NGL Energy Partners
Annual Report 2013

Plain-text annual report

Table of Contents UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 Form 10-K xx ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934 For the fiscal year ended March 31, 2013 or oo TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT 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) Delaware27-3427920(State or Other Jurisdiction of Incorporation or Organization)(I.R.S. Employer Identification No.) 6120 South Yale AvenueSuite 805Tulsa, Oklahoma74136(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 ClassName of Each Exchange on Which RegisteredCommon Units Representing Limited Partner InterestsNew 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 1934during 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 filingrequirements 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 Filerequired 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 suchshorter 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 thebest 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 thisForm 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. Seethe definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. Large accelerated filer oAccelerated filer x Non-accelerated filer oSmaller 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 ofthe Common Units on the New York Stock Exchange on such date ($24.04 per Common Unit) was approximately $504,278,498. For purposes of thiscomputation, all executive officers, directors and 10% owners of the registrant are deemed to be affiliates. Such a determination should not be deemed anadmission 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 TABLE OF CONTENTS PART I Item 1.Business3Item 1A.Risk Factors22Item 1B.Unresolved Staff Comments44Item 2.Properties44Item 3.Legal Proceedings45Item 4.Mine Safety Disclosures45 PART II Item 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities46Item 6.Selected Financial Data47Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations50Item 7A.Quantitative and Qualitative Disclosures About Market Risk84Item 8.Financial Statements and Supplementary Data85Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure85Item 9A.Controls and Procedures85Item 9B.Other Information86 PART III Item 10.Directors, Executive Officers and Corporate Governance87Item 11.Executive Compensation93Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters103Item 13.Certain Relationships and Related Transactions and Director Independence107Item 14.Principal Accountant Fees and Services111 PART IV Item 15.Exhibits and Financial Statement Schedules112 iTable of Contents 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, aswell as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement that does not relatestrictly 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 toidentify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based arereasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to avariety of risks, uncertainties, and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, ouractual results may vary materially from those anticipated, estimated, projected, or expected. Among the key risk factors that may have a direct bearing on ourresults 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 ofcapacity 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 transportationservices; · 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; 1Table of Contents · 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 newinterpretations by regulatory agencies concerning such laws and regulations and the impact of such laws and regulations (now existing or in thefuture) on our business operations, including our sales of crude oil, condensate, and natural gas liquids, our processing of wastewater, andtransportation 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 ofnew information, future events, or otherwise. When considering forward-looking statements, please review the risks described under “Item 1A — RiskFactors.” 2Table of Contents PART I References in this annual report to (i) “NGL Energy Partners LP,” “we,” “our,” “us” or similar terms refer to NGL Energy Partners LPand 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 EnergyPartners LP, (iv) “NGL Supply” refers to NGL Supply, Inc. for periods prior to our formation and refers to NGL Supply, LLC, a wholly ownedsubsidiary of NGL Energy Operating LLC, for periods after our formation (v) “Hicksgas” refers to the combined assets and operations of HicksgasGifford, Inc., which we refer to as Gifford, and Hicksgas, LLC, a wholly owned subsidiary of NGL Energy Operating LLC, which we refer to as HicksLLC, (vi) the “NGL Energy GP Investor Group” refers to, collectively, the 32 individuals and entities that own all of the outstanding membershipinterests in our general partner (vii) the “NGL Energy LP Investor Group” refers to, collectively, the 15 individuals and entities that owned all of ouroutstanding common units before the closing date of our initial public offering, and (viii) the “NGL Energy Investor Group” refers to, collectively, theNGL 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 notinclude 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 andcombined the assets and operations of NGL Supply, primarily a wholesale propane and terminalling business founded in 1967, and Hicksgas, primarily aretail 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 oiland 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 liquidslogistics 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 AnnualReport 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’spropane and propane-related assets. The shareholders of Gifford contributed all of their shares of stock in Gifford to a newly formed holdingcompany, 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% generalpartner interest in us and incentive distribution rights and the IEP Parties (owner of a 32.53% interest in our general partner) made a cash capitalcontribution to us in the aggregate amount of approximately $11.0 million in exchange for an aggregate 18.67% limited partner interest in us. 3Table of Contents · NGL Supply and Gifford each converted into a limited liability company and the members of NGL Supply, Hicksgas, LLC and Giffordcontributed 100% of their respective membership interests in those entities to us as capital contributions in exchange for (i) in the case of NGLSupply, 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 paidapproximately $27.9 million of existing indebtedness of NGL Supply, (ii) in the case of Hicksgas, LLC, a 37.96% limited partner interest inus, a cash distribution of approximately $1.6 million and our agreement to pay or cause to be paid approximately $6.5 million of existingindebtedness 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 ownedoperating 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 thesymbol “NGL.” We sold a total of 4,025,000 common units (including the exercise by the underwriters of their option to purchase additional common unitsfrom 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 totaloffering costs of approximately $9.0 million, were used to repay advances under our acquisition credit facility and for general partnership purposes. Proceedsfrom 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 usedto 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 andthe redemption, we had outstanding 8,864,222 common units, 5,919,346 subordinated units, a 0.1% general partner interest and incentive distributionrights, or IDRs. The public owned an approximately 27.2% limited partner interest in us and the NGL Energy LP Investor Group owned an approximately72.7% limited partner interest in us. IDRs entitle the holder to specified increasing percentages of cash distributions as our per-unit cash distributions increaseabove 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 thefollowing: · On October 3, 2011, we completed a business combination transaction with E. Osterman Propane, Inc., its affiliated companies and membersof the Osterman family (collectively, “Osterman”), whereby we acquired retail propane operations in the northeastern United States. We issued4,000,000 common units and paid $94.9 million of cash, net of cash acquired, in exchange for the assets and operations of Osterman. Theagreement also contemplated a post-closing payment of $4.8 million for certain specified working capital items, which we paid inNovember 2012. · On November 1, 2011, we completed a business combination transaction with SemStream, L.P. (“SemStream”), whereby we acquiredSemStream’s wholesale natural gas liquids supply and marketing operations and its 12 natural gas liquids terminals. We issued 8,932,031common 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 commonunits, valued at $30.4 million, and paid $32.2 million of cash in exchange for the assets and operations of Pacer, including working capital. Wealso 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 weacquired retail propane and distillate operations in the northeastern United States. We paid $69.8 million of cash in exchange for the assets andoperations 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. Ona combined basis, we paid $6.4 million of cash for these assets and operations, including working capital. We also assumed $0.7 million oflong-term debt in the form of non-compete agreements. 4Table of Contents · 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 alsopaid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLCby paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLCto 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 itsaffiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texasand New Mexico. We paid cash of $132.4 million at closing (net of $2.2 million of cash acquired), subject to customary post-closingadjustments, 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 aminimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners of Pecospurchased 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 companymembership interests in Third Coast Towing, LLC (“Third Coast”) for $43.0 million in cash. The business of Third Coast consists primarilyof 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 ofThird 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 distillateoperations, primarily in the northeastern and southeastern United States. On a combined basis, we paid $71.4 million of cash and issued850,676 common units in exchange for these assets and operations, including working capital. We also assumed $6.6 million of long-termdebt 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 andwater 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. 5Table of Contents 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 6Table of Contents 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: 7Table of Contents 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 stabilityof 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 ourability to transport crude oil from the wellhead to refiners, wastewater from the wellhead to treatment for disposal, recycle, or discharge, andtransport 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 ofreturn. We believe that there are accretive organic growth opportunities that originate from assets we have acquired. We also believe that there arefurther 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. Weintend 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 andassets 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, ormargin-based revenues. We believe that expanding our retail propane business with an emphasis on a high level of residential customers and ahigh level of company-owned tanks will result in strong customer retention rates and consistent operating margins. In our natural gas liquidslogistics and crude oil logistics segments, we intend to focus on back-to-back contracts which minimize commodity price exposure. In our waterservices segment, cash flows are typically supported by fee-based contracts, some of which include acreage dedications from producers orvolume commitments. These contracts not only help minimize commodity price exposure but also provide a degree of certainty with respect tovolumes and provide stable cash flows. · Maintain a disciplined capital structure characterized by low leverage. We target leverage levels that are consistent with those of investmentgrade companies. Through our disciplined approach to leverage, we maintain sufficient liquidity to manage existing and future capitalrequirements. · Maintain a disciplined cash distribution policy that complements our acquisition and organic growth strategies. We intend to use cashflows 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 toexecute 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 thefollowing competitive strengths: · Our seasoned management team with extensive midstream industry experience and a track record of acquiring, integrating, operatingand 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 theUnited 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 orexpand our existing operations. · Our vertically integrated and diversified operations, which help us generate more predictable and stable cash flows on a year-to-yearbasis. Our ability to provide multiple services to producers in numerous geographic areas enhances our competitive position. Our retail propanebusiness sources propane through our natural gas liquids logistics business, which allows us to leverage the expertise of our natural gas liquidslogistics business to help improve our margins and profitability and enhance our cash flows. Furthermore, we believe that our natural gasliquids 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 thisexpansive 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 waterprocessing facilities are located among the most prolific oil and gas producing basins in the U.S., including the Permian, Niobrara, and EagleFord shale plays. In addition, we believe that the technological capabilities of our water processing business can be quickly implemented at newfacilities and locations. · Our network of natural gas liquids transportation, terminal, and storage assets, which allow us to provide multiple services over thecontinental United States. Our strategically located terminals, large rail car fleet, shipper status on common carrier pipelines, and substantialleased 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 highermargins than other customers. Our high percentage of propane tank ownership, payment billing systems, and automatic delivery programhave 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, storageterminals, barge loading facilities, rail facilities, refineries, and other trade hubs. Our operations are centered near areas of high crude oil production, such asthe Bakken Shale Basin in North Dakota, the Niobrara Shale Basin in Colorado, the Mississippi Lime Basin in Oklahoma, the Permian Basin in Texas andNew 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 8Table of Contents · Four towboats and ten barges operating primarily in the inter-coastal waterways of the Gulf Coast and along the Mississippi and Arkansas riversystems. We also contract for truck, rail, and barge transportation services from third parties and ship on common carrier pipelines. We own 42 pipelineinjection 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, Oklahoma138,000Rio Hondo, Texas80,000Wheatland, Wyoming80,000Sunray, Texas9,500 Customers. Our customers include crude oil refiners and marketers. Approximately 58% of the revenues from our crude oil logistics segment duringthe 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 alsoprovide 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 greaterfinancial 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 500producers 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 asCushing, Oklahoma. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by enteringinto 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. Asa result, receivables from individual customers in our crude business are typically higher than the receivables from customers of our other segments. Weperform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our crude oil logistics customers. We believe thefollowing 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 theirability 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 oiland natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. Our 9Table of Contents 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 inColorado, 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: ProcessingCapacityLocation(barrels per day)Pinedale, Wyoming60,000(*)Grover, Colorado27,000Kersey, Colorado11,800Cornish, Colorado9,000LaSalle, Colorado5,500Brighton, Colorado6,500Platteville, Colorado4,500Greeley, Colorado3,800Artesia Wells, Texas16,000Dilley Lea, Texas14,000Carrizo Springs, Texas13,000Andrews, Texas10,000Los Angeles, Texas10,000 (*) The Pinedale, Wyoming facility has a capacity of 20,000 barrels per day to process water to a discharge standard and a capacity of 60,000barrels 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 takedelivery 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 thanbeing 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 drillingoperations, 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 Coloradohave 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. Ourfacilities 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 facilitiesowned 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 conductdrilling operations near our facilities. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume to ourfacility. Certain other customers, primarily those of our facilities in Colorado, have committed to deliver to our facilities all wastewater produced at all wells ina 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 therevenues 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 arestrategically located near areas of significant oil and natural gas production. Most of the primary customers served by our facilities in Wyoming and Coloradoare 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. 10Table of Contents Pricing Policy. We generally charge customers a processing fee per barrel of wastewater processed. Certain of our contracts require the customer todeliver a specified minimum volume of wastewater over a specified period of time. We also generate revenue from the sale of hydrocarbons we recover in theprocess 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 smallerwater transportation companies. We typically invoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establishcredit limits, and follow monitoring procedures on our water services customers. We believe the following procedures enhance our collection efforts with ourwater 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 theirability 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, TiburonResources, 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 treatmentprocesses and cost minimization. Natural Gas Liquids Logistics Overview. Our natural gas liquids logistics segment provides natural gas liquids procurement, storage, transportation, and supply services tocustomers through assets owned by us and third parties. Our natural gas liquids logistics business also supplies the majority of the propane for our retailpropane business. We also sell butanes and natural gasolines to refiners and producers for use as blending stocks and diluent and assist refineries bymanaging 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 transportvehicles 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 contractualarrangements. Back-to-back arrangements, in which we balance our contractual portfolio by buying propane supply when we have a matching purchasecommitment from our wholesale customers, protects our margins, and mitigates commodity price risk. Pre-sales also reduce the impact of warm weatherbecause 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 propaneproducers 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. Inorder 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 refinersduring 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 storageto 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, wesub-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. 11Table of Contents We own 17 natural gas liquids terminals and we lease a fleet of rail cars. These assets give us the opportunity to access wholesale marketsthroughout 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 ourwholesale 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 CapacityFacility(in gallons per day)Rosemount, Minnesota1,441,000Lebanon, Indiana1,058,000West Memphis, Arkansas1,058,000Dexter, Missouri930,000East St. Louis, Illinois883,000Jefferson City, Missouri883,000St. Catherines, Ontario, Canada700,000Janesville, Wisconsin553,000Light, Arkansas524,400Rixie, Arkansas524,400Winslow, Arizona500,000Kingsland, Arkansas405,000Portland, Maine360,000West Springfield, Massachusetts360,000Green Bay, Wisconsin310,000Ritzville, Washington198,000Sidney, Montana180,000Total10,867,800 We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouriare 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 ofthe 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 tolocations 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. Welease approximately 163 million gallons of storage space for natural gas liquids in various storage hubs in Arizona, Canada, Kansas, Michigan, Mississippi,Missouri, and Texas. 12Table of Contents The following chart shows our leased storage space at natural gas liquids storage facilities and interconnects to those facilities: Leased Storage Space(in gallons)BeginningAs ofApril 1,March 31,Storage Facility20132013Storage InterconnectsConway, Kansas80,850,000101,850,000Connected to Enterprise Mid-America and NuStar PipelinesBorger, Texas31,500,00031,500,000Connected to ConocoPhillips Blue Line PipelineBushton, Kansas12,600,00010,500,000Connected to ONEOK North System PipelineMont Belvieu, Texas2,940,0003,990,000Connected to Enterprise Texas Eastern Products PipelineCarthage, Missouri7,560,0007,560,000Connected to Mid-America PipelineMarysville, Michigan15,750,0004,200,000Connected to Cochin PipelineHattiesburg, Mississippi3,150,0003,150,000Connected to Enterprise Dixie PipelineRedwater, Alberta, Canada4,620,0004,200,000Connected to Cochin PipelineAdamana, Arizona1,680,0001,680,000Rail facilityCorunna, Ontario, Canada2,100,0002,100,000Rail facilityTotal162,750,000170,730,000 During the typical heating season from September 15 through March 15 each year, we have the right to utilize ConocoPhillips’ capacity as a shipperon 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 servesnational, regional and independent retail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. Our natural gas liquidslogistics business also supplies the majority of the propane for our retail propane business. We deliver the propane supply to our customers at terminalslocated on common carrier pipeline systems, rail terminals, refineries, and major U.S. propane storage hubs. For the year ended March 31, 2013, our tenlargest natural gas liquids logistics customers represented approximately 42% of the total sales of our natural gas liquids logistics business (exclusive of salesto 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, weare able to partially mitigate the effects of seasonality by pre-selling a portion of our wholesale volumes to retailers and wholesalers and requiring the customerto 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. 13Table of Contents Our competitors generally include other natural gas liquids wholesalers and companies involved in the natural gas liquids midstream industry (suchas 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 carrierpipelines: · 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 andprotect 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 ourdaily 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 ofcontractual agreement. Billing and Collection Procedures. Our natural gas liquids logistics customers consist of commercial accounts varying in size from localindependent distributors to large regional and national retailers. These sales tend to be large volume transactions that can range from approximately 10,000gallons 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 enhanceour 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 totake 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 paidprevious invoices timely. Trade Names. Our natural gas liquids logistics business operates primarily under the NGL Supply Wholesale, Centennial Energy, and CentennialGas 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 leaseof propane tanks, equipment and supplies, to more than 270,000 residential, agricultural, commercial and industrial customers. We also sell propane tocertain re-sellers. We purchase the majority of the propane sold in our retail propane business from our natural gas liquids logistics business, which providesour retail propane business with a stable and secure supply of propane. 14Table of Contents 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 customersin suburban areas where energy alternatives to propane such as natural gas are not generally available. We own or lease 86 customer service locations and 94satellite distribution locations, with aggregate above ground propane storage capacity of approximately 10.8 million gallons. Our customer service locations arestaffed 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 customersin rural areas to treat well water or other problem water. We sell water conditioning equipment and treatment supplies as well. Although the water conditioningportion of our retail propane business is small, it generates steady year round revenues. The customer bases in Illinois and Indiana for retail propane and waterconditioning 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 CustomerNumber of SatelliteServiceDistributionStateLocationsLocationsIllinois2321Maine1510Georgia113Massachusetts105Kansas530Indiana45Connecticut32Pennsylvania23North Carolina21Oregon21Washington2—Mississippi13New Hampshire12Maryland11Rhode Island11Utah11Wyoming11Colorado1—Delaware—1New Jersey—1Tennessee—1Vermont—1Total8694 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 thefollowing 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 otherservice trucks. 15Table of Contents Retail deliveries of propane are usually made to customers by means of our fleet of bulk delivery trucks. Propane is pumped from the bulk deliverytruck, 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 to1,000 gallons. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of five to 25 gallons. These cylinders aretypically picked up on a delivery route, refilled at our customer service locations, and then returned to the retail customer. Customers can also bring thecylinders 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 tomaximize our delivery efficiency. For these customers, our delivery forecasting software system utilizes a customer’s historical consumption patternscombined with current weather conditions to more accurately predict the optimal time to refill their tank. The delivery information is then uploaded to routingsoftware to calculate the most cost effective delivery route. Our automatic delivery program promotes customer retention by ensuring an uninterrupted supplyof 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 andprice 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. AtMarch 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. Inparticular, residential and agricultural customers who use propane and distillates to heat homes and livestock buildings generally only need to purchasepropane during the typical fall and winter heating season. Propane sales to agricultural customers who use propane for crop drying are also seasonal, althoughthe 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 ofharvest. Propane and distillate sales to commercial and industrial customers, while affected by economic patterns, are not as seasonal as are sales to residentialand 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 whichhave greater financial resources than we do. We compete with alternative energy sources and with other companies engaged in the retail propane distributionbusiness. Competition with other retail propane distributors in the propane industry is highly fragmented and generally occurs on a local basis with other largefull-service, multi state propane marketers, smaller local independent marketers and farm cooperatives. Our customer service locations generally have one tofive 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 competitiveenvironment, since retailers are located in close proximity to their customers due to delivery economics. Our customer service locations generally have aneffective marketing radius of approximately 25 to 50 miles, although in certain areas the marketing radius may be extended by satellite distribution locations. 16Table of Contents The ability to compete effectively depends on the ability to provide superior customer service, which includes reliability of supply, qualityequipment, well-trained service staff, efficient delivery, 24-hours-a-day service for emergency repairs and deliveries, multiple payment and purchase optionsand the ability to maintain competitive prices. Additionally, we believe that our safety programs, policies and procedures are more comprehensive than manyof our smaller, independent competitors, which ensures a higher level of service to our customers. We also believe that our overall service capabilities andcustomer 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 byadjusting our retail propane pricing based on, among other things, prevailing supply costs, local market conditions, and input from management at ourcustomer service locations. We rely on our regional management to set prices based on these factors. Our regional managers are advised regularly of anychanges in the delivered cost of propane and distillates, potential supply disruptions, changes in industry inventory levels and possible trends in the futurecost of propane and distillates. We believe the market intelligence provided by our natural gas liquids logistics business combined with our propane anddistillate 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 andaccount collection. We believe that this decentralized and more personal approach is beneficial because our local staff has more detailed knowledge of ourcustomers, their needs, and their history than would an employee at a remote billing center. Our local staff often develops relationships with our customers thatare 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 tothem 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 thishelps maintain the local identification of these companies and contributes to their continued success. We regard our trademarks, trade names, and otherproprietary 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 andare 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 GasAct 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 allgas resellers subject to its regulation, 17Table of Contents 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, welllocation, methods of drilling, well operations, and conservation of resources. While these regulations do not directly apply to our business, they may affect thebusinesses 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 Actof 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 theNatural Gas Act, the NGPA, or their implementing regulations. In addition, the Federal Trade Commission holds statutory authority under the EnergyIndependence and Security Act of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of upto $1,000,000 per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. TheCommodity Futures Trading Commission is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futuresmarkets, including the energy futures markets. Pursuant to statutory authority, the Commodity Futures Trading Commission has adopted anti-marketmanipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The Commodity Futures Trading Commissionalso 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 forviolations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reporting requirements that are designed tofacilitate 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 andregistered 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 theU.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 maritimetransportation and for taking any remedial action necessary to insure that no violation of the Jones Act ownership restrictions occurs. The Jones Act alsorequires that all U.S.-flagged vessels be manned by U.S. citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received byU.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 byU.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 theenvironment. Accordingly, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict orimpact 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 ouroperations; · limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered orthreatened 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 suchenvironmental laws and regulations. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including theassessment of monetary penalties. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites wheresubstances, hydrocarbons or wastes have been disposed or otherwise released. The trend in environmental regulation is to place more restrictions andlimitations on activities that may affect the environment. Thus, 18Table of Contents there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation and actual future expenditures may bedifferent 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 regulationsgoverning the storage, distribution and transportation of natural gas liquids and the operation of bulk storage LPG terminals, as well as laws and regulationsgoverning environmental protection, including those addressing the discharge of materials into the environment or otherwise relating to protection of theenvironment or occupational health and safety. Generally, these laws (i) regulate air and water quality and impose limitations on the discharge of pollutants andestablish standards for the handling of solid and hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) mayresult in the suspension or revocation of necessary permits, licenses and authorizations; (iv) impose substantial liabilities on us for pollution resulting fromour 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, theHomeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act and comparable state statutes. Forexample, 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 ahazardous substance released at the site. While propane is not a hazardous substance within the meaning of CERCLA, other chemicals used in or generated byour operations may be classified as hazardous. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject tostrict and joint and several liability for the costs of investigating and cleaning up the hazardous substances that have been released into the environment, fordamages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to fileclaims 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 andcleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes inconjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penaltiesfor alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of oil and natural gas, as well aspetroleum-contaminated media, are exempt from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead, are regulated under RCRA’sless stringent solid waste provisions, state laws or other federal laws. It is possible, however, that certain wastes now classified as non-hazardous could beclassified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposedfrom 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 ourcosts 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 utilizedoperating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on orunder the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment ordisposal. These properties and the wastes disposed thereon may be subject to CERCLA, the Resource Conservation and Recovery Act and analogous statelaws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners oroperators), to clean up contaminated property (including contaminated groundwater) or to implement remedial measures to prevent or mitigate futurecontamination. We are not currently aware of any facts, events or conditions relating to such requirements that could materially impact our operations orfinancial condition. Oil Pollution Prevention. Our operations involve the shipment of propane and other natural gas liquids by barge through navigable waters of theU.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 naturalgas 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 notcurrently aware of any facts, events, or conditions related to oil spills that could materially impact our operations or financial condition. In 1973, the EPAadopted oil pollution prevention regulations under the Clean Water Act. These oil pollution prevention regulations, as amended several times since their 19Table of Contents 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, couldreasonably 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. Tobe in compliance, the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading andunloading, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement theSPCC 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 andregulations regulate emissions of air pollutants from various industrial sources, and also impose various monitoring and reporting requirements. Such lawsand regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantlyincrease air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emissioncontrol technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions orrestrictions on operations and, potentially, criminal enforcement actions. Furthermore, we may be required to incur certain capital expenditures in the future forair 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 intostate 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 ofpollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similarstructures to help prevent the contamination of regulated waters in the event of a hydrocarbon or other constituent tank spill, rupture or leak. In addition, theClean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain typesof 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 runofffrom such facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impactgroundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with dischargepermits 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 programauthorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injectionapparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulic fracturingactivities. However, a portion of our customers’ natural gas production is developed from unconventional sources that require hydraulic fracturing as part ofthe 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 requirefederal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluidsused in the fracturing process, have been proposed in recent sessions of the U.S. Congress. Congress will likely continue to consider legislation to amend theSafe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act’s Underground Injection Control Program and/or to requiredisclosure of chemicals used in the hydraulic fracturing process. In addition, several states, including Texas and Colorado, have also proposed or adoptedlegislative 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 inthe future. Greenhouse Gas Regulation There is a growing concern, both nationally and internationally, about climate change and the contribution of greenhouse gas emissions, mostnotably 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-widecap 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 reduceemissions of greenhouse gases, primarily through the planned development of 20Table of Contents greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs, although in recent years some states have scaled back theircommitment to GHG initiatives. On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present anendangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’satmosphere and other climatic changes. These findings allowed the EPA to adopt and implement regulations to restrict emissions of greenhouse gases underexisting provisions of the federal Clean Air Act. Accordingly, the EPA has issued a number of regulations addressing greenhouse gas emissions under theClean Air Act, including: the greenhouse gas reporting rule; greenhouse gas standards applicable to heavy-duty and light-duty vehicles; a rule requiringstationary sources to address greenhouse gas emissions in Prevention of Significant Deterioration and Title V permits; and new source performance standardsfor greenhouse gas emissions from new power plants. The EPA’s greenhouse gas regulations could require us to incur costs to reduce emissions of greenhousegases associated with our operations and also could adversely affect demand for the propane and other natural gas liquids that we transport, store, process, orotherwise 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 hurricanesand floods, which could damage our facilities. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market forour propane and other natural gas liquids is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes inclimate 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 effecton our business. Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, new climate change regulations mayprovide 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, resultingin increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other governmental action is taken thatrestricts certain aspects of our business or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business andprospects 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, stateagencies administer these laws. In others, municipalities administer them. We conduct training programs to help ensure that our operations comply withapplicable 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, andPamphlet 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 thepolicies and procedures currently in effect at all of our facilities for the handling, storage and distribution of propane and distillates and related service andinstallation operations are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safetylaws. 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 transportationof hazardous materials and are administered by the United States Department of Transportation, or DOT. We maintain various permits necessary to ensurethat our operations comply with applicable regulations. The Natural Gas Safety Act of 1968 required the DOT to develop and enforce minimum safetyregulations for the transportation of gases by pipeline. The DOT’s pipeline safety regulations apply to, among other things, a propane gas system whichsupplies 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 islocated in a public place. The code requires operators of all gas systems to provide training and written instructions for employees, establish writtenprocedures to minimize the hazards resulting from gas pipeline emergencies, and conduct and keep records of inspections and testing. Operators are subject tothe Pipeline Safety Improvement Act of 2002, which, among other things, protects employees from adverse employment actions if they provide information totheir employers or to the federal government as to pipeline safety. 21Table of Contents 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 thispurpose. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, as well as other federal and stateregulatory agencies. Occupational Health Regulations The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the requirements of the federalOccupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe we have conducted our operations in substantial compliance withOSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances. Ourmarine vessel operations are also subject to safety and operational standards established and monitored by the U.S. Coast Guard. In general, we expect toincrease our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. However, theseexpenditures 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 orfurnish to the Securities and Exchange Commission (“SEC”), as well as all amendments to these reports, as soon as reasonably practicable after such reportsare 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 andshould 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 aninternet site (http://www.sec.gov) that contains reports, proxy and information statements and other information related to issuers that file electronically withthe 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 cashreserves 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 ourcommon and subordinated units principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarterbased 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. 22Table of Contents 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 bynon-cash items. As a result, we might make cash distributions during periods when we record net losses for financial accounting purposes and we might notmake 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 theability and willingness of other parties to explore for and produce oil and natural gas. Spending on oil and natural gas exploration andproduction 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) continuedcommercially viable areas in which to explore and produce oil and natural gas, and (4) the availability of liquids-rich natural gas needed toproduce 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 continueto be, adversely affected by industry and financial market conditions and existing or new regulations, such as those related to environmental matters, that arebeyond 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 andnatural gas in the United States and Canada, and to extract natural gas liquids from natural gas. Customers’ expectations of lower market prices for oil andnatural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending, thereby reducing businessopportunities 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 geographicareas 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 anddemand for oil and natural gas, environmental restrictions on the exploration and production of oil and natural gas, such as existing and proposed regulationof hydraulic fracturing, domestic and worldwide economic conditions, political instability in oil and natural gas producing countries and merger anddivestiture activity among our current or potential customers. The volatility of the oil and natural gas industry and the resulting impact on exploration andproduction activity could adversely impact the level of drilling activity. This reduction may cause a decline in business opportunities or the demand for ourservices, 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 negativelong-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent existing production is not replaced. 23Table of Contents 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 atwhich it returns to former levels, if ever, will be uncertain. Prior adverse changes in the global economic environment and capital markets and declines inprices for oil and natural gas have caused many customers to reduce capital budgets for future periods and have caused decreased demand for oil and naturalgas. Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause customers to makeadditional reductions to capital budgets in the future even if commodity prices increase from current levels. These cuts in spending may curtail drillingprograms and other discretionary spending, which could result in a reduction in business opportunities and demand for our services, the rates we can chargeand our utilization. In addition, certain of our customers could become unable to pay their suppliers, including us. Any of these conditions or events couldmaterially 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 ofoperations. Propane competes with other sources of energy, some of which are less costly for equivalent energy value. We compete for customers againstsuppliers of electricity, natural gas and fuel oil. Competition from alternative energy sources, including electricity and natural gas, has increased as a result ofreduced regulation of many utilities. Electricity is a major competitor of propane, but propane has historically enjoyed a competitive price advantage overelectricity. Except for some industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelinesalready 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. Theexpansion of natural gas into traditional propane markets has historically been inhibited by the capital cost required to expand distribution and pipelinesystems; however, the gradual expansion of the nation’s natural gas distribution systems has resulted in natural gas being available in areas that previouslydepended on propane, which could cause us to lose customers, thereby reducing our revenues. Although propane is similar to fuel oil in some applications andmarket 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 bothfuel 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 alternativeenergy 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 ofmore efficient furnaces and other heating devices, has adversely affected the demand for propane by retail customers. Future conservation measures ortechnological advances in heating, conservation, energy generation or other devices may reduce demand for propane. In addition, if the price of propaneincreases, 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 marginsdepend 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 gasliquids 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 deliveryobligations. We attempt to obtain a certain margin for our purchases by selling our product to our customers, which include third party consumers, otherwholesalers and retailers, and others. However, market, weather or other conditions beyond our control may disrupt our expected supply of product, and wemay be required to obtain supply at increased prices that cannot be passed through to our customers. In general, product supply contracts permit suppliers tocharge posted prices at the time of delivery or the current prices established at major storage points, creating the potential for sudden and drastic pricefluctuations. Sudden and extended wholesale price increases could reduce our margins and could, if continued over an extended period of time, reduce demandby encouraging retail customers to conserve or convert to alternative energy sources. Conversely, a prolonged decline in product prices could potentially resultin 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. 24Table of Contents 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 forcustomers 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 thetransportation and storage of natural gas liquids. Natural gas and natural gas liquids also compete with other forms of energy, including electricity, coal, fueloils 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 facecompetition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude terminals compete with terminals owned by integratedpetroleum 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 andhave substantially greater financial resources than we do to small retail propane distributors, rural electric cooperatives and fuel oil distributors who haveentered 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 orreduced 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 marketshare 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 significantinterruption 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. Anydisruptions 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 atimely 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 largestcustomers of the segment. Approximately 58% of the revenues of our crude oil logistics segment during the year ended March 31, 2013 were generated from ourten largest customers of the segment. Approximately 42% of the revenues our natural gas liquids logistics segment were generated from our ten largestcustomers of the segment. For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented approximately10% 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 keycustomers, failure to renew contracts upon expiration, or a sustained decrease in demand by key customers could result in a substantial loss of revenues andcould have a material and adverse effect on our results of operations. 25Table of Contents Our future financial performance and growth may be limited by our ability to successfully complete accretive acquisitions on economicallyacceptable 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 tofinance 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 existingunitholders 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 oneconomically acceptable terms, that any acquisitions will not be dilutive to earnings and distributions or that any additional debt that we incur to finance anacquisition will not affect our ability to make distributions to unitholders. Furthermore, if we consummate any future acquisitions, our capitalization andresults of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant informationthat 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. Increasedcompetition from alternative energy sources has limited growth in the propane industry, and year-to-year industry volumes are primarily impacted byfluctuations in weather and economic conditions. In addition, our retail propane business concentrates on sales to residential customers, but because oflongstanding customer relationships that are typical in the retail residential propane industry, the inconvenience of switching tanks and suppliers andpropane’s generally higher cost as compared to certain other energy sources, we may have difficulty in increasing our retail customer base other than throughacquisitions. Therefore, while our business strategy includes expanding our existing operations through internal growth, our ability to grow within theindustries 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 withoperations 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 toa particular acquisition. Even when an issue or risk is identified, we may be unable to obtain adequate contractual protection from the seller. The realization ofany of these risks could have a material adverse effect on the success of a particular acquisition or our financial condition, results of operations or futuregrowth. 26Table of Contents As part of our growth strategy, we may expand our operations into businesses that differ from our existing operations. Integration of new businessesis a complex, costly and time-consuming process and may involve assets with which we have limited operating experience. Failure to timely and successfullyintegrate acquired businesses into our existing operations may have a material adverse effect on our business, financial condition or results of operations. Inaddition to the risks set forth above, new businesses will subject us to additional business and operating risks, such as the acquisitions not being accretive toour unitholders as a result of decreased profitability, increased interest expense related to debt we incur to make such acquisitions or an inability tosuccessfully integrate those operations into our overall business operation. The realization of any of these risks could have a material adverse effect on ourfinancial 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 beimpaired 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 cashflow 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 byprevailing economic and weather conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operatingresults are not sufficient to service our future indebtedness, we would be forced to take actions such as reducing distributions, reducing or delaying ourbusiness activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may be unable to effect any ofthese actions on satisfactory terms or at all. The agreements governing our indebtedness permit us to incur additional debt under certain circumstances, and wewill 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 ofoperations, 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. 27Table of Contents We are permitted to make distributions to our unitholders under our revolving credit facility and note purchase agreement so long as no default orevent of default exists both immediately before and after giving effect to the declaration and payment of the distribution and the distribution does not exceedavailable cash for the applicable quarterly period. Our revolving credit facility and note purchase agreement also contain covenants requiring us to maintaincertain 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 attractivebusiness opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisionsof 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 andconditions of our revolving credit facility, to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately dueand 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 thepayment 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 repaysuch 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, andour 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 thancurrent levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by our level of cashdistributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investmentdecision making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in ourunits, 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 orother 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 gasliquids may not escalate sufficiently to cover increases in costs and the agreements may be suspended in some circumstances, which would affectour 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 orcut 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 isinsufficient to cover increased costs or if any customer suspends or terminates its contracts with us, our profitability could be materially and adverselyaffected. 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 broadregulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of energy commodities, and any related transportationand/or hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantialenforcement authority. Our sales may also be subject to certain reporting and other requirements. Additionally, to the extent that we enter into transportationcontracts with pipelines that are subject to FERC regulation or we become subject to FERC regulation ourselves (see Risk Factor entitled “Some of ourtransportation services could become subject to the jurisdiction of the FERC,” below), we will be obligated to comply with FERC’s regulations andpolicies. 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 theimposition of civil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material and adverse effect onour 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 forderivative transactions, including oil and gas hedging transactions. Certain transactions will be required to be cleared on exchanges and cash collateral willhave to be posted. The Dodd-Frank Act provides for a potential exemption from these 28Table of Contents clearing and cash collateral requirements for commercial end-users and it includes a number of defined terms that will be used in determining how thisexemption applies to particular derivative transactions and the parties to those transactions. Since the Dodd-Frank Act mandates the CFTC to promulgaterules 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 CFTCestablished position limits on certain core futures and equivalent swaps contracts, with exceptions for certain bona fide hedging transactions, those limits werevacated 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 finalizesrevised rules. Additionally, In December 2012, the CFTC published final rules regarding mandatory clearing of four classes of interest rate swaps and twoclasses 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 ofthe Dodd-Frank Act on our hedging activities is uncertain at this time. However, new legislation and any new regulations could significantly increase the costof derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms ofderivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existingderivative contracts, and increase our exposure to less creditworthy counterparties. The Dodd-Frank Act may also materially affect our customers andmaterially 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 asComprehensive, Safety, Analysis, or “CSA.” If our current USDOT safety ratings are downgraded to “Unsatisfactory” or the equivalent inconnection 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 ofchanging its safety rating methodology. Any new methodology adopted in the rulemaking is likely to link safety ratings more closely to roadside inspection anddriver violation data gathered and analyzed from month to month under the agency’s new Safety Measurement System or “SMS.” This linkage could result ingreater 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’splace(s) of business. Preliminary studies by transportation consulting firms indicate that “Satisfactory” ratings (or any equivalent under a new SMS-basedsystem) may become more difficult to achieve and maintain under such a system. If we ever receive an “Unsatisfactory” or equivalent rating, we may losesome 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 growthand 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 andretaining sufficient numbers of qualified drivers. In addition, due in part to current economic conditions, including the cost of fuel, insurance, and tractorsand the U.S. Department of Transportation’s (“DOT”) regulatory requirements, the available pool of qualified truck drivers has been declining. Regulatoryrequirements, including the FMCSA’s CSA initiative, and an improvement in the economy could reduce the number of eligible drivers or require us to paymore to attract and retain drivers. A shortage of qualified drivers and intense competition for drivers from other companies will create difficulties in increasingthe 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 qualifieddrivers, 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 regulatorymatters 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 stringentfederal, state, provincial and local laws and regulations relating to the protection of natural resources and the environment, health and safety, wastemanagement, and transportation and disposal of such products and materials. We face inherent risks of incurring significant environmental costs andliabilities in the performance of our operations due to handling of wastewater and hydrocarbons, such as crude oil, condensate and natural gas liquids. Forinstance, our wastewater treatment and transportation business carries with it environmental risks, including leakage from the treatment plants to surface orsubsurface soils, surface water or groundwater, or accidental spills or releases during the transport of wastewater. Our crude oil, condensate, and natural gasliquids businesses carry similar risks of leakage and sudden or accidental spills of crude oil, condensate, natural gas liquids, and hydrocarbons. Liabilityunder, or violation of, environmental laws and regulations could result in, among other things, the impairment or cancellation of operations, injunctions, finesand penalties, reputational damage, expenditures for remediation and liability for natural resource damages, property damage and personal injuries. 29Table of Contents We use various modes of transportation to carry propane, distillates, crude oil and water, including trucks, railcars and barges, each of which issubject to regulation. With respect to transportation by truck, we are subject to regulations promulgated under federal legislation, including the Federal MotorCarrier Safety Act and the Homeland Security Act of 2002, which cover the security and transportation of hazardous materials and are administered by theUnited States Department of Transportation, or DOT. We also own and lease a fleet of railcars, the operation of which is subject to the regulatory jurisdictionof the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies. Our barge transportation operations, which weacquired 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 UnitedStates, and manned and owned by United States citizens, as well as rules and regulations of the United States Coast Guard. Non-compliance with any ofthese 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 orremediation of previously released materials. As a result, these laws could cause us to become liable for the conduct of others, such as prior owners oroperators 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 actionswere 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 havebeen 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 variousfederal, state, provincial and local governmental authorities relating to wastewater handling, discharge and disposal, air emissions, transportation and otherenvironmental matters. These authorizations subject us to terms and conditions which may be onerous or costly to comply with, and that may require costlyoperational modifications to attain and maintain compliance. The renewal, amendment or modification of these permits, approvals and other authorizationsmay involve the imposition of even more stringent and burdensome terms and conditions with attendant higher costs and more significant effects upon ouroperations. Changes in environmental laws and regulations occur frequently. New laws or regulations, changes to existing laws or regulations, such as morestringent pollution control requirements or additional safety requirements, or more stringent interpretation or enforcement of existing laws and regulations, mayunfavorably 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 wellsmay increase our costs for treatment of frac flow-back water (or affect our hydraulic fracturing customers’ ability to operate) and cause delays, interruption ortermination 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 imposesignificant costs and liabilities on them, including as a result of changes in such laws and regulations causing them to become more stringent over time. Forexample, in April 2012, the U.S. Environmental Protection Agency (“EPA”) issued final rules that established new air emission controls for oil and gasproduction 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 tocomply with environmental laws and regulations could affect their production output significantly. Such an effect could materially and adversely affect ourutilization and profitability, thus reducing demand for our midstream services. Such an effect on our customers could materially and adversely affect ourutilization and profitability. The adoption or implementation of any new regulations imposing additional reporting obligations on GHG emissions, or limitingGHG 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 andadditional 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 animportant and common process used to facilitate production of natural gas and other hydrocarbon condensates in shale formations, as well as tightconventional formations. The hydraulic fracturing process is typically regulated by state oil and gas authorities. This process has come under considerablescrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the fracturing process could adversely affectdrinking water supplies. Some sections of the public have also asserted that the fracturing process could result in increased seismic activity. New laws orregulations, or changes to existing laws or regulations in response to this perceived threat may unfavorably impact the oil and gas drilling industry. Forinstance, the EPA recently asserted federal regulatory authority over certain hydraulic fracturing practices involving the use of diesel fuel. At the same 30Table of Contents 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 haveadopted 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 partiesopposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process couldadversely affect groundwater. We cannot predict whether any proposed federal, state or local laws or regulations will be enacted and, if so, what actions anysuch laws or regulations would require or prohibit. However, any restrictions on hydraulic fracturing could lead to operational delays or increased operatingcosts and regulatory burdens that could make it more difficult or costly to perform hydraulic fracturing which would negatively impact our customer baseresulting 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 ourbusiness, 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 orman-made disasters. During periods of heavy snow, ice, rain or extreme weather conditions such as high winds, tornados and hurricanes or after other naturaldisasters such as earthquakes or wildfires, we may be unable to move our trucks or rail cars between locations and our facilities may be damaged, therebyreducing our ability to provide services and generate revenues. In addition, hurricanes or other severe weather in the Gulf Coast region could seriously disruptthe supply of crude oil and natural gas liquids and cause serious shortages in various areas, including the areas in which we operate. These same conditionsmay cause serious damage or destruction to homes, business structures and the operations of our retail and wholesale customers. Such disruptions couldpotentially have a material adverse impact on our business, financial condition, results of operations and cash flows, which could impair our ability to makedistributions 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 subjectto 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/orincreased 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 suchrights-of-way. Additionally, our loss of rights, through our inability to renew right-of-way contracts or otherwise, could materially and adversely affect ourbusiness, 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 ourrail cars. Our inability to renew facility or equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or theincreased 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 forthe 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 financialcondition 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 sellingsuch commodities for physical delivery to our customers, such as independent refiners or major oil companies, or by entering into future delivery obligationsunder contracts for forward sale. Through these transactions, we seek to maintain a position that is substantially balanced between purchases on the onehand, and sales or future delivery obligations on the other hand. These policies and practices cannot, however, eliminate all risks. For example, any event thatdisrupts our anticipated physical supply of commodities could expose us to risk of loss resulting from the need to cover obligations required under contractsfor forward sale. Additionally, we can provide no assurance that our processes and procedures will detect and/or prevent all violations of our risk managementpolicies 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 ascompared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and 31Table of Contents timing differentials are components of basis risk. In a backwardated market (when prices for future deliveries are lower than current prices), basis risk iscreated with respect to timing. In these instances, physical inventory generally loses value as price of such physical inventory declines over time. Basis riskcannot be entirely eliminated, and basis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our financialcondition and results of operations. Growing our business by constructing new transportation systems and facilities subjects us to construction risks and risks that supplies for suchsystems 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 mayexceed our resources, and involves numerous regulatory, environmental, political and legal uncertainties. If we undertake these projects, we may not be able tocomplete 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. Forinstance, if we build a new wastewater treatment facility, the construction will occur over an extended period of time, and we will not receive any materialincreases in revenues until at least after completion of the project, if at all. Moreover, we may construct facilities to capture anticipated future growth inproduction 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 onestimates of proved, probable or possible reserves in our decision to build new transportation systems and facilities, which may prove to be inaccurate becausethere are numerous uncertainties inherent in estimating quantities of proved, probable or possible reserves. As a result, new facilities may not be able to attractenough 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 combustibleliquids. As a result, we are subject to product liability claims and lawsuits, including potential class actions, in the ordinary course of business. Any productliability claim brought against us, with or without merit, could be costly to defend and could result in an increase of our insurance premiums. Some claimsbrought against us might not be covered by our insurance policies. In addition, we have significant self-insured retention amounts which we would have to payin full before obtaining any insurance proceeds to satisfy a judgment or settlement and we may have insufficient reserves on our balance sheet to satisfy suchself-retention obligations. Furthermore, even where the claim is covered by our insurance, our insurance coverage might be inadequate and we would have topay 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 allsince insurance varies in cost and can be difficult to obtain. Our failure to maintain adequate insurance coverage or successfully defend against productliability 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 inwastewater 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. Ourability 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, afunction of water temperature. Generally, where water temperature is higher, residual crude oil content is lower. Thus, our crude oil recovery during the winterseason 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 crudeoil 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 financialresults. 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 alsobe adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with ormanipulating our operational systems. In addition, dependence upon automated systems may further increase the risk operational system flaws, employeetampering or manipulation of those systems will result in losses that are difficult to detect. 32Table of Contents Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computerprograms to help run our financial and operations sectors, and this may subject our business to increased risks. Any future cyber security attacks that affectour facilities, our customers and any financial data could have a material adverse effect on our business. In addition, cyber attacks on our customer andemployee data may result in a financial loss, including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-partysystems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability orreputational 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/oreconomic downturns may adversely affect demand for propane in those regions, thereby affecting our financial condition and results ofoperations. A substantial portion of our retail propane sales are to residential customers located in the Northeast, Southeast, and Midwest who rely heavily onpropane for heating purposes. A significant percentage of our retail propane volume is attributable to sales during the peak heating season of October throughMarch. Warmer weather may result in reduced sales volumes that could adversely impact our operating results and financial condition. In addition, adverseeconomic conditions in areas where our retail propane operations are concentrated may cause our residential customers to reduce their use of propane regardlessof weather conditions. Localized warmer weather and/or economic downturns may have a significantly greater impact on our operating results and financialcondition 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, whichcould 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 inthe 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 ourderivative and physical purchase and sale contracts. This could impair our ability to obtain supply to fulfill our sales delivery commitments or obtain supplyat 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 rateswere to change in our favor. In addition, although 33Table of Contents we monitor such activities in our risk management processes and procedures, such activities could result in losses, which could adversely affect our results ofoperations 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 ourfinancial 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 becamesubject to the public reporting requirements of the Securities Exchange Act of 1934, as amended, or the Exchange Act. Effective March 31, 2012, we becamesubject 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 publicaccounting 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 tradedpartnership. 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 operatingresults 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 ourindependent registered public accounting firm’s, conclusions about the effectiveness of internal controls in the future, and we may incur significant costs inour efforts to comply with Section 404. Ineffective internal controls would subject us to regulatory scrutiny and a loss of confidence in our reported financialinformation, 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 materialweaknesses 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 financialreporting. 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 andcontrols 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 ourinternal controls are effective in the future. Any future material weaknesses, or any failure to effectively address a material weakness or other control deficiencyor implement required new or improved controls, or difficulties encountered in their implementation, could limit our ability to obtain financing, harm ourreputation 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 reviewson 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 recordunder 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. Wemanage our credit risk exposure through credit analysis, credit approvals, establishing credit limits, requiring prepayments (partially or wholly), requiringpropane deliveries over defined time periods and credit monitoring. While we believe our procedures are effective, we can provide no assurance that bad debtwrite-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 tomake distributions to our unitholders. 34Table of Contents 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 issuesand toxic substance certifications. Such regulations include the “Short Supply Controls” of the Export Administration Act, the North American Free TradeAgreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition ofsignificant 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 AnnualReport, 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 operationsinto areas that are subject to FERC’s regulation, we may have to commit substantial capital to comply with such regulations and such expenditures could havea 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 makedistributions 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” isthe 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 thefacilities. 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 extendedperiod of time. Such a requirement would expose us to inventory and price risk and could negatively impact our working capital position, our liquidity, ouravailability 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 andoperated by third parties. Any interruption of service on the pipeline or lateral connections or adverse change in the terms and conditions of service could havea material adverse effect on our ability, and the ability of our customers, to transport product to and from our facilities and have a corresponding materialadverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities affect the utilizationand value of our terminals. We have historically been able to pass through the costs of pipeline transportation to our customers. However, if competingpipelines do not have similar annual tariff increases or service fee adjustments, such increases could affect our ability to compete, thereby adversely affectingour 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 summermonths. 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 secondfiscal quarters, we may be required to borrow money to pay distributions to our unitholders during these quarters. Any restrictions on our ability to borrowmoney 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 willresult in increased transportation costs to us. The price and supply of fuel is unpredictable and fluctuates based on events we cannot control, such asgeopolitical 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 andthe 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 andnatural gas, the major sources of propane, which could have a material impact on the availability and price of propane. 35Table of Contents Terrorist attacks in the areas of our operations could negatively impact our ability to transport propane to our locations. These risks could potentiallynegatively 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 andinvolvement of those key management personnel could potentially have a material adverse impact on our business and possibly on the market value of ourunits. 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 ourunitholders 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 UniformLimited Partnership Act, or the Delaware LP Act, provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciaryduties owed by the general partner to limited partners and the partnership. Our partnership agreement contains provisions that reduce the standards to whichour general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement: 36Table of Contents · limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders foractions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, our unitholdersconsent 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. Thisentitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration toany interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its votingrights 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 solong as it acted in good faith, meaning our general partner subjectively believed that the decision was in, or not opposed to, the best interests ofthe partnership; · generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee and not involving avote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third partiesor be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner mayconsider the totality of the relationships between the parties involved, including other transactions that may be particularly favorable oradvantageous 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 actsor omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our generalpartner 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 provisionsdescribed above. Our general partner and its affiliates have conflicts of interest with us and limited fiduciary duties to our unitholders, and they may favor theirown 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 partnerhas 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 afiduciary duty to manage our general partner in a manner beneficial to its owners. Furthermore, since certain executive officers and directors of our generalpartner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between the NGL Energy GP Investor Group and itsaffiliates, 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 mayfavor its own interests and the interests of its affiliates over the interests of our unitholders. See “— Our partnership agreement limits the fiduciary duties ofour general partner to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise bebreaches 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 InvestorGroup, 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 securitiesand the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders; 37Table of Contents · our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as amaintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operatingsurplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner and the ability of thesubordinated 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 isto 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-workingcapital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on oursubordinated 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 orentering 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 than80% 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 ourgeneral partner’s incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner orour 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 andnatural resource sectors. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other thanacting as our general partner and those activities incidental to its ownership interest in us. However, members of the NGL Energy GP Investor Group are notprohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, they could potentiallycompete 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 generalpartner 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 suchperson 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 entitypursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or informationto 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 usand 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 generalpartner 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 publiclytraded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetingsof stockholders of corporations. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have limited ability toremove 38Table of Contents 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 atakeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquireinformation 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 byour 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 theconsent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of the NGL Energy GP Investor Group totransfer 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 toreplace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by theboard 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 incentivedistribution 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 itsincentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rightsto a third party but retains its general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterlydistributions 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 mayassign 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 pricethat 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 berequired 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 unitholdersmay 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 ourunitholders. Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on ourbehalf, which will be determined by our general partner in its sole discretion in accordance with the terms of our partnership agreement. In determining thecosts and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, whichrequires 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 aremanaged and operated by executive officers and directors of our general partner. The reimbursement of expenses and payment of fees, if any, to our generalpartner 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, includingcommercial bank borrowings and the issuance of debt and equity securities, as well as reserves we have established 39Table of Contents to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policywill 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 toexpand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment ofdistributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are nolimitations in our partnership agreement or our revolving credit facility on our ability to issue additional units, including units ranking senior to the commonunits. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, inturn, 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 ourunitholders. 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 minimumquarterly 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 generalpartner interest in connection with a resetting of the target distribution levels related to its incentive distribution rights. This could result in lowerdistributions 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 incentivedistribution 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 distributionlevels 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 minimumquarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higherlevels 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 commonunits 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 quarterlycash 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 twoquarters. We anticipate that our general partner would exercise this reset right to facilitate acquisitions or internal growth projects that would not be sufficientlyaccretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at atime 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 distributionlevels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our commonunitholders would have otherwise received had we not issued new common units and general partner interests to our general partner in connection with resettingthe target distribution levels. 40Table of Contents 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 thepartnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in anumber of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearlyestablished 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 courtor 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 partnershipagreement 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 theDelaware 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 lawprovides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at thetime of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liableboth 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 alimited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities topartners on account of their partnership interests nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether adistribution 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 ofproperty 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 fairvalue 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 anumber of reasons, including not having enough “qualifying income.” If the IRS were to treat us as a corporation for federal income taxpurposes, 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 federalincome 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 apartnership 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 forfederal income tax purposes unless, for each taxable year, 90% or more of its gross income is “qualifying income” under Section 7704 of the Internal RevenueCode. “Qualifying income” includes income and gains derived from the exploration, development, production, processing, transportation, storage andmarketing of natural gas and natural gas products or other passive types of income such as certain interest and dividends. Although we do not believe basedupon 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 totaxation 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 ascorporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses or deductions would flow through to ourunitholders. 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, likelycausing a substantial reduction in the value of our common units. 41Table of Contents 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 acorporation or otherwise subjects us to entity level taxation for federal income tax purposes, the minimum quarterly distribution amount and the targetdistribution 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 distributionto our unitholders. Changes in current state law may subject us to additional entity level taxation by individual states. Because of widespread state budget deficits andother reasons, several states are evaluating ways to subject partnerships to entity level taxation through the imposition of state income, franchise and otherforms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders. Our partnership agreementprovides 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 quarterlydistribution 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 oradministrative 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 byadministrative, legislative or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and considersubstantive changes to the existing U.S. federal income tax laws that affect the tax treatment of publicly traded partnerships. Any modification to the incometax 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 federalincome tax purposes or otherwise subject us to entity-level taxation. Moreover, such modifications and change in interpretations may affect or cause us tochange our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adverselyaffect an investment in our common units. Although we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted, anysuch 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 IRScontest 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 adoptpositions 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 wetake 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 maymaterially 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 beborne 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 wedistribute, 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 taxableincome even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxableincome 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 inthose common units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in theircommon 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 theunitholder 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, asubstantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potentialrecapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if aunitholder sell units, they may incur a tax liability in excess of the amount of cash they receive from the sale. 42Table of Contents Tax-exempt entities and non-U.S. persons face unique tax issues from owning our common units that may result in adverse tax consequences tothem. Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (known as IRAs), Keogh plansand other retirement plans and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that areexempt 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 fileU.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 yourtax 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 maychallenge 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 amortizationpositions that may not conform to all aspects of existing Treasury Regulations. Any position we take that is inconsistent with applicable Treasury Regulationsmay have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and proposeadjustments to some or all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to ourunitholders. 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 thevalue 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 additionaloperations in corporate form in the future. Our corporate subsidiaries will be subject to corporate level tax, which will reduce the cash available for distributionto 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 taxliability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would befurther reduced. We prorate our items of income, gain, loss and deduction for U.S. federal income tax purposes between transferors and transferees of our unitseach 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 istransferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among ourunitholders. We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based on the ownership of ourunits 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 permittedunder existing Treasury Regulations. The U.S. Treasury Department, however, has issued proposed Treasury Regulations that provide a safe harborpursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transfereeunitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Therefore, the use of thisproration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge our proration method or new Treasury Regulationswere 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 commonunits. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units duringthe 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 loanedunits, 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 theunitholder 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 ordeduction 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 befully 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 areurged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers fromborrowing their units. 43Table of Contents We have adopted certain valuation methodologies and monthly conventions for U.S. federal income tax purposes that may result in a shift ofincome, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adverselyaffect 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 anyunrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed asunderstating 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 greaterportion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRSmay challenge our valuation methods, or our allocation of the Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations oftaxable 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 ourunitholders. 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 thecommon 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 ourpartnership 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 interestsin 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 unitwill 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 computingour 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 alsoresult in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical terminationcurrently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for taxpurposes. 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 todetermine that a technical termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technicallyterminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholdersfor 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 orown 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 orcontrol 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 localincome 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 andconduct 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 oncorporations and other entities. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional states thatimpose 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 subjectto liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements entered into inconnection with acquisitions and other encumbrances, easements and 44Table of Contents 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 andconsents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local governmental andregulatory 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 yetdeveloped 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 anyaction 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 legalproceedings, please see the discussion under the caption “Legal Contingencies” in Note 10 to our audited consolidated financial statements in Part IV, Item 15of this Annual Report on Form 10-K, which information is incorporated by reference into this Item 3. Item 4. Mine Safety Disclosures Not Applicable. 45Table of Contents 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 toMay 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 commonunits 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 thesubordinated 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 StockExchange Composite Transactions tape, and the amount of cash distributions paid per common unit. Price RangeCash2013 Fiscal YearHighLowDistributionFourth Quarter$26.90$22.64$0.4625Third Quarter25.1621.260.4500Second Quarter26.6722.110.4125First Quarter23.5020.150.3625 Price RangeCash2012 Fiscal YearHighLowDistributionFourth Quarter$23.15$20.59$0.3500Third Quarter22.0519.940.3375Second Quarter22.7018.400.1669First Quarter (May 12, 2011-June 30, 2011)21.7518.62— 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 ourpartnership agreement) to unitholders of record on the applicable record date. The distribution for the quarter ended June 30, 2011 was prorated for the periodfrom 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, generallyconsists 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 conductof our business, (ii) comply with applicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholdersand 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 eachquarter in an amount equal to the minimum quarterly distribution, which is $0.3375 per common unit, plus any arrearages in the payment of the minimumquarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Arrearagesdo 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 thesubordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterlydistribution. The subordination period will end on the first business day after we have earned and paid the minimum quarterly distribution on each outstandingcommon 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 outstandingcommon unit and subordinated unit, the corresponding distribution on the general partner interest and the related distribution on the incentive distributionrights for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminateautomatically if the general 46Table of Contents 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 periodlapses 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 beentitled 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 notthe obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. Our general partner’s interest in ourdistributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon conversion ofoutstanding subordinated units or the issuance of common units upon a reset of the IDRs) and our general partner does not contribute a proportionate amountof 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 entitleour general partner to receive increasing percentages, up to a maximum of 48.1%, of the cash we distribute from operating surplus (as defined in ourpartnership agreement) in excess of $0.388125 per unit per quarter. The maximum distribution of 48.1% includes distributions paid to our general partner onits 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% doesnot 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 containscovenants 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 availablecash, 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 theconsideration for the acquisitions. All of these units were issued in reliance upon the exemption from registration provided by Section 4(2) of the Securities Actof 1933, as amended, as the units were issued to the owners of businesses acquired in privately negotiated transactions not involving any public offering orsolicitation. 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 commonunits 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 issued1,834,414 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 forIssuance 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 operationsof NGL Supply and Hicksgas. We do not have our own historical financial statements for periods prior to our formation. The following table shows selectedhistorical 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 toOctober 1, 2010. The following table should be read in conjunction with “Item 7 — Management’s Discussion and Analysis of Financial Condition andResults 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 andas of March 31, 2011 and for the six months then ended are derived from our audited historical consolidated financial statements included elsewhere in thisAnnual Report on Form 10-K. The selected historical financial data (excluding volume 47Table of Contents information) as of September 30, 2010 and for the six months then ended are derived from the audited historical consolidated financial statements of NGLSupply 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 yearsthen ended are derived from NGL Supply’s financial records. 48Table of Contents NGL Energy Partners LPNGL Supply, Inc.Year EndedYear EndedSix Months EndedSix Months EndedMarch 31,March 31,March 31,September 30,Year Ended March 31,201320122011201020102009(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 sales4,039,1101,217,023583,032310,908708,215706,418 Operating income (loss)87,30715,03014,837(3,795)6,6619,431 Interest expense32,9947,6202,4823726681,621 Loss on early extinguishment of debt5,769————— Net income or net income (loss) attributable to parentequity47,9407,87612,679(2,515)3,6364,949 Basic and diluted earnings per common unit0.960.321.16 Basic earnings (loss) per common share(128.46)178.75242.82 Diluted earnings (loss) per common share(128.46)176.61239.92 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 (subsequentto IPO)1.690.85— Cash distributions per common unit (prior to IPO)—0.35———— Cash distributions paid per common share———357.09—— Capital Expenditures: Purchases of long-lived assets72,4757,5441,440280582577 Acquisitions of businesses, including additionalconsideration paid on prior period acquisitions490,402297,40117,4001233,1133,532 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 currentmaturities742,641199,38965,93618,9408,8519,245 Redeemable preferred stock————3,0003,000 Total equity889,418405,32947,35336,81146,40342,691 Volume Information (1) Retail propane and distillate sales (gallons)173,23279,88634,9323,74715,51414,033 Wholesale propane sales (gallons)(2)912,625659,921372,504226,330623,510510,255 Wholesale butane and other NGL sales (gallons)632,695134,99949,46546,09253,87858,523 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 NGLSupply in fiscal years 2009 and 2010 affect the comparability of this information. (2) Includes intercompany volumes sold to our retail propane segment. 49Table of Contents 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 EnergyHoldings LLC serves as our general partner. As part of our formation, we acquired and combined the assets and operations of NGL Supply, which wasprimarily a wholesale propane and terminaling business that was founded in 1967, and Hicksgas, which was primarily a retail propane business that wasfounded 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 andwholesale natural gas liquids businesses. Subsequent to our initial public offering, we significantly expanded our operations through a number of businesscombinations, as described under Part I, Item I, “Businesses — Acquisitions Subsequent to Initial Public Offering.” 50Table of Contents 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 railcars, 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 refinersthroughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 17 terminals throughoutthe 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 industrialcustomers 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 aseconomic hedges of our physical forward sales and purchase contracts with our customers and suppliers. The operations of our crude oil logistics segmentbegan 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 intofinancial derivatives. We utilize our transportation assets to move crude oil from the well head to the highest value market. The spread between crude oil pricesin different markets can fluctuate widely, which may expand or limit our opportunity to generate margins by transporting crude to different markets. We alsoseek to maximize margins by blending crude oil of varying properties. 51Table of Contents The range of high and low spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma for the periods indicated andthe prices as of period end are as follows: Spot Price Per BarrelAt PeriodLowHighEnd 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 andnatural gas production operations, and from the sale of recycled water and recovered hydrocarbons. The operations of our water services segment began withour 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 theprofitability 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 minimumvolume of water to our facility under long-term contracts. The primary customers of our facilities in Colorado have committed to deliver to our facilities allwastewater 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, andother parties, and sells the product to retailers, refiners, and other participants in the wholesale markets. Our natural gas liquids logistics segment owns 17terminals and operates a fleet of owned and leased rail cars and leases underground storage capacity. The margins we realize in our wholesale business aresubstantially 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 pricefluctuations by using “back-to-back” contractual agreements and “pre-sale” agreements that essentially allow us to lock in a margin on a percentage of ourwinter 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 floatingrate 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 thevalue of a portion of our inventory. Our natural gas liquids logistics segment includes the operations that were previously reported in our wholesale marketingand supply and terminals segments. Our natural gas liquids logistics segment also includes the natural gas liquids operations we acquired in our June 2012merger with High Sierra. Through our natural gas liquids logistics segment, we distribute propane and other natural gas liquids to our retail operation and other propaneretailers, refiners, wholesalers and other related businesses. Our wholesale business is a “cost-plus” business that is affected both by price fluctuations andvolume variations. We establish our selling price based on a pass through of our product supply, transportation, handling, storage and capital costs plus anacceptable 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 retailpropane business. 52Table of Contents Propane prices continued to be volatile during our fiscal years 2011 through 2013. At Conway, Kansas and Mt. Belvieu, Texas, two of our mainpricing 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, KansasMt. Belvieu, TexasSpot PriceSpot PriceSpot PriceSpot PricePer GallonPer GallonPer GallonPer GallonLowHighAt Period EndLowHighAt 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, 20120.90001.49000.98001.16501.62751.2363 For the Six Months Ended:March 31, 20111.11751.58501.27631.16942.28501.3650September 30, 20100.88131.16251.16250.96311.20001.2000 We purchase butane from refiners during the summer months, when refiners have a greater supply of butane than they need, and sell butane torefiners 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 GallonLowHighAt 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 marginsbased 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 tosupply and demand conditions. Weather conditions have a significant impact on our sales volumes and prices, as a significant portion of our sales are toresidential 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 centsper 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 tomaintain expected margins by passing on the wholesale costs to our customers. We believe that volatility in commodity prices will continue, and our ability toadjust 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 ourcustomers that could result in a decline in our sales volumes, revenues and gross margins. In periods of decreasing costs, we have experienced an increase inour 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 inresidential and commercial buildings and for agricultural purposes. As a result, operating revenues are generally highest from October through March. 53Table of Contents 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 downturncould 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 impacton 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 sixmonths ended March 31, 2011 and NGL Supply’s consolidated statement of operations for the six months ended September 30, 2010. NGL Energy Partners LPNGL Supply, Inc.Year EndedYear EndedSix Months EndedSix Months EndedMarch 31,March 31,March 31,September 30,2013201220112010(in thousands)Revenues$4,417,767$1,310,473$622,232$316,943Cost of sales4,039,1101,217,023583,032310,908Operating and general and administrative expenses222,49763,30920,9228,441Depreciation and amortization68,85315,1113,4411,389Operating income (loss)87,30715,03014,837(3,795)Interest expense(32,994)(7,620)(2,482)(372)Loss on early extinguishment of debt(5,769)———Interest and other income1,5211,055324190Income (loss) before income taxes50,0658,46512,679(3,977)(Provision) benefit for income taxes(1,875)(601)—1,417Net income (loss)48,1907,86412,679(2,560)Net (income) loss attributable to noncontrolling interests(250)12—45Net 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 andamortization 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. 54Table of Contents 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 weissued 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 foradditional information on our long-term debt. The change in interest expense during the periods presented is due primarily to fluctuations in the averageoutstanding debt balance, and in the applicable interest rates, as summarized below: Revolving Credit FacilitiesSenior NotesAverageAverageBalanceAverageBalanceOutstandingInterestOutstandingInterest(in thousands)Rate(in thousands)RateYear Ended March 31, 2013$405,1143.56%$195,8906.65% Year Ended March 31, 2012125,8594.48%—— Six Months Ended March 31, 201173,1155.71%—— Six Months Ended September 30, 201013,7674.63%—— 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 $0.1million 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 theportion 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 consolidatedstatement 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 theacquisitions of businesses. Interest and Other Income Our non-operating other income consists of the following: NGL Energy Partners LPNGL Supply, Inc.Year EndedYear EndedSix Months EndedSix Months EndedMarch 31,March 31,March 31,September 30,2013201220112010(in thousands)Interest income$1,261$765$221$66Gain (loss) on sale of assets(187)71(16)124Other447219119—$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 ownerreports his or her share of our income or loss on his or her individual tax return. 55Table of Contents We have two taxable corporate subsidiaries in the United States and three taxable corporate subsidiaries in Canada. The income tax provisionreported 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 endedSeptember 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 subsidiariesrange 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 Supplydid 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-GAAPfinancial measures, for the periods indicated: NGL Energy Partners LPNGL Supply, Inc.Year EndedYear EndedSix Months EndedSix Months EndedMarch 31,March 31,March 31,September 30,2013201220112010 EBITDA:Net income (loss) attributable to parent equity$47,940$7,876$12,679$(2,515)Provision (benefit) for income taxes1,875601—(1,417)Interest expense32,9947,6202,482372Loss on early extinguishment of debt5,769———Depreciation and amortization73,73915,9113,8411,789EBITDA$162,317$32,008$19,002$(1,771)Unrealized (gain) loss on derivative contracts5,2754,384(1,357)200Loss (gain) on sale of assets187(71)16(124)Share-based compensation expense10,138———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 flowsfrom operating activities, or any other measure of financial performance calculated in accordance with GAAP as those items are used to measure operatingperformance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information for evaluating our ability to makequarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additionalinformation for evaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDAand Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other entities. 56Table of Contents 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 periodspresented due to the following reasons: · In connection with our formation transactions, we also acquired the retail propane operations of Hicksgas. This acquisition was accounted foras a business combination, and the assets acquired and liabilities assumed were recorded in our consolidated financial statements at acquisitiondate fair value. · During the fiscal years ended March 31, 2012 and 2013, we completed a number of acquisitions, as described under “Overview” above. Wehave 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 betreated 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 publiclytraded 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 relationsexpenses; registrar and transfer agent fees; director and officer liability insurance costs; and director compensation. These incremental generaland 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 toOctober 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 Supplybecame the accounting basis for our assets and liabilities. There were no adjustments to the carryover basis of the assets and liabilities that we acquired fromNGL Supply. Our results of operations are also significantly impacted by seasonality, primarily due to the increase in volumes of propane sold by our retailpropane and natural gas liquids logistics segments during the peak heating season of October through March. As a result of our business combination withNGL Supply and Hicksgas in October 2010 and the impact of seasonality, our results of operations for the six months ended March 31, 2011 are notindicative 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 endedSeptember 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 financialstatements 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 arethose 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). 57Table of Contents Year Ended March 31, 2013 of NGL Energy Partners LPCompared 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 byour natural gas liquids logistics segment shown in the table below include sales to our retail segment. Year EndedChange Resulting FromMarch 31,RetailSemStreamHigh SierraSegment20132012Combinations (1)CombinationCombinations (2)Other(in thousands)Crude oil logisticsCrude oil barrels sold24,373———24,373— Water servicesBarrels of water delivered25,009———25,009— Natural gas liquids logisticsPropane gallons sold912,625659,921—(3)140,632112,072Other natural gas liquids gallons sold632,695134,999—(3)447,44950,247 Retail propanePropane gallons sold144,37978,23654,949——11,194Distillate gallons sold28,8531,65027,027——176 (1) This data includes the operations of Osterman (acquired in October 2011) from April 1, 2012 through September 30, 2012, Pacer (acquired inJanuary 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 propanebusiness acquired during fiscal 2013. (2) This data includes the operations of High Sierra (acquired in June 2012), Pecos (acquired in November 2012), and other subsequentacquisitions 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 thevolumes sold subsequent to the combination were specifically attributable to the SemStream combination and which were attributable to ourhistorical 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. Theremaining increase in volume of our retail propane business was due primarily to colder weather during the most recent winter season, which increased thedemand for propane. 58Table of Contents Operating Income by Segment Our operating income by segment is as follows: Year EndedMarch 31,Segment20132012Change(in thousands)Crude oil logistics$34,236$—$34,236Water services8,576—8,576Natural gas liquids logistics30,3369,73520,601Retail propane46,8699,61637,253Corporate 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 $4.3million 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 ofHigh Sierra. In addition, corporate general and administrative expense for the year ended March 31, 2013 includes $10.1 million of compensation expenserelated to certain restricted units granted pursuant to employee and director compensation programs. Corporate general and administrative expense for the yearended March 31, 2013 also includes costs related to acquisitions, including $3.7 million of expense related to the acquisition of High Sierra. The operations ofour 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$2,322,706Crude oil transportation16,442Total revenues(1)2,339,148Expenses:Cost of sales2,267,507Operating expenses25,484General and administrative expenses2,745Depreciation and amortization expense9,176Total expenses2,304,912Segment 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 averageprice 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 yearended March 31, 2013. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationshipintangible assets, was $9.2 million during the year ended March 31, 2013. 59Table of Contents Water Services The following table summarizes the operating results of our water services segment for the year ended March 31, 2013 (amounts in thousands). Theoperations of our water services segment began with our June 19, 2012 combination with High Sierra. Revenues:Water treatment and disposal$54,334Water transportation7,893Total revenues (1)62,227Expenses:Cost of sales5,611Operating expenses25,452General and administrative expenses1,665Depreciation and amortization expense20,923Total expenses53,651Segment 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, takingdelivery 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 perbarrel 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 processingrevenue 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 aportion 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 theyear ended March 31, 2013. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationshipintangible assets, was $20.9 million during the year ended March 31, 2013. 60Table of Contents Natural Gas Liquids Logistics The following table compares the operating results of our natural gas liquids logistics segment for the periods indicated: Year EndedChange Resulting FromMarch 31,High Sierra20132012CombinationOther(in thousands)Revenues:Propane sales$841,448$923,022$115,606$(197,180)Other natural gas liquids sales858,276251,627563,21143,438Transportation and other revenues33,9542,46219,05312,439Total revenues (1)1,733,6781,177,111697,870(141,303) Expenses:Cost of sales - propane801,694904,082109,851(212,239)Cost of sales - other NGLs836,747246,995546,58843,164Costs of sales - other20,9501,7768,63710,537Operating expenses27,6058,12415,0974,384General and administrative expenses5,2612,7381,693830Depreciation and amortization expense11,0853,6613,1014,323Total expenses1,703,3421,167,376684,967(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 $66.0million of sales to our retail propane segment during the year ended March 31, 2012. These intercompany sales, along with a correspondingamount 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 decreasedapproximately $197.2 million during the year ended March 31, 2013, as compared to $923.0 million during the year ended March 31, 2012. This resultedfrom 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 inrevenue 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 prioryear. During the year ended March 31, 2013, the operations of High Sierra contributed revenues of $115.6 million from propane sales. These operationssold 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 increasedapproximately $43.4 million during the year ended March 31, 2013, as compared to $251.6 million during the year ended March 31, 2012. This resultedfrom 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 inthe 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 2011SemStream acquisition, which expanded the markets we are able to serve. We believe the decline in average selling prices is due primarily to a greater thannormal supply in the marketplace, due in part to low demand as a result of mild weather. 61Table of Contents Transportation and other revenues for the year ended March 31, 2013 relate primarily to fees charged for transporting customer-owned product byrail car. Cost of Sales. Exclusive of the operations acquired in our June 2012 merger with High Sierra, costs of wholesale propane sales decreasedapproximately $212.2 million during the year ended March 31, 2013, as compared to $904.1 million during the year ended March 31, 2012. This resultedfrom 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 partiallyoffset 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 propanesales 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 onderivatives. These derivatives consisted primarily of propane swaps that we entered into as economic hedges against the potential decline in the market value ofour 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 140.6million 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 increasedapproximately $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 froman 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 theaverage 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. Theseoperations 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 gasliquids 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-ownedproduct. Operating Expenses. Exclusive of the operations acquired in our June 2012 merger with High Sierra, operating expenses of our natural gas liquidslogistics segment increased approximately $4.4 million during the year ended March 31, 2013 as compared to operating expenses of $8.1 million during theyear ended March 31, 2012. The increase in operating expenses is due primarily to increased compensation and terminal operating expenses resulting from ourSemStream combination. During the year ended March 31, 2013, our natural gas liquids logistics segment incurred $15.1 million of operating expensesrelated 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 administrativeexpenses of our natural gas liquids logistics segment increased approximately $0.8 million during the year ended March 31, 2013 as compared to general andadministrative expenses of $2.7 million during the year ended March 31, 2012. This increase is due primarily to increased compensation and related expensesresulting from our SemStream combination. During the year ended March 31, 2013, our natural gas liquids logistics segment incurred $1.7 million of generaland 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 andamortization expense of our natural gas liquids logistics segment increased approximately $4.3 million during the year ended March 31, 2013, as compared todepreciation and amortization expense of approximately $3.7 million during the year ended March 31, 2012. This increase is due primarily to depreciation andamortization expense related to assets acquired in the SemStream combination, including depreciation of terminal assets and amortization of customerrelationship intangible assets. During the year ended March 31, 2013, our natural gas liquids logistics segment recorded $3.1 million of depreciation andamortization 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 millionof operating income contributed by the operations acquired in the merger with High Sierra. Exclusive of these operations, operating income improved by $7.7million, which was due to increased product margins, partially offset by increased expenses. 62Table of Contents Retail Propane The following table compares the operating results of our retail propane segment for the periods indicated: Year EndedChange Resulting FromMarch 31,Retail20132012Combinations(*)Other(in thousands)Revenues:Propane sales$288,410$175,417$117,686$(4,693)Distillate sales106,1926,54799,410235Other sales35,85617,37020,752(2,266)Total revenues430,458199,334237,848(6,724)Expenses:Cost of sales - propane155,118117,72263,080(25,684)Cost of sales - distillates90,7725,72884,933111Cost of sales - other12,6886,6926,516(520)Operating expenses88,65139,17647,4542,021General and administrative expenses10,8648,9505,409(3,495)Depreciation and amortization expense25,49611,45013,059987Total expenses383,589189,718220,451(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 inJanuary 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 propanebusiness 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 millionduring the year ended March 31, 2012. The principal reason for the increase in propane sales was the acquisitions of Osterman, Pacer, North American, andDowneast. 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 gallonsold 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 werehigher 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. Thewinter 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 endedMarch 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 theacquired operations was higher than the average selling price for our historical operations, due in part to the fact that the markets served by the acquiredoperations 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 atan 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 salesof $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 thanduring 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, ascompared 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 duringthe 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 wascolder 63Table of Contents 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 endedMarch 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 acquiredoperations 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, ingeneral, 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 anaverage 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 ourOsterman, Pacer, North American, and Downeast acquisitions, the operations of which generated $47.5 million of operating expense during the year endedMarch 31, 2013. General and Administrative Expenses. General and administrative expenses of our retail propane segment increased approximately $1.9 millionduring the year ended March 31, 2013 as compared to general and administrative expenses of $9.0 million during the year ended March 31, 2012. Theprincipal 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 ofacquisition 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 duringthe 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 isdue primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which generated $13.1 million ofdepreciation 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, 2013compared 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 operationsof Osterman, Pacer, North American, and Downeast. Excluding these acquired operations, our retail segment’s operating income was higher during the yearended 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 reducedsales volumes during fiscal 2012. 64Table of Contents Year Ended March 31, 2012 of NGL Energy Partners LPCompared 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 EndedSix Months EndedMarch 31,March 31,20122011 Revenues$1,310,473$622,232 Expenses:Cost of sales1,217,023583,032Operating expenses47,30015,898General and administrative expenses16,0095,024Depreciation and amortization15,1113,441Total expenses1,295,443607,395 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 thesix months ended March 31, 2011, due in part to the Osterman, SemStream, Pacer, and North American combinations. Three of these acquisitionssignificantly expanded our retail propane customer base. The SemStream combination significantly expanded our natural gas liquids logistics business, as theacquisition of SemStream’s terminals and leased rail cars gave us considerably more flexibility in the wholesale markets we can serve. In addition, the yearended 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 yearended 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 duringthe six months ended March 31, 2011, due primarily to business combinations. In the business combination accounting, we recorded a significant amount ofproperty, 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 tocompare 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 changesfrom period to period that are attributable to acquisitions. This is not possible for the wholesale operations acquired in our business combination withSemStream; for product purchases and sales subsequent to the combination date, it is not possible to determine which of the transactions are attributable toour historical operations and which are attributable to the operations acquired from SemStream. 65Table of Contents Six Months Ended March 31, 2012 for NGL Energy Partners LPCompared 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 endedMarch 31, 2012 and the six months ended March 31, 2011, respectively. Gallons sold by our natural gas liquids logistics segment shown in the table belowinclude sales to our retail segment. Six Months EndedChange Resulting FromMarch 31,March 31,RetailSemStreamOther20122011CombinationsCombinationVolumePercentage(gallons in thousands)Retail propane —Propane65,27234,93234,839—(4,499)(12.9)%Distillates1,650—1,650———Natural gas liquids logistics —Propane447,755372,504—(*)75,25120.2%Other NGLs96,89949,465—(*)47,43495.9% (*) Although the SemStream combination enabled us to significantly expand our wholesale operations, it is not possible to determine which of thevolumes sold subsequent to the combination were specifically attributable to this combination and which were attributable to our historicalwholesale business. Operating income by segment Our operating income by segment is as follows: Six Months EndedMarch 31,March 31,Segment20122011Change(in thousands)Retail propane$15,908$7,362$8,546Natural gas liquids logistics11,1289,5901,538Corporate general and adminstrative expenses(1,795)(2,115)320$25,241$14,837$10,404 66Table of Contents Retail Propane The following table compares the operating results of our retail propane segment for the periods indicated: Six Months EndedChange Resulting FromMarch 31,March 31,Retail20122011CombinationsOther(in thousands)Revenues:Propane sales$149,161$67,175$85,687$(3,701)Distillate sales6,547—6,547—Service and rental income6,5752,9813,339255Parts, fittings, appliance and other sales4,9742,6571,693624Total revenues167,25772,81397,266(2,822)Expenses:Cost of sales - propane98,83044,74455,174(1,088)Cost of sales - distillates5,728—5,728—Cost of sales - other sales4,2702,2411,790239Operating expenses26,88213,51713,478(113)General and administrative expenses6,6442,0624,631(49)Depreciation and amortization8,9952,8876,08127Total expenses151,34965,45186,882(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 sixmonths ended March 31, 2011. The increase in propane sales is due primarily to the impact of our Osterman combination in October 2011, our Pacercombination in January 2012, and our North American combination in February 2012. Excluding the impact of these combinations, propane sales were lowerduring 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 milliongallons 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 dueprimarily to unusually warm weather during the heating season, which reduced demand. The decrease in volumes was partially offset by an increase in theaverage 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 pergallon. 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 thefact 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 byour 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 $44.7million 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 inOctober 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 adecline 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 volumeswas 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 monthsended 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 pergallon. 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 themarkets served by the acquired operations are, in general, farther away from the primary areas of propane supply than are the markets served by ourhistorical operations. 67Table of Contents Operating Expenses. Operating expenses of our retail propane segment increased $13.4 million during the six months ended March 31, 2012 ascompared to operating expenses of $13.5 million during the six months ended March 31, 2011. This increase is due primarily to our Osterman, Pacer, andNorth American combinations. General and Administrative Expenses. General and administrative expenses of our retail propane segment increased $4.6 million during the sixmonths ended March 31, 2012 as compared to general and administrative expenses of $2.1 million during the six months ended March 31, 2011. Thisincrease 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 monthsended March 31, 2012 as compared to depreciation and amortization expense of $2.9 million during the six months ended March 31, 2011. This increase isdue primarily to the impact of depreciation and amortization on assets acquired in the Osterman combination in October 2011, our Pacer combination inJanuary 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 tooperating 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 primarilyto the operations acquired in our business combinations during the six months ended March 31, 2012. Operating income from our historical retail operationswas 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 ofmild 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 EndedMarch 31,March 31,20122011Change(in thousands)Revenues:Propane sales$611,781$477,774$134,007Other natural gas liquids sales174,92190,74684,175Transportaion and other revenues1,7021,183519Total revenues (1) 788,404569,703218,701 Expenses:Cost of sales766,842556,331210,511Operating expenses6,0262,3813,645General and adminstrative expenses1,370847523Depreciation and amortization expense3,0385542,484Total expenses777,276560,113217,163 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 $20.3million of sales to our retail propane segment during the six months ended March 31, 2011. These intercompany sales, along with acorresponding 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 SemStreamcombination and an increase in wholesale customer pre-buys as compared to the prior fiscal year. Sales of other natural gas liquids (including sales toaffiliates) increased approximately $84.2 million as compared to the same period in fiscal 2011 primarily as a result of the impact of the SemStreamcombination and resulting acquisition of owned and leased rail cars, which have allowed us to significantly expand our marketing of such liquids. 68Table of Contents 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 $31.2million 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 sixmonths 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 resultingfrom 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 sixmonths 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 wholesalecost 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 ofpropane 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 ofapproximately $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 ofother 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 fixedprice sale commitments we had entered into prior to the beginning of the heating season and to the impact of commodity derivative instruments. We entered intocertain commodity swaps as economic hedges against the potential decline in the market value of our inventories. When commodity prices declined throughoutthe 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 increasedcompensation 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 millionduring 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 SemStreamcombination. Depreciation and Amortization. Depreciation and amortization expense of the natural gas liquids logistics segment increased $2.5 million duringthe 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, 2012as compared to operating income of $9.6 million during the six months ended March 31, 2011. This increase in operating income of $1.5 million is dueprimarily to increased margins from product sales, partially offset by an increase in operating and general and administrative expenses from the SemStreamcombination. 69Table of Contents Six Months Ended September 30, 2011 for NGL Energy Partners LPCompared to Six Months Ended September 30, 2010 for NGL Supply Volumes Sold The following table summarizes the volume of gallons sold by our retail propane and natural gas liquids segments for the six months endedSeptember 30, 2011 and the six months ended September 30, 2010, respectively. Gallons sold by our natural gas liquids logistics segment shown in the tablebelow include sales to our retail segment. Six Months EndedChange Resulting FromSeptember 30,September 30,AcquisitionOther20112010of HicksgasVolumePercentage(gallons in thousands)Retail propane12,9643,7479,198190.5%Natural gas liquids logistics250,265272,422—(22,157)(8.1)% Our retail propane sales volumes for the six months ended September 30, 2011 increased 9.2 million gallons as compared to sales of 3.7 milliongallons during the six months ended September 30, 2010 due entirely to the impact of our Hicksgas acquisition in October 2010. Hicksgas had retail sales of9.2 million gallons during the six months ended September 30, 2011. The increased sales of our pre-existing business during the six months endedSeptember 30, 2011 were not significant. Sales of our natural gas liquids logistics segment decreased 22.2 million gallons during the six months ended September 30, 2011 as compared tosales of 272.4 million gallons during the six months ended September 30, 2010. This decrease in sales is due primarily to a decrease in purchases for storageby our wholesale customers and a reduced level of liftings from storage by our pre-sale customers. Operating income (loss) by segment Our operating income (loss) by segment is as follows: Six Months EndedSeptember 30,September 30,Segment20112010Change(in thousands)Retail propane$(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 andadministrative 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. 70Table of Contents Retail Propane The following table compares the operating results of our retail propane segment for the periods indicated: Six Months EndedChange Resulting FromSeptember 30,September 30,Acquisition of20112010HicksgasOther(in thousands)Revenues:Propane sales$26,256$6,128$18,790$1,338Service and rental income2,7014842,228(11)Parts, fittings, appliance and other sales3,1202562,907(43)Total revenues32,0776,86823,9251,284Expenses:Cost of sales - propane18,8924,48913,3241,079Cost of sales - other sales2,4222602,256(94)Operating expenses12,2943,3308,830134General and administrative expenses2,3064881,337481Depreciation and amortization2,4558701,56520Total expenses38,3699,43727,3121,620 Segment operating loss$(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 duringthe six months ended September 30, 2010. This increase is due primarily to the impact of our Hicksgas acquisition in October 2010. During the six monthsended 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 pergallon. Excluding the impact of Hicksgas, propane sales of our pre-existing business increased $1.3 million during the six months ended September 30, 2011as 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 costof 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, dueentirely to the effect of propane price increases. Overall, our propane cost per gallon averaged $1.46 during the six months ended September 30, 2011compared 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 ascompared 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 Hicksgasacquisition in October 2010. Hicksgas had operating expenses of $8.8 million during the six months ended September 30, 2011. The increase in operatingexpenses 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 sixmonths ended September 30, 2011 as compared to general and administrative expenses of $0.5 million during the six months ended September 30, 2010. Thisincrease 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 andadministrative expenses of $1.3 million. In addition, the general and administrative expenses of our pre-existing business increased $0.5 million during the sixmonths 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 theperiod 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 monthsended September 30, 2011 as compared to depreciation and amortization expense of $0.9 million during the six months ended September 30, 2010. Thisincrease is due to the impact of our Hicksgas acquisition in October 2010. Hicksgas had depreciation and amortization expense of $1.6 million during the sixmonths ended September 30, 2011. 71Table of Contents Operating Loss. Our retail propane segment had an operating loss of $6.3 million during the six months ended September 30, 2011 as compared toan 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 dueprimarily to the impact of our Hicksgas acquisition in October 2010. Hicksgas had an operating loss of $3.4 million during the six months endedSeptember 30, 2011. The operating loss of our pre-existing business increased approximately $0.3 million during the six months ended September 30, 2011primarily 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 EndedSeptember 30,September 30,20112010Change(in thousands)Revenues:Product sales$387,947$315,364$72,583Storage revenues760959(199)Total revenues (1) 388,707316,32372,384 Expenses:Cost of sales386,011312,40773,604Operating expenses2,0981,901197General and adminstrative expenses1,368631737Depreciation and amortization expense623519104Total expenses390,100315,45874,642 Segment operating income (loss)$(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 acorresponding 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 millionduring 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 salesprice, 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 endedSeptember 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 theoverall 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 millionduring 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 ofpropane, 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 duringthe 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 increasein 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 endedSeptember 30, 2011 as compared to operating expenses of $1.9 million during the six months ended September 30, 2010. This increase is due to increasedcompensation 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 millionduring the six months ended September 30, 2011 as compared to general and administrative expenses of $0.6 72Table of Contents million during the six months ended September 30, 2010. This increase is due primarily to an increase in compensation expense due to an increase inemployees 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 endedSeptember 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 $2.3million. 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 generaland administrative expenses of $0.7 million. 73Table of Contents Six Months Ended March 31, 2011 for NGL Energy Partners LPCompared 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 NGLSupply for the six months ended September 30, 2010 by approximately $305.3 million. This increase is due to the significant increase in volume of propanesales for both our retail propane and natural gas liquids logistics segments. This increase in volume is due to the combined impact of seasonality and theacquisition of Hicksgas. Propane prices also increased during the six months ended March 31, 2011 as compared to the prices during the six months endedSeptember 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 sixmonths ended September 30, 2010 by approximately $272.1 million. This increase is also due to the significant increase in volume of propane sales of ourretail propane and natural gas liquids logistics segments as a result of the combined impact of seasonality and the acquisition of Hicksgas. Cost of sales alsoincreased 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 monthsended 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 ofapproximately $12.5 million. The operations of Hicksgas resulted in an increase in operating and general and administrative expenses of $11.4 million duringthe six months ended March 31, 2011 as compared to the six months ended September 30, 2010. In addition, our costs during the six months endedMarch 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 ascompared 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 amortizationexpense 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 forthe six months ended September 30, 2010. This increase in net income is due primarily to the increased gross margin resulting from the seasonal impact ofincreased 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 residentialmarket where propane is used primarily for heating. During the year ended March 31, 2013, approximately 74% of our retail propane volume was sold duringthe peak heating season from October through March. Consequently, sales, operating profits and positive operating cash flows are generated mostly in thethird and fourth quarters of each fiscal year. We have historically realized operating losses and negative operating cash flows during our first and second fiscalquarters. 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 cashflows 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 needsgenerally occur during the period of June through December, when we are building our natural gas liquids inventories in anticipation of the heating season. Ourworking capital borrowing needs generally decline during the period of January through March, when the cash flows from our retail propane and natural gasliquids 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 45days 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 therespective fiscal quarter less the amount of cash reserves established by our general partner in its reasonable discretion for future cash requirements. Thesereserves are retained for the proper conduct of our business, 74Table of Contents debt principal and interest payments and for distributions to our unitholders during the next four quarters. Our general partner reviews the level of availablecash 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 meetour 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 additionalcapital. Our ability to raise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give anyassurances that we can raise additional capital to meet these needs (see Part I, Item 1A, “Risk Factors”). Commitments or expenditures, if any, we may maketoward 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 ofcommon units or debt securities, and public offerings of common units or debt securities. Our ability to raise additional capital through the issuance of debt orequity 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 revolvingcredit 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 $250million of Senior Notes in a private placement (the “Senior Notes”). We used the proceeds from the issuance of the Senior Notes and borrowings under theCredit 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 aremaining capacity of $146.4 million at March 31, 2013. The Expansion Capital Facility had a total capacity of $527.5 million for cash borrowings atMarch 31, 2013. At March 31, 2013, we had outstanding cash borrowings of $441.5 million on the Expansion Capital Facility, leaving a remaining capacityof $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 theCredit Agreement, which is calculated based on the value of certain working capital items at any point in time. At March 31, 2013, the borrowing baseprovisions 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 paidapproximately $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 CreditAgreement without incurring any penalties, and pre-payments of principal may be required if we enter into certain transactions to sell assets or obtain newborrowings. 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, asdefined 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 of0.21% 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 bysubstantially 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. AtMarch 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 CreditAgreement, 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, limitationson fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement 75Table of Contents may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal orinterest 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. TheSenior Notes are required to be repaid in semi-annual installments of $25 million beginning on December 19, 2017 and ending on the maturity date ofJune 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured bysubstantially 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 ourability 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 withaffiliates, (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 isdescribed above. The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary graceand 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 unpaidor 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 PurchaseAgreement, 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 ofbankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregateprincipal 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, wewrote 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 ourconsolidated 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): AmountRate Expansion capital facility —LIBOR borrowings$441,5003.21%Working capital facility —LIBOR borrowings20,0003.21%Base rate borrowings16,0005.25% 76Table of Contents The following table provides certain information on revolving credit facility borrowings during the year ended March 31, 2013 (dollars inthousands): AverageAverageDailyLowestHighestInterestBalanceBalanceBalanceRate New credit facility (June 19, 2012 - March 31, 2013) —Expansion loans$351,355$254,000$451,0003.48%Working capital loans92,626—153,5003.77%Previous credit facility (April 1, 2012 - June 19, 2012) —Acquisition loans222,238186,000239,2753.65%Working capital loans42,70022,00067,5004.07% Business Combinations Subsequent to our initial public offering, we significantly expanded our operations through a number of business combinations, as described underPart I, Item I, “Businesses — Acquisitions Subsequent to Initial Public Offering.” 77Table of Contents Cash Flows The following summarizes the sources and uses of our cash flows for the periods indicated: NGL Energy Partners LPNGL SupplyYear EndedYear EndedSix Months EndedSix Months EndedMarch 31,March 31,March 31,September 30,Cash Flows Provided by (Used In):2013201220112010(in thousands)Operating activities, before changes in operating assets andliabilities$146,395$20,459$15,905$(2,491)Changes in operating assets and liabilities(14,164)69,87018,104(28,258) Operating activities$132,231$90,329$34,009$(30,749) Investing activities(546,218)(296,897)(18,438)333 Financing activities417,716198,063(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 increasedoperating activity resulting from acquisitions. Changes in working capital due to changes in the timing of cash receipts and payments can have a significantimpact on cash flows from operations. During fiscal 2013, our cash outflows from investing activities included the purchase of working capital in businesscombinations, a portion of which has benefitted (or will benefit) cash flows from operations as the working capital is recovered. Our operating cash flowsduring 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 assetsfrom SemStream on November 1, 2011, in which we acquired $104.2 million of inventory. The cash paid to complete the SemStream transaction is includedwithin cash outflows from investing activities. The seasonality of our retail propane and natural gas liquids logistics business had a significant effect on ourcash flows from operating activities during fiscal year 2011. As shown in the table above, cash flows from operations were significantly greater during thewinter heating season of fiscal 2011 than during the first six months of the fiscal year. 78Table of Contents Investing Activities. Our cash flows from investing activities are primarily impacted by our capital expenditures and business combinations. Inperiods where we are engaged in significant acquisitions, we will generally realize negative cash flows from investing activities, which may require us toincrease the borrowings under our acquisition or working capital facilities. During the year ended March 31, 2013, we completed thirteen acquisitions, forwhich 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 additionto the acquisitions of businesses. Of this amount, approximately $58.7 million represented expansion capital and approximately $13.8 million representedmaintenance capital. During the year ended March 31, 2013, we generated $11.6 million of investing cash inflows from commodity derivatives and $5.1million of investing cash inflows from the sale of long-lived assets. During the year ended March 31, 2012, we completed four significant acquisitions andseveral 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 ourrevolving credit facilities, either to fund our operating or investing requirements. In periods where our cash flows from operating activities are reduced (such asduring our first and second quarters), we fund the cash flow deficits through our working capital facility. Cash flows required by our investing activities inexcess of cash available through our operating activities have historically been funded by our acquisition credit facility. In the table above, we had positivecash 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 endedSeptember 30, 2010. During the year ended March 31, 2012, we borrowed $149.0 million on our revolving credit facilities (net of repayments), primarily tofund 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 eachyear 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 inadvance of our formation transactions. We made a distribution of $40.0 million to the previous shareholders of NGL Supply during the six months endedMarch 31, 2011. Such distributions and the negative cash flows realized from our operating activities during the six months ended September 30, 2010required us to increase our borrowings under our revolving credit facility. We expect our distributions to our partners to increase in future periods under theterms of our partnership agreement. Based on the number of common and subordinated units outstanding at March 31, 2013, if we made distributions equalto our minimum quarterly distribution of $0.3375 per unit ($1.35 annualized), total distributions would equal $18.1 million per quarter ($72.5 million peryear). To the extent our cash flows from operating activities are not sufficient to finance our required distributions, we may be required to increase theborrowings under our working capital credit facility. The following table summarizes the distributions declared since our initial public offering: AmountAmount Paid toAmount Paid toDate DeclaredRecord DateDate PaidPer UnitLimited PartnersGeneral Partner(in thousands)(in thousands)July 25, 2011August 3, 2011August 12, 2011$0.1669$2,467$3October 21, 2011October 31, 2011November 14, 20110.33754,9905January 24, 2012February 3, 2012February 14, 20120.35007,73510April 18, 2012April 30, 2012May 15, 20120.36259,16510July 24, 2012August 3, 2012August 14, 20120.412513,574134October 17, 2012October 29, 2012November 14, 20120.450022,846707January 24, 2013February 4, 2013February 14, 20130.462524,245927April 25, 2013May 6, 2013May 15, 20130.477525,6051,189 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 creditfacility. 79Table of Contents 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,Total20142015201620172017(in thousands)Debt principal payments —Acquisition advances$441,500$—$—$—$—$441,500Working capital advances36,000————36,000Senior Notes250,000————250,000Other long-term debt21,5628,6266,4563,0882,0911,301Scheduled interest payments on revolving credit facility(1)77,32918,32818,32818,32818,3284,017Scheduled interest payments on senior notes116,37516,62516,62516,62516,62549,875Scheduled interest payments on other long-term debt——————Standby letters of credit60,082————60,082Future minimum lease payments under noncancelableoperating leases211,43855,06538,28331,29729,00557,788Fixed price commodity purchase commitments (2)380,205312,43539,25228,518——Index priced commodity purchase commitments (2) (3)604,584586,32418,260———Total contractual obligations$2,199,075$997,403$137,204$97,856$66,049$900,563 Natural gas liquids gallons under fixed-price purchasecommitments (thousands)84,15984,159————Natural gas liquids gallons under index-price purchasecommitments (thousands)540,518521,53418,984———Crude oil barrels under fixed-price purchase commitments(thousands)3,3822,550475358—— (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 consolidatedfinancial statements as of March 31, 2013 included elsewhere herein for additional information on our credit agreement. We are required to pay a commitment fee rangingfrom 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. AtMarch 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, 2013would result in a change of approximately $54.1 million in the value of our index-based purchase commitments. 80Table of Contents 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 elsewherein this annual report. Environmental Legislation Please see “Item 1 — Business — Government Regulation — Greenhouse Gas Regulation” for a discussion of proposed environmental legislationand regulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure or outcome ofany 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 logisticsbusiness is heavily influenced by the volume of crude oil being produced. Currently, market conditions are favorable, and production of crude oil in NorthAmerica 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 togenerate higher margins by transporting crude from lower-price markets to higher-price markets. During fiscal 2013, the spread between crude oil prices in themid-continent region and crude oil prices in south Texas widened, which gave us the opportunity to generate favorable margins by transporting crude from oneregion 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 ourfacilities are located. Recently, production has been strong in these regions. A future decline in the level of production could have an adverse impact onprofitability. 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 theproducer for use in future drilling operations. We typically generate higher margins from this activity than from our disposal operations. Under currentconditions, 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 incustomer 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 influencedby 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 areinfluenced 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 utilizeour 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 customerdemand 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 81Table of Contents 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 appropriateaccounting principles to the relevant facts and circumstances of the Partnership’s operations and the use of estimates made by management. We have identifiedthe following critical accounting policies that are most important to the portrayal of our financial condition and results of operations. Changes in these policiescould have a material effect on the financial statements. The application of these accounting policies necessarily requires subjective or complex judgmentsregarding 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 productby 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 theterm 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 customersfor shipping and handling costs are included in revenues in the consolidated statements of operations. Shipping and handling costs associated with productsales 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 samecounterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we recordthe 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 ofour fiscal year, and more frequently if circumstances warrant. We completed the assessment of each of our reporting units and determined no impairmentexisted for the year ended March 31, 2013. The assessment of the value of our reporting units requires us to make certain assumptions relating to futureoperations. When evaluating operating performance, various factors are considered such as current and changing economic conditions and the commodityprice environment, among others. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairmentcharge. 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 areview. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the assetgroup 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 todetermine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, theestimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimatedfair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. At March 31, 2013, we haverecorded 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 ofour water services business. In addition to the pipeline injection facilities and the water processing facilities, we may be obligated by contractual or regulatory requirements toremove 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 donot believe the present value of such asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of ourfacilities, is material to our financial position or results of operations. 82Table of Contents 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 theresults of operations for the quarterly and annual periods during which the assets are used. We depreciate the majority of our property and equipment using thestraight-line method, which results in our recording depreciation expense evenly over the estimated life of the individual asset. The estimate of depreciationexpense requires us to make assumptions regarding the useful economic lives and residual values of our assets. At the time we acquire and place our propertyand equipment in service, we develop assumptions about such lives and residual values that we believe are reasonable; however, circumstances may developthat could require us to change these assumptions in future periods, which would change our depreciation expense amounts prospectively. Examples of suchcircumstances include changes in laws and regulations that limit the estimated economic life of an asset, changes in technology that render an asset obsolete, orchanges 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 $39.2million, $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 includedelsewhere 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 quarterlyand annual periods during which the assets are used. We amortize the majority of these intangible assets using the straight-line method, which results in ourrecording amortization expense evenly over the estimated life of the individual asset. The estimate of amortization expense requires us to make assumptionsregarding the useful economic lives of our assets. At the time we acquire intangible assets, we develop assumptions about the lives of such assets that webelieve to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which could change ouramortization expense amounts prospectively. Examples of such circumstances include changes in customer attrition rates and changes in laws and regulationsthat 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 inthis annual report. For additional information on the valuation methodology for customer relationship intangible assets acquired in business combinations, seeNote 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 methodknown as the “acquisition method”, in which the assets acquired and liabilities assumed are recorded at their estimated fair values. Fair values of assetsacquired 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 tangibleand intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involveproperty and equipment and intangible assets, including those with indefinite lives. The excess of purchase price over the net fair value of acquired assets overthe assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Generally, we have up to one year from theacquisition date to finalize the identification and valuation of acquired assets and liabilities. The impact of subsequent changes to the identification of assetsand 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 anddemand conditions change. We value our inventory using the weighted-average cost and first-in first-out 83Table of Contents 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 basedon 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 intoconsideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business to sellthe inventory in retail markets. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record alower-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 marketvalue of these commodities and are unable to determine whether writedowns will be required in future periods. In addition, writedowns at interim periods couldbe 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 productvolumes 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 nocost, 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 ofproduct exchange assets and liabilities based on the weighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus orminus location differentials, which we believe represents the value of the exchange volumes at such date. Changes in product prices could impact ourestimates. 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 ourvariable-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 butdo 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 ordecrease 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 themarket 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 receivepayment from customers on a monthly basis. As a result, receivables from individual customers in our crude business are generally higher than thereceivables 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 onan ongoing basis. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operationspersonnel. 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 forcertain 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. 84Table of Contents The natural gas liquids and crude oil industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential ofsales 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 thereare 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 customersthrough retail or wholesale prices. Natural gas liquids and crude oil are commodities and the price we pay for them can fluctuate significantly in response tosupply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost increases can significantly affect ourrealized 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 futurecontracts, 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 productduring periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment fromour wholesale and retail customers. We may experience net unbalanced positions from time to time which we believe to be immaterial in amount. In addition toour 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 ourderivative portfolio. Although we use derivative commodity instruments to reduce the market price risk associated with forecasted transactions, we have not accountedfor 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 $7.1 million. We record the changes in fair valueof these derivative commodity instruments within cost of sales. The following table summarizes the hypothetical impact on the fair value of our commodityderivatives of an increase of 10% in the value of the underlying commodity (in thousands): Increase(Decrease)To Fair ValuePropane (Natural gas liquids logistics segment)$(1,119)Natural gas liquids (Natural gas liquids logistics segment)(17,698)Heating oil (Retail segment)33Crude 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 andother 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 “ExchangeAct”), that are designed to provide reasonable assurance that information required to be disclosed in our filings and submissions under the Exchange Act isrecorded, processed, summarized and reported within the periods specified in the rules and forms of the SEC and that such information is accumulated andcommunicated to our management, 85Table of Contents including the principal executive officer and principal financial officer of our general partner, as appropriate, to allow timely decisions regarding requireddisclosure. We completed an evaluation under the supervision and with participation of our management, including the principal executive officer and principalfinancial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2013. Basedon this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31, 2013, suchdisclosure 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 monthsended 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 statementsincluded in this Annual Report on Form 10-K. At this time, we continue to evaluate the business and internal controls and processes of these acquiredbusinesses and are making various changes to their operating and organizational structure based on our business plan. We are in the process of implementingour internal control structure over these acquired businesses. We expect that our evaluation and integration efforts related to those combined operations willcontinue 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 financialreporting, as such term is defined in Exchange Act Rule 13a-15(f). Under the supervision and with the participation of our management, including the ChiefExecutive Officer and Chief Financial Officer of our general partner, we conducted an evaluation of the effectiveness of our internal control over financialreporting based on the framework in 1992 Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of theTreadway 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 financialreporting for the year ending March 31, 2013 due to their size and complexity and the limited time available to complete the evaluation. The operations excludedfrom our evaluation represent approximately 68% of our total assets at March 31, 2013, and approximately 73% of our total revenues for the year endedMarch 31, 2013. Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as ofMarch 31, 2013. Our internal control over financial reporting as of March 31, 2013 has been audited by Grant Thornton LLP, an independent registered publicaccounting 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. 86Table of Contents 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 orindirectly participate in our management or operations. The NGL Energy GP Investor Group appoints all members to the board of directors of our generalpartner. The board of directors of our general partner currently has eleven members. The board of directors of our general partner has determined thatMr. Kneale, Mr. Cropper, and Mr. Guderian satisfy the NYSE and SEC independence requirements. The NYSE does not require a listed publicly tradedlimited 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 andbusiness, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. Our general partner has no minimumqualifications for director candidates. In general, however, the NGL Energy GP Investor Group reviews and evaluates both incumbent and potential newdirectors 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 ortransportation, 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 partnershipmatters. Although our general partner does not have a formal policy in regard to the consideration of diversity in identifying director nominees, qualifiedcandidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin. 87Table of Contents 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 electedand qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, theboard of directors of our general partner. The following table shows information regarding the current directors of our general partner and our executive officers. NameAgePosition with NGL Energy Holdings LLCH. Michael Krimbill59Chief Executive Officer and DirectorPatrice Armbruster52Senior Vice President, AccountingAtanas H. Atanasov40Chief Financial OfficerBradley K. Atkinson58Vice President, Business DevelopmentJames J. Burke57Chief Executive Officer of High Sierra Energy and DirectorShawn W. Coady51President and Chief Operating Officer, Retail Division and DirectorTodd M. Coady55Vice President, AdministrationDavid C. Kehoe54Chief Operating Officer of High Sierra EnergyVincent J. Osterman56President, Eastern Retail Propane Operations and DirectorSharra Straight49Vice President and ControllerKevin C. Clement54DirectorStephen L. Cropper63DirectorBryan K. Guderian53DirectorJames C. Kneale62DirectorNorman J. Szydlowski62DirectorPatrick Wade44DirectorWilliam A. Zartler48Director 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 ourgeneral partner since its formation in September 2010. From February 2007 through September 2010, Mr. Krimbill managed private investments. Mr. Krimbillwas the President and Chief Financial Officer of Energy Transfer Partners, L.P. from 2004 until his resignation in January 2007. Mr. Krimbill joined HeritagePropane Partners, L.P., the predecessor of Energy Transfer Partners, as Vice President and Chief Financial Officer in 1990. Mr. Krimbill was President ofHeritage from 1999 to 2000 and President and Chief Executive Officer of Heritage from 2000 to 2005. Mr. Krimbill also served as a director of EnergyTransfer Equity, the general partner of Energy Transfer Partners, from 2000 to January 2007. Mr. Krimbill is also currently a member of the board ofdirectors of Pacific Commerce Bank. Mr. Krimbill brings leadership, oversight and financial experience to the board. Mr. Krimbill provides expertise in managing and operating apublicly traded partnership, including substantial expertise in successfully acquiring and integrating propane and midstream businesses. Mr. Krimbill alsobrings financial expertise to the board, including through his prior service as a chief financial officer. As a director for other public companies, Mr. Krimbillalso provides cross board experience. Patrice Armbruster. Ms. Armbruster has served as our Senior Vice President of Accounting since May 2012. Ms. Armbruster previously servedseveral roles in accounting and SEC reporting with Energy Transfer Partners, L.P. and Heritage Propane from March 2001 through May 2012. InMarch 2001, Ms. Armbruster joined Heritage Propane Partners, L.P. the predecessor of Energy Transfer Partners, as the manger of financial reporting. Hermost recent role prior to coming to NGL was the Director of Financial Reporting and Controller with Heritage Propane. For 10 years prior to joining HeritagePropane Partners, L.P. Ms. Armbruster worked as an audit manager for a regional public accounting firm in Montana. Ms. Armbruster received a B.A. inAccounting 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 inNovember 2011, and previously served as our Senior Vice President of Finance. Prior to joining NGL, Mr. Atanasov spent nine years at GE Capital, workingin lending and leveraged equity. Prior to GE Capital, he was with The Williams Companies. Mr. Atanasov is a Certified Public Accountant and holds aMasters 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 throughSeptember 2010, Mr. Atkinson managed private investments. Mr. Atkinson was previously an officer of Energy 88Table of Contents Transfer Partners, L.P., and its predecessor, Heritage Propane Partners, L.P., serving as the Vice President — Corporate Development from August 2000 toMarch 2007 and as the Vice President of Administration from April 1998 to July 2000. Prior to joining Energy Transfer Partners, Mr. Atkinson held variouspositions at Mapco, Inc. from 1986 to 1998, where he managed the acquisitions and business development for Thermogas as the Vice President ofAdministration 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 andserved as Chairman of the High Sierra board and President and Chief Executive Officer of the High Sierra general partner since September 2010. FromJuly 2004 to September 2010, he was the High Sierra general partner’s Managing Director. Mr. Burke, along with three other entrepreneurs, co-founded PetroSource 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. Burkeserved 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 atPermian Corporation, where he worked from 1978 to 1981. Mr. Burke also serves as the Managing Director of Impact Energy Services, LLC. Mr. Burkereceived 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 asour 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 ofdirectors 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 tous as part of our formation transactions. Dr. Coady was an executive officer of Bachtold Brothers, Incorporated, a family owned company, when it filed forChapter 7 bankruptcy protection in October 2005. Dr. Coady was also the President of Gifford from March 1989 until the membership interests in Giffordwere 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 IllinoisPropane Gas Association since 2004. Dr. Coady has also served as the Illinois state director of the National Propane Gas Association since 2004. Dr. Coady hasa 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 propaneindustry, and provides expertise in both acquisition and organic growth strategies. Dr. Coady also provides insight into developments and trends in thepropane 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, RetailDivision from October 2010 through April 2012. Mr. Coady has served as an officer of HOH since March 1989. HOH contributed its propane and propanerelated 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 theVice President of Gifford from March 1989 until the membership interests in Gifford were contributed to us as part of our formation transactions. Mr. Coadywas 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 propaneoperations 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 ofthe Board of Directors of our general partner since October 2011. Mr. Osterman also serves as a director of the National Propane Gas Association, Propane GasAssociation 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 theretail propane businesses to the board. Mr. Osterman also provides insight into developments and trends in the propane industry through his leadership rolesin industry associations. David C. Kehoe. Mr. Kehoe serves as the Chief Operating Officer of our High Sierra subsidiary. Mr. Kehoe joined our management team throughour June 2012 merger with High Sierra. He has served on High Sierra’s management team since 2007. Prior to that, Mr. Kehoe held various leadershippositions 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 Financeand 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 promotedto positions of increasing responsibility at Texaco during the 89Table of Contents 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 ofSemStream L.P., which is a wholly owned subsidiary of SemGroup Corporation, since 2009. SemGroup Corporation has been an affiliate of NGL EnergyPartners LP and its general partner since November 2011. Mr. Clement previously served as President and Chief Operating Officer of SemMaterials, which isalso a wholly owned subsidiary of SemGroup Corporation, from 2008 to 2010 and also previously served SemMaterials as Vice President of residual fuelfrom 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 industryincludes officer positions over 24 years at Koch Industries while leading business unit divisions of NGL trading, U.S. refined products, asphalt and residualfuels. 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 hisfamiliarity 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 his25-year career at The Williams Companies, Inc., including serving as the President and Chief Executive Officer of Williams Energy Services, a Williamsoperating 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 ofSunoco 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 significantmanagement and governance experience, Mr. Cropper provides important skills in identifying, assessing and addressing various business issues. As adirector 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 VicePresident of Operations of WPX Energy, Inc. since August 2011. Mr. Guderian previously served as Vice President of the Exploration & Production unit ofThe Williams Companies, Inc. from 1998 until December 2011. Mr. Guderian had responsibility for overseeing Williams’ international operations and hasserved 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 petroleumindustry 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 OperatingOfficer of ONEOK, Inc., from January 2007, and ONEOK Partners, L.P., from May 2008, until his retirement in January 2010. After joining ONEOK in1981, Mr. Kneale served in various other roles, including Chief Financial Officer from 1999 through 2006. Mr. Kneale also served as a director of ONEOKPartners, 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 oiland 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 gasindustry 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 directorand President and Chief Executive Officer of SemGroup Corporation since November 2009. SemGroup Corporation has been an affiliate of NGL EnergyPartners LP and its general partner since November 2011. Mr. Szydlowski also serves as chairman of the board of directors, president and chief executiveofficer of SemGroup’s wholly-owned subsidiary Rose Rock Midstream GP, LLC, the general partner of Rose Rock Midstream, L.P. From January 2006 untilJanuary 2009, Mr. Szydlowski served as president and chief executive officer of Colonial Pipeline Company, an interstate common carrier of petroleumproducts. 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 heled an advisory team in the rehabilitation, infrastructure security and development of future strategy of the Iraqi oil sector. From 2002 until 2004, he served asvice president of refining for Chevron Corporation (formerly 90Table of Contents ChevronTexaco), one of the world’s largest integrated energy companies. Mr. Szydlowski joined Chevron in 1981 and served in various capacities ofincreasing 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 Sciencedegree 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 ofSemGroup 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 energysector. In 2002, Mr. Wade co-founded Tiger Midstream Investments, a natural gas midstream development and investment company that was involvedprimarily in the U.S. Rockies. From 2005 to 2007, Mr. Wade was a Managing Director at Bear Energy LP, responsible for investments in natural gasmidstream infrastructure, as well as contracting for a diverse portfolio of natural gas storage capacity. In 2008, Mr. Wade joined The Energy & MineralsGroup, as a Managing Director in the Houston office. The Energy & Minerals Group is a highly specialized private equity firm that focuses exclusively oninvesting across various facets of the global natural resource industry that are integral to the global economy. The Energy & Minerals Group has $6.2 billionof 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 resourcesindustry. 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 degreefrom 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 providesvaluable 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 ourformation transactions. Mr. Zartler was a founder and managing partner of Denham Capital Management LP, an energy and commodities focused privateequity firm, having been with the firm since its inception in 2004, and headed the firm’s Energy Infrastructure Group. Prior to joining Denham, Mr. Zartlerwas 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 developingacquisition 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 personsto 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 andKevin 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 thedesignees 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., theCoady Group (which consists of certain entities controlled by Shawn W. Coady and Todd M. Coady), and the IEP Parties (which consists of certain entitiescontrolled by H. Michael Krimbill, Bradley K. Atkinson, and another investor who is not a member of management of the Partnership) each have the right todesignate one person to serve on the board of directors. NGL Holdings, Inc. has designated William A. Zartler, the Coady Group has designatedShawn 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 orseparated should be decided by the board, from time to time, in its business judgment after considering relevant circumstances. The board of directors of ourgeneral 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 andrisks with respect to the creation of value for our unitholders. The board of directors of our general partner has delegated to management the primaryresponsibility for enterprise level risk management, while the board has retained responsibility for oversight of management in that regard. Management willoffer an enterprise level risk assessment to the board at least once every year. 91Table of Contents 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 theintegrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee hasthe 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 registeredpublic accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Ourindependent 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 directorsof our general partner has determined that Mr. Kneale, an independent director, is as an “audit committee financial expert” as defined under SEC rules. Incompliance 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 thefollowing, 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 registeredclass of our equity securities, to file initial reports of beneficial ownership and reports of changes in beneficial ownership of our common units and otherequity securities with the SEC. Directors, officers and greater than 10% unitholders are required by SEC regulations to furnish to us copies of allSection 16(a) forms they file with the SEC. 92Table of Contents 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, webelieve that all reporting obligations of our general partner’s directors and officers and our greater than 10% unitholders under Section 16(a) were satisfiedduring 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 theunits, certain officers elected to have the Partnership withhold a portion of the common units, in return for which the Partnership remitted withholdingpayments to taxing authorities on the officers’ behalf. The resultant changes in ownership of common units for these officers were reported late, including forPatrice 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 (reportedon 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 withthe 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. NGLHoldings, 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 reportedon 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 ofEthics, that applies to the chief executive officer, chief financial officer, chief accounting officer, controller and all other senior financial and accountingofficers 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 generalpartner has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of BusinessConduct 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 toany unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics and the charters of theaudit committee and the compensation committee of the board of directors of our general partner. Requests for print copies may be directed to Investor Relationsat investorinfo@nglep.com or to Investor Relations, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, OK 74136 or made by telephoneat (918) 481-1119. The information contained on, or connected to, our website is not incorporated by reference into this annual report and should not beconsidered 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 executivesession 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, anyindependent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of ourSecretary 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. 93Table of Contents Introduction The board of directors of our general partner has responsibility and authority for compensation-related decisions for our executive officers. InNovember 2011, the board of directors formed a compensation committee to develop our compensation program, to determine the compensation of our ChiefExecutive Officer, and to make recommendations to the board of directors regarding the compensation of our other executive officers. Our executive officers arealso officers of our operating companies and are compensated directly by our operating companies. While we reimburse our general partner and its affiliates forall 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 toour unitholders. Pay-for-performance is based on a combination of our performance and the individual executive officer’s contribution to our performance. Webelieve this pay-for-performance approach generally aligns the interests of our executive officers with the interests of our unitholders, and at the same timeenables 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 executiveofficers. Our Chief Executive Officer also provides periodic recommendations to the compensation committee and the board of directors regarding thecompensation of our other named executive officers. 94Table of Contents Elements of Executive Compensation As part of our pay-for-performance approach to executive compensation, the compensation of our executive officers includes a significant componentof incentive compensation based on our performance. We use three primary elements of compensation in our executive compensation program: ElementPrimary PurposeHow Amount DeterminedBase Salary ·Fixed income to compensate executive officersfor their level of responsibility, expertise andexperienceBased on competition in the marketplace forexecutive talent and abilitiesCash Bonus Awards ·Rewards the achievement of specific annualfinancial and operational performance goalsBased on the named executive officer’s relativecontribution to achieving or exceeding annualgoals ·Recognizes individual contributions to ourperformanceLong-Term Equity Incentive Awards ·Motivates and rewards the achievement of long-term performance goals, including increasingthe market price of our common units and thequarterly distributions to our unitholdersBased on the named executive officer’s expectedcontribution to long-term performance goals ·Provides a forfeitable long-term incentive toencourage 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 basesalary amounts were originally determined as part of the negotiations for our formation transactions. In setting the base salaries, the parties considered variousfactors, including the compensation needed to attract or retain the officers, the historical compensation of the officers, and each officer’s expected individualcontribution to our performance. At the request of Mr. Krimbill, the parties agreed that he should receive a lower base salary than our other named executiveofficers because, as our Chief Executive Officer, a significant portion of his compensation should be performance-based, to further align his interests with theinterests 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 andfinancial 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 completionof 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 themerger as they were before the merger. The base salary of Mr. Atanasov of $195,000 was negotiated prior to his joining our management team inNovember 2011. Cash Bonus Awards None of the named executive officers is subject to a formal bonus plan, and therefore annual bonus awards are discretionary. We did not make anybonus awards to our named executive officers for fiscal years 2012 and 2011, and have not yet made any bonus awards to our named executive officers forfiscal year 2013. 95Table of Contents Long-Term Equity Incentive Awards In May 2011, our general partner adopted the NGL Energy Partners LP 2011 Long-Term Incentive Plan for the employees and directors of our generalpartner who perform services for us. The Long-Term Incentive Plan authorizes the grant of restricted units, phantom units, unit options, unit appreciationrights and other unit-based awards. During fiscal 2013, the compensation committee granted awards of restricted units to certain of our named executive officers, in order to incentivizeretention and to reward the officers if the value of common units increases over time. The restricted units vest in tranches, subject to the continued service ofthe recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or bepaid on the restricted units during the vesting period. The scheduled vesting of the awards is summarized below: Grant DateTotalFair ValueNumber ofof RestrictedNumber of Restricted Units Awarded Vesting OnRestrictedUnitsJanuary 1,July 1,July 1,July 1,July 1,July 1,UnitsAwarded Name Grant Date201320132014201520162017Awarded($) H. Michael Krimbilln/a———————— Craig S. Jonesn/a———————— James J. BurkeDecember 26, 2012—10,00010,00010,00010,00010,00050,000836,400 David C. KehoeDecember 26, 2012—10,00010,00010,00010,00010,00050,000836,400 Atanas H. AtanasovJune 15, 20125,0005,0005,0005,0005,000—25,000463,900December 26, 20123,0003,0003,0003,0003,000—15,000279,540 Our Chief Executive Officer made recommendations to the compensation committee regarding the number of common units that each of the namedexecutive officer would receive. These recommendations were based on his judgment, considering the level of responsibility of each named executive officer andthe expected contribution of each of the named executive officers to our long-term performance. After the compensation committee reviewed theserecommendations, 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 inDecember 2012, primarily for officers and employees who joined in the Partnership in the merger with High Sierra. Mr. Atanasov was awarded an additionalgrant in December 2012, in recognition of an increase in his responsibilities between June 2012 and December 2012. 96Table of Contents 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 theapplicable dates, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of thelack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participantmight make about future distribution growth. This calculation of fair value is consistent with the provisions of the Financial Accounting Standards Board’sAccounting 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 vestingof 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. The401(k) plan permits all eligible employees, including our named executive officers, to make voluntary pre-tax contributions to the plan, subject to applicabletax 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 eligiblecompensation (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, untilwe 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 matchingcontributions equal to 100% of the employee’s contribution that is not in excess of 1% of the employee’s eligible compensation, and for employer matchingcontributions 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 annualIRS 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 thanperformance. 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 thecompensation committee. Pearl Meyer will prepare a marketplace compensation analysis for 25 management positions, including those of the named executiveofficers. This analysis will provide context to assist the compensation committee in making decisions related to the compensation arrangements for theseindividuals. Pearl Meyer will also provide specific recommendations about the design of the compensation programs, including annual incentive plan designand 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 thecompensation 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 limitedpartnership and we do not meet the definition of a “corporation” subject to deduction limitations under Section 162(m) of the Code. Nonetheless, the taxablecompensation paid to each of our named executive officers in calendar 2012 was substantially less than the Section 162(m) threshold of $1,000,000. Althoughthe value of the restricted units granted during fiscal 97Table of Contents 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 thegranting 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 Analysisset forth above with management. Based on this review and discussion, the compensation committee recommended to the board of directors of our generalpartner that the Compensation Discussion and Analysis be included in this annual report. Members of the compensation committee: Stephen L. Cropper (Chairman)James C. KnealeNorman J. SzydlowskiWilliam 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 toachieve short-term, unsustainable results. This includes using restricted unit grants as a significant element of the executive compensation, as the restrictedunits are designed to reward the executives based on the long-term performance of the Partnership. In combination with our risk-management practices, we donot 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 ofour general partner. Dr. Coady and Mr. Coady also serve as officers and directors of HOH, a family owned company. Both Dr. Coady and Mr. Coadyparticipate in the compensation setting process of the HOH board of directors 98Table of Contents 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 theperiod from October 1, 2010 (the date of our formation) through March 31, 2011. RestrictedAll OtherUnitCompensationFiscalSalaryBonusAwards (1)(2)Total Name and Position Year($)($)($)($)($) H. Michael Krimbill201382,849——2,49285,341Chief Executive Officer2012110,769——2,700113,469NGL Energy Partners LP201154,538———54,538 Craig S. Jones (3) 201383,836——3,00086,836Chief Financial Officer2012242,308——7,904250,212NGL Energy Partners LP2011118,830——3,077121,907 James J. Burke (4) 2013275,630—836,40013,0151,125,045Chief Executive OfficerHigh Sierra Energy GP, LLC David C. Kehoe (4) 2013228,781—836,40013,4901,078,671Chief Operating OfficerHigh Sierra Energy GP, LLC Atanas H. Atanasov (5) 2013195,000—743,4402,738941,178Senior Vice President of FinanceNGL 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 unitson 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 thegrant date and assumptions that a market participant might make about future distribution growth. This calculation of fair value is consistentwith 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 includeapproximately $6,300 for club memberships. (3) Mr. Jones retired during fiscal 2013, and Mr. Krimbill assumed the title of Chief Financial Officer. (4) Mr. Burke and Mr. Kehoe joined our management team upon completion of our merger with High Sierra on June 19, 2012. (5) Mr. Atanasov was not a named executive officer prior to fiscal 2013. 99Table of Contents Restricted Unit Awards During fiscal 2013, the board of directors granted awards of restricted units to certain of our named executive officers. The restricted units will vestin tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board ofdirectors. No distributions will accrue to or be paid on the restricted units during the vesting period. 2013 Grants of Plan Based Awards Table The number of restricted units granted to our named executive officers, and their grant date fair values, are summarized below: Grant DateTotalFair ValueNumber ofof RestrictedRestrictedUnitsGrantUnitsAwardedNameDateAwarded($) H. Michael Krimbilln/a—— Craig S. Jonesn/a—— James J. BurkeDecember 26, 201250,000836,400 David C. KehoeDecember 26, 201250,000836,400 Atanas H. AtanasovJune 15, 201225,000463,900December 26, 201215,000279,540 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 thegrant 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 lackof 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 marketparticipant 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 ofthe previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through each reporting date using the estimated fairvalue of the awards at the reporting date. 100Table of Contents 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 ofFair ValueRestrictedof UnvestedUnits ThatRestrictedHave NotUnits as ofYet VestedMarch 31,at March 31,2013Name 2013($) H. Michael Krimbill—— Craig S. Jones—— James J. Burke50,0001,345,000 David C. Kehoe50,0001,345,000 Atanas H. Atanasov32,000860,800 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 atMarch 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 $23.32 per unit. NumberValueof UnitsRealizedAcquiredon VestingName on Vesting($) H. Michael Krimbill—— Craig S. Jones—— James J. Burke—— David C. Kehoe—— Atanas H. Atanasov8,000186,560 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 inlieu 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 perunit). 101Table of Contents 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 vestingof 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 toexercise 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 adirector 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 hisboard 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 $5,000 for each member of the audit committee other than the chairman. All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Eachdirector is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law. Director Compensation for Fiscal 2013 The following table sets forth the compensation earned during fiscal 2013 by each director who is not an officer or employee of our general partner: FeesEarned orRestrictedPaid inUnitCashAwardsTotalName ($)($)($) Stephen L. Cropper65,000306,850371,850 Bryan K. Guderian65,000306,850371,850 James C. Kneale70,000306,850376,850 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 thegrant 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 ofdistribution rights during the vesting period was estimated using the value of the most recent distribution as of the grant date and assumptions that a marketparticipant might make about future distribution growth. This calculation of fair value is consistent with the provisions of ASC 718. 102Table of Contents 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 incontrol, 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 followingtable provides information on the restricted units awarded to non-employee members of our board of directors: Number ofFair ValueGrant DateRestrictedof UnvestedFair ValueUnits ThatRestrictedNumber of Restricted Unitsof RestrictedHave NotUnits as ofAwarded Vesting OnUnitsYet VestedMarch 31,GrantJanuary 1,July 1,July 1,TotalAwardedat March 31,2013NameDate201320132014Awards($) (1)2013($) (2) Stephen L. CropperJune 15, 20125,0005,0005,00015,000306,85010,000269,000 Bryan K. GuderianJune 15, 20125,0005,0005,00015,000306,85010,000269,000 James C. KnealeJune 15, 20125,0005,0005,00015,000306,85010,000269,000 (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 onthe grant date, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. Theimpact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution as of theapplicable date and assumptions that a market participant might make about future distribution growth. This calculation of fair value isconsistent 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 atMarch 31, 2013 of $26.90. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during thevesting 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 thesedirectors 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. 103Table of Contents Percentage ofTotal CommonPercentage ofandCommonPercentage ofSubordinatedSubordinatedSubordinatedUnitsCommon UnitsUnitsUnitsUnitsBeneficiallyBeneficiallyBeneficiallyBeneficiallyBeneficiallyBeneficial OwnersOwnedOwned(1)OwnedOwned(1)Owned(1)5% of greater unitholders (other than officers anddirectors):SemGroup Corporation (2)9,133,40918.58%——16.59%EMG NGL HC LLC (3)3,696,6347.52%——6.71%Ernest Osterman(4)3,063,3216.23%——5.56%NGL Holdings, Inc.(5)1,807,9443.68%1,544,10026.09%6.09%Directors and officers:Atanas H. Atanasov (6)37,168*——*James J. Burke (7)311,440*——*Kevin C. Clement5,000*——*Shawn W. Coady(8)1,330,6052.71%1,125,35119.01%4.46%Stephen L. Cropper25,000*——*Bryan K. Guderian20,000*——*Craig S. Jones(9)20,330*24,867**David C. Kehoe(10)319,007*——*James C. Kneale(11)17,500*——*H. Michael Krimbill(12)970,5571.97%497,8468.41%2.67%Vincent J. Osterman(13)3,762,6217.66%——6.83%Norman J. Szydlowski—————Patrick Wade—————William A. Zartler————— All directors and executive officers as a group (14persons)(14)8,730,21017.76%3,097,81152.33%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, amember 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., asubsidiary 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 thenumber of common units held, is based upon its Form 4 filed with the SEC on June 10, 2013. 104Table of Contents (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. Theinformation related to NGP MR, L.P., NGP Midstream & Resources, L.P., and EMG NGL HC LLC is based upon EMG NGL HC LLC’sForm 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 owneddirectly by AO Energy, Inc. (110,587 common units), E. Osterman, Inc. (394,350 common units), E. Osterman Gas Service, Inc. (301,700common 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 tohave sole voting and investment power over its own common units and Propane Gas, LLC, as sole shareholder of Propane Gas, Inc., may bedeemed to have sole voting and investment power over those common units. Ernest Osterman is a director, executive officer and shareholder ormember of each of these entities and may be deemed to have shared voting and investment power (with his son, Vincent J. Osterman) over3,063,321 common units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. The preceding informationrelated 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 ofNGL Holdings, Inc., and as such, has sole voting and investment power over these units, but disclaims beneficial ownership except to theextent of his pecuniary interest therein. NGL Holdings, Inc. is 100% owned by Denham Commodity Partners Fund II LP, which is managedby its general partner, Denham Commodity Partners GP II LP, which is owned by the employees of Denham Capital Management LP and iscontrolled by its general partner, Denham GP II LLC, which is in turn owned by Stuart D. Porter. Denham Capital Management LP, of whichWilliam A. Zartler is a founder and managing partner, acts as the investment advisor for Denham Commodity Partners Fund II LP and iscontrolled 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.’sSchedule 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 bedeemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of hispecuniary 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 and1,125,351 of these subordinated units. SWC Family Partnership LP is solely owned by SWC General Partner, LLC, of whichShawn W. Coady is the sole partner. Shawn W. Coady may be deemed to have sole voting and investment power over these units, butdisclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady Irrevocable InsuranceTrust, which was established for the benefit of Shawn W. Coady’s children, owns 110,000 of these common units. Shawn W. Coady may bedeemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of hispecuniary interest therein. Shawn W. Coady also owns a 12.27% interest in our general partner through Coady Enterprises, LLC, of whichhe 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 Krimbilland James E. Krimbill own 90.89%, 4.05%, and 5.06% of Krim2010, LLC, respectively. H. Michael Krimbill exercises the sole voting andinvestment power for Krimbill Enterprises LP. H. Michael Krimbill may be deemed to have sole voting and investment power over theseunits, but disclaims such beneficial ownership 105Table of Contents except to the extent of his pecuniary interest therein. H. Michael Krimbill also owns an 11.59% interest in our general partner throughKrimGP2010, LLC, of which he owns 100% of the membership interests. KrimGP2010 LLC owns 363,555 of these units. KrimGP2010LLC 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. (110,587common 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. (1,445,850common units), Propane Gas, Inc. (36,450 common units) and Saveway Propane Gas Service, Inc. (214,600 common units). Each of theseholding entities may be deemed to have sole voting and investment power over its own common units and Propane Gas, LLC, as soleshareholder of Propane Gas, Inc., may be deemed to have sole voting and investment power over those common units. Vincent J. Osterman isa director, executive officer and shareholder or member of each of these entities and may be deemed to have sole voting and investment powerover 699,300 common units and shared voting and investment power (with his father, Ernest Osterman) over 3,063,321 common units, butdisclaims beneficial ownership except to the extent of his pecuniary interest therein. Vincent J. Osterman also owns a 0.5% interest in ourgeneral 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 beneficiallyheld 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, Oklahoma74136. 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 SecuritiesRemaining Available forNumber of Securities to beWeighted-averageFuture Issuances UnderIssued upon Exercise ofExercise Price ofEquity Compensation PlansOutstanding Options,Outstanding Options,(Excluding SecuritiesWarrants and RightsWarrants and RightsReflected in Column (a))Plan Category(a)(b)(c)(1)Equity Compensation Plans Approved by Security Holders———Equity Compensation Plans Not Approved by SecurityHolders(2) 1,444,900—3,760,539Total1,444,900—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 outstandingcommon and subordinated units. The maximum number of common units deliverable under the LTIP automatically increases to 10% of theissued and outstanding common and subordinated units immediately after each issuance of common units, unless the plan administratordetermines 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 didnot require the approval of our unitholders. 106Table of Contents 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 4,641,911subordinated units, representing an aggregate 52% limited partner interest in us. In addition, our general partner owns a 0.1% general partner interest in us andall 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, butthey are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. Our general partner determines the amount ofthese expenses. In addition, our general partner owns the 0.1% general partner interest and all of the incentive distribution rights. Our general partner is entitledto 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 itsaffiliates 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 connectionwith our ongoing operation and any liquidation. These distributions and payments were determined by and among affiliated entities before our initial publicoffering and, consequently, are not the result of arm’s length negotiations. Formation Stage The consideration received by the NGL Energy LP Investor Group and ourgeneral partner and its affiliates prior to or in connection with our initialpublic offering· 5,014,222 common units; (4,839,222 common units after giving effect tothe 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 than5% owners and our general partnerWe generally make cash distributions 99.9% to our unitholders pro rata,including our directors, officers, and greater than 5% owners as the holders ofan aggregate 23,368,197 common units and 4,641,911 subordinated units,and 0.1% to our general partner. In addition, when distributions exceed theminimum quarterly distribution and other higher target distribution levels, ourgeneral partner is entitled to increasing percentages of the distributions, up to48.1% of the distributions above the highest target distribution level. Assuming we have sufficient available cash to pay the full minimum quarterlydistribution on all of our outstanding units for four quarters, our generalpartner would receive an annual distribution of approximately $0.1 million onits general partner interest and our directors, officers, and greater than 5%owners would receive an aggregate annual distribution of approximately $37.8million on their common and subordinated units. If our general partner elects to reset the target distribution levels, it will beentitled to receive common units and to maintain its general partner interest. 107Table of Contents Payments to our general partner and its affiliatesOur general partner and its affiliates do not receive any management fee orother compensation for the management of our business and affairs, but theyare reimbursed for all expenses that they incur on our behalf, including generaland administrative expenses. As the sole purpose of the general partner is to actas our general partner, we expect that substantially all of the expenses of ourgeneral partner will be incurred on our behalf and reimbursed by us or oursubsidiaries. Our general partner will determine the amount of these expenses. Withdrawal or removal of our general partnerIf our general partner withdraws or is removed, its general partner interest andits incentive distribution rights will either be sold to the new general partner forcash or converted into common units, in each case for an amount equal to thefair market value of those interests. Liquidation Stage LiquidationUpon our liquidation, our partners, including our general partner, will beentitled to receive liquidating distributions according to their respective capitalaccount balances. Related Party Transactions SemGroup Corporation Since our business combination with SemStream on November 1, 2011, SemGroup Corporation (“SemGroup”) has held ownership interests in usand 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 transactionsare included within revenues and cost of sales of our natural gas liquids logistics business in our consolidated statements of operations. We also madepayments to SemGroup for certain administrative and operational services. These transactions are reported within operating and general and administrativeexpenses in our consolidated statements of operations. The transactions with SemGroup are summarized below by fiscal year (in thousands): 20132012Product sales to SemGroup32,43129,200Product purchases from SemGroup60,42523,800Payments to SemGroup for services256700 108Table of Contents 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 aresummarized below: Mr. Kehoe’sAcquisitionPurchaseOwnership InterestSelling EntityDatePricein Selling EntityCowhouse Partners, L.L.C.August 31, 2012$7.3 million27.5%Key Pipeline Services, Inc.December 28, 2012$6.7 million46.5% 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’sMr. Burke’sFiscal 2013OwnershipOwnershipNature ofExpenseInterestInterestEntityServices(in thousands)in Entityin EntityCowhouse Partners, L.L.C.Terminalling services$49427.5%—Impact Energy Services LLCCrude oil purchases648—50.0%Key Pipeline Services, Inc.Terminalling services11546.5%—Key Pipelines, LTDTerminalling services64346.5%—Fluid Services, LLCCrude oil purchases and transportation services52820.0%—Fluid Disposal Services, LLCWaste disposal services75120.0%— 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 membersof management. These transactions are summarized below: Mr. Kehoe’sNature ofFiscal 2013Ownership InterestEntityServicesExpensein EntityCowhouse Partners, L.L.C.Transition services$50427.5% 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 ofapproximately $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 ofthe 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 duringthe 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 theserestricted 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 thatthe restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period wasestimated 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 theyear ended March 31, 2013. 109Table of Contents Transition Services Agreement We entered into a Transition Services Agreement with SemStream on November 1, 2011 pursuant to which SemStream agreed to provide us withcertain administrative and operational transition services related to the assets that we acquired from SemStream. We paid approximately $0.1 million toSemStream for the transition services during the year ended March 31, 2013. The Transition Services Agreement expired on April 30, 2012, althoughSemStream 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 of1933, as amended, or the Securities Act, common units, including any common units issued upon the conversion of subordinated units, owned by membersof 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 registrationrequirements 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 AtkinsonInvestors, 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 theSEC 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 inany twelve month period as well as customary cutbacks at the discretion of the underwriter. In addition, the registration rights agreement provides thatmembers of the NGL Energy LP Investor Group may have their common units included in any registration statement filed by us for an offering of commonunits for cash, subject to customary cutbacks at the discretion of the underwriter. We are obligated to pay all expenses incidental to any registration of commonunits, 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 thecommon units issued to the entities affiliated with Ernest Osterman and Vincent J. Osterman in connection with the closing of the Osterman transaction. Wefurther 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 certainacquisitions: SemStream, Pacer, Downeast, EMG NGL HC LLC (a former High Sierra unitholder), Enstone, and the sellers of Pecos and its affiliatedcompanies. 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 policiesfor the review, approval and ratification of transactions with related persons. The Code of Business Conduct and Ethics provides that the board of directors ofour 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 committeeconsiders ratification of a related person transaction and determines not to so ratify, the Code of Business Conduct and Ethics provides that our officers willmake 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 relatedparty transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstancesavailable, 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 directoror an entity in which a director is a partner, shareholder or executive officer); 110Table of Contents · 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 ourgeneral partner. For a discussion of the independence of the board of directors of our general partner, please see “Item 10 — Directors, Executive Officers andCorporate 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 GrantThornton LLP to audit our annual consolidated financial statements and for other services for the fiscal year ended March 31, 2013 and 2012: 20132012 Audit fees (1) $1,861,979$909,655Audit-related fees (2)47,100272,044Tax 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 arenormally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews ofdocuments 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 beperformed by Grant Thornton LLP. This policy lists specific audit-related services as well as any other services that Grant Thornton LLP is authorized toperform and sets out specific dollar limits for each specific service, which may not be exceeded without additional audit committee authorization. The auditcommittee receives quarterly reports on the status of expenditures pursuant to the pre-approval policy. The audit committee reviews the policy at least annuallyin 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 theaudit committee prior to engagement. 111Table of Contents 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 informationrequired in such schedules appears in the financial statements or the related notes. 3. Exhibits. ExhibitNumberDescription2.1Contribution, 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 andSilverthorne 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) 2.2Contribution and Sale Agreement, dated August 12, 2011, by and among the Partnership and the Sellers named therein (incorporatedby reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 7, 2011) 2.3Contribution 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) 2.4Contribution 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) 2.5Contribution 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) 2.6Contribution 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) 2.7Contribution 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) 2.8Contribution 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 onJanuary 9, 2012) 2.9Contribution 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) 2.10Contribution 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) 112Table of Contents ExhibitNumberDescription2.11Asset Purchase Agreement, dated as of January 16, 2012, by and among NGL Energy Partners LP and North AmericanPropane, 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) 2.12Waiver and First Amendment to Asset Purchase Agreement dated as of January 31, 2012 by and among NGL Energy Partners LP andNorth American Propane, Inc., EnergyUSA Propane, Inc., EUSA-Allied Acquisition Corp. and EUSA Heating & Air ConditioningServices, Inc. (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K/A (File No. 001-35172) filed with the SECon April 20, 2012) 2.13Waiver and Second Amendment to Asset Purchase Agreement dated as of February 3, 2012 by and among NGL Energy Partners LPand North American Propane, Inc., EnergyUSA Propane, Inc., EUSA-Allied Acquisition Corp. and EUSA Heating & AirConditioning Services, Inc. (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K/A (File No. 001-35172) filedwith the SEC on April 20, 2012) 2.14Agreement 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 CurrentReport on Form 8-K (File No. 001-35172) filed with the SEC on May 21, 2012) 2.15Agreement and Plan of Merger, dated as of May 18, 2012, by and among NGL Energy Holdings LLC, HSEGP LLC and HighSierra Energy GP, LLC (incorporated by reference to Exhibit 2.2 the Current Report on Form 8-K (File No. 001-35172) filed with theSEC on May 21, 2012) 2.16Equity 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 (FileNo. 001-35172) filed with the SEC on November 7, 2012) 2.17Sale Agreement, dated as of December 31, 2012, among Third Coast Towing, LLC, Jeff Kirby, Jane Helm, James Rudellat and HighSierra Transportation, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filedwith the SEC on January 7, 2013) 3.1Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Registration Statementon Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.2Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.2 tothe Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.3Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference toExhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011) 3.4First Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 26, 2011) 3.5Second Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012) 3.6Third Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 26, 2012) 113Table of Contents ExhibitNumberDescription3.7Fourth Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 2012) 3.8Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement onForm S-1 (File No. 333-172186) filed on April 15, 2011) 3.9Certificate of Amendment to Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.5 to theRegistration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.10Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC (incorporated by reference toExhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on February 28, 2013) 4.1First 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 onForm 8-K (File No. 001-35172) filed on October 7, 2011) 4.2Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 by andamong 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) 4.3Amendment No. 2 and Joinder to First Amended and Restated Registration Rights Agreement, dated January 3, 2012, by and amongNGL Energy Holdings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-PortlandPropane, L.L.C., Pacer Propane (Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C. (incorporatedby reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012) 4.4Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and betweenNGL 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) 4.5Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and betweenNGL 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) 4.6Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and betweenNGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on October 3, 2012) 4.7Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by andbetween NGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, CaritasTrust, 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) 4.8Call Agreement, dated as of November 1, 2012, among Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco PetroleumCorporation, Caritas Trust, Animosus Trust, Nitor Trust and NGL Energy Partners LP (incorporated by reference to Exhibit 4.1 theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012) 4.9Call 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) 114Table of Contents ExhibitNumberDescription4.10Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by reference toExhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 4.11Amendment No. 1 to Note Purchase Agreement, dated as of January 15, 2013, among the Partnership and the purchasers namedtherein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onJanuary 18, 2013) 4.12Amendment 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) 10.1Agreement Relating to Redemption of Common Units in Connection with the Underwriters’ Option to Purchase Additional CommonUnits with Respect to the Initial Public Offering of NGL Energy Partners LP by and among NGL Energy Partners LP, NGL EnergyHoldings 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) 10.2Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders partythereto and Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 10.3Facility 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 10.1to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012) 10.4Amendment No. 1 to Credit Agreement, dated as of January 15, 2013, among NGL Energy Operating LLC, the Partnership, thesubsidiary 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) 10.5Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, thesubsidiary 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) 10.6Letter 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) 10.7NGL 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) 10.8Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long Term Incentive Plan (incorporated byreference 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 theSEC 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Table of Contents ExhibitNumberDescription31.1*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 endedMarch 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010, (iii) Consolidated Statements of ComprehensiveIncome (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 andSeptember 30, 2010 and (v) Consolidated Statements of Cash Flows for years ended March 31, 2013 and 2012 and the six months endedMarch 31, 2011 and September 30, 2010. + Management contracts or compensatory plans or arrangements. 116Table of Contents 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 besigned 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 KrimbillH. Michael KrimbillChief 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 onbehalf of the registrant and in the capacities and on the dates indicated. SignatureTitleDate /s/ H. Michael KrimbillChief Executive Officer and DirectorJune 13, 2013H. Michael Krimbill(Principal Executive Officer) /s/ Atanas H. AtanasovChief Financial OfficerJune 13, 2013Atanas H. Atanasov(Principal Financial Officer) /s/ Jeffrey A. HerbersChief Accounting OfficerJune 13, 2013Jeffrey A. Herbers(Principal Accounting Officer) /s/ James J. BurkeDirectorJune 13, 2013James J. Burke /s/ Shawn W. CoadyDirectorJune 13, 2013Shawn W. Coady /s/ Kevin C. ClementDirectorJune 13, 2013Kevin C. Clement /s/ Stephen L. CropperDirectorJune 13, 2013Stephen L. Cropper /s/ Bryan K. GuderianDirectorJune 13, 2013Bryan K. Guderian /s/ James C. KnealeDirectorJune 13, 2013James C. Kneale /s/ Vincent J. OstermanDirectorJune 13, 2013Vincent J. Osterman /s/ Norman J. SzydlowskiDirectorJune 13, 2013Norman J. Szydlowski /s/ Patrick WadeDirectorJune 13, 2013Patrick Wade /s/ William A. ZartlerDirectorJune 13, 2013William A. Zartler 117Table of Contents INDEX TO FINANCIAL STATEMENTS NGL ENERGY PARTNERS LP AND NGL SUPPLY, INC. Reports of Independent Registered Public Accounting FirmF-2 Consolidated Balance Sheets as of March 31, 2013 and 2012F-5 Consolidated Statements of Operations for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30,2010F-6 Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011and September 30, 2010F-7 Consolidated Statements of Changes in Equity for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011 andSeptember 30, 2010F-8 Consolidated Statements of Cash Flows for the years ended March 31, 2013 and 2012 and the six months ended March 31, 2011and September 30,2010F-9 Notes to Consolidated Financial StatementsF-10 F-1Table of Contents Report of Independent Registered Public Accounting Firm Board of Directors and PartnersNGL 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, andcash 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 responsibilityof 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 thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includesexamining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accountingprinciples used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our auditsprovide 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 LPand 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 andthe 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 controlover financial reporting as of March 31, 2013, based on criteria established in 1992 Internal Control—Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission (COSO), and our report dated June 13, 2013 expressed an unqualified opinion. /s/ GRANT THORNTON LLP Tulsa, OklahomaJune 13, 2013 F-2Table of Contents Report of Independent Registered Public Accounting Firm PartnersNGL Energy Partners LP We have audited the accompanying consolidated statements of operations, comprehensive income (loss), changes in equity and cash flows for the six monthperiod ended September 30, 2010 of NGL Supply, Inc. (an Oklahoma corporation) and subsidiaries. These financial statements are the responsibility of theCompany’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 thatwe plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is notrequired to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal controlover financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion onthe effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on atest basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimatesmade 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 NGLSupply, Inc. and subsidiaries for the six month period ended September 30, 2010, in conformity with accounting principles generally accepted in the UnitedStates of America. /s/ GRANT THORNTON LLP Tulsa, OklahomaJune 29, 2011 F-3Table of Contents 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 SponsoringOrganizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financialreporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on InternalControl Over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Partnership’s internal control over financialreporting based on our audit. Our audit of, and opinion on, the Partnership’s internal control over financial reporting does not include the internal control overfinancial reporting of High Sierra Energy, LP, and High Sierra Energy GP, LLC, and their subsidiaries, along with other businesses acquired during the yearended March 31, 2013 (“the acquired companies”), whose financial statements in the aggregate reflect total assets and revenues constituting approximately 68and 73 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended March 31, 2013. As indicated inManagement’s Report, the acquired companies were acquired during the year ended March 31, 2013, and therefore, management’s assertion on theeffectiveness 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 thatwe plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all materialrespects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testingand evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considerednecessary 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 andthe preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control overfinancial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflectthe transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permitpreparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are beingmade only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention ortimely 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 ofeffectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliancewith 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 criteriaestablished 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 financialstatements 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 thosefinancial statements. /s/ GRANT THORNTON LLP Tulsa, OklahomaJune 13, 2013 F-4Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Balance SheetsMarch 31, 2013 and 2012(U.S. Dollars in Thousands, except unit amounts) March 31,March 31,20132012(Note 4)ASSETSCURRENT ASSETS:Cash and cash equivalents$11,561$7,832Accounts receivable, net of allowance for doubtful accounts of $1,760 and $818, respectively562,88984,004Accounts receivable - affiliates22,8832,282Inventories126,89594,504Prepaid expenses and other current assets37,89110,002Total current assets762,119198,624 PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $50,127 and $12,843,respectively516,937231,394GOODWILL563,146167,245INTANGIBLE ASSETS, net of accumulated amortization of $44,155 and $8,174, respectively442,603149,490OTHER NONCURRENT ASSETS6,5422,766Total assets$2,291,347$749,519 LIABILITIES AND PARTNERS’ EQUITYCURRENT LIABILITIES:Trade accounts payable$535,687$81,369Accrued expenses and other payables85,70314,143Advance payments received from customers22,37220,293Accounts payable - affiliates6,9009,462Current maturities of long-term debt8,62619,534Total current liabilities659,288144,801 LONG-TERM DEBT, net of current maturities740,436199,177OTHER NONCURRENT LIABILITIES2,205212 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 and2012, respectively(50,497)442Limited partners, representing a 99.9% interest -Common units, 47,703,313 and 23,296,253 units issued and outstanding at March 31, 2013 and2012, respectively920,998384,604Subordinated units, 5,919,346 units issued and outstanding at March 31, 2013 and 201213,15319,824Accumulated other comprehensive income -Foreign currency translation2431Noncontrolling interest5,740428Total partners’ equity889,418405,329Total liabilities and partners’ equity$2,291,347$749,519 The accompanying notes are an integral part of these consolidated financial statements. F-5Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Consolidated Statements of OperationsFor the Years Ended March 31, 2013 and 2012and 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 LPNGL Supply, Inc.Six MonthsSix MonthsYear EndedYear EndedEndedEndedMarch 31,March 31,March 31,September 30,2013201220112010REVENUES:Crude oil logistics$2,316,288$—$—$—Water services62,227———Natural gas liquids logistics1,604,7461,111,139549,419310,075Retail propane430,273199,33472,8136,868Other4,233———Total Revenues4,417,7671,310,473622,232316,943 COST OF SALES:Crude oil logistics2,244,647———Water services5,611———Natural gas liquids logistics1,530,4591,086,881536,047306,159Retail propane258,393130,14246,9854,749Total Cost of Sales4,039,1101,217,023583,032310,908 OPERATING COSTS AND EXPENSES:Operating169,79947,30015,8985,231General and administrative52,69816,0095,0243,210Depreciation and amortization68,85315,1113,4411,389Operating Income (Loss)87,30715,03014,837(3,795) OTHER INCOME (EXPENSE):Interest income1,26176522166Interest expense(32,994)(7,620)(2,482)(372)Loss on early extinguishment of debt(5,769)———Other, net260290103124Income (Loss) Before Income Taxes50,0658,46512,679(3,977) INCOME TAX (PROVISION) BENEFIT(1,875)(601)—1,417 Net Income (Loss)48,1907,86412,679(2,560) NET INCOME ALLOCATED TO GENERAL PARTNER(2,917)(8)(13)— NET (INCOME) LOSS ATTRIBUTABLE TONONCONTROLLING INTEREST(250)12—45 NET INCOME (LOSS) ATTRIBUTABLE TO PARENTEQUITY ALLOCATED TO LIMITED PARTNERS$45,023$7,868$12,666$(2,515) BASIC AND DILUTED EARNINGS PER LIMITEDPARTNER UNIT:Common units$0.96$0.32$1.16Subordinated units$0.93$0.58$—BASIC AND DILUTED WEIGHTED AVERAGE UNITSOUTSTANDING:Common units41,353,57415,169,98310,933,568Subordinated units5,919,3465,175,384— BASIC AND DILUTED LOSS PER COMMON SHARE$(128.46) BASIC AND DILUTED WEIGHTED AVERAGE COMMONSHARES OUTSTANDING19,711 The accompanying notes are an integral part of these consolidated financial statements. F-6Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Consolidated Statements of Comprehensive Income (Loss)For the Years Ended March 31, 2013 and 2012and the Six Months Ended March 31, 2011 and September 30, 2010(U.S. Dollars in Thousands) NGL Energy Partners LPNGL Supply, Inc.Six MonthsSix MonthsYear EndedYear EndedEndedEndedMarch 31,March 31,March 31,September 30,2013201220112010 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Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Consolidated Statements of Changes in EquityFor the Years Ended March 31, 2013 and 2012and the Six Months Ended March 31, 2011 and September 30, 2010(U.S. Dollars in Thousands, except unit and share amounts) AccumulatedReceivableAdditionalOtherFrom ExerciseClass A Common StockPaid-inRetainedComprehensiveof StockNoncontrollingTotalSharesAmountCapitalEarningsIncomeOptionsInterestEquity NGL SUPPLY, INC. BALANCES, MARCH 31, 201019,603$196$36,039$9,859$84$—$225$46,403 Exercise of stock options65071,423——(1,430)—— Net loss———(2,515)——(45)(2,560) Foreign currency translationadjustment————(15)——(15) Dividends -Preferred———(17)———(17)Common———(7,000)———(7,000)BALANCES, SEPTEMBER 30,201020,253$203$37,462$327$69$(1,430)$180$36,811 AccumulatedLimited PartnersOtherGeneralCommonSubordinatedComprehensiveNoncontrollingTotalPartnerUnitsAmountUnitsAmountIncomeInterestEquityNGL ENERGY PARTNERS LPSix Months Ended March 31,2011: Combination transaction withNGL Supply (Notes 1 & 2)$—4,735,328$1,252—$—$—$—$1,252 Acquisition of HOH & Gifford(Notes 1 & 4)—4,154,75722,326————22,326 Sale of units at formation—2,043,48310,981————10,981 General partner contribution59——————59 Net income13—12,666————12,679 Foreign currency translationadjustment—————56—56BALANCES, MARCH 31, 20117210,933,56847,225——56—47,353 Distribution to partners prior toinitial public offering(4)—(3,846)————(3,850) Conversion of common units tosubordinated units—(5,919,346)(23,485)5,919,34623,485——— Sale of units in public offering,net—4,025,00075,289————75,289 Repurchase of common units—(175,000)(3,418)————(3,418) Units issued in businesscombinations, net ofissuance costs—14,432,031296,500————296,500 General partner contributions386——————386 Contributions fromnoncontrolling interestowners——————440440 Net income (loss)8—6,472—1,396—(12)7,864 Distribution to partnerssubsequent to initial publicoffering(20)—(10,133)—(5,057)——(15,210) Foreign currency translationadjustment—————(25)—(25)BALANCES, MARCH 31, 201244223,296,253384,6045,919,34619,82431428405,329 Distributions(1,778)—(59,841)—(9,989)—(74)(71,682) Contributions510—————403913 Units issued in businesscombinations, net ofissuance costs (Note 4)(52,588)24,250,258550,873———4,733503,018 Equity issued pursuant toincentive compensation plan—156,8023,657————3,657 Net income2,917—41,705—3,318—25048,190 Foreign currency translationadjustment—————(7)—(7)BALANCES, MARCH 31, 2013$(50,497)47,703,313$920,9985,919,346$13,153$24$5,740$889,418 The accompanying notes are an integral part of these consolidated financial statements. F-8Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Consolidated Statements of Cash FlowsFor the Years Ended March 31, 2013 and 2012and the Six Months Ended March 31, 2011 and September 30, 2010(U.S. Dollars in Thousands) NGL Energy Partners LPNGL Supply, Inc.YearYearSix MonthsSix MonthsEndedEndedEndedEndedMarch 31,March 31,March 31,September 30,2013201220112010OPERATING ACTIVITIES:Net income (loss)$48,190$7,864$12,679$(2,560)Adjustments to reconcile net income (loss) to net cash providedby (used in) operating activities:Depreciation and amortization, including debt issuance costamortization77,51317,1884,4061,825Loss on early extinguishment of debt5,769———Non-cash equity-based compensation8,670———(Gain) loss on sale of assets187(71)16(124)Provision for doubtful accounts1,3151,0492693(Gain) loss on commodity derivative financial instruments4,376(5,974)(1,468)(226)Other3754033(1,409)Changes in operating assets and liabilities, net ofacquisitions -Accounts receivable2,430(20,179)(813)203Inventories18,43330,26860,413(59,598)Product exchanges, net1,8164,775(16,329)18,688Other current assets20,7699,5693,697(1,023)Trade accounts payable(17,281)35,7472,835(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)19,912Net cash provided by (used in) operating activities132,23190,32934,009(30,749) INVESTING ACTIVITIES:Purchases of long-lived assets(72,475)(7,544)(1,440)(280)Acquisitions of businesses, including acquired workingcapital(490,402)(297,401)(17,400)(123)Net cash flows on non-hedge commodity derivative financialinstruments11,5796,464111426Proceeds from sales of assets5,0801,238291185Other—346—125Net cash provided by (used in) investing activities(546,218)(296,897)(18,438)333 FINANCING ACTIVITIES:Issuance of senior notes250,000———Proceeds from borrowings under revolving credit facilities1,227,975478,900149,50034,490Payments on revolving credit facilities(964,475)(329,900)(112,381)(13,590)Proceeds from borrowings under other long-term debt653———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)——Contributions91344011,040—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 activities417,716198,063(3,170)10,161EFFECT OF EXCHANGE RATE CHANGES ON CASH——(47)—Net increase (decrease) in cash and cash equivalents3,729(8,505)12,354(20,255)Cash and cash equivalents, beginning of period7,83216,3373,98324,238Cash 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Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial StatementsAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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. (“NGLSupply”), Hicks Oils and Hicksgas, Incorporated (“HOH”), and Hicksgas Gifford, Inc. (“Gifford”). The acquisitions were effected through the followingtransactions, 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. Theshareholders 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% generalpartner interest in us and incentive distribution rights and the IEP Parties (owner of a 32.53% interest in our general partner) made a cash capitalcontribution 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 Giffordcontributed 100% of their respective membership interests in those entities to us as capital contributions in exchange for (i) in the case of NGLSupply, 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 paidapproximately $27.9 million of existing indebtedness of NGL Supply, (ii) in the case of Hicksgas, LLC, a 37.96% limited partner interest inus, a cash distribution of approximately $1.6 million and our agreement to pay or cause to be paid approximately $6.5 million of existingindebtedness 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 ownedoperating 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 ofpropane services including retail propane distribution; wholesale supply and marketing of propane and other natural gas liquids; and midstream operationswhich 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 liabilitieswere recorded at the historical net book values of NGL Supply. The assets and liabilities of Hicksgas, LLC and Gifford were recorded at their estimated fairvalues 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 Kansasand Georgia, and expanded its retail operations through additional acquisitions during fiscal 2008 through 2010. As discussed above and in Note 4, weacquired Hicksgas LLC and Gifford in connection with our formation transactions. Hicksgas LLC and Gifford are both in the retail propane business withoperations 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. Weused 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 forgeneral partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) were used to purchase 175,000 of the common units outstandingprior to our initial public offering. Upon the completion of our IPO, our limited partner equity consisted of 8,864,222 common units and 5,919,346subordinated units. F-10Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 thefollowing: · On October 3, 2011, we completed a business combination transaction with E. Osterman Propane, Inc., its affiliated companies and membersof the Osterman family (collectively, “Osterman”), whereby we acquired retail propane operations in the northeastern United States. We issued4,000,000 common units and paid $94.9 million of cash, net of cash acquired, in exchange for the assets and operations of Osterman. Theagreement also contemplated a post-closing payment of $4.8 million for certain specified working capital items, which we paid inNovember 2012. · On November 1, 2011, we completed a business combination transaction with SemStream, L.P. (“SemStream”), whereby we acquiredSemStream’s wholesale natural gas liquids supply and marketing operations and its 12 natural gas liquids terminals. We issued 8,932,031common 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 commonunits, valued at $30.4 million, and paid $32.2 million of cash in exchange for the assets and operations of Pacer, including working capital. Wealso 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 weacquired retail propane and distillate operations in the northeastern United States. We paid $69.8 million of cash in exchange for the assets andoperations 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. Ona combined basis, we paid $6.4 million of cash for these assets and operations, including working capital. We also assumed $0.7 million oflong-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 alsopaid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLCby paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLCto 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 itsaffiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texasand New Mexico. We paid cash of $132.4 million at closing (net of $2.2 million of cash acquired), subject to customary post-closingadjustments, 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 aminimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners of Pecospurchased 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 companymembership interests in Third Coast Towing, LLC (“Third Coast”) for $43.0 million in cash. The business of Third Coast consists primarilyof 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 ofThird Coast agreed to F-11Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 ofThird 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 distillateoperations, primarily in the northeastern and southeastern United States. On a combined basis, we paid $71.4 million of cash and issued850,676 common units in exchange for these assets and operations, including working capital. We also assumed $6.6 million of long-termdebt 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 logisticsand 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 ofnon-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 railcars, and a fleet of barges and tow boats. Our crude oil logistics business purchases crude oil from producers and transports it for resale atpipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. The operations of our crudeoil 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 waterservices business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from oil and natural gasproduction operations, and from the sale of recycled water and recovered hydrocarbons. The operations of our water services segment began withour June 2012 merger with High Sierra. · Our natural gas liquids logistics business, which supplies natural gas liquids to retailers, wholesalers, and refiners throughout the UnitedStates and in Canada, and which provides natural gas liquids terminaling services through its 17 terminals throughout the United States andrail car transportation services through its fleet of owned and predominantly leased rail cars. Our natural gas liquids logistics segment purchasespropane, 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 previouslyreported in our wholesale marketing and supply and terminals segments. Our natural gas liquids logistics segment also includes the natural gasliquids 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 capitalizationsthrough September 30, 2010. Accordingly, we are presenting our financial statements for periods subsequent to September 30, 2010. As described above, NGLSupply was deemed to be the acquiring entity in our formation transactions. Therefore, our financial statements for the six months ended September 30, 2010represent the historical financial statements of NGL Supply. We recorded the assets acquired and liabilities assumed from NGL Supply at their historical netbook values. F-12Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 significantintercompany 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. Thesereclassifications 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 ofour assets, liabilities, revenues, expenses and costs. These estimates are based on our knowledge of current events, historical experience, and various otherassumptions 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 liabilitiesacquired in business combinations; the collectability of accounts receivable; the recoverability of inventories; useful lives and recoverability of property, plantand equipment and amortizable intangible assets; the impairment of goodwill; the fair value of derivative financial investments; and accruals for variouscommitments 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 liabilitiesacquired 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 anorderly transaction between market participants at the measurement date. Fair value should be based upon assumptions that market participants would usewhen pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes notonly the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair valuemeasurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the mostadvantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amountpaid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustmentswere 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 measurementdate. · 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 inactivemarkets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data bycorrelation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity priceswap and option contracts and interest rate protection agreements. The majority of our fair value measurements related to our derivative financialinstruments were categorized as Level 2 at March 31, 2013 and 2012 (see Note 12). We determine the fair value of all our derivative financialinstruments utilizing pricing models for significantly similar instruments. Inputs to the pricing model include publicly available prices andforward 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Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 thesignificance 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 ourcommodity derivative instruments included in our consolidated statements of operations in cost of sales. Changes in the value of our interest rate swapagreements are recorded in our consolidated statements of operations in interest expense. Contracts that qualify for the normal purchase or sale exemption arenot 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 derivativeinstruments 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 donot enter such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changesin market prices, newly originated transactions, and the timing of the settlements. We attempt to balance our contractual portfolio in terms of notional amountsand timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipatedmarket movements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the riskthat 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 andhave established control procedures that we review on an ongoing basis. We monitor market risk through a variety of techniques and attempt to minimizecredit 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 productby 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 ofthe 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 customersfor shipping and handling costs are included in revenues in the consolidated statements of operations. Shipping and handling costs associated with productsales 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 samecounterparty at a different location or time. When such agreements are entered into concurrently and are entered into in contemplation of each other, we recordthe 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 todelivery to our customers. Cost of sales does not include any depreciation of our property, plant and equipment. Cost of sales does include amortization ofcertain 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 thethird parties who operate our terminal facilities under operating and maintenance agreements. F-14Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 theyear 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 andamortization of intangible assets other than debt issuance costs, for which the amortization is recorded to interest expense, and certain contract-based intangibleassets, 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 ofthree 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 LPNGL SupplyYearYearSix MonthsSix MonthsEndedEndedEndedEndedMarch 31,March 31,March 31,September 30,2013201220112010(in thousands)Interest paid$27,384$4,966$2,063$335Income 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 haveestablished policies and procedures that allow for an evaluation of each customer’s creditworthiness as well as general economic conditions. The allowance fordoubtful accounts is based on our assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customersand any specific disputes. Accounts receivable are considered F-15Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 havebeen 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 anetting 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, 2013March 31, 2012GrossAllowance forGrossAllowance forSegmentReceivableDoubtful AccountsReceivableDoubtful Accounts(in thousands)Crude oil logistics$360,721$11$—$—Water services9,61829——Natural gas liquids logistics144,2677652,640113Retail Propane49,2331,64432,182705Other810———$564,649$1,760$84,822$818 Changes in the allowance for doubtful accounts are as follows during the periods indicated: NGL Energy Partners LPNGL SupplyYearYearSix MonthsSix MonthsEndedEndedEndedEndedMarch 31,March 31,March 31,September 30,2013201220112010(in thousands)Allowance for doubtful accounts, beginning of period$818$161$—$235Bad debt provision1,3151,0492693Write 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 ourconsolidated total revenues. For the year ended March 31, 2012, no single customer accounted for more than 10% of our consolidated total revenues. For the sixmonths ended March 31, 2011, we had one customer of our wholesale supply and marketing segment who represented approximately 10% of totalconsolidated revenues. In the six months ended September 30, 2010, two customers of our natural gas liquids logistics segment accounted for 28% of totalconsolidated revenues. As of March 31, 2013, one customer of our crude oil logistics segment represented approximately 10% of our consolidated accountsreceivable balance. As of March 31, 2012, one customer of our wholesale supply and marketing segment represented approximately 21% of our consolidatedaccounts receivable balance. Inventories Our inventories include propane, normal butane, natural gasoline, isobutane, transmix, distillates, appliances, and parts and supplies. We valueour 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 thecost of transportation. We monitor inventory values for potential lower of cost or market adjustments and will record such adjustments at fiscal year-end, oron 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Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and the Six Months Ended March 31, 2011 and September 30, 2010 Our inventories as of March 31, 2013 and 2012 consisted of the following: 20132012(in thousands)Crude oil$46,156$—Propane45,42878,993Other natural gas liquids24,0909,259Other11,2216,252Total$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 maintenanceand repairs are expensed as incurred. As we dispose of assets, we remove the cost and related accumulated depreciation from the accounts and any resultinggain or loss is included in other income. We compute depreciation expense using the straight-line method over the estimated useful lives of the assets (seeNote 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 groupis 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 assetgroup. 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 theintangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardlessof 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 ofthe 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 beimpaired. 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 unitexceeds 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 thefollowing 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 fairvalue of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amount of areporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of impairment loss, ifany. F-17Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 anamount equal to that excess. Estimates and assumptions used to perform the impairment evaluation are inherently uncertain and can significantly affect the outcome of theanalysis. The estimates and assumptions we used in the annual assessment for impairment of goodwill included market participant considerations and futureforecasted operating results. Changes in operating results and other assumptions could materially affect these estimates. Based on the results of theseevaluations, we did not record any goodwill impairments during the years ended March 31, 2013 and 2012 or the six months ended March 31, 2011 andSeptember 30, 2010. Product Exchanges Quantities of products receivable or returnable under exchange agreements are reported within prepaid expenses and other current assets or withinaccrued 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 isincurred, which is typically at the time the assets are placed into service. After the initial measurement, we recognize changes in the amount of the liabilityresulting 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 subsidiariesrange 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 endedSeptember 30, 2010 reflects a 30% interest in a consolidated subsidiary that was owned by unrelated parties at the time. We currently own 100% of thissubsidiary. 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 isallowed a reasonable period of time to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in abusiness combination. As described in Note 4, certain of our acquisitions during the fiscal year ended March 31, 2013 are still within this measurementperiod, and as a result, the acquisition date values we have recorded for the acquired assets and assumed liabilities are subject to change. F-18Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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: YearYearSix MonthsEndedEndedEndedMarch 31,March 31,March 31,201320122011(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$12,679Less - 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$12,666Subordinated unitholders$5,506$3,009$— Weighted average common units outstanding41,353,57415,169,98310,933,568Weighted average subordinated units outstanding5,919,3465,175,384— Earnings per unit - basic and diluted:Common unitholders$0.96$0.32$1.16Subordinated 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 ofincentive 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, exceptshare 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 outstanding19,711 Basic and diluted loss per common share$(128.46) F-19Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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. Wepaid $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 commonunits 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 alsopaid $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 forwhich 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 2,685,042common 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 byour 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 onassumptions of future distributions and a discount rate that a hypothetical buyer might use. Under this model, the potential for distribution growth resultingfrom the prospect of future acquisitions and capital expansion projects would not be considered in the fair value calculation. The difference between theestimated 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 thecommon 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 areduction to equity. We incurred and charged to general and administrative expense during the years ended March 31, 2013 approximately $3.7 million of costsrelated 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 endedMarch 31, 2013, our consolidated statement of operations includes operating income of approximately $46.6 million generated by the operations of High Sierraand by the operations of the subsequent acquisitions of crude oil logistics and water services businesses. The following table summarizes the revenues andcost of sales contributed by High Sierra’s operations and the operations of the subsequent acquisitions of crude oil logistics and water services businesses (inthousands): RevenuesCost of SalesCrude oil logistics$2,316,288$2,244,647Natural gas liquids logistics696,424663,630Water services62,2275,611Other4,233—Total$3,079,172$2,913,888 F-20Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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$395,311Inventory43,575Receivables from affiliates7,724Derivative assets10,646Forward purchase and sale contracts34,717Other current assets11,131Property, plant and equipment:Land5,910Transportation vehicles and equipment (5 - 10 years)20,968Facilities and equipment (2 - 30 years)103,574Buildings and improvements (5 - 30 years)9,691Information technology equipment and software (3 - 5 years)4,099Construction in progress11,213Intangible assets:Customer relationships (5 - 17 years)245,000Lease contracts (1 - 10 years)12,400Trade names (indefinite)13,000Goodwill220,884 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$239,251Value of common units issued, net of issuance costs414,794Total 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 ofliabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquiredbusinesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income taxpurposes. We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert futureamounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current marketexpectations 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 oilpurchasing 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 tocustomary post-closing adjustments, and assumed certain obligations with a value of $10.2 million under certain equipment financing facilities. Also onNovember 1, 2012, we entered into a call agreement F-21Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 $60.0million 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 thiscall agreement. We incurred and charged to general and administrative expense during the year ended March 31, 2013 approximately $0.6 million of costsrelated 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 estimatesof 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 finalizingour financial statements for the quarter ended September 30, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumedas follows (in thousands): Accounts receivable$73,704Inventory1,903Other current assets1,425Property, plant and equipment:Vehicles and related equipment (5 - 10 years)19,193Other2,562Customer relationships (5 years)8,000Trade names (indefinite life)1,000Goodwill86,661Accounts 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$87,444Value of common units issued pursuant to Call Agreement44,943Total 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, netof liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquiredbusinesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income taxpurposes. 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-closingadjustment to the purchase price for certain working capital items. Also on December 31, 2012, we entered into a call agreement with the former owners ofThird 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 commonunits 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 thisagreement. We incurred and charged to general and administrative expense during the year ended March 31, 2013 approximately $0.3 million of costs related tothe Third Coast combination. F-22Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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. Theestimates of fair value reflected as of March 31, 2013 are subject to change. We currently expect to complete this process prior to finalizing our financialstatements for the quarter ended December 31, 2013. We have preliminarily estimated the fair value of the assets acquired and liabilities assumed as follows (inthousands): Accounts receivable$2,248Other current assets140Property, plant and equipment:Barges and tow boats (20 years)12,883Other (3 - 5 years)30Customer relationships (5 years)4,000Trade names (indefinite life)500Goodwill22,551Other noncurrent assets2,733Assumed 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$35,000Value of common units issued pursuant to call agreement7,883Total 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, netof liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquiredbusinesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income taxpurposes. 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 andwater 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-competeagreements. We also issued 516,978 common units, valued at $12.4 million, as partial consideration for one of these acquisitions. Certain of the agreementscontemplate post-closing adjustments to the purchase price for certain specified working capital items. We incurred and charged to general and administrativeexpense during the year ended March 31, 2013 approximately $0.3 million of costs related to these acquisitions. F-23Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 estimatesof 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 forthe 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$2,660Inventory191Other current assets738Property, plant and equipment:Disposal wells and related equipment (3 - 30 years)13,322Other (5 - 30 years)5,671Customer relationships (5 - 15 years)6,800Non-compete agreements (3 - 5 years)510Trade names (indefinite life)500Goodwill43,822Current 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$52,552Value of common units issued12,433Total 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, netof liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquiredbusinesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income taxpurposes. F-24Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 distillateoperations, primarily in the northeastern and southeastern United States. On a combined basis, we paid cash of $71.4 million and issued 850,676 commonunits, 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. Weincurred and charged to general and administrative expense during the year ended March 31, 2013 approximately $0.3 million related to these acquisitions. Weare 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 reflectedas 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 valueof the assets acquired and liabilities assumed in these six combinations are as follows (in thousands): Accounts receivable$8,715Inventory5,155Other current assets1,228Property, plant and equipment:Land1,945Tanks and other retail propane equipment (5-20 years)28,763Vehicles (5 years)11,344Buildings (30 years)7,052Other equipment1,201Intangible assets:Customer relationships (10-15 years)16,890Tradenames (indefinite)2,924Non-compete agreements (5 years)1,387Goodwill21,983Other non-current assets784Long-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$71,392Value of common units issued18,874Total 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 acquiredbusinesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income taxpurposes. We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert futureamounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current marketexpectations 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Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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. Theoperations of Pecos have been included in our consolidated statement of operations since Pecos was acquired on November 1, 2012. The operations ofThird Coast have been included in our consolidated statement of operations since Third Coast was acquired on December 31, 2012. The following unauditedpro forma consolidated data below are presented as if the High Sierra, Pecos, and Third Coast acquisitions had been completed on April 1, 2011 (inthousands, 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 31,20132012Revenues$5,430,449$4,789,040Income from continuing operations56,36615,720Limited partners’ interest in income from continuing operations53,44215,704Basic and diluted earnings from continuing operations per commonunit1.000.29Basic and diluted earnings from continuing operations persubordinated unit1.000.29 The pro forma consolidated data in the table above was prepared by adding the historical results of operations of High Sierra, Pecos, andThird Coast to our historical results of operations and making certain pro forma adjustments. The pro forma adjustments include: (i) replacing the historicaldepreciation and amortization expense of High Sierra, Pecos, and Third Coast with pro forma depreciation and amortization expense, calculated using theestimated fair values of long-lived assets recorded in the acquisition accounting; (ii) replacing the historical interest expense of High Sierra, Pecos, andThird Coast with pro forma interest expense; and (iii) excluding professional fees and other expenses incurred by us and by the acquirees that were directlyrelated 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 unitsoutstanding at March 31, 2013 had been outstanding throughout the periods shown in the table, and (ii) all of the common units were eligible for distributionsrelated 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 theacquisitions 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 thenortheastern 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 andoperations of Osterman. The agreement also contemplated a post-closing payment of $4.8 million for certain specified working capital items, which was paidin 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 costsincurred in connection with the Osterman transaction. We also incurred costs related to the equity issuance of approximately $127,000 that we charged toequity. We have included the results of Osterman’s operations in our consolidated financial statements beginning October 3, 2011. F-26Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 allocationof the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands): EstimatedAllocationas ofFinalMarch 31,Allocation2012Revision Accounts receivable$9,350$5,584$3,766Inventory3,8693,898(29)Other current assets2152123 Property, plant and equipment:Land2,3494,500(2,151)Tanks and other retail propane equipment (15-20 years)47,16055,000(7,840)Vehicles (5-20 years)7,69912,000(4,301)Buildings (30 years)3,8296,500(2,671)Other equipment (3-5 years)7321,520(788) Intangible assets:Customer relationships (20 years)54,50062,479(7,979)Tradenames (indefinite life)8,5005,0003,500Non-compete agreements (7 years)700—700 Goodwill52,26730,40521,862Assumed 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): EstimatedAllocationas ofFinalMarch 31,Allocation2012Revision Cash paid at closing, net of cash acquired$94,873$96,000$(1,127)Fair value of common units issued at closing81,88081,880—Working capital payment (paid in November 2012)4,7633,787976Consideration 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. Theserevisions 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, netof liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquiredbusinesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income taxpurposes. F-27Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 futureamounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current marketexpectations 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 ournatural gas liquids logistics operations. SemStream contributed substantially all of its natural gas liquids business and assets to us in exchange for 8,932,031of 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 atapproximately $184.8 million, based on the closing price of our common units on the closing date ($21.07) reduced by the expected present value ofdistributions for certain units which were not eligible for full distributions until the quarter ending September 30, 2012. In addition, in exchange for a cashcontribution, SemStream acquired a 7.5% interest in our general partner. We incurred and charged to general and administrative expense during the year endedMarch 31, 2012 approximately $736,000 of costs related to the SemStream transaction. We also incurred costs of approximately $43,000 related to the equityissuance that we charged to equity. The acquired assets included 12 natural gas liquids terminals in Arizona, Arkansas, Indiana, Minnesota, Missouri, Montana, Washington andWisconsin, 12 million gallons of above ground propane storage, 3.7 million barrels of underground leased storage for natural gas liquids and a rail fleet ofapproximately 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 ofSemStream 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$104,226Derivative financial instruments3,578Assets held for sale3,000Prepaids and other current assets9,833Property, plant and equipment:Land3,470Tanks and terminals (20-30 years)41,434Vehicles and rail cars (5 years)470Other (5 years)3,326Investment in capital lease3,112Amortizable intangible assets:Customer relationships (8-15 years)31,950Rail car leases (1-4 years)1,008Goodwill74,924Assumed 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, netof liabilities. Goodwill primarily represents the value of synergies between the acquired operations and the Partnership, the opportunity to use the acquiredbusinesses as a platform to expand our wholesale marketing operations, and the acquired assembled workforce. We estimate that all of the goodwill will bedeductible for federal income tax purposes. F-28Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 futureamounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current marketexpectations 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 fundedwith 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 commonunits on the closing date. We incurred and charged to general and administrative expense during the year ended March 31, 2012 approximately $710,000 ofcosts 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. Thecontributed assets include 17 owned or leased customer service centers and satellite distribution locations. We have included the results of Pacer’s operations inour 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$32,213Common units30,375$62,588 During the year ended March 31, 2013, we completed the acquisition accounting for this transaction. The following table presents the final allocationof the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands): EstimatedAllocationas ofFinalMarch 31,Allocation2012Revision Accounts receivable$4,389$4,389$—Inventory965965—Other current assets4343—Property, plant and equipment:Land1,9671,400567Tanks and other retail propane equipment (15 - 20 years)12,79311,2001,593Vehicles (5 years)3,0905,000(1,910)Buildings (30 years)4092,300(1,891)Other equipment (3-5 years)59200(141)Intangible assets:Customer relationships (15 years)23,56021,9801,580Tradenames (indefinite life)2,4101,0001,410Noncompete agreements1,520—1,520Goodwill15,78218,460(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. Theserevisions did not have a material impact on the consolidated statements of operations. F-29Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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, netof liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquiredbusinesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income taxpurposes. We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert futureamounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current marketexpectations 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 combinationwas 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 ourconsolidated 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 allocationof the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (in thousands): EstimatedAllocationas ofFinalMarch 31,Allocation2012Revision Accounts receivable$10,338$10,338$—Inventory3,4373,437—Other current assets282282—Property, plant and equipment:Land2,2512,600(349)Tanks and other retail propane equipment (15-20 years)24,79027,100(2,310)Terminal assets (15-20 years)1,044—1,044Vehicles (5-15 years)5,8199,000(3,181)Buildings (30 years)2,3862,200186Other equipment (3-5 years)634500134Intangible assets:Customer relationships (10 years)12,6009,8002,800Tradenames (10 years)2,7001,0001,700Noncompete agreements (3 years)700—700Goodwill13,97814,702(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. Theserevisions did not have a material impact on the consolidated statements of operations. F-30Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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, netof liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquiredbusinesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income taxpurposes. We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert futureamounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current marketexpectations 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 combinedbasis. 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 ofoperations 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 formationtransactions. The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their estimated fairvalues, in the acquisition of the retail propane businesses of Hicksgas LLC and Gifford described above (in thousands): Accounts receivable$5,669Inventory6,182Prepaid expenses and other current assets2,60014,451Property, plant, and equipment:Land2,666Tanks and other retail propane equipment (15 year life)23,016Vehicles (5 year life)6,599Buildings (30 year life)7,053Office equipment (5 year life)523Amortizable intangible assets:Customer relationships (15 year life)2,170Non-compete agreements (5 year life)550Tradenames (indefinite-life intangible asset)830Goodwill (retail propane segment)3,716Total assets acquired61,574 Accounts payable1,837Customer advances and deposits12,089Accrued and other current liabilities2,15216,078 Long-term debt5,768Other long-term liabilities274Total liabilities assumed22,120 Net assets acquired$39,454 F-31Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 unitsvalued 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 byunrelated 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: 2012Description and Depreciable Life2013(Note 4)(in thousands)Natural gas liquids terminal assets (30 years)$63,637$62,024Retail propane equipment (5-20 years)152,802119,972Vehicles (5-10 years)85,20026,372Water 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)12,1694,347Buildings and leasehold improvements (5-30 years)48,39414,651Land21,60413,084Other (3-10 years)17,2883,108Construction in progress31,926679567,064244,237Less: 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 LPNGL SupplyYearYearSix MonthsSix MonthsEndedEndedEndedEndedMarch 31,March 31,March 31,September 30,2013201220112010(in thousands)$39,196$10,573$2,848$998 F-32Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 LPNGL SupplyYearYearSix MonthsSix MonthsEndedEndedEndedEndedMarch 31,March 31,March 31,September 30,2013201220112010(in thousands)Beginning of period, as retrospectively adjusted (Note 4)$167,245$8,568$4,580$4,457Goodwill from acquisitions, including additional consideration paid forprevious acquisitions395,901158,6773,988123End 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 services119,668———Retail propane112,26990,2876,5342,546Natural gas liquids logistics87,13676,9582,0342,034 Note 7 - Intangible Assets Intangible assets consist of the following: March 31, 2013March 31, 2012(Note 4)Gross CarryingAccumulatedGross CarryingAccumulatedAmortizable LivesAmountAmortizationAmountAmortization(in thousands)Amortizable -Customer relationships5-20 years*$407,835$30,959$128,071$3,868Lease and other agreements1-8 years15,2107,0182,8101,545Non-compete agreements2-7 years11,8552,8715,033919Trade names3-10 years2,7843262,700—Debt issuance costs5-10 years19,4942,9817,3101,842Total amortizable457,17844,155145,9248,174Non-amortizable -Trade namesIndefinite29,580—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Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and the Six Months Ended March 31, 2011 and September 30, 2010 Amortization expense was as follows for the periods indicated: NGL Energy Partners LPNGL SupplyYearYearSix MonthsSix MonthsEndedEndedEndedEndedMarch 31,March 31,March 31,September 30,Recorded in2013201220112010(in thousands)Depreciation and amortization$29,657$4,538$593$391Interest expense3,3751,27756536Loss on early extinguishment of debt5,769———Cost of sales - natural gas liquids logistics5,285800400400$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$44,485201543,137201641,396201739,567201834,234Thereafter210,204$413,023 Note 8 - Long-Term Obligations We have the following long-term debt: March 31,20132012(in thousands)Revolving credit facility —Expansion capital loans$441,500$—Working capital loans36,000—Previous revolving credit facility —Acquisition loans—186,000Working capital loans—28,000Senior notes250,000—Other notes payable21,5624,711749,062218,711 Less current maturities8,62619,534Long-term debt$740,436$199,177 F-34Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 revolvingcredit 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 $250million of Senior Notes in a private placement (the “Senior Notes”). We used the proceeds from the issuance of the Senior Notes and borrowings under theCredit 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 aremaining capacity of $146.4 million at March 31, 2013. The Expansion Capital Facility had a total capacity of $527.5 million for cash borrowings atMarch 31, 2013. At March 31, 2013, we had outstanding cash borrowings of $441.5 million on the Expansion Capital Facility, leaving a remaining capacityof $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 theCredit Agreement, which is calculated based on the value of certain working capital items at any point in time. At March 31, 2013, the borrowing baseprovisions 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 paidapproximately $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 CreditAgreement without incurring any penalties, and pre-payments of principal may be required if we enter into certain transactions to sell assets or obtain newborrowings. 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, asdefined 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 of0.21% 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 bysubstantially 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. AtMarch 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 CreditAgreement, 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, limitationson fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events ofdefault (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnershipor 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. TheSenior 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 ofJune 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured bysubstantially all of our assets and rank equal in priority with borrowings under the Credit Agreement. F-35Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 ourability 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 withaffiliates, (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 graceand 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 unpaidor 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 PurchaseAgreement, 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 ofbankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregateprincipal 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, wewrote 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 ourconsolidated 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): AmountRate Expansion capital facility —LIBOR borrowings$441,5003.21%Working capital facility —LIBOR borrowings20,0003.21%Base rate borrowings16,0005.25% F-36Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and the Six Months Ended March 31, 2011 and September 30, 2010 Other Notes Payable We have executed various non-interest bearing notes, payable primarily related to acquisitions described in Note 4. We also acquired certain notespayable in our acquisition of Pecos that relate to equipment financing; the interest rates on these notes payable range from 2.6% to 4.9% at March 31, 2013. Debt Maturity Schedule The future maturities of our long-term debt are as follows as of March 31, 2013 (in thousands): RevolvingOtherCreditSeniorNotesYear ending March 31,FacilityNotesPayableTotal 2014$—$—$8,626$8,6262015——6,4566,4562016——3,0883,0882017——2,0912,0912018477,50025,0001,182503,682Thereafter—225,000119225,119$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 ownerreports 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 taxreporting 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 provisionreported 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 certainqualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generateincome 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 thecalendar 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 incometaxes. 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, wedetermine 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 berecognized in the consolidated financial statements. The amount of tax benefit recognized with respect to any tax position is measured as the largest amount ofbenefit that is greater than 50 percent likely of being realized upon settlement. We had no material uncertain tax positions that required recognition in theconsolidated financial statements at March 31, 2013 or 2012. Any interest or penalties would be recognized as a component of income tax expense. We considerNGL 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Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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, theultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, willnot have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters isinherently 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 Texasagainst a number of defendants, including High Sierra. Pemex alleged that High Sierra and the other defendants purchased condensate from a source that hadacquired the condensate illegally from Pemex. We do not believe that High Sierra had knowledge at the time of the purchases of the condensate that suchcondensate was allegedly sold illegally to High Sierra and others. During March 2013, we settled this litigation for $3.1 million, which we recorded as aliability 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 theywere entitled to enforce lien rights on crude oil purchased by High Sierra and other defendants. These cases were subsequently transferred to the United StatesBankruptcy 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 providedfrom 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. InMay 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, thecustomer 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 revenuefor 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 theoutcome 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 ofoperations. 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 shouldhave 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. Weare in the process of gathering information to support High Sierra’s position that the transactions were exempt from the taxes, which we believe couldsubstantially reduce the amount of the tax assessed. If we are unsuccessful in demonstrating that these transactions were exempt, we would be required to remitpayment 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 withthe 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 materialadverse effect on our consolidated financial position or results of operations. We recorded in the acquisition accounting for the merger with High Sierra aliability 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 fromthe 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 insubstantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there canbe no assurance that significant costs will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmentallaws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantialcosts. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and thehandling, storage, use, and F-38Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 suchevents. 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 assetsand 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 otherassets. However, we do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration theestimated 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. Futureminimum lease payments under contractual commitments as of March 31, 2013 are as follows (in thousands): Year Ending March 31,2014$55,065201538,283201631,297201729,005201821,520Thereafter36,268Total$211,438 Rental expense relating to operating leases was as follows for the periods indicated (in thousands): Year ended March 31, 2013$51,354Year ended March 31, 20125,202Six months ended March 31, 2011838Six months ended September 30, 2010676 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 infuture periods. These contracts require that the parties physically settle the transactions with inventory. At March 31, 2013, we had the following suchcommitments outstanding: VolumeValue(in thousands)Natural gas liquids fixed-price purchase commitments (gallons)84,159$76,386Natural gas liquids floating-price purchase commitments (gallons)540,518604,584Natural gas liquids fixed-price sale commitments (gallons)102,071100,246Natural gas liquids floating-price sale commitments (gallons)262,143339,757 Crude oil fixed-price purchase commitments (barrels)3,382303,819Crude oil fixed-price sale commitments (barrels)5,642504,505 F-39Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 recordthe 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 recordedthese 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 thecontracts. At March 31, 2013, the unamortized balances included in our consolidated balance sheet were as follows (in thousands): Current assets$3,124Current 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, tocost of sales related to the forward purchase and sale contracts acquired in the merger with High Sierra (in thousands): Natural Gas LiquidsCrude OilLogistics SegmentLogistics SegmentTotal Year ended March 31, 2013$14,587$(1,089)$13,498Year ending March 31, 20142,701(163)2,538Total 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 commonand subordinated units. The common and subordinated units share equally in the allocation of income or loss. The principal difference between common andsubordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until thecommon units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from priorquarters. 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 outstandingcommon 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 outstandingcommon unit and subordinated unit, the corresponding distribution on the general partner interest and the related distribution on the incentive distributionrights for each calendar quarter in a four-quarter period, the subordination period will terminate automatically. The subordination period will also terminateautomatically 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. Whenthe subordination period lapses or otherwise terminates, all remaining subordinated units will convert into common units on a one-for-one basis and thecommon 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Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 unitconversion on our limited partner equity as of March 31, 2011 and earnings per unit information for the six months ended March 31, 2011, assuming theconversion occurred on October 1, 2010, is as follows: HistoricalUnaudited Pro FormaUnitsAmountUnitsAmount(U.S. Dollars in thousands, except per unit amounts)Limited Partner Equity —Common units10,933,568$47,2255,014,222$21,658Subordinated units——5,919,34625,56710,933,568$47,22510,933,568$47,225Earnings per unit, basic and diluted —Common units$1.16$1.16Subordinated units$—$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 of3,850,000 common units of $71.9 million, net of offering costs of approximately $9.0 million, were used to repay advances under our acquisition creditfacility 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 commonunits 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 combination4,000,000SemStream combination8,932,031Pacer combination1,500,000Total - year ended March 31, 201214,432,031 High Sierra combination20,703,510Retail propane combinations850,676Water services combination516,978Pecos combination1,834,414Third Coast combination344,680Total - year ended March 31, 201324,250,258 In connection with the completion of these transactions, we amended our Registration Rights Agreement, which provides for certain registration rightsfor certain holders of our common units. F-41Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 cashfrom operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates, referred toas “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 minimumquarterly 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 specifiedminimum 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 ofdistributions paid to the limited partners. These distributions are referred to as “incentive distributions.” Our minimum quarterly distribution is $0.3375 perunit ($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 partnerbased on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest in Distributions” are the percentage interests of ourgeneral 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 arealso applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our generalpartner include its 0.1% general partner interest, assume our general partner has contributed any additional capital necessary to maintain its 0.1% generalpartner interest and has not transferred its incentive distribution rights and there are no arrearages on common units. Marginal Percentage Interest InTotal QuarterlyDistributionsDistribution per UnitUnitholdersGeneral PartnerMinimum quarterly distribution$0.337599.9%0.1%First target distributionabove$0.3375up to$0.38812599.9%0.1%Second target distributionabove$0.388125up to$0.42187586.9%13.1%Third target distributionabove$0.421875up to$0.5062576.9%23.1%Thereafterabove$0.5062551.9%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, adistribution 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: AmountAmount Paid toAmount Paid toDate DeclaredRecord DateDate PaidPer UnitLimited PartnersGeneral Partner(in thousands)(in thousands)July 25, 2011August 3, 2011August 12, 2011$0.1669$2,467$3October 21, 2011October 31, 2011November 14, 20110.33754,9905January 24, 2012February 3, 2012February 14, 20120.35007,73510April 18, 2012April 30, 2012May 15, 20120.36259,16510July 24, 2012August 3, 2012August 14, 20120.412513,574134October 17, 2012October 29, 2012November 14, 20120.450022,846707January 24, 2013February 4, 2013February 14, 20130.462524,245927April 25, 2013May 6, 2013May 15, 20130.477525,6051,189 F-42Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 wereentitled. The following table summarizes the number of equivalent units that were not eligible to receive a distribution on each of the record dates: EquivalentUnits NotRecord DateEligibleAugust 3, 2011—October 31, 20114,000,000February 3, 20127,117,031April 30, 20123,932,031August 3, 201217,862,470October 29, 2012516,978February 4, 20131,202,085May 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 partnerand its affiliates who perform services for us. The Long-Term Incentive Plan allows for the issuance of restricted units, phantom units, unit options, unitappreciation rights and other unit-based awards, as discussed below. The number of common units that may be delivered pursuant to awards under the planis limited to 10% of the issued and outstanding common and subordinated units. The maximum number of units deliverable under the plan automaticallyincreases to 10% of the issued and outstanding common and subordinated units immediately after each issuance of common units, unless the planadministrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations willnot be considered to be delivered under the Long-Term Incentive Plan. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates orexpires without the delivery of units, the units subject to such award will again be available for new awards under the Long-Term Incentive Plan. Commonunits 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 openmarket, 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 awardunder 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 ofthe 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 granted1,684,400Units vested and issued(156,802)Units withheld for employee taxes(61,698)Units forfeited(21,000)Unvested restricted units at March 31, 20131,444,900 F-43Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and the Six Months Ended March 31, 2011 and September 30, 2010 The scheduled vesting of the awards is summarized below: Vesting DateNumber of Awards July 1, 2013377,300July 1, 2014360,800July 1, 2015272,300July 1, 2016263,500July 1, 2017169,000July 1, 20182,000Total unvested units at March 31, 20131,444,900 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 onMarch 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 ofdistribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant mightmake 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 thevesting 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 inaccrued expenses and other payables on our consolidated balance sheet at March 31, 2013 includes $5.0 million related to these awards. We estimate that theexpense 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 forfeituresof 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$12,16820157,51620166,55920174,61320181,040201915Total$31,911 As of March 31, 2013, 3,760,539 units remain available for issuance under the Long-Term Incentive Plan. F-44Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 ofClass A common stock, $10 par value per share. During the six months ended September 30, 2010, 650 outstanding stock options were exercised for a totalconsideration 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$36,811Collection of stock option receivable1,430Net tax obligations of NGL Supply not assumed by the Partnership3,120Distribution 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 pershare plus dividends in arrears at the option of the shareholder with 30 days notice. These preferred shares have been separately classified in the consolidatedstatement 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 allof 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 derivativeinstruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature. The carrying amounts of our debtobligations 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 atMarch 31, 2013: DerivativeDerivativeAssetsLiabilities(in thousands)Level 1 measurements$947$(3,324)Level 2 measurements9,911(13,280)10,858(16,604) Netting of counterparty contracts(3,503)3,503Cash collateral provided or held(1,760)400Commodity contracts reported on consolidated balance sheet$5,595$(12,701) F-45Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 atMarch 31, 2012: DerivativeDerivativeAssetsLiabilities(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 31,20132012(in thousands)Prepaid expenses and other current assets$5,551$—Other noncurrent assets44—Accrued expenses and other payables(12,701)(36)Net liability$(7,106)$(36) F-46Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 derivativesas hedges. ContractsSettlement PeriodTotalNotionalUnits(Barrels)Fair Valueof Net Assets(Liabilities)(in thousands)As of March 31, 2013 -Propane swaps (1)April 2013 - March 2014(282)$3,197Heating oil calls and futures (2)May 2013 - June 2013879Crude swaps (3)April 2013 - June 2014(91)153Crude - butane spreads (4)April 2013 - March 2014(1,116)(7,651)Crude forwards (5)April 2013 - March 2014(144)1,033Butane forwards (6)April 2013 - March 20141,546(2,557)(5,746)Net cash collateral held(1,360)Net fair value of commodity derivatives on consolidatedbalance sheet$(7,106) As of March 31, 2012 -Propane swapsApril 2012 - March 2013(460)$(36) (1) Propane swaps — Our natural gas liquids logistics segment routinely purchases inventory during the warmer months and stores the inventoryfor sale in the colder months. The contracts listed in this table as “propane swaps” represent financial derivatives we have entered into as aneconomic 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 fixedprice. The contracts listed in this table as “heating oil calls and futures” represent financial derivatives we have entered into as an economichedge against the risk that heating oil prices will rise between the time we entered into the fixed price sale commitment with the customers and thetime 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 oilindex. 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 thistable as “crude swaps” represent hedges against the risk that changes in the different index prices would reduce the margins between thepurchase 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 calculatedas a specified percentage of a crude oil index at the delivery date. The contracts listed in this table as “crude — butane spreads” representfinancial derivatives we have entered into as economic hedges against the risk that the spread between butane prices and crude prices will narrowbetween 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 beplaced by our customers. The contracts listed in this table as “crude forwards” represent financial derivatives we have entered into as aneconomic 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 expectedto be placed by our customers. The contracts listed in this table as “butane forwards” represent F-47Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 LPNGL SupplyYearYearSix MonthsSix MonthsEndedEndedEndedEndedMarch 31,March 31,March 31,September 30,2013201220112010(in thousands)Commodity contracts -Unrealized gain (loss)$(5,275)$(4,384)$1,357$(200)Realized gain89910,351111426Interest 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 aportion 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 notionalamounts of derivative instruments do not represent actual amounts exchanged between the parties, but instead represent amounts on which the contracts arebased. 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. Werecorded 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 theuse 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 overallexposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or otherconditions. 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 receivepayment from customers on a monthly basis. As a result, receivables from individual customers in our crude business are generally higher than thereceivables 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 consolidatedstatements 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 revolvingcredit 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 wouldresult 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 ofthe revolving credit facility are consistent with current market rates, and that the book value of the debt approximates fair value. F-48Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 monthsended 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 isshown 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 operationsbegan 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 gasproduction, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. These operations began with our June 2012 merger withHigh 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 gasliquids operations acquired in the June 2012 merger with High Sierra. We previously reported our natural gas liquids operations in two segments, referred to asour “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 gasliquids 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 2012merger with High Sierra, and also include certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included toreconcile the data for the reportable segments to data in our consolidated financial statements. F-49Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and the Six Months Ended March 31, 2011 and September 30, 2010 NGL Energy Partners LPNGL SupplyYearYearSix MonthsSix MonthsEndedEndedEndedEndedMarch 31,March 31,March 31,September 30,2013201220112010(in thousands)Revenues:Crude oil logistics$2,339,148$—$—$—Water services62,227———Natural gas liquids logistics -Propane sales841,448923,022477,774243,908Other natural gas liquids sales858,276251,62790,74671,456Storage revenues and other33,9542,4621,183959Retail propane -Propane sales288,410175,41767,1756,128Distillate sales106,1926,547——Other retail sales35,85617,3705,638740Other4,233———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 services20,923———Natural gas liquids logistics11,0853,661554519Retail propane25,49611,4502,887870Other2,173———Total depreciation and amortization$68,853$15,111$3,441$1,389 Operating income (loss):Crude oil logistics$34,236$—$—$—Water services8,576———Natural gas liquids logistics30,3369,7359,590865Retail propane46,8699,6167,362(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 income1,26176522166Interest expense(32,994)(7,620)(2,482)(372)Loss on early extinguishment of debt(5,769)———Other income (expense), net260290103124Income tax (provision) benefit(1,875)(601)—1,417Net income (loss)$48,190$7,864$12,679$(2,560) Additions to property, plant and equipment, includingacquisitions (accrual basis):Crude oil logistics$89,860$—$—$—Water services137,116———Natural gas liquids logistics15,12950,27629015Retail propane66,933150,18141,152386Corporate and other17,858———Total$326,896$200,457$41,442$401 March 31,March 31,20132012(in thousands)Year-End Information:Total assets:Crude oil logistics$801,030$—Water services466,462—Natural gas liquids logistics474,141325,173Retail propane513,301417,639Corporate36,4136,707Total$2,291,347$749,519 Long-lived assets, net of depreciation and amortization,including goodwill and intangibles:Crude oil logistics$356,750$—Water services453,986—Natural gas liquids logistics238,192176,419Retail propane441,762366,242Corporate31,9965,468Total$1,522,686$548,129 F-50Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and 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 usand 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 transactionsare included within revenues and cost of sales of our natural gas liquids logistics business in our consolidated statements of operations. We also madepayments to SemGroup for certain administrative and operational services. These transactions are reported within operating and general and administrativeexpenses 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 Sierraown interests in several entities. Subsequent to this business combination with High Sierra, we have purchased products and services from and have soldproducts and services to these entities. The majority of these transactions relate to crude oil purchases and crude oil transportation services and are reportedwithin 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 withinrevenues in our consolidated statement of operations. In addition, our retail operations purchased goods and services from certain entities owned by ourexecutive officers and their family members. These transactions are summarized in the table below for the years ended March 31, 2013 and 2012 (in thousands): 20132012 Product sales to SemGroup$32,431$29,200Product purchases from SemGroup60,42523,800Payments to SemGroup for services256700Sales to entities affiliated with High Sierra management16,828—Purchases from entities affiliated with High Sierra management60,942—Purchases from entities affiliated with retail segment management273300 In addition to the amounts shown in the table above, we completed two business combinations during the year ended March 31, 2013 with entities inwhich 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. Wealso paid $5.0 million under a non-compete agreement to an employee. Receivables from affiliates at March 31, 2013 and 2012 consist of the following (in thousands): 20132012 Receivables from sales of product to SemGroup$—$1,878Receivables from entities affiliated with High Sierramanagement22,787—Other96404$22,883$2,282 Payables to related parties at March 31, 2013 and 2012 consist of the following (in thousands): F-51Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and the Six Months Ended March 31, 2011 and September 30, 2010 20132012 Working capital settlement for Osterman combination$—$4,763Payables to SemGroup4,6014,699Payables to entities affiliated with High Sierra management2,299$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 certaintransactions 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 acquireHigh 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 HighSierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High SierraEnergy 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 doneseparately by quarter and year. The total of net income per common and subordinated unit of the individual quarters may not equal the net income percommon and subordinated unit for the year, due primarily to the income allocation between the general partner and limited partners and variations in theweighted 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 commercialcustomers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period fromOctober through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September ofeach year. Our natural gas liquids logistics segment is also subject to seasonal fluctuations, as demand for propane and butane is typically higher during thewinter months. Our operating revenues from our other segments are less weather sensitive. Additionally, the acquisitions described in Note 4 impact thecomparability of the quarterly information within the year, and year to year. F-52Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESAND NGL SUPPLY, INC.Notes to Consolidated Financial Statements - ContinuedAs of March 31, 2013 and 2012, and for the Years Ended March 31, 2013 and 2012and the Six Months Ended March 31, 2011 and September 30, 2010 Quarter EndedYear EndedJune 30,September 30,December 31,March 31,March 31,20122012201220132013(dollars in thousands, except unit and per unit data)Total revenues$326,436$1,135,510$1,338,208$1,617,613$4,417,767 Total cost of sales298,9851,053,6901,204,5451,481,8904,039,110 Net income (loss)(24,710)10,08240,47722,34148,190 Net income (loss) to parent equity(24,650)10,07340,17622,34147,940 Earnings (loss) per unit, basic and diluted -Common$(0.76)$0.18$0.75$0.39$0.96Subordinated$(0.77)$0.18$0.75$0.39$0.93 Weighted average common units outstanding - basic anddiluted26,529,13344,831,83646,364,38147,665,01541,353,574Weighted average subordinated outstanding units - basicand diluted5,919,3465,919,3465,919,3465,919,3465,919,346 Quarter EndedYear EndedJune 30,September 30,December 31,March 31,March 31,20112011201120122012(dollars in thousands, except unit and per unit data)Total revenues$190,845$210,041$470,649$438,938$1,310,473 Total cost of sales185,973201,454439,790389,8061,217,023 Net income (loss)(6,773)(5,395)6,09013,9427,864 Net income (loss) to parent equity(6,773)(5,395)6,09013,9547,876 Earnings (loss) per unit, basic and diluted -Common$(0.53)$(0.36)$0.24$0.47$0.32Subordinated$(0.53)$(0.36)$0.28$0.53$0.58 Weighted average common units outstanding - basic anddiluted9,883,3428,864,22218,699,59023,263,38615,169,983Weighted average subordinated outstanding units - basicand diluted2,927,1495,199,3465,919,3465,919,3465,175,384 F-53Table of Contents INDEX TO EXHIBITS ExhibitNumberDescription2.1Contribution, 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 andSilverthorne 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) 2.2Contribution and Sale Agreement, dated August 12, 2011, by and among the Partnership and the Sellers named therein (incorporated byreference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 7, 2011) 2.3Contribution 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) 2.4Contribution 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) 2.5Contribution 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) 2.6Contribution 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) 2.7Contribution 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) 2.8Contribution 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 onJanuary 9, 2012) 2.9Contribution 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) 2.10Contribution 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) 2.11Asset 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 byreference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed on February 10, 2012) 2.12Waiver and First Amendment to Asset Purchase Agreement dated as of January 31, 2012 by and among NGL Energy Partners LP andNorth American Propane, Inc., EnergyUSA Propane, Inc., EUSA-Allied Acquisition Corp. and EUSA Heating & Air ConditioningServices, 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 onApril 20, 2012) Table of Contents ExhibitNumberDescription2.13Waiver and Second Amendment to Asset Purchase Agreement dated as of February 3, 2012 by and among NGL Energy Partners LPand North American Propane, Inc., EnergyUSA Propane, Inc., EUSA-Allied Acquisition Corp. and EUSA Heating & AirConditioning Services, Inc. (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K/A (File No. 001-35172) filedwith the SEC on April 20, 2012) 2.14Agreement 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 CurrentReport on Form 8-K (File No. 001-35172) filed with the SEC on May 21, 2012) 2.15Agreement and Plan of Merger, dated as of May 18, 2012, by and among NGL Energy Holdings LLC, HSEGP LLC and High SierraEnergy GP, LLC (incorporated by reference to Exhibit 2.2 the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onMay 21, 2012) 2.16Equity 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) 2.17Sale Agreement, dated as of December 31, 2012, among Third Coast Towing, LLC, Jeff Kirby, Jane Helm, James Rudellat and HighSierra Transportation, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed withthe SEC on January 7, 2013) 3.1Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Registration Statement onForm S-1 (File No. 333-172186) filed on April 15, 2011) 3.2Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.2 tothe Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.3Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011) 3.4First Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 26, 2011) 3.5Second Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012) 3.6Third Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 26, 2012) 3.7Fourth Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 2012) 3.8Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement onForm S-1 (File No. 333-172186) filed on April 15, 2011) 3.9Certificate of Amendment to Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.5 to theRegistration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) Table of Contents ExhibitNumberDescription3.10Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC (incorporated by reference toExhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on February 28, 2013) 4.1First 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) 4.2Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 by andamong 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) 4.3Amendment No. 2 and Joinder to First Amended and Restated Registration Rights Agreement, dated January 3, 2012, by and amongNGL Energy Holdings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-PortlandPropane, L.L.C., Pacer Propane (Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C. (incorporated byreference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012) 4.4Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGLEnergy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on May 4, 2012) 4.5Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and betweenNGL 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) 4.6Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and betweenNGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on October 3, 2012) 4.7Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by andbetween NGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, CaritasTrust, 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) 4.8Call Agreement, dated as of November 1, 2012, among Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco PetroleumCorporation, Caritas Trust, Animosus Trust, Nitor Trust and NGL Energy Partners LP (incorporated by reference to Exhibit 4.1 theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012) 4.9Call 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) 4.10Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by reference toExhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 4.11Amendment 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) 4.12Amendment 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) Table of Contents ExhibitNumberDescription10.1Agreement Relating to Redemption of Common Units in Connection with the Underwriters’ Option to Purchase Additional CommonUnits with Respect to the Initial Public Offering of NGL Energy Partners LP by and among NGL Energy Partners LP, NGL EnergyHoldings 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) 10.2Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders partythereto and Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to the CurrentReport on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 10.3Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP, DeutscheBank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012) 10.4Amendment No. 1 to Credit Agreement, dated as of January 15, 2013, among NGL Energy Operating LLC, the Partnership, thesubsidiary 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) 10.5Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K (File No 001-35172) filed on May 9, 2013) 10.6Letter 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) 10.7NGL 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) 10.8Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long Term Incentive Plan (incorporated by referenceto 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 onAugust 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 Table of Contents ExhibitNumberDescription 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 endedMarch 31, 2013 and 2012 and the six months ended March 31, 2011 and September 30, 2010, (iii) Consolidated Statements of ComprehensiveIncome (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 andSeptember 30, 2010 and (v) Consolidated Statements of Cash Flows for years ended March 31, 2013 and 2012 and the six months endedMarch 31, 2011 and September 30, 2010. + Management contracts or compensatory plans or arrangements. 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 LPNGL Supply, Inc.YearSix MonthsSix MonthsEndedYear EndedEndedEndedYear EndedYear EndedMarch 31,March 31,March 31,September 30,March 31,March 31,201320122011201020102009 EARNINGS:Income (loss) from continuingoperations before income taxes$50,065$8,465$12,679$(3,977)$6,108$8,124Loss (income) from continuingoperations before income taxesattributable to noncontrolling interests(250)1245680Fixed charges55,8819,3542,7615971,1492,135Total earnings$105,696$17,83115,440(3,335)7,26310,339 FIXED CHARGES:Interest expense$32,994$7,620$2,482$372$668$1,621Loss on early extinguishment of debt5,769—————Portion of rental expense estimated torelate to interest (1)17,1181,734279225481514Total fixed charges$55,881$9,354$2,761$597$1,149$2,135 Ratio of earnings to fixed charges1.891.915.59(2)6.324.84 (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. Exhibit 21.1 LIST OF SUBSIDIARIES OF NGL ENERGY PARTNERS LP SubsidiaryJurisdiction of OrganizationNGL Energy Operating LLCDelawareHicksgas, LLCDelawareNGL Supply, LLCDelawareNGL Gateway Terminals, Inc.OntarioNGL Supply Retail, LLCDelawareNGL Supply Terminal Company, LLCDelawareNGL Supply Wholesale, LLCDelawareRocket Supply, Inc.DelawareOsterman Propane, LLCDelawareNGL-NE Real Estate, LLCDelawareNGL-MA Real Estate, LLCDelawareNGL-MA, LLCDelawareAtlantic Propane LLC (1)OklahomaNGL Hutch, LLCDelawareHigh Sierra Energy GP, LLCColoradoHigh Sierra Energy, LPDelawareHigh Sierra Energy Shared Services, LLCColoradoHigh Sierra Energy Operating, LLCColoradoHigh Sierra Compression, LLCColoradoHigh Sierra SERTCO, LLC (2)ColoradoHigh Sierra Energy Marketing, LLCColoradoCentennial Energy, LLCColoradoCentennial Gas Liquids, ULCAlbertaHigh Sierra Crude Oil & Marketing, LLCColoradoAndrews Oil Buyers, Inc.TexasPetro Source Products, LLCTexasPetro Source Terminals, LLCTexasBlack Hawk Gathering, LLCTexasPecos Gathering & Marketing, LLCTexasMidstream Operations, LLCTexasHigh Sierra Canada Holdings, LLCColoradoHigh Sierra Energy Canada ULCAlbertaHigh Sierra Storage, LLCColoradoHigh Sierra Transportation, LLCColoradoThird Coast Towing, LLCTexasHigh Sierra Water Holdings, LLCColoradoHigh Sierra Water Services, LLCColoradoAntiCline Disposal, LLCWyomingHigh Sierra Water Services Midcontinent, LLCOklahomaHigh Sierra Water Permian, LLCColoradoGreensburg Oilfield, LLCColoradoHigh Sierra Water-Eagle Ford, LLCDelawareIndigo 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 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 reportingincluded 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 reportdated June 29, 2011, with respect to the consolidated financial statements of NGL Supply, Inc. for the six month period ended September 30, 2010. We herebyconsent 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, effectiveNovember 20, 2012). /s/ GRANT THORNTON LLP Tulsa, OklahomaJune 13, 2013 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 makethe statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered bythis report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respectsthe 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 inExchange 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 oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us byothers 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 oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal 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 theeffectiveness 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 mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto 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, tothe 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 arereasonably 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 internalcontrol over financial reporting. Date: June 13, 2013/s/ H. Michael KrimbillH. Michael KrimbillChief Executive Officer ofNGL Energy Holdings LLC, the general partner ofNGL Energy Partners LP 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 makethe statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered bythis report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respectsthe 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 inExchange 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 oursupervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us byothers 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 oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal 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 theeffectiveness 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 mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto 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, tothe 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 arereasonably 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 internalcontrol over financial reporting. Date: June 13, 2013/s/ Atanas H. AtanasovAtanas H. AtanasovChief Financial Officer ofNGL Energy Holdings LLC, the general partner ofNGL Energy Partners LP EXHIBIT 32.1 CERTIFICATIONPURSUANT 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 asfiled with the Securities and Exchange Commission on the date hereof (the “Report”), I, H. Michael Krimbill, Chief Executive Officer of NGL EnergyHoldings 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-OxleyAct 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 thePartnership. Dated: June 13, 2013/s/ H. Michael KrimbillH. Michael KrimbillChief Executive Officer ofNGL Energy Holdings LLC, thegeneral 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 andfurnished to the Securities and Exchange Commission or its staff upon request. EXHIBIT 32.2 CERTIFICATIONPURSUANT 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 asfiled with the Securities and Exchange Commission on the date hereof (the “Report”), I, Atanas H. Atanasov, Chief Financial Officer of NGL EnergyHoldings 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-OxleyAct 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 thePartnership. Dated: June 13, 2013/s/ Atanas H. AtanasovAtanas H. AtanasovChief Financial Officer ofNGL Energy Holdings LLC, thegeneral 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 andfurnished to the Securities and Exchange Commission or its staff upon request. 

Continue reading text version or see original annual report in PDF format above