NGL Energy Partners
Annual Report 2014

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, 2014 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 xAccelerated filer o 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 at September 30, 2013 of the Common Units held by non-affiliates of the registrant, based on the reported closing price of theCommon Units on the New York Stock Exchange on such date ($30.84 per Common Unit) was $1,443,663,823. For purposes of this computation, allexecutive officers, directors and 10% owners of the registrant are deemed to be affiliates. Such a determination should not be deemed an admission that suchexecutive officers, directors and 10% beneficial owners are affiliates. At May 23, 2014, there were 74,706,160 common units and 5,919,346 subordinated units issued and outstanding. Table of Contents TABLE OF CONTENTS PART I Item 1.Business3Item 1A.Risk Factors27Item 1B.Unresolved Staff Comments49Item 2.Properties49Item 3.Legal Proceedings49Item 4.Mine Safety Disclosures49 PART II Item 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities50Item 6.Selected Financial Data51Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations54Item 7A.Quantitative and Qualitative Disclosures About Market Risk85Item 8.Financial Statements and Supplementary Data86Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure86Item 9A.Controls and Procedures87Item 9B.Other Information87 PART III Item 10.Directors, Executive Officers and Corporate Governance88Item 11.Executive Compensation94Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters103Item 13.Certain Relationships and Related Transactions and Director Independence105Item 14.Principal Accountant Fees and Services109 PART IV Item 15.Exhibits and Financial Statement Schedules110 iTable of Contents Forward-Looking Statements This Annual Report on Form 10-K (“Annual Report”) contains various forward-looking statements and information that are based on our beliefs andthose of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as anystatement that does not relate strictly to historical or current facts. When used in this Annual Report, words such as “anticipate,” “believe,” “could,”“estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will,” and similar expressions and statements regarding our plans andobjectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on whichsuch forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to becorrect. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize,or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the keyrisk factors that may impact our consolidated financial position and results of operations are: · the prices for crude oil, natural gas, natural gas liquids, refined products, ethanol, and biodiesel; · energy prices generally; · the price of propane relative to the price of alternative and competing fuels; · the price of gasoline relative to the price of corn, which impacts the price of ethanol; · the general level of crude oil, natural gas, and natural gas liquids production; · the general level of demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel; · the availability of supply of crude oil, natural gas liquids, refined products, ethanol, and biodiesel; · the level of crude oil and natural gas drilling and production in producing basins in which we have water treatment facilities; · the ability to obtain adequate supplies of propane and distillates for retail sale in the event of an interruption in supply or transportation and theavailability of capacity to transport propane and distillates to market areas; · actions taken by foreign oil and gas producing nations; · the political and economic stability of petroleum producing nations; · the effect of weather conditions on supply and demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel; · the effect of natural disasters, lightning strikes, or other significant weather events; · availability of local, intrastate and interstate transportation infrastructure, including with respect to our truck, railcar, and barge transportationservices; · availability, price, and marketing of competitive fuels; · the impact of energy conservation efforts on product demand; · energy efficiencies and technological trends; · governmental regulation and taxation; · the impact of legislative and regulatory actions on hydraulic fracturing and on the treatment of flowback and produced water; · hazards or operating risks incidental to the transporting and distributing of petroleum products that may not be fully covered by insurance; · the maturity of the crude oil and natural gas liquids industries and competition from other marketers; 1Table of Contents · loss of key personnel; · the ability to hire drivers; · the ability to renew contracts with key customers; · the ability to maintain or increase the margins we realize for our terminal, barging, trucking, and water disposal, recycling, and dischargeservices; · the ability to renew leases for general purpose and high pressure railcars; · the ability to renew leases for underground natural gas liquids storage; · the non-payment or nonperformance by our customers; · the availability and cost of capital and our ability to access certain capital sources; · a deterioration of the credit and capital markets; · the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results; · the ability to successfully integrate acquired assets and businesses; · changes in the volume of crude oil recovered during the wastewater treatment process; · changes in the financial condition and results of operations of entities in which we own noncontrolling equity interests; · changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations or 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, natural gas liquids, refined products, ethanol, and biodiesel,our processing of wastewater, and transportation and risk management activities; · the costs and effects of legal and administrative proceedings; · the demand for refined products; · any reduction or elimination of the Renewable Fuels Standard; · the operational and financial success of our joint ventures; and · changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our joint venture’s pipeline assets. You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this AnnualReport. Except as required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as aresult of new information, future events, or otherwise. When considering forward-looking statements, please review the risks described under “Item 1A —Risk Factors.” 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 36 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, 2014. Unless otherwise indicated, thisdata is as of March 31, 2014. Item 1. Business Overview We are a Delaware limited partnership formed in September 2010 by several investors (“IEP Parties”). As part of our formation, we acquired andcombined the assets and operations of NGL Supply, Inc., primarily a wholesale propane and terminaling business founded in 1967, and Hicksgas, LLCand Hicksgas Gifford, Inc., primarily a retail propane business founded in 1940. Subsequent to our formation, we significantly expanded our operationsthrough numerous business combinations. At March 31, 2014, our primary businesses include: · A crude oil logistics business, the assets of which include crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet ofleased railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics business purchases crudeoil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, andother trade hubs. · A water solutions business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Ourwater solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oiland natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. · Our liquids business, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the UnitedStates and in Canada, and which provides natural gas liquids terminaling services through its 22 terminals throughout the United States andrailcar transportation services through its fleet of leased and owned railcars. Our liquids business purchases propane, butane, and otherproducts from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in thewholesale markets. · Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural,commercial, and industrial customers and to certain re-sellers in more than 20 states. We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products inback-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business,which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchasesbiodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders.These businesses were acquired in our December 2013 acquisition of Gavilon, LLC (“Gavilon Energy”). For more information regarding our operating segments, please see Note 13 to our consolidated financial statements included in this Annual Report. 3Table of Contents Initial Public Offering On May 17, 2011, we completed our initial public offering (“IPO”) and listed our common units on the New York Stock Exchange under thesymbol “NGL.” Upon the completion of our IPO, we had outstanding common units, subordinated units, a 0.1% general partner interest, and incentivedistribution rights (“IDRs”). IDRs entitle the holder to specified increasing percentages of cash distributions as our per-unit cash distributions increase abovespecified levels. Acquisitions Subsequent to Initial Public Offering Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, including the following, amongothers: · In October 2011, we completed a business combination with E. Osterman Propane, Inc., its affiliated companies, and members of theOsterman family (collectively, “Osterman”), whereby we acquired retail propane operations in the northeastern United States. · In November 2011, we completed a business combination with SemStream, L.P. (“SemStream”), whereby we acquired SemStream’s wholesalenatural gas liquids supply and marketing operations and its 12 natural gas liquids terminals. · In January 2012, we completed a business combination with seven companies associated with Pacer Propane Holding, L.P. (collectively,“Pacer”), whereby we acquired retail propane operations, primarily in the western United States. · In February 2012, we completed a business combination with North American Propane, Inc. (“North American”), whereby we acquired retailpropane and distillate operations in the northeastern United States. · In May 2012, we acquired the retail propane and distillate operations of Downeast Energy Corp (“Downeast”). These operations are primarily inthe northeastern United States. · In June 2012, we completed a business combination with High Sierra Energy, LP and High Sierra Energy GP, LLC (collectively,“High Sierra”), whereby we acquired all of the ownership interests in High Sierra. High Sierra’s businesses include crude oil gathering,transportation and marketing; water treatment, disposal, and transportation; and natural gas liquids transportation and marketing. · In November 2012, we completed a business combination whereby we acquired Pecos Gathering & Marketing, L.L.C. and certain of itsaffiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texasand New Mexico. · In December 2012, we completed a business combination transaction whereby we acquired all of the membership interests in Third CoastTowing, LLC (“Third Coast”). The business of Third Coast consists primarily of transporting crude oil via barge. · In July 2013, we completed a business combination whereby we acquired the assets of Crescent Terminals, LLC and the ownership interests inCierra Marine, LP and its affiliated companies (collectively, “Crescent”), whereby we acquired four towboats, seven crude oil barges, and acrude oil terminal in South Texas. · In July 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd. (“Big Lake”), whereby we acquired awater disposal facility in West Texas. We also entered into a development agreement that provides us the option to purchase disposal facilitiesthat may be developed in the future. During March 2014, we purchased one additional facility under this development agreement. 4Table of Contents · In August 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively,“OWL”). The businesses of OWL include water disposal operations and a water transportation business in Texas. · In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), in which we acquired theownership interests in water disposal facilities in Texas and the right to purchase one additional facility, which we exercised in March 2014. · In December 2013, we acquired the ownership interests in Gavilon Energy. The assets of Gavilon Energy include crude oil terminals inOklahoma, Texas, and Louisiana and a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipelinethat originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline became operational in February 2014. The operationsof Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids. Primary Service Areas The following maps show the primary service areas of our businesses at various points in time, to illustrate the growth of our businesses: Primary Service Areas at May 11, 2011 5Table of Contents Primary Service Areas at March 31, 2012 Primary Service Areas at March 31, 2013 6Table of Contents Primary Service Areas at March 31, 2014 7Table of Contents Organizational Chart The following chart provides a summarized view of our legal entity structure at March 31, 2014: (1) Includes the operations of our crude oil logistics, refined products, and renewables businesses(2) Includes the operations of our water solutions business(3) Includes the operations of our liquids business(4) Includes the operations of our retail propane business 8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 midstream master limited partnership providing multiple services to producers. We continue toenhance our ability to transport crude oil from the wellhead to refiners, wastewater from the wellhead to treatment for disposal, recycle, ordischarge, and transport natural gas liquids from processing plants to end users, including retail propane customers. · Achieve organic growth by investing in new assets that increase volumes, enhance our operations, and generate attractive rates 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 solutions 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 solutions 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 liquids and crude oillogistics segments, we intend to focus on back-to-back contracts which minimize commodity price exposure. In our water solutions segment,cash flows are typically supported by fee-based contracts, some of which include acreage dedications from producers or volume commitments. · Maintain a disciplined capital structure characterized by low leverage. We target leverage levels that are consistent with those of 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 finance organic growth and opportunisticallyrepay indebtedness, including amounts outstanding under our revolving credit facility. We believe this strategy positions us to pursue futureacquisitions and to execute upon our organic growth initiatives. Our Competitive Strengths We believe that we are well-positioned to successfully execute our business strategies and achieve our principal business objectives because of 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, includingmaster limited partnerships. In addition, through decades of experience, our management team has developed strong business relationships withkey industry participants throughout the United States. We believe that our management’s knowledge of the industry, relationships within theindustry, and experience in identifying, evaluating and completing acquisitions provides us with opportunities to grow through strategic andaccretive acquisitions that complement or expand our existing operations. · Our vertically integrated and diversified operations, which help us generate more predictable and stable cash flows on a year-to-yearbasis. Our ability to provide multiple services to producers in numerous geographic areas enhances our competitive position. Our retail propanebusiness sources propane through our liquids business which allows us to leverage the expertise of our liquids business to help improve ourmargins and profitability and enhance our cash flows. Furthermore, we believe that our liquids business provides us with valuable marketintelligence that helps us identify potential acquisition opportunities. 9Table of Contents · Our network of crude oil transportation assets, which allows us to serve customers over a wide geographic area and optimize sales.Our strategically deployed railcar fleet, towboats, barges, and trucks, and our owned and contracted pipeline capacity, provide access to a widerange of customers and markets. We use this expansive network of transportation assets, together with our proprietary linear programmingmodel, 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 United States, including the Permian, Niobrara, andEagle Ford shale plays. In addition, we believe that the technological capabilities of our water processing business can be quickly implemented atnew facilities 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 railcar 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 distillates andgenerate higher margins than other customers. Our high percentage of propane tank ownership, payment billing systems, and automaticdelivery program have resulted in a strong record of customer retention and help us better predict our cash flows in the retail propane businesssegment. 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, the Eagle Ford Basin in Texas, and the Anadarko Basin in Oklahoma and Texas. Operations. We transport crude oil using the following assets: · 300 owned trucks, 300 owned trailers, and 100 leased trucks operating primarily in the Mid-Continent, Permian Basin, Eagle Ford Basin, andRocky Mountain regions; · 200 owned railcars and 700 leased railcars operating primarily in North Dakota, Oklahoma, Colorado, Wyoming, and Texas; and · 8 owned towboats, 19 owned barges, 5 leased towboats and 12 leased barges (including 1 leased storage barge) operating primarily in the inter-coastal waterways of the Gulf Coast and along the Mississippi and Arkansas river systems. We contract for truck, rail, and barge transportation services from third parties and ship on common carrier pipelines. We own 60 pipeline injectionfacilities in Kansas, Oklahoma, North Dakota, New Mexico, Texas, and Montana. We lease six rail transload facilities and have throughput agreements atseven rail transload facilities in Colorado, Kansas, Louisiana, New Mexico, North Dakota, Oklahoma, and Texas. We own seven storage terminal facilities, as summarized below: Storage CapacityLocation (barrels)Cushing, Oklahoma4,140,000Catoosa, Oklahoma138,000Port Aransas, Texas120,000Rio Hondo, Texas80,000Wheatland, Wyoming80,000Seadrift, Texas25,000Sunray, Texas9,500 10Table of Contents We lease 3.85 million barrels of storage capacity in Cushing, Oklahoma. We have two Gulf Coast terminal facilities that are under construction and are expected to be completed during the latter part of fiscal 2015 with atotal expected storage capacity of 625,000 barrels. We also own a 50% interest in Glass Mountain, which owns a 210-mile crude oil pipeline that originates inwestern Oklahoma and terminates in Cushing, Oklahoma. This pipeline, which became operational in February 2014, has a capacity of 147,000 barrels perday. Customers. Our customers include crude oil refiners and marketers. Approximately 60% of the revenues from our crude oil logistics segment duringthe year ended March 31, 2014 related to our ten largest customers of the segment. In addition to utilizing our assets to transport product we own, we 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 havegreater financial resources than we do. The primary factors on which we compete are: · price; · availability of supply; · level and quality of service; · available space on common carrier pipelines; · the availability of railcars; · proprietary terminals; · owned barges and towboats; · obtaining and retaining customers; and · the acquisition of businesses. Supply. We obtain crude oil from a large base of suppliers, which consist primarily of crude oil producers. We currently purchase from 800producers at 7,600 leases. Pricing Policy. Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets, such 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 oil 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 11Table of Contents · 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 NGL — Crude Logistics trade name. Water Solutions Overview. Our water solutions segment generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated fromcrude oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. Our facilities are located near fields withhigh levels of crude oil and natural gas production, such as the Pinedale Anticline Basin in Wyoming, the DJ Basin in Colorado, and the Permian and EagleFord Basins in Texas. Operations. We own 23 wastewater processing facilities. The location of the facilities and the processing capacities at which the facilities currentlyoperate are summarized below. ProcessingCapacityLocation(barrels per day)Pinedale, Wyoming (A)(B)60,000Briggsdale, Colorado (C)(D)34,000Grover, Colorado (C)25,000Greeley, Colorado (B)18,000Platteville, Colorado (C)(E)16,200Kersey, Colorado (C)14,000LaSalle, Colorado (C)5,900Brighton, Colorado (C)5,100Big Lake, Texas (C)30,000Pecos, Texas (C)(F)23,000Carrizo Springs, Texas (B)22,500Charlotte, Texas (C)(F)22,000Cheapside, Texas (C)22,000Gillett, Texas (C)22,000Karnes City, Texas (C)22,000Artesia Wells, Texas (C)20,000Nixon, Texas (C)20,000Los Angeles, Texas (B)20,000Fowlerton, Texas (C)18,000Pearsall, Texas (B)17,000Cotulla, Texas (C)16,500Dilley Lea, Texas (B)15,000Andrews, Texas (C)12,000 (A) This facility has a design capacity of 60,000 barrels per day to process water to a recycle standard which also includes a design capacity of20,000 barrels per day to process water to a discharge standard.(B) These facilities are located on land we lease.(C) These facilities are located on land we own.(D) The processing capacity listed above for this facility includes a design capacity of 12,000 barrels per day to process water to a recycle standard.(E) The processing capacity listed above for this facility includes a design capacity of 10,000 barrels per day to process water to a recycle standard.(F) We purchased these facilities effective March 1, 2014. Our customers bring wastewater generated by crude oil and natural gas exploration and production operations to our facilities for treatment. Once wetake delivery of the water, the level of processing is determined by the ultimate disposition of the water. Our facility in Wyoming has the assets and technology needed to treat the water more extensively. At this facility, the water is recycled, rather thanbeing disposed of in an injection well. We either process the water to the point where it can be returned to 12Table of Contents producers to be re-used in future drilling operations, or we treat the water to a greater extent, such that it exceeds the standards for drinking water, and can bereturned 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 producers for use in future drilling operations. Our facilities in Texas dispose of wastewater into deep underground formations via injection wells. We also operate a wastewater transportationbusiness in Texas, whereby we transport wastewater via truck to processing facilities owned by us and other parties. We operate this business with 70 ownedtrucks, 20 owned trailers, and 80 frac tanks. Customers. The customers of our Wyoming and Colorado facilities consist primarily of large exploration and production companies who conductdrilling operations near our facilities. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume to our facilityunder multi-year contracts. Certain other customers, primarily those of our facilities in Colorado, have committed to deliver to our facilities all wastewaterproduced at all wells in a designated area under multi-year contracts. The customers of our facilities in Texas consist primarily of wastewater transportationcompanies, although one customer has committed to deliver 50,000 barrels per day to our facilities in Texas. During the year ended March 31, 2014, 37% ofthe revenues of the water solutions segment were generated from our two largest customers of the segment, and 73% of the revenues of the segment weregenerated 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 crude oil and natural gas production. Pricing Policy. We generally charge customers a processing fee per barrel of wastewater processed. Certain of our contracts require the customer 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 solutions customers consist of large oil and natural gas producers, and also include smaller watertransportation companies. We typically invoice customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits,and follow monitoring procedures on our water solutions customers. We believe the following procedures enhance our collection efforts with our water solutionscustomers: · 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 solutions business operates primarily under the NGL — Water Solutions trade name. Technology. We hold multiple patents for processing technologies. We own a research and development center, which we use to optimize treatmentprocesses and cost minimization. Liquids Overview. Our liquids segment provides natural gas liquids procurement, storage, transportation, and supply services to customers through assetsowned by us and third parties. Our liquids business also supplies the majority of the propane for our retail propane business. We also sell butanes and naturalgasolines to refiners and producers for use as blending stocks and diluent and assist refineries by managing their seasonal butane supply needs. Operations. We procure natural gas liquids from refiners, gas processing plants, producers and other resellers for delivery to leased storage space,common carrier pipelines, railcar terminals, and direct to certain customers. Our customers take delivery by loading natural gas liquids into transport vehiclesfrom common carrier pipeline terminals, private terminals, our terminals, directly from refineries and rail terminals, and by railcar. 13Table of Contents A portion of our wholesale propane gallons are presold to third-party retailers and wholesalers at a fixed price under back-to-back contracts. Back-to-back contracts, in which we balance our contractual portfolio by buying propane supply when we have a matching purchase commitment from our wholesalecustomers, protects our margins, and mitigates commodity price risk. Pre-sales also reduce the impact of warm weather because the customer is required totake delivery of the propane regardless of the weather. We generally require cash deposits from these customers. In addition, on a daily basis we have theability to balance our inventory by buying or selling propane, butanes, and natural gasoline to refiners, resellers, and propane producers through pipelineinventory 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 may sell those volumes at a lesser margin than we earn in our other wholesale operations. We purchase butane from refiners during the summer months, when refiners have a greater butane supply than they need, and sell butane to refinersduring the winter blending season, when demand for butane is higher. We utilize a portion of our railcar fleet and a portion of our leased underground storage tostore butane for this purpose. We also transport customer-owned natural gas liquids on our leased railcars and charge the customers a transportation service fee. In addition, wesub-lease railcars to certain customers. We also purchase and sell asphalt. We utilize leased railcars to move the asphalt from our suppliers to our customers. We own 22 natural gas liquids terminals and we lease a fleet of railcars. These assets give us the opportunity to access wholesale markets throughoutthe United States, and to move product to locations where demand is highest. We utilize these terminals and railcars primarily in the service of our wholesaleoperations, 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, Missouri883,000Hutchinson, Kansas840,000St. Catherines, Ontario, Canada700,000Janesville, Wisconsin553,000Light, Arkansas524,400Rixie, Arkansas524,400Winslow, Arizona500,000Albuquerque, New Mexico408,000Kingsland, Arkansas405,000Portland, Maine360,000West Springfield, Massachusetts360,000Vancouver, Washington358,000Green Bay, Wisconsin310,000Thackerville, Oklahoma235,000Ritzville, Washington198,000Sidney, Montana180,000Shelton, Washington161,000 14Table of Contents 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 a third party for a monthly fee under an operating and maintenance agreement that has a term that expires in 2017. The terminal in St.Catherines, Ontario, Canada is operated by a third party under a year-to-year agreement. We own the terminal assets. We own the land on which 12 of the terminals are located and we either have easements or lease the land on which 10 ofthe terminals are located. The terminals in East St. Louis, Illinois and Jefferson City, Missouri have perpetual easements, and the terminal in St. Catherines,Ontario, Canada has a long-term lease that expires in 2022. We own 4 railcars and lease 3,700 additional railcars, of which 600 railcars are subleased to a third party. These include high pressure and generalpurpose railcars. We own 16 transloading units, which enable customers to transfer product from railcars 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 storage space for natural gas liquids in various storage hubs in Arizona, Canada, Kansas, Michigan, Mississippi, Missouri, New York and Texas. The following chart shows our leased storage space at natural gas liquids storage facilities and interconnects to those facilities: Leased Storage Space(in gallons)BeginningAtApril 1,March 31,Storage Facility20142014Storage Interconnects Conway, Kansas73,290,00085,890,000Connected to Enterprise Mid-America and NuStar Pipelines; Rail FacilityBorger, Texas42,000,00031,500,000Connected to ConocoPhillips Blue Line PipelineBushton, Kansas10,500,00012,600,000Connected to ONEOK North System PipelineMont Belvieu, Texas3,150,0002,940,000Connected to Enterprise Texas Eastern Products PipelineCarthage, Missouri7,560,0007,560,000Connected to Magellan PipelineMarysville, Michigan4,200,00015,750,000Connected to Cochin PipelineHattiesburg, Mississippi6,930,0007,350,000Connected to Enterprise Dixie Pipeline; Rail FacilityRedwater, Alberta, Canada7,938,0009,055,200Connected to Cochin Pipeline; Rail FacilityRegina, Saskatchewan, Canada1,260,000—Connected to Cochin Pipeline; Rail FacilityBath, New York—10,122,000Rail FacilityAdamana, Arizona1,398,6001,680,000Rail FacilityCorunna, Ontario, Canada2,100,0002,100,000Rail FacilityTotal160,326,600186,547,200 During the typical heating season from September 15 through March 15 each year, we have the right to utilize ConocoPhillips’ capacity as a 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 liquids business serves 900 customers in 45 states. Our liquids business serves national, regional and independent retail,industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. Our liquids business also supplies the majority of the propane forour retail propane business. We deliver the propane supply to our customers at terminals located on common carrier pipeline systems, rail terminals,refineries, and major United States propane storage hubs. For the year ended March 31, 2014, our ten largest liquids customers represented 35% of the totalsales of our liquids business (exclusive of sales to our retail propane segment). 15Table of Contents Seasonality. Our liquids business is affected by the weather in a similar manner as our retail propane business. However, we are able to partiallymitigate the effects of seasonality by pre-selling a portion of our wholesale volumes to retailers and wholesalers and requiring the customer to take deliveryregardless of the weather. Competition. Our liquids business faces significant competition. The primary factors on which we compete are: · price; · availability of supply; · level and quality of service; · available space on common carrier pipelines; · storage availability; · the availability of railcars; · proprietary terminals; · obtaining and retaining customers; and · the acquisition of businesses. Our competitors generally include other natural gas liquids wholesalers and companies involved in the natural gas liquids midstream industry (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 contracts for many of our liquids segment sales to limit exposure to commodity price risk and protect our margins. We are ableto match our supply and sales commitments by offering our customers purchase contracts with flexible price, location, storage, and ratable delivery. However,certain common carrier pipelines require us to keep minimum in-line inventory balances year round to conduct our daily business, and these volumes may notbe 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 liquids segment customers consist of commercial accounts varying in size from local independentdistributors to large regional and national retailers. These sales tend to be large volume transactions that can range from 10,000 gallons to as much as 1,000,000gallons, and deliveries can occur over time periods extending from days to as long as a year. We perform credit analysis, require credit approvals, establishcredit limits, and follow monitoring procedures on our wholesale customers. We believe the following procedures enhance our collection efforts with ourwholesale customers: · we require certain customers to prepay or place deposits for their purchases; 16Table of Contents · 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 liquids business operates primarily under the NGL - Liquids, Centennial Energy, and Centennial Gas Liquids trade names. Retail Propane Overview. Our retail propane business consists of the retail marketing, sale and distribution of propane and distillates, including the sale and leaseof propane tanks, equipment and supplies, to more than 290,000 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 liquids business, which provides our retail propanebusiness with a stable and secure supply of propane. Operations. We market retail propane and distillates through our customer service locations. We sell propane primarily in rural areas, but we alsohave a number of customers in suburban areas where energy alternatives to propane such as natural gas are not generally available. We own or lease 92customer service locations and 91 satellite distribution locations, with aggregate propane storage capacity of 10.7 million gallons and aggregate distillate storagecapacity of 3.4 million gallons. Our customer service locations are staffed and operated to service a defined geographic market area and typically include abusiness office, product showroom, and secondary propane storage. Our satellite distribution locations, which are unmanned storage tanks, allow ourcustomer service centers to serve an extended market area. Our customer service locations in Illinois and Indiana also rent 15,000 water softeners and filters, primarily to residential customers in rural areas totreat well water or other problem water. We sell water conditioning equipment and treatment supplies as well. Although the water conditioning portion of ourretail propane business is small, it generates steady year round revenues. The customer bases in Illinois and Indiana for retail propane and water conditioninghave significant overlap, providing the opportunity to cross-sell both products between those customer bases. 17Table of Contents The following table shows the number of our customer service locations and satellite distribution locations by state: Number of CustomerNumber of SatelliteServiceDistributionStateLocationsLocationsIllinois2319Maine1710Georgia113Massachusetts108Kansas527Indiana45Pennsylvania43Connecticut32North Carolina31Oregon21Washington2—Mississippi13New Hampshire11Maryland11Rhode Island11Utah11Wyoming11Colorado1—South Carolina1—Delaware—1New Jersey—1Tennessee—1Vermont—1Total9291 We own 74 of our 92 customer service centers and 63 of our 91 satellite distribution locations, and we lease the remainder. Tank ownership at customer locations is an important component to our operations and customer retention. At March 31, 2014, we owned thefollowing propane storage tanks: · 400 bulk storage tanks with capacities ranging from 2,000 to 90,000 gallons; and · 300,000 stationary customer storage tanks with capacities ranging from 7 to 30,000 gallons. We also lease an additional 20 bulk storage tanks. At March 31, 2014, we owned a fleet of 370 bulk delivery trucks, 40 semi-tractors, 40 propane transport trailers and 480 other service trucks. Retail deliveries of propane are usually made to customers by means of our fleet of bulk delivery trucks. Propane is pumped from the bulk 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 30 to 1,000 gallons.We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 25 gallons. These cylinders are typically picked upon a delivery route, refilled at our customer service locations, and then returned to the retail customer. Customers can also bring the cylinders to our customerservice centers to be refilled. 18Table of Contents Approximately 73% of our residential customers receive their propane supply via our automatic route delivery program, which allows us to maximizeour delivery efficiency. For these customers, our delivery forecasting software system utilizes a customer’s historical consumption patterns combined withcurrent weather conditions to more accurately predict the optimal time to refill the customer’s 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 providing 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,and price cap programs, further promote our automatic delivery program. Customers. Our retail propane and distillate customers fall into three broad categories: residential, agricultural, and commercial and industrial. AtMarch 31, 2014, our retail propane and distillate customers were comprised of: · 71% residential customers; · 28% commercial and industrial customers; and · 1% agricultural customers. No single customer accounted for more than 1% of our retail propane volumes during the year ended March 31, 2014. Seasonality. The retail propane and distillate business is largely seasonal due to the primary use of propane and distillates as heating fuels. 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 25 to 65 miles, although in certain areas the marketing radius may be extended by satellite distribution locations. The ability to compete effectively depends on the ability to provide superior customer service, which includes reliability of supply, 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 offers a higher level of service to our customers. We also believe that our overall service capabilities andcustomer responsiveness differentiate us from many of our competitors. 19Table of Contents Supply. Our retail propane segment purchases the majority of its propane from our liquids segment. Pricing Policy. Our pricing policy is an essential element in the successful marketing of retail propane and distillates. We protect our margin 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 liquids business, combined with our propane and distillate pricing methodsallows 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 · 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 Gas, Osterman, Pacer,Downeast Energy, Allied Propane, Lessig Oil and Propane, and Proflame, among others. We typically retain and continue to use the names of the companiesthat we acquire and believe that this helps maintain the local identification of these companies and contributes to their continued success. We regard ourtrademarks, trade names, and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products. Refined Products Overview. Our refined products marketing business purchases gasoline and diesel fuel primarily from eight suppliers and typically sells theseproducts in back-to-back contracts to over 300 customers at a nationwide network of third-party owned terminaling and storage facilities. We lease 175,000barrels of refined products storage on a third-party pipeline. Customers. Our customers include convenience stores, petroleum-related transportation companies and railroad companies, among others.Approximately 41% of the revenues from our refined products segment during the year ended March 31, 2014 related to our ten largest customers of thesegment. Competition. We face significant competition, as many entities are engaged in the refined products business, some of which are larger and havegreater financial resources than we do. The primary factors on which we compete are: · price; · availability of supply; · level and quality of service; · available space on common carrier pipelines; · the availability of railcars; · proprietary terminals; and 20Table of Contents · obtaining and retaining customers. Supply. We obtain refined products primarily from eight suppliers, which consist primarily of large energy and petrochemicals companies. Pricing Policy. Most of our contracts to purchase or sell refined products are at floating prices that are indexed to published rates in active markets.We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financialderivatives. Billing and Collection Procedures. Our refined products customers consist primarily of large energy and petrochemicals companies. We typicallyinvoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures onour refined products customers. We believe the following procedures enhance our collection efforts with our refined products customers: · we require certain customers to prepay or place deposits for our services; · we require certain customers to post letters of credit on a portion of our receivables; · we review receivable aging analyses regularly to identify issues or trends that may develop; and · we require our sales personnel to manage their customers’ receivable position and tie a portion of our sales personnel’s compensation to theirability to manage their accounts and minimize and collect past due balances. Renewables Overview. Our renewables business, including ethanol marketing and biodiesel marketing businesses, purchases ethanol primarily at productionfacilities, and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwestand in Houston, Texas, and transports the product using 40 leased railcars operating primarily in Iowa, Oklahoma, Minnesota, Missouri, and Texas for saleto refiners and blenders. We also transport and market third-party owned ethanol for a service fee. In our ethanol business, we lease and sublease railcars. Welease 2.5 million gallons of biodiesel storage at a facility in Deer Park, Texas and have a terminaling agreement at a facility in Phoenix, Arizona, with aminimum monthly throughput requirement of one million gallons. Customers. Our customers include crude oil refiners and blenders. Approximately 70% of the revenues from our renewables segment during the yearended March 31, 2014 related to our ten largest customers of the segment. Competition. We face significant competition, as many entities are engaged in the renewables business, some of which are larger and have 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 railcars; · proprietary terminals; and · obtaining and retaining customers. Supply. We obtain renewables from production facilities in the Midwest and in Houston, Texas. 21Table of Contents Pricing Policy. Most of our contracts to purchase or sell renewables are at floating prices that are indexed to published rates in active markets. Weseek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives. Billing and Collection Procedures. Our renewables customers consist primarily of crude oil refiners and blenders. We typically invoice thesecustomers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our refinedproducts customers. We believe the following procedures enhance our collection efforts with our renewables customers: · we require certain customers to prepay or place deposits for our services; · we require certain customers to post letters of credit on a portion of our receivables; · we review receivable aging analyses regularly to identify issues or trends that may develop; and · we require our sales personnel to manage their customers’ receivable position and tie a portion of our sales personnel’s compensation to theirability to manage their accounts and minimize and collect past due balances. Employees At March 31, 2014, we had 2,500 full-time employees, of which 2,300 were operational and 200 were general and administrative. Fourteen of ouremployees 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 United States Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price andnon-price controls affecting wellhead sales of natural gas. The Federal Energy Regulatory Commission (“FERC”), which has the authority under the NaturalGas Act to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations forall natural gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or FERC (with respect to theresale of natural gas in interstate commerce), however, could re-impose price controls in the future. Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting, 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. Regulation of the Transportation and Storage of Natural Gas and Oil and Related Facilities. FERC regulates oil pipelines under the InterstateCommerce Act and natural gas pipeline and storage companies under the Natural Gas Act, and Natural Gas Policy Act of 1978 (the “NGPA”), as amended bythe Energy Policy Act of 2005. While this regulation does not currently apply directly to our facilities, it may affect the price and availability of supply andthereby indirectly affect our business. Additionally, contracts we enter into for the transportation or storage of natural gas or oil are subject to FERC regulationincluding reporting or other requirements. In addition, the intrastate transportation and storage of oil and natural gas is subject to regulation by the state inwhich such facilities are located and such regulation can affect the availability and price of our supply and have both a direct and indirect effect on ourbusiness. Anti-Market Manipulation Rules. We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, as amended bythe Energy Policy Act of 2005, which authorizes FERC to impose fines of up to $1,000,000 per day per violation of the Natural Gas Act, the NGPA, or theirimplementing regulations. In addition, the Federal Trade Commission holds statutory authority under the Energy Independence and Security Act of 2007 toprevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,000,000 per violation. Theseagencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The Commodity Futures TradingCommission is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futures markets, including the energyfutures markets. Pursuant to statutory authority, the Commodity Futures Trading Commission has adopted anti-market manipulation regulations that prohibitfraud and price manipulation in the commodity and futures markets. The Commodity Futures 22Table of Contents Trading Commission also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per day per violation or triple the monetary gain tothe violator for violations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reporting requirements thatare designed to facilitate transparency and prevent market manipulation. Maritime Transportation. The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels builtand registered in the United States and owned and manned by United States citizens. Since we engage in maritime transportation through our barge fleetbetween locations in the United States, we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of oursubsidiaries that engage in maritime transportation and for taking any remedial action necessary to insure that no violation of the Jones Act ownershiprestrictions occurs. The Jones Act also requires that all United States-flagged vessels be manned by United States citizens. Foreign-flagged seamen generallyreceive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of United States-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governments subsidize their nations’ shipyards. This results in lowershipyard costs both for new vessels and repairs than those paid by United States-flagged vessel owners. The United States Coast Guard and AmericanBureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance costs forUnited States-flagged operators than for owners of vessels registered under foreign flags of convenience. Environmental Regulation General. Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of 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, there can be no assurance as to the amount or timing of future expenditures for environmentalcompliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. The following is a discussion of the material environmental laws and regulations that relate to our business. Hazardous Substances and Waste. We are subject to various federal, state, and local environmental, health and safety laws and 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 (“RCRA”),the Comprehensive Environmental Response, Compensation and Liability Act (“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. 23Table of Contents 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 United States Environmental Protection Agency (“EPA”), most states administersome or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek toimpose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated withthe production of oil and natural gas, as well as petroleum-contaminated media, are exempt from regulation as hazardous waste under Subtitle C of RCRA.These wastes, instead, are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. It is possible, however, that certainwastes now classified as non-hazardous could be classified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposalrequirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas wastes as “hazardous wastes.” Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results ofoperations 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, RCRA and analogous state laws. Under these laws, we could berequired to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminatedproperty (including contaminated groundwater) or to implement remedial measures to prevent or mitigate future contamination. We are not currently aware ofany facts, events or conditions relating to such requirements that could materially impact our operations or financial condition. Oil Pollution Prevention. Our operations involve the shipment of crude oil by barge through navigable waters of the United States. The Oil PollutionPrevention Act imposes liability for releases of oil from vessels or facilities into navigable waters. If a release of crude oil to navigable waters occurred duringshipment or from a terminal, we could be subject to liability under the Oil Pollution Prevention Act. We are not currently aware of any facts, events, orconditions related to oil spills that could materially impact our operations or financial condition. In 1973, the EPA adopted oil pollution prevention regulationsunder the Clean Water Act. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a SpillPrevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring,distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantitiesinto 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 spillprevention plan, which details how a facility’s operations comply with the requirements. To be in compliance, the facility’s SPCC plan must satisfy all of theapplicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacility piping), inspections andrecords, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We maintain andimplement such plans for our facilities. Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws 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. 24Table of Contents 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. Underground Injection Control. Our underground injection operations are subject to the Safe Drinking Water Act, as well as analogous state lawsand regulations, which establish requirements for permitting, testing, monitoring, record keeping, and reporting of injection well activities, as well as aprohibition against the migration of fluid containing any contaminant into underground sources of drinking water. Any leakage from the subsurface portionsof the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our permits, issuance of fines andpenalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third-parties forproperty damages and personal injuries. 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’ oil and natural gas production is developed from unconventional sources that require hydraulic fracturing aspart of the completion process and our water solutions business treats and disposes of wastewater generated from natural gas production, including productionutilizing hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate gasproduction. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of underground injection andrequire federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of thefluids used in the fracturing process, have been proposed in recent sessions of the United States Congress. Congress will likely continue to consider legislationto amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act’s Underground Injection Control Program and/or torequire disclosure of chemicals used in the hydraulic fracturing process. Federal agencies, including the EPA and the United States Department of the Interior,have asserted their regulatory authority to, for example, study the potential impacts of hydraulic fracturing on the environment, and initiate rulemakings tocompel disclosure of the chemicals used in hydraulic fracturing operations, and establish pretreatment standards for wastewater from hydraulic fracturingoperations. In addition, several states, including Texas, Colorado and California, have also proposed or adopted legislative or regulatory restrictions onhydraulic fracturing, which include additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and/or temporaryor permanent bans on hydraulic fracturing. We expect that scrutiny of hydraulic fracturing activities will continue in the future. Greenhouse Gas Regulation There is a growing concern, both nationally and internationally, about climate change and the contribution of greenhouse gas emissions, mostnotably carbon dioxide, to global warming. In June 2009, the United States House of Representatives passed the ACES Act, also known as the WaxmanMarkey Bill. The ACES Act did not pass the United States Senate, however, and so was not enacted by the 111th Congress. The ACES Act would haveestablished an economy-wide cap on emissions of greenhouse gases in the United States and would have required most sources of greenhouse gas emissions toobtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. More recently, the Climate Protection Act of 2013 was introduced inthe United States Senate in February 2013. The Climate Protection Act of 2013 would introduce a carbon tax on all fossil fuels extracted, manufactured,produced in, or imported into the United States. The bill has not been advanced out of a United States Senate committee. The ultimate outcome of any possiblefuture legislative initiatives is uncertain. In addition, several states have already adopted some legal measures to reduce emissions of greenhouse gases,primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs, although in recentyears some states have scaled back their commitment to greenhouse gas initiatives. On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present 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 permitting rule is currently being reviewed by the United States SupremeCourt with a decision expected by June 2014. The outcome of the litigation is unknown. The EPA’s greenhouse gas regulations could require us to incur coststo reduce emissions of greenhouse gases associated with our operations and also could adversely affect demand for the products that we transport, store,process, or otherwise handle in connection with our services. 25Table of Contents 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 natural gas liquids is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affectthe market for our products and services. If there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business. Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, new climate change regulations 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 (the“NFPA”), Pamphlet Nos. 54 and No. 58, or comparable regulations, which establish a set of rules and procedures governing the safe handling of propane,and Pamphlet Nos. 30, 30A, 31, 385 and 395 which establish rules and procedures governing the safe handling of distillates, such as fuel oil. We believe thatthe policies 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 (“DOT”). Specifically, crude oil pipelines are subject toregulation by the DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Hazardous Liquid Pipeline Safety Act of1979 (“HLPSA”), which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the storage and transportation ofhazardous liquids by and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management ofpipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with suchregulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary ofTransportation. These regulations include potential fines and penalties for violations. The Pipeline Safety Act of 1992 added the environment to the list ofstatutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain “regulatedgathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in highconsequence areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have ahigh population density. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, Congress required mandatory inspections for certainU.S. crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipelinecontrol room management. Railcar Regulation We transport a significant portion of our natural gas liquids and crude oil via rail transportation, and we own and lease a fleet of railcars for 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 United States Coast Guard. In general, weexpect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. However,these expenditures cannot be accurately estimated at this time, but we do not expect them to have a material adverse effect on our business. 26Table of Contents 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, natural gas liquids, refined products, ethanol, and biodiesel that we buy for resale and whether we are able to pass alongcost increases to our customers; · the volume of wastewater delivered to our processing facilities; · disruptions in the availability of crude oil and/or natural gas liquids supply; · our ability to renew leases for storage and railcars; · the effectiveness of our commodity price hedging strategy; · the level of competition from other energy providers; and · prevailing economic conditions. In addition, the actual amount of cash we will have available for distribution also depends on other factors, some of which are beyond our control,including: · the level of capital expenditures we make; · the cost of acquisitions, if any; · restrictions contained in our credit agreement (the “Credit Agreement”), the purchase agreement governing our outstanding 6.65% senior securednotes due 2022 (the “Note Purchase Agreement”), the indenture governing our outstanding 6.875% senior notes due 2021 (the “Indenture”) andother 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. 27Table of Contents 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 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 Credit Agreement, Note Purchase Agreement and Indenture that limit the amount and types of indebtedness that we may incurto finance acquisitions and which may adversely affect our ability to make distributions to our unitholders; · lack of available cash or external capital or limitations on our ability to issue equity to pay for acquisitions; and · possible unwillingness of prospective sellers to accept our common units as consideration and the potential dilutive effect to our 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, we mayhave difficulty in increasing our retail customer base other than through acquisitions. Therefore, while our business strategy includes expanding our existingretail propane operations through internal growth, our ability to grow within the retail propane business will depend principally on acquisitions. We may be subject to substantial risks in connection with the integration and operation of acquired businesses, in particular those businesses 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; 28Table of Contents · 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. 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 Credit Agreement, Note Purchase Agreement and Indenture could adversely affect our business, financial condition, results ofoperations, ability to make distributions to unitholders and the value of our common units. Our Credit Agreement, Note Purchase Agreement and Indenture limit our ability to, among other things: · incur additional debt or issue letters of credit; · redeem or repurchase units; · make certain loans, investments and acquisitions; · incur certain liens or permit them to exist; 29Table of Contents · engage in sale and leaseback transactions; · enter into certain types of transactions with affiliates; · enter into agreements limiting subsidiary distributions; · change the nature of our business or enter into a substantially different business; · merge or consolidate with another company; and · transfer or otherwise dispose of assets. We are permitted to make distributions to our unitholders under our Credit Agreement, Note Purchase Agreement and Indenture as long as no defaultor event 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 Credit Agreement, Note Purchase Agreement and Indenture also contain covenants requiring us tomaintain certain financial ratios. Please read “Item 7 —Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, Sources of Capital and Capital Resource Activities —Long-Term Debt.” The provisions of our Credit Agreement, Note Purchase Agreement and Indenture may affect our ability to obtain future financing and pursueattractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with theprovisions of our Credit Agreement could result in a covenant violation, default or an event of default that could enable our lenders, subject to the terms andconditions of our Credit Agreement, to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due andpayable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral we granted them to secure our debts. If the paymentof our debt is accelerated, defaults under our other debt instruments, if any then exist, may be triggered, and our assets may be insufficient to repay such debtin 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 payments on our debt obligations and cash distributions at our intended levels. Our business depends on the availability of supply of crude oil and natural gas liquids in the United States and Canada, which is dependent onthe ability and willingness of other parties to explore for and produce crude oil and natural gas. Spending on crude oil and natural gasexploration and production may be adversely affected by industry and financial market conditions that are beyond our control including, withoutlimitation, (1) prices for crude oil, condensate, and natural gas liquids, (2) crude oil and natural gas producers having success in theiroperations, (3) continued commercially viable areas in which to explore and produce crude oil and natural gas, (4) the availability of liquids-richnatural gas needed to produce natural gas liquids, and (5) the availability of pipeline transportation and storage capacity. Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business have been, and may 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 as well as the availability of necessary pipeline transportationand storage capacity. Customers’ expectations of lower market prices for oil and natural gas, as well as the availability of capital for operating and capitalexpenditures, may cause them to curtail spending, thereby reducing business opportunities and demand for our services and equipment. Actual marketconditions 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. 30Table of Contents 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. 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. Our profitability could be negatively impacted by price and inventory risk related to our business. The crude oil logistics, liquids, retail propane, refined products, and renewables businesses are “margin-based” businesses in which our realizedmargins depend on the differential of sales prices over our total supply costs. Our profitability is therefore sensitive to changes in product prices caused bychanges in supply, pipeline transportation and storage capacity or other market conditions. Generally, we attempt to maintain an inventory position that is substantially balanced between our purchases and sales, including our future 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 inventory that we have already pre-sold. We are affected by competition from other midstream, transportation, terminaling and storage and retail marketing companies, some of which arelarger and more firmly established and may have greater marketing and development budgets and capital resources than we do. We experience competition in all of our segments. In our liquids segment, we compete for natural gas supplies and also for customers for our services.Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, storeand market natural gas. Our natural gas liquids terminals compete with other terminaling and storage providers in the transportation and storage of natural gasliquids. Natural gas and natural gas liquids also compete with other forms of energy, including electricity, coal, fuel oil and renewable or alternative energy. Our crude oil logistics segment faces significant competition for crude oil supplies and also for customers for our services. These operations also facecompetition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude oil terminals compete with terminals owned byintegrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and tradingoperations. Our water solutions segment is in direct and indirect competition with other businesses, including disposal and other wastewater treatmentbusinesses. We face strong competition in the market for the sale of retail propane. Our competitors vary from retail propane companies who are larger and havesubstantially greater financial resources than we do to small retail propane distributors, rural electric cooperatives and fuel oil distributors who have entered themarket due to a low barrier to entry. The actions of our retail marketing 31Table of Contents competitors, including the impact of imports, could lead to lower prices or reduced margins for the products we sell, which could have an adverse effect onour business or results of operations. Our refined products and renewables segments also face significant competition for refined products and renewables supplies and also for customersfor our services. We can make no assurances that we will be able to compete successfully in each of our lines of business. If a competitor attempts to increase 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. We use third-party common carrier pipelines to transport crude oil and natural gas liquids and we use third-party facilities to store natural gasliquids and ethanol. Any significant interruption in the service at these storage facilities or on the common carrier pipelines we use would adversely affect ourability to obtain propane. Our business would be adversely affected if service on the railroads we use is interrupted. We transport crude oil, natural gas liquids, ethanol, and biodiesel by railcar. We do not own or operate the railroads on which these cars aretransported. Any disruptions in the operations of these railroads could adversely impact our ability to deliver product to our customers. If we are unable to purchase product from our principal suppliers, our results of operations would be adversely affected. If we are unable to purchase product from significant suppliers, our failure to obtain alternate sources of supply at competitive prices and on a timelybasis would adversely affect our ability to satisfy customer demand, reduce our revenues and adversely affect our results of operations. The fees charged to customers under our agreements with them for the transportation and marketing of crude oil, condensate, natural gasliquids, refined products, ethanol, and biodiesel may not escalate sufficiently to cover increases in costs and the agreements may be suspended insome circumstances, which would affect our profitability. Our costs may increase at a rate greater than the rate that the fees that we charge to customers increase pursuant to our contracts with them.Additionally, some customers’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events,some of which are beyond our control, including force majeure events wherein the supply of crude oil, condensate, and/or natural gas liquids are curtailed 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, natural gas liquids, refined products, ethanol, and biodiesel and related transportation and hedging activities,and our processing of wastewater, expose us to potential regulatory risks. The Federal Trade Commission (“FTC”), the Federal Energy Regulatory Commission (“FERC”), and the Commodity Futures Trading Commission(“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed 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 the FERC regulation or we become subject to the FERC regulation ourselves (see —“Some of our operations couldbecome subject to the jurisdiction of the FERC,” below), we will be obligated to comply with the FERC’s regulations and policies. Any failure on our part tocomply with the FERC’s regulations and policies at that time could result in the imposition of civil and criminal penalties. Failure to comply with suchregulations, as interpreted and enforced, could have a material and adverse effect on our business, results of operations and financial condition. The intrastate transportation or storage of natural gas or crude oil is subject to regulation by the state in which the facilities and transactions occurand requires compliance with all such regulation. This state regulation can have a material and adverse effect on that portion of our business, results ofoperations and financial condition. 32Table of Contents 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 clearing and cash collateral requirements for commercial end users and itincludes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and the parties to thosetransactions. Since the Dodd-Frank Act mandates the CFTC to promulgate rules to define these terms, we do not know the definitions the CFTC will actuallyadopt or how these definitions will apply to us. Although the CFTC established position limits on certain core futures and equivalent swaps contracts, withexceptions for certain bona fide hedging transactions, those limits were vacated by a federal district court on September 28, 2012, and will not go into effectuntil the CFTC prevails on appeal of this ruling, or issues and finalizes revised rules. Additionally, in December 2012, the CFTC published finalrules regarding mandatory clearing of four classes of interest rate swaps and two classes of credit swaps and setting compliance dates of March 11, 2013,June 10, 2013, and, for end users of swaps, September 9, 2013. The full impact of the Dodd-Frank Act on our hedging activities is uncertain at this time.However, new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post collateralwhich could adversely affect our available liquidity), materially alter the terms of derivative contracts, reduce the availability of derivatives to protect againstrisks that we encounter, reduce our ability to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthycounterparties. The Dodd-Frank Act may also materially affect our customers and materially and adversely affect the demand for our services. We are subject to the trucking safety regulations, which are likely to be amended, and made stricter, as part of the initiative known asComprehensive, Safety, Analysis (“CSA”). If our current United States Department of Transportation (“DOT”) safety ratings are downgraded to“Unsatisfactory” or the equivalent in connection with this initiative, our business and results of our operations may be adversely affected. As part of the CSA initiative, the Federal Motor Carrier Safety Administration (“FMCSA”) is expected to open a rulemaking docket for purposes 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 (“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. 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, natural gas liquids, refinedproducts, ethanol, and biodiesel. For instance, our wastewater treatment and transportation business carries with it environmental risks, including leakagefrom the treatment plants to surface or subsurface soils, surface water or groundwater, or accidental spills or releases during the transport of wastewater. Ourcrude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel businesses carry similar risks of leakage and sudden or accidental spillsof crude oil, condensate, natural gas liquids, and hydrocarbons. Liability under, or violation of, environmental laws and regulations could result in, amongother things, the impairment or cancellation of operations, injunctions, fines and penalties, reputational damage, expenditures for remediation and liability fornatural resource damages, property damage and personal injuries. We use various modes of transportation to carry propane, distillates, crude oil and water, including trucks, railcars and barges, each of which 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 theDOT. We also own and lease a fleet of railcars, the operation of which is subject to the regulatory jurisdiction of the Federal Railroad Administration of theDOT, as well as other federal and state regulatory agencies. In response to recent train derailments occurring in the United States and Canada in 2013, UnitedStates regulators are implementing or considering new rules to address the safety risks of transporting crude oil by rail. On January 23, 2014, the NationalTransportation Safety Board issued a series of recommendations to address safety risks, and on February 25, 2014 the DOT issued an emergency orderrequiring all persons, prior to offering petroleum crude oil into transportation, to ensure such product 33Table of Contents is properly tested and classed. The introduction of these or other regulations that result in new requirements addressing the type, design, specifications orconstruction of railcars used to transport crude oil could result in severe transportation capacity constraints during the period in which new railcars areretrofitted or constructed to meet new specifications. Our barge transportation operations, which we acquired in 2012, are subject to the Jones Act, a federal lawrestricting marine transportation in the United States to vessels built and registered in the United States, and manned and owned by United States citizens, aswell as rules and regulations of the United States Coast Guard. Non-compliance with any of these regulations could result in increased costs related to thetransportation 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 effect on our operations and financial performance. Furthermore, our customers in the oil and gas production industry are subject to certain environmental laws and regulations that may 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 EPA issued final rules that established new air emission controls for oil and gas production and gas processing operations. Thefinal rule includes a 95% reduction in volatile organic compounds (“VOCs”) (which contribute to smog) emitted during the completion of new and modifiedhydraulically fractured wells. In August 2013, the EPA updated its 2012 air emission standards for crude oil and natural gas storage tanks to extend thecompliance date and allow an alternate emissions limit of less than 4 tons per year without emission controls. Any significant increased costs or restrictionsplaced on our customers to comply with environmental laws and regulations could affect their production output significantly. Such an effect could materiallyand adversely affect our utilization and profitability, thus reducing demand for our midstream services. Such an effect on our customers could materially andadversely affect our utilization and profitability. The adoption or implementation of any new regulations imposing additional reporting obligations ongreenhouse gas emissions, or limiting greenhouse gas emissions from our equipment and operations, could require us to incur significant costs. Federal and state legislation and regulatory initiatives relating to our hydraulic fracturing customers could result in increased costs 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 solutions 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. In addition, some have asserted that the fracturing process and/or the wastewater disposal process could result in increased seismicactivity. New laws or regulations, or changes to existing laws or regulations in response to this perceived threat may unfavorably impact the oil and gas drillingindustry. For instance, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices involving the use of diesel fuel under theSafe Drinking Water Act and its Underground Injection Control program. In February 2014, the EPA issued technical guidance for the permitting of theunderground injection of diesel fuel for hydraulic fracturing activities. The EPA has also commenced a study of the potential environmental impact ofhydraulic fracturing activities, the final results of which are expected in 2014. In addition, the United States 34Table of Contents Department of the Interior published a revised proposed rule on May 16, 2013 that would update existing regulation of hydraulic fracturing activities onfederal lands, including requirements for disclosure, well bore integrity and handling of flowback water. Also, legislation has been introduced, but notadopted, in Congress to provide for federal regulation of hydraulic fracturing. In addition, some states have adopted and other states are considering adoptingregulations that could restrict or regulate hydraulic fracturing in certain circumstances. For example, some states have adopted legislation requiring thedisclosure of hydraulic fracturing chemicals, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legalproceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. We cannot predict whether anyproposed federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require or prohibit. However,any restrictions on hydraulic fracturing could lead to operational delays or increased operating costs and regulatory burdens that could make it more difficultor costly to perform hydraulic fracturing which would negatively impact our customer base resulting in an adverse effect on our profitability. Seasonal weather conditions and natural or man-made disasters could severely disrupt normal operations and have an adverse effect on 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 railcars 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 products and cause serious shortages in various areas, including the areas in which we operate. These same conditions may cause seriousdamage or destruction to homes, business structures and the operations of customers. Such disruptions could potentially have a material adverse impact onour business, financial condition, results of operations and cash flows. Risk management procedures cannot eliminate all commodity risk, basis risk, or risk of adverse market conditions which can adversely affect ourfinancial condition and results of operations. In addition, any non-compliance with our risk policy could result in significant financial losses. Pursuant to the requirements of our market risk policy, we attempt to lock in a margin for a portion of the commodities we purchase by selling suchcommodities for physical delivery to our customers, such as independent refiners or major oil companies, or by entering into future delivery obligations undercontracts for forward sale. Through these transactions, we seek to maintain a position that is substantially balanced between purchases on the one hand, andsales or future delivery obligations on the other hand. These policies and practices cannot, however, eliminate all risks. For example, any event that disruptsour anticipated physical supply of commodities could expose us to risk of loss resulting from the need to cover obligations required under contracts forforward 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 timing differentials are components ofbasis risk. In a backwardated market (when prices for future deliveries are lower than current prices), basis risk is created with respect to timing. In theseinstances, physical inventory generally loses value as price of such physical inventory declines over time. Basis risk cannot be entirely eliminated, and basisexposure, particularly in backwardated or other adverse market conditions, can adversely affect our financial condition and results of operations. The counterparties to our commodity derivative and physical purchase and sale contracts may not be able to perform their obligations to us, whichcould materially affect our cash flows and results of operations. We encounter risk of counterparty non-performance in our businesses. Disruptions in the supply of product and in the oil and gas commoditiessector overall for an extended or near term period of time could result in counterparty defaults on our derivative and physical purchase and sale contracts. Thiscould impair our ability to obtain supply to fulfill our sales delivery commitments or obtain supply at reasonable prices, which could result in decreased grossmargins and profitability, thereby impairing our ability to make payments on our debt obligations or distributions to our unitholders. Our use of derivative financial instruments could have an adverse effect on our results of operations. We have used derivative financial instruments as a means to protect against commodity price risk or interest rate risk and expect to continue to do so.We may, as a component of our overall business strategy, increase or decrease from time to time our use of such derivative financial instruments in the future.Our use of such derivative financial instruments could cause us to forego the economic benefits we would otherwise realize if commodity prices or interest rateswere to change in our favor. In addition, although 35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 payments on our debt obligations or distributions to our unitholders. Some of our operations could become subject to the jurisdiction of the FERC. Any of our transportation services could in the future become subject to the jurisdiction of the FERC, which could adversely affect the terms ofservice, rates and revenues of such services. At the date of this Annual Report, our facilities do not fall under the FERC’s jurisdiction. Currently, the FERCregulates crude oil and natural gas pipelines, among other things. Intrastate transportation and gathering pipelines that do not provide interstate services are notsubject to regulation by the FERC. However, the distinction between the FERC-regulated interstate pipeline transportation on the one hand and intrastatepipeline transportation on the other hand, is a fact-based determination. The classification and regulation of our crude oil pipelines are subject to change basedon future determinations by the FERC, federal courts, Congress or regulatory commissions, courts or legislatures in the states in which we operate. GlassMountain Pipeline, LLC (“Glass Mountain”), one of our joint ventures, owns a pipeline in Oklahoma that carries crude oil owned by us and by third parties.We believe that the pipeline segments on which Glass Mountain would provide service to third parties and the services it would provide to third parties on thispipeline system meet the traditional tests that the FERC has used to determine that the pipeline services provided are not in interstate commerce. However, wecannot provide assurance that the FERC will not in the future, either at the request of other entities or on its own initiative, determine that some or all of thepipeline and the services Glass Mountain will provide on that system are within its jurisdiction, or that such a determination would not adversely affect GlassMountain’s or our results of operations. Further, if the FERC’s regulatory reach was expanded to our other facilities, or if we expand our operations into areasthat are subject to the FERC’s regulation, we may have to commit substantial capital to comply with such regulations and such expenditures could have amaterial and adverse effect on our results of operations and cash flows. Volumes of crude oil recovered during the wastewater treatment process can vary. Any significant reduction in residual crude oil content 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. 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 36Table of Contents reduce demand for propane. In addition, if the price of propane increases, some of our customers may increase their conservation efforts and thereby decreasetheir consumption of propane. 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. Reduced demand for refined products could have an adverse effect our results of operations. Any sustained decrease in demand for refined products in the markets we serve could reduce our cash flow. Factors that could lead to a decrease inmarket demand include: · a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel; · higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline; · an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technologicaladvances by manufacturers; · an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drivedemand for alternative products; and · the increased use of alternative fuel sources, such as battery-powered engines. Recent attempts to reduce or eliminate the Renewable Fuels Standard, if successful, could unfavorably impact our results of operations. The United States renewables industry is highly dependent on several federal and state incentives which promote the use of renewable fuels. Withoutthese incentives, demand for and the price of renewable fuels could be negatively impacted which could have an adverse effect on our results of operations.The most significant of the federal and state incentives which benefit renewable products we market, such as ethanol and biodiesel, is the federal RenewableFuels Standard (“RFS”). The RFS requires that an increasing amount of renewable fuels must be blended with petroleum-based fuels each year in the UnitedStates. However, the EPA has authority to waive the requirements of the RFS, in whole or in part, provided one of two conditions is met. The conditions are:(1) there is inadequate domestic renewable fuel supply; or (2) implementation of the requirement would severely harm the economy or environment of a state,region or the United States. Opponents of the RFS are seeking to force the EPA to reduce or eliminate the RFS. Further, several pieces of legislation have beenintroduced with the goal of significantly reducing or eliminating the RFS. While the outcome of these legislative efforts is uncertain, it is possible that the EPAcould adjust the RFS requirements in the future. If the EPA were to adjust the RFS requirements in any material way, it could negatively impact demand forthe renewable fuel products we market, which could unfavorably impact our results of operations. A loss of one or more significant customers could materially or adversely affect our results of operations. Approximately 37% of the revenues of our water solutions segment during the year ended March 31, 2014 were generated from our two largestcustomers of the segment. Approximately 60% of the revenues of our crude oil logistics segment during the year ended March 31, 2014 were generated from ourten largest customers of the segment. Approximately 35% of the revenues of our liquids segment were generated from our ten largest customers of the segment.Approximately 41% of the revenues of our refined products segment were generated from our ten largest customers of the segment. Approximately 70% of therevenues of our renewables segment were generated from our ten largest customers of the segment. For the year ended March 31, 2014, sales of crude oil andnatural gas liquids to our largest customer represented 10% of our consolidated total revenues. We expect to continue to depend on key customers to support ourrevenues for the foreseeable future. The loss of key customers, failure to renew contracts 37Table of Contents upon expiration, or a sustained decrease in demand by key customers could result in a substantial loss of revenues and could have a material and adverseeffect on our results of operations. Certain of our operations are conducted through joint ventures which have unique risks. Certain of our operations are conducted through joint ventures. With respect to our joint ventures, we share ownership and managementresponsibilities with partners that may not share our goals and objectives. Differences in views among the partners may result in delayed decisions or failuresto agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others.Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture.Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business andoperations. From time to time, our joint ventures may be involved in disputes or legal proceedings which may negatively affect our investments. Accordingly,any such occurrences could adversely affect our financial condition, operating results and cash flows. Growing our business by constructing new transportation systems and facilities subjects us to construction risks and risks that supplies for 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 terminaling,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 self-insured retention amounts which we would have to pay in fullbefore obtaining any insurance proceeds to satisfy a judgment or settlement and we may have insufficient reserves on our balance sheet to satisfy such self-retention obligations. Furthermore, even where the claim is covered by our insurance, our insurance coverage might be inadequate and we would have to paythe amount of any settlement or judgment that is in excess of our policy limits. We may not be able to obtain insurance on terms acceptable to us or at all sinceinsurance varies in cost and can be difficult to obtain. Our failure to maintain adequate insurance coverage or successfully defend against product liabilityclaims could materially and adversely affect our business, results of operations, financial condition and cash flows. A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our 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 financialresults could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tamperingwith or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk related to operational systemflaws, and employee tampering or manipulation of those systems will result in losses that are difficult to detect. Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use 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 38Table of Contents operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have anadverse effect on our financial results. We do not own all of the land on which our facilities are located, and instead lease certain facilities and equipment, and we, therefore, are 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 ourrailcars. 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 United States Bureau of LandManagement for the rights of way on which our pipelines are constructed and the Wyoming State Engineer’s Office for water well, disposal well andcontainment pits. Difficulty in attracting and retaining qualified drivers could adversely affect our growth and profitability. Maintaining a staff of qualified truck drivers is critical to the success of our operations. We have in the past experienced difficulty in attracting andretaining sufficient numbers of qualified drivers. In addition, due in part to current economic conditions, including the cost of fuel, insurance, and tractorsand the DOT regulatory requirements, the available pool of qualified truck drivers has been declining. Regulatory requirements, including the FMCSA’s CSAinitiative, and an improvement in the economy could reduce the number of eligible drivers or require us to pay more to attract and retain drivers. A shortage ofqualified drivers and intense competition for drivers from other companies will create difficulties in increasing the number of our drivers for our anticipatedexpansion in our fleet of trucks. If we are unable to continue to attract and retain a sufficient number of qualified drivers, we could have difficulty meetingcustomer demands, any of which could materially and adversely affect our growth and profitability. If we fail to maintain an effective system of internal controls, including internal controls over financial reporting, we may be unable to report ourfinancial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units. We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). We are also subject tothe obligation under Section 404(a) of the Sarbanes Oxley Act of 2002 to annually review and report on our internal control over financial reporting, and to theobligation under Section 404(b) of the Sarbanes Oxley Act to engage our independent registered public accounting firm to attest to the effectiveness of ourinternal 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. These risks may be heightened after a business combination, during the phase when we areimplementing our internal control structure over the recently-acquired business. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or 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 could 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. An impairment of goodwill and intangible assets could reduce our earnings. At March 31, 2014, we had reported goodwill and intangible assets of $1.8 billion. Such assets are subject to impairment reviews on an annualbasis, or at an interim date if information indicates that such asset values have been impaired. Any impairment we would be required to record in our financialstatements would result in a charge to our income, which would reduce our earnings. 39Table of Contents Our business requires extensive credit risk management that may not be adequate to protect against customer non-payment. Our credit management procedures may not fully eliminate the risk of non-payment by our customers. We manage our credit risk exposure throughcredit analysis, credit approvals, establishing credit limits, requiring prepayments (partially or wholly), requiring product deliveries over defined timeperiods, and credit monitoring. While we believe our procedures are effective, we can provide no assurance that bad debt write-offs in the future may not besignificant and any such non-payment problems could impact our results of operations and potentially limit our ability to make payments on our debtobligations or distributions to our unitholders. Our terminaling operations depend on pipelines to transport crude oil and natural gas liquids. We own 22 natural gas liquids terminals and seven crude oil terminals. These facilities depend on pipeline and storage systems that are owned 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. Our marketing operations depend on the availability of transportation and storage capacity. Our product supply is transported and stored on facilities owned and operated by third parties. Any interruption of service on the pipeline or storagecompanies or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, totransport natural gas and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines fortransportation affects the profitability of our operations. The financial results of our natural gas liquids businesses are seasonal and generally lower in the first and second quarters of our fiscal year,which may require us to borrow money to make distributions to our unitholders during these quarters. The natural gas liquids inventory we have pre-sold to customers is highest during summer months, and our cash receipts are lowest during 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. Some of our operations cross the United States/Canada border and are subject to cross-border regulation. Our cross-border activities subject us to regulatory matters, including import and export licenses, tariffs, Canadian and United States customs andtax issues and toxic substance certifications. Such regulations include the “Short Supply Controls” of the Export Administration Act, the North American FreeTrade Agreement 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. The risk of terrorism and political unrest in various energy producing regions may adversely affect the economy and the price and availability ofproducts. 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. Terrorist attacks in the areas of ouroperations could negatively impact our ability to transport propane to our locations. These risks could potentially negatively impact our results of operations. 40Table of Contents 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 (“Delaware LP Act”), provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary dutiesowed by the general partner to limited partners and the partnership. Our partnership agreement contains provisions that reduce the standards to which ourgeneral partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement: · limits the liability and reduces the fiduciary duties of our general partner, while also restricting the remedies available to our unitholders 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 41Table of Contents our general partner that might otherwise be breaches of fiduciary duty,” above). The risk to our unitholders due to such conflicts may arise because of thefollowing 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; · 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 incentive distributions; · our partnership agreement permits us to classify up to $20.0 million as operating surplus, even if it is generated from asset sales, non-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 42Table of Contents any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of anyfiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity toanother person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between usand affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Even if our unitholders are dissatisfied, they have limited voting rights and are not entitled to elect our general partner or its directors. Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore,limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our 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 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 orreduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings orto acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management. Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units. Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20%or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved 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 10 anniversary of the closing date of our IPO, a transfer of incentive distribution rights(“IDRs”) by our general partner requires (except in certain limited circumstances) the consent of a majority of our outstanding common units (excludingcommon units held by our general partner and its affiliates). However, after the expiration of this period, our general partner may transfer its IDRs to a thirdparty at any time without the consent of our unitholders. If our general partner transfers its IDRs to a third party but retains its general partner interest, ourgeneral partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it hadretained ownership of its IDRs. Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price. If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it 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. 43thTable of Contents 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 to fund our acquisitions and expansioncapital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability togrow. 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 Credit Agreement on our ability to issue additional units, including units ranking senior to the common units.The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn,may impact the available cash that we have to distribute to our unitholders. We may issue additional units without the approval of our unitholders, which would dilute the interests of existing unitholders. Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of 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 IDRs at thehighest level to which it is entitled (48.1%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levelsbased on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distributionwill be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based onpercentage 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 44Table of Contents their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on theIDRs in the prior two quarters. We anticipate that our general partner would exercise this reset right to facilitate acquisitions or internal growth projects thatwould not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner couldexercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may,therefore, desire to be issued common units rather than retain the right to receive distributions on its IDRs based on the initial target distribution levels. As aresult, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders wouldhave otherwise received had we not issued new common units and general partner interests to our general partner in connection with resetting the targetdistribution levels. Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business. A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of 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 Internal Revenue Service (“IRS”) were to treat us as a corporationfor federal income tax purposes, our cash available for distribution to our unitholders would be substantially reduced. The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federalincome tax purposes. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal incometax 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 of 1986, as amended (the “Code”). “Qualifying income” includes income and gains derived from the exploration, development, production, processing,transportation, storage and marketing of natural gas, natural gas products, and crude oil or other passive types of income such as certain interest anddividends and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income.Although we do not believe based upon our current operations that we are treated as a corporation, we could be treated as a corporation for federal income taxpurposes or otherwise subject to taxation as an entity if our gross income is not properly classified as qualifying income, there is a change in our business orthere is a change in current law. 45Table of Contents 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. 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 United States Congress propose and considersubstantive changes to the existing United States federal income tax laws that affect the tax treatment of publicly traded partnerships. Members of Congresshave recently proposed substantive changes to the existing U.S. tax laws that would affect certain publicly traded partnerships, if such proposals are enactedinto law. We are unable to predict whether any such change or other proposals will ultimately be enacted or will affect our tax treatment. Any modification to theincome tax laws and interpretations thereof may or may not be applied retroactively and could, among other things, cause us to be treated as a corporation forfederal income tax purposes or otherwise subject us to entity-level taxation. Moreover, such modifications and change in interpretations may affect or cause usto change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income andadversely affect an investment in our common units. Although we are unable to predict whether any of these changes, or other proposals, will ultimately beenacted, any such changes could negatively impact the value of an investment in our common units. If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any 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 we expect to be treated as a partnership for United States federal income tax purposes, our unitholders will be treated as partners to whom wewill allocate taxable income that could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxes and,in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may notreceive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. Tax gain or loss on the disposition of our common units could be more or less than expected. If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis 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 46Table of Contents units the unitholder sells will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, evenif the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or notrepresenting gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realizedincludes a unitholder’s share of our nonrecourse liabilities, if a unitholder sell units, they may incur a tax liability in excess of the amount of cash they receivefrom the sale. Tax-exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse taxconsequences to them. 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-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations thatare exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons willbe required to file United States federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-UnitedStates person, you should consult your tax advisor before investing in our common units. We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS 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 United States federal income tax purposes between transferors and transferees ofour units each month based on the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit 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 United States 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 affect 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 47Table of Contents the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assuretheir status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable tomodify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. We have adopted certain valuation methodologies and monthly conventions for United States federal income tax purposes that may result in a shiftof income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which couldadversely affect the value of our common units. When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate 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 Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challengeour valuation methods, or our allocation of the Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxableincome, 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. There are limits on the deductibility of our losses that may adversely affect our unitholders. There are a number of limitations that may prevent unitholders from using their allocable share of our losses as a deduction against unrelated income.In cases where our unitholders are subject to the passive loss rules (generally, individuals and closely-held corporations), any losses generated by us will onlybe available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unusedlosses may be deducted when the unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A unitholder’s shareof our net passive income may be offset by unused losses from us carried over from prior years but not by losses from other passive activities, includinglosses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by a unitholder include the at-riskrules and the prohibition against loss allocations in excess of the unitholder’s tax basis in its units. Purchasers of our common units may become subject to state and local taxes and return filing requirements in jurisdictions where we operate 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. 48Table of Contents 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 restrictions, we do not believe that any of these burdens will materially interfere with ourcontinued use of these properties in our business, taken as a whole. Our obligations under our credit facilities are secured by liens and mortgages onsubstantially 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 and Houston, Texas. For additional information regarding our properties and the reportable segments in which they are used, see “Item 1 — Business.” Item 3. Legal Proceedings We are involved from time to time in various legal proceedings and claims arising in the ordinary course of business. For information related to 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, which information is incorporated by reference into this Item 3. Item 4. Mine Safety Disclosures Not Applicable. 49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 New York Stock Exchange (“NYSE”) under the symbol “NGL.” Our common units began trading on theNYSE on May 12, 2011. Prior to May 12, 2011, our common units were not listed on any exchange or traded in any public market. At May 23, 2014, there were 239 common unitholders of record. This number does not include unitholders for whom common units may be held in“street name.” We have also issued 5,919,346 subordinated units, for which there is no established public trading market. All of the subordinated units areheld 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 RangeCash2014 Fiscal YearHighLowDistributionFourth Quarter$37.72$33.45$0.5313Third Quarter34.5030.430.5113Second Quarter33.7328.210.4938First Quarter30.3726.650.4775 Price RangeCash2013 Fiscal YearHighLowDistributionFourth Quarter$26.90$22.64$0.4625Third Quarter25.1621.260.4500Second Quarter26.6722.110.4125First Quarter23.5020.150.3625 Cash Distribution Policy Available Cash Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in ourpartnership agreement) to unitholders of record on the applicable record date. Available cash, for any quarter, generally consists of all cash on hand at the endof that quarter less the amount of cash reserves established by our general partner to (i) provide for the proper conduct of our business, (ii) comply withapplicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for anyone 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 which we expect to occur in August 2014. The subordination period will also terminate automatically if thegeneral 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 subordinationperiod lapses or otherwise terminates, all 50Table of Contents remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages. General Partner Interest Our general partner is entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but 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 (“IDRs”) which represent a variable interest in our distributions. IDRs entitle ourgeneral partner to receive increasing percentages, up to a maximum of 48.1%, of the cash we distribute from operating surplus (as defined in our partnershipagreement) in excess of $0.388125 per unit per quarter. The maximum distribution of 48.1% includes distributions paid to our general partner on its 0.1%general partner interest and assumes that our general partner maintains its general partner interest at 0.1%. The maximum distribution of 48.1% does notinclude any distributions that our general partner may receive on common units or subordinated units that it owns. Restrictions on the Payment of Distributions As described in Note 8 to our consolidated financial statements included in this Annual Report, our Credit Agreement contains covenants limiting ourability to pay distributions if we are in default under the Credit Agreement and to pay distributions that are in excess of available cash, as defined in the CreditAgreement. Sales of Unregistered Securities During the fiscal year ended March 31, 2014, we completed three acquisitions in which we issued unregistered common units as part of theconsideration for the acquisitions. All of these units were issued in reliance upon the exemption from registration provided by Section 4(a)(2) of the SecuritiesAct, as the units were issued to the owners of businesses acquired in privately negotiated transactions not involving any public offering or solicitation. OnJuly 1, 2013, we issued 175,211 common units to the sellers of Crescent Terminals, LLC and Cierra Marine, LP. On August 1, 2013, we issued 2,463,287common units to the sellers of entities affiliated with Oilfield Water Lines, LP. On September 3, 2013, we issued 222,381 common units to the sellers ofCoastal Plains Disposal #1, LLC. On October 16, 2013, we completed the sale to a group of financial institutions, for which RBC Capital Markets, LLC acted as representative(collectively, the “Initial Purchasers”), of $450.0 million aggregate principal amount of 6.875% Senior Notes due 2021 (the “Unsecured Notes”) of thePartnership and its subsidiary NGL Energy Finance Corp. (collectively, the “Issuers”). The Initial Purchasers resold the Unsecured Notes to qualifiedinstitutional buyers pursuant to Rule 144A under the Securities Act, and to persons outside of the United States pursuant to Regulation S under the SecuritiesAct. The Unsecured Notes were sold at par, and the Issuers received approximately $439.4 million of net proceeds from the sale of the Unsecured Notes. On December 2, 2013, we issued and sold 8,110,848 common units in a private placement at a price of $29.59 per common unit for aggregateconsideration of $240.0 million. This sale of common units was made in reliance upon an exemption from the registration requirements of the Securities Act of1933, as amended, pursuant to Section 4(a)(2) thereof, as a transaction by an issuer not involving any public offering. Securities Authorized for Issuance Under Equity Compensation Plans In connection with the completion of our initial public offering, our general partner adopted the NGL Energy Partners LP Long-Term Incentive Plan.Please see “Item 12 — Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters — Securities Authorized 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 51Table of Contents formation. The following table shows selected historical financial and operating data for NGL Energy Partners LP and NGL Supply (the deemed acquirer foraccounting purposes in our formation) for the periods and as of the dates indicated. The financial statements of NGL Supply became our historical financialstatements for all periods prior to October 1, 2010. The following table should be read in conjunction with “Item 7 — Management’s Discussion and Analysisof Financial Condition and Results of Operations” and the financial statements and related notes included in this Annual Report. The selected consolidated historical financial data (excluding volume information) at March 31, 2014 and 2013 and for each of the three years in theperiod ended March 31, 2014 are derived from our audited historical consolidated financial statements included in this Annual Report. The selectedconsolidated historical financial data (excluding volume information) at March 31, 2012 and 2011 and for the six months ended March 31, 2011 are derivedfrom our financial records. The selected consolidated historical financial data (excluding volume information) at September 30, 2010 and for the six monthsthen ended and at March 31, 2010 and for the year then ended are derived from the financial records of NGL Supply. 52Table of Contents NGL Energy Partners LPNGL Supply, Inc.Six Months EndedSix Months EndedYear EndedYear Ended March 31,March 31,September 30,March 31,201420132012201120102010(in thousands, except per unit data)Income Statement Data (1)Total revenues$9,699,274$4,417,767$1,310,473$622,232$316,943$735,506Total cost of sales9,132,6994,039,1101,217,023583,032310,908708,215Operating income (loss)106,56587,30715,03014,837(3,795)6,661Interest expense58,85432,9947,6202,482372668Loss on early extinguishment of debt—5,769————Net income (loss) attributable to parent equity47,65547,9407,87612,679(2,515)3,636Basic and diluted earnings per common unit0.510.960.321.16Basic earnings (loss) per common share(128.46)178.75Diluted earnings (loss) per common share(128.46)176.61Cash Flows Data (1)Cash flows from operating activities$85,236$132,634$90,329$34,009$(30,749)$7,480Cash distributions paid per common unit (subsequent to IPO)2.011.690.85Cash distributions per common unit (prior to IPO)0.35—Cash distributions paid per common share357.09—Capital expenditures:Purchases of long-lived assets165,14872,4757,5441,440280582Acquisitions of businesses, including additional considerationpaid on prior period acquisitions1,268,810490,805297,40117,4001233,113Balance Sheet Data - Period End (1)Total assets$4,167,223$2,291,618$749,519$163,833$148,596$111,580Total long-term obligations, exclusive of current maturities1,639,578742,641199,38965,93618,9408,851Redeemable preferred stock—————3,000Total equity1,531,853889,418405,32947,35336,81146,403Volume Information (1)Retail propane and distillates sold (gallons)197,326173,23279,88634,9323,74715,514Wholesale propane sold (gallons) (2)1,190,106912,625659,921372,504226,330623,510Wholesale other products sold (gallons)786,671505,529134,99949,46546,09253,878Crude oil sold (barrels)46,10724,373————Water delivered (barrels)62,77425,009————Refined products sold (gallons)412,974—————Renewables sold (gallons)150,925————— (1) The acquisitions of businesses affect the comparability of this information. (2) Includes intercompany volumes sold to our retail propane segment. 53Table of Contents Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Overview We are a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. As part of ourformation, we acquired and combined the assets and operations of NGL Supply, which was primarily a wholesale propane and terminaling business that wasfounded in 1967, and Hicksgas, which was primarily a retail propane business that was founded in 1940. We completed an initial public offering (“IPO”) inMay 2011. At the time of our IPO, we owned and operated retail propane and wholesale natural gas liquids businesses. Subsequent to our IPO, wesignificantly expanded our operations through a number of business combinations, as described under Part I, Item 1, “Business — Acquisitions Subsequentto Initial Public Offering.” At March 31, 2014, our primary businesses include: · A crude oil logistics business, the assets of which include crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet ofleased railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics business purchases crudeoil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, andother trade hubs. · A water solutions business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Ourwater solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oiland natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. · Our liquids business, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the UnitedStates and in Canada, and which provides natural gas liquids terminaling services through its 22 terminals throughout the United States andrailcar transportation services through its fleet of leased and owned railcars. Our liquids business purchases propane, butane, and otherproducts from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in thewholesale markets. · Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural,commercial, and industrial customers and to certain re-sellers in more than 20 states. We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products inback-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business,which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchasesbiodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders.These businesses were acquired in our December 2013 acquisition of Gavilon Energy. Crude Oil Logistics Our crude oil logistics business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, bargeloading facilities, rail facilities, refineries, and other trade hubs. We attempt to reduce our exposure to price fluctuations by using back-to-back contractswhenever possible. In addition, we enter into forward contracts, financial swaps, and commodity spread trades as economic hedges of our physical forwardsales and purchase contracts with our customers and suppliers. 54Table of Contents 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 wellhead 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 oil to different markets. Wealso seek to maximize margins by blending crude oil of varying properties. The range of low and high spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma and the prices at period endwere as follows: Spot Price Per BarrelAt PeriodYear Ended:LowHighEndMarch 31, 2014$86.68$110.53$101.58March 31, 201377.69106.1697.23 We believe volatility in commodity prices will continue, and our ability to adjust and manage this volatility may impact our financial results. Water Solutions Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from oil andnatural gas production operations, and from the sale of recycled water and recovered hydrocarbons. Our water processing facilities are strategically locatednear areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutions segment is the extent of explorationand production in the areas near our facilities, which is based upon producers’ expectations about the profitability of drilling new wells. The primarycustomers of our facility in Wyoming have committed to deliver a specified minimum volume of water to our facility under long-term contracts. The primarycustomers of our facilities in Colorado have committed to deliver to our facilities all wastewater produced at wells in a designated area. Most of the customers atour other facilities in Texas are not under volume commitments, other than one customer that has committed to deliver 50,000 barrels per day to our facilities. Liquids Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells theproduct to retailers, refiners, petrochemical plants, and other participants in the wholesale markets. Our liquids segment owns 22 terminals and operates afleet of owned and leased railcars and leases underground storage capacity. We attempt to reduce our exposure to the impact of price fluctuations by usingback-to-back contracts and pre-sale agreements that allow us to lock in a margin on a percentage of our winter volumes. We also attempt to reduce our exposureto the impact of price fluctuations by entering into swap agreements whereby we agree to pay a floating rate and receive a fixed rate on a specified notionalamount of product. We enter into these agreements as economic hedges against the potential decline in the value of a portion of our inventory. Our wholesale business is a “cost-plus” business that is affected both by price fluctuations and volume variations. We establish our selling pricebased on a pass-through of our product supply, transportation, handling, storage and capital costs plus an acceptable margin. The margins we realize in ourwholesale business are substantially less on a per gallon basis than our retail propane business. Weather conditions and gasoline blending have a significant impact on the demand for propane and butane, and sales volumes and prices aretypically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the firstand second quarters of each fiscal year. 55Table of Contents The range of low and high spot propane prices per gallon at Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, and the pricesat period end were as follows: Conway, KansasMt. Belvieu, TexasSpot PriceSpot PriceSpot PriceSpot PricePer GallonPer GallonPer GallonPer GallonYear Ended:LowHighAt Period EndLowHighAt Period EndMarch 31, 2014$0.77$4.33$1.03$0.81$1.73$1.06March 31, 20130.500.960.900.711.220.96March 31, 20120.901.490.981.171.631.24 The range of low and high spot butane prices per gallon at Mt. Belvieu, Texas and the prices at period end were as follows: Spot Price Per GallonYear Ended:LowHighAt Period EndMarch 31, 2014$1.08$1.64$1.26March 31, 20131.141.931.45 We believe volatility in commodity prices will continue, and our ability to adjust and manage this volatility may impact our financial results. Retail Propane Our retail propane segment sells propane, distillates, and equipment and supplies to residential, agricultural, commercial, and industrial end users.Our retail propane segment purchases the majority of its propane from our liquids segment. Our retail propane segment generates margins based on thedifference between the wholesale cost of product and the selling price of the product in the retail markets. These margins fluctuate over time due to supply anddemand conditions. Weather conditions have a significant impact on our sales volumes and prices, as a significant portion of our sales are to residentialcustomers who purchase propane and distillates for home heating purposes. A significant factor affecting the profitability of our retail propane segment is our ability to maintain our realized product margin on a cents per gallonbasis. Product margin is the differential between our sales prices and our total product costs, including transportation and storage. Historically, we have beensuccessful in passing on price increases to our customers. We monitor propane prices daily and adjust our retail prices to maintain expected margins bypassing on the wholesale costs to our customers. We believe that volatility in commodity prices will continue, and our ability to adjust to and manage thisvolatility 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 propane costs, we have experienced anincrease in our product margin. The retail propane business is weather-sensitive and subject to seasonal volume variations due to propane’s primary use as aheating source in residential and commercial buildings and for agricultural purposes. Typically, over 70% of our retail volume is sold during the peak heatingseason from October through March. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and secondquarters of each fiscal year. Refined Products Our refined products marketing business purchases gasoline and diesel fuel primarily from eight suppliers, and sells to over 300 customers. Wepurchase and sell these products at a nationwide network of third-party owned terminaling and storage facilities. We typically sell the product at the same timeit is purchased in back-to-back transactions. 56Table of Contents Renewables Our ethanol marketing business purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations torefiners and blenders. We also transport and market third-party owned ethanol for a service fee. Our biodiesel marketing business purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the producton leased railcars for sale to refiners and blenders. We lease biodiesel storage at facilities in Phoenix, Arizona and Deer Park, Texas. Recent Developments Acquisitions of businesses have had a significant impact on the comparability of our results of operations from fiscal 2012 through 2014. Thesetransactions are described under Part I, Item 1, “Business — Acquisitions Subsequent to Initial Public Offering.” Consolidated Results of Operations The following table summarizes our historical consolidated statements of operations for the years ended March 31, 2014, 2013, and 2012: Year Ended March 31,201420132012(in thousands)Total revenues$9,699,274$4,417,767$1,310,473Total cost of sales9,132,6994,039,1101,217,023Operating and general and administrative expenses339,256222,49763,309Depreciation and amortization120,75468,85315,111Operating income106,56587,30715,030Earnings of unconsolidated entities1,898——Interest expense(58,854)(32,994)(7,620)Loss on early extinguishment of debt—(5,769)—Other, net861,5211,055Income before income taxes49,69550,0658,465Income tax provision(937)(1,875)(601)Net income48,75848,1907,864Net (income) loss attributable to noncontrolling interests(1,103)(250)12Net income attributable to parent equity$47,655$47,940$7,876 See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, depreciation and amortization expenseand operating income by segment below. Interest Expense See Note 8 to our consolidated financial statements included in this Annual Report for additional information on our long-term debt. The change ininterest expense during the periods presented is due primarily to fluctuations in the average outstanding debt balance, and in the applicable interest rates, assummarized below: Revolving Credit FacilitiesSenior NotesUnsecured NotesAverageAverageAverageBalanceAverageBalanceBalanceOutstandingInterestOutstandingInterestOutstandingInterestYear Ended:(in thousands)Rate(in thousands)Rate(in thousands)RateMarch 31, 2014$588,3753.04%$250,0006.65%$205,8906.88%March 31, 2013405,1143.56%195,8906.65%——March 31, 2012125,8594.48%———— 57Table of Contents Interest expense also includes amortization of debt issuance costs, which represented $5.7 million of expense during the year ended March 31, 2014,$3.4 million of expense during the year ended March 31, 2013, and $1.3 million of expense during the year ended March 31, 2012. Interest expense alsoincludes letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations assumed in businesscombinations. 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. The increased levels of debt outstanding during the periods from fiscal 2012 through fiscal 2014 are due primarily to borrowings to financeacquisitions. Income Tax Provision We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, eachowner reports his or her share of our income or loss on his or her individual tax return. We have certain taxable corporate subsidiaries in the United States and Canada. In addition, our operations in Texas are subject to a state franchisetax that is calculated based on revenues net of cost of sales. Noncontrolling Interests We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated statements ofoperations represents the other owners’ share of the net income of these entities. Non-GAAP Financial Measures The following tables reconcile net income attributable to parent equity to EBITDA and Adjusted EBITDA, each of which are non-GAAP financialmeasures: Year Ended March 31,201420132012(in thousands)Net income attributable to parent equity$47,655$47,940$7,876Income tax provision9371,875601Interest expense58,87132,9947,620Loss on early extinguishment of debt—5,769—Depreciation and amortization127,82173,73915,911EBITDA235,284162,31732,008Unrealized (gain) loss on derivative contracts(1,327)5,2754,384Loss (gain) on disposal or impairment of assets3,597187(71)Share-based compensation expense17,80410,138—Adjusted EBITDA$255,358$177,917$36,321 We define EBITDA as net income (loss) attributable to parent equity, plus interest expense, loss on early extinguishment of debt, income taxes, anddepreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding the unrealized gain or loss on derivative contracts, the gain or losson the disposal or impairment of assets, and share-based compensation expense. EBITDA and Adjusted EBITDA should not be considered an alternative tonet income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance withaccounting principles generally accepted in the United States (“GAAP”) as those items are used to measure operating performance, liquidity or the ability toservice debt obligations. We believe that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions to ourunitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information for evaluating our financialperformance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we definethem, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures used by other entities. 58Table of Contents For purposes of our Adjusted EBITDA calculation, we make a distinction between unrealized gains and losses on derivatives and realized gains andlosses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as unrealized gains or losses.When a derivative contract is settled, we reverse the previously-recorded unrealized gain or loss and record a realized gain or loss. The realized gain or loss isequal to the amount received or paid on the contract. We acquired Gavilon Energy in December 2013. We are still in the process of developing procedures tocalculate realized and unrealized gains and losses for the Gavilon Energy operations in the same way we calculate them for our other operations. Accordingly,the unrealized gain and loss in the table above excludes any unrealized gains and losses related to Gavilon Energy. The tables below reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported inour consolidated statements of operations and consolidated statements of cash flows: Year Ended March 31,201420132012(in thousands)Reconciliation to consolidated statements of operations:Depreciation and amortization per EBITDA table$127,821$73,739$15,911Intangible asset amortization recorded to cost of sales(6,172)(5,285)(800)Depreciation and amortization of unconsolidated entities(1,638)——Depreciation and amortization attributable to noncontrolling interests743399—Depreciation and amortization per consolidated statements of operations$120,754$68,853$15,111 Reconciliation to consolidated statements of cash flows:Depreciation and amortization per EBITDA table$127,821$73,739$15,911Amortization of debt issuance costs recorded to interest expense5,7273,3751,277Depreciation and amortization of unconsolidated entities(1,638)——Depreciation and amortization attributable to noncontrolling interests743399—Depreciation and amortization per consolidated statements of cash flows$132,653$77,513$17,188 Segment Operating Results Items Impacting the Comparability of Our Financial Results Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to businesscombinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of High Sierra in June 2012, Pecosin November 2012, Third Coast in December 2012, Crescent in July 2013, and Gavilon Energy in December 2013. We expanded our water solutions businessthrough several acquisitions of water disposal and transportation businesses, including High Sierra in June 2012, Big Lake in July 2013, OWL inAugust 2013, and Coastal in September 2013. We expanded our liquids business through the acquisitions of SemStream in October 2011 and High Sierra inJune 2012. We expanded our retail propane operations through the acquisitions of Osterman in October 2011, Pacer in January 2012, North American inFebruary 2012, and Downeast in May 2012. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy. 59Table of Contents Volumes The following table summarizes the volume of product sold and water delivered for the years ended March 31, 2014 and 2013. Volumes shown in thetable below for our liquids segment include sales to our retail propane segment. Year Ended March 31,Segment20142013Change(in thousands)Crude oil logisticsCrude oil sold (barrels)46,10724,37321,734 Water solutionsWater delivered (barrels)62,77425,00937,765 LiquidsPropane sold (gallons)1,190,106912,625277,481Other products sold (gallons)786,671505,529281,142 Retail propanePropane sold (gallons)162,361144,37917,982Distillates sold (gallons)34,96528,8536,112 Refined productsRefined products sold (gallons)412,974—412,974 RenewablesRenewables sold (gallons)150,925—150,925 Volumes sold by our crude oil logistics and water solutions segments were higher during the year ended March 31, 2014 than during the year endedMarch 31, 2013, due primarily to the expansion of our business through acquisitions. Volumes sold by our liquids segment were higher during the year ended March 31, 2014 than during the year ended March 31, 2013, due to severalfactors. Market demand for propane was higher, due in part to colder weather conditions. Market demand for butane to be used in gasoline blending operationswas also higher. Volumes also increased due to the expansion of our customer base. In addition, during the year ended March 31, 2013, we upgraded twoterminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals. Volumes sold by our retail propane segment during the year ended March 31, 2014 increased compared to the volumes sold during the year endedMarch 31, 2013, due primarily to colder weather conditions. Our refined products and renewables segments began with the December 2013 acquisition of Gavilon Energy. 60Table of Contents Operating Income (Loss) by Segment Our operating income (loss) by segment for the years ended March 31, 2014 and 2013 was as follows: Year Ended March 31,Segment20142013Change(in thousands)Crude oil logistics$678$34,236$(33,558)Water solutions10,3178,5761,741Liquids71,88830,33641,552Retail propane61,28546,86914,416Refined products4,080—4,080Renewables2,434—2,434Corporate and other(44,117)(32,710)(11,407)Operating income$106,565$87,307$19,258 Crude Oil Logistics The following table summarizes the operating results of our crude oil logistics segment for the years ended March 31, 2014 and 2013: Year Ended March 31,20142013Change(in thousands)Revenues:Crude oil sales$4,559,923$2,322,706$2,237,217Crude oil transportation and other36,46916,44220,027Total revenues (1)4,596,3922,339,1482,257,244Expenses:Cost of sales4,515,2442,267,5072,247,737Operating expenses53,87225,48428,388General and administrative expenses4,4872,7451,742Depreciation and amortization expense22,1119,17612,935Total expenses4,595,7142,304,9122,290,802Segment operating income$678$34,236$(33,558) (1) Revenues include $37.8 million of intersegment sales during the year ended March 31, 2014 and $22.9 million of intersegment sales during theyear ended March 31, 2013 that are eliminated in our consolidated statements of operations. Revenues. Our crude oil logistics segment generated $4.6 billion of revenue from crude oil sales during the year ended March 31, 2014, selling 46.1million barrels at an average price of $98.90 per barrel. During the year ended March 31, 2013, our crude oil logistics segment generated $2.3 billion ofrevenue from crude oil sales, selling 24.4 million barrels at an average price of $95.30 per barrel. The increase in volume during the year ended March 31,2014 compared to the year ended March 31, 2013 was due in part to the fact that we did not own a crude oil logistics business for the full 12 months endedMarch 31, 2013, as we acquired this business in our June 19, 2012 merger with High Sierra. The increase in volume was also due to acquisitions of crude oillogistics businesses, including Gavilon Energy, Pecos, and Third Coast, among others. Of this increase, $1.0 billion was attributable to Gavilon Energy. Crude oil transportation and other revenues of our crude oil logistics segment were $36.5 million during the year ended March 31, 2014, compared to$16.4 million of crude oil transportation and other revenues during the year ended March 31, 2013. This increase was due primarily to the fact that we did notown a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to acquisitions of crude oil logistics businesses,including Gavilon Energy, Pecos, and Third Coast. 61Table of Contents Cost of Sales. Our cost of crude oil sold was $4.5 billion during the year ended March 31, 2014, as we sold 46.1 million barrels at an average costof $97.93 per barrel. Our cost of sales during the year ended March 31, 2014 was increased by $2.2 million of unrealized losses on derivatives. During theyear ended March 31, 2013, our cost of crude oil was $2.3 billion, as we sold 24.4 million barrels at an average cost of $93.03 per barrel. Operating Expenses. Our crude oil logistics segment incurred $53.9 million of operating expenses during the year ended March 31, 2014, comparedto $25.5 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oillogistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions,including Gavilon Energy, Pecos, and Third Coast. Of this increase, $10.1 million was attributable to Gavilon Energy. General and Administrative Expenses. Our crude oil logistics segment incurred $4.5 million of general and administrative expenses during the yearended March 31, 2014, compared to $2.7 million of general and administrative expenses during the year ended March 31, 2013. This increase was dueprimarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to theexpansion of operations resulting from acquisitions. Of this increase, $1.0 million was attributable to our acquisition of Gavilon Energy. Depreciation and Amortization Expense. Our crude oil logistics segment incurred $22.1 million of depreciation and amortization expense duringthe year ended March 31, 2014, compared to $9.2 million of depreciation and amortization expense during the year ended March 31, 2013. This increase wasdue primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to theexpansion of operations resulting from acquisitions. Of this increase, $2.8 million was attributable to our acquisition of Gavilon Energy. Operating Income. Our crude oil logistics segment generated $0.7 million of operating income during the year ended March 31, 2014, compared to$34.2 million of operating income during the year ended March 31, 2013. Acquisitions of businesses contributed to operating income during the year endedMarch 31, 2014, although this benefit was offset by several factors. These factors included a narrowing of price differences between markets, which reducedour opportunities to generate increased margins by transporting product from lower-price to higher-price markets, and increased competition in the South Texasregion from newly-constructed pipelines. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and tonot fully utilize our transportation fleet until this process has been completed and margins have improved. Operating income during the year ended March 31,2014 was reduced by $3.0 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingentupon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of theemployees. We also recorded $0.5 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent tothe Gavilon Energy acquisition. Water Solutions The following table summarizes the operating results of our water solutions segment for the years ended March 31, 2014 and 2013: Year Ended March 31,Change20142013Acquisitions (1)Other(in thousands)Revenues:Water treatment and disposal$125,788$54,334$64,119$7,335Water transportation17,3127,89314,231(4,812)Total revenues143,10062,22778,3502,523Expenses:Cost of sales11,7385,6119,325(3,198)Operating expenses58,17825,45235,377(2,651)General and administrative expenses7,7621,6651,2394,858Depreciation and amortization expense55,10520,92326,9557,227Total expenses132,78353,65172,8966,236Segment operating income$10,317$8,576$5,454$(3,713) (1) Represents the change in revenues and expenses attributable to acquisitions subsequent to the merger with High Sierra. The cost of sales amountshown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities. 62Table of Contents Revenues. Our water solutions segment generated $125.8 million of treatment and disposal revenue during the year ended March 31, 2014, takingdelivery of 62.8 million barrels of wastewater at an average revenue of $2.00 per barrel. During the year ended March 31, 2013, our water solutions segmentgenerated $54.3 million of treatment and disposal revenue, taking delivery of 25.0 million barrels of wastewater at an average revenue of $2.17 per barrel. Theincrease in revenues was due primarily to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra and wasdue also to acquisitions during the year ended March 31, 2013, including Indigo, and acquisitions during the year ended March 31, 2014, including OWL,Big Lake and Coastal. The decrease in revenue per barrel was due primarily to the fact that the expansion of our water solutions business subsequent to ourmerger with High Sierra has been primarily in Texas, where the market rates for water disposal services are typically lower than in Wyoming or Colorado. In our June 2012 merger with High Sierra, we acquired a water transportation business in Oklahoma. In our August 2013 acquisition of OWL, weacquired a water transportation business in Texas. Our water solutions segment generated $17.3 million of transportation revenues during the year endedMarch 31, 2014, compared to $7.9 million of transportation revenues during the year ended March 31, 2013. This increase was due primarily to theacquisition of OWL. This increase was partially offset by a decrease in water transportation revenues generated by the water solutions business acquired in themerger with High Sierra, which resulted primarily from a slowdown in production activities by a customer. During the three months ended December 31,2013, we wound down our water transportation operations in Oklahoma, transferring certain of the assets to our business in Texas and selling the remainingassets. Cost of Sales. The cost of sales for our water solutions segment was $11.7 million during the year ended March 31, 2014. Our cost of sales duringthe year ended March 31, 2014 was increased by $0.6 million of unrealized losses on derivatives. Because a portion of our processing revenue is generatedfrom the sale of recovered hydrocarbons, we enter into derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbonswe expect to recover. During the year ended March 31, 2013, the cost of sales for our water solutions segment was $5.6 million. Our cost of sales during theyear ended March 31, 2013 was increased by $1.0 million of unrealized losses on derivatives. The increase in our cost of sales was due primarily to theexpansion of our operations through acquisitions of water solutions businesses. Operating Expenses. Our water solutions segment incurred $58.2 million of operating expenses during the year ended March 31, 2014, compared to$25.5 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a water solutionsbusiness until our June 19, 2012 merger with High Sierra, and was also due primarily to subsequent acquisitions of businesses. We incurred losses ondisposal of property, plant and equipment of $2.0 million during the year ended March 31, 2014 as a result of property damage from lightning strikes at twoof our facilities. General and Administrative Expenses. Our water solutions segment incurred $7.8 million of general and administrative expenses during the yearended March 31, 2014, compared to $1.7 million of general and administrative expenses during the year ended March 31, 2013. This increase was due in partto the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due to subsequent acquisitions ofbusinesses. Depreciation and Amortization Expense. Our water solutions segment incurred $55.1 million of depreciation and amortization expense during theyear ended March 31, 2014, compared to $20.9 million of depreciation and amortization expense during the year ended March 31, 2013. This increase wasdue in part to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due to subsequentacquisitions of businesses. The increase is also due in part to $2.1 million of amortization expense related to trade name intangible assets. During the yearended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets. Operating Income. Our water solutions segment generated $10.3 million of operating income during the year ended March 31, 2014, compared tooperating income of $8.6 million during the year ended March 31, 2013. Exclusive of acquisitions during the year ended March 31, 2014, our operatingincome decreased by $3.7 million. Increases in revenues were offset by increases in operating expenses, including a $7.2 million increase in depreciation andamortization expense. The businesses acquired during the year ended March 31, 2014 generated operating income of $5.5 million, which included $27.0million of depreciation and amortization expense, which consisted primarily of amortization expense on acquired customer relationship intangible assets. 63Table of Contents Liquids The following table summarizes the operating results of our liquids segment for the years ended March 31, 2014 and 2013: Year Ended March 31,20142013Change(in thousands)Revenues:Propane sales$1,632,948$841,448$791,500Other product sales1,231,965858,276373,689Other revenues31,06233,954(2,892)Total revenues (1) 2,895,9751,733,6781,162,297 Expenses:Cost of sales - propane1,559,266801,694757,572Cost of sales - other products1,179,944836,747343,197Cost of sales - other24,43920,9503,489Operating expenses42,97727,60515,372General and administrative expenses6,4435,2611,182Depreciation and amortization expense11,01811,085(67)Total expenses2,824,0871,703,3421,120,745Segment operating income$71,888$30,336$41,552 (1) Revenues include $245.6 million of intersegment sales during the year ended March 31, 2014 and $128.9 million of intersegment sales duringthe year ended March 31, 2013 that are eliminated in our consolidated statements of operations. Revenues. Our liquids segment generated $1.6 billion of wholesale propane sales revenue during the year ended March 31, 2014, selling 1.1 billiongallons at an average price of $1.37 per gallon. During the year ended March 31, 2013, our liquids segment generated $841.4 million of wholesale propanesales revenue, selling 912.6 million gallons at an average price of $0.92 per gallon. Approximately 221.2 million gallons of the increase in volumes was due tothe fact that we only owned the natural gas liquids business of High Sierra for a part of the year ended March 31, 2013. The remaining increase in volume wasdue to several factors, including higher market demand, due in part to colder weather conditions, and the expansion of our customer base. In addition, duringthe year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations fromthese terminals. Our liquids segment generated $1.2 billion of other wholesale products sales revenue during the year ended March 31, 2014, selling 786.7 milliongallons at an average price of $1.57 per gallon. During the year ended March 31, 2013, our liquids segment generated $858.3 million of other wholesaleproducts sales revenue, selling 505.5 million gallons at an average price of $1.70 per gallon. Approximately 454.1 million gallons of the increase in volumeswas due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the year ended March 31, 2013. The remaining increase involume was due to several factors, including higher market demand for butane to be used in gasoline blending operations, the expansion of our customer base,and an increased focus on the opportunity to more fully utilize our terminals to market butane. Cost of Sales. Our cost of wholesale propane sales was $1.6 billion during the year ended March 31, 2014, as we sold 1.1 billion gallons at anaverage cost of $1.31 per gallon. Our cost of wholesale propane sales during the year ended March 31, 2014 was increased by $1.6 million of unrealizedlosses on derivatives. During the year ended March 31, 2013, our cost of wholesale propane sales was $801.7 million, as we sold 912.6 million gallons at anaverage cost of $0.88 per gallon. Our cost of wholesale propane sales during the year ended March 31, 2013 was reduced by $3.2 million of unrealized gainson derivatives. 64Table of Contents Declining wholesale propane prices during the first quarter of the prior fiscal year had an adverse effect on cost of sales during the year endedMarch 31, 2013. Our wholesale segment utilizes a weighted-average inventory costing method to calculate cost of sales. Propane prices decreased steadilyduring April and May 2012, as a result of which the replacement cost of propane was at times lower than the weighted-average cost, which had an adverseeffect on margins. One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek tolock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. Wealso have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated withthese contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of allinventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on thesesales. During periods of falling prices, such as we experienced during the three months ended June 30, 2012, this can result in negative margins on these sales,which we recovered when delivering future volumes. Our cost of sales of other products was $1.2 billion during the year ended March 31, 2014, as we sold 786.7 million gallons at an average cost of$1.50 per gallon. Our cost of sales of other products during the year ended March 31, 2014 was reduced by $5.8 million of unrealized gains on derivatives.During the year ended March 31, 2013, our cost of sales of other products was $836.7 million, as we sold 505.5 million gallons at an average cost of $1.66per gallon. Our cost of sales of other products during the year ended March 31, 2013 was increased by $7.5 million of unrealized losses on derivatives. Operating Expenses. Our liquids segment incurred $43.0 million of operating expenses during the year ended March 31, 2014, compared to $27.6million of operating expenses during the year ended March 31, 2013. This increase was due primarily to expanded operations. In addition, during the yearended March 31, 2014, we recorded an impairment of $5.3 million related to the property, plant and equipment of one of our terminals. General and Administrative Expenses. Our liquids segment incurred $6.4 million of general and administrative expenses during the year endedMarch 31, 2014, compared to $5.3 million of general and administrative expenses during the year ended March 31, 2013. This increase was due primarily toexpanded operations. Depreciation and Amortization Expense. Our liquids segment incurred $11.0 million of depreciation and amortization expense during the yearended March 31, 2014, compared to $11.1 million of depreciation and amortization expense during the year ended March 31, 2013. Operating Income. Our liquids segment generated $71.9 million of operating income during the year ended March 31, 2014, compared to $30.3million of operating income during the year ended March 31, 2013. The increase in operating income was due primarily to the expansion of our operations andto colder weather conditions. As a result of the cold weather conditions, the demand for natural gas liquids increased considerably during the recent winter,which had a favorable impact on our sales volumes. The demand also resulted in increases to the market prices for natural gas liquids, which had a favorableimpact on product margins, as we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory.These increases were partially offset by increased operating expenses as a result of expanding our operations. During the year ended March 31, 2014, operatingincome was increased by $4.2 million of unrealized gains on derivatives. During the year ended March 31, 2013, operating income was reduced by $4.3million of unrealized losses on derivatives. 65Table of Contents Retail Propane The following table summarizes the operating results of our retail propane segment for the years ended March 31, 2014 and 2013: Year Ended March 31,20142013Change(in thousands)Revenues:Propane sales$388,225$288,410$99,815Distillate sales127,672106,19221,480Other revenues35,91835,85662Total revenues551,815430,458121,357Expenses:Cost of sales - propane233,110155,11877,992Cost of sales - distillates109,05890,77218,286Cost of sales - other11,53112,688(1,157)Operating expenses96,93688,6518,285General and administrative expenses11,01710,864153Depreciation and amortization expense28,87825,4963,382Total expenses490,530383,589106,941Segment operating income$61,285$46,869$14,416 Revenues. Our retail propane segment generated revenue of $388.2 million from propane sales during the year ended March 31, 2014, selling 162.4million gallons at an average price of $2.39 per gallon. During the year ended March 31, 2013, our retail propane segment generated $288.4 million of revenuefrom propane sales, selling 144.4 million gallons at an average price of $2.00 per gallon. The increase in volumes and average sales prices during the yearended March 31, 2014 compared to the year ended March 31, 2013 was due primarily to market demand being higher as a result of colder weather conditions.Revenues also benefitted from the continued integration of previously-acquired businesses. Our retail propane segment generated revenue of $127.7 million from distillate sales during the year ended March 31, 2014, selling 35.0 milliongallons at an average price of $3.65 per gallon. During the year ended March 31, 2013, our retail propane segment generated $106.2 million of revenue fromdistillate sales, selling 28.9 million gallons at an average price of $3.68 per gallon. The increase in volumes was due primarily to colder weather conditionsand to the acquisitions of smaller retailers. Cost of Sales. Our cost of retail propane sales was $233.1 million during the year ended March 31, 2014, as we sold 162.4 million gallons at anaverage cost of $1.44 per gallon. During the year ended March 31, 2013, our cost of retail propane sales was $155.1 million, as we sold 144.4 million gallonsat an average cost of $1.07 per gallon. Our cost of distillate sales was $109.1 million during the year ended March 31, 2014, as we sold 35.0 million gallons at an average cost of $3.12 pergallon. During the year ended March 31, 2013, our cost of distillate sales was $90.8 million, as we sold 28.9 million gallons at an average cost of $3.15 pergallon. Operating Expenses. Our retail propane segment incurred $96.9 million of operating expenses during the year ended March 31, 2014, compared to$88.7 million of operating expenses during the year ended March 31, 2013. This increase was due in part to the inclusion of Downeast in our results ofoperations for the full 12 months ended March 31, 2014, as compared to only 11 of the months in the 12-month period ended March 31, 2013. General and Administrative Expenses. Our retail propane segment incurred $11.0 million of general and administrative expenses during the yearended March 31, 2014, compared to $10.9 million of general and administrative expenses during the year ended March 31, 2013. This increase was dueprimarily to acquisitions of smaller retailers. 66Table of Contents Depreciation and Amortization Expense. Our retail propane segment incurred $28.9 million of depreciation and amortization expense during theyear ended March 31, 2014, compared to $25.5 million of depreciation and amortization expense during the year ended March 31, 2013. This increase wasdue primarily to capital expenditures and acquisitions. Operating Income. Our retail propane segment generated $61.3 million of operating income during the year ended March 31, 2014, compared to$46.9 million of operating income during the year ended March 31, 2013. The increase in operating income was due primarily to increased market demanddue to colder weather conditions, partially offset by increased operating expenses. Refined Products The following table summarizes the operating results of our refined products segment for the year ended March 31, 2014 (in thousands). Our refinedproducts segment began with our December 2013 acquisition of Gavilon Energy. Revenues$1,180,895 Expenses:Cost of sales1,172,754Operating expenses3,887General and administrative expenses65Depreciation and amortization expense109Total expenses1,176,815Segment operating income$4,080 Revenues. Our refined products segment generated $1.2 billion of revenue during the year ended March 31, 2014, selling 413.0 million gallons at anaverage price of $2.86 per gallon. Cost of Sales. Our cost of sales was $1.2 billion during the year ended March 31, 2014, as we sold 413.0 million gallons at an average cost of $2.84per gallon. Operating Expenses. Our refined products segment incurred $3.9 million of operating expenses during the year ended March 31, 2014. General and Administrative Expenses. Our refined products segment incurred $0.1 million of general and administrative expenses during the yearended March 31, 2014. Depreciation and Amortization Expense. Our refined products segment incurred $0.1 million of depreciation and amortization expense during theyear ended March 31, 2014. Operating Income. Our refined products segment generated $4.1 million of operating income during the year ended March 31, 2014. 67Table of Contents Renewables The following table summarizes the operating results of our renewables segment for the year ended March 31, 2014 (in thousands). Our renewablessegment began with our December 2013 acquisition of Gavilon Energy. Revenues$176,781 Expenses:Cost of sales171,422Operating expenses2,318General and administrative expenses91Depreciation and amortization expense516Total expenses174,347Segment operating income$2,434 Revenues. Our renewables segment generated $176.8 million of revenue during the year ended March 31, 2014, selling 150.9 million gallons at anaverage price of $1.17 per gallon. Cost of Sales. Our cost of sales was $171.4 million during the year ended March 31, 2014, as we sold 150.9 million gallons at an average cost of$1.14 per gallon. Operating Expenses. Our renewables segment incurred $2.3 million of operating expenses during the year ended March 31, 2014. General and Administrative Expenses. Our renewables segment incurred $0.1 million of general and administrative expenses during the year endedMarch 31, 2014. Depreciation and Amortization Expense. Our renewables segment incurred $0.5 million of depreciation and amortization expense during the yearended March 31, 2014. Operating Income. Our renewables segment generated $2.4 million of operating income during the year ended March 31, 2014. 68Table of Contents Corporate and Other The operating loss within “corporate and other” includes the following components: Year Ended March 31,20142013Change(in thousands)Compressor leasing business$2,336$(1)$2,337Natural gas business1,363—1,363Equity-based compensation expense(17,804)(10,138)(7,666)Acquisition expenses(6,908)(5,602)(1,306)Other corporate expenses(23,104)(16,969)(6,135)$(44,117)$(32,710)$(11,407) Operating income of our compressor leasing business for the year ended March 31, 2014 includes a $4.4 million gain from the sale of the business inFebruary 2014. We acquired the natural gas business in our December 2013 acquisition of Gavilon Energy. We subsequently wound down the natural gas businessand, as of March 31, 2014, this business has no revenue-generating activity. The increase in equity-based compensation is due in part to the timing of award grants and is also due in part to an increase in the market value ofour common units. The first restricted units were granted during fiscal 2013, and therefore were not in existence for the full fiscal year. The life-to-date expensefor unvested units is adjusted based on the market value of the common units on the reporting date, and the value of the common units was higher atMarch 31, 2014 than at March 31, 2013. The increase in other corporate expenses is due primarily to increases in compensation expense, due to the addition of new corporate employees toprovide general and administrative services in support of the growth of our business. Operating income during the year ended March 31, 2014 was reduced by $2.0 million of compensation expense related to bonuses that the previousowners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable inDecember 2014, contingent upon the continued service of the employees. We also recorded $2.2 million of employee severance expense during the year endedMarch 31, 2014 as a result of personnel changes subsequent to the Gavilon Energy acquisition, $1.3 million of which is reported under “natural gasbusiness” in the table above and the remainder of which is reported under “other corporate expenses” in the table above. 69Table of Contents Year Ended March 31, 2013Compared to Year Ended March 31, 2012 Volumes Sold or Delivered The following table summarizes the volume of product sold and water delivered for the years ended March 31, 2013 and 2012. Volumes shown in thetable below for our liquids segment include sales to our retail propane segment. Year EndedChange Resulting FromMarch 31,RetailSemStreamHigh SierraSegment20132012Combinations (1)CombinationCombinations (2)Other(in thousands)Crude oil logisticsCrude oil sold (barrels)24,373———24,373— Water solutionsWater delivered (barrels)25,009———25,009— LiquidsPropane sold (gallons)912,625659,921—(3)140,632112,072Other products sold (gallons)505,529134,999—(3)320,28350,247 Retail propanePropane sold (gallons)144,37978,23654,949——11,194Distillates sold (gallons)28,8531,65027,027——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, North American (acquired in February 2012) from April 1, 2012 throughJanuary 31, 2013, Downeast (acquired in May 2012), and certain other smaller retail propane business acquired during fiscal 2013. (2) This data includes the operations of High Sierra (acquired in June 2012), Pecos (acquired in November 2012), and other subsequentacquisitions of smaller crude oil and water solutions businesses. (3) Although the SemStream combination enabled us to significantly expand our wholesale operations, it is not possible to determine which of 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 2013-2014 winter season, which increased thedemand for propane. 70Table of Contents Operating Income by Segment Our operating income by segment is as follows: Year Ended March 31,Segment20132012Change(in thousands)Crude oil logistics$34,236$—$34,236Water solutions8,576—8,576Liquids30,3369,73520,601Retail 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 $28.4 million during the year ended March 31, 2013 as compared to $4.3 million duringthe year ended March 31, 2012. This increase is due in part to $8.4 million of incremental expenses associated with the corporate activities of High Sierra. Inaddition, corporate general and administrative expense for the year ended March 31, 2013 includes $10.1 million of compensation expense related to certainrestricted units granted pursuant to employee and director compensation programs. Corporate general and administrative expense for the year ended March 31,2013 also includes costs related to acquisitions, including $3.7 million of expense related to the acquisition of High Sierra. The operations of our compressorleasing 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 transportation and other16,442Total 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 $22.9 million of intersegment sales that are eliminated in our consolidated statement of operations. Revenues. We generated revenue of $2.3 billion from crude oil sales during the year ended March 31, 2013, selling 24.4 million barrels at an 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 incurred $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. 71Table of Contents Water Solutions The following table summarizes the operating results of our water solutions segment for the year ended March 31, 2013 (amounts in thousands). Theoperations of our water solutions segment began with our June 19, 2012 combination with High Sierra. Revenues:Water treatment and disposal$54,334Water transportation7,893Total revenues62,227Expenses:Cost of sales5,611Operating expenses25,452General and administrative expenses1,665Depreciation and amortization expense20,923Total expenses53,651Segment operating income$8,576 Revenues. Our water solutions segment generated $54.3 million of treatment and disposal revenue during the year ended March 31, 2013, 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 solutions 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 solutions segment incurred $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. 72Table of Contents Liquids The following table compares the operating results of our liquids segment for the years ended March 31, 2013 and 2012: Change Resulting FromYear Ended March 31,High Sierra20132012CombinationOther(in thousands)Revenues:Propane sales$841,448$923,022$115,606$(197,180)Other product sales858,276251,627563,21143,438Other 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 products836,747246,995546,58843,164Costs 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) Revenues include $128.9 million of intersegment sales during the year ended March 31, 2013 and $66.0 million of intersegment sales duringthe year ended March 31, 2012 that are eliminated in our consolidated statements of operations. Revenues. Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale propane sales decreased $197.2million during the year ended March 31, 2013, as compared to $923.0 million during the year ended March 31, 2012. This resulted from a decrease in theaverage selling price of $0.46 per gallon, as compared to an average selling price per gallon of $1.40 in the prior year. This decrease in revenue was partiallyoffset by an increase in volume sold of 112.1 million gallons, as compared to 659.9 million gallons sold in the prior year. During the year ended March 31, 2013, the operations of High Sierra contributed revenues of $115.6 million from propane sales. These 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 products increased $43.4million during the year ended March 31, 2013, as compared to $251.6 million during the year ended March 31, 2012. This resulted from an increase involume sold of 50.2 million gallons as compared to 135.0 million gallons in the prior year, partially offset by a decrease in the average selling price of $0.27per gallon, as compared to $1.86 per gallon in the prior year. During the year ended March 31, 2013, the operations of High Sierra contributed revenues of $563.2 million from sales of other products (primarilybutane). These operations sold 320.3 million gallons of other products at an average price of $1.76 per gallon. Exclusive of the operations acquired in our June 2012 merger with High Sierra, the increase in volume sold is due primarily to the November 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. Transportation and other revenues for the year ended March 31, 2013 relate primarily to fees charged for transporting customer-owned product byrailcar. 73Table of Contents Cost of Sales. Exclusive of the operations acquired in our June 2012 merger with High Sierra, costs of wholesale propane sales decreased $212.2million during the year ended March 31, 2013, as compared to $904.1 million during the year ended March 31, 2012. This resulted from a decrease in theaverage cost of $0.47 per gallon, as compared to an average cost per gallon of $1.37 in the prior year. This decrease in cost was partially offset by an increasein volume sold of 112.1 million gallons, as compared to 659.9 million gallons sold in the prior year. Cost of propane sales were reduced by $14.8 millionduring the year ended March 31, 2013 due to $11.6 million of realized gains and $3.2 million of unrealized gains on derivatives. These derivatives consistedprimarily of propane swaps that we entered into as economic hedges against the potential decline in the market value of our propane inventories. Excludinggains 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 products increased $43.2 millionduring the year ended March 31, 2013, as compared to $247.0 million during the year ended March 31, 2012. This resulted from an increase in volume soldof 50.2 million gallons as compared to 135.0 million gallons in the prior year, partially offset by a decrease in the average cost of $0.26 per gallon, ascompared to $1.83 per gallon in the prior year. Cost of other products sales during the year ended March 31, 2013 was reduced by $0.2 million due to realizedgains on derivatives. During the year ended March 31, 2013, the cost of other products sales of the High Sierra operations was $546.6 million. These operations sold320.3 million gallons of other products (primarily butane) at an average price of $1.71 per gallon. Costs of sales of other products during the year endedMarch 31, 2013 were increased by $7.5 million of unrealized losses and $0.3 million of realized losses on derivatives. Other cost of sales for the year ended March 31, 2013 relate primarily to the cost of leasing railcars used in the transportation of customer-ownedproduct. Operating Expenses. Exclusive of the operations acquired in our June 2012 merger with High Sierra, operating expenses of our liquids segmentincreased $4.4 million during the year ended March 31, 2013 as compared to operating expenses of $8.1 million during the year ended March 31, 2012. Theincrease in operating expenses is due primarily to increased compensation and terminal operating expenses resulting from our SemStream combination. Duringthe year ended March 31, 2013, our liquids segment incurred $15.1 million of operating expenses related to the operations of High Sierra. General and Administrative Expenses. Exclusive of the operations acquired in our June 2012 merger with High Sierra, general and administrativeexpenses of our liquids segment increased $0.8 million during the year ended March 31, 2013 as compared to general and administrative expenses of $2.7million during the year ended March 31, 2012. This increase is due primarily to increased compensation and related expenses resulting from our SemStreamcombination. During the year ended March 31, 2013, our liquids segment incurred $1.7 million of general and administrative expenses related to theoperations 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 liquids segment increased $4.3 million during the year ended March 31, 2013, as compared to depreciation and amortizationexpense of $3.7 million during the year ended March 31, 2012. This increase is due primarily to depreciation and amortization expense related to assetsacquired in the SemStream combination, including depreciation of terminal assets and amortization of customer relationship intangible assets. During the yearended March 31, 2013, our liquids segment recorded $3.1 million of depreciation and amortization expense related to assets acquired in our merger withHigh Sierra. Operating Income. Our liquids segment had operating income of $30.3 million during the year ended March 31, 2013 as compared to operatingincome of $9.7 million during the year ended March 31, 2012. The increased operating income is due in part to $12.9 million of operating income contributedby the operations acquired in the merger with High Sierra. Exclusive of these operations, operating income improved by $7.7 million, which was due toincreased product margins, partially offset by increased expenses. 74Table of Contents Retail Propane The following table compares the operating results of our retail propane segment for the years ended March 31, 2013 and 2012: Change Resulting FromYear Ended March 31,Retail20132012Combinations (1)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 (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, North American (acquired in February 2012) from April 1, 2012 throughJanuary 31, 2013, Downeast (acquired in May 2012), and certain other smaller retail propane business acquired during fiscal 2013. Revenues. Propane sales for the year ended March 31, 2013 increased $113.0 million as compared to propane sales of $175.4 million during theyear ended March 31, 2012. The principal reason for the increase in propane sales was the acquisitions of Osterman, Pacer, North American, and Downeast.Excluding the impact of these acquisitions, propane sales were lower during the year ended March 31, 2013 than during the year ended March 31, 2012, dueprimarily to a decline in the average price per gallon sold of $0.33 during the year ended March 31, 2013, as compared to an average price per gallon sold of$2.24 during the year ended March 31, 2012. Excluding the effect of these acquisitions, volumes sold during the year ended March 31, 2013 were higher thanvolumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder than that of fiscal 2012. The winter offiscal 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 54.9 million gallons sold at an average price of $2.14 per gallon. The average selling price per gallon for the acquired operationswas higher than the average selling price for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general,further away from the primary areas of propane supply than are the markets served by our historical operations. We generated $106.2 million of revenue from the sales of distillates during the year ended March 31, 2013, consisting of 28.9 million gallons sold atan average selling price of $3.68 per gallon. Cost of Sales. Propane cost of sales for the year ended March 31, 2013 increased $37.4 million as compared to propane cost of sales of $117.7million during the year ended March 31, 2012. This increase in propane cost of sales is due primarily to the acquisitions of Osterman, Pacer, NorthAmerican, and Downeast. Excluding the impact of these acquisitions, propane cost of sales was lower during the year ended March 31, 2013 than during theyear ended March 31, 2012, due primarily to a decline in the average cost per gallon sold of $0.47 during the year ended March 31, 2013, as compared to anaverage price per gallon sold of $1.50 during the year ended March 31, 2012. Excluding the effect of these acquisitions, volumes sold during the year endedMarch 31, 2013 were 75Table of Contents higher than volumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder than that of fiscal 2012. Our acquired Osterman, Pacer, North American, and Downeast operations had propane cost of sales of $63.1 million during the year endedMarch 31, 2013, consisting of 54.9 million gallons sold at an average cost of $1.15 per gallon. The average cost per gallon for the acquired operations washigher than the average cost for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further awayfrom the primary areas of propane supply than are the markets served by our historical operations. We had $90.8 million of cost of sales for distillates during the year ended March 31, 2013, consisting of 28.9 million gallons sold at an average costof $3.15 per gallon. Operating Expenses. Operating expenses of our retail propane segment increased $49.5 million during the year ended March 31, 2013 as comparedto operating expenses of $39.2 million during the year ended March 31, 2012. This increase is due primarily to the impact of our Osterman, Pacer, NorthAmerican, and Downeast acquisitions, the operations of which incurred $47.5 million of operating expense during the year ended March 31, 2013. General and Administrative Expenses. General and administrative expenses of our retail propane segment increased $1.9 million during the yearended March 31, 2013 as compared to general and administrative expenses of $9.0 million during the year ended March 31, 2012. The principal factorcausing the increase is the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $5.4 million ofgeneral and administrative expense during the year ended March 31, 2013. General and administrative expense included $4.3 million of acquisition expensesduring the year ended March 31, 2012. Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased $14.0 million during the year endedMarch 31, 2013 as compared to depreciation and amortization expense of $11.5 million during the year ended March 31, 2012. The increase is due primarilyto the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $13.1 million of depreciation andamortization expense during the year ended March 31, 2013. Operating Income. Our retail propane segment had operating income of $46.9 million during the year ended March 31, 2013 compared to operatingincome of $9.6 million during the year ended March 31, 2012. The increased operating income is due in part to the acquired operations of Osterman, Pacer,North American, and Downeast. Excluding these acquired operations, our retail propane segment’s operating income was higher during the year endedMarch 31, 2013 than during the year ended March 31, 2012, due primarily to improved margins on propane sales, and to increased sales volumes. During theyear ended March 31, 2012, the winter was one of the warmest on record. As a result, demand for propane was low, which resulted in reduced sales volumesduring fiscal 2012. Seasonality Seasonality impacts our liquids and retail propane segments. A large portion of our retail propane operation is in the residential market where propaneis used primarily for heating. During the year ended March 31, 2014, 74% of our retail propane volume was sold during the peak heating season fromOctober through March. Consequently, for these two segments, sales, operating profits and operating cash flows are generated mostly in the third and fourthquarters of each fiscal year. See “—Liquidity, Sources of Capital and Capital Resource Activities — Cash Flows.” Liquidity, Sources of Capital and Capital Resource Activities Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. Our 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 liquidssegments are the greatest. Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in ourpartnership agreement) to unitholders of record on the applicable record date. Available cash, for any quarter, generally consists of all cash on hand at the endof that quarter less the amount of cash reserves established by our general partner to (i) provide for the proper conduct of our business, (ii) comply withapplicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for anyone or more of the next four quarters. 76Table of Contents We believe that our anticipated cash flows from operations and the borrowing capacity under our Credit Agreement are sufficient to meet our liquidityneeds. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital. Our ability to raise additionalcapital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances that we can raise additionalcapital to meet these needs (see Part I, Item 1A, “Risk Factors”). Commitments or expenditures, if any, we may make toward any acquisition projects are atour discretion. We continue to pursue a strategy of growth through acquisitions. We expect to consider financing future acquisitions through a variety of sources,including the use of available capacity on our Revolving Credit Facility (as defined below), the issuance of equity to sellers of the businesses we acquire,private placements of common units or debt securities, and public offerings of common units or debt securities. Our ability to raise additional capital throughthe issuance of debt or equity securities will have a significant impact on our ability to continue to pursue our growth strategy. Credit Agreement On June 19, 2012, we entered into the Credit Agreement with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fundworking capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the “Expansion CapitalFacility,” and together with the Working Capital Facility, “Revolving Credit Facility”). The Working Capital Facility had a total capacity of $935.5 million for cash borrowings and letters of credit at March 31, 2014. At March 31,2014, we had outstanding cash borrowings of $389.5 million and outstanding letters of credit of $270.6 million on the Working Capital Facility. TheExpansion Capital Facility had a total capacity of $785.5 million for cash borrowings at March 31, 2014. At March 31, 2014, we had outstanding cashborrowings of $532.5 million on the Expansion Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowingbase,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time. The commitments under the Credit Agreement expire on November 5, 2018. We have the right to pre-pay outstanding borrowings under the 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 0.50% to 1.50% per annum or(ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, asdefined in the Credit Agreement. At March 31, 2014, the interest rate in effect on outstanding LIBOR borrowings was 1.91%, calculated as the LIBOR rate of0.16% plus a margin of 1.75%. At March 31, 2014, the interest rate in effect on letters of credit was 1.75%. Commitment fees are charged at a rate rangingfrom 0.38% to 0.50% on any unused credit. At March 31, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were asfollows (dollars in thousands): AmountRateExpansion Capital Facility —LIBOR borrowings$532,5001.91%Working Capital Facility —LIBOR borrowings358,0001.91%Base rate borrowings31,5004.00% The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our “leverage ratio,” as defined in the CreditAgreement, cannot exceed 4.25 to 1.0 at any quarter end. At March 31, 2014, our leverage ratio was approximately 3 to 1. The Credit Agreement also specifiesthat our “interest coverage ratio,” as defined in the Credit Agreement, cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At March 31, 2014,our interest coverage ratio was approximately 7 to 1. The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, 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. 77Table of Contents At March 31, 2014, we were in compliance with the covenants under the Credit Agreement. Senior Notes On June 19, 2012, we entered into the Note Purchase Agreement whereby we issued $250.0 million of Senior Notes in a private placement (the“Senior Notes”). The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a fixed rate of 6.65%. Interest is payablequarterly. The Senior Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on thematurity date of June 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes aresecured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement. The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit 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 are 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 $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note 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, 2014, we were in compliance with the covenants under the Note Purchase Agreement and the Senior Notes. Unsecured Notes On October 16, 2013, we issued $450.0 million of 6.875% senior unsecured notes (the “Unsecured Notes”) in a private placement exempt fromregistration under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. We receivednet proceeds of $438.4 million, after the initial purchasers’ discount of $10.1 million and estimated offering costs of $1.5 million. We used the net proceeds toreduce the outstanding balance on our Revolving Credit Facility. The Unsecured Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem theUnsecured Notes prior to the maturity date, although we would be required to pay a premium for early redemption. The purchase agreement and the indenture governing the Unsecured Notes contain various customary representations, warranties, and additionalcovenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchaseagreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) thefailure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy orinsolvency. At March 31, 2014, we were in compliance with the covenants under the Unsecured Notes. We also entered into a registration rights agreement whereby we have committed to exchange the Unsecured Notes for a new issue of notes registeredunder the Securities Act that has substantially identical terms to the Unsecured Notes on or before October 16, 2014. If we are unable to fulfill this obligation,we would be required to pay liquidated damages to the holders of the Unsecured Notes. 78Table of Contents Revolving Credit Balances The following table summarizes Revolving Credit Facility borrowings: AverageDailyLowestHighestBalanceBalanceBalance(in thousands)Year Ended March 31, 2014:Expansion loans$392,822$—$546,000Working capital loans195,553—448,500Year Ended March 31, 2013:Expansion loans$351,355$254,000$451,000Working capital loans92,626—153,500 Business Combinations Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, as described under Part I, Item 1,“Business — Acquisitions Subsequent to Initial Public Offering.” Cash Flows The following summarizes the sources (uses) of our cash flows: Year Ended March 31,Cash Flows Provided by (Used in):201420132012(in thousands)Operating activities, before changes in operating assets andliabilities$243,303$146,395$20,459Changes in operating assets and liabilities(158,067)(13,761)69,870 Operating activities$85,236$132,634$90,329 Investing activities(1,455,373)(546,621)(296,897) Financing activities1,369,016417,716198,063 Operating Activities. The growth in our operating cash flows over the period from fiscal 2012 to fiscal 2014 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 and fiscal 2014, our cash outflows from investing activities included the purchase of workingcapital in business combinations, a portion of which has benefitted (or will benefit) cash flows from operations as the working capital is recovered. Ouroperating cash flows during the year ended March 31, 2012 included the sale of $30.3 million of inventory (net of purchases). This was due in part to ouracquisition of assets from SemStream on November 1, 2011, in which we acquired $104.2 million of inventory. The cash paid to complete the SemStreamtransaction is included within cash outflows from investing activities. Investing Activities. Our cash flows from investing activities are primarily impacted by our capital expenditures. In periods where we are engaged insignificant acquisitions, we will generally realize negative cash flows in investing activities, which, depending on our cash flows from operating activities,may require us to increase the borrowings under our Revolving Credit Facility. During the year ended March 31, 2014, we completed a number of businesscombinations for which we paid $1.3 billion of cash, net of cash acquired, on a combined basis. Also during the year ended March 31, 2014, we paid$165.1 million for capital expenditures, which related primarily to water disposal and natural gas liquids terminal assets. Of this amount, $132.9 millionrepresented expansion capital and $32.2 million represented maintenance capital. During the year ended March 31, 2014, we used $36.0 million of investingcash outflows from commodity derivatives and generated $24.7 million of investing cash inflows from the sale of long-lived assets. During the year endedMarch 31, 2013, we completed our merger with High Sierra, for which we paid $239.3 million, net of cash 79Table of Contents acquired. Also during the year ended March 31, 2013, we completed 12 other acquisitions, for which we paid $251.5 million of cash, net of cash acquired,on a combined basis. Also during the year ended March 31, 2013, we paid $72.5 million for capital expenditures in addition to the acquisitions of businesses.Of this amount, $58.7 million represented expansion capital and $13.8 million represented maintenance capital. During the year ended March 31, 2013, wegenerated $11.6 million of investing cash inflows from commodity derivatives and $5.1 million of investing cash inflows from the sale of long-lived assets.During the year ended March 31, 2012, we completed four significant acquisitions and several smaller acquisitions. We paid a combined cash amount of$297.4 million to complete these acquisitions. Financing Activities. Changes in our cash flow from financing activities include advances from and repayments on our revolving credit facilities,either to fund our operating or investing requirements. In periods where our cash flows from operating activities are reduced (such as during our first andsecond quarters), we may fund the cash flow deficits through our Working Capital Facility. During the year ended March 31, 2014, we borrowed $444.5million on our Revolving Credit Facility (net of repayments) and issued $450.0 million of Unsecured Notes. During the year ended March 31, 2014, we paid$24.6 million of debt issuance costs. During the year ended March 31, 2013, we borrowed $263.5 million on our revolving credit facilities (net ofrepayments) and issued $250.0 million of Senior Notes. During the year ended March 31, 2013, we paid $20.2 million of debt issuance costs. During theyear ended March 31, 2012, we borrowed $149.0 million on our revolving credit facilities (net of repayments), primarily to fund acquisitions. Cash flows from financing activities include proceeds from sales of equity. During the year ended March 31, 2014, we completed three equityissuances for which we received net proceeds of $650.2 million on a combined basis. Cash flows from financing activities also include distributions paid to owners. We expect our distributions to our partners to increase in futureperiods under the terms of our partnership agreement. Based on the number of common and subordinated units outstanding at March 31, 2014 (exclusive ofunvested restricted units issued pursuant to employee compensation programs), if we made distributions equal to our minimum quarterly distribution of$0.3375 per unit ($1.35 annualized), total distributions would equal $26.8 million per quarter ($107.2 million per year). To the extent our cash flows fromoperating activities are not sufficient to finance our required distributions, we may be required to increase the borrowings under our Working Capital Facility. The following table summarizes the distributions declared since our IPO: Amount PaidAmount PaidAmountToToDate 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, 20130.477525,6051,189July 25, 2013August 5, 2013August 14, 20130.493831,7251,739October 23, 2013November 4, 2013November 14, 20130.511335,9082,491January 23, 2014February 4, 2014February 14, 20140.531342,1504,283April 24, 2014May 5, 2014May 15, 20140.551343,7375,754 On May 5, 2011, we made a distribution of $3.9 million from available cash to our general partner and common unitholders at March 31, 2011.Also in May 2011, we used $65.0 million of the proceeds from our IPO to repay advances under our previous credit facility. 80Table of Contents Contractual Obligations The following table summarizes our contractual obligations at March 31, 2014 for our fiscal years ending thereafter: For the Years Ending March 31,After March 31,Total20152016201720182018(in thousands)Principal payments on long-term debt—Expansion capital borrowings$532,500$—$—$—$—$532,500Working capital borrowings389,500————389,500Senior Notes250,000———25,000225,000Unsecured Notes450,000————450,000Other long-term debt14,9147,0813,6142,3561,449414Interest payments on long-term debt—Revolving credit facility(1)114,93624,98624,98624,98624,98614,992Senior Notes99,75016,62516,62516,62516,20933,666Unsecured Notes247,50030,93830,93830,93830,938123,748Other long-term debt8143722131238224Letters of credit270,626————270,626Future minimum lease paymentsunder other noncancelable operatingleases428,030133,17093,45464,20949,80287,395Fixed-price commodity purchasecommitments39,11739,117————Index-priced commodity purchasecommitments(2)982,850982,706144———Total contractual obligations$3,820,537$1,234,995$169,974$139,237$148,466$2,127,865 Natural gas liquids gallons underfixed-priced purchase commitments(thousands)(3)31,11131,111————Natural gas liquids gallons underindex-priced purchasecommitments (thousands)(3)522,947522,827120———Crude oil barrels under index-pricedpurchase commitments(thousands)(3)4,0164,016———— (1) The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at March 31, 2014. SeeNote 8 to our consolidated financial statements included in this Annual Report for additional information on our Credit Agreement. (2) Index prices are based on a forward price curve at March 31, 2014. A theoretical change of $0.10 per gallon in the underlying commodity priceat March 31, 2014 would result in a change of $52.3 million in the value of our index-based natural gas liquids purchase commitments. Atheoretical change of $1.00 per barrel in the underlying commodity price at March 31, 2014 would result in a change of approximately $8.0million in the value of our index-based crude oil purchase commitments. (3) At March 31, 2014, we had fixed-price and index-price sales contracts for 63.9 million and 272.5 million gallons of natural gas liquids,respectively. At March 31, 2014, we had index-price sales contracts for 7.1 million barrels of crude oil. Off-Balance Sheet Arrangements We do not have any off balance sheet arrangements other than the operating leases described in Note 10 to our consolidated financial statementsincluded in this Annual Report. 81Table of Contents 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, production of crude oil in North America is high, but changes in the levelof production could impact our ability to generate revenues in the future. The spread between the prices of crude oil in different locations can also fluctuate widely. If these price differences are high, we are able to generateincreased margins by transporting crude oil from lower-price markets to higher-price markets. During the year ended March 31, 2013, the spread betweencrude oil prices in the mid-continent region and crude oil prices in south Texas widened, which gave us the opportunity to generate favorable margins bytransporting crude oil from one region to the other. During the year ended March 31, 2014, spreads narrowed considerably, which had a significant impact onour operations in the Rocky Mountain and South Texas regions. When price differences between markets are reduced, it is necessary to renegotiate price termswith producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved. Water Solutions Our opportunity to earn revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areas whereour facilities are located. Recently, production has been strong in most of these regions, but a future decline in the level of production could have an adverseimpact on profitability. During the year ended March 31, 2014, we completed three separate acquisitions of water solutions businesses with operations in Texas. As a result,the geographic mix of our water solutions segment has changed, and we expect a greater share of the revenues from this segment to be generated from ouroperations in the Permian and Eagle Ford Basins in Texas than in the past. During the year ended March 31, 2014, the revenues of our water solutions segment were lower than our expectations and the operating expenses ofour water solutions segment were higher than our expectations. This related primarily to our operations in the Eagle Ford Basin in Texas, which were obtainedthrough several acquisitions during the year ended March 31, 2014. We have incurred higher than expected expenses, and have generated lower revenue thanexpected, in the process of bringing these operations up to the standards we have established for our water solutions business. Liquids The volumes we sell in our wholesale natural gas liquids business are heavily dependent on the demand for propane and butane, which is influencedby weather conditions. The margins we generate in our wholesale natural gas liquids business are influenced by changes in prices over the course of a year.During years when demand is higher during the winter months, we have the opportunity to utilize our storage assets to increase margins. Weather conditionsduring the recent winter season were colder than normal. As a result, the demand for natural gas liquids increased considerably, which had a favorable impacton our sales volumes. The demand has also resulted in increases to market prices for natural gas liquids. This has had a favorable impact on productmargins, based on the fact that we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory. Retail Propane The volumes we sell in our retail propane business are heavily dependent on weather conditions, as cold weather significantly increases customerdemand for propane. During times of lower propane prices, margins per gallon typically increase. During times of higher propane prices, margins per gallontypically decrease. Weather conditions during the recent winter season were colder than normal. As a result, the demand for natural gas liquids increasedconsiderably, which had a favorable impact on our sales volumes. The demand also resulted in increases to market prices for natural gas liquids. This had afavorable impact on product margins, based on the fact that we purchased inventory when prices, and therefore our average cost of inventory, were lower thanwhen we sold the inventory. The sharp rise in prices may increase the collectability risk of accounts receivable, and the recent high 82Table of Contents prices may create downward pressure on future demand, as some customers may invest in making their homes more energy efficient or may take other stepsto reduce their need for propane. Renewables The spread between the prices of ethanol in different locations can fluctuate widely. If these price differences are high, we are able to generateincreased margins by transporting ethanol from lower-price markets to higher-price markets. During the last few months of the fiscal year ended March 31,2014, the spread between ethanol prices in different markets widened, which gave us the opportunity to generate favorable margins by transporting ethanolfrom one region to the other. During April 2014, ethanol price spreads between regions narrowed considerably. Recent Accounting Pronouncement In April 2014, the Financial Accounting Standards Board issued an Accounting Standards Update that changes the criteria for reportingdiscontinued operations. Under the new standard, a disposal of part of an entity is not classified as a discontinued operation unless the disposal represents astrategic shift that will have a major effect on an entity’s operations and financial results. We adopted the new standard during the fiscal year ended March 31,2014. As described in Note 14 to our consolidated financial statements included elsewhere in this Annual Report, during the year ended March 31, 2014,we sold our compressor leasing business and wound down our natural gas marketing business. These actions do not represent a strategic shift that had amajor effect on our operations, and do not meet the criteria under the new accounting standard for these businesses to be reported as discontinued operations. Critical Accounting Policies The preparation of financial statements and related disclosures in compliance with GAAP requires the selection and application of 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 accounting policies that are most important to the portrayal of our financial condition and results of operations. Changes in these policies couldhave a material effect on the financial statements. The application of these accounting policies necessarily requires subjective or complex judgments regarding estimates and projected outcomes offuture events that could have a material effect on our financial statements. Revenue Recognition We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the 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. 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 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. To perform this assessment, we consider qualitative factors to determine whether it is morelikely than not that the fair value of each reporting unit exceeds its carrying amount. We completed the assessment of each of our reporting units anddetermined it was more likely than not that no impairment existed for the year ended March 31, 2014. The assessment of the value of our reporting unitsrequires us to make certain assumptions relating to future operations. When evaluating operating performance, various factors are considered, such as currentand changing economic conditions and the commodity price environment, among others. If the growth assumptions embodied in the current year impairmenttesting prove inaccurate, we could incur an impairment charge. 83Table of Contents 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 evaluate equity method investments for impairment when we believe the current fair value may be less than the carrying amount. We recordimpairments of equity method investments if we believe the decline in value is other than temporary. Asset Retirement Obligations We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order 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. We have recorded a liability of $2.3million at March 31, 2014. This liability is related to the wastewater disposal facilities and crude oil facilities for which we have contractual and regulatoryobligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired. In addition to the obligations described above, we may be obligated to remove facilities, or perform other remediation, upon retirement of certainassets. However, we do not believe the present value of such 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. Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment Depreciation expense represents the systematic write-off of the cost of our property and equipment, net of residual or salvage value (if any), to 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. 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. Business Combinations We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using the“acquisition method,” in which the assets acquired and liabilities assumed are recorded at their estimated fair values. Fair values of assets acquired andliabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fairvalues can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangibleassets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property andequipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchaseand sale agreements, storage and transportation contracts, and employee compensation commitments. The excess of purchase price over the net fair value ofacquired assets over the assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Generally, we have up toone year from the acquisition date to finalize the identification and valuation of acquired assets and liabilities. The impact of subsequent changes to theidentification of assets and liabilities may require retrospective adjustments to our previously-reported consolidated financial position and results of operations. 84Table of Contents Inventory Our inventory consists primarily of crude oil, natural gas liquids, refined products, ethanol, and biodiesel. The market values of these commoditieschange on a daily basis as supply and demand conditions change. We value our inventory using the weighted-average cost and first-in first-out methods. At theend of each fiscal year, we also perform a “lower of cost or market” analysis; if the cost basis of the inventory would not be recoverable based on marketprices at the end of the year, we reduce the book value of the inventory to the recoverable amount. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business to sell the inventory inretail markets. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost ormarket write-down if we expect the market values to recover by our fiscal year end of March 31. We are unable to control changes in the market value of thesecommodities and are unable to determine whether write-downs will be required in future periods. In addition, write-downs at interim periods could be requiredif we cannot conclude that market values will recover sufficiently by our fiscal year end. Equity-Based Compensation Our general partner has granted certain restricted common units to employees and directors under a long-term incentive plan. These units vest intranches, subject to the continued service of the recipients. We record the expense for the first tranche of each award on a straight-line basis over the period beginning with the grant date of the awards andending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previoustranche and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. Wecalculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted toreflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distributionrights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distributiongrowth. We report unvested units as liabilities on our consolidated balance sheets. When units vest and are issued, we record an increase to equity. Item 7A. Quantitative and Qualitative Disclosures About Market Risk Interest Rate Risk At March 31, 2014, a significant portion of our long-term debt is variable-rate debt. Changes in interest rates impact the interest payments of 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. At March 31,2014, we had $922.0 million of outstanding borrowings under our Revolving Credit Facility at a rate of 1.98%. A change in interest rates of 0.125% wouldresult in an increase or decrease of our annual interest expense of $1.2 million on the $922.0 million of outstanding borrowings on the Revolving CreditFacility at March 31, 2014. Commodity Price and Credit Risk Our operations are subject to certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that themarket value of crude oil, propane, and other products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk isthe risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. As is customary in the crude oil industry, we generally receive payment from customers for sale of crude oil on a monthly basis. As a result,receivables from individual customers in our crude oil logistics business are generally higher than the receivables from customers in our other segments. Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy,respectively. Open commodity positions and market price changes are monitored daily and are reported to 85Table of Contents senior management and to marketing operations personnel. We attempt to minimize credit risk exposure through credit policies and periodic monitoringprocedures as well as through customer deposits, restrictions on product liftings, letters of credit and entering into netting agreements that allow for offsettingcounterparty receivable and payable balances for certain transactions, as deemed appropriate. The principal counterparties associated with our operations atMarch 31, 2014 were retailers, resellers, energy marketers, producers, refiners, and dealers. The natural gas liquids and crude oil industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential ofsales prices over supply costs. As a result, our profitability may be impacted by changes in wholesale prices of natural gas liquids and crude oil. When 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 and financial derivatives, toreduce the effect of price volatility on our product costs, protect the value of our inventory positions, and to help ensure the availability of product duringperiods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment from ourwholesale and retail customers. We may experience net unbalanced positions from time to time. In addition to our ongoing policy to maintain a balancedposition, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio. Although we use derivative commodity instruments to reduce the market price risk associated with forecasted transactions, we have not accountedfor such derivative commodity instruments as hedges. We record the changes in fair value of these derivative commodity instruments within cost of sales. Thefollowing table summarizes the hypothetical impact on the fair value of our commodity derivatives of an increase of 10% in the value of the underlyingcommodity (in thousands): Increase(Decrease)To Fair ValueCrude oil (crude oil logistics segment)$(13,528)Crude oil (water solutions segment)(6,365)Propane (liquids segment)461Other products (liquids segment)2,410Refined products (refined products segment)5,690Renewables (renewables segment)1,776 Fair Value We use observable market values for determining the fair value of our trading instruments. In cases where actively quoted prices are not available,other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets andother market fundamental analysis. Item 8. Financial Statements and Supplementary Data Our consolidated financial statements beginning on page F-1 of this Annual Report, together with the report of Grant Thornton LLP, our independentregistered 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. 86Table of Contents 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, including the principal executive officer and principal financial officer of our general partner, as appropriate, to allowtimely decisions regarding required disclosure. 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 at March 31, 2014. Based onthis evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31, 2014, such disclosurecontrols and procedures were effective to provide the reasonable assurance described above. Changes in Internal Control over Financial Reporting Other than changes that have resulted or may result from our business combinations during the year ended March 31, 2014, as discussed below,there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)—15(f) of the Exchange Act) during the three monthsended March 31, 2014 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We acquired Gavilon Energy on December 2, 2013, as described in Note 4 to our consolidated financial statements included in this Annual Report.At this time, we continue to evaluate the business and internal controls and processes of Gavilon Energy and are making various changes to its operating andorganizational structure based on our business plan. We are in the process of implementing our internal control structure over this acquired business. Ourevaluation and integration efforts related to those operations have continued into fiscal 2015. Management’s Report on Internal Control Over Financial Reporting The management of the Partnership and subsidiaries is responsible for establishing and maintaining adequate internal control over financialreporting, as such term is defined in Exchange Act Rule 13(a)-15(f). Under the supervision and with the participation of our management, including the 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 Gavilon Energy from our evaluation of the effectiveness of internal control overfinancial reporting for the year ended March 31, 2014 due to their size and complexity and the limited time available to complete the evaluation. The operationsexcluded from our evaluation represent 31% of our total assets at March 31, 2014, 30% of our total revenues for the year ended March 31, 2014, and 10% ofour operating income for the year ended March 31, 2014. Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective atMarch 31, 2014. Our internal control over financial reporting at March 31, 2014 has been audited by Grant Thornton LLP, an independent registered public accountingfirm, as stated in their report, which appears in “Item 15 — Exhibits and Financial Statement Schedules” of this Annual Report. Item 9B. Other Information None. 87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 New York Stock Exchange (“NYSE”) and SEC independence requirements. The NYSE does notrequire a listed publicly traded limited partnership like us to have a majority of independent directors on the board of directors of our general partner. Inaddition, we are not required to have a nominating and corporate governance committee. In evaluating director candidates, the NGL Energy GP Investor Group assesses whether a candidate possesses the integrity, judgment, knowledge,experience, skill and expertise that are likely to enhance the ability of the board of directors of our general partner to manage and direct our affairs 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 and 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. 88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 Krimbill60Chief Executive Officer and DirectorAtanas H. Atanasov41Chief Financial Officer and TreasurerJames J. Burke58President, NGL Energy Partners and DirectorShawn W. Coady52President and Chief Operating Officer, Retail Division and DirectorTodd M. Coady56Vice President, AdministrationDavid C. Kehoe55Executive Vice President, NGL - Crude LogisticsPatrice A. Lemon53Senior Vice President, AccountingVincent J. Osterman57President, Eastern Retail Propane Operations and DirectorKevin C. Clement55DirectorCarlin G. Conner46DirectorStephen L. Cropper64DirectorBryan K. Guderian54DirectorJames C. Kneale62DirectorJohn T. Raymond43DirectorPatrick Wade44Director 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, L.P., as Vice President and Chief Financial Officer in 1990. Mr. Krimbill was Presidentof Heritage Propane Partners, L.P. from 1999 to 2000 and President and Chief Executive Officer of Heritage Propane Partners, L.P. from 2000 to 2005.Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners, L.P., from 2000 to January 2007.Mr. Krimbill is also currently a member of the board of directors of Pacific Commerce Bank. Mr. Krimbill brings leadership, oversight and financial experience to the board. Mr. Krimbill provides expertise in managing and operating 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. 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 and Treasurer. Prior to joining NGL, Mr. Atanasov spent nine years at GECapital, working in lending and leveraged equity. Prior to GE Capital, he was with The Williams Companies, Inc. Mr. Atanasov is a Certified PublicAccountant and holds an M.B.A. from the University of Tulsa and a B.S. in Accounting from Oral Roberts University. James J. Burke. Mr. Burke serves as the President of NGL Energy Partners and joined the board of directors of our general partner in 2012.Mr. Burke was one of High Sierra’s co-founders and served as Chairman of the High Sierra board and President and Chief Executive Officer of theHigh Sierra general partner since September 2010. From July 2004 to September 2010, Mr. Burke was the High Sierra general partner’s Managing Director.Mr. Burke, along with three other entrepreneurs, co-founded Petro Source Partners, LP, where he ran six business units throughout the United States andCanada for the company over a 17-year span. Prior to that, Mr. Burke served as Manager of Crude Oil Acquisitions at Asamera Oil (United States) Inc. from1981 to 1984. Mr. Burke began his career as a Crude Oil Representative at Permian Corporation, where he worked from 1978 to 1981. Mr. Burke also servesas the Managing Director of Impact Energy Services, LLC. Mr. Burke received his B.S. from University of Colorado in 1978. 89Table of Contents 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 25 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. David C. Kehoe. Mr. Kehoe serves as the Executive Vice President of the NGL — Crude Logistics segment. Mr. Kehoe joined our management teamthrough our June 2012 merger with High Sierra. Mr. Kehoe has served on High Sierra’s management team since 2007. Prior to that, Mr. Kehoe held variousleadership positions with Petro Source Partners, LP from 1989 to 2007. Patrice A. Lemon. Ms. Lemon has served as our Senior Vice President of Accounting since May 2012. Ms. Lemon previously served several rolesin accounting and SEC reporting with Energy Transfer Partners, L.P. and Heritage Propane Partners, L.P. from March 2001 through May 2012. InMarch 2001, Ms. Lemon joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as the Manager of Financial Reporting.Ms. Lemon’s most recent role prior to joining NGL was the Director of Financial Reporting and Controller with Heritage Propane Partners, L.P. For ten yearsprior to joining Heritage Propane Partners, L.P., Ms. Lemon worked as an audit manager for a regional public accounting firm in Montana. Ms. Lemonreceived a B.A. in Accounting from Carroll College of Helena, Montana. Vincent J. Osterman. Mr. Osterman has served as the President of Osterman Associated Companies, which contributed the assets of its 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. 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, United States refined products, asphalt andresidual fuels. He is a graduate of Wichita State University’s W. Frank Barton School of Business with a B.A. in Marketing. 90Table of Contents 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. Carlin G. Conner. Mr. Conner joined the board of directors of our general partner in April 2014. Mr. Conner serves as President and ChiefExecutive Officer of SemGroup Corporation and Rose Rock Midstream GP, LLC. Mr. Conner previously served as managing director of Oiltanking GmbH,an independent worldwide storage provider of crude oil, refined petroleum products, liquid chemicals and gases, since 2012. Mr. Conner has served as amember of the board of directors of the general partner of Oiltanking Partners, L.P., a publicly traded master limited partnership engaged in independentterminaling, storage and transportation of crude oil, refined petroleum products and liquefied petroleum gas (“Oiltanking Partners”), since March 2011 andwas elected chairman in July 2011 in connection with the completion of the initial public offering of Oiltanking Partners. Mr. Conner also served as Presidentand Chief Executive Officer of Oiltanking Partner’s general partner from March 2011 to November 2012, and as President and Chief Executive Officer ofOiltanking Holding Americas, Inc., a wholly-owned subsidiary of Oiltanking GmbH, from July 2006 to November 2012. Previously, from 2003 to 2006, heworked at Oiltanking GmbH corporate headquarters in Hamburg, Germany, where he was responsible for international business development and was on theboards of several Oiltanking GmbH ventures. He joined Oiltanking Houston, L.P. in 2000. He began his career at GATX Terminals Corporation in variousroles including operations and commercial management. Mr. Conner has more than 23 years of experience in the midstream industry. Mr. Conner provides the Board more than 23 years of experience in the midstream industry and executive level experience gained through his serviceswith Oiltanking GmbH and its affiliates. He also has substantial board experience related to management and oversight of a midstream publicly traded masterlimited partnership. His industry knowledge and board experience allow him to be a valuable contributor to the Board. Stephen L. Cropper. Mr. Cropper joined the board of directors of our general partner in June 2011. Mr. Cropper held various positions during 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 Mr. Cropper’s retirement from The Williams Companies, Inc. in 1998, he has been a consultant and private investor and alsoserved as a director of Sunoco Logistics Partners, L.P., NRG Energy, Inc., and Berry Petroleum Company. Mr. Cropper brings substantial experience in the energy business and in the marketing of energy products to the board. With his 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 August 2011, where he had responsibility for overseeing international operations. Mr. Guderian has served asa director of Apco Oil & Gas International Inc., since 2002 and as a director of Petrolera Entre Lomas S.A. since 2003. Mr. Guderian brings considerable upstream experience to the board including executive, operational and financial expertise from 30 years of 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 is a former CPA and has a B.B.A. in Accounting in 1973 from West Texas A&Min 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. John T. Raymond. Mr. Raymond joined the board of directors of our general partner in August 2013. Mr. Raymond is the Founder and MajorityOwner of The Energy & Minerals Group of which he has been a Managing Partner and the Chief Executive Officer since its September 2006 inception.Mr. Raymond has held executive leadership positions with various energy companies, including President and Chief Executive Officer of Plains Resources Inc.(the predecessor entity of Vulcan Energy Corporation), President and Chief Operating Officer of Plains Exploration and Production Company and was aDirector of Plains All American Pipeline, LP. Mr. Raymond is also currently a director of American Energy Ohio Holdings, LLC, Ferus Inc., Ferus Natural Gas Fuels Inc., Iron Ore Holdings,Lighthouse Oil & Gas GP, LLC, MarkWest Utica EMG, LLC, Medallion Midstream, LLC, Plains All American GP LLC and Tallgrass MLP GP LLC.Mr. Raymond manages various private investments through personally held Lynx Holdings, 91Table of Contents LLC. Mr. Raymond received a B.S.M. from the A.B. Freeman School of Business at Tulane University with dual concentrations in finance and accountingand currently sits on the Board of the Business School Council. Patrick Wade. Mr. Wade has served as a member of the High Sierra board since November 2008 and a member of the board of directors of ourgeneral partner since 2012. Mr. Wade has twenty years of experience in the energy sector. In 2002, Mr. Wade co-founded Tiger Midstream Investments, anatural gas midstream development and investment company that was involved primarily in the United States Rockies. From 2005 to 2007, Mr. Wade was aManaging Director at Bear Energy LP, responsible for investments in natural gas midstream infrastructure, as well as contracting for a diverse portfolio ofnatural gas storage capacity. In 2008, Mr. Wade joined The Energy & Minerals Group (“EMG”), as a Managing Director in the Houston office. EMG is themanagement company for a series of specialized private equity funds. EMG focuses on investing across various facets of the global natural resource industryincluding the upstream and midstream segments of the energy complex. EMG has approximately $13.3 billion of regulatory assets under management(RAUM) and approximately $6.1 billion in commitments have been allocated across the energy sector since inception. EMG is the managing partner of EMGNGL HC LLC. Mr. Wade’s primary focus is making direct investments across the natural resources industry. In addition, Mr. Wade serves on the board ofdirectors of Medallion Midstream, L.L.C. and Ferus Inc. Mr. Wade received his Bachelor’s degree from the University of Oklahoma in 1991 and his M.B.A.from the Jesse H. Jones School of Management at Rice University in 1995. Mr. Wade brings extensive financial and industry experience to the board. With almost 20 years of experience in the energy sector, Mr. Wade providesvaluable insight into our business. Director Appointment Rights The Limited Liability Company Agreement of NGL Energy Holdings LLC grants certain parties the right to designate a specified number of personsto serve on the board of directors. SemGroup Corporation has the right to designate two persons to serve on the board of directors, and has designated CarlinG. Conner and Kevin C. Clement. EMG NGL HC LLC has the right to designate two persons to serve on the board of directors, and has designated JohnRaymond and Patrick Wade. The Coady Group (which consists of certain entities controlled by Shawn W. Coady and Todd M. Coady) and the IEP Parties(which consists of certain entities controlled by H. Michael Krimbill, Bradley K. Atkinson, and another investor who is not a member of management of thePartnership) each have the right to designate one person to serve on the board of directors. The Coady Group has designated Shawn W. Coady and the IEPParties 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 board of directors and its committees regularly review material operational, financial, compensation and compliance risks with seniormanagement. In particular, the audit committee is responsible for risk oversight with respect to financial and compliance risks and risks relating to our auditand independent registered public accounting firm. Our compensation committee considers risk in connection with its design and evaluation of compensationprograms for our senior management. Each committee regularly reports to the board of directors. Audit Committee The board of directors of our general partner has established an audit committee. The audit committee assists the board in its oversight of 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. 92Table of Contents 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 andthat each member of the audit committee is financially literate. In compliance with the requirements of the NYSE, all of the members of the audit committee areindependent 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. Conner, Mr. Cropper, and Mr. Kneale currently serve on the compensation committee. Mr. Cropper serves as the chairman. The board ofdirectors has determined that Mr. Cropper and Mr. Kneale are independent directors under applicable NYSE and Exchange Act rules. The NYSE does notrequire a listed publicly-traded limited partnership to have a compensation committee consisting entirely of independent directors. Section 16(a) Beneficial Ownership Reporting Compliance Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who own more than 10% of a 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. 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, 2014, except as described in the paragraph below. SemStream, L.P., a wholly-owned subsidiary of SemGroup Corporation, transferred common units to SemGroup Corporation on June 6, 2013 andreported this on Form 4 on June 10, 2013. EMG NGL HC LLC sold common units on June 6, 2013 and reported this on Form 4 on June 10, 2013. On July 1,2013, certain restricted common units that were granted pursuant to an incentive compensation plan vested. Upon vesting of these common units, certainofficers elected to have the Partnership withhold a portion of the common units, in return for which the Partnership remitted withholding payments to taxingauthorities on the officers’ behalf. The resultant changes in ownership of common units for Patrice A. Lemon, Atanas H. Atanasov, James J. Burke,Shawn W. Coady, Todd M. Coady, Jeffrey A. Herbers, and David C. Kehoe were reported on Form 4 on July 30, 2013. Atanas H. Atanasov received a grant ofrestricted common units pursuant to an incentive compensation plan on July 16, 2013, and reported this on Form 4 on July 30, 2013. Corporate Governance The board of directors of our general partner has adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers, or Code 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 93Table of Contents made by telephone at (918) 481-1119. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report andshould not be considered part of this or any other report that we file with or furnish to the SEC. Meeting of Non-Management Directors and Communications with Directors At each quarterly meeting of the audit committee and/or the board of directors of our general partner, our independent directors meet in an 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 “2014” in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31,2014. Introduction The board of directors of our general partner has responsibility and authority for compensation-related decisions for our executive officers. 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 2014 were: · H. Michael Krimbill — Chief Executive Officer· Atanas H. Atanasov — Chief Financial Officer and Treasurer· James J. Burke — President· Shawn W. Coady — President and Chief Operating Officer, Retail Division· David C. Kehoe — Executive Vice President, NGL Crude Logistics Compensation Philosophy Our compensation philosophy emphasizes pay-for-performance, focused primarily on the ability to increase sustainable quarterly distributions 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. 94Table of Contents Factors Enhancing Alignment with Unitholder Interests · Majority of officer pay is incentive compensation at risk based on annual financial performance and growth in unitholder value· Equity-based incentives are the largest single component of officer compensation· 50% of officers’ equity awards subject to achievement of above-median total unitholder return relative to our performance peer group· No excise tax gross-ups· Compensation committee engages an independent compensation adviser Compensation Setting Process Our compensation program for our named executive officers supports our philosophy of pay-for-performance. · Role of Management: Our Chief Executive Officer also provides periodic recommendations to the compensation committee and the board ofdirectors regarding the compensation of our other named executive officers. · Role of the Compensation Committee’s Consultant: In carrying out its responsibilities for establishing, implementing and monitoring theeffectiveness of our executive compensation philosophy, plans and programs, our compensation committee has the authority to engage outsideexperts to assist in its deliberations. During fiscal 2014, the compensation committee received compensation advice and data from Pearl Meyer &Partners (“PM&P”). PM&P conducted a competitive review of the principal components of compensation for our executives, including ourNamed Executive Officers. PM&P also provided input on peer group selection (compensation and performance peers), and short and long-termincentive plan design. The compensation committee reviewed the services provided by PM&P and determined that they are independent inproviding executive compensation consulting services. In making this determination, the compensation committee noted that during fiscal 2014: · PM&P did not provide any services to the Company or management other than compensation consulting services requested by or with theapproval of the compensation committee;· PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or humanresource outsourcing;· PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and procedures designed toensure independence;· Fees paid to PM&P by NGL Energy Partners during fiscal 2014 were less than 1% of PM&P’s total revenue;· None of the PM&P consultants working on Company matters had any business or personal relationship with compensation committeemembers;· None of the PM&P consultants working on Company matters (or any consultants at PM&P) had any business or personal relationshipwith any executive officer of the Company; and· None of the PM&P consultants working on Company matters own Company stock. The compensation committee continues to monitor the independence of its compensation consultant on a periodic basis. The compensation committeeis considering the recommendations provided by PM&P and is in the process of designing the fiscal 2015 compensation program. 95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: Objective SupportedElementPrimary PurposeHow Amount DeterminedAttract &RetainMotivate &Pay forPerformanceUnitholderAlignmentBase Salary· Fixed income to compensate executiveofficers for their level ofresponsibility, expertise andexperience· Based on competition in themarketplace for executivetalent and abilitiesXCash Bonus Awards· Rewards achievement of specificannual financial and operationalperformance goals· Recognizes individual contributionsto our performance· Based on the namedexecutive officer’s relativecontribution to achieving orexceeding annual goalsXXXLong-Term EquityIncentive Awards· Motivates and rewards theachievement of long-termperformance goals, includingincreasing the market price of ourcommon units and the quarterlydistributions to our unitholders· Provides a forfeitable long-termincentive to encourage executiveretention· Based on the namedexecutive officer’s expectedcontribution to long-termperformance goalsXXX Base Salary The compensation committee periodically reviews the base salaries of our named executive officers and may recommend adjustments as necessary.We do not make automatic annual adjustments to base salary. · Mr. Krimbill’s base salary of $120,000 was originally determined as part of the negotiations for our formation transactions. In setting the basesalaries, the parties considered various factors, including the compensation needed to attract or retain the officers, the historical compensation ofthe officers, and each officer’s expected individual contribution to our performance. At the request of Mr. Krimbill, the parties agreed that heshould receive a lower base salary than our other executive officers at the time because, as our Chief Executive Officer, a significant portion ofhis compensation should be performance-based, to further align his interests with the interests of our unitholders. In February 2012, the basesalary of Mr. Krimbill was reduced to $60,000, based on our operating and financial performance as a result of an unusually warm winter. Thebase salary of Mr. Krimbill was restored to $120,000 effective November 12, 2012. · Mr. Atanasov’s base salary of $195,000 was negotiated prior to his joining our management team in November 2011. The base salary ofMr. Atanasov was increased in July 2013 to $250,000. · Mr. Burke and Mr. Kehoe’s base salaries, which became effective on June 19, 2012 when they joined our management team upon completion ofour merger with High Sierra, were $353,000 and $293,000, respectively. The base salaries of Mr. Burke and Mr. Kehoe were increased inJuly 2013 to $375,000 and $340,000, respectively. · Dr. Coady’s base salary of $300,000 was determined as part of the negotiations for our formation transactions. In February 2012, the basesalary of Dr. Coady was reduced to $200,000 based on our operating and financial performance as a result of an unusually warm winter. Thebase salary of Dr. Coady was restored to $300,000 effective November 12, 2012. 96Table of Contents Cash Bonus Awards Neither the compensation committee nor the Board of Directors has yet approved bonuses to be paid to the named executive officers based onperformance during fiscal 2014. For fiscal 2014, none of the named executive officers was subject to a formal bonus plan, and therefore annual bonus awardsfor fiscal 2014 performance, if any, would be discretionary. During fiscal 2014, bonuses were paid to the named executive officers. These bonuses were approved by the Board of Directors in fiscal 2014 at therecommendation of the compensation committee, which determined the bonus amounts using recommendations provided by the Chief Executive Officer. Thebonus amounts were determined based on the contributions of the individuals since the time they joined the Partnership through the date of the bonus andbased on expectations of future performance. The amounts of these bonuses were as follows: Atanas H. Atanasov195,000James J. Burke450,000Shawn W. Coady200,000David C. Kehoe425,000 Also during fiscal 2014, the compensation committee approved a bonus of $475,000 to be paid to H. Michael Krimbill. The bonus amount wasdetermined based on the contributions of Mr. Krimbill since the time the Partnership was formed through the date of the bonus and based on expectations offuture performance. The cash bonus program for fiscal 2015 is still under development, as further described in the “Fiscal 2015 Compensation Program” section below. Long-Term Equity Incentive Awards In May 2011, our general partner adopted the NGL Energy Partners LP 2011 Long-Term Incentive Plan (the “LTIP”) for the employees and directorsof our general partner who perform services for us. The LTIP authorizes the grant of restricted units, phantom units, unit options, unit appreciation rights andother unit-based awards. On June 27 2013, Mr. Atanasov was granted 10,000 restricted units in recognition of his increased responsibilities. The restricted units will vest infive equal annual installments, the first of which vests on July 1, 2014, subject to the continued service of Mr. Atanasov. The awards may also vest in theevent of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vestingperiod. Previously, the compensation committee granted awards of restricted units to certain of our named executive officers during fiscal year 2013. Initialgrants under the LTIP were awarded in June 2012 upon formation of the award program. Additional grants were awarded in December 2012, primarily forofficers and employees who joined the Partnership in the merger with High Sierra. The fiscal year 2013 awards were designed to incentivize retention and toenhance unitholder alignment by rewarding the officer if the value of common units increases over time. These awards vest in tranches, subject to thecontinued service of the recipient. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions willaccrue to or be paid on the restricted units during the vesting period. The long-term equity incentive award program for fiscal 2015 is still under development, as further described in the “Competitive Review and Fiscal2015 Compensation Program” section below. 97Table of Contents Severance and Change in Control Benefits We do not provide any severance or change of control benefits to our named executive officers. The board of directors has the option to accelerate thevesting of the restricted units in the event of a change in control of the Partnership, although it is not under any obligation to do so. 401(k) Plan We have established a defined contribution 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred basis. 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. 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. Competitive Review and Fiscal 2015 Compensation Program During fiscal 2014, PM&P conducted a competitive review of our executive compensation program and provided input to the compensationcommittee regarding competitive compensation levels and compensation program design. In order to provide guidance to the compensation committee regardingcompetitive rates of compensation, PM&P collected pay data from the following sources: · Compensation surveys including data from published compensation surveys representative of other energy industry and broader generalindustry companies with revenues of between $1 billion and $6 billion; and· Peer group data including pay data from 10-K and proxy filings for a group of 20 publicly-traded midstream oil & gas partnerships of similarsize and scope to us. Compensation Peer Group Companies AmeriGas Partners LPEnbridge Energy Partners, L.P.Crosstex Energy LPFerrellgas Partners LPNuStar Energy L.P.DCP Midstream Partners LPStar Gas Partners, L.P.Targa Resources Partners LPMartin Midstream Partners LPSuburban Propane Partners, L.P.Buckeye Partners, L.P.Regency Energy Partners LPONEOK Partners, L.P.Genesis Energy LPBoardwalk Pipeline Partners, LPKinder Morgan Energy Partners, L.P.Crestwood Midstream Partners LPWestern Gas Partners LPWilliams Partners L.P.Magellan Midstream Partners LP PM&P defines “market” as the combination of survey data and peer group data. The compensation committee is considering the recommendationsprovided by PM&P and is in the process of designing the fiscal 2015 compensation program. 98Table of Contents Employment Agreements We do not have employment agreements with any of our named executive officers. Deductibility of Compensation We believe that the compensation paid to the named executive officers is generally fully deductible for federal income tax purposes. We are a 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 2013 was less than the Section 162(m) threshold of $1,000,000. Although the value ofthe restricted units granted during fiscal 2014 are reflected in the Summary Compensation Table below, the grant is subject to vesting conditions. The vestingof the award is a taxable event, but the granting of the award is not. Compensation Committee Report The compensation committee of the board of directors of our general partner has reviewed and discussed the Compensation Discussion and 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)Carlin G. ConnerJames C. Kneale 99Table of Contents 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. Summary Compensation Table for 2014 The following table includes the compensation earned by our named executive officers for fiscal years 2012-2014. RestrictedAll OtherUnitCompensationFiscalSalaryBonus (1)Awards (2)(3)TotalName and Position Year($)($)($)($)($) H. Michael Krimbill2014117,693475,000—6,493599,186Chief Executive Officer201382,849——2,49285,3412012110,769——2,700113,469 Atanas H. Atanasov (4) 2014232,500195,000259,6967,038694,234Chief Financial Officer2013195,000—743,4402,738941,178 James J. Burke (5) 2014367,385450,000—24,651842,036President2013275,630—836,40013,0151,125,045 Shawn W. Coady2014300,000200,000—19,630519,630President and Chief Operating Officer,Retail Division20132012238,462285,587——613,700—17,73020,950869,892306,537 David C. Kehoe (5) 2014323,731425,000—15,932764,663Executive Vice President,NGL Crude Logistics2013228,781—836,40013,4901,078,671 (1) Amounts for fiscal 2014 include discretionary bonuses paid in 2014 based on contributions of the individuals since the time they joined thePartnership through the date of the bonus and based on expectations of future performance. Amounts payable based on fiscal 2014performance, if any, have not yet been determined, but are expected to be determined during the first or second quarters of fiscal 2015. (2) The fair values of the restricted units shown in the table above were calculated based on the closing market prices of our limited partner 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 tothe grant 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. (3) The amounts in this column include matching contributions to our 401(k) plan. Amounts for Mr. Burke and Mr. Kehoe each include $8,124for club memberships. The fiscal 2014 amount for Mr. Burke includes $9,000 for a car allowance. Amounts in this column for Dr. Coadyinclude matching contributions to our 401(k) plan of $8,750 for fiscal 2014. Amounts in this column for Dr. Coady also include theincremental cost of the use of a company car, including depreciation, maintenance, insurance, and fuel, of $10,880 for fiscal 2014. 100Table of Contents (4) Mr. Atanasov was not a named executive officer prior to fiscal 2013. (5) Mr. Burke and Mr. Kehoe joined our management team upon completion of our merger with High Sierra on June 19, 2012. Restricted Unit Awards During fiscal 2014, the board of directors granted an award of restricted units to Mr. Atanasov. The restricted units will vest in tranches, subject tohis continued service. The restricted units may also vest in the event of a change in control, at the discretion of the board of directors. No distributions willaccrue to or be paid on the restricted units during the vesting period. 2014 Grants of Plan Based Awards Table The number of restricted units granted to our named executive officers, and their grant date fair value, are summarized below: Grant Date Fair ValueTotal Number ofof Restricted UnitsGrantRestricted UnitsAwardedNameDateAwarded($)H. Michael Krimbilln/a——Atanas H. AtanasovJune 27, 201310,000259,696James J. Burken/a——Shawn W. Coadyn/a——David C. Kehoen/a—— The fair value of the restricted units shown in the table above were calculated based on the closing market price of our limited partner units on 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 at 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. Outstanding Equity Awards as of March 31, 2014 The number of unvested restricted units outstanding at March 31, 2014, and their fair values at March 31, 2014, are summarized below: Fair Value of UnvestedNumber of Restricted UnitsRestricted UnitsThat Have Not Yet Vestedas of March 31, 2014Nameat March 31, 2014($)H. Michael Krimbill——Atanas H. Atanasov32,0001,200,960James J. Burke40,0001,501,200Shawn W. Coady10,000375,300David C. Kehoe40,0001,501,200 The fair values of the restricted units shown in the table above were calculated based on the closing market price of our limited partner units atMarch 31, 2014 of $37.53. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. 101Table of Contents 2014 Option Exercises and Stock Vested On July 1, 2013, certain of the restricted units granted vested. The value of the awards on the vesting date shown in the table below was calculatedbased of the closing market price of $30.49 per unit on the vesting date. Number of Units AcquiredValue Realized on VestingName on Vesting($)H. Michael Krimbill——Atanas H. Atanasov10,000304,900James J. Burke10,000304,900Shawn W. Coady10,000304,900David C. Kehoe10,000304,900 Upon vesting, certain of the named executive officers elected for us to remit payments to taxing authorities in lieu of issuing units. Mr. Atanasovelected to have 3,260 units withheld, Mr. Burke elected to have 3,181 units withheld, Dr. Coady elected to have 4,235 units withheld, and Mr. Kehoe electedto have 3,184 units withheld for this purpose. Subsequent to vesting, these individuals received distributions of $1.54 on each of the vested units during the fiscal year ended March 31, 2014. Potential Payments upon Termination or Change in Control We do not provide any severance or change of control benefits to our executive officers. The board of directors has the option to accelerate the 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, 2014” table above. Director Compensation Officers or employees of our general partner and its affiliates who also serve as directors do not receive additional compensation for their service as 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 $5,000 for each member of the audit committee other than the chairman. All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Eachdirector is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law. Director Compensation for Fiscal 2014 The following table sets forth the compensation earned during fiscal 2014 by each director who is not an officer or employee of our general partner: Fees Earned orRestricted UnitPaid in CashAwardsTotalName ($)($)($)Stephen L. Cropper65,000—65,000Bryan K. Guderian65,000—65,000James C. Kneale70,000—70,000 These directors did not receive any equity grants under the LTIP during fiscal 2014. During fiscal 2013, each of these directors received a grant ofunvested units under the LTIP. These units vest in tranches, contingent on the continued service of the directors. During fiscal 2014, a tranche of 5,000 unitsvested for each director. Subsequent to the vesting, these individuals received distributions of $1.54 on each of the vested units. 102Table of Contents Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters Security Ownership of Certain Beneficial Owners and Management The following table sets forth the beneficial ownership, as of May 23, 2014 of our units by: · each person or group of persons known by us to be a beneficial owner of more than 5% of our outstanding units; · each director of our general partner; · each named executive officer of our general partner; and · all directors and executive officers of our general partner as a group. Percentage ofTotal CommonPercentage ofandCommonPercentage ofSubordinatedSubordinatedSubordinatedUnitsCommon UnitsUnitsUnitsUnitsBeneficiallyBeneficiallyBeneficiallyBeneficiallyBeneficiallyBeneficial OwnersOwnedOwned (1)OwnedOwned (1)Owned (1)5% or greater unitholders (other than officers anddirectors):SemGroup Corporation (2) 9,133,40912.23%——11.33%Oppenheimer Funds, Inc. (3)8,559,17811.46%——10.62%Goldman Sachs Asset Management, L.P. (4)4,938,2296.61%——6.12%Directors and officers:Atanas H. Atanasov (5)43,908*——*James J. Burke (6) 308,259*——*Kevin C. Clement5,000*——*Shawn W. Coady (7) 1,326,3701.78%1,125,35119.01%3.04%Carlin G. Conner—————Stephen L. Cropper25,000*——*Bryan K. Guderian20,000*——*David C. Kehoe (8) 315,823*——*James C. Kneale (9) 17,500*——*H. Michael Krimbill (10) 970,5571.30%497,8468.41%1.82%Vincent J. Osterman (11)3,955,4375.29%——4.94%Patrick Wade—————John T. Raymond (12)2,176,6342.91%——2.70% All directors and executive officers as a group (15persons) (13)10,491,43814.04%2,747,19846.41%16.45% * Less than 1.0% (1) Based on 74,706,160 common units and 5,919,346 subordinated units outstanding at May 23, 2014. (2) The mailing address for SemGroup Corporation is 6120 S. Yale Avenue, Suite 700, Tulsa, OK 74136. Carlin G. Conner, a member of theboard of directors of our general partner, serves as President and Chief Executive Officer, and as a Director of SemGroup Corporation.Kevin C. Clement, a member of the board of directors of our general partner, serves as President of SemStream, L.P. and SemGas, L.P., eacha subsidiary of SemGroup 103Table of Contents Corporation. Each of Messrs. Conner and Clement disclaims beneficial ownership of these common units. SemGroup Corporation also ownsan 11.78% interest in our general partner. The information related to SemGroup Corporation, including the number of common units held, isbased upon its Form 4 filed with the SEC on June 10, 2013. (3) The mailing address for OppenheimerFunds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281.OppenheimerFunds, Inc. reported shared voting and dispositive power with respect to all common units beneficially owned. The informationrelated to OppenheimerFunds, Inc. is based on OppenheimerFunds, Inc.’s Form 13G filed with the SEC on April 10, 2014. (4) The mailing address for Goldman Sachs Asset Management, L.P. is 200 West Street, New York, NY 10282. Goldman Sachs AssetManagement, L.P. reported shared voting and dispositive power with respect to all common units beneficially owned. The information relatedto Goldman Sachs Asset Management, L.P. is based on Goldman Sachs Asset Management, L.P.’s Form 13G filed with the SEC onFebruary 13, 2014. (5) Atanas H. Atanasov also owns a 0.40% interest in our general partner. (6) Impact Development, LLC owns 33,872 of these common units. Impact Development, LLC is solely owned by James J. Burke, who may 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 2.87% interest in our general partner. (7) Shawn W. Coady owns 21,330 of these common units. SWC Family Partnership LP owns 1,195,040 of these common units 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. (8) David C. Kehoe also owns a 0.75% interest in our general partner through DCK GP, LLC, of which he owns 100% of the membershipinterests. (9) Of these common units, 12,500 are owned by the Suzanne and Jim Kneale Living Trust. (10) Krim2010, LLC owns 407,002 of these common units and all of these subordinated units. Krimbill Enterprises LP, H. Michael Krimbill andJames 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 except to the extent of his pecuniary interest therein. H. Michael Krimbill also owns a 14.81%interest in our general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests. KrimGP2010 LLC owns363,555 of these common units. KrimGP2010 LLC is solely owned by H. Michael Krimbill. H. Michael Krimbill may be deemed to havesole voting and investment power over these units. (11) Vincent J. Osterman owns 30,000 of these common units. The remaining common units are owned by AO Energy, Inc. (110,587 commonunits), E. Osterman, Inc. (394,350 common units), E. Osterman Gas Services, Inc. (301,700 common units), E. Osterman Propane, Inc.(669,300 common units), Milford Propane, Inc. (559,784 common units), Osterman Family Foundation (192,816 common units),Osterman Propane, Inc. (1,445,850 common units), Propane Gas, Inc. (36,450 common units) and Saveway Propane Gas Service, Inc.(214,600 common units). Each of these holding entities may be deemed to have sole voting and investment power over its own common unitsand Propane Gas, LLC, as sole shareholder of Propane Gas, Inc., may be deemed to have sole voting and investment power over thosecommon units. Vincent J. Osterman is a director, executive officer and shareholder or member of each of these entities and may be deemed tohave sole voting and investment power over 729,300 common units and shared voting and investment power (with his father, ErnestOsterman) over 3,281,137 common units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. Vincent J.Osterman also owns a 0.75% interest in our general partner through VE Properties XI LLC. 104Table of Contents (12) EMG NGL HC, LLC owns all of these common units. John T. Raymond is the Chief Executive Officer and Managing Partner of NGP MRGP, LLC, the general partner of NGP MR, LP, the general partner of NGP Midstream & Resources, LLC, a member holding a majorityinterest in EMG NGL HC, LLC. John T. Raymond may be deemed to have shared voting and investment power over these units, butdisdains beneficial ownership except to the extent of his pecuniary interest therein. EMG I NGL GP Holdings, LLC, an affiliate of EMG NGLHC, LLC, owns a 6.73% interest in our general partner. EMG II NGL GP Holdings, LLC, an affiliate of EMG NGL HC, LLC, owns a5.36% interest in our general partner. (13) The directors and executive officers of our general partner also collectively own a 68.00% interest in our general partner. Unless otherwise noted, each of the individuals listed above is believed to have sole voting and investment power with respect to the units beneficiallyheld by them. The mailing address for each of the officers and directors of our general partner listed above is 6120 South Yale Avenue, Suite 805, Tulsa, OK74136. Securities Authorized for Issuance Under Equity Compensation Plan The following table sets forth information regarding the securities that may be issued under the NGL Energy Partners LP Long-Term Incentive Plan,or the LTIP, at March 31, 2014. Number of 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 bySecurity Holders———Equity Compensation Plans Not Approved bySecurity Holders(2)1,311,100—6,169,869Total1,311,100—6,169,869 (1) The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of our issued and 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 (“IPO”) in May 2011. The adoption ofthe LTIP did not require the approval of our unitholders. Item 13. Certain Relationships and Related Transactions and Director Independence Our directors, executive officers, and greater than 5% unitholders collectively own an aggregate of 33,122,254 common units and 2,747,198subordinated units, representing an aggregate 44.52% limited partner interest in us. In addition, our general partner owns a 0.1% general partner interest in usand all of our incentive distribution rights. Distributions and Payments to Our General Partner and Its Affiliates Our general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, 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 IDRs. Our general partner is entitled to receive incentivedistributions 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 IPO and,consequently, are not the result of arm’s length negotiations. 105Table of Contents 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 IPO· 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 IDRs. 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 33,122,254 common units and 2,747,198 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 $0.1 million on its generalpartner interest and our directors, officers, and greater than 5% owners wouldreceive an aggregate annual distribution of $48.5 million on their common andsubordinated 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. Payments to our general partner and its affiliatesOur general partner and its affiliates do not receive any management fee or othercompensation for the management of our business and affairs, but they arereimbursed for all expenses that they incur on our behalf, including general andadministrative expenses. As the sole purpose of the general partner is to act asour 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 IDRs will either be sold to the new general partner for cash or converted intocommon units, in each case for an amount equal to the fair market value ofthose interests. Liquidation Stage LiquidationUpon our liquidation, our partners, including our general partner, will beentitled to receive liquidating distributions according to their respective capitalaccount balances. 106Table of Contents Related Party Transactions SemGroup Corporation SemGroup Corporation (“SemGroup”) holds ownership interests in us and in our general partner, and has the right to appoint two members to theboard of directors of our general partner. We sell product to and purchase product from affiliates of SemGroup. These transactions are included withinrevenues and cost of sales in our consolidated statements of operations. The transactions with SemGroup are summarized below for the year ended March 31,2014 (in thousands): Sales to SemGroup$306,780Purchases from SemGroup445,951 WPX Energy, Inc. Bryan Guderian is a member of our board of directors and an executive officer of WPX Energy, Inc. (“WPX”). Since our December 2013 acquisitionof Gavilon Energy, we (through the prior Gavilon Energy operations) have purchased crude oil and natural gas from and sold crude oil and natural gas toWPX. These transactions are recorded within revenues and cost of sales in our consolidated statement of operations. The relationship between Gavilon Energyand WPX preceded our acquisition of Gavilon Energy. These transactions were entered into in the ordinary course of business and in accordance with ournormal procedures for purchases and sales of crude oil and natural gas. The transactions with WPX are summarized below for the year ended March 31, 2014(in thousands): Sales to WPX$101,303Purchases from WPX157,729 Other Transactions Subsequent to our merger with High Sierra, we purchased goods and services from several entities that are partially owned by Mr. Burke, Mr. Kehoeand by other members of management. These transactions are summarized below for the year ended March 31, 2014: Mr. Kehoe’sMr. Burke’sNature ofAmountOwnership InterestOwnership InterestEntityPurchasesPurchasedin Entityin Entity(in thousands)Cowhouse Partners, L.L.C.Terminaling services andtransportation services$60527.5%—Impact Energy Services LLCCondensate purchases191—50%Petro Source Consulting, LLCEquipment170100%—Fluid Services, LLCCrude oil purchases andtransportation services1,09720%— Subsequent to our merger with High Sierra, we provided goods and services to an entity that is partially owned by Mr. Burke. These transactions aresummarized below for the year ended March 31, 2014: Mr. Burke’sNature ofRevenuesOwnership InterestEntityServicesGeneratedin Entity(in thousands)Impact Energy Services LLCCondensate sales$52550% We rent office space from VE III LLC and VE Properties V, which are entities that are owned by Vincent J. Osterman and his father. We paid rent of$142,784 during the year ended March 31, 2014 to these entities. We purchase vehicles from Hicks Motor Sales, which is an entity owned by Shawn W. Coady and Todd M. Coady. We paid $696,900 during theyear ended March 31, 2014 to this entity for vehicle purchases. Todd Coady, an executive officer of the Partnership, is the brother of Shawn Coady, who also is an executive officer of the Partnership and a memberof the board of directors. Todd Coady’s annual base compensation was $200,000 until July 1, 2013, when it was increased to $225,000. During fiscal 2014,Todd Coady was granted a cash bonus of $125,000. Todd Coady was also eligible to participate in the Partnership’s 401(k) plan, and he received $5,877 ofemployer matching contributions during the year ended March 31, 2014. Timothy Osterman, an employee of the Partnership, is the son of Vincent J. Osterman, who is an executive officer of the Partnership and a memberof the board of directors. Timothy Osterman’s base compensation during the year ended March 31, 2014 was $83,200. During fiscal 2014,Timothy Osterman was granted a cash bonus of $90,000. Timothy Osterman was also eligible to participate in the Partnership’s 401(k) plan, and he received$5,196 of employer matching contributions during the year ended March 31, 2014. 107Table of Contents Registration Rights Agreement We have entered into a registration rights agreement (as amended, the “Registration Rights Agreement”) with certain third parties (the “registrationrights parties”) pursuant to which we agreed to register for resale under the Securities Act common units, including any common units issued upon theconversion of subordinated units, owned by the parties to the Registration Rights Agreement. In connection with our initial public offering, we grantedregistration rights to the individuals and entities that owned all of our then-outstanding common units (collectively, the “NGL Energy LP Investor Group”),and subsequently, we have granted registration rights in connection with several acquisitions. We will not be required to register such common units if anexemption from the registration requirements of the Securities Act is available with respect to the number of common units desired to be sold. Subject tolimitations specified in the Registration Rights Agreement, the registration rights of the registration rights parties include the following: Demand Registration Rights. Certain registration rights parties deemed “Significant Holders” under the agreement may, to the extent that theycontinue to own more than 4% of our common units, require us to file a registration statement with the Securities and Exchange Commission registering theoffer and sale of a specified number of common units, subject to limitations on the number of requests for registration that can be made in any twelve-monthperiod as well as customary cutbacks at the discretion of the underwriters relating to a potential offering. All other registration rights parties are entitled to noticeof a Significant Holder’s exercise of its demand registration rights and may include their common units in such registration. We can only be required to file atotal of eight registration statements upon the Significant Holders’ exercise of these demand registration rights and are only required to effect demandregistration if the aggregate proposed offering price to the public is at least $10.0 million. Piggyback Registration Rights. If we propose to file a registration statement under the Securities Act to register our common units, the registrationrights parties are entitled to notice of such registration and have the right to include their common units in the registration, subject to limitations that theunderwriters relating to a potential offering may impose on the number of common units included in the registration. These counterparties also have the right toinclude their units in our future registrations, including secondary offerings of our common units. Expenses of Registration. With specified exceptions, we are required to pay all expenses incidental to any registration of common units, excludingunderwriting discounts and commissions Review, Approval or Ratification of Transactions with Related Parties The board of directors of our general partner has adopted a Code of Business Conduct and Ethics that, among other things, sets forth our 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); · 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. 108Table of Contents 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 years ended March 31, 2014 and 2013: 20142013 Audit fees(1)$2,531,229$1,861,979Audit-related fees(2)—47,100Tax fees(3)—66,711All other fees70,091—Total$2,601,320$1,975,790 (1) Includes fees for audits of the Partnership’s financial statements, reviews of the related quarterly financial statements, and services that 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 our 401(k) defined contribution plan. (3) Includes fees for tax services in connection with tax compliance and consultation on tax matters. Audit Committee Approval of Audit and Non-Audit Services The audit committee of the board of directors of our general partner has adopted a pre-approval policy with respect to services which may 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. 109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 (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 110Table of Contents ExhibitNumberDescriptionConditioning Services, Inc. (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed onFebruary 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) 2.13Waiver and Second Amendment to Asset Purchase Agreement dated as of February 3, 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 2.3 to the Current Report on Form 8-K/A (File No. 001-35172) filed with the SEC onApril 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., PecosGathering & Marketing, L.L.C., Striker Oilfield Services, LLC, Transwest Leasing, LLC, the owners of the Pecos Entities, NGLEnergy 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) 2.18LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWLPearsall SWD, LLC, OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporatedby reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.19LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWLKarnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated byreference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.20LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC,Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporatedby reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.21LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, TerryBailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated byreference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.22LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWLOperating, LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLCand High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172)filed with the SEC on August 7, 2013) 111Table of Contents ExhibitNumberDescription2.23Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP,Gavilon, LLC and Gavilon Energy Intermediate, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on December 5, 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 to theRegistration 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 3.1 tothe 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 on Form 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) 3.11Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as ofAugust 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onAugust 7, 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) 112Table of Contents ExhibitNumberDescription4.4Amendment 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 between NGLEnergy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (FileNo. 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 and betweenNGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust,Animosus Trust and Nitor Trust (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filedwith the SEC on November 19, 2012) 4.8Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by and amongNGL Energy Partners LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to the Current Reporton Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 4.9Call 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) 4.10Call 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) 4.11Note 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) 4.12Amendment 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) 4.13Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 9, 2013) 4.14Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s6.65% senior secured notes due 2022 signatory thereto (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, 2013) 4.15Amendment No. 4 to Note Purchase Agreement, dated as of November 5, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8,2013) 4.16Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 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 onDecember 30, 2013) 113Table of Contents ExhibitNumberDescription4.17Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors partythereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on October 16, 2013) 4.18Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013) 4.19*First Supplemental Indenture, dated as of December 2, 2013, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee 4.20*Second Supplemental Indenture, dated as of April 22, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiary party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee 4.21Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., theGuarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporatedby reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013) 4.22Registration Rights Agreement, dated December 2, 2013, by and among NGL Energy Partners LP and the purchasers set forth onSchedule A thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SECon December 5, 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 toExhibit 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 party theretoand Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to the Current Reporton 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 the CurrentReport 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) 10.6Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, eachsubsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank TrustCompany Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “IssuingBank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onOctober 3, 2013) 10.7Amendment No. 4 to Credit Agreement, dated as of November 5, 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 November 8,2013) 114Table of Contents ExhibitNumberDescription10.8Amendment No. 5 to Credit Agreement, dated as of December 23, 2013, among NGL Energy Operating, LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank and Trust Company Americas and the other financial institutions party thereto(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30,2013) 10.9Facility Increase Agreement among NGL Energy Operating, LLC, Deutsche Bank Trust Company Americas and the other financialinstitutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with theSEC on January 3, 2014) 10.10Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed onSchedule A thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SECon December 5, 2013) 10.11+Letter Agreement among Silverthorne Energy Holdings LLC, Shawn W. Coady and Todd M. Coady dated October 14, 2010(incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 10.12+NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K(File No. 001-35172) filed on May 17, 2011) 10.13+Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long Term Incentive Plan (incorporated by 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 101.SCH**XBRL Taxonomy Extension Schema Document 101.CAL**XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF**XBRL Taxonomy Extension Definition Linkbase Document 101.LAB**XBRL Taxonomy Extension Label Linkbase Document 101.PRE**XBRL Taxonomy Extension Presentation Linkbase Document * Exhibits filed with this report ** Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language):(i) Consolidated Balance Sheets at March 31, 2014 and 2013, (ii) Consolidated Statements of Operations for 115Table of Contents the years ended March 31, 2014, 2013, and 2012, (iii) Consolidated Statements of Comprehensive Income for the years ended March 31, 2014,2013, and 2012, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2014, 2013, and 2012 and (v) ConsolidatedStatements of Cash Flows for the years ended March 31, 2014, 2013, and 2012. + 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 May 30, 2014. 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 DirectorMay 30, 2014H. Michael Krimbill(Principal Executive Officer) /s/ Atanas H. AtanasovChief Financial OfficerMay 30, 2014Atanas H. Atanasov(Principal Financial Officer) /s/ Jeffrey A. HerbersChief Accounting OfficerMay 30, 2014Jeffrey A. Herbers(Principal Accounting Officer) /s/ James J. BurkeDirectorMay 30, 2014James J. Burke /s/ Shawn W. CoadyDirectorMay 30, 2014Shawn W. Coady /s/ Kevin C. ClementDirectorMay 30, 2014Kevin C. Clement /s/ Carlin G. ConnerDirectorMay 30, 2014Carlin G. Conner /s/ Stephen L. CropperDirectorMay 30, 2014Stephen L. Cropper /s/ Bryan K. GuderianDirectorMay 30, 2014Bryan K. Guderian /s/ James C. KnealeDirectorMay 30, 2014James C. Kneale /s/ Vincent J. OstermanDirectorMay 30, 2014Vincent J. Osterman /s/ John T. RaymondDirectorMay 30, 2014John T. Raymond /s/ Patrick WadeDirectorMay 30, 2014Patrick Wade 117Table of Contents INDEX TO FINANCIAL STATEMENTS NGL ENERGY PARTNERS LP Report of Independent Registered Public Accounting FirmF-2 Consolidated Balance Sheets at March 31, 2014 and 2013F-4 Consolidated Statements of Operations for the years ended March 31, 2014, 2013, and 2012F-5 Consolidated Statements of Comprehensive Income for the years ended March 31, 2014, 2013, and 2012F-6 Consolidated Statements of Changes in Equity for the years ended March 31, 2014, 2013, and 2012F-7 Consolidated Statements of Cash Flows for the years ended March 31, 2014, 2013, and 2012F-8 Notes to Consolidated Financial StatementsF-9 F-1Table of Contents Report of Independent Registered Public Accounting Firm 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, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, changes in equity, and cashflows for each of the three years in the period ended March 31, 2014. These financial statements are the responsibility of the Partnership’s management. Ourresponsibility 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, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period endedMarch 31, 2014 in conformity with accounting principles generally accepted in the United States of America. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal controlover financial reporting as of March 31, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committeeof Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 30, 2014 expressed an unqualified opinion. /s/ GRANT THORNTON LLP Tulsa, OklahomaMay 30, 2014 F-2Table of Contents Report of Independent Registered Public Accounting Firm PartnersNGL Energy Partners LP We have audited the internal control over financial reporting of NGL Energy Partners LP (a Delaware limited Partnership) and subsidiaries (the “Partnership”)as of March 31, 2014, based on criteria established in the 1992 Internal Control—Integrated Framework issued by the Committee of 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 Gavilon, LLC (“Gavilon”), a wholly-owned subsidiary, whose financial statements reflect total assets and revenues constituting 31 and30 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended March 31, 2014. As indicated in Management’sReport, Gavilon was acquired during the year ended March 31, 2014. Management’s assertion on the effectiveness of the Partnership’s internal control overfinancial reporting excluded internal control over financial reporting of Gavilon. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require 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, 2014, based on criteriaestablished in the 1992 Internal Control—Integrated Framework issued by COSO. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financialstatements of the Partnership as of and for the year ended March 31, 2014, and our report dated May 30, 2014 expressed an unqualified opinion on thosefinancial statements. /s/ GRANT THORNTON LLP Tulsa, OklahomaMay 30, 2014 F-3Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Balance SheetsAt March 31, 2014 and 2013(U.S. Dollars in Thousands, except unit amounts) March 31,20142013(Note 2)ASSETSCURRENT ASSETS:Cash and cash equivalents$10,440$11,561Accounts receivable - trade, net of allowance for doubtful accounts of $2,822 and $1,760, respectively900,904562,757Accounts receivable - affiliates7,44522,883Inventories310,160126,895Prepaid expenses and other current assets80,35037,891Total current assets1,309,299761,987 PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $109,564 and $50,127,respectively829,346526,437GOODWILL1,107,006555,220INTANGIBLE ASSETS, net of accumulated amortization of $116,728 and $44,155, respectively714,956441,432INVESTMENTS IN UNCONSOLIDATED ENTITIES189,821—OTHER NONCURRENT ASSETS16,7956,542Total assets$4,167,223$2,291,618 LIABILITIES AND EQUITYCURRENT LIABILITIES:Accounts payable - trade$740,211$536,055Accounts payable - affiliates76,8466,900Accrued expenses and other payables141,69085,606Advance payments received from customers29,96522,372Current maturities of long-term debt7,0808,626Total current liabilities995,792659,559 LONG-TERM DEBT, net of current maturities1,629,834740,436OTHER NONCURRENT LIABILITIES9,7442,205 COMMITMENTS AND CONTINGENCIES EQUITY, per accompanying statement:General partner, representing a 0.1% interest, 79,420 and 53,676 notional units at March 31, 2014 and2013, respectively(45,287)(50,497)Limited partners, representing a 99.9% interest -Common units, 73,421,309 and 47,703,313 units issued and outstanding at March 31, 2014 and 2013,respectively1,570,074920,998Subordinated units, 5,919,346 units issued and outstanding at March 31, 2014 and 20132,02813,153Accumulated other comprehensive income (loss)(236)24Noncontrolling interests5,2745,740Total equity1,531,853889,418Total liabilities and equity$4,167,223$2,291,618 The accompanying notes are an integral part of these consolidated financial statements. F-4Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of OperationsFor the Years Ended March 31, 2014, 2013, and 2012 (U.S. Dollars in Thousands, except unit and per unit amounts) Year Ended March 31,201420132012REVENUES:Crude oil logistics$4,558,545$2,316,288$—Water solutions143,10062,227—Liquids2,650,4251,604,7461,111,139Retail propane551,815430,273199,334Refined products1,180,895——Renewables176,781——Other437,7134,233—Total Revenues9,699,2744,417,7671,310,473 COST OF SALES:Crude oil logistics4,477,3972,244,647—Water solutions11,7385,611—Liquids2,518,0991,530,4591,086,881Retail propane354,676258,393130,142Refined products1,172,754——Renewables171,422——Other426,613——Total Cost of Sales9,132,6994,039,1101,217,023 OPERATING COSTS AND EXPENSES:Operating259,396169,79947,300General and administrative79,86052,69816,009Depreciation and amortization120,75468,85315,111Operating Income106,56587,30715,030 OTHER INCOME (EXPENSE):Earnings of unconsolidated entities1,898——Interest expense(58,854)(32,994)(7,620)Loss on early extinguishment of debt—(5,769)—Other, net861,5211,055Income Before Income Taxes49,69550,0658,465 INCOME TAX PROVISION(937)(1,875)(601) Net Income48,75848,1907,864 NET INCOME ALLOCATED TO GENERAL PARTNER(14,148)(2,917)(8) NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS(1,103)(250)12 NET INCOME ALLOCATED TO LIMITED PARTNERS$33,507$45,023$7,868 BASIC AND DILUTED INCOME PER COMMON UNIT$0.51$0.96$0.32 BASIC AND DILUTED INCOME PER SUBORDINATED UNIT$0.32$0.93$0.58 BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING:Common units61,970,47141,353,57415,169,983Subordinated units5,919,3465,919,3465,175,384 The accompanying notes are an integral part of these consolidated financial statements. F-5Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Comprehensive IncomeFor the Years Ended March 31, 2014, 2013, and 2012(U.S. Dollars in Thousands) Year Ended March 31,201420132012 Net income$48,758$48,190$7,864Other comprehensive loss, net of tax(260)(7)(25)Comprehensive income$48,498$48,183$7,839 The accompanying notes are an integral part of these consolidated financial statements. F-6Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Changes in EquityFor the Years Ended March 31, 2014, 2013, and 2012 (U.S. Dollars in Thousands, except unit and share amounts) AccumulatedLimited PartnersOtherGeneralCommonSubordinatedComprehensiveNoncontrollingTotalPartnerUnitsAmountUnitsAmountIncomeInterestsEquityBALANCES, MARCH 31, 2011$7210,933,568$47,225—$—$56$—$47,353 Distribution to partners prior toinitial public offering(4)—(3,846)————(3,850) Conversion of common units tosubordinated units—(5,919,346)(23,485)5,919,34623,485——— Sale of units in public offering,net—4,025,00075,289————75,289 Repurchase of common units—(175,000)(3,418)————(3,418) Units issued in businesscombinations, net of issuancecosts—14,432,031296,500————296,500 Contributions386—————440826 Net income (loss)8—6,472—1,396—(12)7,864 Distribution to partnerssubsequent to initial publicoffering(20)—(10,133)—(5,057)——(15,210) Other comprehensive loss—————(25)—(25)BALANCES, MARCH 31, 201244223,296,253384,6045,919,34619,82431428405,329 Distributions(1,778)—(59,841)—(9,989)—(74)(71,682) Contributions510—————403913 Units issued in businesscombinations, net of issuancecosts(52,588)24,250,258550,873———4,733503,018 Equity issued pursuant toincentive compensation plan—156,8023,657————3,657 Net income2,917—41,705—3,318—25048,190 Other comprehensive loss—————(7)—(7)BALANCES, MARCH 31, 2013(50,497)47,703,313920,9985,919,34613,153245,740889,418 Distributions(9,703)—(123,467)—(11,920)—(840)(145,930) Contributions765—————2,0602,825 Units issued in businesscombinations, net of issuancecosts—2,860,87980,591————80,591 Sales of units, net of issuancecosts—22,560,848650,155————650,155 Equity issued pursuant toincentive compensation plan—296,2699,085————9,085 Disposal of noncontrolling interest——————(2,789)(2,789) Net income14,148—32,712—795—1,10348,758 Other comprehensive loss—————(260)—(260) BALANCES, MARCH 31, 2014$(45,287)73,421,309$1,570,0745,919,346$2,028$(236)$5,274$1,531,853 The accompanying notes are an integral part of these consolidated financial statements. F-7Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Cash FlowsFor the Years Ended March 31, 2014, 2013, and 2012 (U.S. Dollars in Thousands) Year Ended March 31,201420132012OPERATING ACTIVITIES:Net income$48,758$48,190$7,864Adjustments to reconcile net income to net cash provided by operating activities:Depreciation and amortization, including debt issuance cost amortization132,65377,51317,188Loss on early extinguishment of debt—5,769—Non-cash equity-based compensation expense14,0548,670—Loss (gain) on disposal or impairment of assets3,597187(71)Provision for doubtful accounts2,1721,3151,049Commodity derivative (gain) loss43,6554,376(5,974)Earnings of unconsolidated entities(1,898)——Other312375403Changes in operating assets and liabilities, exclusive of acquisitions:Accounts receivable - trade21,3882,562(20,179)Accounts receivable - affiliates18,002(12,877)193Inventories(73,321)18,43330,268Prepaid expenses and other current assets18,90022,58514,344Accounts payable - trade(146,152)(16,913)35,747Accounts payable - affiliates67,361(6,813)4,549Accrued expenses and other payables(61,171)(9,689)366Advance payments received from customers(3,074)(11,049)4,582Net cash provided by operating activities85,236132,63490,329 INVESTING ACTIVITIES:Purchases of long-lived assets(165,148)(72,475)(7,544)Acquisitions of businesses, including acquired working capital, net of cash acquired(1,268,810)(490,805)(297,401)Cash flows from commodity derivatives(35,956)11,5796,464Proceeds from sales of assets24,6605,0801,238Investments in unconsolidated entities(11,515)——Distributions of capital from unconsolidated entities1,591——Other(195)—346Net cash used in investing activities(1,455,373)(546,621)(296,897) FINANCING ACTIVITIES:Proceeds from borrowings under revolving credit facilities2,545,5001,227,975478,900Payments on revolving credit facilities(2,101,000)(964,475)(329,900)Issuances of notes450,000250,000—Proceeds from borrowings on other long-term debt880653—Payments on other long-term debt(8,819)(4,837)(1,278)Debt issuance costs(24,595)(20,189)(2,380)Contributions2,825913440Distributions(145,930)(71,682)(19,060)Proceeds from sale of common units, net of offering costs650,155(642)74,759Repurchase of common units——(3,418)Net cash provided by financing activities1,369,016417,716198,063Net increase (decrease) in cash and cash equivalents(1,121)3,729(8,505)Cash and cash equivalents, beginning of period11,5617,83216,337Cash and cash equivalents, end of period$10,440$11,561$7,832 The accompanying notes are an integral part of these consolidated financial statements. F-8Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Note 1 — Nature of Operations and Organization NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in September 2010 by several investors(“IEP Parties”). NGL Energy Holdings LLC serves as our general partner. At March 31, 2014, our operations include: · A crude oil logistics business, the assets of which include crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet ofleased railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics business purchases crudeoil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, andother trade hubs. · A water solutions business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Ourwater solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oiland natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. · Our liquids business, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the UnitedStates and in Canada, and which provides natural gas liquids terminaling services through its 22 terminals throughout the United States andrailcar transportation services through its fleet of leased and owned railcars. Our liquids business purchases propane, butane, and otherproducts from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in thewholesale markets. · Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural,commercial, and industrial customers and to certain re-sellers in more than 20 states. We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products inback-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business,which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchasesbiodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders.These businesses were acquired in our December 2013 acquisition of Gavilon, LLC (“Gavilon Energy”). Initial Public Offering On May 17, 2011, we completed our initial public offering (“IPO”). We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. Ourproceeds from the sale of 3,850,000 common units of $71.9 million, net of total offering costs of $9.0 million, were used to repay advances under ouracquisition credit facility and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) from the underwriters’ exerciseof their option to purchase additional common units from us were used to redeem 175,000 of the common units outstanding prior to our IPO. Upon thecompletion of our IPO and the underwriters’ exercise in full of their option to purchase additional common units from us and the redemption, we hadoutstanding 8,864,222 common units, 5,919,346 subordinated units, a 0.1% general partner interest, and incentive distribution rights (“IDRs”). Acquisitions Subsequent to Initial Public Offering Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, including the following, amongothers: · In October 2011, we completed a business combination with E. Osterman Propane, Inc., its affiliated companies, and members of theOsterman family, whereby we acquired retail propane operations in the northeastern United States. · In November 2011, we completed a business combination with SemStream, L.P. (“SemStream”), whereby we acquired SemStream’s wholesalenatural gas liquids supply and marketing operations and its 12 natural gas liquids terminals. · In January 2012, we completed a business combination with seven companies associated with Pacer Propane Holding, L.P., whereby weacquired retail propane operations, primarily in the western United States. F-9Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 · In February 2012, we completed a business combination with North American Propane, Inc., whereby we acquired retail propane and distillateoperations in the northeastern United States. · In May 2012, we acquired the retail propane and distillate operations of Downeast Energy Corp (“Downeast”). These operations are primarily inthe northeastern United States. · In June 2012, we completed a business combination with High Sierra Energy, LP and High Sierra Energy GP, LLC (collectively, “HighSierra”), whereby we acquired all of the ownership interests in High Sierra. High Sierra’s businesses include crude oil gathering, transportationand marketing; water treatment, disposal, and transportation; and natural gas liquids transportation and marketing. · In November 2012, we completed a business combination whereby we acquired Pecos Gathering & Marketing, L.L.C. and certain of itsaffiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texasand New Mexico. · In December 2012, we completed a business combination whereby we acquired all of the membership interests in Third Coast Towing LLC(“Third Coast”). The business of Third Coast consists primarily of transporting crude oil via barge. · In July 2013, we completed a business combination whereby we acquired the assets of Crescent Terminals, LLC and the ownership interests inCierra Marine, LP and its affiliated companies (collectively, “Crescent”), whereby we acquired four towboats, seven crude oil barges, and acrude oil terminal in South Texas. · In July 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd. (“Big Lake”), whereby we acquired awater disposal facility in West Texas. We also entered into a development agreement that provides us the option to purchase disposal facilitiesthat may be developed in the future. During March 2014, we purchased one additional facility under this agreement. · In August 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively,“OWL”). The businesses of OWL include water disposal operations and a water transportation business in Texas. · In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), in which we acquired theownership interests in water disposal facilities in Texas and the right to purchase one additional facility, which we exercised in March 2014. · In December 2013, we acquired the ownership interests in Gavilon Energy. The assets of Gavilon Energy include crude oil terminals inOklahoma, Texas, and Louisiana and a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipelinethat originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline became operational in February 2014. The operationsof Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids. Note 2 — Significant Accounting Policies Basis of Presentation Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America(“GAAP”). The accompanying consolidated financial statements include the accounts of the Partnership and its controlled subsidiaries. All significantintercompany transactions and account balances have been eliminated in consolidation. We have made certain reclassifications to the prior period financial statements to conform with classification methods used in fiscal 2014. Thesereclassifications had no impact on previously-reported amounts of equity or net income. In addition, certain balances at March 31, 2013 were adjusted toreflect the final acquisition accounting for certain business combinations. F-10Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect thereported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amount of revenues and expenses during theperiod. 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 is based upon assumptions that market participants would use whenpricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only thecredit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurementsassume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market forthe asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate theneed for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to thefair 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, 2014 and 2013 (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, 2014 or 2013. The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3).In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fairvalue measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurementrequires 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. Contracts that qualify for the normal purchase or saleexemption and are designated as such are not accounted for as derivatives at market value and, accordingly, are recorded when the delivery occurs. F-11Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 We have not designated any financial instruments as hedges for accounting purposes. All mark-to-market gains and losses on commodity derivativeinstruments that do not qualify as normal purchases or sales, whether cash transactions or non-cash mark-to-market adjustments, are reported within cost ofsales in the consolidated statements of operations, regardless of whether the contract is physically or financially settled. We utilize various commodity derivative financial instrument contracts to help reduce our exposure to variability in future commodity prices. We 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 termof 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. 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 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 of $6.2 million, $5.3 million, and $0.8 million during the years ended March 31, 2014, 2013, and 2012, respectively. Depreciation and Amortization Depreciation and amortization in the consolidated statements of operations includes all depreciation of our property, plant and equipment 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. 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. F-12Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Supplemental cash flow information is as follows: Year Ended March 31,201420132012(in thousands)Interest paid, exclusive of debt issuance costs and letter of creditfees$31,827$27,384$4,966Income taxes paid$1,639$1,027$430 Cash flows from commodity derivative instruments are classified as cash flows from investing activities in the consolidated statements of cashflows. 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 past due or delinquent based on contractual terms. We write off accounts receivable against theallowance for doubtful accounts when collection efforts have been exhausted. We execute netting agreements with certain customers to mitigate our credit risk. Receivables and payables are reflected at a net balance to the extent anetting agreement is in place and we intend to settle on a net basis. Our accounts receivable consist of the following: March 31, 2014March 31, 2013GrossGrossAllowance forReceivableAllowance forSegmentReceivableDoubtful Accounts(Note 2)Doubtful Accounts(in thousands)Crude oil logistics$411,090$105$360,589$11Water solutions25,7004059,61829Liquids192,529617144,26776Retail propane75,6061,66749,2331,644Refined products105,670———Renewables54,466———Other38,66528810—$903,726$2,822$564,517$1,760 Changes in the allowance for doubtful accounts are as follows: Year Ended March 31,201420132012(in thousands)Allowance for doubtful accounts, beginning of period$1,760$818$161Provision for doubtful accounts2,1721,3151,049Write off of uncollectible accounts(1,110)(373)(392)Allowance for doubtful accounts, end of period$2,822$1,760$818 F-13Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 For the year ended March 31, 2014, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated totalrevenues. For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated totalrevenues. At March 31, 2013, one customer of our crude oil logistics segment represented 10% of our consolidated accounts receivable balance. Inventories We value our inventory at the lower of cost or market, with cost determined using either the weighted average cost or the first in, first out (FIFO)methods, including the cost of transportation. In performing this analysis, we take into consideration fixed-price forward sale commitments and theopportunity to transfer propane inventory from our wholesale business to our retail business for sale in the retail markets. Inventories consist of the following: March 31,20142013(in thousands)Crude oil$156,473$46,156Natural gas liquids —Propane85,15945,428Butane and other19,05124,090Refined products23,209—Renewables11,778—Other14,49011,221$310,160$126,895 Investments in Unconsolidated Entities As part of the December 2013 acquisition of Gavilon Energy, we acquired a 50% interest in Glass Mountain and an 11% interest in a limited liabilitycompany that owns an ethanol production facility. We account for these investments under the equity method of accounting. Under the equity method, we donot report the individual assets and liabilities of these entities on our consolidated balance sheet; instead, our ownership interests are reported within“Investments in Unconsolidated Entities” on our consolidated balance sheet. We record our share of any income or loss generated by these entities as anincrease to our equity method investments, and record any distributions we receive from these entities as reductions to our equity method investments. F-14Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Accrued Expenses and Other Payables Accrued expenses and other payables consist of the following: March 31,20132014(Note 4)(in thousands)Accrued compensation and benefits$45,006$27,252Derivative liabilities42,21412,701Income and other tax liabilities13,42122,659Product exchange liabilities3,7196,741Other37,33016,253$141,690$85,606 Property, Plant and Equipment We record property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and 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 lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group. Intangible Assets Our intangible assets include contracts and arrangements acquired in business combinations, including lease agreements, customer relationships,covenants not to compete, and trade names. In addition, we capitalize certain debt issuance costs incurred in our long-term debt arrangements. We amortize ourintangible assets on a straight-line basis over the assets’ estimated useful lives (see Note 7). We amortize debt issuance costs over the terms of the related debton a method that approximates the effective interest method. We evaluate the carrying value of our amortizable intangible assets for potential impairment when events and circumstances warrant such a review. Along-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group islower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group. Whenwe cease to use an acquired trade name, we test the trade name for impairment using the “relief from royalty” method and we begin amortizing the trade nameover its estimated useful life as a defensive asset. Goodwill Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Business combinations are accounted for using the“acquisition method” (see Note 4). We expect that substantially all of our goodwill at March 31, 2014 is deductible for income tax purposes. Goodwill and intangible assets determined to have an indefinite useful life are not amortized, but instead are evaluated for impairment periodically.We evaluate goodwill and indefinite-lived intangible assets for impairment annually, or more often if events or circumstances indicate that the assets might beimpaired. We perform the annual evaluation at January 1 of each year. To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting 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 the first step of the goodwill impairment test, we compare the fair value of the reporting unit with its carrying amount, including goodwill. Ifthe fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amount ofa reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of impairment loss, ifany. F-15Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 · In the second step of the goodwill impairment test, we compare the implied fair value of reporting unit goodwill with the carrying amount of thatgoodwill. If the carrying amount of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized inan amount 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 our assessment of qualitativefactors, we determined that the two-step impairment test was not required. Accordingly, we did not record any goodwill impairments during the years endedMarch 31, 2014, 2013, and 2012. Product Exchanges Quantities of products receivable or returnable under exchange agreements are reported within prepaid expenses and other current assets or 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. Advance Payments Received from Customers We record customer advances on product purchases as a liability on the consolidated balance sheets. Noncontrolling Interests We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated statements ofoperations represents the other owners’ share of the net income (loss) of these entities. Water Facility Development Agreement In connection with one of our business combinations, we entered into a development agreement whereby we may acquire additional water disposalfacilities in Texas. Under this agreement, the other party (the “Developer”) may develop facilities in a designated area. We then have the option to operate thefacility for a period of up to 90 days, during which time we may elect to purchase the facility. If we elect to purchase the facility, the Developer may choose oneof two options specified in the agreement for the calculation of the purchase price. During the period between which we have begun operating the facility and we have decided whether to purchase the facility, we are entitled to a fee foroperating the facility, which is forfeitable if we elect not to purchase the facility. We recognize revenue for these operator fees once they cease to be forfeitable.When we elect to purchase a facility, we account for the transaction as a business combination. Business Combination Measurement Period We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity 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 year ended March 31, 2014 are still within this measurement period, andas a result, the acquisition-date fair values we have recorded for the acquired assets and assumed liabilities are subject to change. Also as described in Note 4, we made certain adjustments during the year ended March 31, 2014 to our estimates of the acquisition date fair valuesof assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2013. We retrospectively adjusted theMarch 31, 2013 consolidated balance sheet for these adjustments. Due to the immateriality of these adjustments, we did not retrospectively adjust theconsolidated statement of operations for the year ended March 31, 2013 for these measurement period adjustments. Discontinued Operations In April 2014, the Financial Accounting Standards Board issued an Accounting Standards Update that changes the criteria for reportingdiscontinued operations. Under the new standard, a disposal of part of an entity is not classified as a discontinued operation F-16Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 unless the disposal represents a strategic shift that will have a major effect on an entity’s operations and financial results. We adopted the new standard duringthe fiscal year ended March 31, 2014. As described in Note 14, during the year ended March 31, 2014, we sold our compressor leasing business and wound down our natural gasmarketing business. These actions do not represent a strategic shift that had a major effect on our operations, and do not meet the criteria under the newaccounting standard for these businesses to be reported as discontinued operations. Note 3 — Earnings per Unit Our earnings per common and subordinated unit were computed as follows: Year Ended March 31,201420132012(in thousands, except unit and per unit amounts) Income attributable to parent equity$47,655$47,940$7,876Income allocated to general partner (1)(14,148)(2,917)(8)Income attributable to limited partners$33,507$45,023$7,868 Income allocated to:Common unitholders$31,614$39,517$4,859Subordinated unitholders$1,893$5,506$3,009 Weighted average common units outstanding61,970,47141,353,57415,169,983Weighted average subordinated units outstanding5,919,3465,919,3465,175,384 Income per common unit - basic and diluted$0.51$0.96$0.32 Income per subordinated unit - basic and diluted$0.32$0.93$0.58 (1) The income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights (“IDRs”),which are described in Note 11. The restricted units described in Note 11 were antidilutive for the years ended March 31, 2014, 2013, and 2012. Note 4 — Acquisitions Year Ended March 31, 2014 Gavilon Energy On December 2, 2013, we completed a business combination in which we acquired Gavilon Energy. We paid $832.4 million of cash, net of cashacquired, in exchange for these assets and operations. The acquisition agreement also contemplates a post-closing adjustment to the purchase price for certainworking capital items. We incurred and charged to general and administrative expense $5.3 million of costs during the year ended March 31, 2014 related tothe acquisition of Gavilon Energy. The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana and a 50% interest in Glass Mountain, which owns acrude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline became operational in February 2014. Theoperations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in the acquisition of Gavilon Energy.The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could F-17Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending September 30, 2014. We have preliminarilyestimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands): Accounts receivable - trade$349,529Accounts receivable - affiliates2,564Inventories107,430Prepaid expenses and other current assets68,322Property, plant and equipment:Crude oil tanks and related equipment (3—40 years)77,429Vehicles (3 years)791Information technology equipment (3—7 years)4,046Buildings and leasehold improvements (3—40 years)7,716Land6,427Linefill and tank bottoms15,230Other (7 years)170Construction in process7,190Goodwill359,169Intangible assets:Customer relationships (10—20 years)101,600Lease agreements (1—5 years)8,700Investments in unconsolidated entities178,000Other noncurrent assets9,918Accounts payable - trade(342,792)Accounts payable - affiliates(2,585)Accrued expenses and other payables(70,999)Advance payments received from customers(10,667)Other noncurrent liabilities(44,740)Fair value of net assets acquired$832,448 Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net ofliabilities assumed. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership, the opportunity to use the acquiredbusiness as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income taxpurposes. Our preliminary estimate of the fair value of investments in unconsolidated subsidiaries exceeds our share of the historical net book value of thesesubsidiaries’ net assets by approximately $70 million. This difference relates primarily to goodwill and customer relationships. The acquisition method of accounting requires that executory contracts that are at unfavorable terms relative to current market conditions at theacquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain crude oil storage lease commitments were at unfavorable termsrelative to current market conditions, we recorded a liability of $12.9 million related to these lease commitments in the acquisition accounting, and weamortized $2.9 million of this balance through cost of sales during the period from the acquisition date through March 31, 2014. We will amortize theremainder of this liability over the term of the leases. The future amortization of this liability is shown below (in thousands): Year Ending March 31,2015$6,50020163,2602017300 As described in Note 14, on March 31, 2014, we assigned all of the storage and transportation contracts of the natural gas marketing business to athird party. Since these contracts were at unfavorable terms relative to current market conditions, we paid $44.8 million to assign these contracts. We recordeda liability of $50.8 million related to these storage and transportation contracts in the acquisition accounting, and we amortized $6.0 million of this balancethrough cost of sales during the period from the acquisition date through the date we assigned the contracts. F-18Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 We recorded $3.2 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to theacquisition of Gavilon Energy. In addition, certain personnel who were employees of Gavilon Energy are entitled to a bonus, half of which was payable uponsuccessful completion of the business combination and the remainder of which is payable in December 2014. We are recording this as compensation expenseover the vesting period. We recorded expense of $5.0 million during the year ended March 31, 2014 related to these bonuses, and we expect to record anadditional expense of $6.6 million during the year ending March 31, 2015. The operations of Gavilon Energy have been included in our consolidated statement of operations since Gavilon Energy was acquired on December 2,2013. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $2.9 billion and operating income of $11.0 millionthat were generated by the operations of Gavilon Energy. Oilfield Water Lines, LP On August 2, 2013, we completed a business combination with entities affiliated with OWL, whereby we acquired water disposal and transportationassets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL.The acquisition agreements included a provision whereby the purchase price could have been increased if certain performance targets were achieved in the sixmonths following the acquisition. These performance targets were not achieved, and therefore no increase to the purchase price was warranted. The acquisitionagreements also contemplate a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense $0.8million of costs related to the OWL acquisition during the year ended March 31, 2014. We have completed the process of identifying and determining the fair value of the long-lived assets acquired in the acquisition of OWL. We have notyet finalized any post-closing payment for certain working capital items, and such changes could be material. We expect to complete this process prior tofinalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives)and liabilities assumed as follows (in thousands): Accounts receivable - trade$7,268Inventories154Prepaid expenses and other current assets402Property, plant and equipment:Land710Water treatment facilities and equipment (3—30 years)23,173Vehicles (5—10 years)8,157Buildings and leasehold improvements (7—30 years)2,198Other (3—5 years)53Intangible assets:Customer relationships (10 years)110,000Non-compete agreements (2.5 years)2,000Goodwill89,699Accounts payable - trade(6,469)Accrued expenses and other payables(992)Other noncurrent liabilities(64)Fair value of net assets acquired$236,289 Consideration paid consists of the following (in thousands): Cash paid, net of cash acquired$167,732Value of common units issued68,557Total consideration paid$236,289 The customer relationships were valued using a variation of the income approach known as the excess earnings method. This methodology consistsof deriving relevant cash flows to the underlying asset, and then deducting appropriate returns for other assets contributing to the generation of the relevantcash flows. This valuation methodology requires estimates of customer retention, which were based on our understanding of the level of competition in theregion in which the assets operate. Our estimates of customer retention are also relevant to the determination of the estimated useful lives of the assets. F-19Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net ofliabilities assumed. 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. The operations of OWL have been included in our consolidated statement of operations since OWL was acquired on August 2, 2013. Ourconsolidated statement of operations for the year ended March 31, 2014 includes revenues of $26.2 million and operating income of $0.9 million that wasgenerated by the operations of OWL. Other Water Solutions Acquisitions During the year ended March 31, 2014, we completed four separate acquisitions of businesses to expand our water solutions operations in Texas. Ona combined basis, we issued 222,381 common units, valued at $6.8 million, and paid $178.9 million of cash, net of cash acquired, in exchange for theassets and operations of these businesses. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $20.6 million andoperating income of $7.1 million that was generated by the operations of these acquisitions. We incurred and charged to general and administrative expense$0.4 million of costs related to these acquisitions during the year ended March 31, 2014. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these four business combinations.The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior tofinalizing our financial statements for the quarter ending September 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and usefullives) and liabilities assumed as follows (in thousands): Accounts receivable - trade$2,391Inventories390Prepaid expenses and other current assets61Property, plant and equipment:Land419Vehicles (5—10 years)90Water treatment facilities and equipment (3—30 years)24,933Buildings and leasehold improvements (7—30 years)3,036Other (3—5 years)13Intangible assets:Customer relationships (8—10 years)72,000Trade names (indefinite life)3,325Non-compete agreements (3 years)260Water facility development agreement (5 years)14,000Water facility option agreement2,500Goodwill63,031Accounts payable - trade(382)Accrued expenses and other payables(300)Other noncurrent liabilities(114)Fair value of net assets acquired$185,653 Consideration paid consists of the following (in thousands): Cash paid, net of cash acquired$178,867Value of common units issued6,786Total consideration paid$185,653 Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net ofliabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the F-20Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of thegoodwill will be deductible for federal income tax purposes. As part of one of these business combinations, we entered into an option agreement with the seller of the business whereby we had the option topurchase a salt water disposal facility that was under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this optionagreement. On March 1, 2014, we purchased the saltwater disposal facility for additional cash consideration of $3.7 million. The assets associated with thisfacility are included in the data in the table above. As part of one of these business combinations, we entered into a development agreement that provides us a first right of refusal to purchase disposalfacilities that may be developed by the seller within a defined area in the Eagle Ford Basin through June 2018. On March 1, 2014, we purchased our firstdisposal facility pursuant to the development agreement for $21.0 million. The assets associated with this facility are included in the data in the table above. Inaddition, we have exercised our option to operate, for evaluation purposes, three additional disposal facilities developed by the seller. Pending the results of ourevaluation, we have the right to purchase any or all of these facilities within the 90-day evaluation period. Crude Oil Logistics Acquisitions During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our crude oil logistics business in Texas andOklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, inexchange for the assets and operations of these businesses. The agreement for the acquisition of one of these businesses contemplates a post-closing paymentfor certain working capital items. We incurred and charged to general and administrative expense during the year ended March 31, 2014 $0.1 million of costsrelated to these acquisitions. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these two business combinations.The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior tofinalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives)and liabilities assumed as follows (in thousands): Accounts receivable - trade$1,235Inventories1,021Prepaid expenses and other current assets54Property, plant and equipment:Vehicles (5—10 years)2,977Buildings and leasehold improvements (5—30 years)280Crude oil tanks and related equipment (2—30 years)3,462Barges and towboats (20 years)20,065Other (3—5 years)53Intangible assets:Customer relationships (3 years)6,300Non-compete agreements (3 years)35Trade names (indefinite life)530Goodwill37,867Accounts payable - trade(665)Accrued expenses and other payables(124)Fair value of net assets acquired$73,090 Consideration paid consists of the following (in thousands): Cash paid, net of cash acquired$67,842Value of common units issued5,248Total consideration paid$73,090 Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net ofliabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the F-21Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of thegoodwill will be deductible for federal income tax purposes. Retail Propane and Liquids Acquisitions During the year ended March 31, 2014, we completed four acquisitions of retail propane businesses and the acquisition of four natural gas liquidsterminals. On a combined basis, we paid $21.9 million of cash to acquire these assets and operations. The agreements for certain of these acquisitionscontemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquiredand liabilities assumed in certain of these business combinations, and as a result the estimates of fair value reflected at March 31, 2014 are subject to change. Year Ended March 31, 2013 High Sierra Combination On June 19, 2012, we completed a business combination with High Sierra, whereby we acquired all of the ownership interests in High Sierra. 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 $3.7 million of costs related to theHigh Sierra transaction. We also incurred or accrued costs of $0.6 million related to the equity issuance that we charged to equity. F-22Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 The fair values of the assets acquired and liabilities assumed in our acquisition of High Sierra are summarized below (in thousands): Accounts receivable - trade$395,311Accounts receivable - affiliates7,724Inventories43,575Derivative assets10,646Forward purchase and sale contracts34,717Prepaid expenses and other current assets11,131Property, plant and equipment:Land5,723Vehicles (5—10 years)22,507Water treatment facilities and equipment (3—30 years)64,057Crude oil tanks and related equipment (2—15 years)17,851Buildings and leasehold improvements (5—30 years)19,145Information technology equipment (3 years)5,541Other (2—30 years)11,010Construction in progress9,621Intangible assets:Customer relationships (5—17 years)245,000Lease contracts (1—10 years)12,400Trade names (indefinite)13,000Goodwill220,884Accounts payable - trade(417,369)Accounts payable - affiliates(9,014)Advance payments received from customers(1,237)Accrued expenses and other payables(35,611)Derivative liabilities(5,726)Forward purchase and sale contracts(18,680)Long-term debt(2,537)Other noncurrent liabilities(3,224)Noncontrolling interest in consolidated subsidiary(2,400)Consideration paid, net of cash acquired$654,045 Consideration paid consists of the following (in thousands): Cash paid, net of cash acquired$239,251Value of common units issued, net of issurance costs414,794Total consideration paid$654,045 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. 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. F-23Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Pecos Combination On November 1, 2012, we completed a business combination whereby we acquired Pecos Gathering & Marketing, L.L.C. and certain of itsaffiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil marketing and logistics operations in Texas and NewMexico. We paid $132.4 million of cash (net of cash acquired) and assumed certain obligations with a value of $10.2 million under certain equipmentfinancing 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 Pecosagreed to purchase a minimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former ownerspurchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement. We incurred and charged to general and administrative expenseduring the year ended March 31, 2013 $0.6 million of costs related to the Pecos combination. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisitionof Pecos: Estimated atMarch 31,Final2013Change(in thousands)Accounts receivable - trade$73,609$73,704$(95)Inventories1,9031,903—Prepaid expenses and other current assets1,4261,426—Property, plant and equipment:Vehicles (5—10 years)22,09719,1932,904Buildings and leasehold improvements (5—30 years)1,3391,24891Crude oil tanks and related equipment (2—15 years)1,099913186Land223224(1)Other (3—5 years)36177(141)Intangible assets:Customer relationships—8,000(8,000)Trade names (indefinite life)9001,000(100)Goodwill91,74786,6615,086Accounts payable - trade(50,795)(50,808)13Accrued expenses and other payables(963)(1,020)57Long-term debt(10,234)(10,234)—Fair value of net assets acquired$132,387$132,387$— Consideration paid consists of the following (in thousands): Cash paid, net of cash acquired$87,444Value of common units issued44,943Total 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 CoastTowing, LLC (“Third Coast”) for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. Also onDecember 31, 2012, we entered into a call agreement with the former owners of Third Coast pursuant to which the former owners of Third Coast agreed topurchase a minimum of $8.0 million or a maximum of $10.0 million of F-24Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 common units from us. On January 11, 2013, the former owners of Third Coast purchased 344,680 common units from us for $8.0 million pursuant to thisagreement. During the year ended March 31, 2014, we completed the acquisition accounting for this business combination. The following table presents the finalcalculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Third Coast: Estimated atMarch 31,Final2013Change(in thousands)Accounts receivable - trade$2,195$2,248$(53)Inventories140140—Property, plant and equipment:Barges and towboats (20 years)17,71112,8834,828Other—30(30)Intangible assets:Customer relationships (3 years)3,0004,000(1,000)Trade names (indefinite life)850500350Goodwill18,84722,551(3,704)Other noncurrent assets2,7332,733—Accounts payable - trade(2,429)(2,048)(381)Accrued expenses and other payables(164)(154)(10)Fair value of net assets acquired$42,883$42,883$— Consideration paid consists of the following (in thousands): Cash paid, net of cash acquired$35,000Value of common units issued7,883Total 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 Solutions Business Combinations During the year ended March 31, 2013, we completed four separate acquisitions to expand the assets and operations of our crude oil logistics andwater solutions businesses. On a combined basis, we paid $52.6 million in cash and assumed $1.3 million of long-term debt in the form of non-competeagreements. We also issued 516,978 common units, valued at $12.4 million, as partial consideration for one of these acquisitions. We incurred and chargedto general and administrative expense during the year ended March 31, 2013 $0.3 million of costs related to these acquisitions. F-25Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 During the year ended March 31, 2014, we completed the acquisition accounting for these business combinations. The following table presents thefinal calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of these businesses: Estimated atMarch 31,Final2013Change(in thousands)Accounts receivable - trade$2,676$2,660$16Inventories191191—Prepaid expenses and other current assets737738(1)Property, plant and equipment:Land21819127Vehicles (5—10 years)85377182Water treatment facilities and equipment (3—30 years)13,66513,322343Buildings and leasehold improvements (5—30 years)8952,233(1,338)Crude oil tanks and related equipment (2—15 years)4,5101,7812,729Other (3—5 years)27225Construction in progress490693(203)Intangible assets:Customer relationships (5—10 years)13,1256,8006,325Non-compete agreements (3 years)164510(346)Trade names (indefinite life)2,1005001,600Goodwill34,45143,822(9,371)Accounts payable - trade(3,374)(3,374)—Accrued expenses and other payables(1,914)(2,026)112Notes payable(1,340)(1,340)—Other noncurrent liabilities(156)(156)—Noncontrolling interest(2,333)(2,333)—Fair value of net assets acquired$64,985$64,985$— Consideration paid consists of the following (in thousands): Cash paid, net of cash acquired$52,552Value 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-26Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Retail Propane Combinations During the Year Ended March 31, 2013 During the year ended March 31, 2013, we entered into six separate business combination agreements to acquire retail propane and 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 $0.3 million related to these acquisitions. The fair values ofthe assets acquired and liabilities assumed in these six combinations are as follows (in thousands): Accounts receivable - trade$8,715Inventory5,155Other current assets1,228Property, plant and equipment:Land1,945Retail propane equipment (5—20 years)28,763Vehicles (5 years)11,344Buildings and leasehold improvements (30 years)7,052Other1,201Intangible assets:Customer relationships (10—15 years)16,890Trade names (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. F-27Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Pro Forma Results of Operations (Unaudited) As described above, we completed a number of acquisitions during the years ended March 31, 2014 and 2013. The operations of each acquired businesshave been included in our consolidated results of operations since the date of acquisition of the business. The unaudited pro forma consolidated data presentedbelow has been prepared as if the following acquisitions had been completed on April 1, 2012: · High Sierra; · Pecos; · Third Coast; · OWL; and · Gavilon Energy. The unaudited pro forma consolidated data presented below has also been prepared as if the following transactions, which are described in Notes 8and 11 to these consolidated financial statements, had been completed on April 1, 2012: · Our sale of common units in December 2013 in a private placement; · The amendment of our Credit Agreement in November 2013; · Our issuance of senior unsecured notes in October 2013; · Our sale of common units in September 2013 in a public offering; · The sale of common units in a public offering in July 2013; · Our entry into the Credit Agreement in June 2012; and · Our issuance of senior notes in June 2012. Year Ended March 31,20142013(in thousands, except per unit amounts)Revenues$9,800,398$5,697,988Net income (loss)798(72,171)Net loss attributable to limited partners(14,446)(75,251)Basic and diluted loss per common unit(0.18)(0.95)Basic and diluted loss per subordinated unit(0.18)(0.95) The pro forma consolidated data in the table above was prepared by adding historical results of operations of acquired businesses to our historicalresults of operations and making certain pro forma adjustments. The pro forma information is not necessarily indicative of the results of operations that wouldhave occurred if the transactions had occurred on April 1, 2012, nor is it necessarily indicative of future results of operations. F-28Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Gavilon Energy historically conducted trading operations, whereas we operate as a logistics business. Gavilon Energy’s historical results ofoperations were subject to more volatility as a result of its trading operations than we would expect future results of operations to have under our businessmodel. In the pro forma data in the table above, no pro forma effect was given to the change in business model from a trading business to a logistics business.Gavilon Energy historically recorded revenues net of product costs. In the pro forma table above, no pro forma effect was given to the fact that this accountingpolicy is different than our accounting policy. The pro forma net loss for the year ended March 31, 2013 in the table above includes $4.8 million of expense related to the retirement of a liabilityassociated with a business combination that OWL completed prior to our acquisition of OWL. This non-recurring expense is not excluded from the pro formanet loss, as it does not directly result from our acquisition of OWL. The pro forma net loss for the year ended March 31, 2014 shown in the table above reflects depreciation and amortization expense estimates whichare preliminary, as our identification of the assets and liabilities acquired, and the fair value determinations thereof, for the business combination with GavilonEnergy have not been completed. The pro forma losses per unit have been computed based on earnings or losses allocated to the limited partners after deducting the total earningsallocated to the general partner. To calculate earnings attributable to the general partner, we have used historical distribution amounts. For purposes of thiscalculation, we have assumed that the common units outstanding at March 31, 2014 were outstanding during the full years presented above. Year Ended March 31, 2012 Osterman On October 3, 2011, we completed a business combination transaction with Osterman, whereby we acquired retail propane operations in 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 $0.8 million of costs incurred inconnection with the Osterman transaction. We also incurred costs related to the equity issuance of $0.1 million that we charged to equity. The following tablepresents the final allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands): Accounts receivable - trade$9,350Inventories3,869Prepaid expenses and other current assets215Property, plant and equipment:Land2,349Retail propane equipment (15—20 years)47,160Vehicles (5—20 years)7,699Buildings and leasehold improvements (30 years)3,829Other (3—5 years)732Intangible assets:Customer relationships (20 years)54,500Trade names (indefinite life)8,500Non-compete agreements (7 years)700Goodwill52,267Assumed liabilities(9,654)Consideration paid, net of cash acquired$181,516 F-29Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Consideration paid consists of the following (in thousands): Cash paid at closing, net of cash acquired$94,873Fair value of common units issued at closing81,880Working capital payment (paid in November 2012)4,763Consideration paid, net of cash acquired$181,516 Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, 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. SemStream On November 1, 2011, we completed a business combination with SemStream. We entered into this business combination in order to expand ourliquids segment. SemStream contributed substantially all of its natural gas liquids business and assets to us in exchange for 8,932,031 of our limited partnercommon units and a cash payment of $91.0 million. We have valued the 8.9 million limited partner common units at $184.8 million, based on the closingprice of our common units on the closing date ($21.07) reduced by the expected present value of distributions for certain units which were not eligible for fulldistributions until the quarter ending September 30, 2012. In addition, in exchange for a cash contribution, SemStream acquired a 7.5% interest in our generalpartner. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.7 million of costs related to the SemStreamtransaction. We also incurred costs of less than $0.1 million related to the equity issuance that we charged to equity. The acquired assets included 12 natural gas liquids terminals in Arizona, Arkansas, Indiana, Minnesota, Missouri, Montana, Washington andWisconsin, 12 million gallons of aboveground propane storage, 3.7 million barrels of underground leased storage for natural gas liquids and a rail fleet of 350leased 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 liquids segment. The following table presents the fair values of the assets acquired and liabilities assumed in the SemStream combination (in thousands): Inventories$104,226Derivative assets3,578Assets held for sale3,000Prepaid expenses and other current assets9,833Property, plant and equipment:Land3,470Natural gas liquids terminal assets (20—30 years)41,434Vehicles and railcars (5 years)470Other (5 years)3,326Investment in capital lease3,112Intangible assets:Customer relationships (8—15 years)31,950Lease contracts (1—4 years)1,008Goodwill74,924Assumed current liabilities(4,591)Consideration paid$275,740 F-30Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, 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. 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 $0.7 million of costs related tothe Pacer transaction. We also incurred costs of $0.1 million related to the equity issuance that we charged to equity. The assets contributed by Pacer consist of retail propane operations in Colorado, Illinois, Mississippi, Oregon, Utah and Washington. 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. Consideration paid consists of the following (in thousands): Cash$32,213Common units30,375Consideration paid$62,588 The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (inthousands): Accounts receivable - trade$4,389Inventories965Prepaid expenses and other current assets43Property, plant and equipment:Land1,967Retail propane equipment (15—20 years)12,793Vehicles (5 years)3,090Buildings and leasehold improvements (30 years)409Other (3—5 years)59Intangible assets:Customer relationships (15 years)23,560Trade names (indefinite life)2,410Non-compete agreements1,520Goodwill15,782Assumed liabilities(4,399)Consideration paid$62,588 Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, 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-31Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert 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 $1.6 millionof costs related to the North American acquisition. The assets acquired from North American include retail propane and distillate operations in Connecticut, Delaware, Maine, Maryland,Massachusetts, New Hampshire, New Jersey, Pennsylvania, and Rhode Island. The following table presents the allocation of the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (inthousands): Accounts receivable - trade$10,338Inventories3,437Prepaid expenses and other current assets282Property, plant and equipment:Land2,251Retail propane equipment (15—20 years)24,790Natural gas liquids terminal assets (15—20 years)1,044Vehicles (5—15 years)5,819Buildings and leasehold improvements (30 years)2,386Other (3—5 years)634Intangible assets:Customer relationships (10 years)12,600Trade names (10 years)2,700Non-compete agreements (3 years)700Goodwill13,978Assumed liabilities(11,129)Consideration paid$69,830 Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, 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 $6.4 million on a combined basis. We alsoassumed $0.6 million in long-term debt in the form of non-compete agreements. These operations have been included in our results of operations since theacquisition dates, and have not been material to our consolidated financial statements. F-32Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Note 5 — Property, Plant and Equipment Our property, plant and equipment consists of the following: March 31,2013Description and Estimated Useful Lives2014(Note 2)(in thousands)Natural gas liquids terminal assets (2—30 years)$75,141$63,637Retail propane equipment (2—30 years)160,758152,802Vehicles (3—25 years)152,67688,173Water treatment facilities and equipment (3—30 years)180,98591,944Crude oil tanks and related equipment (2—40 years)106,12522,577Barges and towboats (5—40 years)52,21725,963Information technology equipment (3—7 years)20,76812,169Buildings and leasehold improvements (3—40 years)60,00448,975Land30,24121,815Linefill and tank bottoms13,403—Other (5—30 years)6,34116,104Construction in progress80,25132,405938,910576,564Less: Accumulated depreciation(109,564)(50,127)Net property, plant and equipment$829,346$526,437 Depreciation expense was $59.9 million, $39.2 million and $10.6 million during the years ended March 31, 2014, 2013 and 2012, respectively.During the year ended March 31, 2014, we capitalized $0.7 million of interest expense. Note 6 — Goodwill The changes in the balance of goodwill were as follows: Year Ended March 31,201420132012(in thousands)Beginning of period, as retrospectively adjusted (Note 2)$555,220$167,245$8,568Acquisitions551,786387,975158,677End of period, as retrospectively adjusted (Note 2)$1,107,006$555,220$167,245 Goodwill by reportable segment is as follows: March 31,20142013(in thousands)Crude oil logistics$606,383$246,345Water solutions262,203109,470Liquids90,13587,136Retail propane114,285112,269Refined products22,000—Renewables12,000—$1,107,006$555,220 F-33Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Note 7 — Intangible Assets Our intangible assets consist of the following: March 31, 2014March 31, 2013Gross CarryingAmortizableGross CarryingAccumulatedAmountAccumulatedLivesAmountAmortization(Note 2)Amortization(in thousands)Amortizable -Customer relationships (1)3–20 years$697,405$83,261$405,160$30,959Water facility development agreement5 years14,0002,100——Lease and other agreements5–8 years23,92013,19015,2107,018Non-compete agreements2–7 years14,1616,38811,5092,871Trade names1–10 years15,4893,0812,784326Debt issuance costs5–10 years44,0898,70819,4942,981Total amortizable809,064116,728454,15744,155 Non-amortizable -Trade names22,62031,430Total$831,684$116,728$485,587$44,155 (1) The weighted-average remaining amortization period for customer relationship intangible assets is approximately nine years. Amortization expense was as follows: Year Ended March 31,Recorded in201420132012(in thousands)Depreciation and amortization$60,855$29,657$4,538Cost of sales6,1725,285800Interest expense5,7273,3751,277Loss on early extinguishment of debt—5,769—$72,754$44,086$6,615 Expected amortization of our intangible assets is as follows (in thousands): Year Ending March 31,2015$88,970201683,449201776,826201872,857201966,826Thereafter303,408$692,336 F-34Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Note 8 — Long-Term Obligations Our long-term debt consists of the following: March 31,20142013(in thousands)Revolving credit facility —Expansion capital loans$532,500$441,500Working capital loans389,50036,000Senior notes250,000250,000Unsecured notes450,000—Other notes payable14,91421,5621,636,914749,062 Less - current maturities7,0808,626Long-term debt$1,629,834$740,436 Credit Agreement On June 19, 2012, we entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreementincludes a revolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions andexpansion projects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). The Working Capital Facility had a total capacity of $935.5 million for cash borrowings and letters of credit at March 31, 2014. At March 31,2014, we had outstanding cash borrowings of $389.5 million and outstanding letters of credit of $270.6 million on the Working Capital Facility. TheExpansion Capital Facility had a total capacity of $785.5 million for cash borrowings at March 31, 2014. At March 31, 2014, we had outstanding cashborrowings of $532.5 million on the Expansion Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowingbase,” as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time. The commitments under the Credit Agreement expire on November 5, 2018. We have the right to pre-pay outstanding borrowings under the 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 0.50% to 1.50% per annum or(ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, asdefined in the Credit Agreement. At March 31, 2014, the interest rate in effect on outstanding LIBOR borrowings was 1.91%, calculated as the LIBOR rate of0.16% plus a margin of 1.75%. At March 31, 2014, the interest rate in effect on letters of credit was 1.75%. Commitment fees are charged at a rate rangingfrom 0.38% to 0.50% on any unused credit. At March 31, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were asfollows (dollars in thousands): AmountRateExpansion capital facility —LIBOR borrowings$532,5001.91%Working capital facility —LIBOR borrowings358,0001.91%Base rate borrowings31,5004.00% The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our “leverage ratio,” as defined in the CreditAgreement, cannot exceed 4.25 to 1.0 at any quarter end. At March 31, 2014, our leverage ratio was approximately 3 to 1. The Credit Agreement also specifiesthat our “interest coverage ratio,” as defined in the Credit Agreement, F-35Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At March 31, 2014, our interest coverage ratio was approximately 7 to 1. The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, 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, 2014, we were in compliance with the covenants under the Credit Agreement. Senior Notes On June 19, 2012, we entered into a note purchase agreement (as amended, the “Note Purchase Agreement”) whereby we issued $250.0 million ofsenior notes in a private placement (the “Senior Notes”). The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a fixedrate of 6.65%. Interest is payable quarterly. The Senior Notes are required to be repaid in semi-annual installments of $25.0 million beginning onDecember 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement. The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit 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 are 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 $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note 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, 2014, we were in compliance with the covenants under the Note Purchase Agreement and the Senior Notes. Unsecured Notes On October 16, 2013, we issued $450.0 million of 6.875% senior unsecured notes (the “Unsecured Notes”) in a private placement exempt fromregistration under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. We receivednet proceeds of $438.4 million, after the initial purchasers’ discount of $10.1 million and estimated offering costs of $1.5 million. We used the net proceeds toreduce the outstanding balance on our Revolving Credit Facility. The Unsecured Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem theUnsecured Notes prior to the maturity date, although we would be required to pay a premium for early redemption. The purchase agreement and the indenture governing the Unsecured Notes contain various customary representations, warranties, and additionalcovenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchaseagreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) thefailure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy orinsolvency. F-36Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 At March 31, 2014, we were in compliance with the covenants under the Unsecured Notes. We also entered into a registration rights agreement whereby we have committed to exchange the Unsecured Notes for a new issue of notes registeredunder the Securities Act that has substantially identical terms to the Unsecured Notes on or before October 16, 2014. If we are unable to fulfill this obligation,we would be required to pay liquidated damages to the holders of the Unsecured Notes. Other Notes Payable We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitionsof businesses. We also have certain notes payable related to equipment financing, which have interest rates ranging from 2.1% to 4.9% at March 31, 2014. Debt Maturity Schedule The scheduled maturities of our long-term debt are as follows at March 31, 2014: RevolvingOtherCreditSeniorUnsecuredNotesYear Ending March 31,FacilityNotesNotesPayableTotal(in thousands)2015$—$—$—$7,081$7,0812016———3,6143,6142017———2,3562,3562018—25,000—1,44926,4492019922,00050,000—238972,238Thereafter—175,000450,000176625,176$922,000$250,000$450,000$14,914$1,636,914 Previous Credit Facilities On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, 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. Note 9 — Income Taxes We believe that we qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, eachowner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial andtax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner’s basis in the Partnership. We have certain taxable corporate subsidiaries in the United States and Canada. In addition, our operations in Texas are subject to a state franchisetax that is calculated based on revenues net of cost of sales. A publicly traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from 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 each of thecalendar years since our IPO. 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 position will be sustained upon examination, including resolution of any related appeals or litigation,based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to berecognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in the consolidated financial statementsat March 31, 2014. F-37Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Note 10 — Commitments and Contingencies Legal Contingencies We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, 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 liabilities may change materially as circumstances develop. Customer Dispute A customer of our crude oil logistics segment has disputed the transportation rate schedule we used to bill the customer for services that we 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 $1.7 million of the amount we charged for services we provided from November 2012 throughFebruary 2013. In May 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. Later inMay 2013, the customer filed an answer and counterclaim seeking to recover $5.5 million that it paid to Pecos prior to our acquisition of Pecos. We have notrecorded revenue for the $1.7 million of unpaid fees charged from November 2012 through February 2013, pending resolution of the dispute. During August 2013, the customer notified us that it intended to withhold payment of $3.3 million for services performed by us during the periodfrom June 2013 through August 2013, pending resolution of the dispute, although the customer has not disputed the validity of the amounts billed for servicesperformed during this time frame. Upon receiving this notification, we ceased providing services under this contract, and on November 5, 2013, we filed apetition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. We are not able to reliably predict the outcome ofthis dispute at this time, but we do not believe the outcome will have a material adverse effect on our consolidated financial position or results of operations. Canadian Fuel and Sales Taxes The taxing authority of a province in Canada completed an audit of fuel and sales tax payments and alleged that an entity we acquired should havecollected from customers and remitted to the taxing authority fuel and sales taxes on certain historical sales. We recorded in the acquisition accounting aliability of $0.8 million (net of receivables for expected recoveries from other parties). We now believe this matter is resolved, and we removed the liability fromour consolidated balance sheet and recorded a corresponding reduction to cost of sales during the year ended March 31, 2014. Environmental Matters Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are 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 disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability thatcould result from such events. However, some risk of environmental or other damage is inherent in our business. Asset Retirement Obligations We have recorded a liability of $2.3 million at March 31, 2014 for asset retirement obligations. This liability is related to wastewater disposalfacilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement andremoval activities when the assets are retired. In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain 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. F-38Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Operating Leases We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, and equipment. Futureminimum lease payments under contractual commitments at March 31, 2014 are as follows (in thousands): Year Ending March 31,2015$133,170201693,454201764,209201849,802201929,213Thereafter58,182Total$428,030 Rental expense relating to operating leases was $98.3 million, $84.2 million, and $5.2 million during the years ended March 31, 2014, 2013, and2012, respectively. Sales and Purchase Contracts We have entered into sales and purchase contracts for products to be delivered in future periods for which we expect the parties to physically settle thecontracts with inventory. At March 31, 2014, we had the following such commitments outstanding: VolumeValue(in thousands)Natural gas liquids fixed-price purchase commitments (gallons)31,111$39,117Natural gas liquids floating-price purchase commitments (gallons)522,947618,293Natural gas liquids fixed-price sale commitments (gallons)63,94477,682Natural gas liquids floating-price sale commitments (gallons)272,495395,095Crude oil fixed-price purchase commitments (barrels)4,016364,557Crude oil fixed-price sale commitments (barrels)3,574324,765 We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not 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. Contracts in thetable above may have offsetting derivative contracts (described in Note 12) or inventory positions (described in Note 2). Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded atfair value on our consolidated balance sheet and are not included in the data in the table above. These contracts are included in the derivative disclosures inNote 12, and represent $43.5 million of our prepaid expenses and other current assets and $34.6 million of our accrued expenses and other payables atMarch 31, 2014. Note 11 — Equity Partnership Equity The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest. Limited partner equity includes 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. We expect the subordination period to end in August 2014. When the subordination period ends, all remaining subordinated units will convert intocommon units on a one-for-one basis and the common units will no longer be entitled to arrearages. Our general partner is not obligated to make any additional capital contributions or to guarantee or pay any of our debts and obligations. F-39Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Initial Public Offering On May 17, 2011, we completed our IPO. We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. Our proceeds from the sale of3,850,000 common units of $71.9 million, net of total offering costs of $9.0 million, were used to repay advances under our acquisition credit facility and forgeneral partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) from the underwriters’ exercise of their option to purchaseadditional common units from us were used to redeem 175,000 of the common units outstanding prior to our IPO. Upon the completion of our IPO and theunderwriters’ exercise in full of their option to purchase additional common units from us and the redemption, we had outstanding 8,864,222 common units,5,919,346 subordinated units, a 0.1% general partner interest, and IDRs. Common Units Issued in Business Combinations As described in Note 4, we issued common units as partial consideration for several acquisitions. These are summarized below: Osterman combination4,000,000SemStream combination8,932,031Pacer combination1,500,000Total - Year Ended March 31, 201214,432,031 High Sierra combination20,703,510Retail propane combinations850,676Crude oil logistics and water solutions combinations516,978Pecos combination1,834,414Third Coast combination344,680Total - Year Ended March 31, 201324,250,258 Water solutions combinations222,381Crude oil logistics combinations175,211OWL combination2,463,287Total - Year Ended March 31, 20142,860,879 In connection with the completion of certain of these transactions, we amended our Registration Rights Agreement, which provides for certainregistration rights for certain holders of our common units. Equity Issuances On July 5, 2013, we completed a public offering of 10,350,000 common units. We received net proceeds of $287.5 million, after underwritingdiscounts and commissions of $12.0 million and offering costs of $0.7 million. On September 25, 2013, we completed a public offering of 4,100,000 common units. We received net proceeds of $127.6 million, after underwritingdiscounts and commissions of $5.0 million and offering costs of $0.2 million. On December 2, 2013, we issued and sold 8,110,848 of our common units in a private placement. We received net proceeds of $235.1 million, afteroffering costs of $4.9 million. Distributions Our general partner has adopted a cash distribution policy that will require us to pay a quarterly distribution to the extent we have sufficient 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.” 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 F-40Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Distributions” are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to andincluding the corresponding amount in the column “Total Quarterly Distribution per Unit.” The percentage interests shown for our unitholders and our generalpartner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution.The percentage interests set forth below for our general partner include its 0.1% general partner interest, assume our general partner has contributed anyadditional capital necessary to maintain its 0.1% general partner interest and has not transferred its IDRs and there are no arrearages on common units. Marginal Percentage Interest InTotal QuarterlyDistributionsDistribution per UnitUnitholdersGeneral PartnerMinimum quarterly distribution$ 0.33750099.9%0.1%First target distributionabove$ 0.337500up to$ 0.38812599.9%0.1%Second target distributionabove$ 0.388125up to$ 0.42187586.9%13.1%Third target distributionabove$ 0.421875up to$ 0.50625076.9%23.1%Thereafterabove$ 0.50625051.9%48.1% On May 5, 2011, we made a distribution of $3.9 million from available cash to our general partner and common unitholders at March 31, 2011. The following table summarizes the distributions declared subsequent to our IPO: 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, 20130.477525,6051,189July 25, 2013August 5, 2013August 14, 20130.493831,7251,739October 23, 2013November 4, 2013November 14, 20130.511335,9082,491January 23, 2014February 4, 20143February 14, 20140.531342,1504,283April 24, 2014May 5, 2014May 15, 20140.551343,7375,754 F-41Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Several of our business combination agreements contained provisions that temporarily limited the distributions to which the newly-issued units 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—August 5, 2013—November 4, 2013979,886February 4, 2014—May 5, 2014— Equity-Based Incentive Compensation Our general partner has adopted a long-term incentive plan (“LTIP”) which allows for the issuance of equity-based compensation to employees anddirectors. The board of directors of our general partner has granted certain restricted units to employees and directors, which will vest in tranches, subject tothe continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributionswill accrue to or be paid on the restricted units during the vesting period. F-42Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 The following table summarizes the restricted unit activity during the years ended March 31, 2014 and 2013: Unvested restricted units at March 31, 2012—Units 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, 20131,444,900Units granted494,000Units vested and issued(296,269)Units withheld for employee taxes(122,531)Units forfeited(209,000)Unvested restricted units at March 31, 20141,311,100 The scheduled vesting of the awards is summarized below: Vesting DateNumber of AwardsJuly 1, 2014408,300January 1, 20154,000July 1, 2015341,300January 1, 20164,000July 1, 2016322,500January 1, 20174,000July 1, 2017192,500January 1, 20184,000July 1, 201830,500Total unvested units at March 31, 20141,311,100 We record the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with 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.The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that amarket participant might make about future distribution growth. We estimate that the future expense we will record on the unvested awards at March 31, 2014will be as follows (in thousands), after taking into consideration an estimate of forfeitures of 95,000 units. For purposes of this calculation, we have used theclosing price of the common units on March 31, 2014, which was $37.53. Year Ending March 31,2015$14,393201611,27920177,42920182,3102019229Total$35,640 F-43Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Following is a rollforward of the liability related to equity-based compensation, which is reported within accrued expenses and other payables on ourconsolidated balance sheets (in thousands): Balance at March 31, 2012$—Expense recorded10,138Value of units vested and issued(3,627)Taxes paid on behalf of participants(1,468)Balance at March 31, 20135,043Expense recorded17,804Value of units vested and issued(9,085)Taxes paid on behalf of participants(3,750)Balance at March 31, 2014$10,012 The weighted-average fair value of the awards at March 31, 2014 was $33.78, which was calculated as the closing price of the common units onMarch 31, 2014, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack 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. The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common andsubordinated units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common andsubordinated units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of unitsdeliverable by a lesser amount. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, if an awardis forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available fornew awards under the LTIP. At March 31, 2014, 6.2 million units remain available for issuance under the LTIP. Note 12 — Fair Value of Financial Instruments Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current liabilities (excluding derivativeinstruments) are carried at amounts which reasonably approximate their fair values, due to their short-term nature. We believe the carrying amounts of ourlong-term debt instruments, including the Revolving Credit Facility and the Senior Notes, approximate their fair values, as we do not believe market conditionshave changed materially since we entered into these debt agreements. F-44Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Commodity Derivatives The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet atMarch 31, 2014: DerivativeDerivativeAssetsLiabilities(in thousands)Level 1 measurements$4,990$(3,258)Level 2 measurements49,605(43,303)54,595(46,561) Netting of counterparty contracts(1)(4,347)4,347Cash collateral provided or held456—Commodity contracts reported on consolidated balance sheet$50,704$(42,214) (1) Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with thecounterparty. 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(1)(3,503)3,503Cash collateral provided or held(1,760)400Commodity contracts reported on consolidated balance sheet$5,595$(12,701) (1) Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with thecounterparty. The commodity derivative assets (liabilities) are reported in the following accounts on the consolidated balance sheets: March 31,20142013(in thousands)Prepaid expenses and other current assets$50,704$5,551Other noncurrent assets—44Accrued expenses and other payables(42,214)(12,701)Net asset (liability)$8,490$(7,106) F-45Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 The following table sets forth our open commodity derivative contract positions at March 31, 2014 and 2013. We do not account for these derivativesas hedges. ContractsSettlement PeriodTotal NotionalUnits(Barrels)Fair Valueof Net Assets(Liabilities)(in thousands)At March 31, 2014 -Cross-commodity (1)April 2014 – March 2015140$(1,876)Crude oil fixed-price (2)April 2014 – March 2015(1,600)(2,796)Crude oil index (3)April 2014 – December 20153,5986,099Propane fixed-price (4)April 2014 – March 2015601,753Refined products fixed-price (5)April 2014 – July 2014732560Renewable products fixed-price (6)April 2014 – July 20141064,084OtherApril 2014—2108,034Net cash collateral provided456Net value of commodity derivatives on consolidatedbalance sheet$8,490 At March 31, 2013 -Cross-commodity (1)April 2013 - March 2014430$(10,208)Crude oil fixed-price (2)April 2013 - March 2014(144)1,033Crude oil index (3)April 2013 - June 2014(91)153Propane fixed-price (4)April 2013 - March 2014(282)3,197OtherMay 2013 - June 2013879(5,746)Net cash collateral held(1,360)Net value of commodity derivatives on consolidatedbalance sheet$(7,106) (1) Cross-commodity — Our operating segments may purchase or sell a physical commodity where the underlying contract pricing mechanismsare tied to different commodity price indices. The contracts listed in this table as “Cross-commodity” represent derivatives we have entered intoas economic hedges against the risk of one commodity price moving relative to another commodity price. (2) Crude oil fixed-price — Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to beplaced by our customers. The contracts listed in this table as “Crude oil fixed-price” represent derivatives we have entered into as an economichedge against the risk that crude oil prices will decline while we are holding the inventory. (3) Crude oil index — Our crude oil logistics segment may purchase or sell crude oil where the underlying contract pricing mechanisms are tied todifferent crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. Thecontracts listed in this table as “Crude oil index” represent derivatives we have entered into as an economic hedge against the risk of one crude oilindex moving relative to another crude oil index. (4) Propane fixed-price — Our liquids segment routinely purchases inventory during the warmer months and stores the inventory for sale in thecolder months. The contracts listed in this table as “Propane fixed-price” represent derivatives we have entered into as an economic hedge againstthe risk that propane prices will decline while we are holding the inventory. F-46Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 (5) Refined products fixed-price — Our refined products segment routinely purchases refined products inventory to enable us to fulfill future ordersexpected to be placed by our customers. The contracts listed in this table as “Refined products fixed-price” represent derivatives we have enteredinto as an economic hedge against the risk that refined product prices will decline while we are holding the inventory. (6) Renewable products fixed-price — Our renewables segment routinely purchases biodiesel and ethanol inventory to enable us to fulfill futureorders expected to be placed by our customers. The contracts listed in this table as “Renewable products fixed-price” represent derivatives wehave entered into as an economic hedge against the risk that biodiesel or ethanol prices will decline while we are holding the inventory. We recorded the following net gains (losses) from our commodity derivatives to cost of sales: Year Ended March 31,2014$(43,655)2013(4,381)20125,676 Credit Risk We maintain credit policies with regard to our counterparties on the derivative financial instruments that we believe minimize our overall credit risk,including an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and theuse of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty. We may enter into industry standard master netting agreements and may enter into cash collateral agreements requiring the counterparty to depositfunds into a brokerage margin account. The netting agreements reduce our credit risk by providing for net settlement of any offsetting positive and negativeexposures with counterparties. The cash collateral agreements reduce the level of our net counterparty credit risk because the amount of collateral representsadditional funds that we may access to net settle positions due us, and the amount of collateral adjusts each day in response to changes in the market value ofcounterparty derivatives. 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. As is customary in the crude oil industry, we generally receive payment from customers on a monthly basis. As a result, receivables from individualcustomers in our crude oil logistics are typically higher than the receivables from customers of our other segments. Failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidatedstatements of financial position and recognized in our net income. Interest Rate Risk Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31,2014, we have $922.0 million of outstanding borrowings under our Revolving Credit Facility at a rate of 1.98%. A change in interest rates of 0.125% wouldresult in an increase or decrease of our annual interest expense of $1.2 million on the $922.0 million of outstanding borrowings on the revolving credit facilityat March 31, 2014. Note 13 — Segments Our reportable segments are based on the way in which our management structure is organized. Certain financial data related to our segments 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. Our watersolutions segment provides services for the transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production, andgenerates revenue from the sale of recycled wastewater and recovered hydrocarbons. Our liquids segment supplies propane, butane, and other products, andprovides natural gas liquids transportation, terminaling, and storage services to retailers, wholesalers, and refiners. Our retail propane segment sells propaneand distillates to end users consisting of F-47Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 residential, agricultural, commercial, and industrial customers, and to certain re-sellers. Our retail propane segment consists of two divisions, which areorganized based on the location of the operations. We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products inback-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business,which purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations to refiners and blenders, and purchasesbiodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders.These businesses were acquired in our December 2013 acquisition of Gavilon Energy. Items labeled “corporate and other” in the table below include the operations of a compressor leasing business that we acquired in our June 2012merger with High Sierra and sold in February 2014, and the natural gas marketing operations that we acquired in our December 2013 acquisition of GavilonEnergy and began winding down during fiscal 2014. The “corporate and other” category also includes certain corporate expenses that are incurred and are notallocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our consolidated financial statements. Certain information related to the results of operations of each segment is shown in the tables below: Year Ended March 31,201420132012(in thousands)Revenues:Crude oil logistics -Crude oil sales$4,559,923$2,322,706$—Crude oil transportation and other36,46916,442—Water solutions -Water treatment and disposal125,78854,334—Water transportation17,3127,893—Liquids -Propane sales1,632,948841,448923,022Other product sales1,231,965858,276251,627Other revenues31,06233,9542,462Retail propane -Propane sales388,225288,410175,417Distillate sales127,672106,1926,547Other revenues35,91835,85617,370Refined products1,180,895——Renewables176,781——Corporate and other437,7134,233—Eliminations of intersegment sales(283,397)(151,977)(65,972)Total revenues$9,699,274$4,417,767$1,310,473 F-48Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Year Ended March 31,201420132012(in thousands)Depreciation and amortization:Crude oil logistics$22,111$9,176$—Water solutions55,10520,923—Liquids11,01811,0853,661Retail propane28,87825,49611,450Refined products109——Renewables516——Corporate and other3,0172,173—Total depreciation and amortization$120,754$68,853$15,111 Year Ended March 31,201420132012(in thousands)Operating income (loss):Crude oil logistics$678$34,236$—Water solutions10,3178,576—Liquids71,88830,3369,735Retail propane61,28546,8699,616Refined products4,080——Renewables2,434——Corporate and other(44,117)(32,710)(4,321)Total operating income$106,565$87,307$15,030 The table below shows additions to property, plant and equipment for each segment. This information has been prepared on the accrual basis, andincludes property, plant and equipment acquired in acquisitions. Year Ended March 31,201420132012(in thousands)Additions to property, plant and equipment, including acquisitions(accrual basis):Crude oil logistics$204,642$89,860$—Water solutions100,877137,116—Liquids52,56015,12950,276Retail propane24,43066,933150,181Refined products719——Renewables519——Corporate and other7,24217,858—Total$390,989$326,896$200,457 F-49Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 The following tables show long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets bysegment: March 31,20132014(Note 2)(in thousands)Total assets:Crude oil logistics$1,723,812$801,351Water solutions875,714466,412Liquids577,795474,141Retail propane541,832513,301Refined products157,581—Renewables145,649—Corporate and other144,84036,413Total$4,167,223$2,291,618 Long-lived assets, net:Crude oil logistics$980,978$357,230Water solutions848,479453,909Liquids274,846238,192Retail propane438,324441,762Refined products27,017—Renewables33,703—Corporate and other47,96131,996Total$2,651,308$1,523,089 Note 14 — Disposals and Impairments We acquired Gavilon Energy in December 2013, which operated a natural gas marketing business. During March 2014, we assigned all of thestorage and transportation contracts of the natural gas marketing business to a third party. Since these contracts were at unfavorable terms relative to currentmarket conditions, we paid $44.8 million to assign these contracts. We recorded a liability of $50.8 million related to these storage and transportation contractsin the acquisition accounting, and we amortized $6.0 million of this balance through cost of sales during the period from the acquisition date through the datewe assigned the contracts. We also assigned all forward purchase and sale contracts and all financial derivative contracts, and thereby wound down thenatural gas business. Our consolidated statement of operations for the year ended March 31, 2014 includes $1.4 million of operating income related to thenatural gas business, which is reported within “corporate and other” in the segment disclosures in Note 13. We acquired High Sierra in June 2012, which operated a compressor leasing business. We sold the compressor leasing business in February 2014 for$10.8 million (net of the amount due to the owner of the noncontrolling interest in the business). We recorded a gain on the sale of the business of $4.4 million,$1.6 million of which was attributable to the disposal of the noncontrolling interest. We reported the gain as a reduction to operating expenses in ourconsolidated statement of operations. Our consolidated statement of operations for the year ended March 31, 2014 includes $2.3 million of operating incomerelated to the compressor leasing business, which is reported within “corporate and other” in the segment disclosures in Note 13. During the year ended March 31, 2014, we recorded an impairment of $5.3 million to the property, plant and equipment of one of our natural gasliquids terminals. This loss is reported within operating expenses of our liquids segment. F-50Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 During the year ended March 31, 2014, two of our water solutions facilities experienced damage to their property, plant and equipment as a result oflightning strikes. We recorded a write-down to property, plant and equipment of $1.5 million related to these incidents, which is reported within operatingexpenses in our consolidated statement of operations. Note 15 — Transactions with Affiliates Since our business combination with SemStream on November 1, 2011, SemGroup Corporation (“SemGroup”) has held ownership interests in usand in our general partner, and has the right to appoint two members to the board of directors of our general partner. Subsequent to November 1, 2011, wehave sold product to and purchased product from affiliates of SemGroup. These transactions are included within revenues and cost of sales in ourconsolidated statements of operations. Certain members of our management own interests in entities with which we have purchased products and services from and have sold products andservices. The majority of these purchases represent crude oil purchases and are reported within cost of sales in our consolidated statements of operations,although $8.2 million of these transactions during the year ended March 31, 2014 represented capital expenditures and were recorded as increases to property,plant and equipment. The majority of these sales represent sales of crude oil and have been recorded within revenues in our consolidated statement ofoperations. These transactions are summarized in the table below: Year Ended March 31,201420132012(in thousands)Sales to SemGroup$306,780$32,431$29,200Purchases from SemGroup445,95160,42523,800Sales to entities affiliated with management110,82416,828—Purchases from entities affiliated with management120,03860,942— Receivables from affiliates consist of the following: March 31,20142013(in thousands)Receivables from entities affiliated with management$142$22,883Receivables from SemGroup7,303—$7,445$22,883 Payables to affiliates consist of the following: March 31,20142013(in thousands)Payables to SemGroup$76,192$4,601Payables to entities affiliated with management6542,299$76,846$6,900 F-51Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 We completed a merger with High Sierra Energy, LP and High Sierra Energy GP, LLC in June 2012. We paid $91.8 million of cash, net of $5.0million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP’slong-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Ourgeneral partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million ofcash and issued 2,685,042 common units to our general partner. During the year ended March 31, 2014, we completed the acquisition of a crude oil logistics business owned by an employee. We paid $11.0 millionof cash for this acquisition. During the year ended March 31, 2013, we completed two business combinations with entities in which members of ourmanagement owned interests. We paid $14.0 million of cash (net of cash acquired) on a combined basis for these two acquisitions. We also paid $5.0 millionunder a non-compete agreement to an employee. Note 16 — Quarterly Financial Data (Unaudited) Our summarized unaudited quarterly financial data is presented below. The computation of net income per common and subordinated unit is 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 liquids segment is also subject to seasonal fluctuations, as demand for propane and butane is typically higher during the winter months. Ouroperating revenues from our other segments are less weather sensitive. Additionally, the acquisitions described in Note 4 impact the comparability of thequarterly information within the year, and year to year. F-52Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial Statements - ContinuedAt March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012 Quarter EndedYear EndedJune 30,September 30,December 31,March 31,March 31,20132013201320142014(in thousands, except unit and per unit data)Total revenues$1,385,957$1,593,937$2,743,445$3,975,935$9,699,274Total cost of sales$1,303,076$1,488,850$2,576,029$3,764,744$9,132,699Net income (loss)$(17,508)$(932)$24,052$43,146$48,758Net income (loss) attributable to parent equity$(17,633)$(941)$23,898$42,331$47,655Earnings (loss) per unit, basic and diluted -Common units$(0.35)$(0.05)$0.27$0.46$0.51Subordinated units$(0.46)$(0.09)$0.23$0.46$0.32Weighted average common units outstanding - basic anddiluted47,703,31358,909,38967,941,72673,421,30961,970,471Weighted 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 31,20122012201220132013(in thousands, except unit and per unit data)Total revenues$326,436$1,135,510$1,338,208$1,617,613$4,417,767Total cost of sales$298,985$1,053,690$1,204,545$1,481,890$4,039,110Net income (loss)$(24,710)$10,082$40,477$22,341$48,190Net income (loss) attributable to parent equity$(24,650)$10,073$40,176$22,341$47,940Earnings (loss) per unit, basic and diluted -Common units$(0.76)$0.18$0.75$0.39$0.96Subordinated units$(0.77)$0.18$0.75$0.39$0.93Weighted 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 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 (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) 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 SECon April 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) 2.18LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWLPearsall SWD, LLC, OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporatedby reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.19LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWLKarnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporatedby reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.20LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC,Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporatedby reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.21LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC,Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporatedby reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.22LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWLOperating, LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLCand High Sierra Transportation, LLC (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172)filed with the SEC on August 7, 2013) 2.23Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP,Gavilon, LLC and Gavilon Energy Intermediate, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on December 5, 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) Table of Contents ExhibitNumberDescription3.3Second 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) 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) 3.11Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as ofAugust 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onAugust 7, 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) Table of Contents ExhibitNumberDescription4.6Amendment 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) 4.8Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by andamong NGL Energy Partners LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 4.9Call 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) 4.10Call 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) 4.11Note 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) 4.12Amendment 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) 4.13Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 9, 2013) 4.14Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s6.65% senior secured notes due 2022 signatory thereto (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, 2013) 4.15Amendment No. 4 to Note Purchase Agreement, dated as of November 5, 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 onNovember 8, 2013) 4.16Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 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 onDecember 30, 2013) 4.17Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors partythereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K(File No. 001-35172) filed with the SEC on October 16, 2013) 4.18Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013) 4.19*First Supplemental Indenture, dated as of December 2, 2013, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee 4.20*Second Supplemental Indenture, dated as of April 22, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiary party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee Table of Contents ExhibitNumberDescription4.21Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp.,the Guarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers(incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16,2013) 4.22Registration Rights Agreement, dated December 2, 2013, by and among NGL Energy Partners LP and the purchasers set forth onSchedule A thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SECon December 5, 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 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) 10.6Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC,each subsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche BankTrust Company Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or“Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with theSEC on October 3, 2013) 10.7Amendment No. 4 to Credit Agreement, dated as of November 5, 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 November 8,2013) 10.8Amendment No. 5 to Credit Agreement, dated as of December 23, 2013, among NGL Energy Operating, LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank and Trust Company Americas and the other financial institutions party thereto(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30,2013) 10.9Facility Increase Agreement among NGL Energy Operating, LLC, Deutsche Bank Trust Company Americas and the other financialinstitutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed withthe SEC on January 3, 2014) Table of Contents ExhibitNumberDescription10.10Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed onSchedule A thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with theSEC on December 5, 2013) 10.11+Letter Agreement among Silverthorne Energy Holdings LLC, Shawn W. Coady and Todd M. Coady dated October 14, 2010(incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 10.12+NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K(File No. 001-35172) filed on May 17, 2011) 10.13+Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long Term Incentive Plan (incorporated 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 31.1*Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002 31.2*Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes — Oxley Act of 2002 32.1*Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes —Oxley Act of 2002 32.2*Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes —Oxley Act of 2002 101.INS**XBRL Instance Document 101.SCH**XBRL Taxonomy Extension Schema Document 101.CAL**XBRL Taxonomy Extension Calculation Linkbase Document 101.DEF**XBRL Taxonomy Extension Definition Linkbase Document 101.LAB**XBRL Taxonomy Extension Label Linkbase Document 101.PRE**XBRL Taxonomy Extension Presentation Linkbase Document * Exhibits filed with this report ** Attached as Exhibit 101 to this report are the following documents formatted in XBRL (Extensible Business Reporting Language):(i) Consolidated Balance Sheets at March 31, 2014 and 2013, (ii) Consolidated Statements of Operations for the years ended March 31, 2014,2013, and 2012, (iii) Consolidated Statements of Comprehensive Income for the years ended March 31, 2014, 2013, and 2012,(iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2014, 2013, and 2012 and (v) Consolidated Statements ofCash Flows for the years ended March 31, 2014, 2013, and 2012. + Management contracts or compensatory plans or arrangements. Exhibit 4.19 FIRST SUPPLEMENTAL INDENTURE FIRST SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), dated as of December 2, 2013, among Gavilon, LLC, Gavilon EnergyHoldings I, LLC, Gavilon Energy Holdings II, LLC, Gavilon Energy Holdings III, LLC, Gavilon Energy Holdings IV, LLC, Gavilon Energy Logistics, LLC,Gavilon Energy Transportation Holdco, LLC, Gavilon Energy Transport Services, LLC, Gavilon Midstream Energy, LLC, Gavilon Oil Tanks andTerminals, LLC, Gavilon Pipeline and Storage, LLC and Gavilon Shipping and Trading, LLC (collectively, the “Guaranteeing Subsidiaries”), each asubsidiary (or a permitted successor thereof) of NGL Energy Partners LP (“NGL LP”), a Delaware limited partnership, NGL LP, NGL Energy Finance Corp.(“Finance Corp.,” and, together with NGL LP, the “Issuers”), the other Guarantors (as defined in the Indenture referred to herein) and U.S. Bank NationalAssociation, as trustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers have heretofore executed and delivered to the Trustee an indenture (the “Indenture”), dated as of October 16, 2013 providingfor the issuance of 6.875% Senior Notes due 2021 (the “Notes”); WHEREAS, the Indenture provides that under certain circumstances each Guaranteeing Subsidiary shall execute and deliver to the Trustee asupplemental indenture pursuant to which each Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes andthe Indenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged,each of the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows: 1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. AGREEMENT TO GUARANTEE. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subjectto the conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof. 3. EXECUTION AND DELIVERY. Each Guaranteeing Subsidiary agrees that the Note Guarantees shall remain in full force and effectnotwithstanding any failure to endorse on each Note a notation of such Note Guarantee. 4. NO RECOURSE AGAINST OTHERS. No past, present or future director, officer, partner, employee, incorporator, organizer, manager,unitholder or other owner of Capital Stock (as defined in the Indenture) of any Guaranteeing Subsidiary or agent thereof, as such,  shall have any liability for any obligations of the Issuers, the Guarantors, or any Guaranteeing Subsidiary or any other Subsidiary of an Issuerproviding a Note Guarantee under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, inrespect of, or by reason of, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federalsecurities laws and it is the view of the SEC that such a waiver is against public policy. 5. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THISSUPPLEMENTAL INDENTURE. 6. COUNTERPARTS. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all ofthem together represent the same agreement. 7. EFFECT OF HEADINGS. The Section headings herein are for convenience only and shall not affect the construction hereof. 8. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries andthe Issuers. 2 IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first abovewritten. GUARANTEEING SUBSIDIARIES: GAVILON, LLCGAVILON ENERGY HOLDINGS I, LLCGAVILON ENERGY HOLDINGS II, LLCGAVILON ENERGY HOLDINGS III, LLCGAVILON ENERGY HOLDINGS IV, LLCGAVILON ENERGY LOGISTICS, LLCGAVILON ENERGY TRANSPORTATION HOLDCO, LLCGAVILON ENERGY TRANSPORT SERVICES, LLCGAVILON MIDSTREAM ENERGY, LLCGAVILON OIL TANKS AND TERMINALS, LLCGAVILON PIPELINE AND STORAGE, LLCGAVILON SHIPPING AND TRADING, LLC By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Chief Financial Officer and Treasurer ISSUERS: NGL ENERGY PARTNERS LP By:NGL Energy Holdings, LLC,its general partner By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Chief Financial Officer and Treasurer NGL ENERGY FINANCE CORP. By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Senior Vice President, Chief Financial Officer and Secretary [Signature Page to First Supplemental Indenture]  EXISTING GUARANTORS: NGL ENERGY OPERATING LLCNGL SUPPLY, LLCHICKSGAS, LLCNGL SUPPLY RETAIL, LLCNGL SUPPLY WHOLESALE, LLCNGL SUPPLY TERMINAL COMPANY, LLCOSTERMAN PROPANE, LLCNGL-NE REAL ESTATE, LLCNGL-MA REAL ESTATE, LLCNGL-MA, LLC By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Chief Financial Officer and Treasurer COASTAL PLAINS DISPOSAL #1, L.L.C.GREENSBURG OILFIELD, LLCANTICLINE DISPOSAL, LLCHIGH SIERRA ENERGY MARKETING, LLCCENTENNIAL ENERGY, LLCCENTENNIAL GAS LIQUIDS ULCHIGH SIERRA TRANSPORTATION, LLCHIGH SIERRA CRUDE OIL & MARKETING, LLCHIGH SIERRA WATER SERVICES, LLCANDREWS OIL BUYERS, INC.THIRD COAST TOWING, LLCHIGH SIERRA WATER-EAGLE FORD, LLCPETRO SOURCE TERMINALS, LLCPECOS GATHERING & MARKETING, L.L.C.BLACK HAWK GATHERING, L.L.C.MIDSTREAM OPERATIONS, LLCHIGH SIERRA SERTCO, LLCHIGH SIERRA ENERGY OPERATING, LLCHIGH SIERRA COMPRESSION, LLCHIGH SIERRA WATER HOLDINGS, LLCHIGH SIERRA KARNES SWD, LLCHIGH SIERRA NIXON SWD, LLCHIGH SIERRA PEARSALL SWD, LLCHIGH SIERRA CANADA HOLDINGS, LLCHIGH SIERRA COTULLA SWD, LLCHIGH SIERRA SWD OPERATOR, LLCHIGH SIERRA SWD SHARED SERVICES, LLCHIGH SIERRA WATER PERMIAN, LLC [Signature Page to First Supplemental Indenture]  LOTUS OILFIELD SERVICES, L.L.C.CC MARINE, LLCCIERRA MARINE GP, LLC By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Chief Financial Officer HIGH SIERRA ENERGY LP By:High Sierra Energy GP, LLC,its general partner By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Chief Financial Officer CIERRA MARINE, L.P. By:Cierra Marine GP, LLC,its general partner By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Chief Financial Officer [Signature Page to First Supplemental Indenture]  TRUSTEE: U.S. BANK NATIONAL ASSOCIATION, as Trustee By:/s/ Israel LugoName: Israel LugoTitle: Vice President [Signature Page to First Supplemental Indenture] Exhibit 4.20 SECOND SUPPLEMENTAL INDENTURE SECOND SUPPLEMENTAL INDENTURE, dated as of April 22, 2014 (this “Supplemental Indenture”), among NGL Energy Partners LP, aDelaware limited partnership (“NGL LP”), NGL Energy Finance Corp., a Delaware corporation (“Finance Corp.,” and, together with NGL LP, the“Issuers”), NGL Crude Transportation, LLC, a Colorado limited liability company and a subsidiary of NGL LP (the “Guaranteeing Subsidiary”), theother Guarantors (as defined in the Indenture referred to herein), and U.S. Bank National Association, as trustee under the Indenture referred to below (the“Trustee”). W I T N E S S E T H WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee an indenture, dated as ofOctober 16, 2013 (the “Original Indenture”), providing for the issuance by the Issuers of 6.875% Senior Notes due 2021 (the “Notes”); WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the First Supplemental Indenture,dated as of December 2, 2013 (the “First Supplemental Indenture”), pursuant to which certain subsidiaries of NGL LP became Guarantors; WHEREAS, the Original Indenture as amended and supplemented by the First Supplemental Indenture is referred to herein as the “Indenture”; WHEREAS, the Indenture provides that, under certain circumstances, the Guaranteeing Subsidiary shall execute and deliver to the Trustee asupplemental indenture pursuant to which the Guaranteeing Subsidiary shall unconditionally guarantee all of the Issuers’ Obligations under the Notes and theIndenture on the terms and conditions set forth herein (the “Note Guarantee”); and WHEREAS, pursuant to Section 9.01 of the Indenture, the Trustee is authorized to execute and deliver this Supplemental Indenture. NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged,the Guaranteeing Subsidiary and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows: 1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. AGREEMENT TO GUARANTEE. The Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject tothe conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof.  3. EXECUTION AND DELIVERY. The Guaranteeing Subsidiary agrees that the Note Guarantees shall remain in full force and effectnotwithstanding any failure to endorse on each Note a notation of such Note Guarantee. 4. NO RECOURSE AGAINST OTHERS. No past, present or future director, officer, partner, employee, incorporator, organizer, manager,unitholder or other owner of Capital Stock (as defined in the Indenture) of any Guaranteeing Subsidiary or agent thereof, as such, shall have anyliability for any obligations of the Issuers, the Guarantors, or any Guaranteeing Subsidiary or any other Subsidiary of an Issuer providing a NoteGuarantee under the Notes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reasonof, such obligations or their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release arepart of the consideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is theview of the SEC that such a waiver is against public policy. 5. NEW YORK LAW TO GOVERN. THE LAW OF THE STATE OF NEW YORK SHALL GOVERN AND BE USED TO CONSTRUE THISSUPPLEMENTAL INDENTURE. 6. COUNTERPARTS. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all ofthem together represent the same agreement. 7. EFFECT OF HEADINGS. The Section headings herein are for convenience only and shall not affect the construction hereof. 8. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of thisSupplemental Indenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiary andthe Issuers. 2 IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first abovewritten. GUARANTEEING SUBSIDIARY: NGL CRUDE TRANSPORTATION, LLC By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Chief Financial Officer and Treasurer ISSUERS: NGL ENERGY PARTNERS LP By:NGL Energy Holdings, LLC,its general partner By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Chief Financial Officer and Treasurer NGL ENERGY FINANCE CORP. By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Senior Vice President, Chief Financial Officer and Secretary EXISTING GUARANTORS: NGL ENERGY OPERATING LLCNGL LIQUIDS, LLC(f/k/a NGL Supply, LLC)HICKSGAS, LLCNGL PROPANE, LLC(f/k/a NGL Supply Retail, LLC)NGL SUPPLY WHOLESALE, LLCNGL SUPPLY TERMINAL COMPANY, LLCOSTERMAN PROPANE, LLCNGL-NE REAL ESTATE, LLCNGL-MA REAL ESTATE, LLCNGL-MA, LLC (Signature Page to Second Supplemental Indenture)  NGL CRUDE LOGISTICS, LLC(f/k/a Gavilon, LLC)NGL ENERGY HOLDINGS II, LLC(f/k/a Gavilon Energy Holdings II, LLC)NGL ENERGY LOGISTICS, LLC(f/k/a Gavilon Energy Logistics, LLC)NGL CRUDE TERMINALS, LLC(f/k/a Gavilon Midstream Energy, LLC)NGL CRUDE CUSHING, LLC(f/k/a Gavilon Oil Tanks and Terminals, LLC)NGL CRUDE PIPELINES, LLC(f/k/a Gavilon Pipeline and Storage, LLC)NGL SHIPPING AND TRADING, LLC(f/k/a Gavilon Shipping and Trading, LLC)GREENSBURG OILFIELD, LLCANTICLINE DISPOSAL, LLCHIGH SIERRA ENERGY MARKETING, LLCCENTENNIAL ENERGY, LLCCENTENNIAL GAS LIQUIDS ULCHIGH SIERRA TRANSPORTATION, LLCHIGH SIERRA CRUDE OIL & MARKETING, LLCNGL WATER SOLUTIONS DJ, LLC(f/k/a High Sierra Water Services, LLC)ANDREWS OIL BUYERS, INC.NGL MARINE, LLC(f/k/a Third Coast Towing, LLC)NGL WATER SOLUTIONS EAGLE FORD, LLC(f/k/a High Sierra Water-Eagle Ford, LLC)PETRO SOURCE TERMINALS, LLCMIDSTREAM OPERATIONS, LLCHIGH SIERRA SERTCO, LLCHIGH SIERRA ENERGY OPERATING, LLCHIGH SIERRA COMPRESSION, LLCNGL WATER SOLUTIONS, LLC(f/k/a High Sierra Water Holdings, LLC)NGL CRUDE CANADA HOLDINGS, LLC(f/k/a High Sierra Canada Holdings, LLC)NGL WATER SOLUTIONS PERMIAN, LLC(f/k/a High Sierra Water Permian, LLC)LOTUS OILFIELD SERVICES, L.L.C. By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Chief Financial Officer and Treasurer (Signature Page to Second Supplemental Indenture - Continued)  HIGH SIERRA ENERGY LP By:High Sierra Energy GP, LLC,its general partner By:/s/ Atanas H. AtanasovName: Atanas H. AtanasovTitle: Chief Financial Officer (Signature Page to Second Supplemental Indenture - Continued)  TRUSTEE: U.S. BANK NATIONAL ASSOCIATION, as Trustee By:/s/ Israel LugoName: Israel LugoTitle: Vice President (Signature Page to Second Supplemental Indenture) Exhibit 12.1 NGL ENERGY PARTNERS LP AND SUBSIDIARIES AND NGL SUPPLY, INC.COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES(In thousands, except ratio amounts) NGL Energy Partners LPNGL Supply, Inc.Six MonthsSix MonthsYearEndedEndedEndedYear Ended March 31,March 31,September 30,March 31,201420132012201120102010 EARNINGS:Income (loss) from continuing operationsbefore income taxes$49,695$50,065$8,465$12,679$(3,977)$6,108Loss (income) from continuing operationsbefore income taxes attributable tononcontrolling interests(1,103)(250)12—456Fixed charges91,62266,8249,3542,7615971,149Total earnings (loss)$140,214$116,639$17,831$15,440$(3,335)$7,263 FIXED CHARGES:Interest expense$58,854$32,994$7,620$2,482$372$668Loss on early extinguishment of debt—5,769————Portion of rental expense estimated to relateto interest (a)32,76828,0611,734279225481Fixed charges$91,622$66,824$9,354$2,761$597$1,149 Ratio of earnings to fixed charges1.531.751.915.59(b)6.32 (a) Represents one-third of the total operating lease rental expense, which is that portion estimated to represent interest. (b) Due to NGL Supply, Inc.’s loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2010. NGL Supply, Inc.would have needed to generate an additional $3.9 million of earnings to achieve a ratio of 1:1. 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, LLCDelawareOsterman 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, LLCTexasHigh Sierra Canada Holdings, LLCColoradoHigh Sierra Energy Canada ULCAlbertaHigh Sierra Transportation, LLCColoradoHigh Sierra Marine, 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)DelawareNGL Energy Finance CorpDelawareGavilon, LLCDelawareLotus Oilfield Services, LLCTexasNHG Investments, LLCColoradoE Energy Adams, LLC (4)NebraskaGavilon Midstream Energy, LLCDelawareGavilon Pipeline and Storage, LLCOklahomaGavilon Oil Tanks and Terminals, LLCOklahomaGavilon Energy Holdings II, LLCDelawareGlass Mountain Pipeline, LLC (5)DelawareNGL Shipping and Trading, LLCDelawareGavilon Energy Logistics, LLCDelaware  (1) NGL Energy Partners LP owns a 60% member interest in Atlantic Propane LLC. (2) NGL Energy Partners LP owns an 80% member interest in High Sierra SERTCO, LLC. (3) NGL Energy Partners LP owns a 75% member interest in Indigo Injection #3-1, LLC. (4) NGL Energy Partners LP owns an 11% member interest in E Energy Adams, LLC. (5) NGL Energy Partners LP owns a 50% member interest in Glass Mountain Pipeline, LLC. Exhibit 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We have issued our reports dated May 30, 2014, with respect to the consolidated financial statements and internal control over financial reporting included inthe Annual Report of NGL Energy Partners LP on Form 10-K for the year ended March 31, 2014. We hereby consent to the incorporation by reference of saidreports in the Registration Statements of NGL Energy Partners LP on Form S-8 (File No. 333-185068) and on Forms S-3 (File No. 333-189842 and FileNo. 333-194035). /s/ GRANT THORNTON LLP Tulsa, OklahomaMay 30, 2014 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. Dated: May 30, 2014/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. Dated: May 30, 2014/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, 2014 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: May 30, 2014/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, 2014 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: May 30, 2014/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. 

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