NGL Energy Partners Annual Report 2015

Plain-text annual report

Table of Contents UNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549 Form 10-K (Mark One) xx ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended March 31, 2015 or oo TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF1934 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 Class Name 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 (Section 229.405 of this chapter) is not containedherein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III ofthis Form 10-K or any amendment to this Form 10-K. o Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. 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(Do not check if a smallerreporting company) 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, 2014 of the Common Units held by non-affiliates of the registrant, based on the reported closing price ofthe Common Units on the New York Stock Exchange on such date ($39.37 per Common Unit) was $3,078,563,331. 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 suchexecutive officers, directors and 10% beneficial owners are affiliates. At May 25, 2015, there were 106,328,594 common units issued and outstanding. Table of Contents TABLE OF CONTENTS PART I Item 1.Business3Item 1A.Risk Factors32Item 1B.Unresolved Staff Comments55Item 2.Properties55Item 3.Legal Proceedings56Item 4.Mine Safety Disclosures56 PART II Item 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities57Item 6.Selected Financial Data58Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations60Item 7A.Quantitative and Qualitative Disclosures About Market Risk98Item 8.Financial Statements and Supplementary Data100Item 9.Changes In and Disagreements With Accountants on Accounting and Financial Disclosure100Item 9A.Controls and Procedures100Item 9B.Other Information101 PART III Item 10.Directors, Executive Officers and Corporate Governance102Item 11.Executive Compensation108Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters118Item 13.Certain Relationships and Related Transactions and Director Independence121Item 14.Principal Accountant Fees and Services125 PART IV Item 15.Exhibits and Financial Statement Schedules126 iTable 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 beliefsand those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified asany statement that does not relate strictly to historical or current facts. When used in this Annual Report, words such as “anticipate,” “believe,” “could,”“estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will,” and similar expressions and statements regarding our plans and objectivesfor future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which suchforward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct.Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or ifunderlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key riskfactors 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 and distillates 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 areas in which we have water treatment and disposal 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; 1Table of Contents · 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; · 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, and recycling, and dischargeservices; · the ability to renew leases for our leased equipment and storage facilities; · the nonpayment or nonperformance by our customers; · the availability and cost of capital and our ability to access certain capital sources; · a deterioration of the credit and capital markets; · the ability to successfully identify and consummate strategic acquisitions and 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; · the costs and effects of legal and administrative proceedings; · any reduction or the elimination of the federal 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 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 Part I, Item 1A—“Risk Factors.” 2Table of Contents PART I References in this Annual Report to (i) “NGL Energy Partners LP,” the “Partnership,” “we,” “our,” “us,” or similar terms refer to NGL EnergyPartners LP and its operating subsidiaries, (ii) “NGL Energy Holdings LLC” or “general partner” refers to NGL Energy Holdings LLC, our general partner,(iii) “NGL Energy Operating LLC” or “operating company” refers to NGL Energy Operating LLC, the direct operating subsidiary of NGL Energy PartnersLP, (iv) the “NGL Energy GP Investor Group” refers to, collectively, the 39 individuals and entities that own all of the outstanding membership interests inour general partner, and (v) the “NGL Energy LP Investor Group” refers to, collectively, the 15 individuals and entities that owned all of our outstandingcommon units before the closing date of our initial public offering. We have presented operational data in Part I, Item 1—“Business” for the year ended March 31, 2015. Unless otherwise indicated, this data is as ofMarch 31, 2015. Item 1. Business Overview We are a Delaware limited partnership formed in September 2010. Subsequent to our formation, we significantly expanded our operations throughnumerous business combinations. At March 31, 2015, our operations include: · Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, owned and leased pipeline injectionstations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned and leased barges and towboats, and a 50%interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned andleased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. · Our water solutions segment, the assets of which include water treatment and disposal facilities. Our water solutions segment generates revenuesfrom the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recoveredhydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids. · Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United Statesand in Canada, and which provides natural gas liquids terminaling services through its 21 owned terminals throughout the United States andrailcar transportation services through its fleet of leased railcars. Our liquids segment purchases propane, butane, and other products fromrefiners, processing plants, producers, and other parties, and sells the products to retailers, refiners, petrochemical plants, and other participantsin the wholesale markets. · Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural,commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia. · Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the2.0% general partner interest and a 19.6% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined productsterminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and a 50% interestin Frontera Brownsville LLC (“Frontera”), which are entities that own refined products storage facilities. For more information regarding our reportable segments, please see Note 13 to our consolidated financial statements included in this Annual Report. Acquisitions Subsequent to our initial public offering (“IPO”) in May 2011, we significantly expanded our operations through numerous acquisitions, includingthe following, among others: 3Table of Contents Year Ended March 31, 2012 · In October 2011, we completed a business combination with E. Osterman Propane, Inc., its affiliated companies, and members of the Ostermanfamily (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., whereby we acquired retail propane and distillateoperations in the northeastern United States. Year Ended March 31, 2013 · In May 2012, we acquired the retail propane and distillate operations of Downeast Energy Corp. These operations are primarily in thenortheastern 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 andmarketing; 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. Year Ended March 31, 2014 · In July 2013, we completed a business combination whereby we acquired the operating assets of Crescent Terminals, LLC, which operates aleased crude oil storage and dock facility in Port Aransas, Texas, and the ownership interests in Cierra Marine, LP and its affiliated companies(collectively, “Crescent”), whereby we acquired a fleet of four towboats and seven crude oil barges operating in the intercoastal waterways ofTexas. · In July 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd., whereby we acquired a water treatmentand disposal facility in the Permian Basin in Texas. We also entered into a development agreement that provides us the right to purchase watertreatment and disposal facilities developed by the other party to the agreement, and we are also party to a solids facilities developmentagreement with this other party. During March 2014, we purchased one additional facility under this development agreement. During the yearended March 31, 2015, we purchased 16 water treatment and disposal facilities under this development agreement. · In August 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively,“OWL”). The businesses of OWL include four water treatment and disposal facilities in the Eagle Ford shale play in Texas. · In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), whereby we acquired theownership interests in three water treatment and disposal facilities in the Eagle Ford shale play in Texas, and the option to acquire an additionalfacility, which we exercised in March 2014. · In December 2013, we acquired the ownership interests in Gavilon, LLC (“Gavilon Energy”). The assets of Gavilon Energy include crude oilterminals in Oklahoma, Texas and Louisiana, a 50% interest in Glass Mountain Pipeline, LLC 4Table of Contents (“Glass Mountain”), which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma and becameoperational in February 2014, and an interest in an ethanol production facility in the Midwest. The operations of Gavilon Energy include themarketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids, and also include crude oil storage in Cushing, Oklahoma. Year Ended March 31, 2015 · In July 2014, we acquired TransMontaigne Inc. (“TransMontaigne”). As part of this transaction, we also purchased inventory from the previousowner of TransMontaigne. The operations of TransMontaigne include the marketing of refined products. As part of this transaction, we acquiredthe 2.0% general partner interest, the incentive distribution rights, a 19.7% limited partner interest in TLP, and assumed certain terminalingservice agreements with TLP from an affiliate of the previous owner of TransMontaigne. · In November 2014, we completed the acquisition of two saltwater disposal facilities in the Bakken shale play in North Dakota. · In February 2015, we acquired Sawtooth NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utahwith rail and truck access to western U.S. markets and entered into a construction agreement to expand the storage capacity of the facility. 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 March 31, 2012 5Table of Contents Primary Service Areas at March 31, 2013 Primary Service Areas at March 31, 2014 6Table of Contents Primary Service Areas at March 31, 2015 7Table of Contents Organizational Chart The following chart provides a summarized view of our legal entity structure at March 31, 2015: (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. 8Table 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 ongoingstability of our business and its cash flows. We expect to achieve this objective by executing the following strategies: · Focus on building a vertically integrated midstream master limited partnership providing multiple services to producers. We continue toenhance our ability to transport crude oil from the wellhead to refiners, refined products from refiners to customers, wastewater from thewellhead to treatment for disposal, recycle, or discharge, and natural gas liquids from processing plants to end users, including retail propanecustomers. · Achieve organic growth by investing in new assets that increase volumes, enhance our operations, and generate attractive rates of return. Webelieve that there are accretive organic growth opportunities that originate from assets we have acquired. We also believe that there are furtherorganic growth opportunities within our existing businesses, particularly within our crude oil logistics, water solutions, and refined productsbusinesses. · Deliver accretive growth through strategic acquisitions that complement our existing business model and expand our operations. We intend tocontinue to pursue acquisitions that build upon our vertically integrated business model, add scale to our crude oil logistics platform, andenhance our geographic diversity in our water solutions business. 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, or margin-based revenues under multi-year contracts. In our liquids, crude oil logistics, and refined products businesses, we intend to focus on long-termcontracts associated with pipelines in addition to back-to-back contracts which minimize commodity price exposure. In our water solutionsbusiness, cash flows are supported by certain fee-based, multi-year contracts, some of which include acreage dedications from producers orvolume commitments. 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. Our refined productsbusiness is backed by term marketing agreements and long-term throughput agreements for terminaling operations. · 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 cash flowsfrom our operations to make distributions to our unitholders and to use excess cash flows to finance organic growth and opportunistically repayindebtedness, 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 objective because of thefollowing competitive strengths: · Our seasoned management team with extensive midstream industry experience and a track record of acquiring, integrating, operating andgrowing successful businesses. Our management team has significant experience managing companies in the energy industry, including masterlimited partnerships. In addition, through decades of experience, our management team has developed strong business relationships with keyindustry 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-year basis.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 9Table of Contents leverage the expertise of our liquids business to help improve our margins and profitability and enhance our cash flows. Furthermore, we believethat our liquids business provides us with valuable market intelligence that helps us identify potential acquisition opportunities. Our refinedproducts and retail propane businesses benefit from lower energy prices. · Our network of crude oil transportation assets, which allows us to serve customers over a wide geographic area and optimize sales. Ourstrategically 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 to deliver crude oil to the optimal markets. · Our water processing facilities, which are strategically located near areas of high crude oil and natural gas production. Our water processingfacilities are located among the most prolific crude oil and natural gas producing areas in the United States, including the Permian Basin, the DJBasin, the Eagle Ford shale play, the Bakken shale play, and the Pinedale Anticline. In addition, we believe that the technological capabilitiesof our water solutions business can be quickly implemented at new facilities and locations. · Our network of natural gas liquids transportation, terminal, and storage assets, which allow us to provide multiple services over thecontinental United States. Our strategically located terminals, large railcar fleet, shipper status on common carrier pipelines, and substantialleased and owned 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 and generatehigher margins than other customers. Our high percentage of propane tank ownership, payment billing systems, and automatic deliveryprogram have resulted in a strong record of customer retention and help us better predict our cash flows in the retail propane business. · Our access to refined products pipeline and terminal infrastructure. Our capacity allocations on third-party pipelines and our access to TLP’srefined products terminals give us the opportunity to serve customers over a large geographic area. Our Businesses Crude Oil Logistics Overview. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injectionstations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. Our operations are centered near areas of high crude oilproduction, such as the Bakken shale play in North Dakota, the DJ Basin in Colorado, the Mississippi Lime shale play in Oklahoma, the Permian Basin inTexas and New Mexico, the Eagle Ford shale play in Texas, the Anadarko Basin in Oklahoma and Texas, and southern Louisiana at the Gulf of Mexico. Operations. We purchase crude oil from producers and transport it to refineries or for resale. Our strategically deployed railcar fleet, towboats, barges,and trucks, and our owned and contracted pipeline capacity, provide access to a wide range of customers and markets. We use this expansive network oftransportation assets to deliver crude oil to the optimal markets. We currently transport approximately 275,000 barrels per day of crude oil using the following assets: · 300 owned trucks and 300 owned trailers operating primarily in the Mid-Continent, Permian Basin, Eagle Ford shale play, and RockyMountain regions; · 400 owned railcars and 350 leased railcars operating primarily in Colorado, New Mexico, North Dakota, Oklahoma, Wyoming, and West Texas;and · 8 owned towboats, 19 owned barges, 2 leased towboats and 6 leased barges operating primarily in the intercoastal waterways of the Gulf Coastand along the Mississippi and Arkansas river systems. Of our 400 owned railcars, all are compliant with the standards for railcars built subsequent to 2011. Of our 350 leased railcars, 100 are compliantwith these standards. 10Table of Contents We contract for truck, rail, and barge transportation services from third parties and ship on 17 common carrier pipelines. We own 44 pipelineinjection stations. The location of these facilities is summarized below. Number of Pipeline State Injection Stations Oklahoma 17 Texas 15 New Mexico 5 Kansas 3 North Dakota 3 Montana 1 Total 44 We also lease 5 pipeline injection stations in Kansas, Montana, and North Dakota. We own and lease several rail transload facilities and haveseveral throughput agreements at rail transload facilities in Colorado, New Mexico, North Dakota, and Oklahoma. We also have commitments on severalinterstate pipelines for transportation of crude oil. We own seven storage terminal facilities. The largest of these is a terminal in Cushing, Oklahoma with a storage capacity of 4,140,000 barrels,1,000,000 barrels of which are owned by Glass Mountain. The combined storage capacity of the other six terminals is 462,500 barrels. We lease 3,703,000 barrels of capacity at three storage terminal facilities. Of this leased storage capacity, 3,350,000 barrels are at Cushing,Oklahoma. We have one Gulf Coast terminal facility that is under construction and is expected to be completed early in fiscal year 2017 with a total expectedstorage capacity of 300,000 barrels. We own a 50% interest in Glass Mountain, which owns a 210-mile crude oil pipeline that originates in western Oklahomaand terminates in Cushing, Oklahoma. This pipeline, which became operational in February 2014, has a capacity of 147,000 barrels per day. We also ownGrand Mesa, which is constructing a 20-inch crude oil pipeline originating in Weld County, Colorado and terminating at our Cushing, Oklahoma terminal.We anticipate that the pipeline will commence service in the second half of calendar year 2016. Upon completion, Grand Mesa is expected to have a capacityin excess of 200,000 barrels per day. Rimrock Midstream LLC’s Platte River gathering system, which is currently under development, is expected to delivervolumes from multiple shippers to Grand Mesa’s northern origin near Lucerne, Colorado. Customers. Our customers include crude oil refiners, producers, and marketers. During the year ended March 31, 2015, 65% of the revenues of thecrude oil logistics segment were generated from our ten largest customers of the segment. In addition to utilizing our assets to transport crude oil we own, wealso provide truck transportation, barge transportation, storage, and terminal throughput services to our customers. Competition. Our crude oil logistics business faces significant competition, as many entities are engaged in the crude oil logistics business, some ofwhich are larger and have greater financial resources than we do. The primary factors on which we compete are: · price; · availability of supply; · reliability of service; · logistics capabilities, including the availability of railcars, proprietary terminals, and owned pipelines, barges, railcars, trucks, and towboats; 11Table of Contents · long-term customer relationships; and · the acquisition of businesses. Supply. We obtain crude oil from a large base of suppliers, which consists primarily of crude oil producers. We currently purchase crude oil from 600producers at 6,200 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 hedgingexposure due to fluctuations in actual volumes and scheduled volumes. Our profitability is impacted by forward crude oil prices. Crude oil markets can either be in contango (a condition in which the forward crude price isgreater than the spot price) and can be backwardated (a condition in which the forward crude price is lower than the spot price). Our crude oil logisticsbusiness benefits when the market is in contango, as increasing prices result in inventory holding gains during the time between when we purchase inventoryand when we sell it. In addition, we are able to better utilize our storage assets when crude oil markets are in contango. When markets are backwardated,falling prices typically have an unfavorable impact on our margins. Billing and Collection Procedures. Our crude oil logistics customers consist primarily of crude oil refiners, producers, and marketers. We typicallyinvoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures onour crude oil logistics customers. We believe the following procedures enhance our collection efforts with our crude oil logistics customers: · we require certain customers to prepay or place deposits for our services; · we require certain customers to post letters of credit on a portion of our receivables; · we review receivable aging analyses regularly to identify issues or trends that may develop; and · we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paidinvoices. Trade Names. Our crude oil logistics segment operates primarily under the NGL Crude Logistics, NGL Crude Transportation and NGL Marine tradenames. Water Solutions Overview. Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gasproduction, from the sale of recycled water and recovered hydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids. Our facilitiesare located near areas of high crude oil and natural gas production, including the Permian Basin in Texas, the DJ Basin in Colorado, the Eagle Ford shale playin Texas, the Bakken shale play in North Dakota, and the Pinedale Anticline in Wyoming. During the three months ended March 31, 2015, we took deliveryof 48.9 million barrels of wastewater, an average of 543,000 barrels per day. Our water solutions segment is in the process of expanding its disposal business. With the addition of specialized equipment to select facilities inthe Eagle Ford shale play, the Permian Basin, and the DJ Basin, we will be able to accept and dispose of solids such as tank bottoms and drilling fluidsgenerated by crude oil and natural gas exploration and production activities. Our facilities will accept only exploration and production exempt wasteallowed under our current permits. Operations. We own 46 water treatment and disposal facilities, including 58 wells. The location of the facilities and the processing capacities atwhich the facilities currently operate are summarized below. 12Table of Contents Processing Located on Capacity Land We OwnLocation (barrels per day) or LeasePinedale Anticline:Pinedale, Wyoming (A)60,000LeaseDJ Basin:Briggsdale, Colorado (B)34,000OwnGrover, Colorado25,000OwnGreeley, Colorado18,000LeaseGrover, Colorado17,500LeasePlatteville, Colorado (B)16,200OwnKersey, Colorado14,000OwnOrchard, Colorado10,000OwnLaSalle, Colorado5,900OwnBrighton, Colorado5,100OwnTotal—DJ Basin145,700Permian Basin:Mentone, Texas35,000OwnOrla, Texas (C)35,000OwnBig Lake, Texas30,000OwnOrla, Texas30,000OwnBig Spring, Texas25,000OwnGarden City, Texas25,000OwnKermit, Texas25,000OwnRankin, Texas25,000OwnPecos, Texas23,000OwnColorado City, Texas20,000OwnCrane, Texas20,000OwnMidland, Texas20,000OwnMidkiff, Texas18,000OwnBarnhart, Texas16,000OwnAndrews, Texas12,000OwnTotal—Permian Basin359,000Eagle Ford Shale Play:Carrizo Springs, Texas (D)22,500LeaseCatarina, Texas (D)22,000LeaseCharlotte, Texas22,000OwnCheapside, Texas22,000OwnGillett, Texas22,000OwnKarnes City, Texas22,000OwnArtesia Wells, Texas20,000OwnLos Angeles, Texas20,000LeaseNixon, Texas20,000OwnTilden, Texas20,000LeaseWesthoff, Texas (C)20,000OwnFowlerton, Texas18,000OwnPearsall, Texas17,000LeaseCotulla, Texas16,500OwnDilley Lea, Texas15,000LeaseCatarina, Texas (D)12,000LeaseTotal—Eagle Ford Shale Play311,000Eaglebine Shale Play:Madisonville, Texas20,000OwnGranite Wash Shale Play:Wheeler, Texas27,000OwnCanadian, Texas25,000OwnTotal—Granite Wash Shale Play52,000Bakken Shale Play:Killdeer, North Dakota20,000LeaseJohnsons Corner, North Dakota20,000OwnTotal—Bakken Shale Play40,000Total—All Facilities987,700 13Table of Contents (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 of15,000 barrels per day to process water to a discharge standard. (B) The processing capacity listed above for each of these facilities includes a design capacity of 10,000 barrels per day to process water to a recyclestandard. (C) These facilities can dispose of both wastewater and solids such as tank bottoms and drilling fluids. We own a 50% interest in the disposal ofsolids. (D) Reflects the total processing capacity of each facility, of which we own a 75% interest in each of these facilities. Our customers bring wastewater generated by crude oil and natural gas exploration and production operations to our facilities for treatment throughpipeline gathering systems, which we plan to further expand, and by truck. Once we take delivery of the water, the level of processing is determined by theultimate disposition of the water. Our solids customers bring solids generated by crude oil and natural gas exploration and production operations to ourfacilities with trucks. 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 producers to be reused in future drilling operations(recycle quality water), or we treat the water to a greater extent, such that it exceeds the standards for drinking water, and can be returned to the ecosystem(discharge quality water). Recycling offers producers an alternative to the use of fresh water in hydraulic fracturing operations. This minimizes the impact onaquifers, particularly in arid regions of the United States. We have recycled approximately 9 million barrels (378 million gallons) of recycle quality watersince our merger with High Sierra in June 2012. We have returned approximately 5 million barrels (210 million gallons) of discharge quality water back toNew Fork River, which is a tributary of the Colorado River. We also make discharge quality water available to producers and the surrounding community forpurposes such as dust control. 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 and North Dakota dispose of wastewater into deep underground formations via injection wells. At our disposal facilities, we use proprietary well maintenance programs to enhance injection rates and extend the service lives of the wells. Customers. The customers of our Wyoming and Colorado facilities consist primarily of large exploration and production companies that conductdrilling operations near our facilities. The customers of our Texas and North Dakota facilities consist of both wastewater transportation companies andproducers. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume of water to our facility under long-termcontracts. The primary customers of our facilities in Colorado have committed to deliver to our facilities all wastewater produced at all wells in a designatedarea. One customer in Texas has committed to deliver at least 50,000 barrels of wastewater per day to our facilities. Most of the customers at our otherfacilities are not under volume commitments. During the year ended March 31, 2015, 23% of the water treatment and disposal revenues of the water solutionssegment were generated from our two largest customers of the segment, and 57% of the water treatment and disposal revenues of the segment were generatedfrom 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 crude oil and natural gas producers, and also include smaller watertransportation companies. We typically invoice customers on a monthly basis. We perform credit analysis, 14Table of Contents require credit approvals, establish credit limits, and follow monitoring procedures on our water solutions customers. We believe the following proceduresenhance our collection efforts with our water solutions customers: · we require certain customers to prepay or place deposits for our services; · we review receivable aging analyses regularly to identify issues or trends that may develop; and · we require our marketing personnel to manage their customers’ receivable position and suspend service to customers that have not timely paidinvoices. Trade Names. Our water solutions segment operates primarily under the NGL Water Solutions and Anticline Disposal trade names. Technology. We hold multiple patents for processing technologies. We own a research and development center, which we use to optimize treatmentprocesses and cost minimization. We believe that the technological capabilities of our water solutions business can be quickly implemented at new facilitiesand locations. 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. During theyear ended March 31, 2015, we sold 2.1 billion gallons of natural gas liquids, an average of 5.75 million gallons per day. Operations. We procure natural gas liquids from refiners, gas processing plants, producers and other resellers for delivery to leased or owned storagespace, common carrier pipelines, railcar terminals, and direct to certain customers. Our customers take delivery by loading natural gas liquids into transportvehicles from common carrier pipeline terminals, private terminals, our terminals, directly from refineries and rail terminals, and by railcar. 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. Presales also reduce the impact of warm weather because the customer is required to takedelivery of the propane regardless of the weather. We generally require cash deposits from these customers. In addition, on a daily basis we have the ability tobalance our inventory by buying or selling propane, butanes, and natural gasoline to refiners, resellers, and propane producers through pipeline inventorytransfers 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 storageto store butane for this purpose. We also transport customer-owned natural gas liquids on our leased railcars and charge the customers a transportation service fee. In addition, wesublease railcars to certain customers. In addition, we purchase and sell asphalt. We utilize leased railcars to move the asphalt from our suppliers to our customers. We own 21 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. 15Table of Contents The following chart lists our natural gas liquids terminals and their throughput capacity: Throughput CapacityFacility(gallons per day)Rosemount, Minnesota1,441,000Lebanon, Indiana1,058,000West Memphis, Arkansas1,058,000Dexter, Missouri930,000East St. Louis, Illinois883,000Jefferson City, Missouri883,000St. Catherines, Ontario, Canada700,000Janesville, Wisconsin553,000Light, Arkansas524,400Rixie, Arkansas524,400Winslow, Arizona500,000West Springfield, Massachusetts441,000Albuquerque, New Mexico408,000Kingsland, Arkansas405,000Portland, Maine360,000Vancouver, Washington358,000Green Bay, Wisconsin310,000Thackerville, Oklahoma235,000Ritzville, Washington198,000Sidney, Montana180,000Shelton, Washington161,000Total12,110,800 We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouri areoperated for us by a third party for a monthly fee under an operating and maintenance agreement 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 11 of the terminals are located and we either have easements or lease the land on which ten 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. In February 2015 we acquired an underground storage facility near Delta, Utah. This facility currently has capacity to store approximately 1.8million barrels of natural gas liquids. We have begun construction of new caverns to expand the storage capacity, and we expect these new caverns to beoperational during the year ending March 31, 2016. We lease storage to 11 customers, with lease terms ranging from one to four years. The facility is locatedon property for which we have a long-term lease. We lease 4,591 railcars, of which 520 are subleased to a third party. These include high pressure and general-purpose railcars. We own 23 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, and Texas. 16Table of Contents The following chart shows our leased storage space at natural gas liquids storage facilities and interconnects to those facilities: Leased Storage Space (gallons) Beginning At April 1, March 31, Storage Facility2015 2015 Storage InterconnectsConway, Kansas64,940,00073,290,000Connected to Enterprise Mid-America and NuStar Pipelines; RailFacilityBorger, Texas42,000,00042,000,000Connected to ConocoPhillips Blue Line PipelineBushton, Kansas12,600,00010,500,000Connected to ONEOK North System PipelineMont Belvieu, Texas3,150,0003,150,000Connected to Enterprise Texas Eastern Products PipelineCarthage, Missouri7,560,0007,560,000Connected to Mid-America PipelineMarysville, Michigan2,100,0004,200,000Connected to Cochin PipelineHattiesburg, Mississippi11,340,0006,930,000Connected to Enterprise Dixie Pipeline; Rail FacilityRedwater, Alberta, Canada9,072,0007,938,000Connected to Cochin Pipeline; Rail FacilityRegina, Saskatchewan, Canada—1,260,000Connected to Cochin Pipeline; Rail FacilitySt. Clair, Michigan6,300,000—Rail FacilityAdamana, Arizona1,680,0001,398,600Rail FacilityCorunna, Ontario, Canada2,100,0002,100,000Rail FacilityTotal162,842,000160,326,600 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 approximately 900 customers in 47 states. Our liquids business serves national, regional and independentretail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. Our liquids business also supplies the majority of thepropane for our retail propane business. We deliver the propane supply to our customers at terminals located on common carrier pipeline systems, railterminals, refineries, and major United States propane storage hubs. During the year ended March 31, 2015, 33% of the revenues of the liquids segment weregenerated from our ten largest customers of the segment (exclusive of sales to our retail propane segment). Seasonality. Our wholesale propane business is affected by the weather in a similar manner as our retail propane business as discussed below.However, we are able to partially mitigate the effects of seasonality by preselling a portion of our wholesale volumes to retailers and wholesalers andrequiring the customer to take delivery regardless of the weather. Competition. Our liquids business faces significant competition, as many entities, including other natural gas liquids wholesalers and companiesinvolved in the natural gas liquids midstream industry (such as terminal and refinery operations), are engaged in the liquids business, some of which havegreater financial resources than we do. The primary factors on which we compete are: · price; · availability of supply; · reliability of service; · available space on common carrier pipelines; · storage availability; · logistics capabilities, including the availability of railcars, and proprietary terminals; 17Table of Contents · long-term customer relationships; and · the acquisition of businesses. 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; · market based, which can either be a posted price or an index to spot price at time of delivery; and · load package, a firm price agreement for customers seeking to purchase specific volumes delivered during a specific time period. We 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 maynot be matched with a purchase commitment. We generally require deposits from our customers for fixed priced future delivery of propane if the delivery date is more than 30 days after the timeof contractual 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 as1,000,000 gallons, and deliveries can occur over time periods extending from days to as long as a year. We perform credit analysis, require credit approvals,establish credit limits, and follow monitoring procedures on our liquids customers. We believe the following procedures enhance our collection efforts withour liquids customers: · we require certain customers to prepay or place deposits for their purchases; · we require certain customers to post letters of credit on a portion of our receivables; · we require certain customers to take delivery of their contracted volume ratably to help control the account balance rather than allowing themto take delivery of propane at their discretion; · we review receivable aging analyses regularly to identify issues or trends that may develop; and · we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paidinvoices. Trade Names. Our liquids segment operates primarily under the NGL Supply Wholesale, NGL Supply Terminal Company, Sawtooth NGL Caverns,Centennial Energy, and Centennial Gas Liquids trade names. Retail Propane Overview. Our retail propane segment consists of the retail marketing, sale and distribution of propane and distillates, including the sale and lease ofpropane tanks, equipment and supplies, to more than 300,000 residential, agricultural, commercial and industrial customers. We also sell propane to certainresellers. We purchase the majority of the propane sold in our retail propane business from our liquids business, which provides our retail propane businesswith a stable and secure supply of propane. During the year ended March 31, 2015, we sold 204.1 million gallons of propane and distillates, an average of559,000 gallons per day. 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 107customer service locations and 91 satellite distribution locations, with aggregate propane storage capacity of 11.5 million gallons and aggregate distillatestorage capacity of 3.7 million gallons. Our customer service locations are staffed and operated to service a defined geographic market area and typicallyinclude a business office, product showroom, and secondary propane storage. Our satellite distribution locations, which are unmanned storage tanks, allowour customer service centers to serve an extended market area. 18Table of Contents Our customer service locations in Illinois and Indiana also rent over 16,000 water softeners and filters, primarily to residential customers in ruralareas to treat well water or other problem water. We sell water conditioning equipment and treatment supplies as well. Although the water-conditioningportion of our retail propane business is small, it generates steady year round revenues. The customer bases in Illinois and Indiana for retail propane and waterconditioning have significant overlap, providing the opportunity to cross-sell both products between those customer bases. The following table shows the number of our customer service locations and satellite distribution locations by state: Number of Customer Number of SatelliteService DistributionStateLocations LocationsIllinois2221Maine1610Georgia143Massachusetts108North Carolina81Pennsylvania73Kansas626Indiana45Connecticut42South Carolina3—New Hampshire21Oregon21Washington2—Mississippi13Maryland11Rhode Island11Tennessee11Utah11Wyoming11Colorado1—New Jersey—1Vermont—1Total10791 We own 82 of our 107 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, 2015, we owned thefollowing propane storage tanks: · 400 bulk storage tanks with capacities ranging from 2,000 to 90,000 gallons; and · over 300,000 stationary customer storage tanks with capacities ranging from 7 to 30,000 gallons. We also lease an additional 20 bulk storage tanks. At March 31, 2015, we owned a fleet of 430 bulk delivery trucks, 40 semi-tractors, 40 propane transport trailers and 490 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 50 to 30,000gallons. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 25 gallons. These cylinders are eitherpicked up on a delivery route, refilled at our customer service locations, and 19Table of Contents then returned to the retail customer, or refilled at the customer’s location. Customers can also bring the cylinders to our customer service centers to be refilled. Approximately 69% of our residential customers receive their propane supply via our automatic route delivery program, which allows us tomaximize our delivery efficiency. For these customers, our delivery forecasting software system utilizes a customer’s historical consumption patternscombined with current weather conditions to more accurately predict the optimal time to refill the customer’s tank. The delivery information is then uploadedto routing software to calculate the most cost effective delivery route. Our automatic delivery program promotes customer retention by providing anuninterrupted supply of propane and enables us to efficiently conduct route deliveries on a regular basis. Some of our purchase plans, such as level paymentbilling, 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, commercial and industrial, and agricultural. AtMarch 31, 2015, 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, 2015. 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 timeof harvest. Propane and distillate sales to commercial and industrial customers, while affected by economic patterns, are not as seasonal as sales to residentialand agricultural customers. Competition. Our retail propane business faces significant competition, as many entities are engaged in the retail propane business, some of whichhave greater financial resources than we do. Also, we compete with alternative energy sources, including natural gas, fuel oil, and electricity. The primaryfactors on which we compete are: · price; · availability of supply; · reliability of service; · long-term customer relationships; and · the acquisition of businesses. Competition with other retail propane distributors in the propane industry is highly fragmented and generally occurs on a local basis with otherlarge full-service, multi-state propane marketers, smaller local independent marketers, and farm cooperatives. Our customer service locations generally haveone to five competitors in their market area. The competitive landscape of the markets that we serve has been fairly stable. Each customer service location operates in its own 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 55 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 20Table of Contents level of service to our customers. We also believe that our overall service capabilities and customer responsiveness differentiate us from many of ourcompetitors. 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 pricingmethods allows us to respond to changes in supply costs in a manner that protects our customer base and our margins. Billing and Collection Procedures. In our retail propane business, our customer service locations are typically responsible for customer billing andaccount collection. We believe that this decentralized and more personal approach is beneficial because our local staff has more detailed knowledge of ourcustomers, their needs, and their history than would an employee at a remote billing center. Our local staff often develops relationships with our customersthat are beneficial in reducing payment time for a number of reasons: · customers are billed on a timely basis; · customers tend to keep accounts receivable balances current when paying a local business and people they know; · many customers prefer the convenience of paying in person; and · billing issues may be handled more quickly because local personnel have current account information and detailed customer history availableto them at all times to answer customer inquiries. Our retail propane customers must comply with our standards for extending credit, which typically includes submitting a credit application,supplying credit references, and undergoing a credit check with an appropriate credit agency. Trade Names. We use a variety of trademarks and trade names that we own, including Hicksgas, Propane Central, Brantley Gas, Osterman, Pacer,Downeast Energy, Allied Propane, Lessig Oil and Propane, Proflame, Anthem Propane Exchange, Woodstock Gas, and Bernville Quality Fuels, among others.We typically retain and continue to use the names of the companies that we acquire and believe that this helps maintain the local identification of thesecompanies and contributes to their continued success. We regard our trademarks, trade names, and other proprietary rights as valuable assets and believe thatthey have significant value in the marketing of our products. Refined Products and Renewables Overview. Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We own the 2.0%general partner interest and a 19.6% limited partner interest in TLP, which conducts refined products terminaling operations. TLP also owns a 42.5% interestin BOSTCO and a 50% interest in Frontera, which are entities that own refined products storage facilities. During the nine months ended March 31, 2015, wesold 60.1 million barrels of refined products, an average of 220,000 barrels per day. Operations. We provide integrated terminal, transportation, storage, supply, distribution, and marketing services to refiners, wholesalers,distributors, marketers, and industrial and commercial end users of refined petroleum products. Although the assets and operations of TLP are included in ourconsolidated financial statements, this description of our business describes the activities of TLP separately. The refined products we handle include gasoline, diesel fuel, heating oil, jet fuel, and kerosene. We purchase refined petroleum products primarily inthe Gulf Coast, East Coast, and Midwest regions of the United States and schedule them for delivery primarily on the Colonial, Plantation, and Magellanpipelines. On certain interstate pipelines, demand for shipment exceeds the available capacity, and pipeline capacity is allocated to shippers based on theirhistorical shipment volumes. We hold allocated capacity on the Colonial and Plantation pipelines. We sell our products to commercial and industrial end users, independent retailers, distributors, marketers, government entities, and otherwholesalers of refined petroleum products. We sell our products at TLP’s terminals and at terminals owned by third parties. We have the contractual right tothe exclusive use of the majority of the terminals in TLP’s Southeast region. 21Table of Contents We purchase ethanol primarily at production facilities in the Midwest and transport the ethanol via trucks and railcars for sale at various locations.We also blend ethanol into gasoline for sale to customers at TLP’s terminals. We market and handle logistics for third-party ethanol manufacturers for aservice fee. We purchase biodiesel from production facilities in the Midwest and in Houston, Texas, and transport the biodiesel via railcar to sell tocustomers. We lease approximately 60,000 barrels of biodiesel storage in Deer Park, Texas and have a terminaling agreement at a biodiesel facility inPhoenix, Arizona with a minimum monthly throughput requirement. We lease 32 railcars for the transportation of renewables. Customers. Our refined products and renewables segment serves customers in 43 states. During the year ended March 31, 2015, 22% of the revenuesof this segment were generated from the ten largest customers. We sell to customers via rack spot sales, contract sales, bulk sales, and just-in-time sales. Contract sales are made pursuant to negotiated contracts, generally ranging from one to twelve months in duration, that we enter into with localmarket wholesalers, independent gasoline station chains, heating oil suppliers, and other customers. Contract sales provide these customers with a specifiedvolume of product during the term of the agreement. Delivery of product sold under these arrangements generally is at our truck racks. The pricing of theproduct delivered under a majority of our contract sales is based on published index prices, and varies based on changes in the applicable indices. Inaddition, at the customer’s option, the contract price may be fixed at a stipulated price per gallon. Rack spot sales are sales that do not involve continuing contractual obligations to purchase or deliver product. Rack spot sales are priced anddelivered on a daily basis through truck loading racks. At the end of each day for each of the terminals that we market from, we establish the next day sellingprice for each product for each of our delivery locations. We announce or “post” to customers via website, e-mail, and telephone communications the rackspot sale price of various products for the following morning. Typical rack spot sale purchasers include commercial and industrial end users, independentretailers and small, independent marketers who resell product to retail gasoline stations or other end users. Our selling price of a particular product on aparticular day is a function of our supply at that delivery location or terminal, our estimate of the costs to replenish the product at that delivery location, andour desire to reduce inventory levels at that particular location that day. Bulk sales generally involve the sale of products in large quantities in the major cash markets including the Houston Gulf Coast and New YorkHarbor. A bulk sale of products also may be made while the product is being transported in the common carrier pipelines. We conduct just-in-time sales at a nationwide network of terminals owned by third parties. We post prices at each of these locations on a daily basis.When customers decide to purchase product from us, we purchase the same volume of product from a supplier at a previously agreed-upon price. For thesejust-in-time transactions, our purchase from the supplier occurs at the same time as our sale to our customer. Seasonality. The demand for gasoline typically peaks during the summer driving season, which extends from April to September, and declinesduring the fall and winter months. Competition. Our refined products and renewables business faces significant competition, as many entities are engaged in the refined products andrenewables business, some of which have greater financial resources than we do. The primary factors on which we compete are: · price; · availability of supply; · reliability of service; · available space on common carrier pipelines; · storage availability; · logistics capabilities, including the availability of railcars, and proprietary terminals; and · long-term customer relationships. 22Table of Contents Market Price Risk. Our philosophy is to maintain a minimum commodity price exposure through a combination of purchase contracts, salescontracts and financial derivatives. A significant percentage of our business is contracted on a back-to-back basis where physical purchases are matched withphysical sales. For discretionary inventory, and for those instances where physical transactions cannot be appropriately matched, we utilize financialderivatives to mitigate commodity price exposure. Specific exposure limits are mandated in our credit agreement and in our market risk policy. The value of refined products in any local delivery market is the sum of the commodity price as reflected on the NYMEX and the basis differentialfor that local delivery market. The basis differential for any local delivery market is the spread between the cash price in the physical market and the quotedprice in the futures markets for the prompt month. We typically utilize NYMEX futures contracts to mitigate commodity price exposure. We generally do notmanage the financial impact on us from changes in basis differentials affected by local market supply and demand disruptions. Legal and Regulatory Considerations. Demand for ethanol and biodiesel is driven in large part by government mandates and incentives. Refinersand producers are required to blend a certain percentage of renewables into their refined products, although the percentage can vary from year to year basedon the United States Environmental Protection Agency (“EPA”) mandates. In addition, the federal government has in recent years granted certain tax creditsfor the use of biodiesel, although on several occasions these tax credits have expired. In December 2014 the federal government passed a law to reinstate thetax credit retroactively to January 1, 2014, with the credit expiring on December 31, 2014. Changes in future mandates and incentives, or decisions by thefederal government related to future reinstatement of the biodiesel tax credit, could result in changes in demand for ethanol and biodiesel. Billing and Collection Procedures. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures onour refined products and renewables customers. We believe the following procedures enhance our collection efforts with our 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 monitor individual customer receivables relative to previously-approved credit limits, and our automated rack delivery system gives us theoption to discontinue providing product to customers when they exceed their credit limits; · we review receivable aging analyses regularly to identify issues or trends that may develop; and · we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paidinvoices. Trade Names. Our refined products and renewables segment operates primarily under the NGL Crude Logistics and TransMontaigne ProductServices LLC trade names. TLP Overview. We own the 2.0% general partner interest and a 19.6% limited partner interest in TLP, which conducts refined products terminalingoperations. TLP also provides storage of crude oil, fertilizer, chemicals, vegetable oils, naphtha, and wax. 23Table of Contents Operations. TLP is a terminaling and transportation company with operations in the United States. TLP uses its terminaling facilities to, amongother things: · receive refined products from the pipeline, ship, barge or railcar and transfer those refined products to the tanks located at its terminals; · store the refined products in our tanks for its customers; · monitor the volume of the refined products stored in its tanks; · distribute the refined products out of our terminals in vessels, railcars or truckloads using truck racks and other distribution equipment locatedat its terminals, including pipelines; and · heat residual fuel oils and asphalt stored in our tanks, and provide other ancillary services related to the throughput process. 24Table of Contents The locations and approximate aggregate active storage capacity at TLP’s terminal facilities at March 31, 2015 were as follows: Active Storage Capacity Locations (shell barrels) Gulf Coast Facilities—FloridaCape Canaveral724,000Fisher Island673,000Jacksonville271,000Pensacola270,000Port Everglades ComplexPort Everglades—North2,408,000Port Everglades—South376,000Port Manatee1,375,000Tampa760,000Gulf Coast Total6,857,000Midwest Facilities—Cushing, Oklahoma1,005,000Oklahoma City, Oklahoma158,000Rogers, Arkansas and Mount Vernon, Missouri (aggregate amounts)406,000Midwest Total1,569,000Brownsville Facilities—Brownsville, Texas919,000Frontera (1)1,498,000Brownsville Total2,417,000River Facilities—Arkansas City, Arkansas446,000Baton Rouge, Louisiana (Dock)—Cape Girardeau, Missouri140,000East Liverpool, Ohio227,000Evansville, Indiana245,000Greater Cincinnati, Kentucky189,000Greenville, Mississippi (Clay Street)350,000Greenville, Mississippi (Industrial Road)56,000Henderson, Kentucky169,000Louisville, Kentucky183,000New Albany, Indiana201,000Owensboro, Kentucky157,000Paducah, Kentucky322,000River Total2,685,000Southeast Facilities—Albany, Georgia203,000Americus, Georgia93,000Athens, Georgia203,000Bainbridge, Georgia367,000Belton, South Carolina—Birmingham, Alabama178,000Charlotte, North Carolina121,000Collins, Mississippi200,000Collins/Purvis, Mississippi3,419,000Doraville, Georgia438,000Fairfax, Virginia513,000Greensboro, North Carolina479,000Griffin, Georgia107,000Lookout Mountain, Georgia219,000Macon, Georgia174,000Meridian, Mississippi139,000Montvale, Virginia503,000Norfolk, Virginia1,336,000Richmond, Virginia478,000Rome, Georgia152,000Selma, North Carolina529,000Spartanburg, South Carolina166,000Southeast Total10,017,000BOSTCO (2)7,080,000Total Capacity30,625,000 25Table of Contents (1) Reflects the total active storage capacity of Frontera, of which TLP has a 50% ownership interest. (2) Reflects the completed construction total active storage capacity of BOSTCO, of which TLP has a 42.5%, general voting, Class A Memberownership interest. TLP leases all or part of the land on which seven of the terminals are located. TLP owns the land on which its other terminals are located. TLP owns and operates the Razorback pipeline. The Razorback pipeline is a 67-mile, 8-inch diameter interstate common carrier pipeline thattransports light refined product from its terminal at Mount Vernon, Missouri where it is interconnected with a pipeline system owned by Magellan MidstreamPartners, L.P., to TLP’s terminal at Rogers, Arkansas. TLP also owns and operates the Diamondback pipeline. The Diamondback pipeline consists of an 8-inchpipeline that transports LPG approximately 16 miles from TLP’s Brownsville, Texas facilities to the U.S./Mexico border and a 6-inch pipeline, which runsparallel to the 8-inch pipeline, that can be used by TLP in the future to transport additional LPG or refined products to Matamoros, Mexico. The 8-inchpipeline has a capacity of approximately 20,000 barrels per day. The 6-inch pipeline has a capacity of approximately 12,000 barrels per day. TLP alsooperates and maintains the United States portion of a 174-mile bidirectional refined products pipeline owned by P.M.I. Services North America Inc. Thispipeline connects TLP’s Brownsville, Texas terminal complex to a pipeline in Mexico that delivers to Petróleos Mexicanos (“PEMEX”) terminal located inReynosa, Mexico and terminates at PEMEX’s refinery, located in Cadereyta, Nuevo Leon, Mexico, a suburb of the large industrial city of Monterrey, Mexico. Customers. TLP has several significant customer relationships from which it expects to derive a substantial majority of its revenue for the foreseeablefuture. During the period from July 1, 2014 through March 31, 2015, 33% of TLP’s revenues were generated from services to NGL (these revenues areeliminated in our consolidated statements of operations). Competition. TLP faces competition from other terminals and pipelines that may be able to supply customers with integrated terminaling andtransportation services on a more competitive basis. TLP competes with national, regional and local terminal and transportation companies, including themajor integrated oil companies, of widely varying sizes, financial resources and experience. TLP’s ability to compete could be harmed by factors we cannotcontrol, including: · price competition from terminal and transportation companies, some of which are substantially larger than we are and have greater financialresources, and control substantially greater storage capacity, than TLP does; · the perception that another company can provide better service; and · the availability of alternative supply points, or supply points located closer to customers’ operations. Supply. The volume of product that is handled, transported, throughput or stored in TLP’s terminals and pipeline is directly affected by the level ofsupply and demand in the wholesale markets served by our terminals and pipelines. Overall supply of refined products in the wholesale markets is influencedby the products’ absolute prices, the availability of capacity on delivering pipelines and vessels, fluctuating refinery margins and the markets’ perception offuture project prices. Pricing Policy. TLP derives revenue from its terminal and pipeline transportation operations by charging fees for providing integrated terminaling,transportation and related services. The fees and other sources of revenue are composed of: · Terminaling Service Fees. TLP generates terminaling service fees by receiving, storing and distributing products for customers. Terminalingservice fees include throughput fees based on the volume of product distributed from the facility, injection fees based on the volume of productinjected with additive compounds and storage fees based on a rate per barrel of storage capacity per month. · Pipeline Transportation Fees. TLP earns pipeline transportation fees on its Razorback pipeline and Diamondback pipeline and the Ella-Brownsville pipeline, which it leases from a third party, based on the volume of product transported and the distance from the origin point to thedelivery point. The Federal Energy Regulatory Commission (“FERC”) regulates the tariff on the Razorback, Diamondback andElla-Brownsville pipelines. 26Table of Contents · Management Fees and Reimbursed Costs. TLP manages and operates certain tank capacity at its Port Everglades (South) terminal for a majoroil company and receives a reimbursement of its proportionate share of operating and maintenance costs. TLP manages and operates for anaffiliate of PEMEX, Mexico’s state-owned petroleum company, a bidirectional products pipeline connected to its Brownsville, Texas terminalfacility and receives a management fee and reimbursement of costs. TLP manages and operates Frontera and receives a management fee based oncosts incurred. · Other Revenue. TLP provides ancillary services including heating and mixing of stored products, product transfer services, railcar handling,wharfage fees and vapor recovery fees. Pursuant to certain terminaling services agreements with throughput customers, TLP is entitled to thevolume of net product gained resulting from differences in the measurement of product volumes received and distributed at its terminalingfacilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurementdevices and methodology. TLP recognizes as revenue the net proceeds from the sale of the product gained. Employees At March 31, 2015, we had 3,100 full-time employees. Thirteen of our employees at two of our locations are members of a labor union. We believethat our relations with our employees are satisfactory. Government Regulation Regulation of the Oil and Natural Gas Industries Regulation of Oil and Natural Gas Exploration, Production and Sales. Sales of crude oil and natural gas liquids are not currently regulated and aretransacted 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 FERC, which has the authority under the Natural Gas Act to regulate the prices and other termsand conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all natural gas resellers subject to itsregulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or the FERC (with respect to the resale of natural gas in interstatecommerce), however, could re-impose price controls in the future. Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting,well location, methods of drilling, well operations, and conservation of resources. While these regulations do not directly apply to our business, they mayaffect the businesses of certain of our customers and suppliers and thereby indirectly affect our business. Regulation of the Transportation and Storage of Natural Gas and Oil and Related Facilities. The 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 FERCregulation including reporting or other requirements. In addition, the intrastate transportation and storage of oil and natural gas is subject to regulation by thestate in which such facilities are located, and such regulation can affect the availability and price of our supply, and have both a direct and indirect effect onour business. 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 the FERC to impose fines of up to $1,000,000 per day per violation of the Natural Gas Act, the NGPA, ortheir implementing regulations. In addition, the Federal Trade Commission (“FTC”) holds statutory authority under the Energy Independence and SecurityAct of 2007 to prevent market manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,000,000 perviolation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The Commodity FuturesTrading Commission (“CFTC”) is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futures markets,including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud andprice manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,000,000 perday per violation or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the Commodity Exchange Act. We arealso subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation. Maritime Transportation. The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels builtand registered in the United States and owned and manned by United States citizens. Since we engage in 27Table of Contents maritime transportation through our barge fleet between locations in the United States, we are subject to the provisions of the law. As a result, we areresponsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to ensurethat no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all United States-flagged vessels be manned by United Statescitizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirementsignificantly increases operating costs of United States-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governmentssubsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by United States-flagged vesselowners. The United States Coast Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tendsto result in higher regulatory compliance costs for United States-flagged operators than for owners of vessels registered under foreign flags of convenience. Environmental Regulation General. Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of 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 bysuch environmental 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 adversely affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures forenvironmental compliance or remediation and actual future expenditures may be different from the amounts we currently anticipate. The following is a discussion of the material environmental laws and regulations that relate to our business. Hazardous Substances and Waste. We are subject to various federal, state, and local environmental, laws and regulations governing the storage,distribution and transportation of natural gas liquids and the operation of bulk storage LPG terminals, as well as laws and regulations governingenvironmental protection, including those addressing the discharge of materials into the environment or otherwise relating to protection of the environment.Generally, these laws (i) regulate air and water quality and impose limitations on the discharge of pollutants and establish standards for the handling of solidand hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) may result in the suspension or revocation ofnecessary permits, licenses and authorizations; (iv) impose substantial liabilities on us for pollution resulting from our operations; (v) require remedialmeasures to mitigate pollution from former or ongoing operations; and (vi) may result in the assessment of administrative, civil and criminal penalties forfailure to comply with such laws. These laws include, among others, the Resource Conservation and Recovery Act (“RCRA”), the ComprehensiveEnvironmental Response, Compensation and Liability Act (“CERCLA”), the federal Clean Air Act, the Homeland Security Act of 2002, the EmergencyPlanning and Community Right to Know Act, the Clean Water Act, the Safe Drinking Water Act, and comparable state statutes. For example, as a flammablesubstance, propane is subject to risk management plan requirements under section 112(r) of the federal Clean Air Act. CERCLA, also known as the “Superfund” law, and similar state laws impose liability, without regard to fault or the legality of the original conduct,on certain classes of potentially responsible persons that are considered to have contributed to the release of a “hazardous substance” into the environment.These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of ahazardous substance released at the site. While natural gas liquids are not a hazardous substance within the meaning of CERCLA, other chemicals used in orgenerated by our operations may be 28Table of Contents classified as hazardous. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict and joint andseveral liability for the costs of investigating and cleaning up the hazardous substances that have been released into the environment, for damages to naturalresources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personalinjury and property damage allegedly caused by the hazardous substances released into the environment. RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal andcleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes inconjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penaltiesfor alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of oil and natural gas, as well ascertain types of petroleum-contaminated media and debris, are excluded from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead,are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. It is possible, however, that certain wastes now classified asnon-hazardous could be classified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposal requirements. Indeed,legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas wastes as “hazardous wastes.” Any such change couldresult in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financialposition. 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 OilPollution Prevention Act imposes liability for releases of oil from vessels or facilities into navigable waters. If a release of crude oil to navigable watersoccurred during shipment or from a terminal, we could be subject to liability under the Oil Pollution Prevention Act. We are not currently aware of any facts,events, or conditions related to oil spills that could materially impact our operations or financial condition. In 1973, the EPA adopted oil pollutionprevention regulations under the Clean Water Act. These oil pollution prevention regulations, as amended several times since their original adoption, requirethe preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing,refining, transferring, distributing, using, or consuming oil and oil products, and which due to their location, could reasonably be expected to discharge oil inharmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written,site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. To be in compliance, the facility’s SPCC planmust satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transfer operations (intrafacilitypiping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in itsexecution. We maintain and implement such plans for our facilities. Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws 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 permits prior to the construction or modification of certain projects or facilities expected to produce orsignificantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specificemission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions,conditions or restrictions on operations and, potentially, criminal enforcement actions. Furthermore, we may be required to incur certain capital expendituresin the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We areaware of planned EPA rulemakings concerning air emissions from the oil and gas industry, but the EPA’s schedule for proposing and finalizing theseupcoming rulemakings is not presently known. 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 29Table of Contents contamination of regulated waters in the event of a hydrocarbon or other constituent tank spill, rupture or leak. In addition, the Clean Water Act andanalogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Wehave discharge permits in place for a number of our facilities. These permits may require us to monitor and sample the storm water runoff from such facilities.Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federaland state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of theClean 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 theinjection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulicfracturing activities. However, a portion of our customers’ oil and natural gas production is developed from unconventional sources that require hydraulicfracturing as part of the completion process and our water solutions business treats and disposes of wastewater generated from natural gas production,including production utilizing hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into theformation to stimulate oil and gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from thedefinition of underground injection and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to requiredisclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of the United States Congress.Congress will likely continue to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under theAct’s Underground Injection Control Program and/or to require disclosure of chemicals used in the hydraulic fracturing process. Federal agencies, includingthe EPA and the United States Department of the Interior, have asserted their regulatory authority to, for example, study the potential impacts of hydraulicfracturing on the environment, and initiate rulemakings to compel disclosure of the chemicals used in hydraulic fracturing operations, and establishpretreatment standards for wastewater from hydraulic fracturing operations. In addition, some states have also proposed or adopted legislative or regulatoryrestrictions on hydraulic fracturing, which include additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions,and/or temporary or permanent bans on hydraulic fracturing. We expect that scrutiny of hydraulic fracturing activities will continue in the future. Greenhouse Gas Regulation There is a growing concern, both nationally and internationally, about climate change and the contribution of greenhouse gas emissions, mostnotably carbon dioxide, to global warming. In June 2009, the United States House of Representatives passed the ACES Act, also known as the Waxman-Markey Bill, but the ACES Act ultimately was not enacted by the 111th Congress. The ACES Act would have established an economy-wide cap on emissionsof greenhouse gases in the United States and would have required most sources of greenhouse gas emissions to obtain and hold “allowances” correspondingto their annual emissions of greenhouse gases. A steady stream of legislation regarding climate change continues to be introduced into Congress, but none ofthe proposed bills have received bipartisan support. Recently, Rep. Chris Van Hollen (D-MD) introduced H.R. 1027, which would cap greenhouse gasemissions and require the purchase of carbon permits. The bill was referred to the Ways and Means Committee and the Energy and Commerce Committee onFebruary 24, 2015 but has not yet advanced out of committee. The ultimate outcome of any possible future federal legislative initiatives is uncertain. Inaddition, several states have already adopted some legal measures to reduce emissions of greenhouse gases, primarily through the planned development ofgreenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. 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 thefederal Clean Air Act, including (i) the greenhouse gas reporting rule; (ii) greenhouse gas standards applicable to heavy-duty and light-duty vehicles; and(iii) a rule requiring stationary sources to address greenhouse gas emissions in Prevention of Significant Deterioration and Title V permits, known as theTailoring Rule. The Supreme Court of the United States invalidated the Tailoring Rule in Utility Air Regulatory Group v. EPA on 30Table of Contents June 23, 2014. Under the Supreme Court’s decision, sources are no longer required to obtain Prevention of Significant Deterioration or Title V permits basedsolely on their greenhouse gas emissions; however, installation of the best available control technology for greenhouse gases may be required at sources thatemit more than a de minimis amount of greenhouse gases and are otherwise required to obtain Prevention of Significant Deterioration permits. On January 14,2015, the EPA announced its intention to propose regulations that would require reductions in methane and volatile organic compound emissions from theoil and gas industry. The schedule for when these regulations will be proposed or finalized is not presently known. The EPA’s greenhouse gas regulationscould require us to incur costs to reduce emissions of greenhouse gases associated with our operations and also could adversely affect demand for theproducts that we transport, store, process, or otherwise handle in connection with our services. Some scientists have suggested climate change from greenhouse gases could increase the severity of extreme weather, such as increased hurricanesand floods, which could damage our facilities. Another possible consequence of climate change is increased volatility in seasonal temperatures. The marketfor our natural gas liquids is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate couldaffect the market for our products and services. If there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on ourbusiness. 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,resulting in increased costs of doing business and consequently affecting our profitability. To the extent laws are enacted or other governmental action istaken that restricts certain aspects of our business or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, ourbusiness and prospects could be adversely affected. Safety and Transportation All states in which we operate have adopted fire safety codes that regulate the storage and distribution of propane and distillates. In some states, 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,Pamphlet Nos. 54 and 58, or comparable regulations, which establish a set of rules and procedures governing the safe handling of propane, and Pamphlet Nos.30, 30A, 31, 385, and 395 which establish rules and procedures governing the safe handling of distillates, such as fuel oil. We believe that the policies andprocedures currently in effect at all of our facilities for the handling, storage and distribution of propane and distillates and related service and installationoperations are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws. With respect to the transportation of propane, distillates, crude oil, and water, we are subject to regulations promulgated under federal legislation,including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security andtransportation of hazardous materials and are administered by the United States Department of Transportation (“DOT”). Specifically, crude oil pipelines aresubject to regulation by the DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Hazardous Liquid PipelineSafety Act of 1979 (“HLPSA”), which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the storage and transportationof hazardous 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 of statutory factors that must be considered in establishing safety standards forhazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteriafor operators to use in identifying and inspecting pipelines located in high consequence areas (“HCAs”), defined as those areas that are unusually sensitive toenvironmental damage, that cross a navigable waterway, or that have a high population density. In the Pipeline Inspection, Protection, Enforcement, andSafety Act of 2006, Congress required mandatory inspections for certain United States crude oil and natural gas transmission pipelines in HCAs andmandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management. In January 2012, the federalgovernment passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”). This act provides for additionalregulatory oversight of the nation’s pipelines, increases the penalties for violations of pipeline safety rules, and complements the DOT’s other initiatives. The2011 Pipeline Safety Act increases the maximum fine for the most serious pipeline safety violations involving deaths, injuries or major environmental harmfrom $1 million to $2 million. In addition, this law established additional safety requirements for newly constructed pipelines. The law also provides for(i) additional pipeline damage prevention measures, (ii) allowing the Secretary of Transportation to require automatic and remote-controlled shut-off valveson new pipelines, (iii) requiring 31Table of Contents the Secretary of Transportation to evaluate the effectiveness of expanding pipeline integrity management and leak detection requirements, (iv) improving theway the DOT and pipeline operators provide information to the public and emergency responders and (v) reforming the process by which pipeline operatorsnotify federal, state and local officials of pipeline accidents. 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.Our marine 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. 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 Reportand should not be considered part of this or any other report that we file with or furnish to the SEC. The public may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C.20549. The public may obtain information about the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains 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 cash reserves byour 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 units principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among otherthings: · 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 32Table of Contents · 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% seniorsecured notes due 2022 (the “Note Purchase Agreement”), the indentures governing our outstanding 6.875% senior notes due 2021 and 5.125%senior notes due 2019 (collectively, the “Indentures”) and other debt service requirements; · fluctuations in working capital needs; · our ability to borrow funds and access capital markets; · the amount, if any, of cash reserves established by our general partner; and · other business risks discussed in this Annual Report that may affect our cash levels. The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow rather than on our profitability, which mayprevent 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 economically acceptableterms. 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 Indentures 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 favorable 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 relevantinformation that we will consider in determining the application of these funds and other resources. Our ability to expand our retail propane business is dependent on our ability to successfully complete accretive acquisitions. The propane industryis a mature industry, and we anticipate only limited growth in total national demand for propane in the near future. Increased competition from alternativeenergy sources has limited growth in the propane industry, and year-to-year industry volumes are primarily impacted by fluctuations in weather andeconomic conditions. While our business strategy includes expanding 33Table of Contents our existing retail propane operations through internal growth, our ability to grow within the retail propane business will depend principally on acquisitions,and there can be no assurances that we will be able to identify suitable acquisition candidates or successfully complete acquisitions in this line of business. We may be subject to substantial risks in connection with the integration and operation of acquired businesses, in particular those businesses withoperations that are distinct and separate from our existing operations. Any acquisitions we make in pursuit of our growth strategy are subject to potential risks, including, but not limited to: · the inability to successfully integrate the operations of recently acquired businesses; · the assumption of known or unknown liabilities, including environmental liabilities; · limitations on rights to indemnity from the seller; · mistaken assumptions about the overall costs of equity or debt or synergies; · unforeseen difficulties operating in new geographic areas or in new business segments; · the diversion of management’s and employees’ attention from other business concerns; · customer or key employee loss from the acquired businesses; and · a potential significant increase in our indebtedness and related interest expense. We undertake due diligence efforts in our assessment of acquisitions, but may be unable to identify or fully plan for all issues and risks attendant toa particular acquisition. Even when an issue or risk is identified, we may be unable to obtain adequate contractual protection from the seller. The realizationof any of these risks could have a material adverse effect on the success of a particular acquisition or our financial condition, results of operations or 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. Our substantial indebtedness may limit our flexibility to obtain financing and to pursue other business opportunities. At March 31, 2015, we had $2.7 billion of outstanding indebtedness. Our level of debt could have important consequences to us, including thefollowing: · 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 34Table of Contents assets or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms or at all. The agreements governing ourindebtedness permit us to incur additional debt under certain circumstances, and we will likely need to incur additional debt in order to implement ourgrowth strategy. We may experience adverse consequences from increased levels of debt. Restrictions in our Credit Agreement, Note Purchase Agreement and Indentures 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 Indentures limit our ability to, among other things: · incur additional debt or issue letters of credit; · redeem or repurchase units; · make certain loans, investments and acquisitions; · incur certain liens or permit them to exist; · engage in sale and leaseback transactions; · enter into certain types of transactions with affiliates; · enter into agreements limiting subsidiary distributions; · change the nature of our business or enter into a substantially different business; · merge or consolidate with another company; and · transfer or otherwise dispose of assets. We are permitted to make distributions to our unitholders under our Credit Agreement, Note Purchase Agreement and Indentures as long as nodefault or event of default exists both immediately before and after giving effect to the declaration and payment of the distribution and the distribution doesnot exceed available cash for the applicable quarterly period. Our Credit Agreement, Note Purchase Agreement and Indentures also contain covenantsrequiring us to maintain certain financial ratios. Please see Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results ofOperations—Liquidity, Sources of Capital and Capital Resource Activities—Long-Term Debt.” The provisions of our Credit Agreement, Note Purchase Agreement and Indentures 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 thepayment of our debt is accelerated, defaults under our other debt instruments, if any then exist, may be triggered, and our assets may be insufficient to repaysuch debt in full, and our unitholders could experience a partial or total loss of their investment. Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our abilityto 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, natural gas liquids, and refined products in the United States and Canada, which isdependent on the ability and willingness of other parties to explore for and produce crude oil and natural gas. 35Table of Contents Spending on crude oil and natural gas exploration and production may be adversely affected by industry and financial market conditions that are beyondour control including, without limitation, (1) prices for crude oil, condensate, and natural gas liquids, (2) crude oil and natural gas producers havingsuccess in their operations, (3) continued commercially viable areas in which to explore and produce crude oil and natural gas, (4) the availability ofliquids-rich natural gas needed to produce natural gas liquids, and (5) the availability of pipeline transportation and storage capacity. Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business have been, and may continue tobe, 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. 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 at whichit returns to former levels, if ever, will be uncertain. Prior adverse changes in the global economic environment and capital markets and declines in prices foroil and natural gas have caused many customers to reduce capital budgets for future periods and have caused decreased demand for oil and natural gas.Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause customers to 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. Declining crude oil prices could adversely impact our water solutions and crude oil logistics businesses. Crude oil spot and forward prices experienced a significant decline during the second half of calendar year 2014, and this has an unfavorable impacton the revenues of our water solutions business. The volume of water we process is driven in part by the level of crude oil production, and the lower crude oilprices have given producers less incentive to expand production. In addition, a significant portion of the revenues of our water solutions business aregenerated from the sale of crude oil that we recover in the process of treating the wastewater, and lower crude oil prices have an adverse impact on theserevenues. A further decline in crude oil prices or a prolonged period of low crude oil prices could have an adverse effect on our water solutions business. In addition, the sharp decline in crude oil prices has reduced the incentive for producers to expand production. If crude oil prices remain low,resultant declines in crude oil production could adversely impact volumes in our crude oil logistics business. 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 futuredelivery obligations. We attempt to obtain a certain margin for our purchases by selling our product to our customers, which include third-party consumers,other wholesalers and retailers, and others. However, market, weather or other conditions beyond our control may disrupt our expected supply of product, andwe may be required to obtain supply at increased prices that cannot be passed through to our customers. In general, product supply contracts permit suppliersto charge posted prices at 36Table of Contents the time of delivery or the current prices established at major storage points, creating the potential for sudden and drastic price fluctuations. Sudden andextended wholesale price increases could reduce our margins and could, if continued over an extended period of time, reduce demand by encouraging retailcustomers to conserve or convert to alternative energy sources. Conversely, a prolonged decline in product prices could potentially result in a reduction ofthe borrowing base under our working capital facility, and we could be required to liquidate inventory that we have already presold. One of the strategies of our refined products and renewables segment is to purchase refined products in the Gulf Coast region and to transport theproduct on the Colonial pipeline for sale in the Southeast and East Coast. Spreads between product prices in the Gulf Coast compared to locations along theColonial pipeline can vary significantly, which can create volatility in our product margins. In addition, we are subject to the risk of a price decline betweenthe time we purchase refined products and the time we sell the products. We seek to mitigate this risk by entering into NYMEX futures contracts. However,price changes in locations where we operate do not correspond directly with changes in prices in the NYMEX futures market, and as a result these futurescontracts cannot be perfect hedges of our commodity price risk. We are affected by competition from other midstream, transportation, terminaling and storage, and retail-marketing companies, some of which are largerand 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 ourservices. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process,transport, store and market natural gas. Our natural gas liquids terminals compete with other terminaling and storage providers in the transportation andstorage of natural gas liquids. Natural gas and natural gas liquids also compete with other forms of energy, including electricity, coal, fuel oil and renewableor 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 and distillates. Our competitors vary from retail propane companies who arelarger and have substantially greater financial resources than we do to small retail propane distributors, rural electric cooperatives and fuel oil distributorswho have entered the market due to a low barrier to entry. The actions of our retail-marketing competitors, including the impact of imports, could lead tolower prices or reduced margins for the products we sell, which could have an adverse effect on our business or results of operations. Our refined products and renewables segment also faces 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 and we use third-party facilities to store our products. Any significant interruption in theservice at these storage facilities or on the common carrier pipelines we use would adversely affect our ability to obtain products. 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. 37Table of Contents 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 gas liquids, refinedproducts, ethanol, and biodiesel may not escalate sufficiently to cover increases in costs and the agreements may be suspended in some circumstances,which would affect our profitability. Our costs may increase at a rate greater than the rate that the fees that we charge to customers increase pursuant to our contracts with them.Additionally, some customers’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events,some of which are beyond our control, including force majeure events wherein the supply of crude oil, condensate, and/or natural gas liquids are curtailed 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 ourprocessing of wastewater, expose us to potential regulatory risks. The FTC, the FERC, and the CFTC hold statutory authority to monitor certain segments of the physical and financial energy commodity markets.These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of energycommodities, and any related transportation and/or hedging activities that we undertake, we are required to observe the market-related regulations enforcedby these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Additionally, tothe extent that we enter into transportation contracts with pipelines that are subject to the FERC regulation or we become subject to the FERC regulationourselves (see “— Certain of our operations are subject to the jurisdiction of the FERC, and some of our operations could become subject to thejurisdiction of the FERC in the future,” below), we will be obligated to comply with the FERC’s regulations and policies. Any failure on our part to complywith the FERC’s regulations and policies at that time could result in the imposition of civil and criminal penalties. Failure to comply with such regulations,as interpreted and enforced, could have a material and adverse effect on our business, results of operations and financial condition. The intrastate transportation or storage of crude oil and refined products is subject to regulation by the state in which the facilities and transactionsoccur and 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. The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) provides for statutory and regulatory requirements forderivative transactions, including crude oil and natural gas hedging transactions. Certain transactions will be required to be cleared on exchanges and cashcollateral will have to be posted. The Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercialend users and it includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and theparties to those transactions. Since the Dodd-Frank Act mandates the CFTC to promulgate rules to define these terms, the full impact of the Dodd-Frank Acton our hedging activities is uncertain at this time. However, new legislation and any new regulations could significantly increase the cost of derivativecontracts (including through requirements to post collateral which could adversely affect our available liquidity), materially alter the terms of derivativecontracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability to monetize or restructure our existing derivativecontracts, and increase our exposure to less creditworthy counterparties. The Dodd-Frank Act may also materially affect our customers and materially andadversely affect the demand for our services. We are subject to trucking safety regulations, which are enacted, reviewed and amended by the Federal Motor Carrier Safety Administration (“FMCSA”).If our current DOT safety ratings are downgraded to “Unsatisfactory”, our business and results of our operations may be adversely affected. All federally regulated carriers’ safety ratings are measured through a program implemented by the FMCSA known as the Compliance SafetyAccountability (“CSA”) program. The CSA program measures a carrier’s safety performance based on violations observed during roadside inspections asopposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies ofcomparable size and annual mileage. If a company rises above a threshold established by the FMCSA, it is subject to action from the FMCSA. There is aprogressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company willimplement. If the issues are not 38Table of Contents corrected, the intervention escalates to on-site compliance audits and ultimately an “unsatisfactory” rating and the revocation of the company’s operatingauthority by the FMCSA, which could result in a material adverse effect on our business, results of operations, financial condition and ability to make cashdistributions to our unitholders. Our business is subject to federal, state, provincial and local laws and regulations with respect to environmental, safety and other regulatory matters andthe 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, refined products, renewables, and oil and gas producedwastewater, are subject to stringent federal, state, provincial and local laws and regulations relating to the protection of natural resources and theenvironment, health and safety, waste management, and transportation and disposal of such products and materials. We face inherent risks of incurringsignificant environmental costs and liabilities in the performance of our operations due to handling of wastewater and hydrocarbons, such as crude oil,condensate, natural gas liquids, refined products, ethanol, and biodiesel. For instance, our wastewater treatment business carries with it environmental risks,including leakage from the treatment plants to surface or subsurface soils, surface water or groundwater, or accidental spills. Our crude oil logistics, liquids,and refined products and renewables businesses carry similar risks of leakage and sudden or accidental spills of crude oil, natural gas liquids, andhydrocarbons. Liability under, or violation of, environmental laws and regulations could result in, among other things, the impairment or cancellation ofoperations, injunctions, fines and penalties, reputational damage, expenditures for remediation and liability for natural resource damages, property damageand 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 FederalMotor Carrier Safety Act and the Homeland Security Act of 2002, which cover the security and transportation of hazardous materials and are administered bythe DOT. We also own and lease a fleet of railcars, the operation of which is subject to the regulatory jurisdiction of the Federal Railroad Administration ofthe DOT, as well as other federal and state regulatory agencies. In response to train derailments, United States regulators are implementing or considering newrules to address the safety risks of transporting crude oil by rail. The introduction of these or other regulations that result in new requirements addressing thetype, design, specifications or construction of railcars used to transport crude oil could result in severe transportation capacity constraints during the periodin which new railcars are retrofitted or constructed to meet new specifications. Our barge transportation operations 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,may unfavorably impact us, and could result in increased operating costs and have a material and adverse effect on our activities and profitability. Forexample, new or proposed laws or regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing ofwells may increase our costs for treatment of frac flowback water (or affect our hydraulic fracturing customers’ ability to operate) and cause delays,interruption or termination of our water treatment operations, all of which could have a material and adverse effect on our operations and financialperformance. 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 39Table of Contents become more stringent over time. For example, in April 2012, the EPA issued final rules that established new air emission controls for oil and gas productionand gas processing operations. The final rule includes a 95% reduction in volatile organic compounds (“VOCs”) (which contribute to smog) emitted duringthe completion of new and modified hydraulically fractured wells. In August 2013, the EPA updated its 2012 air emission standards for crude oil and naturalgas storage tanks to extend the compliance date and allow an alternate emissions limit of less than four tons per year without emission controls. InJanuary 2015, the EPA announced its intention to propose regulations that would require further reductions in methane and VOC emissions from the oil andgas industry. The EPA’s schedule for proposing or finalizing these regulations is not presently known. Any significant increased costs or restrictions placedon our customers to comply with environmental laws and regulations could affect their production output significantly. Such an effect could materially andadversely 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 and additionaloperating 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 primarily 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. New laws or regulations, or changes to existing laws or regulations in response to this perceived threat may unfavorably impact theoil and gas drilling industry. For instance, the EPA has asserted federal regulatory authority over certain hydraulic fracturing practices involving the use ofdiesel fuel under the Safe Drinking Water Act and its Underground Injection Control program. In February 2014, the EPA issued technical guidance for thepermitting of the underground injection of diesel fuel for hydraulic fracturing activities. The EPA has also commenced a study of the potential environmentalimpact of hydraulic fracturing activities, the final results of which are expected in 2015. In addition, the United States Department of the Interior issued afinal rule on March 20, 2015 updating existing regulation of hydraulic fracturing activities on federal and tribal lands, including requirements for disclosureof chemicals used in hydraulic fracturing to the Bureau of Land Management, well bore integrity and handling of flowback water. The rule will becomeeffective 90 days after publication in the Federal Register. Also, legislation has been introduced, but not adopted, in Congress to provide for federalregulation of hydraulic fracturing. In addition, some states have adopted and other states are considering adopting regulations that could restrict or regulatehydraulic fracturing in certain circumstances. For example, some states have adopted legislation requiring the disclosure of hydraulic fracturing chemicals,which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specificchemicals used in the fracturing process could adversely affect groundwater. Other states, such as New York, have banned hydraulic fracturing. We cannotpredict whether any proposed federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require orprohibit. However, any restrictions on hydraulic fracturing could lead to operational delays or increased operating costs and regulatory burdens that couldmake it more difficult or costly to perform hydraulic fracturing which would negatively impact our customer base resulting in an adverse effect on ourprofitability. Federal and state legislation and regulatory initiatives relating to saltwater disposal wells could result in increased costs and additional operatingrestrictions or delays and could harm our business. The water disposal process is primarily regulated by state oil and gas authorities. This water disposal process has come under considerable scrutinyfrom sections of the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increased seismicactivity. New laws or regulations, or changes to existing laws or regulations, in response to this perceived threat may unfavorably impact the water disposalindustry. On certain occasions, a state regulatory agency has requested that we suspend operations at a specified disposal facility, pending further study of itspotential impact on seismic activity. In one instance we have modified a disposal well to redirect the flow of water to a different area of the geologicformation in order to address such concerns. We cannot predict whether any federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations wouldrequire or prohibit. However, any restrictions on water disposal could lead to operational delays or increased operating costs and regulatory burdens thatcould make it more difficult or costly to perform water disposal operations, which would negatively impact our profitability. 40Table of Contents Seasonal weather conditions and natural or man-made disasters could severely disrupt normal operations and have an adverse effect on our business,financial condition and results of operations. We operate in various locations across the United States and Canada which may be adversely affected by seasonal weather conditions and natural 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 seriouslydisrupt the 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 our financialcondition and results of operations. In addition, any non-compliance with our risk policy could result in significant financial losses. Pursuant to the requirements of our 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 obligationsunder contracts for forward sale. We also enter into financial derivative contracts, such as futures, to manage commodity price risk. Through thesetransactions, we seek to maintain a position that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on theother hand. These policies and practices cannot, however, eliminate all risks. For example, any event that disrupts our anticipated physical supply ofcommodities could expose us to risk of loss resulting from the need to cover obligations required under contracts for forward sale. Additionally, we canprovide no assurance that our processes and procedures will detect and/or prevent all violations of our risk management policies and procedures, particularlyif 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, which couldmaterially affect our cash flows and results of operations. We encounter risk of counterparty nonperformance in our businesses. Disruptions in the supply of product and in the oil and gas commodities sectoroverall 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 decreasedgross margins and profitability, thereby impairing our ability to make payments on our debt obligations or distributions to our unitholders. Our use of derivative financial instruments could have an adverse effect on our results of operations. We have used derivative financial instruments as a means to protect against commodity price risk or interest rate risk and expect to continue to doso. 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 thefuture. Our use of such derivative financial instruments could cause us to forego the economic benefits we would otherwise realize if commodity prices orinterest rates were to change in our favor. In addition, although we monitor such activities in our risk management processes and procedures, such activitiescould result in losses, which could adversely affect our results of operations and impair our ability to make payments on our debt obligations or distributionsto our unitholders. Certain of our operations are subject to the jurisdiction of the FERC, and some of our operations could be subject to the jurisdiction of the FERC in thefuture. TLP’s Razorback and Diamondback pipelines are subject to the jurisdiction of the FERC. Any of our transportation services could in the futurebecome subject to the jurisdiction of the FERC, which could adversely affect the terms of service, rates and revenues of such services. At the date of thisAnnual Report, our facilities do not fall under the FERC’s jurisdiction. Currently, the FERC regulates crude oil and refined products pipelines, among otherthings. Intrastate transportation and gathering pipelines that do not provide interstate services are not subject to regulation by the FERC. However, thedistinction between the FERC-regulated interstate pipeline transportation on the one hand and intrastate pipeline transportation on the other hand, is a fact-based determination. 41Table of Contents The classification and regulation of our crude oil pipelines are subject to change based on future determinations by the FERC, federal courts, Congress orregulatory commissions, courts or legislatures in the states in which we operate. Glass Mountain, one of our joint ventures, owns a pipeline in Oklahoma thatcarries 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 andthe services it would provide to third parties on this pipeline system meet the traditional tests that the FERC has used to determine that the pipeline servicesprovided are not in interstate commerce. However, we cannot provide assurance that the FERC will not in the future, either at the request of other entities oron its own initiative, determine that some or all of the pipeline and the services Glass Mountain will provide on that system are within its jurisdiction, or thatsuch a determination would not adversely affect Glass Mountain’s or our results of operations. If the FERC’s regulatory reach was expanded to our otherfacilities, or if we expand our operations into areas that are subject to the FERC’s regulation, we may have to commit substantial capital to comply with suchregulations and such expenditures could have a material and adverse effect on our results of operations and cash flows. Additionally, our subsidiary Grand Mesa is in the process of constructing a pipeline originating in Weld County, Colorado and terminating at ourCushing, Oklahoma terminal. We expect that this pipeline will be subject to FERC regulation. Volumes of crude oil recovered during the wastewater treatment process can vary. Any significant reduction in residual crude oil content in wastewater wetreat 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 residualcrude oil content in the wastewater we treat could materially and adversely affect our profitability. Competition from alternative energy sources may cause us to lose customers, thereby negatively impacting our financial condition and results 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.The expansion 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 applicationsand market demand, propane and fuel oil compete to a lesser extent primarily because of the cost of converting from one to the other and due to the fact thatboth fuel oil and propane have generally developed their own distinct geographic markets. We cannot predict the effect that development of alternative energy sources may have on our operations, including whether subsidies of alternativeenergy sources by local, state, and federal governments might be expanded, or what impact this might have on the supply of or the demand for crude oil,natural gas, and natural gas liquids. Energy efficiency and new technology may reduce the demand for propane and adversely affect our operating results. The national trend toward increased conservation and technological advances, such as installation of improved insulation and the development ofmore efficient furnaces and other heating devices, has adversely affected the demand for propane by retail customers. Future conservation measures ortechnological advances in heating, conservation, energy generation or other devices may reduce demand for propane. In addition, if the price of propaneincreases, some of our customers may increase their conservation efforts and thereby decrease their consumption of propane. 42Table of Contents The majority of our retail propane operations are concentrated in the Northeast, Southeast, and Midwest, and localized warmer weather and/or economicdownturns may adversely affect demand for propane in those regions, thereby affecting our financial condition and results of operations. A substantial portion of our retail propane sales are to residential customers located in the Northeast, Southeast, and Midwest who rely heavily 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 propaneregardless of weather conditions. Localized warmer weather and/or economic downturns may have a significantly greater impact on our operating results andfinancial condition than if our retail propane business were less concentrated. Reduced demand for refined products could have an adverse effect our results of operations. Any sustained decrease in demand for refined products in the markets we serve could reduce our cash flow. Factors that could lead to a decrease 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 federal Renewable Fuels Standard (“RFS”), if successful, could unfavorably impact our results of operations. The United States renewables industry is highly dependent on several federal and state incentives which promote the use of renewable fuels.Without these incentives, demand for and the price of renewable fuels could be negatively impacted which could have an adverse effect on our results ofoperations. The most significant of the federal and state incentives which benefit renewable products we market, such as ethanol and biodiesel, is the RFS.The RFS requires that an increasing amount of renewable fuels must be blended with petroleum-based fuels each year in the United States. However, the EPAhas 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 inadequatedomestic renewable fuel supply; or (2) implementation of the requirement would severely harm the economy or environment of a state, region or the UnitedStates. Opponents of the RFS are seeking to force the EPA to reduce or eliminate the RFS. Further, several pieces of legislation have been introduced with thegoal of significantly reducing or eliminating the RFS. While the outcome of these legislative efforts is uncertain, it is possible that the EPA could adjust theRFS requirements in the future. If the EPA were to adjust the RFS requirements in any material way, it could negatively impact demand for the renewable fuelproducts we market, which could unfavorably impact our results of operations. The expiration of tax credits could adversely impact the demand for biodiesel, which could unfavorably impact our results of operations The demand for biodiesel is supported by certain federal tax credits. These tax credits have typically been granted for short durations, and on severaloccasions these tax credits have expired. In December 2014, the federal government passed a law reinstating the tax credit retroactively to January 1, 2014 tobe effective through December 31, 2014. Currently no such tax credit exists for transactions subsequent to December 31, 2014, and there can be no assurancethat the federal government will grant such tax credits in the future. If the federal government were to discontinue the practice of granting such tax credits,this would likely have an adverse effect on demand for biodiesel and on our biodiesel marketing operations. A loss of one or more significant customers could materially or adversely affect our results of operations. Approximately 65% of the revenues of our crude oil logistics segment during the year ended March 31, 2015 were generated from our ten largestcustomers of the segment. Approximately 23% of the water treatment and disposal revenues of our water solutions segment during the year ended March 31,2015 were generated from our two largest customers of the segment. Approximately 33% of the revenues of our liquids segment during the year endedMarch 31, 2015 were generated from our ten largest customers of the segment. Approximately 22% of the revenues of our refined products and renewablessegment during the year ended 43Table of Contents March 31, 2015 were generated from our ten largest customers of the segment. We expect to continue to depend on key customers to support our revenues forthe foreseeable future. The loss of key customers, failure to renew contracts upon expiration, or a sustained decrease in demand by key customers could resultin a substantial loss of revenues and could have a material and adverse effect on our results of operations. Certain of our operations are conducted through joint ventures which have unique risks. Certain of our operations are conducted through joint ventures. With respect to our joint ventures, we share ownership and 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, amongothers. 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 jointventure. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our businessand operations. From time to time, our joint ventures may be involved in disputes or legal proceedings which may negatively affect our investments.Accordingly, any such occurrences could adversely affect our financial condition, operating results and cash flows. Growing our business by constructing new transportation systems and facilities subjects us to construction risks and risks that supplies for such systemsand 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. In addition, Grand Mesa, one of our subsidiaries, is in the process of constructing a crude oil pipelineoriginating in Weld County, Colorado and terminating at our Cushing, Oklahoma terminal. We anticipate that the pipeline will commence service in thesecond half of calendar year 2016. These expansion projects require the expenditure of significant amounts of capital, which may exceed our resources, andinvolves numerous regulatory, environmental, political and legal uncertainties. There can be no assurances that we will be able to complete these projects onschedule or at all or at the budgeted cost. Moreover, our revenues may not increase upon the expenditure of funds on a particular project. Moreover, we mayundertake expansion projects to capture anticipated future growth in production in a region in which anticipated production growth does not materialize orfor which we are unable to acquire new customers. We may also rely on estimates of proved, probable or possible reserves in our decision to undertakeexpansion projects, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved, probable orpossible reserves. As a result, our new facilities and infrastructure may not be able to attract enough product to achieve our expected investment return, whichcould 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 allsince insurance varies in cost and can be difficult to obtain. Our failure to maintain adequate insurance coverage or successfully defend against productliability claims could materially and adversely affect our business, results of operations, financial condition and cash flows. A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results. Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial,operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financialresults could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberatelytampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk related to operationalsystem flaws, and employee tampering or manipulation of those systems will result in losses that are difficult to detect. Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computerprograms to help run our financial and operations sectors, and this may subject our business to increased 44Table of Contents risks. Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse effect on our business. Inaddition, cyber attacks on our customer and employee data may result in a financial loss, including potential fines for failure to safeguard data, and maynegatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disruptour business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results. We do not own all of the land on which our facilities are located, and instead lease certain facilities and equipment, and we, therefore, are subject to thepossibility 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 crude oil logistics and retail propane operations. We have in the pastexperienced difficulty in attracting and retaining sufficient numbers of qualified drivers. In addition, due in part to current economic conditions, includingthe cost of fuel, insurance, and tractors and the DOT regulatory requirements, the available pool of qualified truck drivers has been declining. Regulatoryrequirements, including the FMCSA’s CSA initiative, and an improvement in the economy could reduce the number of eligible drivers or require us to paymore to attract and retain drivers. A shortage of qualified drivers and intense competition for drivers from other companies will create difficulties inincreasing the number of our drivers for our anticipated expansion in our fleet of trucks. If we are unable to continue to attract and retain a sufficient numberof qualified drivers, we could have difficulty meeting customer demands, any of which could materially and adversely affect our growth and profitability. If we fail to maintain an effective system of internal controls, including internal controls over financial reporting, we may be unable to report our financialresults 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. We are also subject to the obligation underSection 404(a) of the Sarbanes Oxley Act of 2002 to annually review and report on our internal control over financial reporting, and to the obligation underSection 404(b) of the Sarbanes Oxley Act to engage our independent registered public accounting firm to attest to the effectiveness of our internal controlsover 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 ouroperating results or cause us to fail to meet our reporting obligations. These risks may be heightened after a business combination, during the phase when weare implementing our internal control structure over the recently acquired business. Given the difficulties inherent in the design and operation of internal controls over financial reporting, we can provide no assurance as to our, or 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. 45Table of Contents An impairment of goodwill and intangible assets could reduce our earnings. At March 31, 2015, we had reported goodwill and intangible assets of $2.7 billion. Such assets are subject to impairment reviews on an annual basis,or at an interim date if information indicates that such asset values have been impaired. Any impairment we would be required to record in our financialstatements would result in a charge to our income, which would reduce our earnings. Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment. Our credit management procedures may not fully eliminate the risk of nonpayment 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 nonpayment 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, natural gas liquids, and refined products. We own natural gas liquids and crude oil terminals, and TLP owns refined products terminals. These facilities depend on pipeline and storagesystems that are owned and operated by third parties. Any interruption of service on the pipeline or lateral connections or adverse change in the terms andconditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport product to and from our facilities andhave a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from ourfacilities affect the utilization and value of our terminals. We have historically been able to pass through the costs of pipeline transportation to our customers.However, if competing pipelines do not have similar annual tariff increases or service fee adjustments, such increases could affect our ability to compete,thereby adversely affecting our revenues. Our marketing operations depend on the availability of transportation and storage capacity. Our product supply is transported and stored on facilities owned and operated by third parties. Any interruption of service on the pipeline or 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 products 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 mayrequire us to borrow money to make distributions to our unitholders during these quarters. The natural gas liquids inventory we have presold 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 and taxissues 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. 46Table of Contents The risk of terrorism and political unrest in various energy producing regions may adversely affect the economy and the price and availability of products. An act of terror in any of the major energy producing regions of the world could potentially result in disruptions in the supply of crude oil 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 ofoperations. 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 our unitholders foractions 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 involvinga vote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated thirdparties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partnermay consider 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 ourgeneral partner or those other persons acted in bad faith or engaged in fraud or willful misconduct. By purchasing a common unit, a common unitholder will become bound by the provisions of our partnership agreement, including the 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 their owninterests 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 47Table of Contents general partner, conflicts of interest may arise between the NGL Energy GP Investor Group and its affiliates, including our general partner, on the one hand,and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliatesover the interests of our unitholders (see “— Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts theremedies available to our unitholders for actions taken by our general partner that might otherwise be breaches of fiduciary duty,” above). The risk to ourunitholders due to such conflicts may arise because of the following factors, among others: · our general partner is allowed to take into account the interests of parties other than us, such as members of the NGL Energy GP Investor Group,in resolving conflicts of interest; · neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us; · except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval; · our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities andthe 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; · our general partner determines which costs incurred by it are reimbursable by us; · our general partner may cause us to borrow funds to permit the payment of cash distributions, even if the purpose or effect of the borrowing is tomake 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 to our generalpartner in respect of the general partner interest or the incentive distribution rights (“IDRs”); · our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us 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 IDRs without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. Thiselection 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. 48Table of Contents Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our generalpartner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction,agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any suchperson or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entitypursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or informationto us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of usand our unitholders. Although we control TLP through our ownership of its general partner, TLP’s general partner owes fiduciary duties to TLP’s unitholders, which mayconflict with our interests. Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and TLP and itslimited partners, on the other hand. The directors and officers of TLP’s general partner have fiduciary duties to manage TLP in a manner beneficial to us. Atthe same time, TLP’s general partner has fiduciary duties to manage TLP in a manner beneficial to TLP and its limited partners. The board of directors ofTLP’s general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of theseconflicts may not always be in our best interest. For example, conflicts of interest with TLP may arise in the following situations: · the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and TLP, on the other hand; · the determination of the amount of cash to be distributed to TLP’s limited partners and the amount of cash to be reserved for the future conductof TLP’s business; and · the determination whether to make borrowings under TLP’s revolving credit facility to pay distributions to its limited partners. 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 annualmeetings of stockholders of corporations. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have limitedability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of theabsence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to callmeetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction ofmanagement. 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 our 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. 49Table of Contents The IDRs of our general partner may be transferred to a third party. Prior to the first day of the first quarter beginning after the 10th anniversary of the closing date of our IPO, a transfer of IDRs by our general partnerrequires (except in certain limited circumstances) the consent of a majority of our outstanding common units (excluding common units held by our generalpartner and its affiliates). However, after the expiration of this period, our general partner may transfer its IDRs to a third party at any time without the consentof our unitholders. If our general partner transfers its IDRs to a third party but retains its general partner interest, our general partner may not have the sameincentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its IDRs. Our general partner has a limited call right that may require our unitholders to sell their common units at an undesirable time or price. If at any time our general partner and its affiliates own more than 80% of the common units, our general partner will have the right, which it 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 may receive a negative return on their investment. Ourunitholders may also incur a tax liability upon a sale of their units. Cost reimbursements to our general partner may be substantial and could reduce our cash available to make quarterly distributions to our unitholders. Prior to making any distribution on the common units, we will reimburse our general partner and its affiliates for all expenses they incur on 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 the agreements governing our indebtedness on our ability to issue additional units, including units ranking seniorto the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interestexpense, 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; · the ratio of taxable income to distributions may increase; 50Table of Contents · the relative voting strength of each previously outstanding unit may be diminished; and · the market price of the common units may decline. Our general partner, without the approval of our unitholders, may elect to cause us to issue common units while also maintaining its general partnerinterest in connection with a resetting of the target distribution levels related to its IDRs. This could result in lower distributions to our unitholders. Our general partner has the right to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise ofthe reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterlydistribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterlydistribution. If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of commonunits to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterlycash distribution in the prior two quarters equal to the average of the distributions to our general partner on the IDRs in the prior two quarters. We anticipatethat our general partner would exercise this reset right to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cashdistributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it isexperiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common unitsrather than retain the right to receive distributions on its IDRs based on the initial target distribution levels. As a result, a reset election may cause ourcommon unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we notissued new common units and general partner interests to our general partner in connection with resetting the target distribution levels. Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business. A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations ofthe partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business ina number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not beenclearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partnerif a court or government agency were to determine that: · we were conducting business in a state but had not complied with that particular state’s partnership statute; or · a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our 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 areliable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time itbecame a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neitherliabilities to partners on account of their partnership interests nor liabilities that are non-recourse to the partnership are counted for purposes of determiningwhether a distribution is permitted. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware LP Act provides that thefair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extentthat the fair value of that property exceeds the nonrecourse liability. Tax Risks to Common Unitholders Our tax treatment depends on our status as a partnership for federal income tax purposes. We could lose our status as a partnership for a number ofreasons, including not having enough “qualifying income.” If the Internal Revenue Service (“IRS”) 51Table of Contents were to treat us as a corporation for federal income tax purposes, our cash available for distribution to our unitholders would be substantially reduced. The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for 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 federalincome tax purposes. Despite the fact that we are a limited partnership under Delaware law, a publicly traded partnership such as us will be treated as a corporation forfederal income tax purposes unless, for each taxable year, 90% or more of its gross income is “qualifying income” under Section 7704 of the InternalRevenue Code of 1986, as amended (the “Internal Revenue 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 ofincome such as certain interest and dividends and gains from the sale or other disposition of capital assets held for the production of income that otherwiseconstitutes qualifying income. Although we do not believe based upon our current operations that we are treated as a corporation, we could be treated as acorporation for federal income tax purposes or otherwise subject to taxation as an entity if our gross income is not properly classified as qualifying income,there is a change in our business or there is a change in current law. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate,which is currently a maximum of 35%, and would pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again 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 distribution to ourunitholders. 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 or administrativechanges 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 United States tax laws that would affect certain publicly traded partnerships, if such proposals areenacted into law. The Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning incomefrom activities related to fossil fuels be taxed as corporations beginning in 2021. If successful, the Obama administration’s proposal, or other similarproposals, could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which we rely for ourtreatment as a partnership for U.S. federal income tax purposes. We are unable to predict whether any such change or other proposals will ultimately be enacted or will affect our tax treatment. Any modification tothe income tax laws and interpretations thereof may or may not be applied retroactively and could, among other things, cause us to be treated as a corporationfor federal income tax purposes or otherwise subject us to entity-level taxation. Moreover, such modifications and change in interpretations may affect orcause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our incomeand adversely affect an investment in our common units. Although we are unable to predict whether any of these changes, or other proposals, will ultimatelybe enacted, any such changes could negatively impact the value of an investment in our common units. 52Table of Contents If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contestwill 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 whomwe will allocate taxable income that could be different in amount than the cash we distribute, our unitholders will be required to pay any federal income taxesand, 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 maynot receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income. Tax gain or loss on the disposition of our common units could be more or less than expected. If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis inthose common units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in theircommon units, the amount, if any, of such prior excess distributions with respect to the units the unitholder sells will, in effect, become taxable income to theunitholder if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore,a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potentialrecapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if aunitholder sell units, they may incur a tax liability in excess of the amount of cash they receive from the sale. Tax exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse tax consequences tothem. Investment in common units by tax exempt entities, such as employee benefit plans, individual retirement accounts (“IRAs”), Keogh plans and otherretirement plans and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations that areexempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them.Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States personswill be required to file United States federal income tax returns and pay tax on their share of our taxable income. If you are a tax exempt entity or a non-United States person, you should consult your tax advisor before investing in our common units. We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challengethis 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 TreasuryRegulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions andpropose adjustments to some or all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefitsavailable to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have anegative impact on the value of our common units or result in audit adjustments to tax returns of unitholders. We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate level income taxes. We conduct a portion of our operations through subsidiaries that are corporations for federal income tax purposes. We may elect to conductadditional operations in corporate form in the future. Our corporate subsidiaries will be subject to corporate level tax, which will reduce the cash available fordistribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions 53Table of Contents were to successfully assert that our corporate subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate taxrate, our cash available for distribution to our unitholders would be further reduced. We prorate our items of income, gain, loss and deduction for United States federal income tax purposes between transferors and transferees of our unitseach month based on the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRSmay challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders. We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based on the ownership of 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 common units. If so,such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loanand may recognize gain or loss from the disposition. Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of the loanedunits, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and theunitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss ordeduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could befully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller areurged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers fromborrowing their units. We have adopted certain valuation methodologies and monthly conventions for United States federal income tax purposes that may result in a shift ofincome, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect thevalue of our common units. When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate anyunrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed asunderstating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner,which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greaterportion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. TheIRS may challenge our valuation methods, or our allocation of the Internal Revenue Code Section 743(b) adjustment attributable to our tangible andintangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of our unitholders. A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to 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 our partnershipfor 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 totalinterests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of thesame unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, amongother 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 twoSchedules K-1 if relief was not available, as described below) for one fiscal year and could result in a significant deferral of depreciation deductions allowablein 54Table of Contents computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxableyear may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technicaltermination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a newpartnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties for failure to file a timely returnif we are unable to determine that a technical termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership thathas technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single ScheduleK-1 to unitholders for the tax years in which the termination occurs. There are limits on the deductibility of our losses that may adversely affect our unitholders. There are a number of limitations that may prevent unitholders from using their allocable share of our losses as a deduction against unrelatedincome. In cases where our unitholders are subject to the passive loss rules (generally, individuals and closely held corporations), any losses generated by uswill only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments.Unused losses may be deducted when the unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. Aunitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years but not by losses from other passiveactivities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by a unitholderinclude the at-risk rules and the prohibition against loss allocations in excess of the unitholder’s tax basis in its units. Purchasers of our common units may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own oracquire 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 ownor control property now or in the future. Holders of our common units are required to file foreign, state and local income tax returns and pay state and localincome taxes in some or all of these various jurisdictions and may be subject to penalties for failure to comply with those requirements. We own assets andconduct business in a number of states, most of which impose a personal income tax on individuals. Most of these states also impose an income tax oncorporations and other entities. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional states thatimpose a personal income tax. Item 1B. Unresolved Staff Comments None. Item 2. Properties Overview. We believe that we have satisfactory title or valid rights to use all of our material properties. Although some of these properties are subjectto liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-compete agreements entered into inconnection with acquisitions and other encumbrances, easements and restrictions, we do not believe that any of these burdens will materially interfere withour continued 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. For additional information regarding our properties and the reportable segments in which they are used, see Part I, Item 1—“Business.” 55Table of Contents 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 captions “Legal Contingencies,” “Customer Dispute,” and “Contractual Disputes” in Note 10 to ourconsolidated financial statements included in this Annual Report, which information is incorporated by reference into this Item 3. Item 4. Mine Safety Disclosures Not applicable. 56Table 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 the NYSEon 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 25, 2015, there wereapproximately 300 common unitholders of record which does not include unitholders for whom common units may be held in “street name.” The following table summarizes, for the periods indicated, the high and low sales 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 Range Cash High Low Distribution 2015 Fiscal YearFourth Quarter$31.70$24.88$0.6175Third Quarter40.5822.570.6088Second Quarter44.8639.130.5888First Quarter46.2537.080.55132014 Fiscal YearFourth Quarter$38.14$33.33$0.5313Third Quarter35.1030.100.5113Second Quarter33.9027.750.4938First Quarter30.6926.080.4775 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 as of the record date. Available cash for any quarter generally consists of all cash on hand at the end of that quarter, lessthe amount of cash reserves established by our general partner, to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any ofour debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for any one or more of the nextfour quarters. TLP’s partnership agreement also requires that, within 45 days after the end of each quarter, it distribute all of its available cash (as defined inits partnership agreement) to its unitholders as of the record date. Minimum Quarterly Distribution Our partnership agreement provided that, during the subordination period, the common units were entitled to distributions of available cash eachquarter in an amount equal to the minimum quarterly distribution, which was $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 were permitted on the subordinated units.Arrearages did not apply to and therefore were not paid on the subordinated units. The effect of the subordinated units was to increase the likelihood that,during the subordination period, available cash was sufficient to fully fund cash distributions on the common units in an amount equal to the minimumquarterly distribution. The subordination period ended in August 2014, at which time all outstanding subordinated units were converted into common unitson a one-for-one basis. 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. 57Table of Contents Incentive Distribution Rights Our general partner also currently holds IDRs which represent a variable interest in our distributions. IDRs entitle our general partner to receiveincreasing percentages, up to a maximum of 48.1%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of$0.388125 per unit per quarter. The maximum distribution of 48.1% includes distributions paid to our general partner on its 0.1% general partner interest andassumes that our general partner maintains its general partner interest at 0.1%. The maximum distribution of 48.1% does not include any distributions thatour general partner may receive on common 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 limitingour ability to pay distributions if we are in default under the Credit Agreement and to pay distributions that are in excess of available cash, as defined in theCredit Agreement. Sales of Unregistered Securities During the year ended March 31, 2015, we completed three acquisitions in which we issued unregistered common units as partial consideration. Allof these units were issued in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act of 1933, as amended (“SecuritiesAct”), as the units were issued to the owners of businesses acquired in privately negotiated transactions not involving any public offering or solicitation.During January 2015, we issued 132,100 common units to the sellers of a retail propane business. During February 2015, we issued 7,396,973 common unitsto the sellers of a natural gas liquids storage business. During the fourth quarter of fiscal year 2015, we issued 1,322,032 common units to the sellers of threewater treatment and disposal facilities. In July 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 in a private placement exempt from registration under the Securities Actpursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $393.5 million, after the initial purchasers’ discount of $6.0million and offering costs of $0.5 million. Securities Authorized for Issuance Under Equity Compensation Plans In connection with the completion of our IPO, our general partner adopted the NGL Energy Partners LP Long-Term Incentive Plan. Please seePart III, Item 12—“Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters—Securities Authorized for IssuanceUnder 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 wholesale propane andterminaling business of NGL Supply, which 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, and the retail propane business of Hicksgas, which refers to the combined assetsand operations of Hicksgas Gifford, Inc. (“Gifford”), and Hicksgas, LLC, a wholly owned subsidiary of NGL Energy Operating LLC (“Hicks LLC”). We do nothave our own historical financial statements for periods prior to our formation. The following table shows selected historical financial and operating data forNGL Energy Partners LP and NGL Supply (the deemed acquirer for accounting purposes in our formation) for the periods and as of the dates indicated. Thefinancial statements of NGL Supply became our historical financial statements for all periods prior to October 1, 2010. The following table should be read inconjunction with Part I, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements andrelated notes included in this Annual Report. 58Table of Contents The selected consolidated historical financial data (excluding volume information) at March 31, 2015, 2014, and 2013 and for each of the threeyears in the period ended March 31, 2015 are derived from our audited historical consolidated financial statements included in this Annual Report. Theselected consolidated historical financial data (excluding volume information) at March 31, 2012 and 2011 and for the six months ended March 31, 2011 arederived from our financial records. The selected consolidated historical financial data (excluding volume information) at September 30, 2010 and for the sixmonths then ended are derived from the financial records of NGL Supply. NGL Energy Partners LPNGL Supply, Inc. Six Months EndedSix Months Ended Year Ended March 31,March 31,September 30, 2015 2014 2013201220112010 (in thousands, except per unit and per share data)Income Statement Data (1)Total revenues$16,802,057$9,699,274$4,417,767$1,310,473$622,232$316,943Total cost of sales15,958,2079,132,6994,039,1101,217,023583,032310,908Operating income (loss)87,111106,56587,30715,03014,837(3,795)Interest expense110,12358,85432,9947,6202,482372Loss on early extinguishment of debt——5,769———Net income (loss) attributable to parent equity16,66147,65547,9407,87612,679(2,515)Basic and diluted income (loss) per commonunit(0.29)0.510.960.321.16Basic and diluted loss per common share(128.46)Cash Flows Data (1)Net cash provided by (used in) operatingactivities$262,394$85,236$132,634$90,329$34,009$(30,749)Cash distributions paid per common unit(subsequent to IPO)2.372.011.690.85Cash distributions paid per common unit(prior to IPO)0.35—Cash distributions paid per common share357.09Capital expenditures:Purchases of long-lived assets203,760165,14872,4757,5441,440280Purchases of pipeline capacity allocations24,218—————Purchase of equity interest in Grand MesaPipeline310,000—————Acquisitions of businesses, includingacquired working capital, net of cashacquired960,9221,268,810490,805297,40117,400123Balance Sheet Data - Period End (1)(2)Total assets$6,547,501$4,147,631$2,291,618$749,519$163,833$148,596Total long-term obligations, exclusive ofcurrent maturities2,761,3851,640,894742,641199,38965,93618,940Total equity2,673,1201,531,853889,418405,32947,35336,811Volume Information (1)Retail propane and distillates sold (gallons)204,141197,326173,23279,88634,9323,747Wholesale propane sold (gallons) (3)1,285,7071,190,106912,625659,921372,504226,330Wholesale other products sold (gallons)825,514786,671505,529134,99949,46546,092Crude oil sold (barrels)83,86446,10724,373———Water delivered (barrels)139,56962,77425,009———Refined products sold (barrels)68,0439,833———— 59Table of Contents (1) The acquisitions of businesses affect the comparability of this information. (2) Certain balance sheet data at March 31, 2014 was adjusted to reflect the final acquisition accounting for certain business combinations (seeNote 2 to our consolidated financial statements included in this Annual Report). (3) Includes intercompany volumes sold to our retail propane segment. Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations Overview We are a Delaware limited partnership (the “Partnership”) formed in September 2010. NGL Energy Holdings LLC serves as our general partner. OnMay 17, 2011, we completed our initial public offering (“IPO”). Subsequent to our IPO, we significantly expanded our operations through numerousacquisitons, as described under Part I, Item 1—“Business—Acquisitions.” At March 31, 2015, our operations include: · Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, owned and leased pipeline injectionstations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned and leased barges and towboats, and a 50%interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned andleased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. · Our water solutions segment, the assets of which include water treatment and disposal facilities. Our water solutions segment generates revenuesfrom the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recoveredhydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids. · Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United Statesand in Canada, and which provides natural gas liquids terminaling services through its 21 owned terminals throughout the United States andrailcar transportation services through its fleet of leased railcars. Our liquids segment purchases propane, butane, and other products fromrefiners, processing plants, producers, and other parties, and sells the products to retailers, refiners, petrochemical plants, and other participantsin the wholesale markets. · Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural,commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia. · Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the2.0% general partner interest and a 19.6% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined productsterminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and a 50% interestin Frontera Brownsville LLC, which are entities that own refined products storage facilities. Crude Oil Logistics Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection stations,storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. We attempt to reduce our exposure to price fluctuations by usingback-to-back contracts whenever possible. In addition, we enter into forward contracts, financial swaps, and commodity spread trades as economic hedges ofour physical forward sales and purchase contracts with our customers and suppliers. 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 hedging exposuredue to fluctuations in actual volumes and scheduled volumes. We utilize our transportation assets to move crude oil from the wellhead to the highest valuemarket. Spreads between crude oil prices in different markets can fluctuate, which may expand or limit our opportunity to generate margins by transportingcrude oil to different markets. We also seek to maximize margins by blending crude oil of varying properties. 60Table of Contents The range of low and high spot crude oil prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma and the prices atperiod end were as follows: Spot Price Per BarrelYear Ended March 31, Low High At Period End2015$43.46$107.26$47.60201486.68110.53101.58201377.69106.1697.23 We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results. Water Solutions Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production,from the sale of recycled water and recovered hydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids. Our water processingfacilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutionssegment is the extent of exploration and production in the areas near our facilities, which is based upon producers’ expectations about the profitability ofdrilling new wells. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume of water to our facility underlong-term contracts. The primary customers of our facilities in the Colorado have committed to deliver to our facilities all wastewater produced at wells in adesignated area. One customer in Texas has committed to deliver at least 50,000 barrels of wastewater per day to our facilities. Most of the customers at ourother facilities are not under volume commitments. Liquids Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells theproducts to retailers, refiners, petrochemical plants, and other participants in the wholesale markets. Our liquids segment owns 21 terminals, operates a fleet ofleased railcars, and leases underground storage capacity. We attempt to reduce our exposure to the impact of price fluctuations by using back-to-backcontracts and pre-sale agreements that allow us to lock in a margin on a percentage of our winter volumes. We also attempt to reduce our exposure to theimpact of price fluctuations by entering into swap agreements whereby we agree to pay a floating rate and receive a fixed rate on a specified notional amountof 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 can be 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 in our retail propane business. Weather conditions and gasoline blending can 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. The range of low and high spot propane prices per gallon at Conway, Kansas, and Mt. Belvieu, Texas, two of our main pricing hubs, and the prices atperiod end were as follows: Conway, Kansas Mt. Belvieu, TexasSpot Price Per Gallon Spot Price Per GallonYear Ended March 31,LowHigh At Period End Low High At Period End2015$0.38$1.13$0.45$0.45$1.13$0.5120140.774.331.030.811.731.0620130.500.960.900.711.220.96 61Table of Contents 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 March 31,Low High At Period End2015$0.60$1.30$0.6320141.081.641.2620131.141.931.45 We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results. Retail Propane Our retail propane segment is a “cost-plus” business that sells propane, distillates, and equipment and supplies to end users consisting of residential,agricultural, commercial, and industrial customers. Our retail propane segment purchases the majority of its propane from our liquids segment. Our retailpropane segment generates margins based on the difference between the wholesale cost of product and the selling price of the product in the retail markets.These margins fluctuate over time due to supply and demand conditions. Weather conditions can have a significant impact on our sales volumes and prices,as a large portion of our sales are to residential customers who purchase propane and distillates for home heating purposes. A significant factor affecting the profitability of our retail propane segment is our ability to maintain our product margin. Product margin is thedifferential between our sales prices and our total product costs, including transportation and storage. Historically, we have been successful in passing onprice increases to our customers. We monitor propane prices daily and adjust our retail prices to maintain expected margins by passing on the wholesale coststo our customers. Volatility in commodity prices may continue, and our ability to adjust to and manage this volatility may impact our financial results. The retail propane business is both weather-sensitive and subject to seasonal volume variations due to propane’s primary use as a heating source inresidential and commercial buildings and for agricultural purposes. Consequently, our revenues, operating profits, and operating cash flows are typicallylower in the first and second quarters of each fiscal year. Refined Products and Renewables Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. Of the sales volumes of ourrefined products and renewables segment during the year ended March 31, 2015, approximately 93% were refined products and approximately 7% wererenewables. We purchase refined petroleum products primarily in the Gulf Coast, East Coast, and Midwest regions of the United States and schedule them fordelivery primarily on the Colonial, Plantation, and Magellan pipelines. We sell our products to commercial and industrial end users, independent retailers,distributors, marketers, government entities, and other wholesalers of refined petroleum products. We sell our products at TLP’s terminals and at terminalsowned by third parties. The range of low and high spot gasoline prices per gallon using NYMEX gasoline prompt-month futures and the prices at period end were asfollows: Spot Price Per GallonYear Ended March 31,Low High At Period End2015$1.27$3.13$1.782014 (1)2.603.022.91 (1) Prices are for the four months ended March 31, 2014 as we acquired Gavilon, LLC (“Gavilon Energy”) on December 2, 2013. 62Table of Contents The range of low and high spot diesel prices per gallon using NYMEX ULSD prompt-month futures and the prices at period end were as follows: Spot Price Per GallonYear Ended March 31, Low High At Period End2015$1.62$3.05$1.722014 (1)2.903.282.93 (1) Prices are for the four months ended March 31, 2014 as we acquired Gavilon Energy on December 2, 2013. Recent Developments Grand Mesa Pipeline, LLC In September 2014, we entered into a joint venture with RimRock Midstream, LLC (“RimRock”) whereby each party owned a 50% interest in GrandMesa Pipeline, LLC (“Grand Mesa”). Grand Mesa is constructing a crude oil pipeline originating in Weld County, Colorado and terminating at our Cushing,Oklahoma terminal. In October 2014, Grand Mesa completed a successful open season in which it received the requisite support, in the form of ship-or-payvolume commitments from multiple shippers, to begin construction of a 20-inch pipeline system. In November 2014, we acquired RimRock’s 50% ownershipinterest in Grand Mesa for $310.0 million in cash. We anticipate that the pipeline will commence service in the second half of calendar year 2016. RimrockMidstream, LLC’s Platte River gathering system, which is currently under development, is expected to deliver volumes from multiple shippers to GrandMesa’s northern origin near Lucerne, Colorado. Acquisitions Acquisitions of businesses have had a significant impact on the comparability of our results of operations during the years ended March 31, 2015,2014 and 2013. These transactions are described under Part I, Item 1—“Business—Acquisitions.” Consolidated Results of Operations The following table summarizes our consolidated statements of operations for the years ended March 31, 2015, 2014, and 2013: Year Ended March 31, 2015 2014 2013 (in thousands) Total revenues$16,802,057$9,699,274$4,417,767Total cost of sales15,958,2079,132,6994,039,110Operating expenses372,176259,799169,612Loss on disposal or impairment of assets, net41,1843,597187General and administrative expense149,43075,86052,698Depreciation and amortization193,949120,75468,853Operating income87,111106,56587,307Earnings of unconsolidated entities12,1031,898—Interest expense(110,123)(58,854)(32,994)Loss on early extinguishment of debt——(5,769)Other income, net37,171861,521Income before income taxes26,26249,69550,065Income tax (provision) benefit3,622(937)(1,875)Net income29,88448,75848,190Less: Net income allocated to general partner(45,679)(14,148)(2,917)Less: Net income attributable to noncontrolling interests(13,223)(1,103)(250)Net income (loss) allocated to limited partners$(29,018)$33,507$45,023 See the detailed discussion of revenues, cost of sales, operating expenses, loss on disposal or impairment of assets, net, general and administrativeexpense, depreciation and amortization expense and operating income by segment below. The acquisitions described under Part I, Item 1—“Business— 63Table of Contents Acquisitions” have had a significant impact on the comparability of our results of operations during the years ended March 31, 2015, 2014 and 2013. Non-GAAP Financial Measures The following table reconciles net income attributable to parent equity to our EBITDA and Adjusted EBITDA (each as hereinafter defined), whichare non-GAAP financial measures: Year Ended March 31, 2015 2014 2013 (in thousands) Net income attributable to parent equity$16,661$47,655$47,940Income tax provision (benefit)(3,676)9371,875Interest expense106,59458,87132,994Loss on early extinguishment of debt——5,769Depreciation and amortization191,998127,82173,739EBITDA311,577235,284162,317Net unrealized (gains) losses on derivatives7,559(1,327)5,275Lower of cost or market adjustments16,806——Loss on disposal or impairment of assets, net41,2743,597187Equity-based compensation expense (1)42,89017,80410,138Adjusted EBITDA$420,106$255,358$177,917 (1) During January 2015, we reached an agreement with certain employees whereby certain bonus commitments otherwise payable in cashsubsequent to our fiscal year end would instead be paid using our common units. The amounts above include $10.1 million of compensationexpense during the year ended March 31, 2015 associated with these bonuses. As a result, the amount in this table for the year ended March 31,2015 is greater than the amount of equity-based compensation reported in Note 11 to our consolidated financial statements included in thisAnnual Report on Form 10-K (“Annual Report”). We define EBITDA as net income 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 net unrealized gains or losses on derivatives, lower of cost ormarket adjustments, gains or losses on the disposal or impairment of assets, and equity-based compensation expense. EBITDA and Adjusted EBITDA shouldnot be considered alternatives to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performancecalculated in accordance with accounting principles generally accepted in the United States (“GAAP”) as those items are used to measure operatingperformance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information to investors for evaluating ourability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA providesadditional information to investors for evaluating our financial performance without regard to our financing methods, capital structure and historical costbasis. Further, EBITDA and Adjusted EBITDA, as we define them, may not be comparable to EBITDA and Adjusted EBITDA or similarly titled measures usedby other entities. Other than for our refined products and renewables segment, for purposes of our Adjusted EBITDA calculation, we make a distinction betweenunrealized gains and losses on derivatives and realized gains and losses on derivatives. During the period when a derivative contract is open, we recordchanges in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recordedunrealized gain or loss and record a realized gain or loss. We do not draw such a distinction between realized and unrealized gains and losses on thederivatives of our refined products and renewables segment. The primary hedging strategy of this segment is to hedge against the risk of declines in the valueof inventory over the course of the contract cycle, and most of the hedges are six months to one year in duration at inception. A portion of the revenues of our water solutions business is generated from the sale of crude oil that we recover in the process of treating thewastewater. We have historically entered into derivative contracts to protect against the risk of declines in the value of the crude oil we expect to recover infuture months. During the year ended March 31, 2015, we settled certain derivative contracts that related to crude oil we expect to recover in the months fromApril 2015 through September 2015 and realized a gain of 64Table of Contents $17.9 million. Of this gain, $9.4 million and $8.5 million were attributable to derivatives with scheduled settlement dates during the quarters ending June 30,2015 and September 30, 2015, respectively. During the year ended March 31, 2015, we recorded $7.4 million of expense related to legal and advisory costs associated with acquisitions and$15.8 million of compensation expense associated with acquisitions (including certain bonuses that the previous owners of Gavilon Energy granted toemployees, contingent upon the successful completion of the sale of the business, and compensation expense related to termination benefits for certainTransMontaigne Inc. (“TransMontaigne”) employees). The following tables reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amountsreported in our consolidated statements of operations and consolidated statements of cash flows: Year Ended March 31,20152014 2013(in thousands)Reconciliation to consolidated statements of operations:Depreciation and amortization per EBITDA table$191,998$127,821$73,739Intangible asset amortization recorded to cost of sales(7,767)(6,172)(5,285)Depreciation and amortization of unconsolidated entities(18,979)(1,638)—Depreciation and amortization attributable to noncontrolling interests28,697743399Depreciation and amortization per consolidated statements of operations$193,949$120,754$68,853 Reconciliation to consolidated statements of cash flows:Depreciation and amortization per EBITDA table$191,998$127,821$73,739Amortization of debt issuance costs recorded to interest expense8,7595,7273,375Depreciation and amortization of unconsolidated entities(18,979)(1,638)—Depreciation and amortization attributable to noncontrolling interests28,697743399Depreciation and amortization per consolidated statements of cash flows$210,475$132,653$77,513 The following table summarizes expansion and maintenance capital expenditures for each of the periods indicated. This information has beenprepared on the accrual basis, and excludes property, plant and equipment acquired in acquisitions. Capital ExpendituresYear Ended March 31,ExpansionMaintenance Total(in thousands)2015$169,207$40,746$209,9532014132,94832,200165,148201358,67513,80072,475 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 Crescent Terminals, LLC, andCierra Marine, LP and its affiliated companies (collectively, “Crescent”) in July 2013, and Gavilon Energy in December 2013. We expanded our watersolutions business through numerous acquisitions of water disposal and transportation businesses, including High Roller Wells Big Lake SWD No. 1, Ltd.(“Big Lake”) in July 2013, Oilfield Water Lines LP (collectively, “OWL”) in August 2013, Coastal Plains Disposal #1, LLC (“Coastal”) in September 2013,and facilities acquired pursuant to development agreements. Our refined products and renewables businesses began with our December 2013 acquisition ofGavilon Energy and expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane businesses areimpacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, productprice fluctuations can have a significant impact on our sales volumes and revenues. 65Table of Contents Volumes The following table summarizes the volume of product sold and water delivered during the years ended March 31, 2015 and 2014. Volumes shownin the following table include intersegment sales. Year Ended March 31, Segment2015 2014 Change(in thousands)Crude oil logisticsCrude oil sold (barrels)83,86446,10737,757 Water solutionsWater delivered (barrels)139,56962,77476,795 LiquidsPropane sold (gallons)1,285,7071,190,10695,601Other products sold (gallons)825,514786,67138,843 Retail propanePropane sold (gallons)169,279162,3616,918Distillates sold (gallons)34,86234,965(103) Refined products and renewablesRefined products sold (barrels)68,0439,83358,210 Revenues and Cost of Sales by Segment Our revenues and cost of sales during the year ended March 31, 2015 by segment are as follows: Cost of ProductRevenuesSales Margin(In thousands)Crude oil logistics$6,665,220$6,590,313$74,907Water solutions200,042(30,506)230,548Liquids2,405,8412,273,630132,211Retail propane489,197278,538210,659Refined products and renewables7,232,7727,036,541196,231Corporate and other1,9162,583(667)Eliminations(192,931)(192,892)(39)Total$16,802,057$15,958,207$843,850 Operating Income (Loss) by Segment Our operating income (loss) by segment is as follows: Year Ended March 31,Segment2015 2014 Change(in thousands)Crude oil logistics$(35,832)$678$(36,510)Water solutions45,03110,31734,714Liquids45,07271,888(26,816)Retail propane64,07561,2852,790Refined products and renewables54,5676,51448,053Corporate and other(85,802)(44,117)(41,685)Operating income$87,111$106,565$(19,454) 66Table of Contents Crude Oil Logistics The following table summarizes the operating results of our crude oil logistics segment for the periods indicated: Year Ended March 31, 2015 2014 Change (in thousands) Revenues:Crude oil sales$6,609,685$4,559,923$2,049,762Crude oil transportation and other55,53536,46919,066Total revenues (1)6,665,2204,596,3922,068,828Expenses:Cost of sales6,590,3134,515,2442,075,069Operating expenses52,79054,043(1,253)Loss (gain) on disposal or impairment of assets, net3,759(171)3,930General and administrative expenses15,5644,48711,077Depreciation and amortization expense38,62622,11116,515Total expenses6,701,0524,595,7142,105,338Segment operating income (loss) (2)$(35,832)$678$(36,510) (1) Revenues include $29.8 million and $37.8 million of intersegment sales during the years ended March 31, 2015 and 2014, respectively, that areeliminated in our consolidated statements of operations. (2) In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent toexecuting these commitments, the producers requested to be released from the commitments. We agreed to release the producers from theircommitments in return for which the producers paid us specified amounts. Upon execution of these agreements in March 2015, we recorded again of $31.6 million to other income in our consolidated statement of operations, net of certain project abandonment costs. Since this gain wasreported in other income, it is not reflected in the table above. Revenues. Our crude oil logistics segment generated $6.6 billion of revenue from crude oil sales during the year ended March 31, 2015, selling 83.9million barrels at an average price of $78.81 per barrel. During the year ended March 31, 2014, our crude oil logistics segment generated $4.6 billion ofrevenue from crude oil sales, selling 46.1 million barrels at an average price of $98.90 per barrel. The decrease in revenue per barrel was due primarily to thesharp decline in crude oil prices during the year ended March 31, 2015. The most significant driver of the increase in our sales volumes was the acquisition ofGavilon Energy in December 2013. Crude oil transportation and other revenues were $55.5 million during the year ended March 31, 2015, compared to $36.5 million of crude oiltransportation and other revenues during the year ended March 31, 2014. This increase was due primarily to the Crescent acquisition in July 2013 and theGavilon Energy acquisition in December 2013. Cost of Sales. Our cost of crude oil sold was $6.6 billion during the year ended March 31, 2015, as we sold 83.9 million barrels at an average cost of$78.58 per barrel. Our cost of sales during the year ended March 31, 2015 was increased by $7.4 million of net unrealized losses on derivatives and wasreduced by $37.4 million of net realized gains on derivatives. During the year ended March 31, 2014, our cost of crude oil sold was $4.5 billion, as we sold46.1 million barrels at an average cost of $97.93 per barrel. Our cost of sales during the year ended March 31, 2014 was increased by $2.2 million of netunrealized losses on derivatives and by $5.1 million of net realized losses on derivatives. Product margins were lower during the year ended March 31, 2015 than during the year ended March 31, 2014, due primarily to the sharp decline incrude oil prices during the year ended March 31, 2015. This had an adverse impact on margins, due to the 67Table of Contents difference in timing of when we purchase product and when we deliver it to the point of sale. In addition, we were unable to utilize certain leased storageduring most of the year ended March 31, 2015, as markets were backwardated for most of the year. Operating Expenses. Our crude oil logistics segment incurred $52.8 million of operating expenses during the year ended March 31, 2015, comparedto $54.0 million of operating expenses during the year ended March 31, 2014. This decrease was due primarily to lower incentive compensation expense, as$7.3 million of compensation otherwise payable in cash will instead be paid in common units, and as a result the related expense was recorded within“corporate and other,” rather than within the crude oil logistics segment, lower railcar lease expense as we purchased railcars beginning in January 2014 toutilize in our operations, and lower relocation expenses, partially offset by an increase due to the Gavilon Energy acquisition in December 2013. Loss (Gain) on Disposal or Impairment of Assets, Net. Our crude oil logistics segment incurred $3.8 million of losses on disposal or impairment ofassets during the year ended March 31, 2015 and recorded a gain of $0.2 million on the disposal of assets during the year ended March 31, 2014. During theyear ended March 31, 2015, we recorded a write-off of project costs of $3.5 million related to a crude oil terminal project that has been discontinued. General and Administrative Expenses. Our crude oil logistics segment incurred $15.6 million of general and administrative expenses during the yearended March 31, 2015, compared to $4.5 million of general and administrative expenses during the year ended March 31, 2014. This increase was due to theacquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. General and administrative expenses during the years ended March 31,2015 and 2014 were increased by $5.6 million and $3.0 million, respectively, of compensation expense related to bonuses that the previous owners ofGavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014.General and administrative expenses during the year ended March 31, 2015 were also increased by $1.3 million of compensation expense related totermination benefits for certain TransMontaigne employees. Depreciation and Amortization Expense. Our crude oil logistics segment incurred $38.6 million of depreciation and amortization expense duringthe year ended March 31, 2015, compared to $22.1 million of depreciation and amortization expense during the year ended March 31, 2014. This increasewas due primarily to acquisitions and capital expansions. Water Solutions The following table summarizes the operating results of our water solutions segment for the periods indicated: Year Ended March 31, 20152014 Change(in thousands)Revenues:Service fees$105,682$58,161$47,521Recovered hydrocarbons81,76267,62714,135Water transportation10,76017,312(6,552)Other revenues1,838—1,838Total revenues200,042143,10056,942Expenses:Cost of sales - derivative (gain) loss (1)(36,763)1,969(38,732)Cost of sales - other6,2579,769(3,512)Operating expenses101,31359,18442,129Loss on disposal or impairment of assets, net7,5042,9944,510General and administrative expenses3,0823,762(680)Depreciation and amortization expense73,61855,10518,513Total expenses155,011132,78322,228Segment operating income$45,031$10,317$34,714 (1) Includes realized and unrealized (gains) losses. 68Table of Contents The following tables summarize activity separated among the following categories: · Facilities we owned prior to March 31, 2013; · Facilities we developed subsequent to March 31, 2013; and · Facilities we acquired subsequent to March 31, 2013. Service Fee Revenues. The following table summarizes our service fee revenue (in thousands, except per barrel amounts): Year Ended March 31, 2015Year Ended March 31, 2014 ServiceWaterBarrelsFees Per WaterServiceWaterBarrelsFees Per Water FeesProcessedBarrel ProcessedFeesProcessedBarrel Processed Existing facilities$65,54163,465$1.03$51,90846,628$1.11Recently developed facilities1,6673,1930.52———Recently acquired facilities38,47472,9110.536,25316,1460.39Total$105,682139,569$58,16162,774 The volumes of our existing facilities were higher during the year ended March 31, 2015 than during the year ended March 31, 2014, due primarilyto increased demand from customers. The average revenue per barrel varies across the areas in which we operate due to market conditions in these areas. Per barrel revenues are highest atour facility in Wyoming due to the nature of the services required. The majority of the recently acquired facilities are in Texas, where market rates for disposalare lower. Recovered Hydrocarbon Revenues. The following table summarizes recovered hydrocarbon revenue (in thousands, except per barrel amounts): Year Ended March 31, 2015Year Ended March 31, 2014 RecoveredWaterRevenueRecoveredWaterRevenue HydrocarbonBarrelsPer WaterHydrocarbonBarrelsPer Water RevenueProcessedBarrel ProcessedRevenueProcessedBarrel Processed Existing facilities$36,36163,465$0.57$40,39346,628$0.87Recently developed facilities1,6373,1930.51———Recently acquired facilities43,76472,9110.6027,23416,1461.69Total$81,762139,569$67,62762,774 The decrease in revenue per barrel associated with recovered hydrocarbons was due primarily to the sharp decline in crude oil prices during the yearended March 31, 2015. Our water solutions segment generated $10.8 million of water transportation revenue during the year ended March 31, 2015, compared to $17.3million of water transportation revenue during the year ended March 31, 2014. The decrease resulted from the sale of our water transportation business duringSeptember 2014. Cost of Sales. We entered into derivatives in our water solutions segment to protect against the risk of a decline in the market price of thehydrocarbons we expected to recover when processing the wastewater. Our cost of sales was reduced by $2.8 million of net unrealized gains on derivativesand $34.0 million of net realized gains on derivatives during the year ended March 31, 2015. Our cost of sales was increased by $0.6 million of netunrealized losses on derivatives and $1.4 million of net realized losses on derivatives during the year ended March 31, 2014. In December 2014, we settledderivative contracts that had scheduled settlement dates from April 2015 through September 2015, in order to lock in the gains on those derivatives. Our other cost of sales was $6.3 million during the year ended March 31, 2015, compared to $9.8 million during the year ended March 31, 2014.These costs related primarily to our water transportation business, which we sold during September 2014. 69Table of Contents Operating Expenses. The following table summarizes our operating expenses (in thousands): Year Ended March 31, 2015 2014 ChangeExisting facilities$46,324$36,381$9,943Recently developed facilities1,032—1,032Recently acquired facilities53,95722,80331,154Total$101,313$59,184$42,129 The increase in operating expenses for existing facilities is due primarily to increased costs associated with the construction and operation of newwater disposal wells at existing facilities. Loss on Disposal or Impairment of Assets, Net. Our water solutions segment incurred $7.5 million of losses on disposal or impairment of assetsduring the year ended March 31, 2015 and $3.0 million of losses on disposal or impairment of assets during the year ended March 31, 2014. During the yearended March 31, 2015, we sold our water transportation business and recorded a loss of $4.0 million. Also, during the year ended March 31, 2015, werecorded a loss on abandonment of $3.1 million related to the property, plant and equipment of water disposal facilities that we have retired. During the yearended March 31, 2014, we recorded losses on disposal of property, plant and equipment of $2.0 million as a result of property damage from lightning strikesat two of our facilities. General and Administrative Expenses. Our water solutions segment incurred $3.1 million of general and administrative expenses during the yearended March 31, 2015, compared to $3.8 million of general and administrative expenses during the year ended March 31, 2014. Depreciation and Amortization Expense. Our water solutions segment incurred $73.6 million of depreciation and amortization expense during theyear ended March 31, 2015, compared to $55.1 million of depreciation and amortization expense during the year ended March 31, 2014. Of this increase,$15.0 million related to acquisitions, which included $1.3 million of amortization expense related to trade name intangible assets. The remaining increasewas due primarily to $1.8 million of amortization expense related to trade name intangible assets. During the fourth quarter of the year ended March 31,2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets. Liquids The following table summarizes the operating results of our liquids segment for the periods indicated: Year Ended March 31, 20152014 Change(in thousands)Revenues:Propane sales$1,263,113$1,632,948$(369,835)Other product sales1,111,4341,231,965(120,531)Other revenues31,29431,062232Total revenues (1)2,405,8412,895,975(490,134)Expenses:Cost of sales - propane1,204,4991,559,266(354,767)Cost of sales - other products1,053,6301,179,944(126,314)Cost of sales - other15,50124,439(8,938)Operating expenses35,58037,672(2,092)Loss on disposal or impairment of assets, net29,7755,30524,470General and administrative expenses8,2716,4431,828Depreciation and amortization expense13,51311,0182,495Total expenses2,360,7692,824,087(463,318)Segment operating income$45,072$71,888$(26,816) 70Table of Contents (1) Revenues include $162.0 million and $245.6 million of intersegment sales during the years ended March 31, 2015 and 2014, respectively, thatare eliminated in our consolidated statements of operations. Revenues. Our liquids segment generated $1.3 billion of wholesale propane sales revenue during the year ended March 31, 2015, selling 1.3 billiongallons at an average price of $0.98 per gallon. During the year ended March 31, 2014, our liquids segment generated $1.6 billion of wholesale propane salesrevenue, selling 1.2 billion gallons at an average price of $1.37 per gallon. The increase in the volume sold from the year ended March 31, 2014 to the yearended March 31, 2015 was due primarily to the inclusion of the natural gas liquids operations acquired from Gavilon Energy for a full fiscal year (comparedto only four months of the prior fiscal year) and to the expansion of an agreement under which we market the majority of the production from a fractionationfacility. Our liquids segment generated $1.1 billion of other wholesale products sales revenue during the year ended March 31, 2015, selling 825.5 milliongallons at an average price of $1.35 per gallon. During the year ended March 31, 2014, our liquids segment generated $1.2 billion of other wholesaleproducts sales revenue, selling 786.7 million gallons at an average price of $1.57 per gallon. Our liquids segment generated $31.3 million of other revenues during the year ended March 31, 2015. This revenue includes storage subleaseincome, terminal gain/loss and income generated from the operation of a terminal for a customer. Cost of Sales. Our cost of wholesale propane sales was $1.2 billion during the year ended March 31, 2015, as we sold 1.3 billion gallons at anaverage cost of $0.94 per gallon. Our cost of wholesale propane sales during the year ended March 31, 2015 was increased by $4.6 million of net unrealizedlosses on derivatives. During the year ended March 31, 2014, our cost of wholesale propane sales was $1.6 billion, as we sold 1.2 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 net unrealizedlosses on derivatives. Our product margins for propane sales are summarized below (in thousands, except per gallon amounts): Year Ended March 31, 2015 2014 Propane revenues$1,263,113$1,632,948Propane cost of sales(1,204,499)(1,559,266)Propane product margin$58,614$73,682 Propane sold (gallons)1,285,7071,190,106 Product margin per gallon$0.05$0.06 Product margins per gallon of propane sold were lower during the year ended March 31, 2015 than during the prior year. Although we sold a highervolume of propane during the year ended March 31, 2015 than during the prior year, product margins were narrower. During the winter season of the yearended March 31, 2014, the price of propane increased as a result of high demand due to cold weather conditions. During the winter season of the year endedMarch 31, 2015, propane prices decreased, due primarily to a decline in the price of crude oil. Our product margins are typically higher during periods ofrising prices, due to the delay between when we purchase product and when we sell it. We utilize forward contracts and financial derivatives to hedge aportion, but not all, of the price risk associated with holding inventory. In addition, cost of sales during the year ended March 31, 2015 were increased by$4.6 million of net unrealized losses on derivatives, compared to $1.6 million of net unrealized losses on derivatives during the year ended March 31, 2014. 71Table of Contents Our cost of sales of other products was $1.1 billion during the year ended March 31, 2015, as we sold 825.5 million gallons at an average cost of$1.28 per gallon. Our cost of sales of other products during the year ended March 31, 2015 was reduced by $1.7 million of net unrealized gains onderivatives. During the year ended March 31, 2014, our cost of sales of other products was $1.2 billion, 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 net unrealized gains onderivatives. Our per-gallon product margins during the year ended March 31, 2015 were similar to those during the year ended March 31, 2014, assummarized below (in thousands, except per gallon amounts): Year Ended March 31, 2015 2014 Other products revenues$1,111,434$1,231,965Other products cost of sales(1,053,630)(1,179,944)Other products product margin$57,804$52,021 Other products sold (gallons)825,514786,671 Product margin per gallon$0.07$0.07 Operating Expenses. Our liquids segment incurred $35.6 million of operating expenses during the year ended March 31, 2015, compared to $37.7million of operating expenses during the year ended March 31, 2014. This decrease was due primarily to lower compensation expense, as $5.0 million ofcompensation otherwise payable in cash was instead paid in common units, and as a result the related expense was recorded within “corporate and other,”rather than within the liquids segment. Loss on Disposal or Impairment of Assets, Net. Our liquids segment incurred $29.8 million of losses on disposal or impairment of assets during theyear ended March 31, 2015, and $5.3 million of losses on disposal or impairment of assets during the year ended March 31, 2014. During the year endedMarch 31, 2015, we recorded a loss of $29.9 million on the sale of a natural gas liquids terminal. During the year ended March 31, 2014, we recorded animpairment of $5.3 million to the value of the property, plant and equipment of another natural gas liquids terminal. General and Administrative Expenses. Our liquids segment incurred $8.3 million of general and administrative expenses during the year endedMarch 31, 2015, compared to $6.4 million of general and administrative expenses during the year ended March 31, 2014. This increase was due primarily toexpanded operations. Depreciation and Amortization Expense. Our liquids segment incurred $13.5 million of depreciation and amortization expense during the yearended March 31, 2015, compared to $11.0 million of depreciation and amortization expense during the year ended March 31, 2014. 72Table of Contents Retail Propane The following table summarizes the operating results of our retail propane segment for the periods indicated: Year Ended March 31, 2015 2014 Change (in thousands)Revenues:Propane sales$347,575$388,225$(40,650)Distillate sales106,037127,672(21,635)Other revenues35,58535,918(333)Total revenues489,197551,815(62,618)Expenses:Cost of sales - propane181,655233,110(51,455)Cost of sales - distillates85,329109,058(23,729)Cost of sales - other11,55411,53123Operating expenses102,40596,9365,469General and administrative expenses12,35211,0171,335Depreciation and amortization expense31,82728,8782,949Total expenses425,122490,530(65,408)Segment operating income$64,075$61,285$2,790 Revenues. Our retail propane segment generated revenue of $347.6 million from propane sales during the year ended March 31, 2015, selling 169.3million gallons at an average price of $2.05 per gallon. During the year ended March 31, 2014, our retail propane segment generated $388.2 million ofrevenue from propane sales, selling 162.4 million gallons at an average price of $2.39 per gallon. The increase in volume sold was due in part to the growthof our business through acquisitions, partially offset by lower demand due to the fact that weather conditions were warmer in some markets in the winter ofthe year ended March 31, 2015 than during the winter of the prior year. Our retail propane segment generated revenue of $106.0 million from distillate sales during the year ended March 31, 2015, selling 34.9 milliongallons at an average price of $3.04 per gallon. During the year ended March 31, 2014, our retail propane segment generated $127.7 million of revenue fromdistillate sales, selling 35.0 million gallons at an average price of $3.65 per gallon. Cost of Sales. Our cost of retail propane sales was $181.7 million during the year ended March 31, 2015, as we sold 169.3 million gallons at anaverage cost of $1.07 per gallon. During the year ended March 31, 2014, our cost of retail propane sales was $233.1 million, as we sold 162.4 million gallonsat an average cost of $1.44 per gallon. Our cost of distillate sales was $85.3 million during the year ended March 31, 2015, as we sold 34.9 million gallons at an average cost of $2.45 pergallon. During the year ended March 31, 2014, our cost of distillate sales was $109.1 million, as we sold 35.0 million gallons at an average cost of $3.12 pergallon. Operating Expenses. Our retail propane segment incurred $102.4 million of operating expenses during the year ended March 31, 2015, compared to$96.9 million of operating expenses during the year ended March 31, 2014. The increase was due primarily to increased compensation expense resultingfrom the growth of the business. General and Administrative Expenses. Our retail propane segment incurred $12.4 million of general and administrative expenses during the yearended March 31, 2015, compared to $11.0 million of general and administrative expenses during the year ended March 31, 2014. Depreciation and Amortization Expense. Our retail propane segment incurred $31.8 million of depreciation and amortization expense during theyear ended March 31, 2015, compared to $28.9 million of depreciation and amortization expense during the year ended March 31, 2014. 73Table of Contents Refined Products and Renewables The following table summarizes the operating results of our refined products and renewables segment for the periods indicated. Our refined productsand renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne. Year Ended March 31, 2015 2014 Change (in thousands)Revenues:Refined products sales (1)$6,684,045$1,180,895$5,503,150Renewables sales473,885176,781297,104Service fees74,842—74,842Total revenues7,232,7721,357,6765,875,096Expenses:Cost of sales - refined products6,574,5451,172,7545,401,791Cost of sales - renewables461,996171,422290,574Operating expenses82,5836,20576,378General and administrative expenses26,13315625,977Depreciation and amortization expense32,94862532,323Total expenses7,178,2051,351,1625,827,043Segment operating income$54,567$6,514$48,053 (1) Revenues include $1.1 million of intersegment sales during the year ended March 31, 2015 that are eliminated in our consolidated statement ofoperations. Revenues. Our refined products sales revenue was $6.7 billion during the year ended March 31, 2015, selling 68.0 million barrels at an average priceof $98.23 per barrel. Our refined products sales revenue was $1.2 billion during the year ended March 31, 2014, selling 9.8 million barrels at an average priceof $120.10 per barrel. Our renewables sales revenue was $473.9 million during the year ended March 31, 2015, selling 5.3 million barrels at an average price of $89.11 perbarrel. Our renewables sales revenue was $176.8 million during the year ended March 31, 2014. Our refined products and renewables segment generated $74.8 million of service fee revenue during the year ended March 31, 2015, which was dueprimarily to TLP’s refined products terminaling operations. Cost of Sales. Our cost of refined products sales was $6.6 billion during the year ended March 31, 2015, as we sold 68.0 million barrels at an averagecost of $96.62 per barrel. Our cost of refined products sales was $1.2 billion during the year ended March 31, 2014, as we sold 9.8 million barrels at anaverage cost of $119.27 per barrel. Our refined product margins are summarized below (in thousands, except per barrel and per gallon amounts): Year Ended March 31,2015 2014 Revenues$6,684,045$1,180,895Cost of sales(6,574,545)(1,172,754)Product margin$109,500$8,141 Refined products sold (barrels)68,0439,833 Product margin per barrel$1.61$0.83 Product margin per gallon$0.04$0.02 Our cost of renewables sales was $462.0 million during the year ended March 31, 2015, as we sold 5.3 million barrels at an average cost of $86.87per barrel. Our cost of renewables sales was $171.4 million during the year ended March 31, 2014. Our renewables product margins for the year ended March31, 2015 are summarized below (in thousands, except per barrel and per gallon amounts): Revenues$473,885Cost of sales(461,996)Product margin$11,889 Renewables sold (barrels)5,318 Product margin per barrel$2.24 Product margin per gallon$0.05 During December 2014, a federal law was passed that enabled us to claim certain biodiesel tax credits for transactions during calendar year 2014.During the year ended March 31, 2015, our cost of sales was reduced by $8.7 million related to these tax credits. Operating Expenses. Our refined products and renewables segment incurred $82.6 million of operating expenses during the year ended March 31,2015, compared to $6.2 million of operating expenses during the year ended March 31, 2014. Of the operating expenses during the year ended March 31,2015, $48.2 million was attributable to TLP. 74Table of Contents General and Administrative Expenses. Our refined products and renewables segment incurred $26.1 million of general and administrative expensesduring the year ended March 31, 2015, compared to $0.2 million of general and administrative expenses during the year ended March 31, 2014. General andadministrative expenses during the year ended March 31, 2015 were increased by $0.5 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 were paid inDecember 2014. General and administrative expenses during the year ended March 31, 2015 were also increased by $8.0 million of compensation expenserelated to termination benefits for certain TransMontaigne employees. Of the general and administrative expenses during the year ended March 31, 2015,$15.0 million was attributable to TLP. Depreciation and Amortization Expense. Our refined products and renewables segment incurred $32.9 million of depreciation and amortizationexpense during the year ended March 31, 2015, compared to $0.6 million of depreciation and amortization expense during the year ended March 31, 2014.This increase was due primarily to depreciation on TLP’s terminal assets and amortization of customer relationship intangible assets acquired in the businesscombination with TransMontaigne. Of the depreciation and amortization expense during the year ended March 31, 2015, $28.7 million was attributable toTLP. Corporate and Other The operating loss within “corporate and other” includes the following components: Year Ended March 31, 2015 2014 Change (in thousands)Compressor leasing business (1)$133$2,336$(2,203)Natural gas business (2)(262)1,363(1,625)Equity-based compensation expense(32,767)(17,804)(14,963)Acquisition expenses(7,382)(6,908)(474)Other corporate expenses(45,524)(23,104)(22,420)Total$(85,802)$(44,117)$(41,685) (1) Operating income of our compressor leasing business during the year ended March 31, 2014 includes a $4.4 million gain from the sale of thebusiness in February 2014. (2) We acquired the natural gas business in our December 2013 acquisition of Gavilon Energy. We subsequently wound down the natural gasbusiness and, as of March 31, 2014, this business has no revenue-generating activity. The increase in equity-based compensation expense during the year ended March 31, 2015 was due primarily to $10.6 million of expense associatedwith restricted units granted in July 2014 to certain employees as a bonus that vested in September 2014, $5.0 million of compensation expense otherwisepayable in cash to employees of our liquids secment that was instead paid in common units, and an increase in the number of unvested restricted unitsoutstanding resulting from the growth of the business. The impact of these factors was partially offset by the fact that the market value of our common unitswas lower at March 31, 2015 than at March 31, 2014. Acquisition expenses during the year ended March 31, 2015 related primarily to the acquisitions of TransMontaigne and Sawtooth NGL Caverns,LLC (“Sawtooth”). Acquisition expenses during the year ended March 31, 2014 related primarily to the acquisition of Gavilon Energy. The increase in other corporate expenses during the year ended March 31, 2015 was due primarily to an increase in compensation expense, due tothe addition of new corporate employees to provide general and administrative services in support of the growth of our business. In addition, duringJanuary 2015, we reached an agreement with certain employees whereby certain bonus commitments otherwise payable in cash subsequent to our fiscal yearend would instead be paid using our common units. Other corporate expenses during the year ended March 31, 2015 include $10.0 million of this bonusexpense, which, if paid in cash, would have been reflected in expenses of the crude oil logistics, liquids, and refined products and renewables segments. Operating loss during the years ended March 31, 2015 and 2014 was increased by $0.4 million and $2.0 million, respectively, of compensationexpense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of thebusiness. These bonuses were paid in December 2014. This amount is reported within “other corporate expenses” in the table above. 75Table of Contents Year Ended March 31, 2014Compared to Year Ended March 31, 2013 Volumes The following table summarizes the volume of product sold and water delivered for the years ended March 31, 2014 and 2013. Volumes shown inthe following table include intersegment sales. Year Ended March 31, Segment20142013 Change(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 products and renewablesRefined products sold (barrels)9,833—9,833 Operating Income (Loss) by Segment Our operating income (loss) by segment is as follows: Year Ended March 31, Segment 2014 2013 Change (in thousands)Crude oil logistics$678$34,236$(33,558)Water solutions10,3178,5761,741Liquids71,88830,33641,552Retail propane61,28546,86914,416Refined products and renewables6,514—6,514Corporate and other(44,117)(32,710)(11,407)Operating income$106,565$87,307$19,258 76Table of Contents Crude Oil Logistics The following table summarizes the operating results of our crude oil logistics segment for the periods indicated: Year Ended March 31, 2014 2013 Change (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 and $22.9 million of intersegment sales during the years ended March 31, 2014 and 2013, respectively, that areeliminated 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 Energy, LP and High Sierra Energy GP, LLC (collectively, “HighSierra”). The increase in volume was also due to acquisitions of crude oil logistics businesses, including Gavilon Energy, Pecos Gathering & Marketing,L.L.C. and certain of its affiliated companies (collectively, “Pecos”), and Third Coast Towing, LLC (“Third Coast”), among others. Of this increase, $1.0billion was attributable to Gavilon Energy. Crude oil transportation and other revenues were $36.5 million during the year ended March 31, 2014, compared to $16.4 million of crude oiltransportation and other revenues during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logisticsbusiness 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. Cost of Sales. Our cost of crude oil sold was $4.5 billion during the year ended March 31, 2014, as we sold 46.1 million barrels at an average cost of$97.93 per barrel. Our cost of sales during the year ended March 31, 2014 was increased by $2.2 million of net 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 77Table of Contents during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions. Of this increase, $2.8 million was attributable toour 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 SouthTexas region from newly constructed pipelines. Operating income during the year ended March 31, 2014 was reduced by $3.0 million of compensationexpense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of thebusiness. These bonuses were paid in December 2014, contingent upon the continued service of the employees. We also recorded $0.5 million of employeeseverance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the Gavilon Energy acquisition. Water Solutions The following table summarizes the operating results of our water solutions segment for the periods indicated: Year Ended March 31, Change20142013 Acquisitions (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 expenses62,17825,45235,3771,349General and administrative expenses3,7621,6651,239858Depreciation 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. 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.The increase in revenues was due primarily to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra and 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. 78Table of Contents 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 inthe merger with High Sierra, which resulted primarily from a slowdown in production activities by a customer. During the three months ended December 31,2013, we wound down our water transportation operations in Oklahoma, transferring certain of the assets to our business in Texas and selling the 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 during theyear ended March 31, 2014 was increased by $0.6 million of net 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 net 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 $62.2 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 on disposalof property, plant and equipment of $2.0 million during the year ended March 31, 2014 as a result of property damage from lightning strikes at two of ourfacilities. General and Administrative Expenses. Our water solutions segment incurred $3.8 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 79Table of Contents during the year ended March 31, 2013. This increase was due in part to the fact that we did not own a water solutions business until our June 19, 2012 mergerwith High Sierra, and was also due to subsequent acquisitions of businesses. The increase is also due in part to $2.1 million of amortization expense related totrade name intangible assets. During the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-liveddefensive 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. Liquids The following table summarizes the operating results of our liquids segment for the periods indicated: Year Ended March 31, 2014 2013 Change (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)2,895,9751,733,6781,162,297Expenses: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 and $128.9 million of intersegment sales during the years ended March 31, 2014 and 2013, respectively, thatare 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 1.2 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 dueto the fact that we only owned the natural gas liquids business of High Sierra for a part of the year ended March 31, 2013. The remaining increase in volumewas due to several factors, including higher market demand, due in part to colder weather conditions, and the expansion of our customer base. In addition,during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operationsfrom these terminals. Our liquids segment generated $1.2 billion of other wholesale products sales revenue during the year ended March 31, 2014, selling 786.7 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 customerbase, and an increased focus on the opportunity to more fully utilize our terminals to market butane. 80Table of Contents Cost of Sales. Our cost of wholesale propane sales was $1.6 billion during the year ended March 31, 2014, as we sold 1.2 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 net 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 net unrealizedgains on derivatives. 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 ofall inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins onthese sales. During periods of declining prices, such as we experienced during the three months ended June 30, 2012, this can result in negative margins onthese 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 net unrealized gains onderivatives. 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 costof $1.66 per gallon. Our cost of sales of other products during the year ended March 31, 2013 was increased by $7.5 million of net unrealized losses onderivatives. 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 operationsand to colder weather conditions. As a result of the cold weather conditions, the demand for natural gas liquids increased considerably during the recentwinter, 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 afavorable impact on product margins, as we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold theinventory. These increases were partially offset by increased operating expenses as a result of expanding our operations. During the year ended March 31,2014, operating income was increased by $4.2 million of net unrealized gains on derivatives. During the year ended March 31, 2013, operating income wasreduced by $4.3 million of net unrealized losses on derivatives. 81Table of Contents Retail Propane The following table summarizes the operating results of our retail propane segment for the periods indicated: Year Ended March 31, 2014 2013 Change (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 ofrevenue from propane sales, selling 144.4 million gallons at an average price of $2.00 per gallon. The increase in volumes and average sales prices during theyear ended March 31, 2014 compared to the year ended March 31, 2013 was due primarily to market demand being higher as a result of colder weatherconditions. 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 Energy Corp. in ourresults of operations for the full 12 months ended March 31, 2014, as compared to only 11 of the months in the 12-month period ended March 31, 2013. General and Administrative Expenses. Our retail propane segment incurred $11.0 million of general and administrative expenses during the 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. 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. 82Table of Contents 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 and Renewables The following table summarizes the operating results of our refined products and renewables segment for the year ended March 31, 2014 (inthousands). Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy. Revenues:Refined products sales$1,180,895Renewables sales176,781Total revenues1,357,676Expenses:Cost of sales - refined products1,172,754Cost of sales - renewables171,422Operating expenses6,205General and administrative expenses156Depreciation and amortization expense625Total expenses1,351,162Segment operating income$6,514 Revenues. Our refined products sales revenue was $1.2 billion during the year ended March 31, 2014, selling 9.8 million barrels at an average priceof $120.10 per barrel. Our renewables sales revenue was $176.8 million during the year ended March 31, 2014. Cost of Sales. Our cost of refined products sales was $1.2 billion during the year ended March 31, 2014, as we sold 9.8 million barrels at an averagecost of $119.27 per barrel. Our cost of renewables sales was $171.4 million during the year ended March 31, 2014. Operating Expenses. Our refined products and renewables segment incurred $6.2 million of operating expenses during the year ended March 31,2014. General and Administrative Expenses. Our refined products and renewables segment incurred $0.2 million of general and administrative expensesduring the year ended March 31, 2014. Depreciation and Amortization Expense. Our refined products and renewables segment incurred $0.6 million of depreciation and amortizationexpense during the year ended March 31, 2014. Operating Income. Our refined products and renewables segment generated $6.5 million of operating income during the year ended March 31, 2014. 83Table of Contents Corporate and Other The operating loss within “corporate and other” includes the following components: Year Ended March 31, 20142013 Change(in thousands)Compressor leasing business (1)$2,336$(1)$2,337Natural gas business (2)1,363—1,363Equity-based compensation expense(17,804)(10,138)(7,666)Acquisition expenses(6,908)(5,602)(1,306)Other corporate expenses(23,104)(16,969)(6,135)Total$(44,117)$(32,710)$(11,407) (1) Operating income of our compressor leasing business during the year ended March 31, 2014 includes a $4.4 million gain from the sale of thebusiness in February 2014. (2) We acquired the natural gas business in our December 2013 acquisition of Gavilon Energy. We subsequently wound down the natural gasbusiness and, as of March 31, 2014, this business has no revenue-generating activity. The increase in equity-based compensation during the year ended March 31, 2014 was due in part to the timing of award grants and is also due inpart to an increase in the market value of our common units. The first restricted units were granted during fiscal year 2013, and therefore were not in existencefor the full fiscal year. The life-to-date expense for unvested units is adjusted based on the market value of the common units on the reporting date, and thevalue of the common units was higher at March 31, 2014 than at March 31, 2013. The increase in other corporate expenses during the year ended March 31, 2014 was due primarily to increases in compensation expense, due to theaddition of new corporate employees to provide general and administrative services in support of the growth of our business. Operating income during the year ended March 31, 2014 was reduced by $2.0 million of compensation expense related to bonuses that the previousowners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid inDecember 2014, contingent upon the continued service of the employees. We also recorded $2.2 million of employee severance expense during the yearended March 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. Other Income, Net In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent toexecuting these commitments, the producers requested to be released from the commitments. We agreed to release the producers from their commitments inreturn for which the producers paid us a specified amount in March 2015 and committed to pay us specified additional amounts over a period of five years. Inaddition, one of the producers committed to pay us a specified fee on each barrel of crude oil it produces in a specified basin over a period of seven years.Upon execution of these agreements in March 2015, we recorded a gain of $31.6 million to other income in our consolidated statement of operations, net ofcertain project abandonment costs. During the year ended March 31, 2015, we settled two separate contractual disputes and recorded $5.5 million of proceeds to other income in ourconsolidated statement of operations. Also during the year ended March 31, 2015, we offered to settle another contractual dispute, and recorded $1.2 millionto other expense as an estimate of the probable loss. 84Table of Contents Interest Expense The largest components of interest expense during the years ended March 31, 2015, 2014 and 2013 have been interest on our Revolving CreditFacility, the 2019 Notes, the 2021 Notes, the 2022 Notes, and the TLP Credit Facility (each as hereinafter defined). See Note 8 to our consolidated financialstatements included in this Annual Report for additional information on our long-term debt. The change in interest expense during the periods presented wasdue primarily to fluctuations in the average outstanding debt balance and the applicable interest rates, as summarized below: Revolving Credit Facilities 2019 Notes2021 Notes2022 NotesTLP Credit Facility Average Average AverageAverageAverage Balance Average Balance BalanceBalanceBalance Outstanding Interest Outstanding InterestOutstandingInterestOutstandingInterestOutstandingInterestYear Ended March 31, (in thousands) Rate (in thousands) Rate(in thousands)Rate(in thousands)Rate(in thousands)Rate2015$1,172,4292.35%$400,0005.13%$450,0006.88%$250,0006.65%$250,3462.10%2014588,3753.04%205,8906.88%250,0006.65%2013405,1143.56%195,8906.65% Interest expense also includes amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion ofinterest on noninterest bearing debt obligations assumed in business combinations. On June 19, 2012, we made a principal payment of $306.8 million to retire a then-existing revolving credit facility. Upon retirement of this facility,we wrote off the portion of the debt issuance cost intangible asset that had not yet been amortized. This expense is reported as “Loss on early extinguishmentof debt” in our consolidated statement of operations for the year ended March 31, 2013. The increased level of debt outstanding from fiscal years 2013 to 2015 was due primarily to borrowings to finance acquisitions and capitalexpenditures. Income Tax Provision (Benefit) We qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reportshis 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 in Canada, and our operations in Texas are subject to a state franchise taxthat is calculated based on revenues net of cost of sales. We utilize the asset and liability method of accounting for income taxes. Under this method, deferredtax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts ofexisting assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in theyears in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includesthe enactment date. Income tax benefit was $3.6 million during the year ended March 31, 2015, compared to $0.9 million of income tax expense during the year endedMarch 31, 2014. The income tax benefit was due primarily to a benefit of $6.3 million related to the July 2014 acquisition of TransMontaigne, asTransMontaigne and certain of its subsidiaries were subject to United States federal and state income taxes. On December 31, 2014, we converted thesesubsidiaries from taxable corporations to non-taxable limited liability companies. Noncontrolling Interests We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated financialstatements represents the other owners’ interest in these entities. Net income attributable to noncontrolling interests was $13.2 million during the year ended March 31, 2015, compared to $1.1 million during theyear ended March 31, 2014. The increase was due primarily to the July 2014 acquisition of TransMontaigne, in which we acquired a 19.7% limited partnerinterest in TLP. 85Table of Contents Seasonality Seasonality impacts our liquids and retail propane segments. A large portion of our retail propane business is in the residential market where propaneis used primarily for home heating purposes. Consequently, for these two segments, revenues, operating profits and operating cash flows are generated mostlyin the third and fourth quarters of each fiscal year. See “—Liquidity, Sources of Capital and Capital Resource Activities—Cash Flows.” Liquidity, Sources of Capital and Capital Resource Activities Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. Our cashflows from operations are discussed below. Our borrowing needs vary during the year due to the seasonal nature of our liquids business. Our greatest working capital borrowing needs generallyoccur 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 as of the record date. Available cash for any quarter generally consists of all cash on hand at the end of that quarter, lessthe amount of cash reserves established by our general partner, to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any ofour debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for any one or more of the nextfour quarters. TLP’s partnership agreement also requires that, within 45 days after the end of each quarter it distribute all of its available cash (as defined in itspartnership agreement) to its unitholders as of the record date. We believe that our anticipated cash flows from operations and the borrowing capacity under our Revolving Credit Facility are sufficient to meetour liquidity needs. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital. Our ability toraise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances that we canraise additional capital to meet these needs (see Part I, Item 1A—“Risk Factors”). Commitments or expenditures, if any, we may make toward any acquisitionprojects are at our discretion. We continue to pursue a strategy of growth through acquisitions. We expect to consider financing future acquisitions through a variety of sources,including the use of available capacity on our Revolving Credit Facility, the issuance of common units to sellers of businesses we acquire, privateplacements of common units or debt securities, and public offerings of common units or debt securities. Our ability to raise additional capital through theissuance of debt or equity securities will have a significant impact on our ability to continue to pursue our growth strategy. Long-Term Debt Credit Agreement We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes arevolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansionprojects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). At March 31, 2015, ourRevolving Credit Facility had a total capacity of $2.296 billion. The Expansion Capital Facility had a total capacity of $858.0 million for cash borrowings at March 31, 2015. At that date, we had outstandingborrowings of $702.5 million on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.438 billion for cash borrowings andletters of credit at March 31, 2015. At that date, we had outstanding borrowings of $688.0 million and outstanding letters of credit of $108.6 million on theWorking Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the CreditAgreement, 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 prepay outstanding borrowings under the CreditAgreement without incurring any penalties, and prepayments 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 86Table of Contents based on our consolidated leverage ratio, as defined in the Credit Agreement. At March 31, 2015, all borrowings under the Credit Agreement were LIBORborrowings with an interest rate at March 31, 2015 of 2.18%, calculated as the LIBOR rate of 0.18% plus a margin of 2.0%. At March 31, 2015, the interestrate in effect on letters of credit was 2.25%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused capacity. 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 at any quarter end. The leverage coverage ratio in our Credit Agreement excludes TLP’s debt. At March 31, 2015, ourleverage ratio was approximately 3.2 to 1. The Credit Agreement also specifies that our interest coverage ratio, as defined in the Credit Agreement, cannot beless than 2.75 to 1 at any quarter end. At March 31, 2015, our interest coverage ratio was approximately 5.9 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 eventsof default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by thePartnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcyor insolvency. At March 31, 2015, we were in compliance with the covenants under the Credit Agreement. 2019 Notes On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”) in a private placement exempt from registrationunder the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. We received netproceeds of $393.5 million, after the initial purchasers’ discount of $6.0 million and offering costs of $0.5 million. We used the net proceeds to reduce theoutstanding balance on our Revolving Credit Facility. The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notesprior to the maturity date, although we would be required to pay a premium price for early redemption. The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certainof our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving CreditFacility. The indenture governing the 2019 Notes contains various customary covenants, including, without limitation, limitations on fundamental changesand limitations on indebtedness and liens. Our obligations under the indenture may be accelerated following certain events of default (subject to applicablecure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debtagreements, or (iii) certain events of bankruptcy or insolvency. At March 31, 2015, we were in compliance with the covenants under the indenture governing the 2019 Notes. We also entered into a registration rights agreement whereby, in February 2015, we exchanged the 2019 Notes for a new issue of notes registeredunder the Securities Act that has substantially identical terms to the 2019 Notes. 2021 Notes On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”) in a private placement exempt fromregistration under the Securities Act pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $438.4 million, after theinitial purchasers’ discount of $10.1 million and offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our RevolvingCredit Facility. The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021Notes prior to the maturity date, although we would be required to pay a premium for early redemption. The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certainof our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving CreditFacility. The indenture governing the 2021 Notes contains various customary covenants, including, without limitation, limitations on fundamental changesand limitations on indebtedness and liens. Our obligations under the indenture may be accelerated following certain events of default (subject to applicablecure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debtagreements, or (iii) certain events of bankruptcy or insolvency. 87Table of Contents At March 31, 2015, we were in compliance with the covenants under the indenture governing the 2021 Notes. We also entered into a registration rights agreement whereby, in February 2015, we exchanged the 2021 Notes for a new issue of notes registeredunder the Securities Act that has substantially identical terms to the 2021 Notes. 2022 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 “2022 Notes”). The 2022 Notes bear interest at a fixed rate of 6.65%, which is payable quarterly. The 2022 Notes arerequired to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. Wehave the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of ourassets 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 similar leverage ratio and interest coverage ratio requirements to those of our Credit Agreement, which is describedabove. 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) nonpayment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the 2022 Notes,(iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtednessunpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the NotePurchase Agreement, the 2022 Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certainevents of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% inaggregate principal amount of the then outstanding 2022 Notes of any series may declare all of the 2022 Notes of such series to be due and payableimmediately. At March 31, 2015, we were in compliance with the covenants under the Note Purchase Agreement. TLP Credit Facility TLP is party to a credit agreement with a syndicate of banks that provides for a revolving credit facility (the “TLP Credit Facility”). The TLP CreditFacility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million and (ii) 4.75 times Consolidated EBITDA (as defined:$368.7 million at March 31, 2015). The terms of the TLP Credit Facility include covenants that restrict TLP’s ability to make cash distributions, acquisitionsand investments, including investments in joint ventures. TLP may make distributions of cash to the extent of TLP’s “available cash” as defined in TLP’spartnership agreement. TLP may make acquisitions and investments that meet the definition of “permitted acquisitions”; “other investments” which may notexceed 5% of “consolidated net tangible assets”; and additional future “permitted JV investments” up to $125 million, which may include additionalinvestments in BOSTCO. The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date of July 31,2018. 88Table of Contents The following table summarizes our basis in the assets and liabilities of TLP at March 31, 2015, inclusive of the impact of our acquisitionaccounting for the business combination with TransMontaigne (in thousands): Cash and cash equivalents$918Accounts receivable - trade9,069Accounts receivable - affiliates583Inventories1,361Prepaid expenses and other current assets1,410Property, plant and equipment, net475,506Goodwill28,074Intangible assets, net72,295Investments in unconsolidated entities255,073Other noncurrent assets2,458Accounts payable - trade(6,565)Accounts payable - affiliates(76)Net intercompany payable(1,965)Accrued expenses and other payables(8,715)Advance payments received from customers(146)Long-term debt(250,000)Other noncurrent liabilities(3,541)Net assets$575,739 TLP may elect to have loans under the TLP Credit Facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% dependingon the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLPalso pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then ineffect. For the period from July 1, 2014 to March 31, 2015, the weighted-average interest rate on borrowings under the TLP Credit Facility was approximately2.10%. TLP’s obligations under the TLP Credit Facility are secured by a first priority security interest in favor of the lenders in the majority of TLP’s assets,including TLP’s investments in unconsolidated affiliates. At March 31, 2015, TLP had outstanding borrowings under the TLP Credit Facility of $250 millionand no outstanding letters of credit. The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization,compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults,covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratiotest (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) in the event TLP issues senior unsecured notes, and (iii) aminimum interest coverage ratio test (not less than 3.0 times). These financial covenants are based on a defined financial performance measure within the TLPCredit Facility known as “Consolidated EBITDA.” TLP’s Credit Facility is non-recourse to NGL. 89Table of Contents Revolving Credit Balances The following table summarizes our revolving credit facility borrowings: Average Balance Lowest Highest Outstanding Balance Balance (in thousands) Year Ended March 31, 2015:Expansion capital borrowings$435,752$114,000$830,000Working capital borrowings736,677339,5001,046,000TLP credit facility borrowings(from July 1, 2014 through March 31, 2015)250,346228,000259,700 Year Ended March 31, 2014:Expansion capital borrowings$392,822$—$546,000Working capital borrowings195,553—448,500 Acquisitions Subsequent to our IPO, we significantly expanded our operations through numerous acquisitions, as described under Part I, Item 1—“Business—Acquisitions.” Cash Flows The following table summarizes the sources (uses) of our cash flows: Year Ended March 31,Cash Flows Provided by (Used in):2015 2014 2013(in thousands)Operating activities, before changes in operating assets and liabilities$99,290$243,303$146,395Changes in operating assets and liabilities163,104(158,067)(13,761) Operating activities$262,394$85,236$132,634 Investing activities(1,366,221)(1,455,373)(546,621) Financing activities1,134,6901,369,016417,716 Operating Activities. The growth in our operating cash flows from fiscal years 2013 through 2015 was driven primarily by increased operatingactivity resulting from acquisitions. Changes in working capital due to changes in the timing of cash receipts and payments can have a significant impact oncash flows from operations. During fiscal years 2013 through 2015, our cash outflows from investing activities included the purchase of working capital inbusiness combinations, a portion of which has benefitted (or will benefit) cash flows from operations as the working capital is recovered. The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. The changes in ouroperating assets and liabilities caused by the seasonality of our retail and wholesale natural gas liquids businesses also have a significant impact on our cashflows from operating activities. Increases in natural gas liquids prices typically reduce our operating cash flows due to higher cash requirements to fundincreases in inventories, and decreases in natural gas liquids prices typically increase our operating cash flows due to lower cash requirements to fundincreases in inventories. In general, our operating cash flows are at their lowest levels during our first and second fiscal quarters, or the six months ending September 30,when we experience operating losses or lower operating income as a result of lower volumes of natural gas liquids sales and when we are building ourinventory levels for the upcoming heating season. Our operating cash flows are generally greatest during our third and fourth fiscal quarters, or the six monthsending March 31, when our operating income levels are highest 90Table of Contents and customers pay for natural gas liquids consumed during the heating season months. We borrow under our revolving credit facility to supplement ouroperating cash flows as necessary during our first and second fiscal quarters. Investing Activities. Net cash used in investing activities was $1.4 billion during the year ended March 31, 2015, compared to $1.5 billion in netcash used in investing activities during the year ended March 31, 2014. The decrease in net cash used in investing activities was due primarily to: · a $307.9 million decrease in cash paid for acquisitions during the year ended March 31, 2015; and · a $235.1 million increase in the proceeds from derivatives. These decreases in net cash used in investing activities were partially offset by: · a $310.0 million increase due to the purchase of the remaining equity interest in Grand Mesa during the year ended March 31, 2015; · a $61.9 million increase related to a loan receivable associated with our financing of the construction of a natural gas liquids facility to beutilized by a third party; · a $38.6 million increase in capital expenditures during the year ended March 31, 2015, of which $30.1 million represented expansion capitaland $8.5 million represented maintenance capital (of this maintenance capital, $7.9 million related to TLP); · a $24.2 million increase for the purchase of certain refined product pipeline capacity allocations from other shippers during the year endedMarch 31, 2015; and · a $22.0 million increase in contributions to unconsolidated entities during the year ended March 31, 2015 due primarily to our investment inBOSTCO which we acquired as part of our July 2014 acquisition of TransMontaigne. Net cash used in investing activities was $1.5 billion during the year ended March 31, 2014, compared to $546.6 million in net cash used ininvesting activities during the year ended March 31, 2013. The increase in net cash used in investing activities was due primarily to: · a $778.0 million increase in cash paid for acquisitions during the year ended March 31, 2014 due primarily to our December 2013 acquisitionof Gavilon Energy; · a $92.7 million increase in capital expenditures during the year ended March 31, 2014, of which $74.3 million represented expansion capitaland $18.4 million represented maintenance capital; and · a $47.5 million increase in investing cash outflows from commodity derivatives during the year ended March 31, 2014. Financing Activities. Net cash provided by financing activities was $1.1 billion during the year ended March 31, 2015, compared to $1.4 billion innet cash provided by financing activities during the year ended March 31, 2014. The decrease in net cash provided by financing activities was due primarilyto: · a $123.8 million increase in distributions paid to our partners and noncontrolling interest owners during the year ended March 31, 2015; · a $109.0 million decrease in the proceeds received from the sale of our common units during the year ended March 31, 2015 as more of ourcommon units were issued during the year ended March 31, 2014 to fund acquisitions; and · a $50.0 million decrease in the proceeds received from debt issuances during the years ended March 31, 2015 and 2014. These decreases in net cash provided by financing activities were partially offset by a $40.0 million increase in borrowings on our revolving creditfacilities (net of repayments) to fund our operating or investing requirements during the year ended March 31, 91Table of Contents 2015. To the extent our cash flows from operating activities are not sufficient to finance our required distributions to our partners and noncontrolling interestowners, we may be required to increase borrowings under our Working Capital Facility. Net cash provided by financing activities was $1.4 billion during the year ended March 31, 2014, compared to $417.7 million in net cash providedby financing activities during the year ended March 31, 2013. The increase in net cash provided by financing activities was due primarily to: · a $650.8 million increase in the proceeds received from the sale of our common units during the year ended March 31, 2014 to fundacquisitions; · a $200.0 million increase in the proceeds received from debt issuances during the years ended March 31, 2014 and 2013; and · a $181.0 million increase in borrowings on our revolving credit facilities (net of repayments) to fund our operating or investing requirementsduring the year ended March 31, 2014. These increases in net cash provided by financing activities were partially offset by a $74.3 million increase in distributions paid to our partners andnoncontrolling interest owners during the year ended March 31, 2014. The following table summarizes the distributions declared subsequent to our IPO: Amount Amount Paid To Amount Paid ToDate DeclaredRecord Date Date Paid Per Unit Limited Partners General 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 19, 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 24, 2014February 4, 2014February 14, 20140.531342,1504,283April 24, 2014May 5, 2014May 15, 20140.551343,7375,754July 24, 2014August 4, 2014August 14, 20140.588852,0369,481October 24, 2014November 4, 2014November 14, 20140.608853,90211,141January 26, 2015February 6, 2015February 13, 20150.617554,68411,860April 24, 2015May 5, 2015May 15, 20150.625059,65113,446 The following table summarizes the distributions declared by TLP subsequent to our acquisition of general and limited partner interests in TLP(exclusive of the distribution declared in July 2014, the proceeds of which we remitted to the former owners of TransMontaigne, pursuant to agreementsentered into at the time of the business combination): Amount Amount Paid Amount Paid ToDate DeclaredRecord Date Date Paid Per Unit To NGL Other Partners (in thousands) (in thousands)October 13, 2014October 31, 2014November 7, 2014$0.6650$4,010$8,614January 8, 2015January 30, 2015February 6, 20150.66504,0108,614April 13, 2015April 30, 2015May 7, 20150.66504,0078,617 92Table of Contents Contractual Obligations The following table summarizes our contractual obligations at March 31, 2015 for our fiscal years ending thereafter: Years Ending March 31,Total 2016 2017 201820192020Thereafter(in thousands)Principal payments on long-term debt —Expansion capital borrowings$702,500$—$—$—$702,500$—$—Working capital borrowings688,000———688,000——2019 Notes400,000————400,000—2021 Notes450,000—————450,0002022 Notes250,000——25,00050,00050,000125,000TLP Credit Facility250,000———250,000——Other long-term debt9,2714,4732,5671,626362105138Interest payments on long-term debt —Revolving Credit Facility (1)128,67835,74435,74435,74421,446——2019 Notes92,25020,50020,50020,50020,50010,250—2021 Notes (2)217,01331,38830,93830,93830,93830,93861,8732022 Notes83,12516,62516,62516,20913,3009,97510,391TLP Credit Facility22,2566,6756,6756,6752,231——Other long-term debt438203123761899Letters of credit108,584———108,584——Future minimum lease payments under othernoncancelable operating leases541,845119,817102,39487,30263,20553,423115,704Future minimum throughput payments undernoncancelable agreements (3)511,708122,05281,93582,01681,22253,51190,972Construction commitments (4)666,497426,384240,113————Fixed-price commodity purchase commitments35,47635,476—————Index-price commodity purchase commitments (5)728,262728,262—————Total contractual obligations$5,885,903$1,547,599$537,614$306,086$2,032,306$608,211$854,087 Purchase commitments (thousands):Natural gas liquids fixed-price (gallons) (6)57,79257,792—————Natural gas liquids index-price (gallons) (6)659,603659,603—————Crude oil index-price (barrels) (6)8,4508,450————— (1) The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at March 31, 2015.See Note 8 to our consolidated financial statements included in this Annual Report for additional information on our Credit Agreement. (2) Interest payments for the fiscal year ending March 31, 2016 include $0.5 million of liquidated damages resulting from a delay in completing anexchange offer. (3) At March 31, 2015, we had agreements with crude oil and refined products pipeline operators obligating us to minimum throughput paymentsin exchange for pipeline capacity commitments. (4) At March 31, 2015, we had the following construction commitments: · As described in “—Recent Developments,” Grand Mesa completed a successful open season in which it received the requisite support,in the form of ship-or-pay volume commitments from multiple shippers, to begin construction of a 20-inch pipeline system. Theestimated construction cost of Grand Mesa is $655.0 million and we anticipate that the pipeline will commence service in the secondhalf of calendar year 2016. · In February 2015, we acquired Sawtooth NGL Caverns, LLC, which owns a natural gas liquids salt dome storage facility in Utah withrail and truck access to western U.S. markets. As part of this acquisition, we also entered into a construction agreement to expand thestorage capacity of the facility by constructing two additional salt dome storage facilities. The estimated construction cost of thisexpansion is $41.2 million and we anticipate this project will be completed by the end of calendar year 2015. · In March 2015, we entered into an agreement with a third party to construct a solids processing facility and solids disposal facility inWeld County, Colorado. Our estimated construction cost for this project is $9.0 million. We anticipate that these facilities will becompleted in the second half of calendar year 2016. 93Table of Contents (5) At March 31, 2015, we had the following purchase commitments (in thousands): Natural gas liquids index-price$352,563Crude oil index-price375,699 Index prices are based on a forward price curve at March 31, 2015. A theoretical change of $0.10 per gallon in the underlying commodity priceat March 31, 2015 would result in a change of $66.0 million in the value of our index-price natural gas liquids purchase commitments. Atheoretical change of $1.00 per barrel in the underlying commodity price at March 31, 2015 would result in a change of $8.5 million in thevalue of our index-price crude oil purchase commitments. (6) At March 31, 2015, we had the following sales contract volumes (in thousands): Natural gas liquids fixed-price (gallons)104,153Natural gas liquids index-price (gallons)223,234Crude oil fixed-price (barrels)1,580Crude oil index-price (barrels)6,684 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. Environmental Legislation Please see Part I, Item 1—“Business—Government Regulation—Greenhouse Gas Regulation” for a discussion of proposed environmentallegislation and regulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure oroutcome of any future legislation or regulations or the eventual cost we could incur in compliance. Trends Crude oil prices can fluctuate widely based on changes in supply and demand conditions. The opportunity to generate revenues in our crude oillogistics business is heavily influenced by the volume of crude oil being produced. Crude oil prices declined sharply during the nine months endedMarch 31, 2015 (the spot price for NYMEX West Texas Intermediate crude oil at Cushing, Oklahoma declined from $105.34 per barrel at July 1, 2014 to$47.60 per barrel at March 31, 2015). While crude oil production in the United States has been strong in recent years, the sharp decline in crude oil prices hasreduced the incentive for producers to expand production. If crude oil prices remain low, resultant declines in crude oil production may adversely impactvolumes in our crude oil logistics business. As of March 31, 2015, crude oil markets were in contango (a condition in which the forward crude price is greater than the spot price). During mostof the last two years, crude oil markets were backwardated (a condition in which the forward crude oil price is lower than the spot price). Our crude oillogistics business benefits when the market is in contango, as increasing prices result in inventory holding gains during the time between when we purchaseinventory and when we sell it. In addition, we are able to better utilize our storage assets when crude oil markets are in contango. Our opportunity to generate revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areaswhere our facilities are located. As described above, crude oil prices declined sharply during the year ended March 31, 2015. At current market prices,producers may reduce drilling activity, which could have an adverse impact on the volumes of our water solutions business. A portion of the revenues of our water solutions business are generated from the sale of crude oil that we recover in the process of treating thewastewater. Because of this, lower crude prices result in lower per barrel revenues for our water solutions business. Recent Accounting Pronouncements In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Simplifying thePresentation of Debt Issuance Costs.” ASU No. 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct deduction from thecarrying amount of that debt liability. The ASU is effective for the Partnership for both annual and interim periods beginning April 1, 2016 and requiresretrospective application for all prior periods presented. Early adoption of this ASU is permitted for financial statements that have not been previously issued.We plan to adopt this ASU effective March 31, 2016, at which time we will begin presenting debt issuance costs as a reduction to long-term debt, rather thanas an intangible asset. 94Table of Contents In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” ASU No. 2014-09 will replace most existing revenuerecognition guidance in GAAP. The core principle of this ASU is that an entity should recognize revenue for the transfer of goods or services equal to theamount that it expects to be entitled to receive for those goods or services. The ASU is effective for the Partnership beginning April 1, 2017, and allows forboth full retrospective and modified retrospective (with cumulative effect) methods of adoption. We are in the process of determining the method of adoptionand assessing the impact of this ASU on our consolidated financial statements. 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 haveidentified the following accounting policies that are most important to the portrayal of our financial condition and results of operations. The application ofthese accounting policies, which requires subjective or complex judgments regarding estimates and projected outcomes of future events, and changes inthese accounting policies, could have a material effect on our consolidated 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 terminaling, transportation, storage and service revenues at the time the service is performed, and we record tank and other rentalsover the term of the lease. Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of productgained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Such measurementdifferentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale ofthe product gained. Revenues for our water solutions segment are recognized upon receipt of the wastewater at our treatment and 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 our consolidated statements of operations. We enter into certain contracts whereby we agree to purchase product from a counterparty and 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, werecord the revenues for these transactions net of cost of sales. Impairment of Long-Lived Assets Goodwill is subject to at least an annual assessment for impairment. We perform our annual assessment of impairment during the fourth quarter ofour fiscal year, and more frequently if circumstances warrant. For purposes of goodwill impairment testing, assets are grouped into “reporting units”. Areporting unit is either an operating segment or a component of an operating segment, depending on how similar the components of the operating segmentare to each other in terms of operational and economic characteristics. We concluded that each of our operating segments represented one reporting unit. Ouroperating segments, and the reportable segments within which they are included, are listed below: Operating SegmentReportable SegmentCrude Oil LogisticsCrude Oil LogisticsWater SolutionsWater SolutionsLiquids—Tulsa-based OperationsLiquidsLiquids—Denver-based OperationsLiquidsRetail—EastRetail PropaneRetail—WestRetail PropaneRefined Products and RenewablesRefined Products and Renewables Our first step in performing the annual goodwill impairment analysis is to perform a qualitative assessment of each reporting unit to assess whether itis more likely than not that the fair value of each reporting unit is greater than the book value of the reporting unit. For the crude oil logistics, liquids, retail,and refined products and renewables segments, our qualitative assessments indicated that it was more likely than not that the fair values for each of thesereporting units exceeded their book values, and therefore no further impairment testing was required. In preparing this analysis, we considered marketconditions in our liquids, retail, and refined products and renewables businesses, which have remained stable, our historic operating results, and our long-term expectations for 95Table of Contents these reporting units. We also considered that although a sharp decline in crude oil prices during the second half of calendar year 2014 had an adverse impacton our crude oil logistics segment gross margin and operating results, by January 1, 2015 crude oil forward prices were in contango (a condition in whichforward prices are higher than spot prices), which we expect will benefit the profitability of the crude oil logistics reporting unit, as it enables us to realizeincreased revenues and margin from our crude oil terminal storage assets. We also considered margins and operating results related to our Grand Mesa crudeoil pipeline, which has ship-or-pay volume commitments from multiple shippers and is currently under construction and expected to commence service in thesecond half of calendar year 2016. Because a significant component of our water solutions revenue and operating results is determined by the price at which we are able to sell crudeoil condensate that is recovered from the disposal water and solids delivered to our disposal sites, and crude oil prices declined significantly during thesecond half of calendar year 2014, we performed a quantitative goodwill impairment assessment for our water solutions reporting unit. We performed our goodwill impairment test and estimated the fair value of our water solutions reporting unit based on the income approach, alsoknown as the discounted cash flow method which utilizes the present value of cash flows to estimate the fair value. The future cash flows of our watersolutions reporting unit were projected based upon estimates as of the test date of future revenues, operating expenses and cash outflows necessary to supportthese cash flows, including working capital and maintenance capital expenditures. We also considered expectations regarding expected disposal volumes,which have continued in spite of the lower crude oil price environment as oilfield producers have focused on their most productive properties and havecontinued to deliver disposal volumes to our facilities, and the crude oil pricing environment as reflected in crude oil forward prices as of the test date. Inperforming the discounted cash flow analysis, we utilized our internal fiscal year 2016 cash flow projections prepared as part of our annual budgetingprocess. Consistent with observed disposal volume trends, the budgeted disposal volumes were based on an expectation that existing crude oil and naturalgas production by our customers will continue, with limited disposal volume growth from development of new producing wells by our customers. Forfiscal years 2016 to 2020, we projected the selling price of recovered crude oil based on crude oil forward prices as of our test date, January 1, 2015. For otheroperating income and expenses for years beyond fiscal year 2016, we assumed a 2% long-term growth rate in operating income, which is lower than our long-term expectations and our actual historic growth rate, and reflects our expectation for long-term growth in oilfield production and long-term inflation. Thediscount rates used in our discounted cash flow method were based upon on a weighted average cost of capital of industry peers as determined by third partyvaluation consultants in connection with recent business combinations, adjusted for specific reporting unit risks, which included the level of customercontractual commitments, the level of tangible investment and technological expertise, and the related uncertainty of achieving our budgeted cash flows. Aterminal value was applied to the final year of projected cash flows projecting our expectations for stable long-term growth. We then calculated the presentvalue of the discounted discrete and terminal value cash flows to arrive at an estimate of fair value under the income approach. The discounted cash flowresults indicated that the estimated fair value of our water solutions reporting unit was greater than its book value at January 1, 2015. We supplemented this analysis with a market value analysis, in which we compared the book value of the long-lived assets at January 1, 2015 to thefiscal year 2016 forecasted earnings before interest, taxes, depreciation, and amortization expense, which we believe is consistent with calculations oftenconsidered by market participants when negotiating the price to be paid for the acquisition of similar businesses. We believe the resulting multiple isreasonably less than the amount that a market participant would be expected to pay, including the following considerations: · The size of the asset portfolio and its geographic diversity; · The technological capabilities of the Wyoming processing facility, which we believe could be replicated at other locations if future state orfederal laws and regulations require more water to be recycled or discharged; · Forward crude prices in fiscal years 2017 to 2020 are higher than forward prices in fiscal year 2016; and · Our solids disposal business, which began in fiscal year 2015 and which earns higher margins and which we expect will enhance the long-termcash flows of our water solutions business. Finally, we compared our combined estimates of fair value for all of our segments to our total market capitalization as of January 1, 2015, withoutconsidering a control premium. Based upon the analyses performed, we concluded that our water segment did not fail step one of the goodwill impairmenttest, and the estimated fair value for each our reporting units exceeded its respective carrying value and that the goodwill assigned to each reporting unit wasnot impaired. We evaluate property, plant and equipment and amortizable intangible assets for potential impairment when events and circumstances warrant sucha review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of theasset group is less than its carrying value. We evaluate equity method investments for impairment when we believe the current fair value may be less than the carrying amount. We 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 orderto determine 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 theestimated fair value of the asset retirement obligation. These 96Table of Contents estimates and assumptions are very subjective and can vary over time. We have recorded a liability of $3.9 million at March 31, 2015. This liability is relatedto facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activitieswhen 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 certainother assets. 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. Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment Depreciation expense represents the systematic write-off of the cost of our property, plant and equipment, net of residual or salvage value (if any), tothe results of operations for the quarterly and annual periods during which the assets are used. We depreciate the majority of our property, plant andequipment using the straight-line method, which results in us recording depreciation expense evenly over the estimated life of the individual asset. Theestimate of depreciation expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. At the time weacquire and place our property, plant and equipment in service, we develop assumptions about the useful economic lives and residual values of such assetsthat we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which wouldchange our depreciation expense prospectively. Examples of such circumstances include changes in laws and regulations that limit the estimated economiclife of an asset, changes in technology that render an asset obsolete, or changes in expected salvage values. Amortization of Intangible Assets Amortization expense represents the systematic write-off of the cost of our amortizable intangible assets to the results of operations for the 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 usrecording 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 useful economic lives of suchassets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, whichwould change our amortization expense prospectively. Examples of such circumstances include changes in customer attrition rates and changes in laws andregulations that could limit the estimated economic life of an asset. Tank Bottoms Storage tanks require a certain minimum amount of product to remain in the tank as long as the tank is in service. This product is known as “tankbottoms.” We report tank bottoms we own in storage facilities we own at historical cost within property, plant and equipment on our consolidated balancesheets. The following table summarizes the tank bottoms reported in our consolidated balance sheet at March 31, 2015 (in thousands): BookProductVolume ValueGasoline (barrels)219$25,710Crude oil (barrels)18416,835Diesel (barrels)12415,153Renewables (barrels)414,220Other504738Total$62,656 Linefill We have entered into long-term commitments to ship specified minimum volumes of crude oil on certain third-party owned pipelines. Theseagreements require that we maintain a certain minimum amount of crude oil in the pipeline to serve as linefill over the duration of the agreement. We reportsuch linefill at historical cost within other noncurrent assets on our consolidated balance sheets. At March 31, 2015, linefill consisted of 487,104 barrels ofcrude oil with a book value of $35.1 million. 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 acquisition date 97Table of Contents fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent thirdparty to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in theallocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. Theestimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include thefair value of contracts including commodity purchase and sale agreements, storage and transportation contracts, and employee compensation commitments.The excess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but isreviewed annually for impairment. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the informationnecessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. The impact of subsequent changesto the identification of assets and liabilities may require retrospective adjustments to our previously reported consolidated financial position and results ofoperations. Inventories Our inventories consist 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 inventories at the lower of cost or market, with cost determined using eitherthe weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. Market is determined based on estimatedreplacement cost using prices at the end of the reporting period. At the end of each fiscal year, we also perform a “lower of cost or market” analysis; if the costbasis of the inventories would not be recoverable based on market prices at the end of the year, we reduce the book value of the inventories to the recoverableamount. In performing this analysis, we consider fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesaleliquids business to our retail propane business to sell the inventory in retail markets. When performing this analysis during interim periods within a fiscalyear, accounting standards do not require us to record a lower of cost or market write-down if we expect the market values to recover by our fiscal year end ofMarch 31. We are unable to control changes in the market value of these commodities and are unable to determine whether write-downs will be required infuture periods. In addition, write-downs at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscalyear end. Equity-Based Compensation Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. These units vest in tranches,subject to the continued service of the recipients. We record the expense for the first tranche of each award on a straight-line basis over the period beginning with the grant date of the awards 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 ofdistribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make aboutfuture distribution growth. We report unvested units as liabilities in 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 A significant portion of our long-term debt is variable-rate debt. Changes in interest rates impact the interest payments of our variable-rate debt butgenerally do not impact the fair value of the liability. Conversely, changes in interest rates impact the fair value of the fixed-rate debt but do not impact itscash 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 31,2015, we had $1.4 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.18%. A change in interest rates of 0.125% wouldresult in an increase or decrease of our annual interest expense of $1.7 million, based on borrowings outstanding at March 31, 2015. 98Table of Contents The TLP Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31, 2015,TLP had $250.0 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.67%. A change in interest rates of 0.125% would result in anincrease or decrease in TLP’s annual interest expense of $0.3 million, based on borrowings outstanding at March 31, 2015. Commodity Price and Credit Risk Our operations are subject to certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the marketvalue of crude oil, natural gas liquids, and refined products will change, either favorably or unfavorably, in response to changing market conditions. Creditrisk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. 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 senior management and to marketing operations personnel.Credit risk is monitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit and entering into nettingagreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. The principalcounterparties associated with our operations at March 31, 2015 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 various types of forward contracts and financial derivative transactions to reduce the effect of price volatility on our product costs, toprotect the value of our inventory positions, and to help ensure the availability of product during periods of short supply. We attempt to balance ourcontractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. We may experiencenet unbalanced positions from time to time. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, onan ongoing basis, to track and report the market value of our derivative portfolio. Although we use financial derivative instruments to reduce the market price risk associated with forecasted transactions, we do not account forfinancial derivative transactions as hedges. We record the changes in fair value of these financial derivative transactions within cost of sales. The followingtable summarizes the hypothetical impact on the March 31, 2015 fair value of our commodity derivatives of an increase of 10% in the value of theunderlying commodity (in thousands): Increase(Decrease)To Fair ValueCrude oil (crude oil logistics segment)$(4,992)Crude oil (water solutions segment)(1,813)Propane (liquids segment)484Other products (liquids segment)65Refined products (refined products and renewables segment)(22,831)Renewables (refined products and renewables segment)(936) Fair Value We use observable market values for determining the fair value of our derivative 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. 99Table of Contents 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, ourindependent registered public accounting firm, are incorporated by reference into this Item 8. Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure None. Item 9A. Controls and Procedures Evaluation of Disclosure Controls and Procedures We maintain disclosure controls and procedures, as defined in Rule 13(a)-15(e) and 15(d)-15(e) of the Securities Exchange Act of 1934, as amended(the “Exchange Act”), that are designed to provide reasonable assurance that information required to be disclosed in our filings and submissions under theExchange Act is recorded, processed, summarized and reported within the periods specified in the rules and forms of the Securities and ExchangeCommission (“SEC”) and that such information is accumulated and communicated to our management, including the principal executive officer andprincipal financial officer of our general partner, as appropriate, to allow timely decisions regarding required disclosure. We completed an evaluation under the supervision and with participation of our management, including the principal executive officer andprincipal financial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures at March 31, 2015.Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31, 2015, suchdisclosure controls and procedures were effective to provide the reasonable assurance described above. Changes in Internal Control Over Financial Reporting Other than changes that have resulted or may result from our acquisitions during the year ended March 31, 2015, as discussed below, there havebeen no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) of the Exchange Act) during the three months endedMarch 31, 2015 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. We acquired TransMontaigne LLC (“TransMontaigne”) (formerly TransMontaigne Inc.) and certain related operations in July 2014, as described inNote 4 to our consolidated financial statements included in this Annual Report on Form 10—K (“Annual Report”). At this time, we continue to evaluate thebusiness and internal controls and processes associated with TransMontaigne and are making various changes to its operating and organizational structurebased on our business plan. We are in the process of implementing our internal control structure over this acquired business. We expect that our evaluationand integration efforts related to those operations will continue into future fiscal quarters. Management’s Report on Internal Control Over Financial Reporting The management of our Delaware limited partnership (the “Partnership”) and subsidiaries is responsible for establishing and maintaining adequateinternal control over financial reporting, as such term is defined in Exchange Act Rule 13(a)-15(f). Under the supervision and with the participation of ourmanagement, including the Chief Executive Officer and Chief Financial Officer of our general partner, we conducted an evaluation of the effectiveness of ourinternal control over financial reporting based on the framework in the 2013 Internal Control—Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission, or the COSO framework. As permitted by SEC rules, we have excluded the refined products marketing operations of TransMontaigne and certain related operations from ourevaluation of the effectiveness of internal control over financial reporting for the year ended March 31, 2015 due to their size and complexity and the limitedtime available to complete the evaluation. The operations excluded from our evaluation represent 9% of our total assets at March 31, 2015, and 23% of ourtotal revenues for the year ended March 31, 2015. We have not excluded TransMontaigne Partners L.P. (“TLP”) from our evaluation of the effectiveness ofinternal control over financial reporting for the year ended March 31, 2015, as TLP is a publicly traded limited partnership that is responsible for establishingand maintaining adequate internal control over financial reporting. Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective atMarch 31, 2015. 100Table of Contents Our internal control over financial reporting at March 31, 2015 has been audited by Grant Thornton LLP, an independent registered public accountingfirm, as stated in their report, which appears in Part IV, Item 15—“Exhibits and Financial Statement Schedules” in this Annual Report. Item 9B. Other Information None. 101Table 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.Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. The NGL EnergyGP Investor Group appoints all members to the board of directors of our general partner. The board of directors of our general partner currently has ten members. The board of directors of our general partner has determined that Mr. Kneale,Mr. Cropper, and Mr. Collingsworth satisfy the New York Stock Exchange (“NYSE”) and SEC independence requirements. The NYSE does not require alisted publicly traded limited partnership like us to have a majority of independent directors on the board of directors of our general partner. In addition, weare 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. 102Table 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 executiveofficers. NameAge Position with NGL Energy Holdings LLCH. Michael Krimbill61Chief Executive Officer and DirectorAtanas H. Atanasov42Chief Financial Officer and TreasurerJames J. Burke59President and DirectorShawn W. Coady53President and Chief Operating Officer, Retail Division and DirectorVincent J. Osterman58President, Eastern Retail Propane Operations and DirectorJames M. Collingsworth60DirectorStephen L. Cropper65DirectorBryan K. Guderian55DirectorJames C. Kneale63DirectorJohn T. Raymond44DirectorPatrick Wade45Director 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. Krimbill was the President and Chief Financial Officer of Energy Transfer Partners, L.P. from 2004 until his resignation in January 2007. Mr. Krimbilljoined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as Vice President and Chief Financial Officer in 1990. Mr. Krimbillwas President of Heritage Propane Partners, L.P. from 1999 to 2000 and President and Chief Executive Officer of Heritage Propane Partners, L.P. from 2000 to2005. 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,Williams Partners L.P. from 2007 to September 2012, and Pacific Commerce Bank from January 2011 to March 2015. 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. Mr. Krimbill’s experience serving on other publiccompany boards is also a valuable asset to our board of directors. 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, Mr. Atanasov was with The Williams Companies, Inc. Mr. Atanasov currently serveson the board of directors of TransMontaigne Partners L.P. Mr. Atanasov is a CPA and holds an M.B.A. from the University of Tulsa and a B.S. in Accountingfrom Oral Roberts University. James J. Burke. Mr. Burke serves as our President and joined the board of directors of our general partner in 2012. Mr. Burke was a co-founder ofHigh Sierra Energy, LP and High Sierra Energy GP, LLC (“High Sierra”) and served as Chairman of the High Sierra board and President and Chief ExecutiveOfficer of the High Sierra general partner since September 2010. From July 2004 to September 2010, Mr. Burke was the Managing Director of High Sierra’sgeneral partner. Mr. Burke, along with three other entrepreneurs, co-founded Petro Source Partners, LP, where he ran six business units throughout the UnitedStates and Canada for the company over a 17-year span. Prior to that, Mr. Burke served as Manager of Crude Oil Acquisitions at Asamera Oil (United States)Inc. from 1981 to 1984. Mr. Burke began his career as a Crude Oil Representative at Permian Corporation, where he worked from 1978 to 1981. Mr. Burkealso serves as the Managing Director of Impact Energy Services, LLC. Mr. Burke received his B.S. from University of Colorado in 1978. Shawn W. Coady. Dr. Coady has served as our President and Chief Operating Officer, Retail Division, since April 2012 and previously served as ourCo-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 served as an officer of Hicks Oils & Hicksgas, Incorporated (“HOH”), fromMarch 1989 to September 2010 when HOH contributed its propane and propane related assets to Hicks LLC, and the membership interests in Hicks LLC werecontributed to us as part of our formation transactions. Dr. Coady was an executive officer of Bachtold Brothers, Incorporated, a family owned company,when it 103Table of Contents filed for Chapter 7 bankruptcy protection in October 2005. Dr. Coady was also the President of Gifford from March 1989 until the membership interests inGifford were contributed to us as part of our formation transactions. Dr. Coady has served as a director and as a member of the executive committee of theIllinois Propane Gas Association from 2004 to March 2015. Dr. Coady has also served as the Illinois state director of the National Propane Gas Associationfrom 2004 to March 2015. Dr. Coady has a B.A. in Chemistry from Emory University and an O.D. from the University of Houston. Dr. Coady is the brother ofMr. 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. 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 Energi Holdings, Inc. and on the Board of Advisorsof 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. James M. Collingsworth. Mr. Collingsworth has served on our board of directors since January 2015. Mr. Collingsworth previously served as aSenior Vice President of the general partner of Enterprise Products Partners L.P. from November 2001 through September 2012. Prior to that,Mr. Collingsworth served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991 to2001 in various management positions, including Senior Vice President of NGL Assets and Business Services from July 1998 to October 2001. Prior tojoining Texaco, Mr. Collingsworth was director of feedstocks for Rexene Petrochemical Company from 1988 to 1991 and served in the MAPCO, Inc.organization from 1973 to 1988 in various capacities, including customer service and business development manager of the Mid-America and Seminolepipelines. Mr. Collingsworth currently serves on the board of directors of Martin Midstream Partners L.P. Mr. Collingsworth brings a wealth of in-depthindustry experience to the Partnership. Mr. Collingsworth has worked in all facets of the midstream and petrochemical industry for more than 40 years. Stephen L. Cropper. Mr. Cropper joined the board of directors of our general partner in June 2011. Mr. Cropper held various positions during his 25-year career at The Williams Companies, Inc., including serving as the President and Chief Executive Officer of Williams Energy Services, a 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., Berry Petroleum Company, and Rental Car Finance Corp., a subsidiary of DollarThrifty Automotive Group. Mr. Cropper currently serves on the board of directors of QuikTrip Corporation and Wawa Inc. 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 a directorfor other public companies, Mr. Cropper also provides cross board experience. Bryan K. Guderian. Mr. Guderian joined the board of directors of our general partner in May 2012. Mr. Guderian has served as Senior Vice Presidentof Business Development of WPX Energy, Inc. (“WPX”) since October 2014. Mr. Guderian served as Senior Vice President of Operations of WPX fromAugust 2011 to October 2014. Mr. Guderian previously served as Vice President of the Exploration & Production unit of The Williams Companies, Inc. from1998 until August 2011, where he had responsibility for overseeing international operations. Mr. Guderian has served as a director of Apco Oil & GasInternational 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 ofpetroleum industry involvement, the majority of which has been focused in exploration and production. James C. Kneale. Mr. Kneale joined the board of directors of our general partner in May 2011. Mr. Kneale served as President and Chief OperatingOfficer of ONEOK, Inc., from January 2007, and ONEOK Partners, L.P., from May 2008, until his retirement in January 2010. After joining ONEOK in 1981,Mr. Kneale served in various other roles, including Chief Financial Officer from 1999 through 2006. Mr. Kneale also served as a director of ONEOK Partners,L.P. from 2006 until his retirement in January 2010. Mr. Kneale is a former CPA and has a B.B.A. in Accounting in 1973 from West Texas A&M in Canyon,Texas. Mr. Kneale brings extensive executive, financial and operational experience to the board. With nearly 30 years of experience in the natural liquidsgas industry in numerous positions, Mr. Kneale provides valuable insight into our business and industry. 104Table of Contents 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 (“EMG”) of which he has been a Managing Partner and the Chief Executive Officer since its September 2006inception. Mr. Raymond has held executive leadership positions with various energy companies, including President and Chief Executive Officer of PlainsResources Inc. (the predecessor entity of Vulcan Energy Corporation), President and Chief Operating Officer of Plains Exploration and Production Companyand was a Director of Plains All American Pipeline, LP. Mr. Raymond is also currently a director of American Energy Ohio Holdings, LLC, Ferus Inc., Ferus Natural Gas Fuels Inc., Iron Ore Holdings,Lighthouse Oil & Gas GP, LLC, MarkWest Utica EMG, LLC, Medallion Midstream, LLC, Plains All American GP LLC and Tallgrass MLP GP LLC.Mr. Raymond manages various private investments through personally held Lynx Holdings, LLC. Mr. Raymond received a B.S.M. from the A.B. FreemanSchool of Business at Tulane University with dual concentrations in finance and accounting and currently sits on the Board of the Business School Council. Patrick Wade. Mr. Wade served as a member of the High Sierra board beginning in November 2008 and as a member of the board of directors of ourgeneral partner since 2012. Mr. Wade has 20 years of experience in the energy sector. In 2002, Mr. Wade co-founded Tiger Midstream Investments, a naturalgas 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 EMG, as a Managing Director in the Houston office. EMG is the management company for a series ofspecialized private equity funds. EMG focuses on investing across various facets of the global natural resource industry including the upstream andmidstream segments of the energy complex. EMG is the managing partner of EMG NGL HC LLC. Mr. Wade’s primary focus is making direct investmentsacross the natural resources industry. Mr. Wade served as a director of MarkWest Liberty Midstream & Resources from 2009 through 2011. In addition,Mr. Wade serves on the board of directors of Medallion Midstream, L.L.C., Ferus Inc., and Lodestar Energy Group, LLC. Mr. Wade received his Bachelor’sdegree 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 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. 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 investors whoformed the Partnership (“IEP Parties”) (which consists of certain entities controlled by H. Michael Krimbill, and two other investors, one of whom is anemployee of the Partnership) each have the right to designate one person to serve on the board of directors. The Coady Group has designatedShawn W. Coady and the IEP Parties have designated H. Michael Krimbill. Board Leadership Structure and Role in Risk Oversight The board of directors of our general partner believes that whether the offices of chairman of the board and chief executive officer are combined orseparated should be decided by the board, from time to time, in its business judgment after considering relevant circumstances. The board of directors of ourgeneral partner currently does not have a chairman. The 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 ofcompensation programs for our senior management. Each committee regularly reports to the board of directors. Audit Committee The board of directors of our general partner has established an audit committee. The audit committee assists the board in its oversight of theintegrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committeehas the sole authority to, among other things: · retain and terminate our independent registered public accounting firm; 105Table of Contents · approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm; and · establish policies and procedures for the pre-approval of all non-audit services and tax services to be rendered by our independent registeredpublic accounting firm. The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Ourindependent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary. Mr. Collingsworth, Mr. Cropper, and Mr. Kneale currently serve on the audit committee, and Mr. Kneale serves as the chairman. The board ofdirectors of our general partner has determined that Mr. Kneale is an “audit committee financial expert” as defined under SEC rules and that each member ofthe audit committee is financially literate. In compliance with the requirements of the NYSE, all of the members of the audit committee are independentdirectors, as defined in the applicable NYSE rules. Compensation Committee The board of directors of our general partner has established a compensation committee. The compensation committee’s responsibilities include thefollowing, among others: · establishing the general partner’s compensation philosophy and objectives; · approving the compensation of the Chief Executive Officer; · making recommendations to the board of directors with respect to the compensation of other officers and directors; and · reviewing and making recommendations to the board of directors with respect to incentive compensation and equity-based plans. Mr. Cropper, Mr. Guderian, 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. 106Table of Contents To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations by our directors and officers, webelieve that all reporting obligations of our general partner’s directors and officers and our greater than 10% unitholders under Section 16(a) were satisfiedduring the year ended March 31, 2015, except as described in the table below. Number of TransactionsAverageReportable Event Name of Filer Reported LateDelay (1)Sale of unitsDavid C. Kehoe13 daysVincent J. Osterman41 day Restricted units net settled for income tax withholdingAtanas H. Atanasov210 daysJames J. Burke118 daysShawn W. Coady210 daysTodd M. Coady210 daysJeffrey A. Herbers210 daysDavid C. Kehoe118 daysVincent J. Osterman210 days Conversion of subordinated units to common unitsShawn W. Coady12 daysTodd M. Coady12 daysH. Michael Krimbill13 days Grant of unvested restricted units under compensation programsAtanas H. Atanasov114 daysShawn W. Coady114 daysTodd M. Coady114 daysJeffrey A. Herbers114 daysVincent J. Osterman114 days (1) Represents the average number of business days by which the filing deadlines were missed. 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 InvestorRelations at investorinfo@nglep.com or to Investor Relations, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136 ormade by telephone at (918) 481-1119. The information contained on, or connected to, our website is not incorporated by reference into this Annual Reportand should not be considered part of this or any other report that we file with or furnish to the SEC. Meeting of Non-Management Directors and Communications with Directors At each quarterly meeting of the audit committee and/or the board of directors of our general partner, our independent directors meet in an 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, 107Table of Contents committee or director to the attention of our Secretary at the following address: Name of the Director(s), c/o Secretary, NGL Energy Partners LP, 6120 SouthYale Avenue, Suite 805, Tulsa, Oklahoma 74136. Communications are distributed to the board, committee, or director as appropriate, depending on the factsand circumstances outlined in the communication. Item 11. Executive Compensation Compensation Discussion and Analysis The year “2015” in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2015. Introduction The board of directors of our general partner has responsibility and authority for compensation-related decisions for our executive officers. Theboard of directors has formed a compensation committee to develop our compensation program, to determine the compensation of our Chief ExecutiveOfficer, and to make recommendations to the board of directors regarding the compensation of our other executive officers. Our executive officers are alsoofficers of our operating companies and are compensated directly by our operating companies. While we reimburse our general partner and its affiliates for allexpenses 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 year 2015 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 · Vincent J. Osterman—President, Eastern Retail Propane Operations 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.We believe this pay-for-performance approach generally aligns the interests of our executive officers with the interests of our unitholders, and at the sametime enables us to maintain a lower level of cash compensation expense in the event our operating and financial performance do not meet our expectations. Our executive compensation program is designed to provide a total compensation package that allows us to: · Attract and retain individuals with the background and skills necessary to successfully execute our business strategies; · Motivate those individuals to reach short-term and long-term goals in a way that aligns their interests with the interests of our unitholders; and · Reward success in reaching those goals. Recent Achievements Our compensation structure is designed to reward our officers for achieving above-market returns for our unitholders. Our achievements during theyear ended March 31, 2015 included the following: · Significantly expanded our refined products and renewables segment through the acquisition of TransMontaigne and related operations; 108Table of Contents · Completed a successful open season and began construction of Grand Mesa to transport crude oil from Weld County, Colorado to Cushing,Oklahoma; · Acquired a strategically-located natural gas liquids salt dome storage facility in Utah; and · Increased our distribution from $0.5513 per common unit in May 2014 to $0.6250 per common unit in May 2015 (an increase of over 13%). Compensation Highlights · We paid no cash bonuses to our named executive officers during fiscal year 2015. · The salaries of most of our named executive officers remain below the median of our benchmark peer group. This enables us to grant moreperformance-based compensation to maintain competitive total compensation packages. · We introduced a new performance-based restricted unit program for which no payout will be made unless the return on our common units exceededthe median returns for a specified peer group over specified periods of time. 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; · Certain of the officers’ equity awards are subject to achievement of above-median total unitholder return relative to our performance peer group; · No excise tax gross-ups; and · Compensation committee engages an independent compensation adviser. 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 year 2015, the compensation committee received compensation advice and data from PearlMeyer & Partners (“PM&P”). PM&P conducted a competitive review of the principal components of compensation for our executives, includingour named executive officers. PM&P also provided input on peer group selection (compensation and performance peers), and short and long-term incentive plan design. The compensation committee reviewed the services provided by PM&P and determined that they are independent inproviding executive compensation consulting services. In making this determination, the compensation committee noted that during fiscal year2015: · PM&P did not provide any services to the Partnership or management other than compensation consulting services requested by orwith the approval of the compensation committee; · PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or humanresource outsourcing; · PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and proceduresdesigned to ensure independence; 109Table of Contents · Fees paid to PM&P by the Partnership during fiscal year 2015 were less than 1% of PM&P’s total revenue; · None of the PM&P consultants working on Partnership matters had any business or personal relationship with compensationcommittee members; · None of the PM&P consultants working on Partnership matters (or any consultants at PM&P) had any business or personal relationshipwith any executive officer of the Partnership; and · None of the PM&P consultants working on Partnership matters own Partnership interests. The compensation committee continues to monitor the independence of its compensation consultant on a periodic basis. The compensationcommittee considered the recommendations provided by PM&P in the process of designing the fiscal year 2015 compensation program. Elements of Executive Compensation As part of our pay-for-performance approach to executive compensation, the compensation of our executive officers includes a significantcomponent of 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 forPerformanceUnitholderAlignment Base Salary·Fixed income to compensateexecutive officers for their levelof responsibility, expertise andexperience·Based on competition in themarketplace for executive talentand abilitiesX Cash Bonus Awards· Rewards achievement of specificannual financial and operationalperformance goals·Based on the named executiveofficer’s relative contribution toachieving or exceeding annualgoalsXXX·Recognizes individualcontributions to our performance Long-Term EquityIncentive Awards·Motivates and rewards theachievement of long-termperformance goals, includingincreasing the market price of ourcommon units and the quarterlydistributions to our unitholders·Based on the named executiveofficer’s expected contribution tolong-term performance goalsXXX·Provides a forfeitable long-termincentive to encourage executiveretention 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 initial base salary of $120,000 was originally determined as part of the negotiations for our formation transactions. In setting thebase salaries, the parties considered various factors, including the compensation needed to attract or retain the officers, the historicalcompensation of the officers, and each officer’s expected individual contribution to our performance. At the request of Mr. Krimbill, the partiesagreed that he should receive a lower base salary than our other executive officers at the time because, as our Chief Executive Officer, asignificant portion of his compensation should be performance-based, to further align his interests with the interests of our unitholders. InFebruary 2012, the base salary of Mr. Krimbill was reduced to $60,000, based on our operating and financial performance as a result of anunusually warm winter. The base salary of Mr. Krimbill was restored to $120,000 effective November 12, 2012. Effective July 1, 2014, theBoard of Directors increased Mr. Krimbill’s salary to $350,000, in 110Table of Contents consideration of the fact that his salary was low relative to the benchmark peer group (and remains below the 25 percentile of the peer group). · Mr. Atanasov’s base salary of $195,000 was negotiated prior to his joining our management team in November 2011. The base salary ofMr. Atanasov was increased to $250,000 in July 2013 and to $300,000 in July 2014, in consideration of the fact that his salary was low relativeto the benchmark peer group. · Mr. Burke’s base salary of $353,000 became effective on June 19, 2012 when Mr. Burke joined our management team upon completion of ourmerger with High Sierra. Mr. Burke’s base salary was increased to $375,000 in July 2013 and to $384,000 in June 2014. Mr. Burke was given alower salary increase than the other named executive officers, based on the fact this his salary is higher relative to the benchmark peer groupthan the other named executive officers (his current salary is close to the 50 percentile of the peer group). · Dr. Coady’s base salary of $300,000 was determined as part of the negotiations for our formation transactions. In February 2012, the base salaryof Dr. Coady was reduced to $200,000 based on our operating and financial performance as a result of an unusually warm winter. The basesalary of Dr. Coady was restored to $300,000 effective November 12, 2012. Dr. Coady’s base salary was increased to $315,000 in July 2014, inconsideration of the fact that his salary was low relative to the benchmark peer group. · Mr. Osterman’s initial base salary of $125,000 was negotiated at the time Mr. Osterman joined our management team upon completion of ouracquisition of Osterman Propane. Mr. Osterman’s salary was increased to $200,000 in January 2013 and to $250,000 in July 2013, inconsideration of the fact that his salary was low relative to the benchmark peer group. Cash Bonus Awards No cash bonuses were paid to the named executive officers during fiscal year 2015. None of the named executive officers is subject to a formal cashbonus plan, and any cash bonuses are at the discretion of the Compensation Committee or the Board of Directors, (in the case of Mr. Krimbill) or theCompensation Committee (in the case of the other named executive officers). Long-Term Equity Incentive Awards Certain restricted units granted to the named executive officers vest in tranches, contingent only on the continued service of the recipient throughthe vesting date (the “Service Awards”). Grants of Service Award units to the named executive officers are summarized below: TotalUnvested Units Units Granted Units Vested Unvested Unitsat March 31, 2014 in July 2014 in March 2015 in Fiscal Year 2015 at March 31, 2015Atanas H. Atanasov32,0007,00024,000(27,000)36,000James J. Burke40,000—25,000(20,000)45,000Shawn W. Coady10,0007,00045,000(17,000)45,000Vincent J. Osterman10,0007,00045,000(17,000)45,000 The vesting dates of the unvested Service Award units at March 31, 2015 are summarized below: TotalService Award Units by Vesting Date Unvested UnitsJuly 1, 2015July 1, 2016July 1, 2017 at March 31, 2015Atanas H. Atanasov12,00012,00012,00036,000James J. Burke15,00015,00015,00045,000Shawn W. Coady15,00015,00015,00045,000Vincent J. Osterman15,00015,00015,00045,000 111ththTable of Contents The Service Award units granted in July 2014 were intended as discretionary bonuses for performance during fiscal year 2014. Of the Service Awardunits granted in March 2015 to Mr. Atanasov and Mr. Burke, 10,000 of the units were intended as a bonus for performance during fiscal year 2015. NoService Award units were granted to Mr. Krimbill until April 2015, at the request of Mr. Krimbill. The number of Service Award units to be granted was determined by reference to peer groups. Assuming a value of $30 value per unit for thispurpose, the annual Service Award value falls between the 25 and 50 percentile of the peer group for Mr. Burke, Dr. Coady, and Mr. Osterman, and belowthe 25 percentile of the peer group for Mr. Atanasov. Fiscal Year 2016 Awards During April 2015, the board of directors granted certain Service Award units to Mr. Krimbill, which will vest in tranches of 71,191 each on July 1,2015, July 1, 2016, and July 1, 2017. The number of award units was calculated based on the median value of equity award units granted to chief executiveofficers in the benchmark peer group. During April 2015, the Partnership granted awards that are contingent both on the continued service of the recipients through the vesting date andalso on the performance of our common units relative to the performance of other entities in the Alerian MLP Index (the “Index”) over specified periods oftime (the “Performance Awards”). The maximum number of units that could vest on the Performance Awards granted to each named executive officer issummarized below: Maximum Performance Award Units by Vesting Date July 1, 2015July 1, 2016July 1, 2017 TotalH. Michael Krimbill142,382142,382142,382427,146Atanas H. Atanasov24,00024,00024,00072,000James J. Burke30,00030,00030,00090,000Shawn W. Coady30,00030,00030,00090,000Vincent J. Osterman30,00030,00030,00090,000 The number of Performance Award units that will vest is contingent on the performance of our common units relative to the performance of the otherentities in the Index. Performance will be calculated based on the return on our common units (including changes in the market price of the common unitsand distributions paid during the performance period) relative to the returns on the common units of the other entities in the Index. Performance will bemeasured over the following periods: Vesting Date of Tranche Performance Period for TrancheJuly 1, 2015July 1, 2012 through June 30, 2015July 1, 2016July 1, 2013 through June 30, 2016July 1, 2017July 1, 2014 through June 30, 2017 The percentage of the maximum Performance Award units that will vest will depend on the percentage of entities in the Index that NGL outperforms,as summarized in the table below: Percentage of MaximumPerformance Relative to Index Performance Award Units to VestLess than 50th percentile0%50th—75th percentile25%–50%75th—90th percentile50%–100%Greater than 90 percentile100% The Performance Award units were determined in consideration of the fact that the base salaries and the service-based equity awards for the namedexecutive officers are in most cases below the median value for officers in their respective peer groups. The compensation committee believes that if theperformance of NGL’s common units falls below the median performance of the Index, the named executive officers should receive lower compensation thantheir peers, but that if the performance of NGL’s common units exceeds the median of the Index, the compensation of the named executive officers should beincreased. Under the provisions of Accounting Standards Codification (“ASC”) 718, the grant date for the Performance Award units was in April 2015, as theperformance metrics were not finalized and communicated to the recipients until April 2015. As a result, these awards are not listed in the SummaryCompensation Table for fiscal year 2015 below. 112thththTable 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 acceleratethe vesting of the restricted units in the event of a change in control of the Partnership, although it is not under any obligation to do so. 401(k) Plan We have established a defined contribution 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred basis. 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 3.5% of the employee’s contribution that is not in excess of 6% of the employee’seligible compensation (subject to annual Internal Revenue Service contribution limits). Our matching contributions prior to January 1, 2015 vest over 5 yearsand, effective January 1, 2015, our matching contributions vest over 2 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 ratherthan performance. We provide a basic benefits package available to substantially all full-time employees, which includes a 401(k) plan and medical, dental,vision, disability and life insurance. Other Officers Certain officers who have leadership roles within our individual business units, but who are not executive officers, participate in formulaic bonusprograms that are based on the performance of the individual business units with which they are involved. In most cases, similar programs were in place priorto our acquisition of the businesses, and we have left the programs substantially intact. Competitive Review and Fiscal Year 2015 Compensation Program During fiscal year 2015, 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 committeeregarding competitive rates of compensation, PM&P collected pay data from the following sources: · Compensation surveys including data from published compensation surveys representative of other energy industry and broader 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 Mistream 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. As described above, the Compensation Committee considered thisdata in establishing salaries for fiscal year 2015 and in determining the number of Service Award and Performance Award units to grant to the namedexecutive officers. Employment Agreements We do not have employment agreements with any of our named executive officers. 113Table of Contents 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 alimited partnership and we do not meet the definition of a “corporation” subject to deduction limitations under Section 162(m) of the Internal Revenue Codeof 1986, as amended. 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)Bryan K. GuderianJames C. Kneale 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 riskto achieve 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 During fiscal year 2015, Stephen L. Cropper, Bryan K. Guderian, and James C. Kneale served on the Compensation Committee. None of theseindividuals is an employee or an officer of our general partner. As described under Part I, Item 13—“Transactions with Related Persons,” Mr. Guderian is anexecutive officer of WPX, and we entered into certain transactions with WPX during fiscal year 2015. Shawn Coady is an executive officer and a member ofthe board of directors. Dr. Coady also serves on the board of directors of HOH, a family-owned company, and in this capacity Dr. Coady participates in thecompensation setting process of the HOH board of directors. 114Table of Contents Summary Compensation Table for 2015 The following table includes the compensation earned by our named executive officers for fiscal years 2013 through 2015. Restricted All Other Unit Compensation Fiscal Salary Bonus (1) Awards (2) (3) TotalName and Position Year ($) ($) ($) ($) ($)H. Michael Krimbill2015292,500——9,319301,819Chief Executive Officer2014117,693475,000—6,493599,186201382,849——2,49285,341 Atanas H. Atanasov2015287,500—864,6649,3461,161,510Chief Financial Officer2014232,500195,000259,6967,038694,2342013195,000—743,4402,738941,178 James J. Burke (4)2015381,750—602,27026,4671,010,487President2014367,385450,000—24,651842,0362013275,630—836,40013,0151,125,045 Shawn W. Coady2015311,250—1,331,50119,1531,661,904President and Chief Operating2014300,000200,000—19,630519,630Officer, Retail Division2013238,462—613,70017,730869,892 Vincent J. Osterman (5)2015250,000—1,331,50131,7631,613,264President, Eastern Retail Propane Operations (1) Amounts for fiscal year 2014 include discretionary bonuses paid in fiscal year 2014 based on contributions of the individuals since the timethey joined the Partnership through the date of the bonus and based on expectations of future performance. (2) The fair values of the restricted units shown in the table above were calculated based on the closing market prices of our limited partner units onthe grant dates, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. Theimpact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution prior to the grantdate and assumptions that a market participant might make about future distribution growth. This calculation of fair value is consistent with theprovisions of Accounting Standards Codification 718 Stock Compensation. 115Table of Contents (3) The amounts in this column include matching contributions to our 401(k) plan. Amounts for Mr. Burke include a club membership and a carallowance. Amounts for Dr. Coady include the incremental cost of the use of a company car, including depreciation, maintenance, insurance,and fuel. Amounts for Mr. Osterman include propane provided to him and to members of his family (valued for this purpose at the cost of thepropane to NGL). These amounts are summarized in the table below: Fiscal401 (k)CarClubTotal Other Name YearMatchAllowanceMembershipPropaneCompensation James J. Burke2015$9,343$9,000$8,124$—$26,46720147,5279,0008,124—24,65120134,891—8,124—13,015 Shawn W.20159,7969,357——19,153Coady20148,75010,880——19,63020137,15410,576——17,730 Vincent J.Osterman201518,468——13,29531,763 (4) Mr. Burke joined our management team upon completion of our merger with High Sierra on June 19, 2012. (5) Mr. Osterman was not a named executive officer prior to fiscal year 2015. Restricted Unit Awards During fiscal year 2015, the Committee granted awards for which units vest at specified dates, contingent only on the continued service of therecipient through the service date (the “Service Awards”). 2015 Grants of Plan Based Awards Table The number of restricted Service Award units granted to our named executive officers, and their grant date fair values, are summarized below: Grant Date Fair Value of Total Number of Service Award UnitsNameGrant Date Service Award Units ($)H. Michael Krimbilln/a—— Atanas H. AtanasovJuly 24, 20147,000307,090March 30, 201524,000557,574 James J. BurkeMarch 30, 201525,000602,270 Shawn W. CoadyJuly 24, 20147,000307,090March 30, 201545,0001,024,411 Vincent J. OstermanJuly 24, 20147,000307,090March 30, 201545,0001,024,411 The fair value of the restricted Service Award units shown in the table above were calculated based on the closing market price of our limited partnerunits on the grant dates, with adjustments made to reflect the fact that restricted units are not entitled to distributions during the vesting period. We record in our consolidated financial statements the expense for each tranche on a straight-line basis over the period beginning with the vestingof the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through each reporting date using theestimated fair value of the awards at the reporting date. 116Table of Contents Outstanding Equity Awards as of March 31, 2015 The number of unvested Service Award units outstanding at March 31, 2015, and their fair values at March 31, 2015, are summarized below: Fair Value ofNumber of Service Award UnitsUnvested Service Award UnitsThat Have Not Yet Vestedas of March 31, 2015Nameat March 31, 2015($) H. Michael Krimbill——Atanas H. Atanasov36,000944,280James J. Burke45,0001,180,350Shawn W. Coady45,0001,180,350Vincent J. Osterman45,0001,180,350 The fair values of the restricted units shown in the table above were calculated based on the closing market price of our common units at March 31,2015 of $26.23. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. 2015 Option Exercises and Stock Vested During fiscal year 2015, certain of the restricted Service Award units vested. The value of the awards on the vesting date summarized in the tablebelow was calculated based of the closing market price per unit on the vesting dates. Number of Units Value Realized on VestingNameAcquired on Vesting ($) H. Michael Krimbill——Atanas H. Atanasov27,000989,770James J. Burke20,000694,300Shawn W. Coady17,000727,470Vincent J. Osterman17,000727,470 Upon vesting, certain of the named executive officers elected for us to remit payments to taxing authorities in lieu of issuing units. The followingtable summarizes the number of units issued and the number of units withheld for taxes: Number of Units Number of Units Name Issued Withheld Total Atanas H. Atanasov18,1498,85127,000James J. Burke13,3336,66720,000Shawn W. Coady10,5016,49917,000Vincent J. Osterman14,7182,28217,000 Subsequent to vesting, regularly-scheduled distributions were paid on the common units. The following table summarizes the distributions paidduring fiscal year 2015 on the units that vested and were issued during fiscal year 2015: Name DistributionsAtanas H. Atanasov$18,020James J. Burke12,376Shawn W. Coady16,271Vincent J. Osterman23,935 Performance Awards As described under “Long-Term Equity Incentive Awards” in the “Compensation Discussion and Analysis” earlier in this Item 11, the CompensationCommittee has also granted restricted unit awards that are contingent both on the continued service of the recipients through the vesting date and also on theperformance of NGL’s common units relative to the performance of other entities in the Alerian MLP Index (the “Performance Awards”). These PerformanceAward units are not included in the Summary Compensation Table for 2015 and related disclosures above, as the grant date of the Performance Award unitswas in fiscal year 2016. 117Table of Contents Potential Payments upon Termination or Change in Control We do not provide any severance or change of control benefits to our named executive officers. The board of directors has the option to acceleratethe vesting of the restricted units in the event of a change in control of the Partnership, although it is not under any obligation to do so. If the board ofdirectors were to exercise its discretion to accelerate the vesting of restricted units upon a change in control, the value of such units would be the same asreported in the “Outstanding Equity Awards as of March 31, 2015” 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 cash compensationfor his board service: · an annual retainer of $60,000; · an annual retainer of $10,000 for the chairman of the audit committee; and · an annual retainer of $5,000 for each member of the audit committee other than the chairman. In addition, each director who is not an officer or an employee of our general partner has been granted awards of restricted units. In June 2012, suchdirectors were granted restricted units that vested in tranches of 5,000 units each on January 1, 2013, July 1, 2013, and July 1, 2014. In April 2015, suchdirectors were granted restricted units that vest in tranches of 5,000 units each on July 1, 2015, July 1, 2016, and July 1, 2017. All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Eachdirector is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law. Director Compensation for Fiscal Year 2015 The following table summarizes the compensation earned during fiscal year 2015 by each director who is not an officer or employee of our generalpartner or its affiliates: Fees Earned or Restricted Unit Paid in Cash Awards TotalName ($) ($) ($)James M. Collingsworth———Stephen L. Cropper65,000—65,000Bryan K. Guderian65,000—65,000James C. Kneale70,000—70,000 Mr. Collingsworth joined the board of directors in January 2015. He will earn annual fees to be paid in cash of $65,000. These directors did not receive any equity grants under the LTIP during fiscal year 2015. During fiscal year 2013, Mr. Cropper, Mr. Guderian, andMr. Kneale received a grant of unvested units under the LTIP. These units vested in tranches, contingent on the continued service of the directors. Duringfiscal year 2015, a tranche of 5,000 units vested for each of these directors. Subsequent to the vesting, these individuals received distributions of $1.82 oneach of the vested units. During April 2015, the board of directors granted restricted units to the four directors listed above. For each of these directors, the awards will vest intranches of 5,000 each on July 1, 2015, July 1, 2016, and July 1, 2017. 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 summarizes the beneficial ownership, as of May 25, 2015 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; 118Table of Contents · each named executive officer of our general partner; and · all directors and executive officers of our general partner as a group. Common Percentage ofUnits Common UnitsBeneficially BeneficiallyBeneficial OwnersOwned Owned (1)5% or greater unitholders (other than officers and directors):Oppenheimer Funds, Inc. (2)10,304,8359.69%Magnum NGL HoldCo LLC (3)7,396,9736.96%Neuberger Berman Group LLC (4)5,374,7705.05%Directors and officers:Atanas H. Atanasov (5)66,073*James J. Burke (6)326,285*Shawn W. Coady (7)2,502,2312.35%James M. Collingsworth (8)17,000*Stephen L. Cropper (9)40,000*Bryan K. Guderian35,000*James C. Kneale (10)34,500*H. Michael Krimbill (11)1,741,9761.64%Vincent J. Osterman (12)3,931,0953.70%John T. Raymond (13)176,634*Patrick Wade—— All directors and executive officers as a group (11 persons) (14)8,870,7948.34% * Less than 1.0% (1) Based on 106,328,594 common units outstanding at May 25, 2015. (2) 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. This informationrelated to OppenheimerFunds, Inc. is based upon its Form 13G filed with the SEC on February 6, 2015. (3) The mailing address for Magnum NGL HoldCo LLC. is 2603 Augusta, Suite 900, Houston, TX 77057. Magnum NGL HoldCo LLC reportedshared voting and dispositive power with respect to all common units beneficially owned. This information related to Magnum NGL HoldCoLLC is based upon its Form 13G filed with the SEC on February 27, 2015. (4) The mailing address for Neuberger Berman Group LLC is 605 Third Avenue, 41st Floor, New York, NY 10158. Neuberger Berman Group LLCreported shared voting and dispositive power with respect to all common units beneficially owned. This information related to NeubergerBerman Group LLC is based upon its Form 13G filed with the SEC on February 6, 2015. (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. 119Table of Contents (7) Shawn W. Coady owns 71,840 of these common units. SWC Family Partnership LP owns 2,320,391 of these common units. SWC FamilyPartnership LP is solely owned by SWC General Partner, LLC, of which Shawn W. Coady is the sole partner. Shawn W. Coady may be deemedto have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniaryinterest therein. The 2012 Shawn W. Coady Irrevocable Insurance Trust, which was established for the benefit of Shawn W. Coady’s children,owns 110,000 of these common units. Shawn W. Coady may be deemed to have sole voting and investment power over these units, butdisclaims such beneficial ownership except to the extent of his pecuniary interest therein. Shawn W. Coady also owns a 12.27% interest in ourgeneral partner through Coady Enterprises, LLC, of which he owns 100% of the membership interests. (8) James M. Collingsworth owns 15,000 of these common units. James M. Collingsworth holds 2,000 common units jointly with his spouse,Cindy Collingsworth. (9) Stephen L. Cropper owns 15,000 of these common units. The Donna L. Cropper Living Trust owns 25,000 of these common units. Stephen L.Cropper and his spouse, Donna L. Cropper, are the Trustees of the Trust. (10) James C. Kneale owns 15,000 of these common units. The Suzanne and Jim Kneale Living Trust owns 19,500 of these common units. (11) H. Michael Krimbill owns 453,573 of these common units. Krim2010, LLC owns 904,848 of these common units. Krimbill Enterprises LP,H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06% of Krim2010, LLC, respectively. Krimbill Enterprises LP owns20,000 of these common units. Krimbill Enterprises LP is controlled by H. Michael Krimbill via his ownership of its general partner, KrimbillHolding Company. H. Michael Krimbill exercises the sole voting and disposition power for Krimbill Enterprises LP, and disclaims beneficialownership of these securities except to the extent of his pecuniary interest therein. H. Michael Krimbill may be deemed to have sole votingand investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein.H. Michael Krimbill also owns a 14.81% interest in our general partner through KrimGP2010, LLC, of which he owns 100% of themembership interests. KrimGP2010 LLC owns 363,555 of these common units. KrimGP2010 LLC is solely owned by H. Michael Krimbill.H. Michael Krimbill may be deemed to have sole voting and investment power over these units. (12) Vincent J. Osterman owns 76,458 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. (669,300common units), Milford Propane, Inc. (559,784 common units), Osterman Family Foundation (122,016 common units), OstermanPropane, Inc. (1,445,850 common units), Propane Gas, Inc. (36,450 common units) and Saveway Propane Gas Service, Inc. (214,600 commonunits). Each of these holding entities may be deemed to have sole voting and investment power over its own common units andPropane Gas, LLC, as sole shareholder of Propane Gas, Inc., may be deemed to have sole voting and investment power over those commonunits. Vincent J. Osterman is a director, executive officer and shareholder or member of each of these entities and may be deemed to have solevoting and investment power over 745,758 common units and shared voting and investment power (with his father, Ernest Osterman) over3,185,337 common units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. Vincent J. Osterman alsoowns a 0.75% interest in our general partner through VE Properties XI LLC. (13) EMG NGL HC, LLC owns all of these common units. John T. Raymond is the Chief Executive Officer and Managing Partner of NGP MR GP,LLC, the general partner of NGP MR, LP, the general partner of NGP Midstream & Resources, LLC, a member holding a majority interest inEMG NGL HC, LLC. John T. Raymond may be deemed to have shared voting and investment power over these units, but disclaims beneficialownership except to the extent of his pecuniary interest therein. EMG I NGL GP Holdings, LLC, an affiliate of EMG NGL HC, LLC, owns a5.73% interest in our general partner. EMG II NGL GP Holdings, LLC, an affiliate of EMG NGL HC, LLC, owns a 5.36% interest in ourgeneral partner. (14) The directors and executive officers of our general partner also collectively own a 42.20% 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 unitsbeneficially held by them. The mailing address for each of the officers and directors of our general partner listed above is 6120 South Yale Avenue, Suite 805,Tulsa, Oklahoma 74136. 120Table of Contents Securities Authorized for Issuance Under Equity Compensation Plan The following table summarizes information regarding the securities that may be issued under the LTIP at March 31, 2015. Number of Securities Remaining Available forNumber of Securities to be Weighted-average Future Issuances UnderIssued upon Exercise of Exercise Price of Equity Compensation PlansOutstanding Options, Outstanding Options, (Excluding SecuritiesWarrants and Rights Warrants and Rights Reflected in Column (a))Plan Category (a) (b) (c)(1)Equity Compensation Plans Approved by Security Holders———Equity Compensation Plans Not Approved by Security Holders(2)2,260,400—7,080,006Total2,260,400—7,080,006 (1) The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of our issued and outstanding commonunits. The maximum number of common units deliverable under the LTIP automatically increases to 10% of the issued and outstandingcommon units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number ofunits deliverable by a lesser amount. (2) Our general partner adopted the LTIP in connection with the completion of our initial public offering (“IPO”) in May 2011. The adoption of theLTIP 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 31,947,372 common units, representing anaggregate 30.05% limited partner interest in us. In addition, our general partner owns a 0.1% general partner interest in us and all of our incentive distributionrights (“IDRs”). 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 amountof these expenses. In addition, our general partner owns the 0.1% general partner interest and all of the IDRs. Our general partner is entitled to receiveincentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement. The following table summarizes the distributions and payments to be made by us to our directors, officers, and greater than 5% owners and ourgeneral partner in connection with our ongoing operation and any liquidation. These distributions and payments were determined by and among affiliatedentities before our IPO and, consequently, are not the result of arm’s length negotiations. 121Table of Contents Operation Stage Distributions of available cash to our directors, officers, and greaterthan 5% 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 31,947,372 common units, and 0.1% to our general partner. Inaddition, when distributions exceed the minimum quarterly distribution andother higher target distribution levels, our general partner is entitled toincreasing percentages of the distributions, up to 48.1% of the distributionsabove the highest target distribution level. Assuming we have sufficient available cash to pay the same quarterlydistribution on all of our outstanding units for four quarters that we paid inMay 2015 ($0.625 per unit), our general partner would receive an annualdistribution of $53.8 million on its general partner interest and incentivedistribution rights, and our directors, officers, and greater than 5% ownerswould receive an aggregate annual distribution of $79.9 million on theircommon 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 orother compensation 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, substantially all of the expenses of our general partner areincurred on our behalf and reimbursed by us or our subsidiaries. Our generalpartner determines 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 respectivecapital account balances. Transactions With Related Persons SemGroup SemGroup holds an 11.78% ownership interest in our general partner. We sell product to and purchase product from SemGroup, and thesetransactions are included within revenues and cost of sales in our consolidated statements of operations (although certain of the purchases and sales that wereentered into in contemplation of each other are recorded on a net basis within revenues in our consolidated statement of operations). We also lease crude oilstorage from SemGroup. The transactions with SemGroup are summarized below for the year ended March 31, 2015 (in thousands): Sales to SemGroup$290,172Purchases from SemGroup332,030 122Table of Contents WPX Bryan Guderian is a member of our board of directors and an executive officer of WPX. We purchase crude oil from and sell crude oil to WPX(certain of the purchases and sales that were entered into in contemplation of each other are recorded on a net basis within revenues in our consolidatedstatement of operations). In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments.Subsequent to executing these commitments, the producers, which included WPX, requested to be released from the commitments. We agreed to release WPXfrom its commitments in return for a cash payment in March 2015 and additional cash payments over the next five years. These payments are included in thesales to WPX in the table below. The transactions with WPX are summarized below for the year ended March 31, 2015 (in thousands): Income from WPX$325,141Purchases from WPX371,540 Other Transactions We purchase goods and services from certain entities that are partially owned by our executive officers. These transactions are summarized below forthe year ended March 31, 2015: Ownership Nature of Amount Interest Entity Purchases Purchased in Entity (in thousands) Dr. Coady:Hicks Motor SalesVehicle purchases$55150.0% Mr. Kehoe:Cowhouse Partners, L.L.CTerminaling services and transportation services14327.5% Fluid Services, LLCCondensate purchases and transportation services33720.0% Mr. Osterman:VE Properties III, LLCOffice space rental149100.0% As of March 31, 2015, we no longer purchase goods or services from Cowhouse Partners, L.L.C. or Fluid Services, LLC. We provide goods and services to several entities that are partially owned by our executive officers. These transactions are summarized below for theyear ended March 31, 2015: Ownership Revenues Interest Entity Nature of Services Generated in Entity (in thousands) Mr. Burke:Impact Energy Services, LLCTruck transportation services$55250.0% Todd Coady, an employee of the Partnership, is the brother of Shawn Coady, who is an officer of the Partnership and a member of the board ofdirectors. Todd Coady’s annual base compensation was $225,000 until July 1, 2014, when it was increased to $250,000. Todd Coady was also eligible toparticipate in the Partnership’s 401(k) plan, and he received $7,077 of employer matching contributions during the year ended March 31, 2015. In July 2014,Todd Coady was granted a bonus of 5,000 restricted units that vested during August 2014. The grant date fair value of this bonus was $219,350. Todd Coadywas also granted 24,000 restricted units 123Table of Contents that are scheduled to vest in three tranches of 8,000 units each on July 1, 2015, July 1, 2016, and July 1, 2017. The aggregate grant date fair value of theseawards was $546,353. Timothy Osterman, an employee of the Partnership, is the son of Vincent J. Osterman, who is an executive officer of the Partnership and a member ofthe board of directors. Timothy Osterman’s base compensation during the year ended March 31, 2015 was $110,000. Timothy Osterman was also eligible toparticipate in the Partnership’s 401(k) plan, and he received $3,515 of employer matching contributions during the year ended March 31, 2015. In July 2014,Tim Osterman was granted a bonus of 3,000 restricted units that vested during August 2014. The grant date fair value of this bonus was $131,610.Tim Osterman was also granted 2,000 restricted units that are scheduled to vest in two tranches of 1,000 units each on July 1, 2015 and July 1, 2016. Theaggregate grant date fair value of these awards was $48,271. 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 of 1933, as amended (“Securities Act”) common units, includingany common units issued upon the conversion of subordinated units, owned by the parties to the Registration Rights Agreement. In connection with our IPO,we granted registration rights to the NGL Energy LP Investor Group, and subsequently, we have granted registration rights in connection with severalacquisitions. We will not be required to register such common units if an exemption from the registration requirements of the Securities Act is available withrespect to the number of common units desired to be sold. Subject to limitations specified in the Registration Rights Agreement, the registration rights of theregistration 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 SEC registering the offer and sale of aspecified 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 areentitled to notice of a Significant Holder’s exercise of its demand registration rights and may include their common units in such registration.We can only be required to file a total of eight registration statements upon the Significant Holders’ exercise of these demand registration rightsand are only required to effect demand registration if the aggregate proposed offering price to the public is at least $10.0 million. · Piggyback Registration Rights. If we propose to file a registration statement under the Securities Act to register our common units, theregistration rights parties are entitled to notice of such registration and have the right to include their common units in the registration, subjectto limitations that the underwriters relating to a potential offering may impose on the number of common units included in the registration.These counterparties also have the right to include their units in our future registrations, including secondary offerings of our common units. · Expenses of Registration. With specified exceptions, we are required to pay all expenses incidental to any registration of common units,excluding underwriting discounts and commissions Review, Approval or Ratification of Transactions with Related Parties The board of directors of our general partner has adopted a Code of Business Conduct and Ethics that, among other things, sets forth our policies forthe review, approval and ratification of transactions with related persons. The Code of Business Conduct and Ethics provides that the board of directors of ourgeneral 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; 124Table of Contents · 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 Business Conduct and Ethics. Director Independence The NYSE does not require a listed publicly traded partnership like us to have a majority of independent directors on the board of directors of ourgeneral partner. For a discussion of the independence of the board of directors of our general partner, please see Part III, Item 10—“Directors, ExecutiveOfficers and Corporate Governance—Board of Directors of our General Partner.” Item 14. Principal Accountant Fees and Services We have engaged Grant Thornton LLP as our independent registered public accounting firm. The following table summarizes fees we have paidGrant Thornton LLP to audit our annual consolidated financial statements and for other services for the years ended March 31, 2015 and 2014: 2015 2014 Audit fees (1)$2,762,764$2,531,229Audit-related fees——Tax fees (2)30,00070,091All other fees——Total$2,792,764$2,601,320 (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 and the preparation of letters to underwriters and other requesting parties. (2) Includes fees for tax services in connection with tax compliance and consultation on tax matters. 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 leastannually in order to approve services and limits for the current year. Any service that is not clearly enumerated in the policy must receive specific pre-approval by the audit committee prior to engagement. 125Table 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. 126Table of Contents Exhibit NumberDescription2.1LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative,OWL Pearsall SWD, LLC, OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC(incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onAugust 7, 2013) 2.2LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative,OWL Karnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC(incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onAugust 7, 2013) 2.3LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC,Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC(incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onAugust 7, 2013) 2.4LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC,Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC(incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onAugust 7, 2013) 2.5LLC 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 (FileNo. 001-35172) filed with the SEC on August 7, 2013) 2.6Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP,Gavilon, LLC and Gavilon Energy Intermediate, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013) 3.1Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the RegistrationStatement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.2Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference toExhibit 3.2 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.3Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference toExhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011) 3.4First Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporatedby reference 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 by reference 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 by reference 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 by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17,2012) 127Table of Contents Exhibit NumberDescription3.8Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.4 to the Registration Statementon 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 tothe Registration 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 referenceto Exhibit 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, datedas of August 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filedwith the SEC on August 7, 2013) 3.12Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, datedas of June 27, 2014 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed withthe SEC on July 3, 2014) 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 CurrentReport 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 byand among the Partnership and SemStream (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 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 andamong NGL Energy Holdings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-Portland Propane, L.L.C., Pacer Propane (Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C.(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012) 4.4Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by andbetween NGL Energy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Reporton Form 8-K (File No. 001-35172) filed with the SEC on May 4, 2012) 4.5Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by andbetween NGL Energy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Reporton Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 4.6Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by andbetween NGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K (File No. 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, byand between NGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation,Caritas Trust, Animosus Trust and Nitor Trust (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 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, byand among NGL Energy Holdings LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 128Table of Contents Exhibit NumberDescription4.9*Amendment No. 8 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of February 17, 2015, byand among NGL Energy Holdings LLC and Magnum NGL Holdco LLC 4.10Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated byreference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 4.11Amendment No. 1 to Note Purchase Agreement, dated as of January 15, 2013, among the Partnership and the purchasers namedtherein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onJanuary 18, 2013) 4.12Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers namedtherein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 9, 2013) 4.13Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders ofNGL’s 6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on October 3, 2013) 4.14Amendment 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) 4.15Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 2013, among the Partnership and the purchasersnamed therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with theSEC on December 30, 2013) 4.16Amendment No. 6 to Note Purchase Agreement, dated as of June 30, 2014, 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 onJuly 3, 2014) 4.17Amendment No. 7 to Note Purchase Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, amongthe 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 January 2, 2015) 4.18*Amendment No. 8 to Note Purchase Agreement, dated as of May 1, 2015, among the Partnership and the purchasers namedtherein 4.19Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantorsparty thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on October 16, 2013) 4.20Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on October 16, 2013) 4.21First 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(incorporated by reference to Exhibit 4.19 to the Annual Report on Form 10—K (File No. 001-35172) for the year endedMarch 31, 2014 filed with the SEC on May 30, 2014) 4.22Second 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(incorporated by reference to Exhibit 4.20 to the Annual Report on Form 10—K (File No. 001-35172) for the year endedMarch 31, 2014 filed with the SEC on May 30, 2014) 129Table of Contents Exhibit NumberDescription4.23Third Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiary party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.6to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with the SEC onNovember 10, 2014) 4.24*Fourth Supplemental Indenture, dated as of December 1, 2014, 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 4.25*Fifth Supplemental Indenture, dated as of February 17, 2015, 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 4.26Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy FinanceCorp., the Guarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initialpurchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SECon October 16, 2013) 4.27Registration 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 withthe SEC on December 5, 2013) 4.28Indenture, dated as of July 9, 2014, 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 onForm 8-K (File No. 001-35172) filed with the SEC on July 9, 2014) 4.29Forms of 5.125% Senior Notes due 2019 (incorporated by reference and included as Exhibits A1 and A2 to Exhibit 4.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014) 4.30Registration Rights Agreement, dated July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., theGuarantors listed therein on Exhibit A and RBS Securities Inc. 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 July 9, 2014) 4.31First Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiaries party thereto and U.S. Bank National Association, as Trustee (incorporated by reference toExhibit 4.5 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with theSEC on November 10, 2014) 4.32*Second Supplemental Indenture, dated as of December 1, 2014, 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 4.33*Third Supplemental Indenture, dated as of February 17, 2015, 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 10.1Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders partythereto and Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 10.2Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP,Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference toExhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012) 130Table of Contents Exhibit NumberDescription10.3Amendment 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 onJanuary 18, 2013) 10.4Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No 001-35172) filed on May 9, 2013) 10.5Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy OperatingLLC, each subsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent,Deutsche Bank Trust Company Americas, as administrative agent and collateral agent and each financial institution identifiedas a “Lender” or “Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on October 3, 2013) 10.6Amendment 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 onNovember 8, 2013) 10.7Amendment 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 partythereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SECon December 30, 2013) 10.8Facility Increase Agreement, dated as of December 30, 2013, among NGL Energy Operating LLC, Deutsche Bank TrustCompany 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 January 3, 2014) 10.9Amendment No. 6 to Credit Agreement, dated as of June 12, 2014, 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 onJune 16, 2014) 10.10Amendment No. 7 to Credit Agreement, dated as of June 27, 2014, 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 July 3,2014) 10.11Facility Increase Agreement, dated December 1, 2014, among NGL Energy Operating LLC, Deutsche Bank Trust CompanyAmericas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on December 1, 2014) 10.12Amendment No. 8 to Credit Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, among NGLEnergy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and theother financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed on January 2, 2015) 10.13*Amendment No. 9 to Credit Agreement, dated as of May 1, 2015, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto 10.14Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listedon Schedule A thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filedwith the SEC on December 5, 2013) 131Table of Contents Exhibit NumberDescription10.15+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) 10.16+NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K (File No. 001-35172) filed on May 17, 2011) 10.17+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 filedwith the SEC on August 14, 2012 ) 10.18*+NGL Performance Unit Program 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 Schema Document 101.CAL**XBRL Calculation Linkbase Document 101.DEF**XBRL Definition Linkbase Document 101.LAB**XBRL Label Linkbase Document 101.PRE**XBRL Presentation Linkbase Document * Exhibits filed with this report. ** The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at March 31,2015 and 2014, (ii) Consolidated Statements of Operations for the years ended March 31, 2015, 2014, and 2013, (iii) Consolidated Statementsof Comprehensive Income for the years ended March 31, 2015, 2014, and 2013, (iv) Consolidated Statements of Changes in Equity for the yearsended March 31, 2015, 2014, and 2013, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2015, 2014, and 2013, and(vi) Notes to Consolidated Financial Statements. + Management contracts or compensatory plans or arrangements. 132Table of Contents SIGNATURES Pursuant to the requirements of Section 13 or 15(d) Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to besigned on its behalf by the undersigned, thereunto duly authorized on June 1, 2015. 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. Signature TitleDate /s/ H. Michael KrimbillChief Executive Officer and DirectorJune 1, 2015H. Michael Krimbill(Principal Executive Officer) /s/ Atanas H. AtanasovChief Financial OfficerJune 1, 2015Atanas H. Atanasov(Principal Financial Officer) /s/ Jeffrey A. HerbersChief Accounting OfficerJune 1, 2015Jeffrey A. Herbers(Principal Accounting Officer) /s/ James J. BurkeDirectorJune 1, 2015James J. Burke /s/ Shawn W. CoadyDirectorJune 1, 2015Shawn W. Coady /s/ James M. CollingsworthDirectorJune 1, 2015James M. Collingsworth /s/ Stephen L. CropperDirectorJune 1, 2015Stephen L. Cropper /s/ Bryan K. GuderianDirectorJune 1, 2015Bryan K. Guderian /s/ James C. KnealeDirectorJune 1, 2015James C. Kneale /s/ Vincent J. OstermanDirectorJune 1, 2015Vincent J. Osterman DirectorJune 1, 2015John T. Raymond DirectorJune 1, 2015Patrick Wade 133Table of Contents INDEX TO FINANCIAL STATEMENTS NGL ENERGY PARTNERS LP Report of Independent Registered Public Accounting FirmF-2 Consolidated Balance Sheets at March 31, 2015 and 2014F-4 Consolidated Statements of Operations for the years ended March 31, 2015, 2014, and 2013F-5 Consolidated Statements of Comprehensive Income for the years ended March 31, 2015, 2014, and 2013F-6 Consolidated Statements of Changes in Equity for the years ended March 31, 2015, 2014, and 2013F-7 Consolidated Statements of Cash Flows for the years ended March 31, 2015, 2014, and 2013F-8 Notes to Consolidated Financial StatementsF-9 F-1Table 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, 2015 and 2014, 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, 2015. 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 standardsrequire that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An auditincludes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing theaccounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe thatour audits provide a reasonable basis for our opinion. In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NGL EnergyPartners LP and subsidiaries as of March 31, 2015 and 2014, and the results of their operations and their cash flows for each of the three years in the periodended March 31, 2015 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’sinternal control over financial reporting as of March 31, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued bythe Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated June 1, 2015 expressed an unqualified opinion. /s/ GRANT THORNTON LLP Tulsa, OklahomaJune 1, 2015 F-2Table 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, 2015, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee ofSponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control overfinancial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’sReport on Internal Control Over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Partnership’s internalcontrol over financial reporting based on our audit. Our audit of, and opinion on, the Partnership’s internal control over financial reporting does not includethe internal control over financial reporting of the refined products marketing operations of TransMontaigne LLC (“TransMontaigne”) and certain relatedoperations whose financial statements reflect total assets and revenues constituting 9 and 23 percent, respectively, of the related consolidated financialstatement amounts as of and for the year ended March 31, 2015. As indicated in Management’s Report, the refined products marketing operations ofTransMontaigne and certain related operations were acquired during the year ended March 31, 2015. Management’s assertion on the effectiveness of thePartnership’s internal control over financial reporting excluded internal control over financial reporting of the refined products marketing operations ofTransMontaigne and certain related operations. We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standardsrequire that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained inall material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weaknessexists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures aswe considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financialreporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’sinternal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail,accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded asnecessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of thecompany are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assuranceregarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on thefinancial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of anyevaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degreeof compliance with the policies or procedures may deteriorate. In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of March 31, 2015, based oncriteria established in the 2013 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 consolidatedfinancial statements of the Partnership as of and for the year ended March 31, 2015, and our report dated June 1, 2015 expressed an unqualified opinion onthose financial statements. /s/ GRANT THORNTON LLP Tulsa, OklahomaJune 1, 2015 F-3Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Balance Sheets(U.S. Dollars in Thousands, except unit amounts) March 31,2015 2014ASSETSCURRENT ASSETS:Cash and cash equivalents$41,303$10,440Accounts receivable—trade, net of allowance for doubtful accounts of $4,367 and $2,822, respectively1,024,226877,904Accounts receivable—affiliates17,1987,445Inventories441,762310,160Prepaid expenses and other current assets120,85580,350Total current assets1,645,3441,286,299 PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $202,959 and $109,564,respectively1,617,389835,848GOODWILL1,402,7611,085,393INTANGIBLE ASSETS, net of accumulated amortization of $220,517 and $116,728, respectively1,288,343736,106INVESTMENTS IN UNCONSOLIDATED ENTITIES472,673194,821LOAN RECEIVABLE—AFFILIATES8,154—OTHER NONCURRENT ASSETS112,8379,164Total assets$6,547,501$4,147,631 LIABILITIES AND EQUITYCURRENT LIABILITIES:Accounts payable—trade$833,380$719,303Accounts payable—affiliates25,79476,846Accrued expenses and other payables195,116141,690Advance payments received from customers54,23429,965Current maturities of long-term debt4,4727,080Total current liabilities1,112,996974,884 LONG-TERM DEBT, net of current maturities2,745,2991,629,834OTHER NONCURRENT LIABILITIES16,08611,060 COMMITMENTS AND CONTINGENCIES EQUITY:General partner, representing a 0.1% interest, 103,899 and 79,420 notional units at March 31, 2015 and2014, respectively(37,021)(45,287)Limited partners, representing a 99.9% interest -Common units, 103,794,870 and 73,421,309 units issued and outstanding at March 31, 2015 and 2014,respectively2,162,9241,570,074Subordinated units, 5,919,346 units issued and outstanding at March 31, 2014—2,028Accumulated other comprehensive loss(109)(236)Noncontrolling interests547,3265,274Total equity2,673,1201,531,853Total liabilities and equity$6,547,501$4,147,631 The accompanying notes are an integral part of these consolidated financial statements. F-4Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Operations(U.S. Dollars in Thousands, except unit and per unit amounts) Year Ended March 31,20152014 2013REVENUES:Crude oil logistics$6,635,384$4,558,545$2,316,288Water solutions200,042143,10062,227Liquids2,243,8252,650,4251,604,746Retail propane489,197551,815430,273Refined products and renewables7,231,6931,357,676—Other1,916437,7134,233Total Revenues16,802,0579,699,2744,417,767 COST OF SALES:Crude oil logistics6,560,5064,477,3972,244,647Water solutions(30,506)11,7385,611Liquids2,111,6142,518,0991,530,459Retail propane278,538354,676258,393Refined products and renewables7,035,4721,344,176—Other2,583426,613—Total Cost of Sales15,958,2079,132,6994,039,110 OPERATING COSTS AND EXPENSES:Operating372,176259,799169,612Loss on disposal or impairment of assets, net41,1843,597187General and administrative149,43075,86052,698Depreciation and amortization193,949120,75468,853Operating Income87,111106,56587,307 OTHER INCOME (EXPENSE):Earnings of unconsolidated entities12,1031,898—Interest expense(110,123)(58,854)(32,994)Loss on early extinguishment of debt——(5,769)Other income, net37,171861,521Income Before Income Taxes26,26249,69550,065 INCOME TAX (PROVISION) BENEFIT3,622(937)(1,875) Net Income29,88448,75848,190 LESS: NET INCOME ALLOCATED TO GENERAL PARTNER(45,679)(14,148)(2,917) LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS(13,223)(1,103)(250) NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS$(29,018)$33,507$45,023 BASIC AND DILUTED INCOME (LOSS) PER COMMON UNIT$(0.29)$0.51$0.96 BASIC AND DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING86,359,30061,970,47141,353,574 The accompanying notes are an integral part of these consolidated financial statements. F-5Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Comprehensive Income(U.S. Dollars in Thousands) Year Ended March 31,20152014 2013 Net income$29,884$48,758$48,190Other comprehensive income (loss)127(260)(7)Comprehensive income$30,011$48,498$48,183 The accompanying notes are an integral part of these consolidated financial statements. F-6Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Changes in EquityFor the Years Ended March 31, 2015, 2014, and 2013(U.S. Dollars in Thousands, except unit amounts) Accumulated Limited Partners Other General Common Subordinated Comprehensive Noncontrolling TotalPartner Units Amount Units Amount Income (Loss) Interests EquityBALANCES AT MARCH 31,2012$44223,296,253$384,6045,919,346$19,824$31$428$405,329Distributions(1,778)—(59,841)—(9,989)—(74)(71,682)Contributions510—————403913Business combinations(52,588)24,250,258550,873———4,733503,018Equity issued pursuant toincentive compensationplan—156,8023,657————3,657Net income2,917—41,705—3,318—25048,190Other comprehensive loss—————(7)—(7)BALANCES AT MARCH 31,2013(50,497)47,703,313920,9985,919,34613,153245,740889,418Distributions(9,703)—(123,467)—(11,920)—(840)(145,930)Contributions765—————2,0602,825Business combinations—2,860,87980,591————80,591Sales of units, net ofoffering costs—22,560,848650,155————650,155Equity issued pursuant toincentive compensationplan—296,2699,085————9,085Disposal of noncontrollinginterest——————(2,789)(2,789)Net income14,148—32,712—795—1,10348,758Other comprehensive loss—————(260)—(260)BALANCES AT MARCH 31,2014(45,287)73,421,3091,570,0745,919,3462,028(236)5,2741,531,853Distributions(38,236)—(197,611)—(6,748)—(27,147)(269,742)Contributions823—————9,43310,256Business combinations—8,851,105259,937———546,740806,677Sales of units, net ofoffering costs—15,017,100541,128————541,128Equity issued pursuant toincentive compensationplan—586,01023,134————23,134Net income (loss)45,679—(25,005)—(4,013)—13,22329,884Other comprehensiveincome—————127—127Conversion ofsubordinated units tocommon units—5,919,346(8,733)(5,919,346)8,733———Other——————(197)(197)BALANCES AT MARCH 31,2015$(37,021)103,794,870$2,162,924—$—$(109)$547,326$2,673,120 The accompanying notes are an integral part of these consolidated financial statements. F-7Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Cash Flows(U.S. Dollars in Thousands) Year Ended March 31,20152014 2013OPERATING ACTIVITIES:Net income$29,884$48,758$48,190Adjustments to reconcile net income to net cash provided by operating activities:Depreciation and amortization, including debt issuance cost amortization210,475132,65377,513Loss on early extinguishment of debt——5,769Non-cash equity-based compensation expense32,76714,0548,670Loss on disposal or impairment of assets, net41,1843,597187Provision for doubtful accounts3,8382,1721,315Commodity derivative (gain) loss(219,421)43,6554,376Earnings of unconsolidated entities(12,103)(1,898)—Distributions of earnings from unconsolidated entities12,539——Other127312375Changes in operating assets and liabilities, exclusive of acquisitions:Accounts receivable—trade50,88721,3882,562Accounts receivable—affiliates(9,225)18,002(12,877)Inventories243,292(73,321)18,433Prepaid expenses and other assets(34,505)20,30822,585Accounts payable—trade(1,965)(167,060)(16,913)Accounts payable—affiliates(51,121)67,361(6,813)Accrued expenses and other liabilities(53,844)(41,671)(9,689)Advance payments received from customers19,585(3,074)(11,049)Net cash provided by operating activities262,39485,236132,634 INVESTING ACTIVITIES:Purchases of long-lived assets(203,760)(165,148)(72,475)Purchases of pipeline capacity allocations(24,218)——Purchase of equity interest in Grand Mesa Pipeline(310,000)——Acquisitions of businesses, including acquired working capital, net of cash acquired(960,922)(1,268,810)(490,805)Cash flows from commodity derivatives199,165(35,956)11,579Proceeds from sales of assets26,26224,6605,080Investments in unconsolidated entities(33,528)(11,515)—Distributions of capital from unconsolidated entities10,8231,591—Loan for facility under construction(63,518)——Payments on loan for facility under construction1,625——Loans to affiliates(8,154)——Other4(195)—Net cash used in investing activities(1,366,221)(1,455,373)(546,621) FINANCING ACTIVITIES:Proceeds from borrowings under revolving credit facilities3,764,5002,545,5001,227,975Payments on revolving credit facilities(3,280,000)(2,101,000)(964,475)Issuances of notes400,000450,000250,000Proceeds from borrowings on other long-term debt—880653Payments on other long-term debt(6,688)(8,819)(4,837)Debt issuance costs(11,076)(24,595)(20,189)Contributions from general partner823765510Contributions from noncontrolling interest owners9,4332,060403Distributions to partners(242,595)(145,090)(71,608)Distributions to noncontrolling interest owners(27,147)(840)(74)Proceeds from sale of common units, net of offering costs541,128650,155(642)Taxes paid on behalf of equity incentive plan participants(13,491)——Other(197)——Net cash provided by financing activities1,134,6901,369,016417,716Net increase (decrease) in cash and cash equivalents30,863(1,121)3,729Cash and cash equivalents, beginning of period10,44011,5617,832Cash and cash equivalents, end of period$41,303$10,440$11,561 The accompanying notes are an integral part of these consolidated financial statements. F-8Table of Contents NGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsAt March 31, 2015 and 2014, and for the Years Ended March 31, 2015, 2014, and 2013 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. NGL Energy HoldingsLLC serves as our general partner. On May 17, 2011, we completed our initial public offering (“IPO”). Subsequent to our IPO, we significantly expanded ouroperations through numerous acquisitions, as described below. At March 31, 2015, our operations include: · Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, owned and leased pipeline injectionstations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned and leased barges and towboats, and a 50%interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned andleased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. · Our water solutions segment, the assets of which include water treatment and disposal facilities. Our water solutions segment generates revenuesfrom the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recoveredhydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids. · Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United Statesand in Canada, and which provides natural gas liquids terminaling services through its 21 owned terminals throughout the United States andrailcar transportation services through its fleet of leased railcars. Our liquids segment purchases propane, butane, and other products fromrefiners, processing plants, producers, and other parties, and sells the products to retailers, refiners, petrochemical plants, and other participantsin the wholesale markets. · Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural,commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia. · Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the2.0% general partner interest and a 19.6% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined productsterminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and a 50% interestin Frontera Brownsville LLC (“Frontera”), which are entities that own refined products storage facilities. Acquisitions At the time of our IPO, we owned a retail propane business operating primarily in Illinois and Indiana and a natural gas liquids wholesale businesswith three natural gas liquids terminals. Subsequent to our IPO, we significantly expanded our operations through numerous acquisitions, including thefollowing, among others: Year Ended March 31, 2012 · In October 2011, we completed a business combination with E. Osterman Propane, Inc., its affiliated companies, and members of the Ostermanfamily, 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. · 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. F-9Table of Contents Year Ended March 31, 2013 · In May 2012, we acquired the retail propane and distillate operations of Downeast Energy Corp. These operations are primarily in thenortheastern 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 andmarketing; 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. Year Ended March 31, 2014 · In July 2013, we completed a business combination whereby we acquired the operating assets of Crescent Terminals, LLC, which operates aleased crude oil storage and dock facility in Port Aransas, Texas, and the ownership interests in Cierra Marine, LP and its affiliated companies,whereby we acquired a fleet of four towboats and seven crude oil barges operating in the intercoastal waterways of Texas. · In July 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd., whereby we acquired a water treatmentand disposal facility in the Permian Basin in Texas. We also entered into a development agreement that provides us the right to purchase watertreatment and disposal facilities developed by the other party to the agreement, and we are also party to a solids facilities developmentagreement with this other party. During March 2014, we purchased one additional facility under this development agreement. During the yearended March 31, 2015, we purchased 16 water treatment and disposal facilities under this development agreement. · In August 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively,“OWL”). The businesses of OWL include four water treatment and disposal facilities in the Eagle Ford shale play in Texas. · In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC, whereby we acquired the ownership interestsin three water treatment and disposal facilities in the Eagle Ford shale play in Texas, and the option to acquire an additional facility which weexercised in March 2014. · In December 2013, we acquired the ownership interests in Gavilon, LLC (“Gavilon Energy”). The assets of Gavilon Energy include crude oilterminals in Oklahoma, Texas, and Louisiana, a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oilpipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma and became operational in February 2014, and an interest inan ethanol production facility in the Midwest. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol,biodiesel, and natural gas liquids, and also include crude oil storage in Cushing, Oklahoma. Year Ended March 31, 2015 · In July 2014, we acquired TransMontaigne Inc. (“TransMontaigne”). As part of this transaction, we also purchased inventory from the previousowner of TransMontaigne. The operations of TransMontaigne include the marketing of refined products. As part of this transaction, we acquiredthe 2.0% general partner interest, the incentive distribution rights, a 19.7% limited partner interest in TLP, and assumed certain terminalingservice agreements with TLP from an affiliate of the previous owner of TransMontaigne. · In November 2014, we completed the acquisition of two saltwater disposal facilities in the Bakken shale play in North Dakota. F-10Table of Contents · In February 2015, we acquired Sawtooth NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utahwith rail and truck access to western U.S. markets and entered into a construction agreement to expand the storage capacity of the facility. 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 our accounts and those of our controlled subsidiaries. Investments where we do nothave the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. Allsignificant intercompany transactions and account balances have been eliminated in consolidation. We have made certain reclassifications to prior period financial statements to conform to classification methods used in fiscal year 2015. Thesereclassifications had no impact on previously reported amounts of equity or net income. In addition, certain balances at March 31, 2014 were adjusted toreflect the final acquisition accounting for certain business combinations. Use of Estimates The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect 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,plant and equipment and amortizable intangible assets; the impairment of goodwill; the fair value of asset retirement obligations; the value of equity-basedcompensation; and accruals for various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual resultscould 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 evaluatethe need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not materialto the fair values of our derivative instruments. We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels: · Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurementdate. · Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability,including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactivemarkets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data bycorrelation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodityprice swap and option contracts and interest rate protection agreements. We determine the fair value of all of our derivative financialinstruments utilizing pricing models for significantly similar instruments. Inputs to the pricing models include publicly available prices andforward curves generated from a compilation of data gathered from third parties. F-11Table of Contents · Level 3—Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. 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 afair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair valuemeasurement requires judgment, considering factors specific to the asset or liability. Derivative Financial Instruments We record our derivative financial instrument contracts at fair value in our 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 orsale election and are designated as such are not accounted for as derivatives at fair value and, accordingly, are recorded when the delivery occurs. We have not designated any financial instruments as hedges for accounting purposes. All mark-to-market gains and losses on commodity derivativeinstruments that do not qualify as normal purchases or sales, whether cash transactions or non-cash mark-to-market adjustments, are reported within cost ofsales in our 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. Wedo not enter into such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily fromchanges in market prices, newly originated transactions, and the timing of settlements. We attempt to balance our contractual portfolio in terms of notionalamounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment ofanticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk isthe risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of lossfrom nonperformance by suppliers, customers, or financial counterparties to a contract. We take an active role in managing and controlling market risk andcredit risk and have established control procedures that we review on an ongoing basis. We monitor market risk through a variety of techniques and attemptto minimize credit risk exposure through credit policies and periodic monitoring procedures. Revenue Recognition We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the productby the purchaser. We record terminaling, transportation, storage, and service revenues at the time the service is performed, and we record tank and otherrentals over the term of the lease. Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume ofproduct gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Such measurementdifferentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale ofthe product gained. Revenues for our water solutions segment are recognized upon receipt of the wastewater at our treatment and 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 our consolidated statements of operations. We enter into certain contracts whereby we agree to purchase product from a counterparty and 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, werecord the revenues for these transactions net of cost of sales. Revenues during the year ended March 31, 2015 include $0.7 million associated with the amortization of a liability recorded in the acquisitionaccounting for an acquired business related to certain out-of-market revenue contracts. 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 $7.8 million, $6.2 million, and $5.3 million during the years ended March 31, 2015, 2014, and 2013, respectively. F-12Table of Contents Depreciation and Amortization Depreciation and amortization in our 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-basedintangible assets, for which the amortization is recorded to cost of sales. Cash and Cash Equivalents Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of threemonths or less at the date of purchase. At times, certain account balances may exceed federally insured limits. Supplemental Cash Flow Information Supplemental cash flow information is as follows: Year Ended March 31, 20152014 2013 (in thousands) Interest paid, exclusive of debt issuance costs and letter of credit fees$90,556$31,827$27,384Income taxes paid$22,816$1,639$1,027 Cash flows from settlements of commodity derivative instruments are classified as cash flows from investing activities in our consolidatedstatements of cash flows, and adjustments to the fair value of commodity derivative instruments are included in the reconciliation of net income to net cashprovided by operating activities. 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 allowancefor doubtful accounts is based on our assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness ofcustomers and any specific disputes. Accounts receivable are considered past due or delinquent based on contractual terms. We write off accounts receivableagainst the allowance for doubtful accounts when collection efforts have been exhausted. We execute netting agreements with certain customers to mitigate our credit risk. Receivables and payables are reflected at a net balance to theextent a netting agreement is in place and we intend to settle on a net basis. Our accounts receivable consist of the following: March 31, 2015 March 31, 2014 Gross Allowance for Gross Allowance forSegment Receivable Doubtful Accounts Receivable Doubtful Accounts (in thousands)Crude oil logistics$600,896$382$410,746$105Water solutions38,68970925,700405Liquids99,6991,133169,827617Retail propane55,1471,61975,6061,667Refined products and renewables233,265524160,182—Other897—38,66528Total$1,028,593$4,367$880,726$2,822 F-13Table of Contents Changes in the allowance for doubtful accounts are as follows: Year Ended March 31,2015 2014 2013(in thousands)Allowance for doubtful accounts, beginning of period$2,822$1,760$818Provision for doubtful accounts3,8382,1721,315Write off of uncollectible accounts(2,293)(1,110)(373)Allowance for doubtful accounts, end of period$4,367$2,822$1,760 Sales of crude oil and natural gas liquids to our largest customer represented 16%, 10%, and 10% of consolidated total revenues for the years endedMarch 31, 2015, 2014, and 2013, respectively. Inventories We value our inventories 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 and storage. Market is determined based on estimated replacement cost using prices at the end of the reportingperiod. In performing this analysis, we consider fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesaleliquids business to our retail propane business to sell the inventory in retail markets. At March 31, 2015, our inventory values were reduced by $16.8 millionof lower-of-cost-or-market adjustments. Inventories consist of the following: March 31,2015 2014(in thousands)Crude oil$145,412$156,473Natural gas liquids—Propane44,53585,159Butane8,66815,106Other3,8743,945Refined products—Gasoline128,09215,597Diesel59,0977,612Renewables44,66811,778Other7,41614,490Total$441,762$310,160 Investments in Unconsolidated Entities In December 2013, as part of our acquisition of Gavilon Energy, we acquired a 50% interest in Glass Mountain and an interest in a limited liabilitycompany that owns an ethanol production facility in the Midwest. In June 2014, we acquired an interest in a limited liability company that operates a watersupply company in the DJ Basin. On July 1, 2014, as part of our acquisition of TransMontaigne, we acquired the 2.0% general partner interest and a 19.7%limited partner interest in TLP, which owns a 42.5% interest in BOSTCO and a 50% interest in Frontera. We account for these investments using the equitymethod of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities in our consolidated balance sheets;instead, our ownership interests are reported within investments in unconsolidated entities in our consolidated balance sheets. Under the equity method, theinvestment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by ourproportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our totalinvestment exceeds our proportionate share of the historical net book value of the net assets of the investee. F-14Table of Contents Our investments in unconsolidated entities consist of the following: March 31,Entity Segment 2015 2014 (in thousands)Glass Mountain (1)Crude oil logistics$187,590$186,488BOSTCO (2)Refined products and renewables238,146—Frontera (2)Refined products and renewables16,927—Water supply companyWater solutions16,471—Ethanol production facilityRefined products and renewables13,5398,333Total$472,673$194,821 (1) When we acquired Gavilon Energy, we recorded the investment in Glass Mountain at fair value. Our investment in Glass Mountain exceeds ourshare of the historical net book value of Glass Mountain’s net assets by $76.7 million at March 31, 2015. This difference relates primarily togoodwill and customer relationships. (2) When we acquired TransMontaigne, we recorded the investments in BOSTCO and Frontera at fair value. Our investments in BOSTCO andFrontera exceed our share of the historical net book value of BOSTCO’s and Frontera’s net assets by $14.7 million at March 31, 2015. Thisdifference relates primarily to goodwill. The following table summarizes the cumulative earnings (loss) from our unconsolidated entities and cumulative distributions received from ourunconsolidated entities: Cumulative Cumulative Earnings (Loss) Distributions From Received From Unconsolidated UnconsolidatedEntity Entities Entities (in thousands)Glass Mountain$3,704$8,733BOSTCO4,5059,725Frontera9591,532Water supply company(29)—Ethanol production facility4,8604,963 The summarized financial information of our unconsolidated entities was as follows: Balance sheets: Water Supply Ethanol Production Glass MountainBOSTCO Frontera Company Facility March 31, 201520142015 2015 2015 2015 2014 (in thousands) Current assets$8,456$4,915$13,710$4,608$3,160$38,607$43,522Noncurrent assets214,494214,063507,65543,80532,44785,27772,751Current liabilities1,0803,18111,1891,37064415,75517,707Noncurrent liabilities3750——26,25121,40311,356 F-15Table of Contents Statements of operations: Water Supply Ethanol Production Glass MountainBOSTCO Frontera Company Facility Year Ended March 31, 201520142015 2015 2015 2015 2014 (in thousands) Revenues$37,539$3,979$45,067$10,643$8,326$159,148$61,929Cost of sales2,771————117,22239,449Net income (loss)12,34544511,0741,352(104)24,60717,599 Other Noncurrent Assets Other noncurrent assets consist of the following: March 31,2015 2014(in thousands)Loan receivable (1)$58,050$—Linefill (2)35,060—Other19,7279,164Total$112,837$9,164 (1) Represents a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party. (2) Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipmentcommitments. At March 31, 2015, linefill consisted of 487,104 barrels of crude oil. Accrued Expenses and Other Payables Accrued expenses and other payables consist of the following: March 31,2015 2014(in thousands)Accrued compensation and benefits$52,078$45,006Excise and other tax liabilities43,84713,421Derivative liabilities27,95042,214Accrued interest23,06518,668Product exchange liabilities15,4803,719Other32,69618,662Total$195,116$141,690 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 loss on disposal or impairment of assets, net. We compute depreciation expense on a majority of our property, plant and equipmentusing the straight-line method over the estimated useful lives of the assets (see Note 5). F-16Table of Contents 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 customer relationships, pipeline capacityrights, a water facility development agreement, executory contracts and other agreements, covenants not to compete, trade names, and customercommitments. In addition, we capitalize certain debt issuance costs incurred in our long-term debt arrangements. We amortize the majority of our intangibleassets on a straight-line basis over the assets estimated useful lives (see Note 7). We amortize debt issuance costs over the terms of the related debt on amethod that approximates the effective interest method. We evaluate the carrying value of our amortizable intangible assets for potential impairment when events and circumstances warrant such a review.A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset 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.When we cease to use an acquired trade name, we test the trade name for impairment using the “relief from royalty” method and we begin amortizing the tradename over its estimated useful life as a defensive asset. Goodwill Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Business combinations are accounted for using the“acquisition method” (see Note 4). We expect that substantially all of our goodwill at March 31, 2015 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 mightbe impaired. We perform the annual evaluation at January 1 of each year. To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting 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, includinggoodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If thecarrying amount of a reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure theamount of impairment loss, if any. · In the second step of the goodwill impairment test, we compare the implied fair value of reporting unit goodwill with the carrying amountof that goodwill. If the carrying amount of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss isrecognized in an amount equal to that excess. Estimates and assumptions used to perform the impairment evaluation are inherently uncertain and can significantly affect the outcome of 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. For our January 1, 2015 goodwillimpairment assessment for our water solutions segment, we completed the first step of the impairment test and concluded that the fair value of the reportingunit exceeded the book value. For our other segments, based on our assessment of qualitative factors, we determined that the two-step impairment test was notrequired. Accordingly, we did not record any goodwill impairments during the years ended March 31, 2015, 2014, and 2013. 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 in our consolidated balance sheets. We estimate the value of product exchange assets and liabilities based on theweighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus or minus location differentials. F-17Table of Contents Advance Payments Received from Customers We record customer advances on product purchases as a liability in our consolidated balance sheets. Noncontrolling Interests We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated financialstatements represents the other owners’ interest in these entities. On July 1, 2014, as part of our acquisition of TransMontaigne, we acquired a 19.7% limited partner interest in TLP. We have attributed net earningsallocable to TLP’s limited partners to the controlling and noncontrolling interests based on the relative ownership interests in TLP as well as includingcertain adjustments related to our acquisition accounting. Earnings allocable to TLP’s limited partners are net of the earnings allocable to TLP’s generalpartner interest. The earnings allocable to TLP’s general partner interest include the distributions of available cash (as defined by TLP’s partnershipagreement) attributable to the period to TLP’s general partner interest and incentive distribution rights, net of adjustments for TLP’s general partner’s share ofundistributed earnings. Undistributed earnings are allocated to TLP’s limited partners and TLP’s general partner interest based on their respective sharing ofearnings or losses specified in TLP’s partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively. 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 (not to exceed one year) to obtain the information necessary to identify and measure the value of the assets acquired andliabilities assumed in a business combination. As described in Note 4, certain of our acquisitions during the year ended March 31, 2015 are still within thismeasurement period, and as a result, the acquisition date fair values we have recorded for the assets acquired and liabilities assumed are subject to change. Also as described in Note 4, we made certain adjustments during the year ended March 31, 2015 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, 2014. We retrospectively adjusted theMarch 31, 2014 consolidated balance sheet for these adjustments. Due to the immateriality of these adjustments, we did not retrospectively adjust ourconsolidated statement of operations for the year ended March 31, 2014 for these measurement period adjustments. Recent Accounting Pronouncements In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Simplifying thePresentation of Debt Issuance Costs.” ASU No. 2015-03 requires that debt issuance costs be presented in the balance sheet as a direct deduction from thecarrying amount of that debt liability. The ASU is effective for the Partnership for both annual and interim periods beginning April 1, 2016 and requiresretrospective application for all prior periods presented. Early adoption of this ASU is permitted for financial statements that have not been previously issued.We plan to adopt this ASU effective March 31, 2016, at which time we will begin presenting debt issuance costs as a reduction to long-term debt, rather thanas an intangible asset. In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” ASU No. 2014-09 will replace most existing revenuerecognition guidance in GAAP. The core principle of this ASU is that an entity should recognize revenue for the transfer of goods or services equal to theamount that it expects to be entitled to receive for those goods or services. The ASU is effective for the Partnership beginning April 1, 2017, and allows forboth full retrospective and modified retrospective (with cumulative effect) methods of adoption. We are in the process of determining the method of adoptionand assessing the impact of this ASU on our consolidated financial statements. F-18Table of Contents Note 3—Earnings Per Unit Our earnings per common unit were computed as follows: Year Ended March 31,2015 2014 2013(in thousands, except unit and per unit amounts)Net income attributable to parent equity$16,661$47,655$47,940Less: Net income allocated to general partner (1)(45,679)(14,148)(2,917)Less: Net loss (income) allocated to subordinated unitholders (2)4,013(1,893)(5,506)Net income (loss) allocated to common unitholders$(25,005)$31,614$39,517 Weighted average common units outstanding86,359,30061,970,47141,353,574 Income (loss) per common unit - basic and diluted$(0.29)$0.51$0.96 (1) Net income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which aredescribed in Note 11. (2) All outstanding subordinated units converted to common units in August 2014. Since the subordinated units did not share in the distribution ofcash generated subsequent to June 30, 2014, we did not allocate any income or loss subsequent to that date to the subordinated unitholders.During the years ended March 31, 2014 and 2013, 5,919,346 subordinated units were outstanding. The income per subordinated unit was $0.32and $0.93 for the years ended March 31, 2014 and 2013, respectively. The restricted units described in Note 11 were antidilutive for the years ended March 31, 2015, 2014, and 2013, but could impact earnings per unitin future periods. Note 4—Acquisitions Year Ended March 31, 2015 As described in Note 2, pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the informationnecessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. The business combinations forwhich this measurement period was still open as of March 31, 2015 are summarized below. Natural Gas Liquids Storage Acquisition In February 2015, we acquired Sawtooth, which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to westernU.S. markets and entered into a construction agreement to expand the storage capacity of the facility. We paid $97.6 million of cash, net of cash acquired, andissued 7,396,973 common units, valued at $218.5 million, in exchange for these assets and operations. The agreement for this acquisition contemplates post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilitiesassumed in this business combination. The estimates of fair value at March 31, 2015 are subject to change, and such changes could be material. We havepreliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands): Accounts receivable—trade$42Prepaid expenses and other current assets600Property, plant and equipment:Natural gas liquids terminal and storage assets (2—30 years)62,205Vehicles and railcars (3—25 years)75Land68Other32Construction in progress19,525Goodwill151,853Intangible assets:Customer relationships (15 years)85,000Non-compete agreements (10 years)12,000Accounts payable—trade(931)Accrued expenses and other payables(6,511)Advance payments received from customers(1,015)Other noncurrent liabilities(6,817)Fair value of net assets acquired$316,126 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 business and the Partnership, the opportunity to use theacquired business as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal incometax 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. 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 natural gas liquids storage lease commitments were atunfavorable terms relative to acquisition-date market conditions, we recorded a liability of F-19Table of Contents $12.8 million related to these lease commitments in the acquisition accounting, and we amortized $0.7 million of this balance as an increase to revenuesduring the year ended March 31, 2015. We will amortize the remainder of this liability over the term of the leases. The future amortization of this liability isshown below (in thousands): Year Ending March 31, 2016$5,80720174,90520181,306201988 The operations of this acquisition have been included in our consolidated statements of operations since the acquisition date. Our consolidatedstatement of operations for the year ended March 31, 2015 includes revenues of $1.7 million that were generated by the operations of this business after weacquired them. Bakken Water Solutions Facilities On November 21, 2014, we completed the acquisition of two saltwater disposal facilities in the Bakken shale play in North Dakota for $34.6 millionof cash. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in this business combination. Theestimates of fair value at March 31, 2015 are subject to change, and such changes could be material. We expect to complete this process prior to finalizingour financial statements for the three months ending September 30, 2015. We have preliminarily estimated the fair values of the assets acquired (and usefullives) and liabilities assumed as follows (in thousands): Property, plant and equipment:Vehicles (10 years)$63Water treatment facilities and equipment (5—40 years)5,815Buildings and leasehold improvements (3—7 years)130Land100Goodwill6,560Intangible asset:Customer relationships (6 years)22,000Other noncurrent liabilities(68)Fair value of net assets acquired$34,600 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 business and the Partnership and the opportunity to use theacquired business as a platform for growth. We estimate that all of the goodwill will be deductible for federal income tax purposes. The operations of these water treatment and disposal facilities have been included in our consolidated statement of operations since their acquisitiondate. Our consolidated statement of operations for the year ended March 31, 2015 includes revenues of $3.6 million and operating income of $1.0 millionthat were generated by the operations of these facilities after we acquired them. TransMontaigne Inc. On July 1, 2014, we acquired TransMontaigne for $200.3 million of cash, net of cash acquired (including $174.1 million paid at closing and $26.2million paid upon completion of the working capital settlement). As part of this transaction, we also purchased $380.4 million of inventory from the previousowner of TransMontaigne (including $346.9 million paid at closing and $33.5 million subsequently paid as the working capital settlement processprogressed). The operations of TransMontaigne include the marketing of refined products. As part of this transaction, we acquired the 2.0% general partnerinterest, the incentive distribution rights, a 19.7% limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from anaffiliate of the previous owner of TransMontaigne. F-20Table of Contents We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in this business combination. Theestimates of fair value at March 31, 2015 are subject to change, and such changes could be material. We expect to complete this process prior to finalizingour financial statements for the three months ending June 30, 2015. We have preliminarily estimated the fair values of the assets acquired (and useful lives)and liabilities assumed as follows (in thousands): Cash and cash equivalents$1,469Accounts receivable—trade197,829Accounts receivable—affiliates528Inventories373,870Prepaid expenses and other current assets15,001Property, plant and equipment:Refined products terminal assets and equipment (20 years)399,323Vehicles1,698Crude oil tanks and related equipment (20 years)1,058Information technology equipment7,253Buildings and leasehold improvements (20 years)14,770Land70,529Tank bottoms (indefinite life)46,900Other15,534Construction in progress4,487Goodwill28,074Intangible assets:Customer relationships (15 years)76,100Pipeline capacity rights (30 years)87,618Investments in unconsolidated entities240,583Other noncurrent assets3,911Accounts payable—trade(113,066)Accounts payable—affiliates(69)Accrued expenses and other payables(78,427)Advance payments received from customers(1,919)Long-term debt(234,000)Other noncurrent liabilities(33,227)Noncontrolling interests(545,120)Fair value of net assets acquired$580,707 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 business and the Partnership, the opportunity to use theacquired business as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal incometax 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. The intangible asset for pipeline capacity rights relates to capacity allocations on a third-party refined products pipeline. Demand for use of thispipeline exceeds the pipeline’s capacity, and the limited capacity is allocated based on a shipper’s historical shipment volumes. The fair value of the noncontrolling interests was calculated by multiplying the closing price of TLP’s common units on the acquisition date by thenumber of TLP common units held by parties other than us, adjusted for a lack-of-control discount. In the acquisition accounting, we recorded a liability of $2.5 million related to certain crude oil contracts with terms that were unfavorable at currentmarket conditions. We amortized this balance to cost of sales during the year ended March 31, 2015. Employees of TransMontaigne participate in a plan whereby they are entitled to certain termination benefits in the event of a change in control ofTransMontaigne and a subsequent change in job status. We recorded expense of $9.3 million during the year F-21Table of Contents ended March 31, 2015 related to these termination benefits. The operations of TransMontaigne have been included in our consolidated statements of operations since TransMontaigne was acquired on July 1,2014. Our consolidated statement of operations for the year ended March 31, 2015 includes revenues of $3.9 billion and operating income of $36.3 millionthat were generated by the operations of TransMontaigne after we acquired them. We have not provided supplemental pro forma financial information asthough the business combination had occurred on April 1, 2013 as the previous owner of TransMontaigne conducted trading operations, whereas we strive togenerate more reliable and predictable cash flows. Because of the difference in strategies between the pre-acquisition and post-acquisition periods, the pre-acquisition operations of TransMontaigne have limited importance as an indicator of post-acquisition results. Water Solutions Facilities As described below, we are party to a development agreement that provides us a right to purchase water treatment and disposal facilities developedby the other party to the agreement, and we are also party to a solids facilities development agreement with this other party. During the year ended March 31,2015, we purchased 16 water treatment and disposal facilities under this development agreement over the course of the year. We also purchased a 75%interest in one additional water treatment and disposal facility in July 2014 from a different seller. On a combined basis, we paid $190.0 million of cash andissued 1,322,032 common units, valued at $37.8 million, in exchange for these 17 facilities. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these business combinations. Theestimates of fair value at March 31, 2015 are subject to change, and such changes could be material. We expect to complete this process prior to finalizingour financial statements for the three months ending December 31, 2015. We have preliminarily estimated the fair values of the assets acquired (and usefullives) and liabilities assumed as follows (in thousands): Accounts receivable—trade$939Inventories253Prepaid expenses and other current assets62Property, plant and equipment:Water treatment facilities and equipment (5—40 years)79,706Buildings and leasehold improvements (3—7 years)10,250Land3,109Other (7 years)129Goodwill132,770Intangible asset:Customer relationships (4 years)10,000Other noncurrent assets50Accounts payable—trade(58)Accrued expenses and other payables(3,092)Other noncurrent liabilities(582)Noncontrolling interest(5,775)Fair value of net assets acquired$227,761 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 business and the Partnership and the opportunity to use theacquired business as a platform for growth. We estimate that all of the goodwill will be deductible for federal income tax purposes. The operations of these water treatment and disposal facilities have been included in our consolidated statement of operations since their acquisitiondate. Our consolidated statement of operations for the year ended March 31, 2015 includes revenues of $27.9 million and operating income of $10.5 millionthat were generated by the operations of these facilities after we acquired them. F-22Table of Contents Retail Propane Acquisitions During the year ended March 31, 2015, we completed eight acquisitions of retail propane businesses. On a combined basis, we paid $39.1 million ofcash and issued 132,100 common units, valued at $3.7 million, in exchange for these assets and operations. The agreements for these acquisitionscontemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assetsacquired and liabilities assumed in certain of these business combinations. The estimates of fair value at March 31, 2015 are subject to change, and suchchanges could be material. We expect to complete this process prior to finalizing our financial statements for the three months ending December 31, 2015.We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands): Accounts receivable—trade$2,237Inventories771Prepaid expenses and other current assets110Property, plant and equipment:Retail propane equipment (15—20 years)13,177Vehicles and railcars (5—7 years)2,332Buildings and leasehold improvements (30 years)784Land655Other (5—7 years)116Goodwill8,097Intangible assets:Customer relationships (10—15 years)17,563Non-compete agreements (5—7 years)500Trade names (3—12 years)950Accounts payable—trade(1,921)Advance payments received from customers(1,750)Current maturities of long-term debt(78)Long-term debt, net of current maturities(760)Fair value of net assets acquired$42,783 Goodwill represents the excess of the consideration paid for the acquired businesses over the fair value of the individual assets acquired, net ofliabilities assumed. Goodwill primarily represents the value of synergies between the acquired businesses and the Partnership, the opportunity to use theacquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federalincome 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. F-23 Water Supply Company On June 9, 2014, we paid cash of $15.0 million in exchange for an interest in a water supply company operating in the DJ Basin. The company holdsexclusive rights to construct water disposal facilities on a dedicated acreage. We account for this investment using the equity method of accounting. 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 assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana, a 50% interest in Glass Mountain, which owns a crudeoil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma, and an interest in an ethanol production facility in the Midwest. Theoperations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids, and also include crude oilstorage in Cushing, Oklahoma. F-24 During the year ended March 31, 2015, we completed the acquisition accounting for this business combination. The following table presents thefinal calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for this acquisition: Estimated at March 31, Final2014 Change(in thousands)Accounts receivable—trade$326,484$349,529$(23,045)Accounts receivable—affiliates2,5642,564—Inventories107,430107,430—Prepaid expenses and other current assets68,32268,322—Property, plant and equipment:Vehicles (3 years)327791(464)Crude oil tanks and related equipment (3—40 years)83,79777,4296,368Information technology equipment (3—7 years)4,0494,0463Buildings and leasehold improvements (3—40 years)7,8177,716101Land6,4276,427—Tank bottoms (indefinite life)16,93015,2301,700Other (7 years)162170(8)Construction in progress7,1807,190(10)Goodwill (1)342,769359,169(16,400)Intangible assets:Customer relationships (10—20 years)107,950101,6006,350Lease agreements (1—5 years)8,7008,700—Pipeline capacity rights (30 years)7,800—7,800Investments in unconsolidated entities183,000178,0005,000Other noncurrent assets2,2879,918(7,631)Accounts payable—trade(342,792)(342,792)—Accounts payable—affiliates(2,585)(2,585)—Accrued expenses and other payables(49,447)(70,999)21,552Advance payments received from customers(10,667)(10,667)—Other noncurrent liabilities(46,056)(44,740)(1,316)Fair value of net assets acquired$832,448$832,448$— (1) Of this goodwill, $302.8 million was allocated to our crude oil logistics segment, $36.0 million was allocated to our refined products andrenewables segment, and $4.0 million was allocated to our liquids segment. 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. F-25 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 acquisition-date market conditions, we recorded a liability of $15.9 million related to these lease commitments in the acquisition accounting, andwe amortized $8.7 million of this balance as a reduction to cost of sales during the year ended March 31, 2015. We will amortize the remainder of thisliability over the term of the leases. The future amortization of this liability is shown below (in thousands): Year Ending March 31, 2016$4,0402017360 Certain personnel who were employees of Gavilon Energy were entitled to a bonus, half of which was payable upon successful completion of thebusiness combination and the remainder of which was paid in December 2014. We recorded this as compensation expense over the vesting period. Werecorded expense of $6.5 million during the year ended March 31, 2015 related to these bonuses. 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.During the year ended March 31, 2015, we completed the acquisition accounting for this business combination. The following table presents the finalcalculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for this acquisition: Estimated at March 31, Final2014 Change(in thousands)Accounts receivable—trade$6,837$7,268$(431)Inventories154154—Prepaid expenses and other current assets402402—Property, plant and equipment:Vehicles (5—10 years)8,1438,157(14)Water treatment facilities and equipment (3—30 years)23,17323,173—Buildings and leasehold improvements (7—30 years)2,1982,198—Land710710—Other (3—5 years)5353—Goodwill90,14489,699445Intangible assets:Customer relationships (8—10 years)110,000110,000—Non-compete agreements (3 years)2,0002,000—Accounts payable—trade(6,469)(6,469)—Accrued expenses and other payables(992)(992)—Other noncurrent liabilities(64)(64)—Fair value of net assets acquired$236,289$236,289$— 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. F-26 Other Water Solutions Acquisitions During the year ended March 31, 2014, we completed two 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 $151.6 million of cash, net of cash acquired, in exchange for theseassets and operations. During the year ended March 31, 2015, we completed the acquisition accounting for these business combinations. The following tablepresents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions: Estimated at March 31, Final2014 Change(in thousands)Accounts receivable—trade$2,146$2,146$—Inventories192192—Prepaid expenses and other current assets62611Property, plant and equipment:Vehicles (5—10 years)7690(14)Water treatment facilities and equipment (3—30 years)11,71714,394(2,677)Buildings and leasehold improvements (7—30 years)3,2781,9061,372Land2072061Other (3—5 years)1212—Goodwill49,06747,7501,317Intangible assets:Customer relationships (8—10 years)72,00072,000—Trade names (indefinite life)3,3253,325—Non-compete agreements (3 years)260260—Water facility development agreement (5 years)14,00014,000—Water facility option agreement2,5002,500—Accounts payable—trade(119)(119)—Accrued expenses and other payables(293)(293)—Other noncurrent liabilities(64)(64)—Fair value of net assets acquired$158,366$158,366$— 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 saltwater disposal facility that was under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to thisoption agreement. On March 1, 2014, we purchased the saltwater disposal facility for additional cash consideration of $3.8 million. In addition, as part of one of these business combinations, we entered into a development agreement that provides us a right to purchase watertreatment and disposal facilities that may be developed by the seller through June 2018. On March 1, 2014, we purchased our first water treatment anddisposal facility pursuant to the development agreement for $21.0 million. F-27 During the year ended March 31, 2015, we completed the acquisition accounting for these business combinations. The following table presents thefinal calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions: Estimated at March 31, Final2014 Change(in thousands)Accounts receivable—trade$124$245$(121)Inventories119197(78)Property, plant and equipment:Water treatment facilities and equipment (3—30 years)10,53910,540(1)Buildings and leasehold improvements (7—30 years)1,1301,130—Land213213—Other (3—5 years)11—Goodwill15,44315,281162Accounts payable—trade(232)(263)31Accrued expenses and other payables—(7)7Other noncurrent liabilities(50)(50)—Fair value of net assets acquired$27,287$27,287$— Crude Oil Logistics Acquisitions During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our crude oil logistics operations in Texasand Oklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, inexchange for these assets and operations. During the year ended March 31, 2015, we completed the acquisition accounting for these business combinations.The following table presents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions: Estimated at March 31, Final2014 Change(in thousands)Accounts receivable—trade$1,221$1,235$(14)Inventories1,0211,021—Prepaid expenses and other current assets58544Property, plant and equipment:Vehicles (5—10 years)2,9802,9773Crude oil tanks and related equipment (2—30 years)3,8223,462360Barges and towboats (20 years)20,06520,065—Buildings and leasehold improvements (5—30 years)58280(222)Other (3—5 years)57534Goodwill30,73037,867(7,137)Intangible assets:Customer relationships (3 years)13,3006,3007,000Non-compete agreements (3 years)3535—Trade names (indefinite life)530530—Accounts payable—trade(521)(665)144Accrued expenses and other payables(266)(124)(142)Fair value of net assets acquired$73,090$73,090$— F-28 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. During the year ended March 31, 2015, we completedthe acquisition accounting for these business combinations. The final calculation of the fair values of the assets acquired and liabilities assumed for theseacquisitions did not materially change from the previous estimates of the fair values of the assets acquired and liabilities assumed for these acquisitions. Note 5—Property, Plant and Equipment Our property, plant and equipment consists of the following: March 31,Description and Estimated Useful Lives2015 2014(in thousands)Natural gas liquids terminal and storage assets (2—30 years)$132,851$75,141Refined products terminal assets and equipment (20 years)403,609—Retail propane equipment (2—30 years)181,140160,758Vehicles and railcars (3—25 years)180,679152,187Water treatment facilities and equipment (3—40 years)317,317178,307Crude oil tanks and related equipment (2—40 years)109,909101,853Barges and towboats (5—40 years)59,84852,217Information technology equipment (3—7 years)34,91520,771Buildings and leasehold improvements (3—40 years)98,98961,255Land107,09830,242Tank bottoms62,65615,103Other (3—30 years)34,41517,337Construction in progress96,92280,2411,820,348945,412Accumulated depreciation(202,959)(109,564)Net property, plant and equipment$1,617,389$835,848 Depreciation expense was $105.7 million, $59.9 million and $39.2 million during the years ended March 31, 2015, 2014 and 2013, respectively.During the years ended March 31, 2015 and 2014, we capitalized $0.1 million and $0.7 million of interest expense, respectively. We did not capitalize anyinterest expense during the year ended March 31, 2013. Product volumes required for the operation of storage tanks, known as tank bottoms, are recorded athistorical cost. We recover tank bottoms when we no longer use the storage tanks or the storage tanks are removed from service. The following table summarizes the tank bottoms included in the table above at March 31, 2015 (in thousands): Product Volume Book Value Gasoline (barrels)219$25,710Crude oil (barrels)18416,835Diesel (barrels)12415,153Renewables (barrels)414,220Other504738Total$62,656 Note 6—Goodwill The changes in the balance of goodwill were as follows: Year Ended March 31, 20152014 2013 (in thousands) Beginning of period, as retrospectively adjusted$1,085,393$555,220$167,245Acquisitions (Note 4)327,350530,173387,975Disposals (Note 14)(9,982)——End of period, as retrospectively adjusted$1,402,761$1,085,393$555,220 F-29 Goodwill by reportable segment is as follows: March 31,2015 2014(in thousands)Crude oil logistics$579,846$579,846Water solutions401,656264,127Liquids234,80391,135Retail propane122,382114,285Refined products and renewables64,07436,000Total$1,402,761$1,085,393 Note 7—Intangible Assets Our intangible assets consist of the following: March 31, 2015 March 31, 2014AmortizableGross Carrying Accumulated Gross Carrying AccumulatedLivesAmount Amortization Amount Amortization(in thousands)Amortizable—Customer relationships3–20 years$921,418$159,215$710,755$83,261Pipeline capacity rights30 years119,6362,5717,800—Water facility development agreement5 years14,0004,90014,0002,100Executory contracts and other agreements2–10 years23,92018,38723,92013,190Non-compete agreements2–10 years26,66210,40814,1616,388Trade names2–12 years15,4397,56915,4893,081Debt issuance costs5–10 years55,16517,46744,0898,708Total amortizable1,176,240220,517830,214116,728Non-amortizable—Customer commitments310,000———Trade names22,620—22,620—Total non-amortizable332,620—22,620— Total$1,508,860$220,517$852,834$116,728 The weighted-average remaining amortization period for intangible assets is approximately 12 years. Amortization expense is as follows: Year Ended March 31,Recorded In20152014 2013(in thousands)Depreciation and amortization$88,262$60,855$29,657Cost of sales7,7676,1725,285Interest expense8,7595,7273,375Loss on early extinguishment of debt——5,769Total$104,788$72,754$44,086 F-30 Expected amortization of our intangible assets, exclusive of assets that are not yet amortizable, is as follows (in thousands): Year Ending March 31,2016$111,3562017104,6332018100,654201991,799202084,791Thereafter462,490Total$955,723 Note 8—Long-Term Debt Our long-term debt consists of the following: March 31, 2015 2014 (in thousands)Revolving credit facility —Expansion capital borrowings$702,500$532,500Working capital borrowings688,000389,5005.125% Notes due 2019400,000—6.875% Notes due 2021450,000450,0006.650% Notes due 2022250,000250,000TLP credit facility250,000—Other long-term debt9,27114,9142,749,7711,636,914Less: Current maturities4,4727,080Long-term debt$2,745,299$1,629,834 Credit Agreement We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes arevolving credit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansionprojects (the “Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). At March 31, 2015, ourRevolving Credit Facility had a total capacity of $2.296 billion. The Expansion Capital Facility had a total capacity of $858.0 million for cash borrowings at March 31, 2015. At that date, we had outstandingborrowings of $702.5 million on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.438 billion for cash borrowings andletters of credit at March 31, 2015. At that date, we had outstanding borrowings of $688.0 million and outstanding letters of credit of $108.6 million on theWorking Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base,” as defined in the CreditAgreement, 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 prepay outstanding borrowings under the CreditAgreement without incurring any penalties, and prepayments 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, 2015, all borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at March 31,2015 of 2.18%, calculated as the LIBOR rate of 0.18% plus a margin of 2.0%. At March 31, 2015, the interest rate in effect on letters of credit was 2.25%.Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused capacity. F-31Table of Contents 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 at any quarter end. The leverage coverage ratio in our Credit Agreement excludes TLP’s debt. At March 31, 2015, ourleverage ratio was approximately 3.2 to 1. The Credit Agreement also specifies that our interest coverage ratio, as defined in the Credit Agreement, cannot beless than 2.75 to 1 at any quarter end. At March 31, 2015, our interest coverage ratio was approximately 5.9 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 eventsof default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by thePartnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcyor insolvency. At March 31, 2015, we were in compliance with the covenants under the Credit Agreement. 2019 Notes On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”). We received net proceeds of $393.5 million, afterthe initial purchasers’ discount of $6.0 million and offering costs of $0.5 million. The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notesprior to the maturity date, although we would be required to pay a premium for early redemption. The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certainof our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving CreditFacility. The indenture governing the 2019 Notes contains various customary covenants, including, without limitation, limitations on fundamental changesand limitations on indebtedness and liens. Our obligations under the indenture may be accelerated following certain events of default (subject to applicablecure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debtagreements, or (iii) certain events of bankruptcy or insolvency. At March 31, 2015, we were in compliance with the covenants under the indenture governing the 2019 Notes. 2021 Notes On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”). We received net proceeds of $438.4 million,after the initial purchasers’ discount of $10.1 million and offering costs of $1.5 million. The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021Notes prior to the maturity date, although we would be required to pay a premium for early redemption. The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certainof our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving CreditFacility. The indenture governing the 2021 Notes contains various customary covenants, including, without limitation, limitations on fundamental changesand limitations on indebtedness and liens. Our obligations under the indenture may be accelerated following certain events of default (subject to applicablecure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debtagreements, or (iii) certain events of bankruptcy or insolvency. At March 31, 2015, we were in compliance with the covenants under the indenture governing the 2021 Notes. 2022 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 “2022 Notes”). The 2022 Notes bear interest at a fixed rate of 6.65%, which is payable quarterly. The 2022 Notes arerequired to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. Wehave the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of ourassets and rank equal in priority with borrowings under the Credit Agreement. F-32Table of Contents 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 similar leverage ratio and interest coverage ratio requirements to those of our Credit Agreement, which is describedabove. 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) nonpayment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the 2022 Notes,(iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtednessunpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the NotePurchase Agreement, the 2022 Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certainevents of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% inaggregate principal amount of the then outstanding 2022 Notes of any series may declare all of the 2022 Notes of such series to be due and payableimmediately. At March 31, 2015, we were in compliance with the covenants under the Note Purchase Agreement. TLP Credit Facility TLP is party to a credit agreement with a syndicate of banks that provides for a revolving credit facility (the “TLP Credit Facility”). The TLP CreditFacility provides for a maximum borrowing line of credit equal to the lesser of (i) $400 million and (ii) 4.75 times Consolidated EBITDA (as defined in theTLP Credit Facility). The terms of the TLP Credit Facility include covenants that restrict TLP’s ability to make cash distributions, acquisitions andinvestments, including investments in joint ventures. TLP may make distributions of cash to the extent of TLP’s “available cash” as defined in TLP’spartnership agreement. TLP may make acquisitions and investments that meet the definition of “permitted acquisitions”; “other investments” which may notexceed 5% of “consolidated net tangible assets”; and additional future “permitted JV investments” up to $125 million, which may include additionalinvestments in BOSTCO. The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date of July 31,2018. The following table summarizes our basis in the assets and liabilities of TLP at March 31, 2015, inclusive of the impact of our acquisitionaccounting for the business combination with TransMontaigne (in thousands): Cash and cash equivalents$918Accounts receivable—trade9,069Accounts receivable—affiliates583Inventories1,361Prepaid expenses and other current assets1,410Property, plant and equipment, net475,506Goodwill28,074Intangible assets, net72,295Investments in unconsolidated affiliates255,073Other noncurrent assets2,458Accounts payable—trade(6,565)Accounts payable—affiliates(76)Net intercompany payable(1,965)Accrued expenses and other payables(8,715)Advanced payments received from customers(146)Long-term debt(250,000)Other noncurrent liabilities(3,541)Net assets$575,739 TLP may elect to have loans under the TLP Credit Facility bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% dependingon the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLPalso pays a commitment fee on the unused amount of commitments, ranging F-33Table of Contents from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. For the period from July 1, 2014 to March 31, 2015, the weighted-average interest rate on borrowings under the TLP Credit Facility was approximately 2.10%. TLP’s obligations under the TLP Credit Facility are secured by afirst priority security interest in favor of the lenders in the majority of TLP’s assets, including TLP’s investments in unconsolidated entities. At March 31,2015, TLP had outstanding borrowings under the TLP Credit Facility of $250 million and no outstanding letters of credit. The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization,compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults,covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratiotest (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) in the event TLP issues senior unsecured notes, and (iii) aminimum interest coverage ratio test (not less than 3.0 times). These financial covenants are based on a defined financial performance measure within the TLPCredit Facility known as “Consolidated EBITDA.” TLP’s Credit Facility is non-recourse to NGL. Other Long-Term Debt We have executed various noninterest bearing notes payable, primarily related to non-compete agreements entered into in connection withacquisitions of businesses. We also have certain notes payable related to equipment financing. Debt Maturity Schedule The scheduled maturities of our long-term debt are as follows at March 31, 2015: Revolving TLP Other Credit20192021 2022 Credit Long-Term Year Ending March 31,FacilityNotesNotes Notes Facility Debt Total(in thousands)2016$—$—$—$—$—$4,473$4,4732017—————2,5672,5672018———25,000—1,62626,62620191,390,500——50,000250,0003621,690,8622020—400,000—50,000—105450,105Thereafter——450,000125,000—138575,138Total$1,390,500$400,000$450,000$250,000$250,000$9,271$2,749,771 Previous Credit Facility On June 19, 2012, we made a principal payment of $306.8 million to retire a then-existing revolving credit facility. Upon retirement of this facility,we wrote off the portion of the debt issuance cost intangible asset that had not yet been amortized. This expense is reported as “Loss on early extinguishmentof debt” in our consolidated statement of operations for the year ended March 31, 2013. Note 9—Income Taxes We qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reportshis or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reportingpurposes 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 in Canada, and our operations in Texas are subject to a state franchise taxthat is calculated based on revenues net of cost of sales. Our fiscal years 2011 to 2014 generally remain subject to examination by federal, state, andCanadian tax authorities. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities arerecognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities andtheir respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporarydifferences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date. F-34Table of Contents We acquired TransMontaigne Inc. on July 1, 2014. TransMontaigne Inc. and certain of its subsidiaries were taxable corporations until we convertedthem to non-taxable limited liability companies on December 31, 2014. The following table is a rollforward of the income tax liability associated with theseentities (in thousands): Acquisition-date deferred tax liability$28,530Income tax benefit (July 1, 2014 to December 31, 2014)(6,276)Tax payments(21,397)Current tax liability at March 31, 2015$857 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 routinelygenerate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income foreach of the calendar years since our IPO. We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, wedetermine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals orlitigation, 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 ofbenefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in our consolidatedfinancial statements at March 31, 2015 or 2014. 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 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 November 1, 2012 acquisition of Pecos). During August 2013, the customer notified us that it intended to withhold payment due for servicesperformed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer did not dispute thevalidity of the amounts billed for services performed during this time frame. During September 2014, we reached an agreement with the former customer whereby the former customer agreed to pay us an agreed-upon amount todismiss its claims against us, in return for which we agreed to dismiss our claims against the former customer. We did not record a gain or loss uponsettlement, as the amount we received approximated the amount we had recorded as receivable from the customer. Contractual Disputes During the year ended March 31, 2015, we settled two separate contractual disputes and recorded $5.5 million of proceeds to other income in ourconsolidated statement of operations. Also during the year ended March 31, 2015, we offered to settle another contractual dispute, and recorded $1.2 millionto other expense as an estimate of the probable loss. Environmental Matters Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are insubstantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there canbe no assurance that significant costs will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmentallaws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantialcosts. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and thehandling, storage, use, and F-35Table of Contents disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from suchevents. However, some risk of environmental or other damage is inherent in our business. Asset Retirement Obligations We have recorded a liability of $3.9 million at March 31, 2015 for asset retirement obligations. This liability is related to facilities for which wehave contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired. In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certainother assets. We do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration theestimated lives of our facilities, is material to our consolidated financial position or results of operations. Operating Leases We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment.Future minimum lease payments under these agreements at March 31, 2015 are as follows (in thousands): Year Ending March 31,2016$119,8172017102,394201887,302201963,205202053,423Thereafter115,704Total$541,845 Rental expense relating to operating leases was $125.5 million, $98.3 million, and $84.2 million during the years ended March 31, 2015, 2014, and2013, respectively. Pipeline Capacity Agreements We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthlyshipping capacity on the pipelines. In exchange, we are obligated to pay the minimum shipping fees in the event actual shipments are less than our allottedcapacity. Future minimum throughput payments under these agreements at March 31, 2015 are as follows (in thousands): Year Ending March 31,2016$122,052201781,935201882,016201981,222202053,511Thereafter90,972Total$511,708 F-36Table of Contents 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 settlethe contracts with inventory. At March 31, 2015, we had the following such commitments outstanding: Volume Value (in thousands) Purchase commitments:Natural gas liquids fixed-price (gallons)57,792$35,476Natural gas liquids index-price (gallons)659,603352,563Crude oil index-price (barrels)8,450375,699Sale commitments:Natural gas liquids fixed-price (gallons)104,15377,674Natural gas liquids index-price (gallons)223,234184,866Crude oil fixed-price (barrels)1,58079,242Crude oil index-price (barrels)6,684321,863 We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do notrecord the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contractsin the table above may have offsetting derivative contracts (described in Note 12) or inventory positions (described in Note 2). Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded atfair value in our consolidated balance sheet and are not included in the table above. These contracts are included in the derivative disclosures in Note 12, andrepresent $33.2 million of our prepaid expenses and other current assets and $26.6 million of our accrued expenses and other payables at March 31, 2015. Note 11—Equity Partnership Equity The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Prior toAugust 2014, the Partnership’s limited partner interest also included subordinated units. The subordination period ended in August 2014, at which time allremaining subordinated units were converted into common units on a one-for-one basis. Our general partner is not obligated to make any additional capitalcontributions or to guarantee or pay any of our debts and obligations. F-37Table of Contents Common Units Issued in Business Combinations We issued common units as partial consideration for several acquisitions. These are summarized below: March 31, 2013—High Sierra combination20,703,510Retail propane combinations850,676Crude oil logistics and water solutions combinations516,978Pecos combination1,834,414Third Coast combination344,680Total24,250,258March 31, 2014—Water solutions combinations222,381Crude oil logistics combinations175,211OWL combination2,463,287Total2,860,879March 31, 2015—Retail propane combinations132,100Natural gas liquids storage combination7,396,973Water solutions combinations1,322,032Total8,851,105 In connection with the completion of certain of these acquisitions, we amended our registration rights agreement, which provides for certainregistration rights for certain holders of our common units. Equity Issuances The following table summarizes our equity issuances for fiscal years 2014 and 2015 (in millions, except unit amounts). There were no equityissuances during fiscal year 2013. Number of Underwriting Type ofCommon Units Gross Discounts and Offering NetIssuance DateOfferingIssued Proceeds Commissions Costs ProceedsMarch 11, 2015Public Offering6,250,000$172.3$1.4$0.2$170.7June 23, 2014Public Offering8,767,100383.212.30.5370.4December 2, 2013Private Placement8,110,848240.0—4.9235.1September 25, 2013Public Offering4,100,000132.85.00.2127.6July 5, 2013Public Offering10,350,000300.212.00.7287.5 Our Distribution Policy Our general partner has adopted a cash distribution policy that requires us to pay a quarterly distribution to unitholders as of the record date to theextent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the generalpartner and its affiliates, referred to as “available cash.” The general partner will also receive, in addition to distributions on its 0.1% general partner interest,additional distributions based on the level of distributions to the limited partners. These distributions are referred to as “incentive distributions” or “IDRs.”Our general partner currently holds the IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnershipagreement. F-38Table of Contents The following table illustrates the percentage allocations of available cash from operating surplus between our unitholders and our general partnerbased on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentage interests ofour general partner and our unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in thecolumn “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. Thepercentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distributionamounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% generalpartner interest, and assume that our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has nottransferred its IDRs. Marginal Percentage Interest In Total Quarterly Distributions Distribution Per Unit UnitholdersGeneral Partner Minimum 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$0.506250 51.9%48.1% The following table summarizes the distributions declared subsequent to our IPO: Amount Amount Paid To Amount Paid ToDate DeclaredRecord DateDate Paid Per Unit Limited Partners General 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 19, 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 24, 2014February 4, 2014February 14, 20140.531342,1504,283April 24, 2014May 5, 2014May 15, 20140.551343,7375,754July 24, 2014August 4, 2014August 14, 20140.588852,0369,481October 24, 2014November 4, 2014November 14, 20140.608853,90211,141January 26, 2015February 6, 2015February 13, 20150.617554,68411,860April 24, 2015May 5, 2015May 15, 20150.625059,65113,446 F-39Table of Contents 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: Equivalent UnitsRecord DateNot EligibleOctober 31, 20114,000,000February 3, 20127,117,031April 30, 20123,932,031August 3, 201217,862,470October 29, 2012516,978February 4, 20131,202,085November 4, 2013979,886February 6, 2015132,100May 5, 20158,352,904 TLP’s Distribution Policy TLP’s partnership agreement requires it to pay a quarterly distribution to unitholders as of the record date to the extent TLP has sufficient cash fromoperations after establishment of cash reserves and payment of fees and expenses, including payments to TLP’s general partner and its affiliates, referred to as“available cash.” TLP’s general partner will also receive, in addition to distributions on its 2.0% general partner interest, additional distributions based on thelevel of distributions to the limited partners. These distributions are referred to as “incentive distributions.” TLP’s general partner currently holds theincentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in TLP’s partnership agreement. The following table illustrates the percentage allocations of available cash from operating surplus between TLP’s unitholders and TLP’s generalpartner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentageinterests of TLP’s general partner and TLP’s unitholders in any available cash from operating surplus TLP distributes up to and including the correspondingamount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus TLP distributes reaches the next target distributionlevel, if any. The percentage interests shown for TLP’s unitholders and TLP’s general partner for the minimum quarterly distribution are also applicable toquarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for TLP’s general partnerinclude its 2.0% general partner interest, and assume that TLP’s general partner has contributed any additional capital necessary to maintain its 2.0% generalpartner interest and has not transferred its incentive distribution rights. Marginal Percentage Interest In Total Quarterly Distributions Distribution Per Unit Unitholders General Partner Minimum quarterly distribution$0.4098%2%First target distributionabove$0.40up to$0.4498%2%Second target distributionabove$0.44up to$0.5085%15%Third target distributionabove$0.50up to$0.6075%25%Thereafterabove$0.6050%50% The following table summarizes the distributions declared by TLP subsequent to our acquisition of general and limited partner interests in TLP(exclusive of the distribution declared in July 2014, the proceeds of which we remitted to the former owners of TransMontaigne, pursuant to agreementsentered into at the time of the business combination): Amount Amount Paid Amount Paid ToDate DeclaredRecord DateDate Paid Per Unit To NGL Other Partners (in thousands) (in thousands)October 13, 2014October 31, 2014November 7, 2014$0.6650$4,010$8,614January 8, 2015January 30, 2015February 6, 20150.66504,0108,614April 13, 2015April 30, 2015May 7, 20150.66504,0078,617 F-40Table of Contents Equity-Based Incentive Compensation Our general partner has adopted a long-term incentive plan (“LTIP”), which allows for the issuance of equity-based compensation. Our generalpartner has granted certain restricted units to employees and directors, which vest in tranches, subject to the continued service of the recipients. The awardsmay also vest in the event of a change in control, at the discretion of the board of directors. No distributions accrue to or are paid on the restricted unitsduring the vesting period. The restricted units include awards that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”).The restricted units also include awards that are contingent both on the continued service of the recipients through the vesting date and also on theperformance of our common units relative to other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”). The following table summarizes the Service Award activity during the years ended March 31, 2015, 2014 and 2013: Unvested Service Award 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 Service Award 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 Service Award units at March 31, 20141,311,100Units granted2,093,139Units vested and issued(586,010)Units withheld for employee taxes(354,829)Units forfeited(203,000)Unvested Service Award units at March 31, 20152,260,400 The scheduled vesting of our Service Award units is summarized below: Year Ending March 31, Number of Units2016739,5002017743,2002018679,200201978,500202020,000Unvested Service Award units at March 31, 20152,260,400 We record the expense for the first tranche of each Service Award on a straight-line basis over the period beginning with the grant date of the awardsand ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of theprevious tranche and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. 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 ofdistribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make aboutfuture distribution growth. F-41Table of Contents We estimate that the future expense we will record on the unvested Service Award units at March 31, 2015 will be as follows (in thousands), aftertaking into consideration an estimate of forfeitures of approximately 129,000 units. For purposes of this calculation, we used the closing price of our commonunits on March 31, 2015, which was $26.23. Year Ending March 31, 2016$26,304201716,93820185,36920191,0332020105Total$49,749 Following is a rollforward of the liability related to the Service Award units, which is reported within accrued expenses and other payables in ourconsolidated balance sheets (in thousands): Balance at March 31, 2012$—Expense recorded10,138Value of units vested and issued(3,657)Taxes paid on behalf of participants(1,438)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, 201410,012Expense recorded32,767Value of units vested and issued(23,134)Taxes paid on behalf of participants(13,491)Balance at March 31, 2015$6,154 The weighted-average fair value of the Service Award units at March 31, 2015 was $22.61 per common unit, which was calculated as the closingprice of the common units on March 31, 2015, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period.The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that amarket participant might make about future distribution growth. During April 2015, our general partner granted Performance Award units to certain employees. The maximum number of units that could vest onthese Performance Awards for each vesting tranche is summarized below: Maximum PerformanceVesting DateAward UnitsJuly 1, 2015681,382July 1, 2016679,382July 1, 2017641,382Total2,002,146 The number of Performance Award units that will vest is contingent on the performance of our common units relative to the performance of the otherentities in the Index. Performance will be calculated based on the return on our common units (including changes in the market price of the common unitsand distributions paid during the performance period) relative to the returns on the common units of the other entities in the Index. Performance will bemeasured over the following periods: Vesting Date of Tranche Performance Period for Tranche July 1, 2015July 1, 2012 through June 30, 2015July 1, 2016July 1, 2013 through June 30, 2016July 1, 2017July 1, 2014 through June 30, 2017 F-42Table of Contents The percentage of the maximum Performance Award units that will vest will depend on the percentage of entities in the Index that NGL outperforms,as summarized in the table below: Percentage of Entities in thePercentage of MaximumIndex that NGL OutperformsPerformance Award Units to VestLess than 50%0%50%–75%25%–50%75%–90%50%–100%Greater than 90%100% Beginning in fiscal year 2016, we will record the expense for each of the three tranches on a straight-line basis over the period beginning with theApril 2015 grant date and ending with the vesting date. At each balance sheet date, we will adjust the cumulative expense recorded using the estimated fairvalue of the awards at the balance sheet date. We will calculate the fair value of the awards using a Monte Carlo simulation. The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding commonunits. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common units immediatelyafter each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Unitswithheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, when an award is forfeited, canceled,exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under theLTIP. At March 31, 2015, approximately 7.1 million common 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 assets and liabilities (excludingderivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature. Commodity Derivatives The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported in our consolidated balancesheet at March 31, 2015: DerivativeDerivativeAssetsLiabilities(in thousands)Level 1 measurements$83,779$(3,969)Level 2 measurements34,963(28,764)118,742(32,733) Netting of counterparty contracts (1)(1,804)1,804Cash collateral provided (held)(56,660)2,979Commodity derivatives on consolidated balance sheet$60,278$(27,950) (1) Relates to commodity derivative assets and liabilities that are expected to be net settled on an exchange or through a master nettingarrangement with the counterparty. F-43Table of Contents The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported in our consolidated balancesheet at March 31, 2014: Derivative Derivative Assets Liabilities (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)4,347Net cash collateral provided456—Commodity derivatives on consolidated balance sheet$50,704$(42,214) (1) Relates to commodity derivative assets and liabilities that are expected to be net settled on an exchange or through a master nettingarrangement with the counterparty. Our commodity derivative assets and liabilities are reported in the following accounts in our consolidated balance sheets: March 31, 2015 2014 (in thousands) Prepaid expenses and other current assets$60,278$50,704Accrued expenses and other payables(27,950)(42,214)Net commodity derivative asset$32,328$8,490 F-44Table of Contents The following table summarizes our open commodity derivative contract positions at March 31, 2015 and 2014. We do not account for thesederivatives as hedges. Net Long (Short) Fair Value Notional of Units Net AssetsContractsSettlement Period (Barrels) (Liabilities) (in thousands)At March 31, 2015—Cross-commodity (1)April 2015–March 201698$(105)Crude oil fixed-price (2)April 2015–June 2015(1,113)(171)Crude oil index-price (3)April 2015–July 20157511,835Propane fixed-price (4)April 2015–December 2016193(2,842)Refined products fixed-price (4)April 2015–December 2015(3,005)84,996OtherApril 2015–December 20152,29686,009Net cash collateral held(53,681)Net commodity derivatives on consolidated balance sheet$32,328At March 31, 2014—Cross-commodity (1)April 2014–March 2015140$(1,876)Crude oil fixed-price (2)April 2014–March 2015(1,600)(2,796)Crude oil index-price (3)April 2014–December 20153,5986,099Propane fixed-price (4)April 2014–March 2015601,753Refined products fixed-price (4)April 2014–July 2014732560Renewables fixed-price (4)April 2014–July 20141064,084OtherApril 20142108,034Net cash collateral provided456Net commodity derivatives on consolidated balance sheet$8,490 (1) Cross-commodity—We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to differentcommodity price indices. The contracts listed in this table as “Cross-commodity” represent derivatives we have entered into as an economichedge 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 tobe placed by our customers. The contracts listed in this table as “Crude oil fixed-price” represent derivatives we have entered into as aneconomic hedge against the risk that crude oil prices will decline while we are holding the inventory. (3) Crude oil index-price—Our crude oil logistics segment may purchase or sell crude oil where the underlying contract pricing mechanisms aretied to different crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month.The contracts listed in this table as “Crude oil index-price” represent derivatives we have entered into as an economic hedge against the risk ofone crude oil index moving relative to another crude oil index. (4) Commodity fixed-price—We may have fixed price physical obligations, including inventory, offset by floating price physical sales or havefloating price physical purchases offset by fixed price physical sales. The contracts listed in the this table as “fixed-price” represent derivativeswe have entered into as an economic hedge against the risk of mismatches between fixed and floating price physical obligations. F-45Table of Contents We recorded the following net gains (losses) from our commodity derivatives to cost of sales (in thousands): Year Ending March 31, 2015$219,4212014(43,655)2013(4,376) 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 andthe use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty. We may enter into industry standard master netting agreements and may enter into cash collateral agreements requiring the counterparty to 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. Failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded in our consolidatedbalance sheets 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 31,2015, we had $1.4 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.18%. A change in interest rates of 0.125% wouldresult in an increase or decrease of our annual interest expense of $1.7 million, based on borrowings outstanding at March 31, 2015. The TLP Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31, 2015,TLP had $250.0 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.67%. A change in interest rates of 0.125% would result in anincrease or decrease in TLP’s annual interest expense of $0.3 million, based on borrowings outstanding at March 31, 2015. Fair Value of Fixed-Rate Notes The following table provides estimates of the fair values of our fixed-rate notes at March 31, 2015 (in thousands): 5.125% Notes due 2019$396,0006.875% Notes due 2021472,5006.650% Notes due 2022253,475 For the 2019 Notes and the 2021 Notes, the fair value estimates were developed based on publicly traded quotes. These fair value estimates wouldbe classified as Level 1 in the fair value hierarchy. For the 2022 Notes, the fair value estimate was developed using observed yields on publicly traded notes issued by other entities, adjusted fordifferences in the key terms of those notes and the key terms of our notes (examples include differences in the tenor of the debt, credit standing of the issuer,whether the notes are publicly traded, and whether the notes are secured or unsecured). This fair value estimate would be classified as Level 3 in the fair valuehierarchy. F-46Table of Contents Note 13—Segments Certain financial data related to our segments is shown below. Transactions between segments are recorded based on prices negotiated between thesegments. Our liquids and retail propane segments each consist of two divisions, which are organized based on the location of the operations. Our refinedproducts and renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition ofTransMontaigne. F-47Table of Contents Items labeled “corporate and other” in the table below include the operations of a compressor leasing business that we sold in February 2014 andcertain natural gas marketing operations that we acquired in our December 2013 acquisition of Gavilon Energy and wound down during fiscal year 2014. The“corporate and other” category also includes certain corporate expenses that are incurred and are not allocated to the reportable segments. This data isincluded to reconcile the data for the reportable segments to data in our consolidated financial statements. Year Ended March 31, 2015 2014 2013 (in thousands) Revenues:Crude oil logistics—Crude oil sales$6,609,685$4,559,923$2,322,706Crude oil transportation and other55,53536,46916,442Water solutions—Service fees105,68258,16134,792Recovered hydrocarbons81,76267,62719,542Water transportation10,76017,3127,893Other revenues1,838——Liquids—Propane sales1,263,1131,632,948841,448Other product sales1,111,4341,231,965858,276Other revenues31,29431,06233,954Retail propane—Propane sales347,575388,225288,410Distillate sales106,037127,672106,192Other revenues35,58535,91835,856Refined products and renewables—Refined products sales6,684,0451,180,895—Renewables sales473,885176,781—Service fees74,842——Corporate and other1,916437,7134,233Elimination of intersegment sales(192,931)(283,397)(151,977)Total revenues$16,802,057$9,699,274$4,417,767 Depreciation and Amortization:Crude oil logistics$38,626$22,111$9,176Water solutions73,61855,10520,923Liquids13,51311,01811,085Retail propane31,82728,87825,496Refined products and renewables32,948625—Corporate and other3,4173,0172,173Total depreciation and amortization$193,949$120,754$68,853 Operating Income (Loss):Crude oil logistics$(35,832)$678$34,236Water solutions45,03110,3178,576Liquids45,07271,88830,336Retail propane64,07561,28546,869Refined products and renewables54,5676,514—Corporate and other(85,802)(44,117)(32,710)Total operating income$87,111$106,565$87,307 F-48Table of Contents The following table summarizes additions to property, plant and equipment for each segment. This information has been prepared on the accrualbasis, and includes property, plant and equipment acquired in acquisitions. Year Ended March 31,2015 2014 2013(in thousands)Additions to property, plant and equipment:Crude oil logistics$58,747$204,642$89,860Water solutions186,007100,877137,116Liquids114,18052,56015,129Retail propane35,60224,43066,933Refined products and renewables573,9541,238—Corporate and other1,2867,24217,858Total$969,776$390,989$326,896 The following tables summarize long-lived assets (consisting of net property, plant and equipment, net intangible assets, and goodwill) and totalassets by segment: March 31,2015 2014(in thousands)Total assets:Crude oil logistics$2,337,188$1,710,776Water solutions1,185,929876,305Liquids713,547556,152Retail propane542,476541,832Refined products and renewables1,668,836317,726Corporate and other99,525144,840Total$6,547,501$4,147,631 Long-lived assets, net:Crude oil logistics$1,327,538$970,986Water solutions1,119,794849,070Liquids534,560275,836Retail propane467,652438,324Refined products and renewables808,75775,170Corporate and other50,19247,961Total$4,308,493$2,657,347 Note 14—Disposals and Impairments During the year ended March 31, 2015, we sold a natural gas liquids terminal and recorded a loss in our consolidated statement of operations of$29.9 million, which included a loss on property, plant and equipment of $21.7 million and a loss of $8.2 million on goodwill allocated to the assets sold.This loss is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations. During the year ended March 31, 2015, we sold the water transportation business of our water solutions segment and recorded a loss in ourconsolidated statement of operations of $4.0 million, which included a loss on property, plant and equipment of $2.2 million and a loss of $1.8 million ongoodwill allocated to the assets sold. This loss is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations. During the year ended March 31, 2015, we recorded a loss on abandonment of $3.1 million related to the property, plant and equipment of waterdisposal facilities that we have retired. This loss is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations. F-49Table of Contents 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 transportationcontracts in the acquisition accounting, and we amortized $6.0 million of this balance as a reduction to cost of sales during the period from the acquisitiondate through the date we assigned the contracts. We also assigned all forward purchase and sale contracts and all financial derivative contracts, and therebywound down the natural gas business. Our consolidated statement of operations for the year ended March 31, 2014 includes $1.4 million of operating incomerelated to the natural gas business, which is reported within “corporate and other” in the segment disclosures in Note 13. We acquired High Sierra in June 2012, which operated a compressor leasing business. We sold the compressor leasing business in February 2014 for$10.8 million (net of the amount due to the owner of the noncontrolling interest in the business). We recorded a gain on the sale of the business of $4.4million, $1.6 million of which was attributable to the disposal of the noncontrolling interest. We reported the gain as a reduction to loss on disposal orimpairment of assets, net in our consolidated statement of operations. Our consolidated statement of operations for the year ended March 31, 2014 includes$2.3 million of operating income related to the compressor leasing business, which is reported within “corporate and other” in the segment disclosures inNote 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 in our liquids segment, which is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations. During the year ended March 31, 2014, two of our water solutions facilities in our water solutions segment experienced damage to their property,plant and equipment as a result of lightning strikes. We recorded a write-down to property, plant and equipment of $1.5 million related to these incidents,which is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations. Note 15—Transactions with Affiliates SemGroup Corporation (“SemGroup”) holds ownership interests in our general partner. We sell product to and purchase product from SemGroup,and these transactions are included within revenues and cost of sales in our consolidated statements of operations. We also lease crude oil storage fromSemGroup. We purchase ethanol from one of our equity method investees. These transactions are reported within cost of sales in our consolidated statements ofoperations. Certain members of our management own interests in entities which we have purchased products and services and to which we have sold productsand services. The majority of our transactions with such entities represented crude oil purchases and sales and are reported within revenues or cost of sales inour consolidated statements of operations, although $27.5 million of these transactions during the year ended March 31, 2015 represented capitalexpenditures and were recorded as increases to property, plant and equipment. The above transactions are summarized in the following table: Year Ended March 31, 2015 2014 2013 (in thousands) Sales to SemGroup$88,276$160,993$54,726Purchases from SemGroup130,134300,164102,351Sales to equity method investees14,493——Purchases from equity method investees149,82847,731—Sales to entities affiliated with management2,151110,82416,828Purchases from entities affiliated with management29,419120,03860,942 F-50Table of Contents Receivables from affiliates consist of the following: March 31,2015 2014(in thousands)Receivables from SemGroup$13,443$7,303Receivables from equity method investees652—Receivables from entities affiliated with management3,103142Total$17,198$7,445 Payables to affiliates consist of the following: March 31,2015 2014(in thousands)Payables to SemGroup$11,546$27,738Payables to equity method investees6,78848,454Payables to entities affiliated with management7,460654Total$25,794$76,846 We also have a loan receivable of $8.2 million at March 31, 2015 from one of our equity method investees. A portion of the loan matures August 29,2018 and the remaining portion matures August 29, 2019. We completed a merger with High Sierra in June 2012. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP’s long-term debt and other obligations. Our generalpartner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interestsin High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our generalpartner. 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—Other Matters Purchase of Pipeline Capacity Allocations On certain interstate refined product pipelines, shipment demand exceeds available capacity, and capacity is allocated to shippers based on theirhistorical shipment volumes. During the year ended March 31, 2015, we paid $24.2 million to acquire certain refined product pipeline capacity allocationsfrom other shippers. Crude Oil Rail Transloading Facility In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent toexecuting these commitments, the producers requested to be released from the commitments. We agreed to release the producers from their commitments inreturn for which the producers paid us a specified amount in March 2015 and committed to pay us specified additional amounts over a period of five years. Inaddition, one of the producers committed to pay us a specified fee on each barrel of crude oil it produces in a specified basin over a period of seven years.Upon execution of these agreements in March 2015, we recorded a gain of $31.6 million to other income in our consolidated statement of operations, net ofcertain project abandonment costs. Prior to terminating these contracts, we leased certain railcars that we expected to utilize to service the contracts with the producers. We will attemptto sublease these railcars or utilize them in our other operations, but we are unable to predict to what extent we will be able to utilize these railcars. F-51Table of Contents Grand Mesa Pipeline, LLC In September 2014, we entered into a joint venture with RimRock Midstream, LLC (“RimRock”), whereby each party owned a 50% interest in GrandMesa. Grand Mesa is constructing a crude oil pipeline originating in Weld County, Colorado and terminating at our Cushing, Oklahoma terminal. InOctober 2014, Grand Mesa completed a successful open season in which it received the requisite support, in the form of ship-or-pay volume commitmentsfrom multiple shippers, to begin construction of a 20-inch pipeline system. In November 2014, we acquired RimRock’s 50% ownership interest in GrandMesa for $310.0 million in cash and allocated the purchase price to a customer commitment intangible asset. We anticipate that the pipeline will commenceservice in the second half of calendar year 2016, at which time we will begin to amortize this intangible asset. Note 17—Quarterly Financial Data (Unaudited) Our summarized unaudited quarterly financial data is presented below. The computation of net income per common unit is done separately byquarter and year. The total of net income per common unit of the individual quarters may not equal the net income per common unit for the year, dueprimarily to the income allocation between the general partner and limited partners and variations in the weighted-average units outstanding used incomputing 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 throughSeptember of each year. Our liquids segment is also subject to seasonal fluctuations, as demand for propane and butane is typically higher during the wintermonths. Our operating revenues from our other segments are less weather sensitive. Additionally, the acquisitions described in Note 4 impact thecomparability of the quarterly information within the year, and year to year. Quarter Ended Year EndedJune 30,September 30, December 31, March 31, March 31,20142014 2014 2015 2015(in thousands, except unit and per unit data)Total revenues$3,648,614$5,380,526$4,552,146$3,220,771$16,802,057Total cost of sales$3,534,053$5,179,465$4,311,668$2,933,021$15,958,207Net income (loss) (1)$(39,910)$(15,879)$(5,269)$90,942$29,884Net income (loss) attributable to parent equity (1)$(39,975)$(19,224)$(10,918)$86,778$16,661Income (loss) per common unit, basic and diluted (1)$(0.61)$(0.34)$(0.26)$0.78$(0.29)Weighted average common units outstanding—basic anddiluted74,126,20588,331,65388,545,76494,447,33986,359,300 Quarter EndedYear EndedJune 30,September 30, December 31, March 31, March 31,20132013 2013 2014 2014(in thousands, except unit and per unit data)Total revenues$1,385,957$1,593,937$2,743,445$3,975,935$9,699,274Total 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$47,655Income (loss) per common unit, basic and diluted$(0.35)$(0.05)$0.27$0.46$0.51Weighted average common units outstanding—basic anddiluted47,703,31358,909,38967,941,72673,421,30961,970,471 (1) As described in Note 16, in March 2015, we agreed to release certain producers from certain commitments in return for which the producers paidus a specified amount in March 2015 and committed to pay us specified additional amounts over a period of five years. Upon execution of theseagreements in March 2015, we recorded a gain of $31.6 million to other income in our consolidated statement of operations, net of certainproject abandonment costs. F-52Table of Contents Note 18—Subsequent Events Water Solutions Facility Acquisitions As described in Note 4, we are party to a development agreement that provides us a right to purchase water treatment and disposal facilitiesdeveloped by the other party to the agreement. During April and May 2015, we purchased three water treatment and disposal facilities under thisdevelopment agreement. On a combined basis, the purchase price for these facilities was $39.0 million of cash. Note 19—Consolidating Guarantor and Non-Guarantor Financial Information Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and the 2021 Notes(described in Note 8). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the consolidating financial information for NGLEnergy Partners LP, NGL Energy Finance Corp. (which, along with NGL Energy Partners LP, is a co-issuer of the 2019 Notes and 2021 Notes), the guarantorsubsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below. During the periods presented in the tables below, the status of certain subsidiaries changed, in that they either became guarantors of or ceased to beguarantors of the 2019 Notes and 2021 Notes. Such changes have been given retrospective application in the tables below. There are no significant restrictions upon the ability of the parent or any of the guarantor subsidiaries to obtain funds from their respectivesubsidiaries by dividend or loan, other than restrictions contained in TLP’s Credit Facility. None of the assets of the guarantor subsidiaries (other than theinvestments in non-guarantor subsidiaries) represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, asamended. For purposes of the tables below, (i) the consolidating financial information is presented on a legal entity basis, (ii) investments in consolidatedsubsidiaries are accounted for as equity method investments, and (iii) contributions, distributions, and advances to or from consolidated entities are reportedon a net basis within net changes in advances with consolidated entities in the consolidating cash flow tables below. F-53Table of Contents NGL ENERGY PARTNERS LPConsolidating Balance Sheet(U.S. Dollars in Thousands) March 31, 2015NGL Energy Partners LPNGL EnergyGuarantorNon-GuarantorConsolidating(Parent) (1)Finance Corp. (1)SubsidiariesSubsidiariesAdjustmentsConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents$29,115$—$9,757$2,431$—$41,303Accounts receivable—trade,net of allowance fordoubtful accounts——1,007,00117,225—1,024,226Accounts receivable—affiliates5—16,610583—17,198Inventories——440,0261,736—441,762Prepaid expenses and othercurrent assets——104,52816,327—120,855Total current assets29,120—1,577,92238,302—1,645,344 PROPERTY, PLANT ANDEQUIPMENT, net ofaccumulated depreciation——1,093,018524,371—1,617,389GOODWILL——1,372,69030,071—1,402,761INTANGIBLE ASSETS, net ofaccumulated amortization17,834—1,195,89674,613—1,288,343INVESTMENTS INUNCONSOLIDATEDENTITIES——217,600255,073—472,673NET INTERCOMPANYRECEIVABLES(PAYABLES)1,363,792—(1,319,724)(44,068)——INVESTMENTS INCONSOLIDATEDSUBSIDIARIES1,834,738—56,690—(1,891,428)—LOAN RECEIVABLE—AFFILIATES——8,154——8,154OTHER NONCURRENTASSETS——110,1202,717—112,837Total assets$3,245,484$—$4,312,366$881,079$(1,891,428)$6,547,501 LIABILITIES AND EQUITYCURRENT LIABILITIES:Accounts payable—trade$—$—$820,441$12,939$—$833,380Accounts payable—affiliates——25,690104—25,794Accrued expenses and otherpayables19,690—165,8199,607—195,116Advance payments receivedfrom customers——53,903331—54,234Current maturities of long-term debt——4,41359—4,472Total current liabilities19,690—1,070,26623,040—1,112,996 LONG-TERM DEBT, net ofcurrent maturities1,100,000—1,395,100250,199—2,745,299OTHER NONCURRENTLIABILITIES——12,2623,824—16,086 EQUITYPartners’ equity2,125,794—1,834,738604,125(2,438,754)2,125,903Accumulated othercomprehensive loss———(109)—(109)Noncontrolling interests————547,326547,326Total equity2,125,794—1,834,738604,016(1,891,428)2,673,120Total liabilities andequity$3,245,484$—$4,312,366$881,079$(1,891,428)$6,547,501 (1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Since the parent received the proceeds from theissuance of the 2019 Notes and 2021 Notes, all activity has been reflected in the parent column. F-54Table of Contents NGL ENERGY PARTNERS LPConsolidating Balance Sheet(U.S. Dollars in Thousands) March 31, 2014NGL Energy Partners LP NGL Energy GuarantorNon-GuarantorConsolidating (Parent) (1) Finance Corp. (1) SubsidiariesSubsidiariesAdjustments ConsolidatedASSETSCURRENT ASSETS:Cash and cash equivalents$1,181$—$8,728$531$—$10,440Accounts receivable—trade, net ofallowance for doubtful accounts——864,78913,115—877,904Accounts receivable—affiliates——7,445——7,445Inventories——306,4343,726—310,160Prepaid expenses and other currentassets——80,29456—80,350Total current assets1,181—1,267,69017,428—1,286,299 PROPERTY, PLANT ANDEQUIPMENT, net of accumulateddepreciation——770,51665,332—835,848GOODWILL——1,083,3951,998—1,085,393INTANGIBLE ASSETS, net ofaccumulated amortization12,721—721,7531,632—736,106INVESTMENTS INUNCONSOLIDATED ENTITIES——194,821——194,821NET INTERCOMPANYRECEIVABLES (PAYABLES)764,995—(720,737)(44,258)——INVESTMENTS IN CONSOLIDATEDSUBSIDIARIES1,462,502—17,673—(1,480,175)—OTHER NONCURRENT ASSETS——9,043121—9,164Total assets$2,241,399$—$3,344,154$42,253$(1,480,175)$4,147,631 LIABILITIES AND EQUITYCURRENT LIABILITIES:Accounts payable—trade$—$—$705,344$13,959$—$719,303Accounts payable—affiliates——73,7033,143—76,846Accrued expenses and otherpayables14,820—124,9231,947—141,690Advance payments received fromcustomers——29,89174—29,965Current maturities of long-termdebt——7,05822—7,080Total current liabilities14,820—940,91919,145—974,884 LONG-TERM DEBT, net of currentmaturities700,000—929,75480—1,629,834OTHER NONCURRENTLIABILITIES——10,97981—11,060 EQUITYPartners’ equity1,526,579—1,462,69122,994(1,485,449)1,526,815Accumulated other comprehensiveloss——(189)(47)—(236)Noncontrolling interests————5,2745,274Total equity1,526,579—1,462,50222,947(1,480,175)1,531,853Total liabilities and equity$2,241,399$—$3,344,154$42,253$(1,480,175)$4,147,631 (1) The parent and NGL Energy Finance Corp. are co-issuers of the 2021 Notes. Since the parent received the proceeds from the issuance of the2021 Notes, all activity has been reflected in the parent column. F-55Table of Contents NGL ENERGY PARTNERS LPConsolidating Statement of Operations(U.S. Dollars in Thousands) Year Ended March 31, 2015NGL Energy Partners LP NGL Energy GuarantorNon-GuarantorConsolidating (Parent) (1) Finance Corp. (1) SubsidiariesSubsidiariesAdjustments Consolidated REVENUES$—$—$16,648,382$189,979$(36,304)$16,802,057 COST OF SALES——15,934,52959,825(36,147)15,958,207 OPERATING COSTS ANDEXPENSES:Operating——314,62157,555—372,176Loss on disposal or impairment ofassets, net——11,61929,565—41,184General and administrative——131,89817,532—149,430Depreciation and amortization——161,90632,043—193,949 Operating Income (Loss)——93,809(6,541)(157)87,111 OTHER INCOME (EXPENSE):Earnings of unconsolidated entities——6,6405,463—12,103Interest expense(65,723)—(39,023)(5,423)46(110,123)Other income, net——36,953264(46)37,171 Income (Loss) Before IncomeTaxes(65,723)—98,379(6,237)(157)26,262 INCOME TAX (PROVISION)BENEFIT——3,795(173)—3,622 EQUITY IN NET INCOME (LOSS) OFCONSOLIDATED SUBSIDIARIES82,384—(19,633)—(62,751)— Net Income (Loss)16,661—82,541(6,410)(62,908)29,884 LESS: NET INCOME ALLOCATEDTO GENERAL PARTNER(45,679)(45,679) LESS: NET INCOMEATTRIBUTABLE TONONCONTROLLING INTERESTS(13,223)(13,223) NET INCOME (LOSS) ALLOCATEDTO LIMITED PARTNERS$16,661$—$82,541$(6,410)$(121,810)$(29,018) (1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. F-56Table of Contents NGL ENERGY PARTNERS LPConsolidating Statement of Operations(U.S. Dollars in Thousands) Year Ended March 31, 2014NGL Energy Partners LP NGL Energy GuarantorNon-GuarantorConsolidating (Parent) (1) Finance Corp. (1) SubsidiariesSubsidiariesAdjustments Consolidated REVENUES$—$—$9,560,124$139,519$(369)$9,699,274 COST OF SALES——9,011,011122,057(369)9,132,699 OPERATING COSTS ANDEXPENSES:Operating——250,8418,958—259,799Loss (gain) on disposal orimpairment of assets, net——6,373(2,776)—3,597General and administrative——73,7562,104—75,860Depreciation and amortization——117,5733,181—120,754 Operating Income——100,5705,995—106,565 OTHER INCOME (EXPENSE):Earnings of unconsolidated entities——1,898——1,898Interest expense(31,818)—(27,031)(51)46(58,854)Other income (expense), net——202(70)(46)86 Income (Loss) Before IncomeTaxes(31,818)—75,6395,874—49,695 INCOME TAX PROVISION——(937)——(937) EQUITY IN NET INCOME OFCONSOLIDATED SUBSIDIARIES79,473—4,771—(84,244)— Net Income47,655—79,4735,874(84,244)48,758 LESS: NET INCOME ALLOCATEDTO GENERAL PARTNER(14,148)(14,148) LESS: NET INCOMEATTRIBUTABLE TONONCONTROLLING INTERESTS(1,103)(1,103) NET INCOME ALLOCATED TOLIMITED PARTNERS$47,655$—$79,473$5,874$(99,495)$33,507 (1) The parent and NGL Energy Finance Corp. are co-issuers of the 2021 Notes. F-57Table of Contents NGL ENERGY PARTNERS LPConsolidating Statement of Operations(U.S. Dollars in Thousands) Year Ended March 31, 2013NGL Energy Partners LPGuarantor Non-Guarantor Consolidating (Parent)Subsidiaries Subsidiaries Adjustments Consolidated REVENUES$—$4,409,198$8,878$(309)$4,417,767 COST OF SALES—4,038,2511,168(309)4,039,110 OPERATING COSTS AND EXPENSES:Operating—164,8704,742—169,612Loss on disposal or impairment of assets, net—74113—187General and administrative—52,461237—52,698Depreciation and amortization—66,9161,937—68,853 Operating Income—86,626681—87,307 OTHER INCOME (EXPENSE):Interest expense(13,041)(19,951)(48)46(32,994)Loss on early extinguishment of debt—(5,769)——(5,769)Other income (expense), net—1,666(99)(46)1,521 Income (Loss) Before Income Taxes(13,041)62,572534—50,065 INCOME TAX PROVISION—(1,875)——(1,875) EQUITY IN NET INCOME OF CONSOLIDATEDSUBSIDIARIES60,981284—(61,265)— Net Income47,94060,981534(61,265)48,190 LESS: NET INCOME ALLOCATED TO GENERALPARTNER(2,917)(2,917) LESS: NET INCOME ATTRIBUTABLE TONONCONTROLLING INTERESTS(250)(250) NET INCOME ALLOCATED TO LIMITED PARTNERS$47,940$60,981$534$(64,432)$45,023 F-58Table of Contents NGL ENERGY PARTNERS LPConsolidating Statements of Comprehensive Income (Loss)(U.S. Dollars in Thousands) Year Ended March 31, 2015NGL Energy Partners LP NGL Energy Guarantor Non-Guarantor Consolidating (Parent) (1) Finance Corp. (1) Subsidiaries Subsidiaries Adjustments Consolidated Net income (loss)$16,661$—$82,541$(6,410)$(62,908)$29,884 Other comprehensive income (loss)——189(62)—127 Comprehensive income (loss)$16,661$—$82,730$(6,472)$(62,908)$30,011 (1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Year Ended March 31, 2014NGL Energy Partners LP NGL Energy Guarantor Non-Guarantor Consolidating (Parent) (2) Finance Corp. (2) Subsidiaries Subsidiaries Adjustments Consolidated Net income$47,655$—$79,473$5,874$(84,244)$48,758 Other comprehensive loss——(189)(71)—(260) Comprehensive income$47,655$—$79,284$5,803$(84,244)$48,498 (2) The parent and NGL Energy Finance Corp are co-issuers of the 2021 Notes. Year Ended March 31, 2013NGL Energy Partners LP Guarantor Non-Guarantor Consolidating (Parent) Subsidiaries Subsidiaries Adjustments Consolidated Net income$47,940$60,981$534$(61,265)$48,190 Other comprehensive loss——(7)—(7) Comprehensive income$47,940$60,981$527$(61,265)$48,183 F-59Table of Contents NGL ENERGY PARTNERS LPConsolidating Statement of Cash Flows(U.S. Dollars in Thousands) Year Ended March 31, 2015 NGL Energy Partners LP NGL Energy Guarantor Non-Guarantor (Parent) (1) Finance Corp. (1) Subsidiaries Subsidiaries ConsolidatedOPERATING ACTIVITIES:Net cash provided by (used in) operatingactivities$(59,448)$—$287,956$33,886$262,394 INVESTING ACTIVITIES:Purchases of long-lived assets——(198,847)(4,913)(203,760)Purchases of pipeline capacity allocations——(24,218)—(24,218)Purchase of equity interest in Grand MesaPipeline——(310,000)—(310,000)Acquisitions of businesses, including acquiredworking capital, net of cash acquired(124,281)—(831,505)(5,136)(960,922)Cash flows from commodity derivatives——199,165—199,165Proceeds from sales of assets——11,80614,45626,262Investments in unconsolidated entities——(13,244)(20,284)(33,528)Distributions of capital from unconsolidatedentities——5,0305,79310,823Loan for facility under construction——(63,518)—(63,518)Payments on loan for facility under construction——1,625—1,625Loans to affiliates——(8,154)—(8,154)Other——4—4Net cash used in investing activities(124,281)—(1,231,856)(10,084)(1,366,221) FINANCING ACTIVITIES:Proceeds from borrowings under revolving creditfacilities——3,663,000101,5003,764,500Payments on revolving credit facilities——(3,194,500)(85,500)(3,280,000)Issuance of notes400,000———400,000Payments on other long-term debt——(6,666)(22)(6,688)Debt issuance costs(8,150)—(2,926)—(11,076)Contributions from general partner823———823Contributions from noncontrolling interestowners———9,4339,433Distributions to partners(242,595)———(242,595)Distributions to noncontrolling interest owners———(27,147)(27,147)Proceeds from sale of common units, net ofoffering costs541,128———541,128Taxes paid on behalf of equity incentiveparticipants——(13,491)—(13,491)Net changes in advances with consolidatedentities(479,543)—499,709(20,166)—Other——(197)—(197)Net cash provided by financing activities211,663—944,929(21,902)1,134,690Net increase in cash and cash equivalents27,934—1,0291,90030,863Cash and cash equivalents, beginning of period1,181—8,72853110,440Cash and cash equivalents, end of period$29,115$—$9,757$2,431$41,303 (1) The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. F-60Table of Contents NGL ENERGY PARTNERS LPConsolidating Statement of Cash Flows(U.S. Dollars in Thousands) Year Ended March 31, 2014 NGL Energy Partners LP NGL Energy Guarantor Non-Guarantor (Parent) (1) Finance Corp. (1) Subsidiaries Subsidiaries ConsolidatedOPERATING ACTIVITIES:Net cash provided by (used in) operatingactivities$(16,625)$—$99,754$2,107$85,236 INVESTING ACTIVITIES:Purchases of long-lived assets——(118,455)(46,693)(165,148)Acquisitions of businesses, including acquiredworking capital, net of cash acquired(334,154)—(932,373)(2,283)(1,268,810)Cash flows from commodity derivatives——(35,956)—(35,956)Proceeds from sales of assets——12,88411,77624,660Investments in unconsolidated entities——(11,515)—(11,515)Distributions of capital from unconsolidatedentities——1,591—1,591Other——540(735)(195)Net cash used in investing activities(334,154)—(1,083,284)(37,935)(1,455,373) FINANCING ACTIVITIES:Proceeds from borrowings under revolving creditfacilities——2,545,500—2,545,500Payments on revolving credit facilities——(2,101,000)—(2,101,000)Issuance of notes450,000———450,000Proceeds from borrowings on other long-termdebt——780100880Payments on other long-term debt——(8,802)(17)(8,819)Debt issuance costs(12,931)—(11,664)—(24,595)Contributions from general partner765———765Contributions from noncontrolling interestowners———2,0602,060Distributions to partners(145,090)———(145,090)Distributions to noncontrolling interest owners———(840)(840)Proceeds from sale of common units, net ofoffering costs650,155———650,155Net changes in advances with consolidatedentities(590,939)—556,23834,701—Net cash provided by financing activities351,960—981,05236,0041,369,016Net increase (decrease) in cash and cashequivalents1,181—(2,478)176(1,121)Cash and cash equivalents, beginning of period——11,20635511,561Cash and cash equivalents, end of period$1,181$—$8,728$531$10,440 (1) The parent and NGL Energy Finance Corp. are co-issuers of the 2021 Notes. F-61Table of Contents NGL ENERGY PARTNERS LPConsolidating Statement of Cash Flows(U.S. Dollars in Thousands) Year Ended March 31, 2013NGL Energy Partners LPGuarantor Non-Guarantor (Parent)Subsidiaries Subsidiaries ConsolidatedOPERATING ACTIVITIES:Net cash provided by (used in) operating activities$(12,428)$140,794$4,268$132,634 INVESTING ACTIVITIES:Purchases of long-lived assets—(59,903)(12,572)(72,475)Acquisitions of businesses, including acquired workingcapital, net of cash acquired(452,087)(38,718)—(490,805)Cash flows from commodity derivatives—11,579—11,579Proceeds from sales of assets—5,080—5,080Net cash used in investing activities(452,087)(81,962)(12,572)(546,621) FINANCING ACTIVITIES:Proceeds from borrowings under revolving credit facilities—1,227,975—1,227,975Payments on revolving credit facilities—(964,475)—(964,475)Issuance of notes250,000——250,000Proceeds from borrowings on other long-term debt—63419653Payments on other long-term debt—(4,837)—(4,837)Debt issuance costs(777)(19,412)—(20,189)Contributions from general partner510——510Contributions from noncontrolling interest owners——403403Distributions to partners(71,608)——(71,608)Distributions to noncontrolling interest owners——(74)(74)Proceeds from sale of common units, net of offering costs(642)——(642)Net changes in advances with consolidated entities286,991(295,105)8,114—Net cash provided by (used in) financing activities464,474(55,220)8,462417,716Net increase (decrease) in cash and cash equivalents(41)3,6121583,729Cash and cash equivalents, beginning of period417,5941977,832Cash and cash equivalents, end of period$—$11,206$355$11,561 F-62Table of Contents INDEX TO EXHIBITS Exhibit NumberDescription2.1LLC 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) 2.2LLC 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) 2.3LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC,Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC(incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7,2013) 2.4LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC,Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC(incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7,2013) 2.5LLC 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 (FileNo. 001-35172) filed with the SEC on August 7, 2013) 2.6Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP,Gavilon, LLC and Gavilon Energy Intermediate, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K(File No. 001-35172) filed with the SEC on December 5, 2013) 3.1Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the RegistrationStatement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.2Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference toExhibit 3.2 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.3Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference toExhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011) 3.4First Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporatedby reference 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 by reference 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 (incorporatedby reference 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 (incorporatedby reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 2012) Table of Contents Exhibit NumberDescription3.8Certificate 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 tothe Registration 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, datedas of August 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed withthe SEC on August 7, 2013) 3.12Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, datedas of June 27, 2014 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed withthe SEC on July 3, 2014) 4.1First Amended and Restated Registration Rights Agreement, dated October 3, 2011, by and among the Partnership, Hicks Oils &Hicksgas, Incorporated, NGL Holdings, Inc., Krim2010, LLC, Infrastructure Capital Management, LLC, Atkinson Investors, LLC,E. Osterman Propane, Inc. and the other holders party thereto (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K (File No. 001-35172) filed on October 7, 2011) 4.2Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 byand among the Partnership and SemStream (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 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 andamong NGL Energy Holdings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-Portland Propane, L.L.C., Pacer Propane (Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C.(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012) 4.4Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by andbetween NGL Energy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Reporton Form 8-K (File No. 001-35172) filed with the SEC on May 4, 2012) 4.5Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by andbetween NGL Energy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Reporton Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 4.6Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by andbetween NGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2012) 4.7Amendment 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 Holdings 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) Table of Contents Exhibit NumberDescription4.9*Amendment No. 8 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of February 17, 2015, byand among NGL Energy Holdings LLC and Magnum NGL Holdco LLC 4.10Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by referenceto Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 4.11Amendment No. 1 to Note Purchase Agreement, dated as of January 15, 2013, among the Partnership and the purchasers namedtherein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onJanuary 18, 2013) 4.12Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 9, 2013) 4.13Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders ofNGL’s 6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on October 3, 2013) 4.14Amendment 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) 4.15Amendment 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) 4.16Amendment No. 6 to Note Purchase Agreement, dated as of June 30, 2014, 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 onJuly 3, 2014) 4.17Amendment No. 7 to Note Purchase Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, among thePartnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed on January 2, 2015) 4.18*Amendment No. 8 to Note Purchase Agreement, dated as of May 1, 2015, among the Partnership and the purchasers named therein 4.19Indenture, 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) 4.20Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on October 16, 2013) 4.21First 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(incorporated by reference to Exhibit 4.19 to the Annual Report on Form 10—K (File No. 001-35172) for the year endedMarch 31, 2014 filed with the SEC on May 30, 2014) 4.22Second 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 (incorporatedby reference to Exhibit 4.20 to the Annual Report on Form 10—K (File No. 001-35172) for the year ended March 31, 2014 filedwith the SEC on May 30, 2014) Table of Contents Exhibit NumberDescription4.23Third Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiary party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.6 tothe Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with the SEC onNovember 10, 2014) 4.24*Fourth Supplemental Indenture, dated as of December 1, 2014, 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 4.25*Fifth Supplemental Indenture, dated as of February 17, 2015, 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 4.26Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy FinanceCorp., 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 onOctober 16, 2013) 4.27Registration 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 withthe SEC on December 5, 2013) 4.28Indenture, dated as of July 9, 2014, 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 July 9, 2014) 4.29Forms of 5.125% Senior Notes due 2019 (incorporated by reference and included as Exhibits A1 and A2 to Exhibit 4.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014) 4.30Registration Rights Agreement, dated July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., theGuarantors listed therein on Exhibit A and RBS Securities Inc. as representative of the several initial purchasers (incorporated byreference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014) 4.31First Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiaries party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.5to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with the SEC onNovember 10, 2014) 4.32*Second Supplemental Indenture, dated as of December 1, 2014, 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 4.33*Third Supplemental Indenture, dated as of February 17, 2015, 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 10.1Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders partythereto and Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 10.2Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP,Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference toExhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012) Table of Contents Exhibit NumberDescription10.3Amendment 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 onJanuary 18, 2013) 10.4Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No 001-35172) filed on May 9, 2013) 10.5Amendment 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, DeutscheBank Trust Company Americas, as administrative agent and collateral agent and each financial institution identified as a“Lender” or “Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013) 10.6Amendment 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 onNovember 8, 2013) 10.7Amendment 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 onDecember 30, 2013) 10.8Facility Increase Agreement, dated as of December 30, 2013, among NGL Energy Operating LLC, Deutsche Bank Trust CompanyAmericas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on January 3, 2014) 10.9Amendment No. 6 to Credit Agreement, dated as of June 12, 2014, 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 June 16,2014) 10.10Amendment No. 7 to Credit Agreement, dated as of June 27, 2014, 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 July 3,2014) 10.11Facility Increase Agreement, dated December 1, 2014, among NGL Energy Operating LLC, Deutsche Bank Trust CompanyAmericas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on December 1, 2014) 10.12Amendment No. 8 to Credit Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, among NGLEnergy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and theother financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed on January 2, 2015) 10.13*Amendment No. 9 to Credit Agreement, dated as of May 1, 2015, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto 10.14Common 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 withthe SEC on December 5, 2013) Table of Contents Exhibit NumberDescription10.15+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) 10.16+NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K (File No. 001-35172) filed on May 17, 2011) 10.17+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 filedwith the SEC on August 14, 2012 ) 10.18*+NGL Performance Unit Program 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 Schema Document 101.CAL**XBRL Calculation Linkbase Document 101.DEF**XBRL Definition Linkbase Document 101.LAB**XBRL Label Linkbase Document 101.PRE**XBRL Presentation Linkbase Document * Exhibits filed with this report. ** The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at March 31, 2015and 2014, (ii) Consolidated Statements of Operations for the years ended March 31, 2015, 2014, and 2013, (iii) Consolidated Statements ofComprehensive Income for the years ended March 31, 2015, 2014, and 2013, (iv) Consolidated Statements of Changes in Equity for the yearsended March 31, 2015, 2014, and 2013 (v) Consolidated Statements of Cash Flows for the years ended March 31, 2015, 2014, and 2013, and(vi) Notes to Consolidated Financial Statements. + Management contracts or compensatory plans or arrangements. Exhibit 4.9 AMENDMENT NO. 8 AND JOINDER TO FIRST AMENDED AND RESTATEDREGISTRATION RIGHTS AGREEMENT This Amendment No. 8 and Joinder to First Amended and Restated Registration Rights Agreement (this “Amendment”) is dated as ofFebruary 17, 2015 by and among NGL Energy Holdings LLC, a Delaware limited liability company (the “General Partner”), and Magnum NGL HoldCo LLC,a Delaware limited liability company (the “Magnum Investor”). Capitalized terms used but not defined herein have the meanings ascribed to them in theRegistration Rights Agreement (as defined below). R E C I T A L S WHEREAS, NGL Energy Partners LP, a Delaware limited partnership (the “Partnership”), acting through the General Partner, is party to thatcertain First Amended and Restated Registration Rights Agreement dated as of October 3, 2011 (the “Registration Rights Agreement”); WHEREAS, reference is hereby made to that certain Purchase and Sale Agreement, dated as of February 7, 2015, by and among MagnumDevelopment, LLC, the other sellers party thereto and NGL Supply Terminal Company, LLC (as amended, restated, supplemented or otherwise modified, the“Purchase Agreement”); WHEREAS, the execution and delivery of this Amendment is a condition precedent to the consummation of the transactions contemplatedunder the Purchase Agreement; WHEREAS, pursuant to Section 6(c) of the Registration Rights Agreement, the General Partner may amend the Registration RightsAgreement in its sole discretion and without any further approval rights or action by or on behalf of the Holders in connection with the transactionscontemplated by the Purchase Agreement; and WHEREAS, the General Partner desires to join Magnum Investor as a party thereto in a capacity as a Rights Holder and amend theRegistration Rights Agreement as set forth below. NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the partieshereby covenant and agree: 1. Amendment of Registration Rights Agreement. (a) The fourth sentence of the definition of “Affiliate” set forth in Section 1 of the Registration Rights Agreement is hereby amendedand restated in its entirety to read as follows: Notwithstanding anything in the foregoing to the contrary, (i) HOH and its respective Affiliates (other than the General Partner or any GroupMember), on the one hand, (ii) NGL Holdings and its Affiliates (other than the General Partner or any Group Member), on another hand, (iii) the IEPGroup and their respective Affiliates (other than the General Partner or any Group Member), on another hand, (iv) the Osterman Group and theirrespective Affiliates (other than the General Partner or any Group Member), on another hand, (v) SemStream and its Affiliates (other than the GeneralPartner or any Group Member), on another hand, (vi) the Pacer Propane Group and their respective Affiliates, on another hand, (vii) Downeast and itsAffiliates (other than the General Partner or any Group Member), on another hand, (viii) NGP and its Affiliates (other than the General Partner or anyGroup Member), on another hand, (ix) Enstone and its Affiliates (other than the General Partner or any Group Member), on another hand, (x) theJensen Investors and each of their Affiliates, on another hand, (xi) OWL and its Affiliates, on another hand, (xii) Mr. Bailey and his Affiliates, onanother hand, and (xiii) Magnum Investor and its Affiliates, on the other hand, will not be deemed to be Affiliates of one another hereunder unlessthere is a basis for such Affiliation independent of their respective Affiliation with any Group Member, the General Partner or any Affiliate(disregarding the immediately preceding sentence) of any Group Member or the General Partner. (b) The definitions of “Significant Holder” and “Transaction Documents” set forth in Section 1 of the Registration Rights Agreementare hereby amended and restated in their entirety to read as follows: “Significant Holder” means each of (i) NGL Holdings, (ii) HOH, (iii) the IEP Group, (iv) the Osterman Group (acting together in their capacities asHolders) (v) SemStream, (vi) the Pacer Propane Group (acting together in their capacities as Holders), (vii) Downeast, in each case only for so long assuch Significant Holder set forth in (i) through (vii) continues to hold a Requisite Ownership Threshold, and (viii) the Magnum Investor, for theperiod commencing on October 1, 2015, provided that the Partnership is eligible to register the resale of Common Units on Form S-3 as of such date,and ending on the date on which all Common Units held by the Magnum Investor are freely transferable in accordance with the terms of theMagnum-NGL Purchase Agreement. Notwithstanding anything to the contrary set forth herein, the Magnum Investor shall be entitled to the rights ofa Significant Holder set forth in Section 2(a) for the entirety of the period set forth in (viii) above, provided that the Magnum Investor may onlyexercise such rights at a time when the Partnership is eligible to register the resale of Common Units on Form S-3 and provided, further, that upon aneligible election of such rights, the Partnership may not postpone or defer any Demand Registration pursuant to Section 2(a)(iv) for more than anaggregate of ninety (90) days. “Transaction Documents” means (i) the Partnership Agreement, (ii) the Second Amended and Restated Limited Liability Company Agreement of theGeneral Partner, dated as of November 1, 2011, as amended from time to time, (iii) with respect to the Initial Holders, the Contribution, Purchase andSale Agreement, (iv) with respect to the Osterman Group, the Contribution and Sale Agreement, (v) with respect to SemStream, the SemStream—NGLContribution Agreement, (vi) with respect to the Pacer Propane Group, the Pacer—NGL Contribution Agreements, (vii) with respect to Downeast, theDowneast—NGL Contribution Agreement, (viii) with respect to NGP, the High Sierra—NGL Merger Agreement, (ix) with respect to Enstone, theEnstone—NGL Contribution Agreement, (x) with respect to the Jensen Investors, the Jensen—NGL Call Agreement, (xi) with respect to OWL andMr. Bailey, the OWL/Bailey Transfer Agreements and (xii) with respect to the Magnum Investor, the Magnum-NGL Purchase Agreement. (c) Section 1 of the Registration Rights Agreement is hereby amended to add the following definitions of “Magnum Investor” and“Magnum—NGL Purchase Agreement” thereto: “Magnum Investor” means Magnum NGL HoldCo LLC. “Magnum-NGL Purchase Agreement” means the Purchase and Sale Agreement, dated as of February 7, 2015, by and among Magnum Development,LLC, the other sellers party thereto and NGL Supply Terminal Company, LLC, as amended, restated, supplemented or otherwise modified from timeto time. (d) Section 2(a)(iii) of the Registration Rights Agreement is hereby amended and restated in its entirety to read as follows: Subject to the other limitations contained in this Agreement, the Partnership is not obligated hereunder to effect more than (A) one (1) DemandRegistration by each Significant Holder other than SemStream and the Magnum Investor, each of which shall have two (2) Demand Registrations;(B) nine (9) Demand Registrations in total; (C) one (1) Demand Registration on Form S-1 (or any equivalent or successor form under the SecuritiesAct) in any twelve (12) month period; or (D) two (2) Demand Registrations on Form S-3 (or any equivalent or successor form under the SecuritiesAct) in any twelve (12) month period. 2. Joinder. (a) The Magnum Investor acknowledges receipt of a copy of the Registration Rights Agreement and, after review and examinationthereof, by execution of this Amendment does hereby agree to be bound by the terms, conditions and agreements contained therein in its capacity as a RightsHolder thereunder. (b) By execution hereof, the General Partner hereby (i) accepts the agreement of the Magnum Investor to be bound by the RegistrationRights Agreement, (ii) covenants and agrees that the Registration Rights Agreement is hereby amended to include the Magnum Investor as a party in acapacity as a Rights Holder and (iii) agrees that the Magnum Investor shall have all rights provided to a Rights Holder under the Registration RightsAgreement. 3. Miscellaneous. (a) From and after the date hereof, each reference in the Registration Rights Agreement to “this Agreement,” “hereunder,” “hereof,”“herein,” or words of like import, shall mean and be a reference to the Registration Rights 2 Agreement as amended hereby. (b) Except as specifically set forth above, the Registration Rights Agreement shall remain unaltered and in full force and effect and therespective terms, conditions or covenants thereof are hereby in all respects ratified and confirmed. (c) This Amendment shall be governed by and construed in accordance with the laws of the State of Delaware without regard to theprinciples of conflicts of law. [Signature Page Follows] 3 IN WITNESS WHEREOF, the parties hereto have executed and deliver this Amendment No. 8 and Joinder to First Amended and RestatedRegistration Rights Agreement on the date first written above. NGL ENERGY HOLDINGS LLC By:/s/ H. Michael KrimbillName:H. Michael KrimbillTitle:CEO MAGNUM NGL HOLDCO LLC By:/s/ M. Scott JonesName:M. Scott JonesTitle:Manager (Signature Page to Amendment No. 8 and Joinder to First Amended and Restated Registration Rights Agreement) Exhibit 4.18 AMENDMENT NO. 8 TO NOTE PURCHASE AGREEMENT THIS AMENDMENT NO. 8 TO NOTE PURCHASE AGREEMENT, dated as of May 1, 2015 but effective as of the Effective Date (as defined inSection 2 hereof) (this “Amendment”), to the Note Purchase Agreement dated as of June 19, 2012, as amended by Amendment No. 1 thereto dated as ofJanuary 15, 2013, Amendment No. 2 thereto dated as of May 8, 2013, Amendment No. 3 thereto dated as of September 30, 2013, Amendment No. 4 theretodated as of November 5, 2013, Amendment No. 5 thereto dated as of December 23, 2013, Amendment No. 6 to Note Purchase Agreement dated as of June 30,2014, Amendment No. 7 to Note Purchase Agreement dated as of December 19, 2014 (such note purchase agreement, as so amended, being referred to hereinas the “Existing Note Purchase Agreement” and as the same shall be further amended hereby, the “Note Purchase Agreement”), is among NGL EnergyPartners LP, a Delaware limited partnership (the “Company”), the Guarantors (solely with respect to Section 5(c) hereof) and the holders of Notes listed on thesignature pages hereto (collectively, the “Noteholders”). RECITALS: A. The Company and the Purchasers party thereto have previously entered into the Existing Note Purchase Agreement. Capitalized terms usedand not otherwise defined herein shall have the respective meanings ascribed to them in the Existing Note Purchase Agreement. B. The Guarantors entered into that certain Guaranty Agreement dated as of June 19, 2012 (as heretofore amended, supplemented or otherwisemodified, the “Guaranty Agreement”). C. The Company has requested certain amendments to the Existing Note Purchase Agreement as more fully described herein below. D. The Noteholders have agreed to such amendments, subject to the performance and observance in full of each of the covenants, terms andconditions, and in reliance upon all of the representations and warranties of the Company, set forth herein. NOW, THEREFORE, in consideration of the premises and the covenants, terms, conditions, representations and warranties herein contained, theparties hereto hereby agree as follows: Section 1. AMENDMENTS TO EXISTING NOTE PURCHASE AGREEMENT. Subject to the covenants, terms and conditions set forth hereinand in reliance upon the representations and warranties of the Company herein contained, the Company and the Noteholders hereby agree to amend theExisting Note Purchase Agreement as set forth below, effective as of the Effective Date: (a) Amendment to Section 10.12 of the Existing Note Purchase Agreement. Section 10.12 of the Existing Note Purchase Agreement is herebyamended and restated in its entirety as follows: “Section 10.12. Redemption, Dividends, Equity Issuance, Distributions and Payments. The Company will not, and will not permit anySubsidiary to, at any time: (a) redeem (whether as a result of mandatory or optional redemption obligations or rights), purchase, retire or otherwise acquire,directly or indirectly, any of the Company’s Equity Interests or any of such Subsidiary’s Equity Interests which are not owned by a Note Party or anywholly-owned Subsidiary thereof, or set aside any amount for any such purpose, except for (i) the redemption by the Company of common units ofthe Company for an amount not to exceed $15,000,000 in the aggregate in any fiscal year (provided that for the fiscal year ending March 31, 2016,the Company shall be permitted to redeem common units of the Company for an aggregate amount not to exceed $45,000,000) or $50,000,000 inthe aggregate during the term of this Agreement (in each case, exclusive of redemptions permitted under clause (ii) of this Section 10.12(a)) and (ii) redemptions in connection with a Permitted Acquisition made in satisfaction of an indemnity obligation owed to a Note Party orAffiliate thereof, in each case so long as no Default or Event of Default exists both immediately before and after giving effect to such redemption; (b) declare or pay, directly or indirectly, any dividend, except (i) dividends paid to a Note Party which is a direct parent of the Note Partypaying a dividend, (ii) non-cash dividends paid to the holders of any Equity Interests of the Company in the form of additional Equity Interests ofthe Company, and (iii) Cash Dividends to the holders of any Equity Interests of the Company, so long as (x) no Default or Event of Default existsboth immediately before and after giving effect to the declaration and the payment of such Cash Dividend and (y) such Cash Dividend does notexceed Available Cash for such quarterly period; or (c) make any other distribution of any Property, cash, securities or a combination thereof, with respect to (whether by reduction of capital orotherwise) any Equity Interests except as permitted in Section 10.12(b).” (b) Amendments to Schedule B to the Existing Note Agreement. Schedule B to the Existing Note Agreement is hereby amended by deletingthe definition of “Reallocated Amount” and by amending and restating the definition of “Total Indebtedness” in its entirety as follows: “Total Indebtedness” means, at any date, all Indebtedness of the Note Parties and their Subsidiaries at such date, determined on aconsolidated basis in accordance with GAAP; provided, that Total Indebtedness shall exclude (a) all Hedging Obligations not then due and owing,(b) any contingent reimbursement obligations (including obligations representing the aggregate amount then available for drawing under all Lettersof Credit), and (c) the outstanding amount of Working Capital Revolving Loans and Swingline Loans owed to Working Capital Revolving Lenders;provided that the aggregate amount of Indebtedness excluded from Total Indebtedness pursuant to this clause (c) shall not exceed $800,000,000. Section 2. EFFECTIVENESS OF AMENDMENTS. The amendments set forth in Section 1 of this Amendment shall become effective (the date ofsuch effectiveness being referred to herein as the “Effective Date”) upon the satisfaction of each of the conditions provided immediately below in thisSection 2 (with each of the documents referred to below being in form and substance satisfactory to the Required Holders and in full force and effect): (a) Execution and Delivery of this Amendment. The Noteholders shall have received a copy of this Amendment duly executed and deliveredby the Company and the Guarantors, and by the Noteholders constituting the Required Holders. (b) Representations and Warranties. Each of the representations and warranties of the Company made in this Amendment shall be true andcorrect on and as of the Effective Date. (c) Amendment to Credit Agreement. The Noteholders shall have received a copy of an amendment in respect of the Credit Agreement, datedon or prior to the date hereof, in form and substance satisfactory to the Required Holders and executed and delivered by the Note Parties, the AdministrativeAgent and the Required Lenders (as defined in the Credit Agreement). (d) Proceedings and Documents. All corporate and other proceedings pertaining directly to this Amendment and all documents andinstruments directly incident to this Amendment shall be satisfactory to the Required Holders and their special counsel, and the Noteholders and their specialcounsel shall have received all such counterpart originals or certified or other copies of such documents as the Required Holders or such special counsel mayreasonably request. 2 Section 3. REPRESENTATIONS AND WARRANTIES; NO DEFAULT. To induce the Noteholders to enter into this Amendment, the Company(by delivery of its counterpart to this Amendment) hereby (i) represents and warrants to the Noteholders that after giving effect to this Amendment and thecontemporaneous amendments to the Credit Agreement and the Intercreditor Agreement, its representations and warranties contained in the Note PurchaseAgreement are true and correct in all material respects (except for those representations and warranties qualified by “materiality,” “Material Adverse Effect”or a like qualification, which shall be correct in all respects) on and as of the Effective Date with the same effect as though made on and as of the EffectiveDate, except to the extent such representations and warranties expressly relate to an earlier date (in which case such representations and warranties were trueand correct in all material respects (except for those representations and warranties qualified by “materiality,” “Material Adverse Effect” or a likequalification, which were true in all respects) as of such earlier date), (ii) represents and warrants to the Noteholders that in connection with this Amendmentand all other documents delivered in connection herewith it (x) has the requisite power and authority to make, deliver and perform the same, (y) has taken allnecessary limited partnership action to authorize its execution, delivery and performance of the same, and (z) has duly executed and delivered the same and(iii) except to the extent waived herein, certifies that no Default or Event of Default exists under any of the Note Documents (both immediately before andafter giving effect to this Amendment) or will result from the making of this Amendment. Section 4. EXPENSES. The Company will promptly (and in any event within thirty (30) days of receiving any statement or invoice therefor) payall reasonable out-of-pocket expenses and costs incurred by the Noteholders relating to this Amendment, including, but not limited to, the reasonable feesand disbursements of Baker Botts L.L.P., incurred in connection with the preparation, negotiation and delivery of this Amendment, and all other relateddocumentation. This Section 4 shall not be construed to limit the Company’s obligations under Section 15.1 of the Existing Note Purchase Agreement. Section 5. MISCELLANEOUS. (a) GOVERNING LAW. THIS AMENDMENT SHALL BE GOVERNED BY, AND SHALL BE CONSTRUED AND INTERPRETED INACCORDANCE WITH, THE LAW OF THE STATE OF NEW YORK. (b) Counterparts. This Amendment may be executed in any number of counterparts and by different parties hereto in separate counterparts,each of which when so executed and delivered shall be deemed an original, but all such counterparts together shall constitute but one and the sameinstrument. Each counterpart may consist of a number of copies hereof, each signed by less than all, but together signed by all, the parties hereto. Delivery ofthis Amendment may be made by telecopy or electronic transmission of a duly executed counterpart copy hereof; provided that any such delivery byelectronic transmission shall be effective only if transmitted in .pdf format, .tif format or other format in which the text is not readily modifiable by anyrecipient thereof. (c) Affirmation of Obligations. Notwithstanding that such consent is not required under the Guaranty Agreement, or any of the other NoteDocuments to which it is a party, each of the Guarantors consents to the execution and delivery of this Amendment by the parties hereto. As a materialinducement to the undersigned to amend the Existing Note Purchase Agreement, each of the Guarantors (i) acknowledges and confirms the continuingexistence, validity and effectiveness of the Guaranty Agreement and each of the other Note Documents to which it is a party and (ii) agrees that the execution,delivery and performance of this Amendment shall not in any way release, diminish, impair, reduce or otherwise affect its obligations thereunder. (d) Note Document. This Amendment is a Note Document and all of the provisions of the Note Purchase Agreement which apply to NoteDocuments apply hereto. (Remainder of Page Intentionally Left Blank; Signature Pages Follow) 3 IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorizedofficers effective as of the Effective Date. 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 Signature Page to Amendment No. 8 to Note Purchase Agreement The foregoing is hereby agreed to as of the date hereof: NOTEHOLDERS: THE PRUDENTIAL INSURANCE COMPANYOF AMERICA, as a Noteholder By:/s/ Matthew BakerName:Matthew BakerTitle:Vice President PRUCO LIFE INSURANCE COMPANY,as a Noteholder By:/s/ Matthew BakerName:Matthew BakerTitle:Assistant Vice President UNIVERSAL PRUDENTIAL ARIZONAREINSURANCE COMPANY, as a Noteholder By:Prudential Investment Management, Inc.,as investment manager By:/s/ Matthew BakerName:Matthew BakerTitle:Vice President PRUDENTIAL ARIZONA REINSURANCECAPTIVE COMPANY, as a Noteholder By:Prudential Investment Management, Inc.,as investment manager By:/s/ Matthew BakerName:Matthew BakerTitle:Vice President Signature Page to Amendment No. 8 to Note Purchase Agreement PRUDENTIAL ARIZONA REINSURANCEUNIVERSAL COMPANY, as a Noteholder By:Prudential Investment Management, Inc.,as investment manager By:/s/ Matthew BakerName:Matthew BakerTitle:Vice President PRUDENTIAL RETIREMENT INSURANCE ANDANNUITY COMPANY, as a Noteholder By:Prudential Investment Management, Inc.,as investment manager By:/s/ Matthew BakerName:Matthew BakerTitle:Vice President Signature Page to Amendment No. 8 to Note Purchase Agreement AMERICAN GENERAL LIFE INSURANCE COMPANY (successor by merger toAMERICAN GENERAL LIFE AND ACCIDENT INSURANCE COMPANY)AMERICAN GENERAL LIFE INSURANCE COMPANY (successor by merger toAMERICAN GENERAL LIFE INSURANCE COMPANY OF DELAWARE)AMERICAN GENERAL LIFE INSURANCE COMPANY (successor by merger toSUNAMERICA ANNUITY AND LIFE ASSURANCE COMPANY)THE UNITED STATES LIFE INSURANCE COMPANY IN THE CITY OF NEW YORKCOMMERCE AND INDUSTRY INSURANCE COMPANYNEW HAMPSHIRE INSURANCE COMPANYAIG PROPERTY CASUALTY COMPANY (f/k/a CHARTIS PROPERTY CASUALTY COMPANY) By:AIG ASSET MANAGEMENT (U.S.), LLC, Investment Adviser By:/s/ Curtis F. SullivanName:Curtis F. SullivanTitle:Vice President Signature Page to Amendment No. 8 to Note Purchase Agreement TEACHERS INSURANCE AND ANNUITY ASSOCIATION OFAMERICA, as a Noteholder By:/s/ Andrew M. LeicesterName:Andrew M. LeicesterTitle:Director Signature Page to Amendment No. 8 to Note Purchase Agreement SUN LIFE ASSURANCE COMPANY OF CANADA,as a Noteholder By:/s/ Keith CressmanName:Keith CressmanTitle:Senior Managing DirectorPrivate Fixed Income By:/s/ Jeffrey MayerName:Jeffery MayerTitle:Managing Director, Private Securitization FinancePrivate Fixed Income Signature Page to Amendment No. 8 to Note Purchase Agreement Agreed to and acknowledged by the undersigned solely with respect to Section 7(c) hereof: GUARANTORS: ANDREWS OIL BUYERS, INC.ANTICLINE DISPOSAL, LLCBLUE GRAMA LAND CORPORATIONCENTENNIAL ENERGY, LLCCENTENNIAL GAS LIQUIDS ULCGRAND MESA PIPELINE, LLCHICKSGAS, LLCHIGH SIERRA CRUDE OIL & MARKETING, LLCHIGH SIERRA ENERGY, LP (BY High Sierra Energy GP, LLC, itsgeneral partner)HIGH SIERRA ENERGY MARKETING, LLCHIGH SIERRA ENERGY OPERATING, LLCNGL CRUDE CANADA HOLDINGS, LLCNGL CRUDE CUSHING, LLCNGL CRUDE LOGISTICS, LLCNGL CRUDE PIPELINES, LLCNGL CRUDE TERMINALS, LLCNGL CRUDE TRANSPORTATION, LLCNGL ENERGY HOLDINGS II, LLCNGL ENERGY LOGISTICS, LLCNGL ENERGY OPERATING LLCNGL LIQUIDS, LLCNGL-MA, LLCNGL-MA REAL ESTATE, LLCNGL MARINE, LLCNGL MILAN INVESTMENTS, LLCNGL-NE REAL ESTATE, LLCNGL PROPANE, LLCNGL SHIPPING AND TRADING, LLCNGL SUPPLY TERMINAL COMPANY, LLCNGL SUPPLY WHOLESALE, LLCNGL WATER SOLUTIONS BAKKEN, LLCNGL WATER SOLUTIONS EAGLE FORD, LLCNGL WATER SOLUTIONS, LLCNGL WATER SOLUTIONS PERMIAN, LLCNGL WATER SOLUTIONS DJ, LLCNGL WATER SOLUTIONS MID-CONTINENT, LLCOSTERMAN PROPANE, LLCTRANSMONTAIGNE LLCTRANSMONTAIGNE PRODUCT SERVICES LLCTRANSMONTAIGNE SERVICES LLCTRANSMONTAIGNE GP L.L.C. By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Chief Financial Officer and Treasurer Signature Page to Amendment No. 8 to Note Purchase Agreement Exhibit 4.24 FOURTH SUPPLEMENTAL INDENTURE FOURTH SUPPLEMENTAL INDENTURE, dated as of December 1, 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”)and NGL Milan Investments, LLC, a Colorado limited liability company, and NGL Water Solutions Mid-Continent, LLC, a Colorado limited liabilitycompany, each a subsidiary of NGL LP (together, the “Guaranteeing Subsidiaries” and each, a “Guaranteeing Subsidiary”), the other Guarantors (as definedin 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 Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Second SupplementalIndenture, dated as of April 22, 2014 (the “Second Supplemental Indenture”), pursuant to which certain subsidiaries of NGL LP became Guarantors; WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Third Supplemental Indenture,dated as of July 31, 2014 (the “Third 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, the Second Supplemental Indenture and theThird Supplemental Indenture, is referred to herein as the “Indenture”; WHEREAS, the Indenture provides that under certain circumstances, a Guaranteeing Subsidiary shall execute and deliver to the Trustee asupplemental indenture pursuant to which such 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,the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows: 1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. AGREEMENT TO GUARANTEE. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject tothe conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof. 3. EXECUTION AND DELIVERY. Each Guaranteeing Subsidiary agrees that the Note Guarantees shall remain in full force and effect notwithstandingany 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 orother owner of Capital Stock (as defined in the Indenture) of any Guaranteeing Subsidiary or agent thereof, as such, shall have any liability for anyobligations of the Issuers, the Guarantors, or any Guaranteeing Subsidiary or any other Subsidiary of an Issuer providing a Note Guarantee under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligationsor their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of theconsideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of theSEC 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 of themtogether represent the same agreement. 7. EFFECT OF HEADINGS. The Section headings herein are for convenience only and shall not affect the construction hereof. 8. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this SupplementalIndenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers. (Signature Pages Follow) 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: NGL WATER SOLUTIONS MID-CONTINENT, LLCNGL MILAN INVESTMENTS, LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer ISSUERS: NGL ENERGY PARTNERS LP By:NGL Energy Holdings, LLC,its general partner By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer NGL ENERGY FINANCE CORP. By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Senior Vice President, Chief Financial Officerand Secretary (Signature Page to Fourth Supplemental Indenture) EXISTING GUARANTORS: NGL ENERGY OPERATING LLCNGL LIQUIDS, LLCHICKSGAS, LLCNGL PROPANE, LLCNGL SUPPLY TERMINAL COMPANY, LLCNGL SUPPLY WHOLESALE, LLCOSTERMAN PROPANE, LLCNGL-NE REAL ESTATE, LLCNGL-MA REAL ESTATE, LLCNGL-MA, LLCNGL CRUDE LOGISTICS, LLCNGL ENERGY HOLDINGS II, LLCNGL ENERGY LOGISTICS, LLCNGL CRUDE TERMINALS, LLCNGL CRUDE CUSHING, LLCNGL CRUDE PIPELINES, LLCNGL SHIPPING AND TRADING, LLCANTICLINE DISPOSAL, LLCCENTENNIAL ENERGY, LLCCENTENNIAL GAS LIQUIDS ULCHIGH SIERRA CRUDE OIL & MARKETING, LLCNGL WATER SOLUTIONS DJ, LLCANDREWS OIL BUYERS, INC.NGL MARINE, LLCNGL WATER SOLUTIONS EAGLE FORD, LLCNGL WATER SOLUTIONS, LLCNGL CRUDE CANADA HOLDINGS, LLCNGL WATER SOLUTIONS PERMIAN, LLCNGL CRUDE TRANSPORTATION, LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer (Signature Page to Fourth Supplemental Indenture) TRANSMONTAIGNE INC.TRANSMONTAIGNE PRODUCT SERVICES INC.TRANSMONTAIGNE SERVICES INC.TRANSMONTAIGNE GP, LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Vice President HIGH SIERRA ENERGY OPERATING, 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 (Signature Page to Fourth Supplemental Indenture) TRUSTEE: U.S. BANK NATIONAL ASSOCIATION, as Trustee By:/s/ Israel LugoName:Israel LugoTitle:Vice President (Signature Page to Fourth Supplemental Indenture) Exhibit 4.25 FIFTH SUPPLEMENTAL INDENTURE FIFTH SUPPLEMENTAL INDENTURE, dated as of February 17, 2015 (this “Supplemental Indenture”), among NGL Energy Partners LP, a Delawarelimited partnership (“NGL LP”), NGL Energy Finance Corp., a Delaware corporation (“Finance Corp.,” and, together with NGL LP, the “Issuers”) and NGLWater Solutions Bakken, LLC, a Colorado limited liability company, Grand Mesa Pipeline, LLC, a Delaware limited liability company and Blue Grama LandCorporation, a Colorado corporation, each a subsidiary of NGL LP (together, the “Guaranteeing Subsidiaries” and each, a “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 Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Second SupplementalIndenture, dated as of April 22, 2014 (the “Second Supplemental Indenture”), pursuant to which certain subsidiaries of NGL LP became Guarantors; WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Third Supplemental Indenture,dated as of July 31, 2014 (the “Third Supplemental Indenture”), pursuant to which certain subsidiaries of NGL LP became Guarantors; WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed an delivered to the Trustee the Fourth Supplemental Indenture,dated December 1, 2014 (the “Fourth 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, the Second Supplemental Indenture, theThird Supplemental Indenture and the Fourth Supplemental Indenture is referred to herein as the “Indenture”; WHEREAS, the Indenture provides that under certain circumstances, a Guaranteeing Subsidiary shall execute and deliver to the Trustee asupplemental indenture pursuant to which such 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,the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows: 1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. AGREEMENT TO GUARANTEE. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject tothe conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof. 3. EXECUTION AND DELIVERY. Each Guaranteeing Subsidiary agrees that the Note Guarantees shall remain in full force and effect notwithstandingany 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 orother owner of Capital Stock (as defined in the Indenture) of any Guaranteeing Subsidiary or agent thereof, as such, shall have any liability for anyobligations of the Issuers, the Guarantors, or any Guaranteeing Subsidiary or any other Subsidiary of an Issuer providing a Note Guarantee under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligationsor their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of theconsideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of theSEC 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 of themtogether represent the same agreement. 7. EFFECT OF HEADINGS. The Section headings herein are for convenience only and shall not affect the construction hereof. 8. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this SupplementalIndenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers. [Signature Pages Follow] 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: NGL WATER SOLUTIONS BAKKEN, LLCGRAND MESA PIPELINE, LLCBLUE GRAMA LAND CORPORATION By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer ISSUERS: NGL ENERGY PARTNERS LP By:NGL Energy Holdings, LLC,its general partner By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer NGL ENERGY FINANCE CORP. By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Senior Vice President, Chief Financial Officerand Secretary (Signature Page to Fifth Supplemental Indenture) EXISTING GUARANTORS: NGL ENERGY OPERATING LLCNGL LIQUIDS, LLCHICKSGAS, LLCNGL PROPANE, LLCNGL SUPPLY TERMINAL COMPANY, LLCNGL SUPPLY WHOLESALE, LLCOSTERMAN PROPANE, LLCNGL-NE REAL ESTATE, LLCNGL-MA REAL ESTATE, LLCNGL-MA, LLCNGL CRUDE LOGISTICS, LLCNGL ENERGY HOLDINGS II, LLCNGL ENERGY LOGISTICS, LLCNGL CRUDE TERMINALS, LLCNGL CRUDE CUSHING, LLCNGL CRUDE PIPELINES, LLCNGL SHIPPING AND TRADING, LLCANTICLINE DISPOSAL, LLCCENTENNIAL ENERGY, LLCCENTENNIAL GAS LIQUIDS ULCHIGH SIERRA CRUDE OIL & MARKETING, LLCNGL WATER SOLUTIONS DJ, LLCANDREWS OIL BUYERS, INC.NGL MARINE, LLCNGL WATER SOLUTIONS EAGLE FORD, LLCNGL WATER SOLUTIONS, LLCNGL CRUDE CANADA HOLDINGS, LLCNGL WATER SOLUTIONS PERMIAN, LLCNGL CRUDE TRANSPORTATION, LLCNGL WATER SOLUTIONS MID-CONTINENT, LLCNGL MILAN INVESTMENTS, LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer (Signature Page to Fifth Supplemental Indenture) TRANSMONTAIGNE INC.TRANSMONTAIGNE PRODUCT SERVICES INC.TRANSMONTAIGNE SERVICES INC.TRANSMONTAIGNE GP, LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Vice President HIGH SIERRA ENERGY OPERATING, 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 (Signature Page to Fifth Supplemental Indenture) TRUSTEE: U.S. BANK NATIONAL ASSOCIATION, as Trustee By:/s/ Israel LugoName:Israel LugoTitle:Vice President (Signature Page to Fifth Supplemental Indenture) Exhibit 4.32 SECOND SUPPLEMENTAL INDENTURE SECOND SUPPLEMENTAL INDENTURE, dated as of December 1, 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”)and NGL Milan Investments, LLC, a Colorado limited liability company, and NGL Water Solutions Mid-Continent, LLC, a Colorado limited liabilitycompany, each a subsidiary of NGL LP (together, the “Guaranteeing Subsidiaries” and each, a “Guaranteeing Subsidiary”), the other Guarantors (as definedin the Indenture referred to herein), and U.S. Bank National Association, as trustee under the Indenture referred to below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee an indenture, dated as of July 9,2014 (the “Original Indenture”), providing for the issuance by the Issuers of 5.125% Senior Notes due 2019 (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 July 31, 2014 (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, a Guaranteeing Subsidiary shall execute and deliver to the Trustee asupplemental indenture pursuant to which such 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,the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows: 1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. AGREEMENT TO GUARANTEE. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject tothe conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof. 3. EXECUTION AND DELIVERY. Each Guaranteeing Subsidiary agrees that the Note Guarantees shall remain in full force and effect notwithstandingany 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 orother owner of Capital Stock (as defined in the Indenture) of any Guaranteeing Subsidiary or agent thereof, as such, shall have any liability for anyobligations of the Issuers, the Guarantors, or any Guaranteeing Subsidiary or any other Subsidiary of an Issuer providing a Note Guarantee under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligationsor their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of theconsideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of theSEC 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 of themtogether represent the same agreement. 7. EFFECT OF HEADINGS. The Section headings herein are for convenience only and shall not affect the construction hereof. 8. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this SupplementalIndenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers. [Signature Pages Follow] 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: NGL WATER SOLUTIONS MID-CONTINENT, LLCNGL MILAN INVESTMENTS, LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer ISSUERS: NGL ENERGY PARTNERS LP By:NGL Energy Holdings, LLC,its general partner By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer NGL ENERGY FINANCE CORP. By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Senior Vice President, Chief Financial Officerand Secretary (Signature Page to Second Supplemental Indenture) EXISTING GUARANTORS: NGL ENERGY OPERATING LLCNGL LIQUIDS, LLCHICKSGAS, LLCNGL PROPANE, LLCNGL SUPPLY TERMINAL COMPANY, LLCNGL SUPPLY WHOLESALE, LLCOSTERMAN PROPANE, LLCNGL-NE REAL ESTATE, LLCNGL-MA REAL ESTATE, LLCNGL-MA, LLCNGL CRUDE LOGISTICS, LLCNGL ENERGY HOLDINGS II, LLCNGL ENERGY LOGISTICS, LLCNGL CRUDE TERMINALS, LLCNGL CRUDE CUSHING, LLCNGL CRUDE PIPELINES, LLCNGL SHIPPING AND TRADING, LLCANTICLINE DISPOSAL, LLCCENTENNIAL ENERGY, LLCCENTENNIAL GAS LIQUIDS ULCHIGH SIERRA CRUDE OIL & MARKETING, LLCNGL WATER SOLUTIONS DJ, LLCANDREWS OIL BUYERS, INC.NGL MARINE, LLCNGL WATER SOLUTIONS EAGLE FORD, LLCNGL WATER SOLUTIONS, LLCNGL CRUDE CANADA HOLDINGS, LLCNGL WATER SOLUTIONS PERMIAN, LLCNGL CRUDE TRANSPORTATION, LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer (Signature Page to Second Supplemental Indenture) TRANSMONTAIGNE INC.TRANSMONTAIGNE PRODUCT SERVICES INC.TRANSMONTAIGNE SERVICES INC.TRANSMONTAIGNE GP, LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Vice President HIGH SIERRA ENERGY OPERATING, 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 (Signature Page to Second Supplemental Indenture) TRUSTEE: U.S. BANK NATIONAL ASSOCIATION, as Trustee By:/s/ Israel LugoName:Israel LugoTitle:Vice President (Signature Page to Second Supplemental Indenture) Exhibit 4.33 THIRD SUPPLEMENTAL INDENTURE THIRD SUPPLEMENTAL INDENTURE, dated as of February 17, 2015 (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”)and NGL Water Solutions Bakken, LLC, a Colorado limited liability company, Grand Mesa Pipeline, LLC, a Delaware limited liability company and BlueGrama Land Corporation, a Colorado corporation, each a subsidiary of NGL LP (together, the “Guaranteeing Subsidiaries” and each, a “GuaranteeingSubsidiary”), the other Guarantors (as defined in the Indenture referred to herein), and U.S. Bank National Association, as trustee under the Indenture referredto below (the “Trustee”). W I T N E S S E T H WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee an indenture, dated as of July 9,2014 (the “Original Indenture”), providing for the issuance by the Issuers of 5.125% Senior Notes due 2019 (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 July 31, 2014 (the “First Supplemental Indenture”), pursuant to which certain subsidiaries of NGL LP became Guarantors; WHEREAS, the Issuers and certain subsidiaries of NGL LP have heretofore executed and delivered to the Trustee the Second SupplementalIndenture, dated as of December 1, 2014, (the “Second 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 and the Second Supplemental Indenture, isreferred to herein as the “Indenture”; WHEREAS, the Indenture provides that under certain circumstances, a Guaranteeing Subsidiary shall execute and deliver to the Trustee asupplemental indenture pursuant to which such 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,the Guaranteeing Subsidiaries and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders of the Notes as follows: 1. CAPITALIZED TERMS. Capitalized terms used herein without definition shall have the meanings assigned to them in the Indenture. 2. AGREEMENT TO GUARANTEE. Each Guaranteeing Subsidiary hereby agrees to provide an unconditional Guarantee on the terms and subject tothe conditions set forth in the Note Guarantee and in the Indenture including but not limited to Article 10 thereof. 3. EXECUTION AND DELIVERY. Each Guaranteeing Subsidiary agrees that the Note Guarantees shall remain in full force and effect notwithstandingany 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 orother owner of Capital Stock (as defined in the Indenture) of any Guaranteeing Subsidiary or agent thereof, as such, shall have any liability for anyobligations of the Issuers, the Guarantors, or any Guaranteeing Subsidiary or any other Subsidiary of an Issuer providing a Note Guarantee under theNotes, any Note Guarantees, the Indenture or this Supplemental Indenture or for any claim based on, in respect of, or by reason of, such obligationsor their creation. Each Holder of the Notes by accepting a Note waives and releases all such liability. The waiver and release are part of theconsideration for issuance of the Notes. Such waiver may not be effective to waive liabilities under the federal securities laws and it is the view of theSEC 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 of themtogether represent the same agreement. 7. EFFECT OF HEADINGS. The Section headings herein are for convenience only and shall not affect the construction hereof. 8. THE TRUSTEE. The Trustee shall not be responsible in any manner whatsoever for or in respect of the validity or sufficiency of this SupplementalIndenture or for or in respect of the recitals contained herein, all of which recitals are made solely by the Guaranteeing Subsidiaries and the Issuers. [Signature Pages Follow] 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: NGL WATER SOLUTIONS BAKKEN, LLCGRAND MESA PIPELINE, LLCBLUE GRAMA LAND CORPORATION By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer ISSUERS: NGL ENERGY PARTNERS LP By:NGL Energy Holdings, LLC,its general partner By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer NGL ENERGY FINANCE CORP. By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Senior Vice President, Chief Financial Officerand Secretary (Signature Page to Third Supplemental Indenture) EXISTING GUARANTORS: NGL ENERGY OPERATING LLCNGL LIQUIDS, LLCHICKSGAS, LLCNGL PROPANE, LLCNGL SUPPLY TERMINAL COMPANY, LLCNGL SUPPLY WHOLESALE, LLCOSTERMAN PROPANE, LLCNGL-NE REAL ESTATE, LLCNGL-MA REAL ESTATE, LLCNGL-MA, LLCNGL CRUDE LOGISTICS, LLCNGL ENERGY HOLDINGS II, LLCNGL ENERGY LOGISTICS, LLCNGL CRUDE TERMINALS, LLCNGL CRUDE CUSHING, LLCNGL CRUDE PIPELINES, LLCNGL SHIPPING AND TRADING, LLCANTICLINE DISPOSAL, LLCCENTENNIAL ENERGY, LLCCENTENNIAL GAS LIQUIDS ULCHIGH SIERRA CRUDE OIL & MARKETING, LLCNGL WATER SOLUTIONS DJ, LLCANDREWS OIL BUYERS, INC.NGL MARINE, LLCNGL WATER SOLUTIONS EAGLE FORD, LLCNGL WATER SOLUTIONS, LLCNGL CRUDE CANADA HOLDINGS, LLCNGL WATER SOLUTIONS PERMIAN, LLCNGL CRUDE TRANSPORTATION, LLCNGL WATER SOLUTIONS MID-CONTINENT, LLCNGL MILAN INVESTMENTS, LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Executive Vice President, Chief Financial Officerand Treasurer (Signature Page to Third Supplemental Indenture) TRANSMONTAIGNE INC.TRANSMONTAIGNE PRODUCT SERVICES INC.TRANSMONTAIGNE SERVICES INC.TRANSMONTAIGNE GP, LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Vice President HIGH SIERRA ENERGY OPERATING, 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 (Signature Page to Third Supplemental Indenture) TRUSTEE: U.S. BANK NATIONAL ASSOCIATION, as Trustee By:/s/ Israel LugoName:Israel LugoTitle:Vice President (Signature Page to Third Supplemental Indenture) Exhibit 10.13 AMENDMENT NO. 9 TO CREDIT AGREEMENT AMENDMENT NO. 9 TO CREDIT AGREEMENT, dated as of May 1, 2015 (this “Amendment”) to the Credit Agreement dated as of June 19,2012, as amended by Amendment No. 1 thereto dated as of January 15, 2013, Amendment No. 2 thereto dated as of May 8, 2013, Amendment No. 3 theretodated as of September 30, 2013, Amendment No. 4 thereto dated as of November 5, 2013, Amendment No. 5 thereto dated as of December 23, 2013,Amendment No. 6 thereto dated as of June 12, 2014, Amendment No. 7 thereto dated as of June 27, 2014, and Amendment No. 8 thereto dated as of December19, 2014 (the credit agreement, as so amended and as otherwise amended, supplemented and modified from time to time, the “Credit Agreement”) amongNGL ENERGY PARTNERS LP, a Delaware limited partnership (“Parent”), NGL ENERGY OPERATING LLC, a Delaware limited liability company(“Borrowers’ Agent”), each subsidiary of the Parent identified as a “Borrower” under the Credit Agreement (together with the Borrowers’ Agent, each, a“Borrower” and collectively, the “Borrowers”), DEUTSCHE BANK AG, NEW YORK BRANCH, as technical agent (in such capacity, together with itssuccessors in such capacity, the “Technical Agent”) and DEUTSCHE BANK TRUST COMPANY AMERICAS (“DBTCA”), as administrative agent for theSecured Parties (in such capacity, together with its successors in such capacity, the “Administrative Agent”) and as collateral agent for the Secured Parties (insuch capacity, together with its successors in such capacity, the “Collateral Agent”) and each financial institution identified as a “Lender” or an “IssuingBank” under the Credit Agreement (each, a “Lender” and together with the Technical Agent, the Administrative Agent and the Collateral Agent, the“Secured Parties”). RECITALS WHEREAS, the Borrowers have requested certain amendments to the Credit Agreement; and WHEREAS, the Lenders have agreed to amend the Credit Agreement solely upon the terms and conditions set forth herein; NOW, THEREFORE, in consideration of the premises and the agreements hereinafter set forth, the parties hereto hereby agree as follows: 1. Defined Terms. Unless otherwise noted herein, terms defined in the Credit Agreement and used herein shall have the respective meaningsgiven to them in the Credit Agreement. 2. Amendments to Section 1.1 (Defined Terms) of the Credit Agreement. The following terms: “Acquisition Revolving Lenders”,“Acquisition Revolving Loans”, “Reallocated Amount”, “Reallocation Period” and “Reallocation Request” as set forth in Section 1.1 of the CreditAgreement are hereby amended and restated in their entirety as follows: ““Acquisition Revolving Lenders” means, as of any date of determination, Lenders having an Acquisition Revolving Commitment; provided thatduring any Reallocation Period, each Working Capital Revolving Lender shall also be deemed an Acquisition Revolving Lender with respect toits portion of the Reallocated Amount.” ““Acquisition Revolving Loans” means the Acquisition Revolving Loans made pursuant to Section 2.1 and any Acquisition Revolving Loansmade utilizing the Reallocated Amount. Acquisition Revolving Loan means any one of such Revolving Loans.” ““Reallocated Amount” means, with respect to any Revolving Facility, the amount of the unused Revolving Commitments of such RevolvingFacility reallocated to the Revolving Commitments of any other Revolving Facility pursuant to a Reallocation Request; provided, that the totalReallocated Amount shall not exceed the lesser of (a) the unused Revolving Commitments of such Revolving Facility on the date of such request,and (b) $125,000,000 (as such amount may be reduced from time to time in accordance with Section 2.4(a)).” ““Reallocation Period” means a period, not to exceed 180 days, during which a portion of the unused Revolving Commitments of any singleRevolving Facility has been reallocated to the Revolving Commitments of any other Revolving Facility pursuant to a Reallocation Request. There may be no more than three (3) Reallocation Periods per Revolving Facility per fiscal year.” ““Reallocation Request” means a written request from Borrowers’ Agent to reallocate up to $125,000,000 of the unused Revolving Commitmentsof any single Revolving Facility to the Revolving Commitments of any other Revolving Facility, which request shall provide the amount of thereallocation (not to exceed the Reallocated Amount) and specify the Reallocation Period.” 3. Amendments to Section 1.1 (Defined Terms) of the Credit Agreement. Section 1.1 of the Credit Agreement is hereby further amended byadding into Section 1.1 of the Credit Agreement the below terms as new defined terms in the appropriate alphabetical order: ““Revolving Commitments” means collectively, the Acquisition Revolving Commitment and the Working Capital Revolving Commitment.” ““Revolving Facilities” means collectively, the Acquisition Facility and the Working Capital Revolving Facility.” 4. Amendment to Section 2.1(c) of the Credit Agreement (Commitments). The first sentence of Section 2.1(c) of the Credit Agreement ishereby amended and restated in its entirety as follows: “Subject to the terms and conditions hereof and so long as no Default or Event of Default exists at the time of such request, the Borrowers’ Agentmay submit a Reallocation Request to the Administrative Agent three times per Revolving Facility during any fiscal year.” 5. Amendment to Section 2.4(a) of the Credit Agreement (Termination and Reductions of Revolving Commitments; Increase in TotalCommitments). Clause (B) of Section 2.4(a)(ii) of the Credit Agreement is hereby amended and restated in its entirety as follows: “(B) any reduction to any Revolving Commitment shall also reduce the amount specified in clause (b) of the defined term “Reallocated Amount”pro rata based on the applicable percentage reduction of such Revolving Commitment.” 6. Amendment to Section 2.5(c) of the Credit Agreement (Mandatory Prepayments). The first sentence of Section 2.5(c) of the CreditAgreement is hereby amended by adding the following phrase directly after the phrase “at any time exceeds the Total Acquisition Revolving Commitment”: “(including upon the conclusion of any Reallocation Period)”. 7. Amendment to Section 7.10(a) of the Credit Agreement (Redemption, Dividends, Equity Issuance, Distributions and Payments). Clause (i)of Section 7.10(a) of the Credit Agreement is hereby amended and restated in its entirety as follows: (i) the redemption by Parent of common units of Parent for an amount not to exceed $15,000,000 in the aggregate in any fiscal year or$50,000,000 in the aggregate during the term of this Agreement exclusive of redemptions permitted under clause (ii) of this Section 7.10(a);provided that for the fiscal year ending March 31, 2016, the Parent shall be permitted to redeem the common units of Parent for an amount not toexceed $45,000,000, or”. 8. Representations and Warranties; No Default. To induce the Lenders to enter into this Amendment, each Credit Party that is a party hereto(by delivery of its respective counterpart to this Amendment) hereby (i) represents and warrants to the Administrative Agent and the Lenders that after givingeffect to this Amendment, its representations and warranties contained in the Credit Agreement and other Loan Documents are 2 true and correct in all material respects on and as of the date hereof with the same effect as though made on and as of the date hereof, except to the extent suchrepresentations and warranties expressly relate to an earlier date (in which case such representations and warranties were true and correct in all materialrespects as of such earlier date); (ii) represents and warrants to the Administrative Agent and the Lenders that in connection with this Amendment and allother documents delivered in connection herewith it (x) has the requisite power and authority to make, deliver and perform the same; (y) has taken allnecessary corporate, limited liability company, limited partnership or other action to authorize its execution, delivery and performance of the same, and (z)has duly executed and delivered the same; and (iii) certifies that no Default or Event of Default has occurred and is continuing under the Credit Agreement(both immediately before and after giving effect to this Amendment) or will result from the making of this Amendment. 9. Conditions to Effectiveness. This Amendment shall become effective upon the first date on which each of the following conditions hasbeen satisfied: (a) Amended Loan Documents. The Administrative Agent shall have received this Amendment executed and delivered by a dulyauthorized officer of each Credit Party party hereto and duly executed counterparts to this Amendment from the Lenders constituting the RequiredLenders. (b) Fees and Expenses. The Borrowers shall have paid to the Administrative Agent for the account of the Lenders the amount of anyand all reasonable fees, costs and expenses that are for the account of the Borrowers pursuant to Section 10.9 of the Credit Agreement, including allsuch fees, costs and expenses incurred in connection with this Amendment. (c) Proceedings and Documents: All corporate and other proceedings pertaining directly to this Amendment and all documents andinstruments directly incident to this Amendment shall be satisfactory to the required Lenders and their counsel and the Technical Agent shall havereceived all such counterpart originals or certified or other copies of such documents as the Technical Agent may reasonably request. 10. Limited Effect. Except as expressly provided hereby, all of the terms and provisions of the Credit Agreement and the other LoanDocuments are and shall remain in full force and effect. The amendments contained herein shall not be construed as a waiver or amendment of any otherprovision of the Credit Agreement or the other Loan Documents or for any purpose, except as expressly set forth herein, or a consent to any further or futureaction on the part of any Credit Party that would require the waiver or consent of the Lenders. This Amendment shall constitute a “Loan Document” for allpurposes of the Credit Agreement and the other Loan Documents. 11. GOVERNING LAW. THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THISAMENDMENT SHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE SUBSTANTIVE LAW OF THE STATE OF NEWYORK. 12. Counterparts. This Amendment may be executed in any number of counterparts, all of which taken together shall constitute one and thesame agreement, and any of the parties hereto may execute this Amendment by signing any such counterpart. Delivery of an executed counterpart hereof byfacsimile or email transmission shall be effective as delivery of a manually executed counterpart hereof. 13. Headings. Section or other headings contained in this Amendment are for reference purposes only and shall not in any way affect themeaning or interpretation of this Amendment. 14. Guarantor Acknowledgement. Each Guarantor party hereto hereby (i) consents to the modifications to the Credit Agreement contemplatedby this Amendment and (ii) acknowledges and agrees that its guaranty pursuant to Section 10.18 of the Credit Agreement is, and shall remain, in full forceand effect after giving effect to the Amendment. 15. Lender Acknowledgement. Each undersigned Lender, by its signature hereto, hereby authorizes and directs DBTCA in its capacity asAdministrative Agent and as Collateral Agent to execute this Amendment. 3 [SIGNATURE PAGES FOLLOW] 4 IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed and delivered by their proper and duly authorizedofficers as of the day and year first above written. BORROWERS’ AGENT: NGL ENERGY OPERATING LLC By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Chief Financial Officer and Treasurer GUARANTOR: 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 Signature Page to Amendment No. 9 to Credit Agreement CREDIT PARTIES: ANDREWS OIL BUYERS, INC.ANTICLINE DISPOSAL, LLCBLUE GRAMA LAND CORPORATIONCENTENNIAL ENERGY, LLCCENTENNIAL GAS LIQUIDS ULCGRAND MESA PIPELINE, LLCHICKSGAS, LLCHIGH SIERRA CRUDE OIL & MARKETING, LLCHIGH SIERRA ENERGY, LP (BY High Sierra Energy GP, LLC, its generalpartner)HIGH SIERRA ENERGY MARKETING, LLCHIGH SIERRA ENERGY OPERATING, LLCNGL CRUDE CANADA HOLDINGS, LLCNGL CRUDE CUSHING, LLCNGL CRUDE LOGISTICS, LLCNGL CRUDE PIPELINES, LLCNGL CRUDE TERMINALS, LLCNGL CRUDE TRANSPORTATION, LLCNGL ENERGY HOLDINGS II, LLCNGL ENERGY LOGISTICS, LLCNGL ENERGY OPERATING LLCNGL LIQUIDS, LLCNGL-MA, LLCNGL-MA REAL ESTATE, LLCNGL MARINE, LLCNGL MILAN INVESTMENTS, LLCNGL-NE REAL ESTATE, LLCNGL PROPANE, LLCNGL SHIPPING AND TRADING, LLCNGL SUPPLY TERMINAL COMPANY, LLCNGL SUPPLY WHOLESALE, LLCNGL WATER SOLUTIONS BAKKEN, LLCNGL WATER SOLUTIONS EAGLE FORD, LLCNGL WATER SOLUTIONS, LLCNGL WATER SOLUTIONS PERMIAN, LLCNGL WATER SOLUTIONS DJ, LLCNGL WATER SOLUTIONS MID-CONTINENT, LLCOSTERMAN PROPANE, LLCTRANSMONTAIGNE LLCTRANSMONTAIGNE PRODUCT SERVICES LLCTRANSMONTAIGNE SERVICES LLCTRANSMONTAIGNE GP L.L.C. By:/s/ Atanas H. AtanasovName:Atanas H. AtanasovTitle:Chief Financial Officer and Treasurer Signature Page to Amendment No. 9 to Credit Agreement SECURED PARTIES: DEUTSCHE BANK TRUST COMPANY AMERICAS, as Administrative Agentand as Collateral Agent By:/s/ Nigel LukeName:Nigel LukeTitle:Vice President By:/s/ Deirdra N. RossName:Deirdra N. RossTitle:Vice President DEUTSCHE BANK AG, NEW YORK BRANCH,as a Lender, as Swingline Lender, as an Issuing Bank and as Technical Agent By:/s/ Shai BandnerName:Shai BandnerTitle:Vice President By:/s/ Vanuza Pereira-BravoName:Vanuza Pereira-BravoTitle:Assistant Vice President Signature Page to Amendment No. 9 to Credit Agreement ROYAL BANK OF CANADA,as a Lender By:/s/ Jason S. YorkName:Jason S. YorkTitle:Authorized Signatory Signature Page to Amendment No. 9 to Credit Agreement BNP PARIBAS,as a Lender and Issuing Bank By:/s/ Keith CoxName:Keith CoxTitle:Managing Director By:/s/ Christine DirringerName:Christine DirringerTitle:Managing Director Signature Page to Amendment No. 9 to Credit Agreement THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.,as Lender By:Name:Title: Signature Page to Amendment No. 9 to Credit Agreement PNC BANK, NATIONAL ASSOCIATION,as a Lender and Issuing Bank By:/s/ Jessica McGuireName:Jessica McGuireTitle:Assistant Vice President Signature Page to Amendment No. 9 to Credit Agreement THE ROYAL BANK OF SCOTLAND PLC,as a Lender By:Name:Title: Signature Page to Amendment No. 9 to Credit Agreement BMO HARRIS BANK N.A,as a Lender By:/s/ Kimberly A. YatesName:Kimberly A. YatesTitle:Director Signature Page to Amendment No. 9 to Credit Agreement RAYMOND JAMES BANK, N.A.,as a Lender By:/s/ Scott G. AxelrodName:Scott G. AxelrodTitle:Senior Vice President Signature Page to Amendment No. 9 to Credit Agreement ABN AMRO CAPITAL USA LLC,as a Lender By:Name:Title: By:Name:Title: Signature Page to Amendment No. 9 to Credit Agreement BANK OF AMERICA, N.A.,as a Lender and as an Issuing Bank By:/s/ Michael ClayborneName:Michael ClayborneTitle:Vice President Signature Page to Amendment No. 9 to Credit Agreement SUNTRUST BANK,as a Lender By:/s/ Carmen MaliziaName:Carmen MaliziaTitle:Director Signature Page to Amendment No. 9 to Credit Agreement UBS AG, STAMFORD BRANCH,as a Lender By:/s/ Darlene AriasName:Darlene AriasTitle:Director By:/s/ Craig PearsonName:Craig PearsonTitle:Associate Director Signature Page to Amendment No. 9 to Credit Agreement COMMERCE BANK, N.A.,as a Lender By:/s/ Shannon O’DohertyName:Shannon O’DohertyTitle:President Signature Page to Amendment No. 9 to Credit Agreement AMEGY BANK NATIONAL ASSOCIATION,as a Lender By:/s/ Kevin DonaldsonName:Kevin DonaldsonTitle:Senior Vice President Signature Page to Amendment No. 9 to Credit Agreement GOLDMAN SACHS BANK USA,as a Lender By:/s/ Jamie MinieriName:Jamie MinieriTitle:Authorized Signatory Signature Page to Amendment No. 9 to Credit Agreement MACQUARIE BANK LIMITED,as a Lender By:/s/ Robert TrevenaName:Robert TrevenaTitle:Division Director By:/s/ Fiona SmithName:Fiona SmithTitle:Division Director Signature Page to Amendment No. 9 to Credit Agreement HSBC BANK USA, NA,as a Lender By:Name:Title: Signature Page to Amendment No. 9 to Credit Agreement KEYBANK NATIONAL ASSOCIATION,as a Lender By:Name:Title: Signature Page to Amendment No. 9 to Credit Agreement WELLS FARGO BANK, NATIONAL ASSOCIATION,as a Lender By:/s/ Jacob L. OstermanName:Jacob L. OstermanTitle:Vice President Signature Page to Amendment No. 9 to Credit Agreement BARCLAYS BANK PLC,as a Lender By:/s/ Luke SymeName:Luke SymeTitle:Assistant Vice President Signature Page to Amendment No. 9 to Credit Agreement SOCIÉTÉ GÉNÉRALEas a Lender By:/s/ Michiel V.M. van der VoortName:Michiel V.M. van der VoortTitle:Managing Director Signature Page to Amendment No. 9 to Credit Agreement MIZUHO BANK, LTD.as a Lender By:Name:Title: Signature Page to Amendment No. 9 to Credit Agreement Exhibit 10.18 NGL Performance Unit Program NGL has created a Performance Unit Program to reward senior management for total unit return, over a rolling three (3) year average, and further align us withour unit holders. Each year we will evaluate NGL’s unit performance for the current and two (2) prior years. The performance will be total return to our unit holders - change inunit price plus distributions. We will then rank NGL against the other companies in the Alerian Index on the same basis. The ranking period will be for three(3) years beginning on July 1 and ending on June 30 three years later. This period aligns us with the reporting of our fiscal year end numbers, which arereleased June 1 (60 days after the close of our fiscal year). The vesting requirements of this plan follow those of the Company’s LTIP plan. Accordingly, youmust be employed on July 1 to receive the performance plan units. The units you will receive under this plan are based on a multiple of that year’s Restricted (time-based) LTIP units you have. Based on NGL’s rank againstthe other companies in the Alerian Index, for the three year period, the multiplier will be calculated as follows: ·If NGL ranks less than the 50 percentile, the multiplier is 0·Between the 50 and 75 percentile the multiplier ranges from 50% to 100%·Between the 75 and 90 percentile the multiplier ranges from 100% to 200%·Above the 90 percentile – 200% The look back period for calculating NGL’s ranking in the Alerian will be: ·2015 – 3 yearsJuly 1, 2012 to June 30, 2015·2016 – 3 yearsJuly 1, 2013 to June 30, 2016·2017 – 3 yearsJuly 1, 2014 to June 30, 2017·2018 and beyondRolling 3 years For example: If you have 5,000 Restricted (time-based) units that vest on July 1, then if on June 30 of that same year we are at the 92 percentile of the Alerian companies,for the three (3) year period, you would receive an additional 10,000 units (5,000 X 200% = 10,000). These are in addition to the 5,000 Restricted (time-based) units. For that year, you would receive a total of 15,000 units. ththththththndExhibit 12.1 NGL ENERGY PARTNERS LP AND SUBSIDIARIES AND NGL SUPPLY, INC.COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES(In thousands, except ratio amounts) NGL Energy Partners LP NGL Supply, Inc. Six Months Six Months Ended Ended Year Ended March 31, March 31, September 30, 20152014 2013 2012 2011 2010 EARNINGS:Income (loss) before income taxes$26,262$49,695$50,065$8,465$12,679$(3,977)Loss (income) before income taxes attributable tononcontrolling interests(13,223)(1,103)(250)12—45Fixed charges151,95691,62266,8249,3542,761597Total earnings (loss)$164,995$140,214$116,639$17,831$15,440$(3,335) FIXED CHARGES:Interest expense$110,123$58,854$32,994$7,620$2,482$372Loss on early extinguishment of debt——5,769———Portion of rental expense estimated to relate tointerest (1)41,83332,76828,0611,734279225Fixed charges$151,956$91,622$66,824$9,354$2,761$597 Ratio of earnings to fixed charges1.091.531.751.915.59(2) (1) Represents one-third of the total operating lease rental expense, which is that portion estimated to represent interest. (2) Due to NGL Supply, Inc.’s loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2010. NGL Supply, Inc. wouldhave 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 LLCDelawareNGL Energy Finance Corp.DelawareTransMontaigne LLCDelawareAtlantic Propane, LLC (1)OklahomaNGL Crude Logistics, LLCDelawareNGL Crude Transportation, LLCColoradoNGL Crude Terminals, LLCDelawareNGL Marine, LLCTexasGrand Mesa Pipeline, LLCDelawareBlue Grama Land CorporationColoradoNGL Milan Investments, LLCColoradoNGL Crude Cushing, LLCOklahomaE Energy Adams, LLC (2)NebraskaHigh Sierra Crude Oil & Marketing, LLCColoradoNGL Crude Canada Holdings, LLCColoradoNGL Crude Canada ULCAlbertaNGL Crude Pipelines, LLCOklahomaNGL Energy Logistics, LLCDelawareNGL Energy Holdings II, LLCDelawareGlass Mountain Pipeline, LLC (3)DelawareNGL Shipping and Trading, LLCDelawareAndrews Oil Buyers, Inc.TexasNGL Propane, LLCDelawareOsterman Propane, LLCDelawareVictory Propane, LLC (4)OklahomaHicksgas, LLCDelawareNGL-NE Real Estate, LLCDelawareNGL-MA Real Estate, LLCDelawareNGL-MA, LLCDelawareNGL Liquids, LLCDelawareCentennial Energy, LLCColoradoCentennial Gas Liquids, ULCAlbertaNGL Gateway Terminals, Inc.OntarioNGL Supply Terminal Company, LLCDelawareNGL Hutch, LLCDelawareSawtooth NGL Caverns, LLCDelawareNGL Supply Terminal Solution Mining, LLCUtahNGL Supply Wholesale, LLCDelawareNGL Water Solutions, LLCColoradoNGL Water Solutions Bakken, LLCColoradoNGL Water Solutions Mid-Continent, LLCColoradoNGL Solids Solutions, LLC (5)ColoradoAntiCline Disposal, LLCWyomingNGL Water Solutions DJ, LLCColoradoGrassland Water Solutions, LLC (6)DelawareNGL Water Solutions Eagle Ford, LLCDelawareIndigo Injection #3-1, LLC (7)DelawareChoya Operating, LLC (8)TexasNGL Water Solutions Permian, LLCColoradoTransMontaigne Product Services LLCDelawareTransMontaigne Services LLCDelawareTransMontaigne GP, L.L.C.DelawareTransMontaigne Partners L.P. (9)DelawareHigh Sierra Energy GP, LLCColoradoHigh Sierra Energy, LPDelawareHigh Sierra Energy Shared Services, LLCColoradoHigh Sierra Energy Operating, LLCColoradoHigh Sierra Energy Marketing, LLCColoradoHigh Sierra Water Services Midcontinent, LLCOklahoma (1) NGL Energy Partners LP owns a 60% member interest in Atlantic Propane, LLC.(2) NGL Energy Partners LP owns an interest in E Energy Adams, LLC.(3) NGL Energy Partners LP owns a 50% member interest in Glass Mountain Pipeline, LLC.(4) NGL Energy Partners LP owns a 50% member interest in Victory Propane, LLC.(5) NGL Energy Partners LP owns a 50% member interest in NGL Solids Solutions, LLC.(6) NGL Energy Partners LP owns a 27.5% member interest in Grassland Water Solutions, LLC.(7) NGL Energy Partners LP owns a 75% member interest in Indigo Injection #3-1, LLC.(8) NGL Energy Partners LP owns a 75% member interest in Choya Operating, LLC.(9) NGL Energy Partners LP owns a 19.6% member interest in TransMontaigne Partners L.P. Exhibit 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We have issued our reports dated June 1, 2015, with respect to the consolidated financial statements and internal control over financial reportingincluded in the Annual Report of NGL Energy Partners LP on Form 10—K for the year ended March 31, 2015. We hereby consent to the incorporation byreference of said reports in the Registration Statements of NGL Energy Partners LP on Form S-8 (File No. 333-185068) and on Forms S-3 (File No. 333—189842, File No. 333-194035 and File No. 333-198276). /s/ GRANT THORNTON LLP Tulsa, OklahomaJune 1, 2015 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) and15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others withinthose entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, tothe registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: June 1, 2015/s/ H. Michael KrimbillH. Michael KrimbillChief Executive Officer of NGL Energy Holdings LLC, the generalpartner of NGL 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) and15d-15(f)) for the registrant and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision,to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others withinthose entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under oursupervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements forexternal purposes in accordance with generally accepted accounting principles; c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about theeffectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s mostrecent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likelyto materially affect, the registrant’s internal control over financial reporting; and 5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, tothe registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which arereasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internalcontrol over financial reporting. Date: June 1, 2015/s/ Atanas H. AtanasovAtanas H. AtanasovChief Financial Officer of NGL 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, 2015 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. Date: June 1, 2015/s/ H. Michael KrimbillH. Michael KrimbillChief Executive Officer of NGL Energy Holdings LLC, thegeneral partner of NGL Energy Partners LP 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, 2015 asfiled with the Securities and Exchange Commission on the date hereof (the “Report”), I, Atanas H. Atanasov, Chief Financial Officer of NGL Energy HoldingsLLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of2002 (“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. Date: June 1, 2015/s/ Atanas H. AtanasovAtanas H. AtanasovChief Financial Officer of NGL Energy Holdings LLC, thegeneral partner of NGL Energy Partners LP 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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