicles | Minimum
Estimated fair value of the assets acquired and liabilities assumed
Useful life of property, plant and equipment										5 years	5 years
Vehicles | Maximum
Estimated fair value of the assets acquired and liabilities assumed
Useful life of property, plant and equipment										10 years	10 years
Buildings | Minimum
Estimated fair value of the assets acquired and liabilities assumed
Useful life of property, plant and equipment											5 years
Common units
Acquisitions
Number of common units issued to acquire ownership interests (in shares)										24,250,258	14,432,031
Retail and distillate operations acquisitions
Acquisitions
Number of business combination agreements										6
Liabilities assumed in the form of non-compete agreements	6,600,000									6,600,000
General and administrative expense	300,000									300,000
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable	8,715,000									8,715,000
Inventory	5,155,000									5,155,000
Other current assets	1,228,000									1,228,000
Goodwill	21,983,000									21,983,000
Other noncurrent assets	784,000									784,000
Long-term debt	(6,594,000)									(6,594,000)
Other assumed liabilities	(12,511,000)									(12,511,000)
Consideration paid, net of cash acquired	90,266,000									90,266,000
Consideration paid for acquisition
Cash paid to acquire ownership interests	71,392,000									71,392,000
Total consideration paid	90,266,000									90,266,000
Revenues										124,300,000
Cost of sales contributed by retail combinations										86,600,000
Retail and distillate operations acquisitions | Trade names
Estimated fair value of the assets acquired and liabilities assumed
Intangible assets	2,924,000									2,924,000
Retail and distillate operations acquisitions | Customer relationships
Estimated fair value of the assets acquired and liabilities assumed
Intangible assets	16,890,000									16,890,000
Retail and distillate operations acquisitions | Customer relationships | Minimum
Estimated fair value of the assets acquired and liabilities assumed
Useful life of intangible assets										10 years
Retail and distillate operations acquisitions | Customer relationships | Maximum
Estimated fair value of the assets acquired and liabilities assumed
Useful life of intangible assets										15 years
Retail and distillate operations acquisitions | Non-compete agreements
Estimated fair value of the assets acquired and liabilities assumed
Intangible assets	1,387,000									1,387,000
Useful life of intangible assets										5 years
Retail and distillate operations acquisitions | Land
Estimated fair value of the assets acquired and liabilities assumed
Property, plant and equipment	1,945,000									1,945,000
Retail and distillate operations acquisitions | Tanks and other retail propane equipment
Estimated fair value of the assets acquired and liabilities assumed
Property, plant and equipment	28,763,000									28,763,000
Retail and distillate operations acquisitions | Tanks and other retail propane equipment | Minimum
Estimated fair value of the assets acquired and liabilities assumed
Useful life of property, plant and equipment										5 years
Retail and distillate operations acquisitions | Tanks and other retail propane equipment | Maximum
Estimated fair value of the assets acquired and liabilities assumed
Useful life of property, plant and equipment										20 years
Retail and distillate operations acquisitions | Vehicles
Estimated fair value of the assets acquired and liabilities assumed
Property, plant and equipment	11,344,000									11,344,000
Useful life of property, plant and equipment										5 years
Retail and distillate operations acquisitions | Buildings
Estimated fair value of the assets acquired and liabilities assumed
Property, plant and equipment	7,052,000									7,052,000
Useful life of property, plant and equipment										30 years
Retail and distillate operations acquisitions | Other
Estimated fair value of the assets acquired and liabilities assumed
Property, plant and equipment	1,201,000									1,201,000
Retail and distillate operations acquisitions | Common units
Acquisitions
Number of common units issued to acquire ownership interests (in shares)										850,676	850,676
Consideration paid for acquisition
Value of common units issued to acquire ownership interests	$ 18,900,000	$ 18,874,000								$ 18,900,000

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Earnings per Limited Partner Unit or Common Share (Details 2) (NGL Supply, USD $) In Thousands, except Share data, unless otherwise specified	6 Months Ended
	Sep. 30, 2010
NGL Supply
Earnings per limited partner unit or common share
Net loss attributable to parent equity	$ (2,515)
Less - preferred stock dividends	(17)
Net loss attributable to common shareholders	$ (2,532)
Weighted average common shares outstanding (in shares)	19,711
Basic and diluted loss per common share (in dollars per share)	$ (128.46)

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Equity (Tables)

12 Months Ended

Mar. 31, 2013

Equity

Schedule of unaudited pro forma information after conversion of units

	Historical			Unaudited Pro Forma
	Units	Amount		Units	Amount
	(U.S. Dollars in thousands, except per unit amounts)
Limited Partner Equity —
Common units	10,933,568	$	47,225	5,014,222	$	21,658
Subordinated units	—	—		5,919,346	25,567
	10,933,568	$	47,225	10,933,568	$	47,225
Earnings per unit, basic and diluted —
Common units		$	1.16		$	1.16
Subordinated units		$	—		$	1.16

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
Water services combination	516,978
Pecos combination	1,834,414
Third Coast combination	344,680
Total - year ended March 31, 2013	24,250,258

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	—

Schedule of restricted unit activity

The following table summarizes the restricted unit activity during the year ended March 31, 2013:

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

Summary of expected vesting of the awards

Vesting Date	Number of Awards
July 1, 2013	377,300
July 1, 2014	360,800
July 1, 2015	272,300
July 1, 2016	263,500
July 1, 2017	169,000
July 1, 2018	2,000
Total unvested units at March 31, 2013	1,444,900

Schedule of estimated share-based expense to be recorded on the awards granted

Year ending March 31,
2014	$	12,168
2015	7,516
2016	6,559
2017	4,613
2018	1,040
2019	15
Total	$	31,911

Schedule of changes in net equity of NGL Supply

The changes in net equity of NGL Supply for the period of September 30, 2010 to October 14, 2010 were as follows (in thousands):

Net equity at September 30, 2010	$	36,811
Collection of stock option receivable	1,430
Net tax obligations of NGL Supply not assumed by the Partnership	3,120
Distribution to previous shareholders	(40,000		)
Other	(109		)
Net carrying value of assets and liabilities contributed by NGL Supply	$	1,252

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

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					$	0.3375	99.9	%	0.1	%
First target distribution	above	$	0.3375	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	$	0.50625	76.9	%	23.1	%
Thereafter	above	$	0.50625				51.9	%	48.1	%

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Quarterly Financial Data (Unaudited) (Details) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended								6 Months Ended	12 Months Ended
	Mar. 31, 2013	Dec. 31, 2012	Sep. 30, 2012	Jun. 30, 2012	Mar. 31, 2012	Dec. 31, 2011	Sep. 30, 2011	Jun. 30, 2011	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012
Total revenues (in dollars)	$ 1,617,613	$ 1,338,208	$ 1,135,510	$ 326,436	$ 438,938	$ 470,649	$ 210,041	$ 190,845	$ 622,232	$ 4,417,767	$ 1,310,473
Total cost of sales	1,481,890	1,204,545	1,053,690	298,985	389,806	439,790	201,454	185,973	583,032	4,039,110	1,217,023
Net income (loss)	22,341	40,477	10,082	(24,710)	13,942	6,090	(5,395)	(6,773)	12,679	48,190	7,864
Net income (loss) to parent equity (in dollars)	$ 22,341	$ 40,176	$ 10,073	$ (24,650)	$ 13,954	$ 6,090	$ (5,395)	$ (6,773)	$ 12,679	$ 47,940	$ 7,876
Common units
Earnings (loss) per unit, basic and diluted -
BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT: (in dollars per unit)	$ 0.39	$ 0.75	$ 0.18	$ (0.76)	$ 0.47	$ 0.24	$ (0.36)	$ (0.53)	$ 1.16	$ 0.96	$ 0.32
BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING: (in shares)	47,665,015	46,364,381	44,831,836	26,529,133	23,263,386	18,699,590	8,864,222	9,883,342	10,933,568	41,353,574	15,169,983
Subordinated units
Earnings (loss) per unit, basic and diluted -
BASIC AND DILUTED EARNINGS PER LIMITED PARTNER UNIT: (in dollars per unit)	$ 0.39	$ 0.75	$ 0.18	$ (0.77)	$ 0.53	$ 0.28	$ (0.36)	$ (0.53)		$ 0.93	$ 0.58
BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING: (in shares)	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,919,346	5,199,346	2,927,149		5,919,346	5,175,384

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Long-Term Obligations (Details 2) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2013
Maturities
2014	$ 8,626
2015	6,456
2016	3,088
2017	2,091
2018	503,682
Thereafter	225,119
Total long-term debt	749,062
Revolving Credit Facility
Maturities
2018	477,500
Total long-term debt	477,500
Senior Notes
Maturities
2018	25,000
Thereafter	225,000
Total long-term debt	250,000
Other notes payable
Maturities
2014	8,626
2015	6,456
2016	3,088
2017	2,091
2018	1,182
Thereafter	119
Total long-term debt	$ 21,562

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Acquisitions (Details 12) (USD $)		12 Months Ended								6 Months Ended		6 Months Ended			6 Months Ended
	Mar. 31, 2013	Mar. 31, 2013 Common units	Mar. 31, 2012 Common units	Mar. 31, 2013 Vehicles Minimum	Mar. 31, 2012 Vehicles Minimum	Mar. 31, 2013 Vehicles Maximum	Mar. 31, 2012 Vehicles Maximum	Mar. 31, 2012 Buildings Minimum	Mar. 31, 2011 Hicksgas LLC and Gifford	Mar. 31, 2011 Hicksgas LLC and Gifford Common units	Mar. 31, 2011 Hicksgas LLC and Gifford Trade names	Mar. 31, 2011 Hicksgas LLC and Gifford Customer relationships	Mar. 31, 2011 Hicksgas LLC and Gifford Non-compete agreements	Mar. 31, 2011 Hicksgas LLC and Gifford Land	Mar. 31, 2011 Hicksgas LLC and Gifford Tanks and other retail propane equipment	Mar. 31, 2011 Hicksgas LLC and Gifford Vehicles	Mar. 31, 2011 Hicksgas LLC and Gifford Buildings	Mar. 31, 2011 Hicksgas LLC and Gifford Office equipment
Estimated fair value of the assets acquired and liabilities assumed
Accounts receivable									$ 5,669,000
Inventory									6,182,000
Other current assets									2,600,000
Total current assets									14,451,000
Property, plant and equipment														2,666,000	23,016,000	6,599,000	7,053,000	523,000
Useful life of property, plant and equipment				5 years	5 years	10 years	10 years	5 years							15 years	5 years	30 years	5 years
Intangible assets											830,000	2,170,000	550,000
Useful life of intangible assets												15 years	5 years
Goodwill									3,716,000
Total assets acquired									61,574,000
Accounts payable									1,837,000
Customer advances and deposits									12,089,000
Accrued and other current liabilities									2,152,000
Total current liabilities									16,078,000
Long-term debt									5,768,000
Other long-term liabilities									274,000
Total liabilities assumed									22,120,000
Consideration paid, net of cash acquired									39,454,000
Cash paid to acquire ownership interests	14,000,000								17,200,000
Number of common units issued to acquire ownership interests (in shares)		24,250,258	14,432,031							4,154,757
Value of common units issued to acquire ownership interests										$ 22,300,000
Issue price of units (in dollars per unit)										$ 5.37

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Fair Value of Financial Instruments

12 Months Ended

Mar. 31, 2013

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. The carrying amounts of our debt obligations reasonably approximate their fair values at March 31, 2013, as most of our debt is subject to terms that were recently negotiated.

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, 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	(3,503		)	3,503
Cash collateral provided or held	(1,760		)	400
Commodity contracts reported on consolidated balance sheet	$	5,595		$	(12,701	)

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2012:

	Derivative		Derivative
	Assets		Liabilities
	(in thousands)
Level 1 measurements	$	—	$	—
Level 2 measurements	—		(36		)
	—		(36		)
Netting of counterparty contracts	—		—
Cash collateral provided or held	—		—
Commodity contracts reported on consolidated balance sheet	$	—	$	(36	)

The commodity derivative assets (liabilities) are reported in the following accounts on the consolidated balance sheets:

	March 31,			March 31,
	2013			2012
	(in thousands)
Prepaid expenses and other current assets	$	5,551		$	—
Other noncurrent assets	44			—
Accrued expenses and other payables	(12,701		)	(36		)
Net liability	$	(7,106	)	$	(36	)

The following table sets forth our open commodity derivative contract positions at March 31, 2013 and 2012. We do not account for these derivatives as hedges.

Contracts	Settlement Period	Total Notional Units (Barrels)		Fair Value of Net Assets (Liabilities)
		(in thousands)
As of March 31, 2013 -
Propane swaps (1)	April 2013 - March 2014	(282	)	$	3,197
Heating oil calls and futures (2)	May 2013 - June 2013	8		79
Crude swaps (3)	April 2013 - June 2014	(91	)	153
Crude - butane spreads (4)	April 2013 - March 2014	(1,116	)	(7,651		)
Crude forwards (5)	April 2013 - March 2014	(144	)	1,033
Butane forwards (6)	April 2013 - March 2014	1,546		(2,557		)
				(5,746		)
Net cash collateral held				(1,360		)
Net fair value of commodity derivatives on consolidated balance sheet				$	(7,106	)
As of March 31, 2012 -
Propane swaps	April 2012 - March 2013	(460	)	$	(36	)

(1) Propane swaps — Our natural gas liquids logistics 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 swaps” represent financial derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.

(2) Heating oil calls and futures — Our retail segment offers our customers the opportunity to purchase a specified volume of heating oil at a fixed price. The contracts listed in this table as “heating oil calls and futures” represent financial derivatives we have entered into as an economic hedge against the risk that heating oil prices will rise between the time we entered into the fixed price sale commitment with the customers and the time we will the purchase heating oil to sell to the customers.

(3) Crude swaps — Our crude oil logistics segment routinely enters into crude oil purchase and sale contracts that are priced based on a crude oil index. 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 swaps” represent hedges against the risk that changes in the different index prices would reduce the margins between the purchase and the sale transactions.

(4) Crude-butane spreads — Our natural gas liquids logistics segment enters into forward contracts to sell butane at a price that will be calculated as a specified percentage of a crude oil index at the delivery date. The contracts listed in this table as “crude — butane spreads” represent financial derivatives we have entered into as economic hedges against the risk that the spread between butane prices and crude prices will narrow between the time we entered into the butane forward sale contracts and the expected delivery dates.

(5) Crude forwards — 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 forwards” represent financial derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding inventory.

(6) Butane forwards — Our natural gas liquids logistics segment routinely purchases butane inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as “butane forwards” represent financial derivatives we have entered into as an economic hedge against the risk that butane prices will decline while we are holding inventory.

We recorded the following net gains (losses) from our commodity and interest rate derivatives during the periods indicated:

	NGL Energy Partners LP								NGL Supply
	Year			Year			Six Months		Six Months
	Ended			Ended			Ended		Ended
	March 31,			March 31,			March 31,		September 30,
	2013			2012			2011		2010
	(in thousands)
Commodity contracts -
Unrealized gain (loss)	$	(5,275	)	$	(4,384	)	$	1,357	$	(200	)
Realized gain	899			10,351			111		426
Interest rate swaps	(5		)	(291		)	224		—
Total	$	(4,381	)	$	5,676		$	1,692	$	226

The commodity contract gains and losses are included in cost of sales in the consolidated statements of operations.

Interest Rate Swap Agreement

We have entered into an interest rate swap agreement to hedge the risk of interest rate fluctuations on our long-term debt. This agreement converts a portion of our revolving credit facility floating rate debt into fixed rate debt on a notional amount of $8.5 million and ends on December 31, 2013. The notional amounts of derivative instruments do not represent actual amounts exchanged between the parties, but instead represent amounts on which the contracts are based. The floating interest rate payments under these swaps are based on three-month LIBOR rates. We do not account for this agreement as a hedge. We recorded a liability of less than $0.1 million at March 31, 2013 and a liability of $0.1 million at March 31, 2012 related to this agreement.

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.

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.

We acquired a crude oil logistics business in our June 2012 merger with High Sierra. 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 business are generally higher than the receivables from customers in 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

The interest rate on our revolving credit facility floats based on market indices. At March 31, 2013, we have $461.5 million of debt on our revolving credit facility at a rate of 3.21% and $16.0 million of debt on our revolving credit facility at a rate of 5.25%. A change of 0.125% in the interest rate would result in a change to annual interest expense of approximately $0.6 million on the revolving debt balance of $477.5 million. We believe that the interest rates of the revolving credit facility are consistent with current market rates, and that the book value of the debt approximates fair value.

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Long-Term Obligations

12 Months Ended

Mar. 31, 2013

Long-Term Obligations

Long-Term Obligations

Note 8 - Long-Term Obligations

We have the following long-term debt:

	March 31,
	2013		2012
	(in thousands)
Revolving credit facility —
Expansion capital loans	$	441,500	$	—
Working capital loans	36,000		—
Previous revolving credit facility —
Acquisition loans	—		186,000
Working capital loans	—		28,000
Senior notes	250,000		—
Other notes payable	21,562		4,711
	749,062		218,711
Less current maturities	8,626		19,534
Long-term debt	$	740,436	$	199,177

On June 19, 2012, we entered into a credit agreement (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”). Also on June 19, 2012, we entered into a note purchase agreement (the “Note Purchase Agreement”) whereby we issued $250 million of Senior Notes in a private placement (the “Senior Notes”). We used the proceeds from the issuance of the Senior Notes and borrowings under the Credit Agreement to repay existing debt and to fund the merger with High Sierra.

Credit Agreement

The Working Capital Facility had a total capacity of $242.5 million for cash borrowings and letters of credit at March 31, 2013. At March 31, 2013, we had outstanding cash borrowings of $36.0 million and outstanding letters of credit of $60.1 million on the Working Capital Facility, leaving a remaining capacity of $146.4 million at March 31, 2013. The Expansion Capital Facility had a total capacity of $527.5 million for cash borrowings at March 31, 2013. At March 31, 2013, we had outstanding cash borrowings of $441.5 million on the Expansion Capital Facility, leaving a remaining capacity of $86.0 million at March 31, 2013. 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. At March 31, 2013, the borrowing base provisions of the Credit Agreement did not have any impact on the capacity available under the Working Capital Facility.

During May 2013, we entered into an amendment to the Credit Agreement that increased the total capacity on the Working Capital Facility from $242.5 million to $325.0 million and increased the total capacity on the Expansion Capital Facility from $527.5 million to $725.0 million. We paid approximately $2.1 million of fees related to this amendment to the Credit Agreement.

The commitments under the Credit Agreement expire on June 19, 2017. 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 1.75% to 2.75% per annum or (ii) an adjusted LIBOR rate plus a margin of 2.75% to 3.75% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At March 31, 2013, the interest rate in effect on outstanding LIBOR borrowings was 3.21%, calculated as the LIBOR rate of 0.21% plus a margin of 3.0%. At March 31, 2013, interest rate in effect on outstanding base rate borrowings was 5.25%, calculated as the base rate of 3.25% plus a margin of 2.0%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. 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, 2013, our leverage ratio was approximately 3.0 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, 2013, our interest coverage ratio was approximately 7.0 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, 2013, we were in compliance with all covenants under the Credit Agreement.

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 is 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 million, (iv) the rendering of a judgment for the payment of money in excess of $10 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, 2013, we were in compliance with all covenants under the Note Purchase Agreement.

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.

Balances Outstanding and Rates

At March 31, 2013, our outstanding borrowings and interest rates under our revolving credit facility were as follows (dollars in thousands):

	Amount		Rate
Expansion capital facility —
LIBOR borrowings	$	441,500	3.21	%
Working capital facility —
LIBOR borrowings	20,000		3.21	%
Base rate borrowings	16,000		5.25	%

Other Notes Payable

We have executed various non-interest bearing notes, payable primarily related to acquisitions described in Note 4. We also acquired certain notes payable in our acquisition of Pecos that relate to equipment financing; the interest rates on these notes payable range from 2.6% to 4.9% at March 31, 2013. 

Debt Maturity Schedule

The future maturities of our long-term debt are as follows as of March 31, 2013 (in thousands):

	Revolving				Other
	Credit		Senior		Notes
Year ending March 31,	Facility		Notes		Payable		Total
2014	$	—	$	—	$	8,626	$	8,626
2015	—		—		6,456		6,456
2016	—		—		3,088		3,088
2017	—		—		2,091		2,091
2018	477,500		25,000		1,182		503,682
Thereafter	—		225,000		119		225,119
	$	477,500	$	250,000	$	21,562	$	749,062

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified	12 Months Ended		13 Months Ended	1 Months Ended
	Mar. 31, 2013 High Sierra	Mar. 31, 2013 Pecos	May 30, 2013 Pecos	Mar. 31, 2013 Pemex High Sierra	May 31, 2010 Associated Producers item
Legal contingencies
Amount for settlement of litigation				$ 3.1
Number of lawsuits filed					2
Amount not paid by customer for disputed transportation rate schedule		2.2
Amount requested as refund by the customer			5.5
Amount of fuel taxes and sales taxes that should have been collected from customers and remitted to taxing authority	14.9
Amount expected to be recovered from the customers, if required to pay the taxes assessed	14.1
Asset retirement obligations
Asset retirement obligations	$ 1.5

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Transactions with Affiliates

12 Months Ended

Mar. 31, 2013

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 had the right to appoint two members to the Board of Directors of our general partner. Subsequent to November 1, 2011, our natural gas liquids logistics segment has sold natural gas liquids to and purchased natural gas liquids from affiliates of SemGroup. These transactions are included within revenues and cost of sales of our natural gas liquids logistics business in our consolidated statements of operations. We also made payments to SemGroup for certain administrative and operational services. These transactions are reported within operating and general and administrative expenses in our consolidated statements of operations.

Certain members of management of High Sierra who joined our management team upon completion of the June 19, 2012 merger with High Sierra own interests in several entities. Subsequent to this business combination with High Sierra, we have purchased products and services from and have sold products and services to these entities. The majority of these transactions relate to crude oil purchases and crude oil transportation services and are reported within cost of sales in our consolidated statements of operations, although approximately $3.1 million of these transactions during the year ended March 31, 2013 represented capital expenditures and were recorded as increases to property, plant and equipment. Product sales to these entities have been recorded within revenues in our consolidated statement of operations. In addition, our retail operations purchased goods and services from certain entities owned by our executive officers and their family members.

These transactions are summarized in the table below for the years ended March 31, 2013 and 2012 (in thousands):

	2013		2012
Product sales to SemGroup	$	32,431	$	29,200
Product purchases from SemGroup	60,425		23,800
Payments to SemGroup for services	256		700
Sales to entities affiliated with High Sierra management	16,828		—
Purchases from entities affiliated with High Sierra management	60,942		—
Purchases from entities affiliated with retail segment management	273		300

In addition to the amounts shown in the table above, we completed two business combinations during the year ended March 31, 2013 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.

Receivables from affiliates at March 31, 2013 and 2012 consist of the following (in thousands):

	2013		2012
Receivables from sales of product to SemGroup	$	—	$	1,878
Receivables from entities affiliated with High Sierra management	22,787		—
Other	96		404
	$	22,883	$	2,282

Payables to related parties at March 31, 2013 and 2012 consist of the following (in thousands):

	2013		2012
Working capital settlement for Osterman combination	$	—	$	4,763
Payables to SemGroup	4,601		4,699
Payables to entities affiliated with High Sierra management	2,299
	$	6,900	$	9,462

As described in Note 1, we completed a merger with High Sierra Energy, LP and High Sierra Energy GP, LLC in June 2012, which involved certain transactions with our general partner. 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.

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Employee Benefit Plan

12 Months Ended

Mar. 31, 2013

Employee Benefit Plan

Employee Benefit Plan

Note 13 - Employee Benefit Plan

We sponsor a 401(k) defined contribution plan for the benefit of our employees. For the years ended March 31, 2013 and 2012, and the six months ended March 31, 2011 and September 30, 2010, we made contributions to the plan totaling $1.9 million, $0.5 million, $0.2 million and $0.1 million, respectively.

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Document and Entity Information (USD $)	12 Months Ended
	Mar. 31, 2013	Sep. 30, 2012	Jun. 07, 2013 Common units	Jun. 07, 2013 Subordinated units
Entity Registrant Name	NGL Energy Partners LP
Entity Central Index Key	0001504461
Document Type	10-K
Document Period End Date	Mar. 31, 2013
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	Accelerated Filer
Entity Public Float		$ 504,278,498
Entity Common Stock, Shares Outstanding			49,147,964	5,919,346
Document Fiscal Year Focus	2013
Document Fiscal Period Focus	FY

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Segment Information

12 Months Ended

Mar. 31, 2013

Segment Information

Segment Information

Note 14 - Segment Information

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. These operations began with our June 2012 merger with High Sierra.

Our water services segment provides services for the transportation, treatment, and disposal of wastewater generated from oil and natural gas production, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. These operations began with our June 2012 merger with High Sierra.

Our natural gas liquids logistics segment supplies propane and other natural gas liquids, and provides natural gas liquids transportation, terminalling, and storage services to retailers, wholesalers, and refiners. This segment includes our historical natural gas liquids operations and the natural gas liquids operations acquired in the June 2012 merger with High Sierra. We previously reported our natural gas liquids operations in two segments, referred to as our “wholesale marketing and supply” and “midstream” segments. The data in the table below has been presented under our new structure for all periods, with the amounts previously reported in the wholesale marketing and supply and midstream segments reported on a combined basis within the natural gas liquids logistics segment.

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.

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 also include 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.

	NGL Energy Partners LP									NGL Supply
	Year			Year			Six Months			Six Months
	Ended			Ended			Ended			Ended
	March 31,			March 31,			March 31,			September 30,
	2013			2012			2011			2010
	(in thousands)
Revenues:
Crude oil logistics	$	2,339,148		$	—		$	—		$	—
Water services	62,227			—			—			—
Natural gas liquids logistics -
Propane sales	841,448			923,022			477,774			243,908
Other natural gas liquids sales	858,276			251,627			90,746			71,456
Storage revenues and other	33,954			2,462			1,183			959
Retail propane -
Propane sales	288,410			175,417			67,175			6,128
Distillate sales	106,192			6,547			—			—
Other retail sales	35,856			17,370			5,638			740
Other	4,233			—			—			—
Eliminations of intersegment sales	(151,977		)	(65,972		)	(20,284		)	(6,248		)
Total revenues	$	4,417,767		$	1,310,473		$	622,232		$	316,943
Depreciation and amortization:
Crude oil logistics	$	9,176		$	—		$	—		$	—
Water services	20,923			—			—			—
Natural gas liquids logistics	11,085			3,661			554			519
Retail propane	25,496			11,450			2,887			870
Other	2,173			—			—			—
Total depreciation and amortization	$	68,853		$	15,111		$	3,441		$	1,389
Operating income (loss):
Crude oil logistics	$	34,236		$	—		$	—		$	—
Water services	8,576			—			—			—
Natural gas liquids logistics	30,336			9,735			9,590			865
Retail propane	46,869			9,616			7,362			(2,569		)
Corporate and other	(32,710		)	(4,321		)	(2,115		)	(2,091		)
Total operating income (loss)	$	87,307		$	15,030		$	14,837		$	(3,795	)
Other items not allocated by segment:
Interest income	1,261			765			221			66
Interest expense	(32,994		)	(7,620		)	(2,482		)	(372		)
Loss on early extinguishment of debt	(5,769		)	—			—			—
Other income (expense), net	260			290			103			124
Income tax (provision) benefit	(1,875		)	(601		)	—			1,417
Net income (loss)	$	48,190		$	7,864		$	12,679		$	(2,560	)
Additions to property, plant and equipment, including acquisitions (accrual basis):
Crude oil logistics	$	89,860		$	—		$	—		$	—
Water services	137,116			—			—			—
Natural gas liquids logistics	15,129			50,276			290			15
Retail propane	66,933			150,181			41,152			386
Corporate and other	17,858			—			—			—
Total	$	326,896		$	200,457		$	41,442		$	401

	March 31,		March 31,
	2013		2012
	(in thousands)
Year-End Information:
Total assets:
Crude oil logistics	$	801,030	$	—
Water services	466,462		—
Natural gas liquids logistics	474,141		325,173
Retail propane	513,301		417,639
Corporate	36,413		6,707
Total	$	2,291,347	$	749,519
Long-lived assets, net of depreciation and amortization, including goodwill and intangibles:
Crude oil logistics	$	356,750	$	—
Water services	453,986		—
Natural gas liquids logistics	238,192		176,419
Retail propane	441,762		366,242
Corporate	31,996		5,468
Total	$	1,522,686	$	548,129

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Goodwill (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended		6 Months Ended
	Mar. 31, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply
Changes to goodwill
Beginning of the period, as retrospectively adjusted	$ 4,580	$ 167,245	$ 8,568	$ 4,457
Goodwill from acquisitions, including additional consideration paid for previous acquisitions	3,988	395,901	158,677	123
End of period, as retrospectively adjusted	$ 8,568	$ 563,146	$ 167,245	$ 4,580

XML

Property, Plant and Equipment (Details) (USD $) In Thousands, unless otherwise specified	6 Months Ended	12 Months Ended		6 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, 2011	Mar. 31, 2013	Mar. 31, 2012	Sep. 30, 2010 NGL Supply	Mar. 31, 2013 Natural gas liquids terminal assets	Mar. 31, 2012 Natural gas liquids terminal assets	Mar. 31, 2013 Retail propane equipment	Mar. 31, 2012 Retail propane equipment	Mar. 31, 2013 Retail propane equipment Minimum	Mar. 31, 2012 Retail propane equipment Minimum	Mar. 31, 2013 Retail propane equipment Maximum	Mar. 31, 2012 Retail propane equipment Maximum	Mar. 31, 2013 Vehicles	Mar. 31, 2012 Vehicles	Mar. 31, 2013 Vehicles Minimum	Mar. 31, 2012 Vehicles Minimum	Mar. 31, 2013 Vehicles Maximum	Mar. 31, 2012 Vehicles Maximum	Mar. 31, 2013 Water treatment facilities and equipment	Mar. 31, 2013 Water treatment facilities and equipment Minimum	Mar. 31, 2012 Water treatment facilities and equipment Minimum	Mar. 31, 2013 Water treatment facilities and equipment Maximum	Mar. 31, 2012 Water treatment facilities and equipment Maximum	Mar. 31, 2013 Crude oil tanks and loading facilities	Mar. 31, 2013 Crude oil tanks and loading facilities Minimum	Mar. 31, 2012 Crude oil tanks and loading facilities Minimum	Mar. 31, 2013 Crude oil tanks and loading facilities Maximum	Mar. 31, 2012 Crude oil tanks and loading facilities Maximum	Mar. 31, 2013 Barges and towboats	Mar. 31, 2012 Barges and towboats	Mar. 31, 2013 Information technology equipment	Mar. 31, 2012 Information technology equipment	Mar. 31, 2013 Information technology equipment Minimum	Mar. 31, 2012 Information technology equipment Minimum	Mar. 31, 2013 Information technology equipment Maximum	Mar. 31, 2012 Information technology equipment Maximum	Mar. 31, 2013 Buildings and leasehold improvements	Mar. 31, 2012 Buildings and leasehold improvements	Mar. 31, 2013 Buildings and leasehold improvements Minimum	Mar. 31, 2012 Buildings and leasehold improvements Minimum	Mar. 31, 2013 Buildings and leasehold improvements Maximum	Mar. 31, 2012 Buildings and leasehold improvements Maximum	Mar. 31, 2013 Land	Mar. 31, 2012 Land	Mar. 31, 2013 Other	Mar. 31, 2012 Other	Mar. 31, 2013 Other Minimum	Mar. 31, 2012 Other Minimum	Mar. 31, 2013 Other Maximum	Mar. 31, 2012 Other Maximum	Mar. 31, 2013 Construction in progress	Mar. 31, 2012 Construction in progress
Property, Plant and Equipment
DEPRECIABLE life					30 years	30 years			5 years	5 years	20 years	20 years			5 years	5 years	10 years	10 years		3 years	3 years	30 years	30 years		2 years	2 years	30 years	30 years	20 years	20 years			3 years	3 years	5 years	5 years			5 years	5 years	30 years	30 years					3 years	3 years	10 years	10 years
Property, plant and equipment, gross		$ 567,064	$ 244,237		$ 63,637	$ 62,024	$ 152,802	$ 119,972					$ 85,200	$ 26,372					$ 91,601					$ 21,308					$ 21,135		$ 12,169	$ 4,347					$ 48,394	$ 14,651					$ 21,604	$ 13,084	$ 17,288	$ 3,108					$ 31,926	$ 679
Less: Accumulated depreciation		(50,127)	(12,843)
Property, plant and equipment, net		516,937	231,394
Depreciation expense	$ 2,848	$ 39,196	$ 10,573	$ 998