NGL Energy Partners
Annual Report 2016

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Table of ContentsUNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549Form 10-K(Mark One)ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended March 31, 2016ORo TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the transition period from __________ to __________Commission File Number: 001-35172NGL Energy Partners LP(Exact Name of Registrant as Specified in Its Charter)Delaware 27-3427920(State or Other Jurisdiction of Incorporation or Organization) (I.R.S. Employer Identification No.)6120 South Yale AvenueSuite 805Tulsa, Oklahoma 74136(Address of Principal Executive Offices) (Zip code)(918) 481-1119(Registrant’s Telephone Number, Including Area Code)Securities registered pursuant to Section 12(b) of the Act:Title of Each Class Name of Each Exchange on Which RegisteredCommon Units Representing Limited Partner Interests New York Stock ExchangeSecurities registered pursuant to Section 12(g) of the Act: NoneIndicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No oIndicate 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 ýIndicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No oIndicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted andposted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit andpost such files). Yes ý No oIndicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained,to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. oIndicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of“large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.Large accelerated filer x Accelerated filer oNon-accelerated filer o (Do not check if a smaller reporting company) Smaller reporting company o Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No ýThe aggregate market value at September 30, 2015 of the Common Units held by non-affiliates of the registrant, based on the reported closing price of the Common Units onthe New York Stock Exchange on such date ($19.97 per Common Unit) was $1.9 billion. For purposes of this computation, all executive officers, directors and 10% owners of theregistrant are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers, directors and 10% beneficial owners are affiliates.At May 23, 2016, there were 104,169,573 common units issued and outstanding. Table of ContentsEXPLANATORY NOTEThis Annual Report on Form 10-K of NGL Energy Partners LP (referred to herein as the “Partnership,” “we,” “us” or “our”) includes restatedunaudited quarterly consolidated financial information as of and for the periods ended June 30, 2015, September 30, 2015 and December 31, 2015. We willnot file amended periodic reports for any prior filings, including Forms 10-Q for any of the affected quarterly periods.Restatement BackgroundIn connection with the recording of business combinations that occurred in the fourth quarter of fiscal year 2016, the Partnership identified certaincontingent consideration liabilities in connection with those fourth quarter 2016 business combinations, and determined that the Partnership had notcorrectly accounted for contingent consideration related to royalty payments that were part of certain prior business combinations within its Water Solutionssegment that had occurred prior to the fourth quarter of fiscal year 2016. The application of the correct accounting treatment results in an increase togoodwill, current liabilities and long-term liabilities and an increase to earnings for the first three quarters of the fiscal year ended March 31, 2016.As a result of this error, on May 31, 2016, the Partnership’s management, Audit Committee and Board of Directors concluded, after consideration ofthe relevant facts and circumstances, that the Partnership’s unaudited interim consolidated financial statements set forth in the Partnership’s QuarterlyReports on Form 10-Q for the quarters ended June 30, 2015, September 30, 2015 and December 31, 2015 should be restated and that such financialstatements previously filed with the Securities and Exchange Commission (the “SEC”) should no longer be relied upon and on that date filed a Form 8-Kwith the SEC to report such non-reliance. In addition, based on the relevant facts and circumstances, the Partnership’s management, Audit Committee andBoard of Directors concluded that the correction was not material to any other periods prior to fiscal year 2016.Within this Annual Report on Form 10-K for the year ended March 31, 2016, the Partnership has included restated unaudited quarterly data for eachof the quarters ended June 30, 2015, September 30, 2015 and December 31, 2015 in the notes to the consolidated financial statements. For the financial datarelated to its fiscal year ended March 31, 2015 and all unaudited quarterly financial data for the quarters ended June 30, 2014, September 30, 2014, December31, 2014 and March 31, 2015, the Partnership has included financial data that contains immaterial corrections for this issue.Management has evaluated the effect of the restatements on its prior conclusions regarding the effectiveness of the Partnership’s internal controlover financial reporting and disclosure controls and procedures and has concluded that a material weakness existed during each of the periods requiringcorrection. In connection therewith, the Partnership’s management concluded that during the periods requiring correction, the Partnership did not maintaineffective controls over the identification of assets acquired and liabilities assumed in the Partnership’s business combinations. Accordingly, the Partnership’sinternal control over financial reporting and disclosure controls and procedures were not effective during the periods being corrected.The following parts of this Form 10-K include discussion of or disclosure related to the restatement:•Part I, Item 1A - Risk Factors•Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations•Part II, Item 8 - Financial Statements and Supplementary Data•Part II, Item 9A - Controls and Procedures•Part IV, Item 15 - Exhibits, Financial Statement Schedulesi Table of ContentsTABLE OF CONTENTSPART I Item 1.Business3Item 1A.Risk Factors29Item 1B.Unresolved Staff Comments52Item 2.Properties52Item 3.Legal Proceedings53Item 4.Mine Safety Disclosures53 PART II Item 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities54Item 6.Selected Financial Data56Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations58Item 7A.Quantitative and Qualitative Disclosures About Market Risk100Item 8.Financial Statements and Supplementary Data101Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure101Item 9A.Controls and Procedures101Item 9B.Other Information102 PART III Item 10.Directors, Executive Officers and Corporate Governance103Item 11.Executive Compensation109Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters121Item 13.Certain Relationships and Related Transactions, and Director Independence123Item 14.Principal Accounting Fees and Services127 PART IV Item 15.Exhibits, Financial Statement Schedules128ii Table of ContentsForward-Looking StatementsThis Annual Report on Form 10-K (“Annual Report”) contains various forward-looking statements and information that are based on our beliefs andthose of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as anystatement that does not relate strictly to historical or current facts. Certain words in this Annual Report such as “anticipate,” “believe,” “could,” “estimate,”“expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will,” and similar expressions and statements regarding our plans and objectives for futureoperations, identify forward-looking statements. Although we and our general partner believe such forward-looking statements are reasonable, neither we norour general partner can assure they will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If oneor more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected.Among the key risk factors that may impact our consolidated financial position and results of operations are:•the prices of crude oil, natural gas liquids, refined products, ethanol, and biodiesel;•energy prices generally;•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 where we have water treatment and disposal facilities;•the prices of propane and distillates relative to the prices of alternative and competing fuels;•the price of gasoline relative to the price of corn, which impacts the price of ethanol;•the ability to obtain adequate supplies of products if an interruption in supply or transportation occurs and the availability of capacity totransport products to market areas;•actions taken by foreign oil and gas producing nations;•the political and economic stability of foreign oil and gas 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;•the availability of local, intrastate and interstate transportation infrastructure with respect to our truck, railcar, and barge transportation services;•the availability, price, and marketing of competing 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, waste water disposal and on the treatment of flowback and producedwater;•hazards or operating risks related to transporting and distributing petroleum products that may not be fully covered by insurance;•the maturity of the crude oil, natural gas liquids, and refined products industries and competition from other marketers;•loss of key personnel;•the ability to renew contracts with key customers;•the ability to maintain or increase the margins we realize for our terminal, barging, trucking, water disposal, recycling, and discharge services;•the ability to renew leases for our leased equipment and storage facilities;1 Table of Contents•the nonpayment or nonperformance by our counterparties;•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 hydrocarbons 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 applicable laws and regulations, including tax, environmental, transportation and employment regulations, or new interpretations byregulatory agencies concerning such laws and regulations and the impact of such laws and regulations (now existing or in the future) on ourbusiness operations;•the costs and effects of legal and administrative proceedings;•any reduction or the elimination of the federal Renewable Fuel Standard; 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 underPart I, Item 1A–“Risk Factors.”2 Table of ContentsPART 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 42 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, 2016. Unless otherwise indicated, this data is as ofMarch 31, 2016. Item 1. BusinessOverviewWe are a Delaware limited partnership formed in September 2010. Subsequent to our initial public offering (“IPO”) in May 2011, we significantlyexpanded our operations through numerous acquisitions. At March 31, 2016, our operations include:•Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals and pipeline injection stations, a fleetof owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests in two crude oil pipelines.Our crude oil logistics segment purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipelineinjection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.•Our water solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solidwaste disposal facilities. Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oiland natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck washouts. In addition, ourwater solutions segment sells the recycled water and recovered hydrocarbons that result from performing these services.•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 and storage services through its 19 owned terminals throughout the UnitedStates, its salt dome storage facility in Utah, and its leased storage and railcar transportation services through its fleet of leased railcars.•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 purchaserefined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedule themfor delivery at various locations. See “Dispositions ” below for a discussion of our interests in TransMontaigne Partners L.P. (“TLP”).For more information regarding our reportable segments, please see Note 13 to our consolidated financial statements included in this Annual Report.AcquisitionsSubsequent to our IPO in May 2011, we significantly expanded our operations through numerous acquisitions, including the following, amongothers: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.3 Table of Contents•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 its affiliatedcompanies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texas and NewMexico.•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 requires us to purchase water solutionsfacilities developed by the other party to the agreement. During March 2014, we purchased one additional facility under this developmentagreement.•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 (“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% general partner interest, the incentive distribution rights, a 19.7% limited partner interest in TLP, and assumed certain terminalingservice4 Table of Contentsagreements with TLP from an affiliate of the previous owner of TransMontaigne. See “Dispositions” below for a discussion of the sale of thegeneral partner interest.•In November 2014, we acquired 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 United States markets and entered into a construction agreement to expand the storage capacity of thefacility.•During the year ended March 31, 2015, we purchased 16 water treatment and disposal facilities under the development agreement discussedabove.•During the year ended March 31, 2015, we acquired eight retail propane businesses.Year Ended March 31, 2016•In August 2015, we acquired four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the DelawareBasin of the Permian Basin in Texas.•In January 2016, we acquired a 57.125% interest in an existing produced water pipeline company operating in the Delaware Basin portion ofWest Texas.•During the year ended March 31, 2016, we purchased 15 water treatment and disposal facilities under the development agreement discussedabove.•During the year ended March 31, 2016, we acquired six retail propane businesses.DispositionsSale of General Partner Interest in TLPOn February 1, 2016, we completed the sale of our general partner interest in TLP to an affiliate of ArcLight Capital Partners (“ArcLight”) for $350million in cash. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equitymethod of accounting. As part of this transaction, we entered into lease agreements whereby we will remain the long-term exclusive tenant in the TLPSoutheast terminal system. In addition, we retained TransMontaigne’s marketing business, which is a significant part of our refined products and renewablessegment, and TransMontaigne Product Services, LLC, its customer contracts and its line space on the Colonial and Plantation pipelines.Sale of TLP Common UnitsOn April 1, 2016, we sold all of the TLP common units we owned to ArcLight for approximately $112.4 million in cash.5 Table of ContentsPrimary Service AreasThe following map shows the primary service areas of our businesses:6 Table of ContentsOrganizational ChartThe following chart summarizes our legal entity structure at April 1, 2016:7 Table of ContentsOur Business StrategiesOur 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 customers. 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 own and operate. We have and expect to continue toinvest within our existing businesses, particularly within our crude oil logistics, water solutions, and refined products businesses as we growthese businesses with highly accretive, fee-based organic growth opportunities.•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 current operating platforms, andenhance our geographic diversity in our businesses. We have established a successful track record of acquiring companies and assets atattractive 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. We intend to focus on long-term fee-based contracts in addition to back-to-back contracts whichminimize commodity price exposure. We continue to increase cash flows that are supported by certain fee-based, multi-year contracts, some ofwhich include acreage dedications from producers or volume commitments. We also believe that expanding our retail propane business with anemphasis on a high level of residential customers with company-owned tanks will result in strong customer retention rates and consistentoperating margins.•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 expect to maintain sufficient liquidity to manage existing and futurecapital requirements and to take advantage of market opportunities.•Maintain a disciplined cash distribution policy that complements our leverage, acquisition and organic growth strategies. We intend to usecash flows from our operations to make distributions to our unitholders and to use excess cash flows to finance organic growth andopportunistically repay indebtedness, including amounts outstanding under our Revolving Credit Facility (as hereinafter defined). We believethis strategy positions us to pursue future acquisitions and to execute upon our organic growth initiatives.Our Competitive StrengthsWe believe that we are well positioned to successfully execute our business strategies and achieve our principal business objective because of thefollowing competitive strengths:•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 customers in numerous geographic areas enhances our competitive position. Our five businesses unitsare diversified by geography, customer-base and commodity sensitivities which we believe proves us with the ability to maintain cash flowsthroughout typical commodity cycles. By examples, our retail propane business sources propane through our liquids business which allows usto leverage the expertise of our liquids business to help improve our margins and profitability and enhance our cash flows. Furthermore, webelieve that our liquids business provides us with valuable market intelligence that helps us identify potential acquisition opportunities. Ourrefined products and retail propane businesses benefit from lower energy prices driving increased customer demand, which can offset thedownward pressure on our crude logistics and water businesses in a low price environment.•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 and8 Table of Contentscontracted pipeline capacity, provide access to a wide range of customers and markets. We use this expansive network of transportation assets todeliver 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 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 Businesses Crude Oil LogisticsOverview. Our crude oil logistics segment purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipelineinjection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. We also lease space and capacity in our ownedassets, such as storage tanks, pipelines, trucks, barges, and railcars, to third parties for a fee. 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 crude oil using the following assets:•200 owned trucks and 270 owned trailers operating primarily in the Mid-Continent, Permian Basin, Eagle Ford shale play, and Rocky Mountainregions;•400 owned railcars and 600 leased railcars operating primarily in Colorado, New Mexico, North Dakota, Oklahoma, Wyoming, and West Texas;and•11 owned towboats and 24 owned barges operating primarily in the intercoastal waterways of the Gulf Coast and along the Mississippi andArkansas river systems.Of our 400 owned railcars, all are compliant with the standards for railcars built subsequent to 2011. Of our 600 leased railcars, 100 are compliantwith these standards (see Part I, Item 1A–“Risk Factors).9 Table of ContentsWe contract for truck, rail, and barge transportation services from third parties and ship on 17 common carrier pipelines. We own 35 pipelineinjection stations, the locations of which are summarized below.State Number of Pipeline Injection StationsTexas 14Oklahoma 9New Mexico 5Kansas 3North Dakota 3Montana 1Total 35We also lease three pipeline injection stations in Montana and North Dakota. We also have commitments on several interstate pipelines fortransportation of crude oil.We own seven storage terminal facilities. The largest of these is a terminal in Cushing, Oklahoma with a storage capacity of 4,600,000 barrels,including 1,000,000 barrels which are owned by Glass Mountain. The combined storage capacity of the other six terminals is 462,500 barrels.We lease 2,052,500 barrels of capacity at two storage terminal facilities. Of this leased storage capacity, 2,000,000 barrels are at Cushing, Oklahoma.We have one Gulf Coast terminal facility that is under construction and is expected to be completed during the second quarter of fiscal year 2017with a total expected storage capacity of 285,000 barrels. We own a 50% interest in Glass Mountain, which owns a 210-mile crude oil pipeline that originatesin western Oklahoma and terminates in Cushing, Oklahoma. This pipeline, which became operational in February 2014, has a capacity of 147,000 barrels perday.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”). In October 2014, we obtained ship-or-pay volume commitments from multiple shippers to begin construction of theGrand Mesa Pipeline, which will originate in Colorado and terminate in Cushing, Oklahoma. In November 2014, we acquired RimRock’s 50% ownershipinterest in Grand Mesa for $310.0 million in cash. In November 2015, Grand Mesa Pipeline entered into an agreement with Saddlehorn Pipeline Company,LLC (“Saddlehorn”), under which we acquired a 37.5% undivided interest in a crude oil pipeline currently under construction (the “Joint Pipeline”). TheJoint Pipeline will take receipt from Grand Mesa Pipeline’s origin in Colorado and will deliver to Cushing, Oklahoma. We will have the right to utilize150,000 barrels per day of capacity on the Joint Pipeline. Operating costs will be allocated to us based on our proportionate ownership interest andthroughput. We expect the Joint Pipeline to be operational beginning in the third quarter of fiscal year 2017.Through our undivided interest in the Joint Pipeline, we will have expanded capacity, sufficient to service our customer contracts at the same originand termination points with the ability to accept additional volume commitments. We will retain ownership of our previously-acquired easements for thepotential future development of transportation projects involving petroleum commodities other than crude oil and condensate. With the consent andparticipation of Saddlehorn, we and Saddlehorn may consider future opportunities using these easements for projects involving the transportation of crudeoil and condensate.Customers. Our customers include crude oil refiners, producers, and marketers. During the year ended March 31, 2016, 65% of the revenues of ourcrude 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;10 Table of Contents•reliability of service;•logistics capabilities, including the availability of railcars, proprietary terminals, and owned pipelines, barges, railcars, trucks, and towboats;•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 fromapproximately 350 producers at approximately 4,300 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 forward crude oil pricesare greater than spot prices) or can be backwardated (a condition in which forward crude oil prices are lower than spot prices). Our crude oil logistics businessbenefits when the market is in contango, as increasing prices result in inventory holding gains during the time between when we purchase inventory andwhen 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, fallingprices 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 or other forms of surety 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 SolutionsOverview. Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gasproduction and for the disposal of solids such as tank bottoms and drilling fluids and performs truck washouts. In addition, our water solutions segment sellsthe recycled water and recovered hydrocarbons that result from performing these services. Our water processing facilities are strategically located near areas ofhigh crude oil and natural gas production, including the Permian Basin in Texas, the DJ Basin in Colorado, the Eagle Ford shale play in Texas, the Bakkenshale play in North Dakota, and the Pinedale Anticline in Wyoming. During the year ended March 31, 2016, we took delivery of 208.4 million barrels ofwastewater, an average of 571,000 barrels per day.Our water solutions segment is in the process of expanding its solids disposal business. With the addition of specialized equipment to selectfacilities in the Eagle Ford shale play, the Permian Basin, and the DJ Basin, we are able to accept and dispose of solids such as tank bottoms and drillingfluids generated by crude oil and natural gas exploration and production activities. Our facilities will accept only exploration and production exempt wasteallowed under our current permits.11 Table of ContentsOperations. We own 70 water treatment and disposal facilities, including 87 wells. The location of the facilities and the processing capacities atwhich the facilities currently operate are summarized below.Location Processing Capacity(barrels per day) Located on LandWe Own or LeasePinedale Anticline (1) 60,000 Lease DJ Basin (2) 189,500 OwnDJ Basin 72,500 LeaseTotal-DJ Basin 262,000 Permian Basin (3) 653,000 Own Eagle Ford Shale Play (3) 304,000 OwnEagle Ford Shale Play (3) 169,000 LeaseTotal-Eagle Ford Shale Play 473,000 Eaglebine Shale Play 20,000 Own Granite Wash Shale Play (3) 52,000 Own Bakken Shale Play 30,000 OwnBakken Shale Play 16,000 LeaseTotal-Bakken Shale Play 46,000 Total-All Facilities 1,566,000 (1)This facility has a design capacity of 60,000 barrels per day to process water to a recycle standard which also includes a design capacity of 15,000 barrelsper day to process water to a discharge standard.(2)Reflects the total processing capacity of facilities located on land we own at this location, which includes two facilities that have a combined designcapacity of 20,000 barrels per day to process water to a recycle standard.(3)Certain facilities can dispose of both wastewater and solids such as tank bottoms and drilling fluids. We own a 50% interest in the disposal of solids.In the table above, the processing capacity for the Permian Basin includes one facility with a processing capacity of 16,000 barrels per day in whichwe own a 50% interest. In the table above, the processing capacity for facilities located on land we lease in the Eagle Ford Shale Play includes three facilitieswith a combined processing capacity of 83,000 barrels per day in which we own a 75% interest.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 by truck.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. Since our merger with High Sierra in June 2012, we have recycled approximately 12 million barrels(504 million gallons) of recycle quality water and have returned approximately 8 million barrels (336 million gallons) of discharge quality water back to NewFork 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.12 Table of ContentsOur 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 customer of our Wyoming facility has committed to deliver a specified minimum volume of water to our facility under a long-termcontract. The primary customers of our Colorado facilities have committed to deliver all wastewater produced at wells in a designated area to our facilities.One customer in Texas has committed to deliver at least 50,000 barrels of wastewater per day to our facilities. Most customers of our other facilities are notunder volume commitments, although certain of our facilities are connected to producer locations by pipeline. During the year ended March 31, 2016, 23%of the water treatment and disposal revenues of our water solutions segment were generated from our two largest customers of the segment, and 52% of thewater treatment and disposal revenues of the segment were generated from our ten largest customers of the segment.Competition. We compete with other processors of wastewater to the extent that other processors have facilities geographically close to our facilities.Location is an important consideration for our customers, who seek to minimize the cost of transporting the wastewater to disposal facilities. Our facilities arestrategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutions segment isthe extent of exploration and production in the areas near our facilities, which is generally based upon producers’ expectations about the profitability ofdrilling new wells.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, require credit approvals, establish credit limits,and follow monitoring procedures on our water solutions customers. We believe the following procedures enhance our collection efforts with our watersolutions customers:•we require certain customers to prepay or place deposits for our services;•we require certain customers to post letters of credit or other forms of surety 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 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.LiquidsOverview. 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, 2016, we sold 2.1 billion gallons of natural gas liquids, an average of 5.72 million gallons per day.13 Table of ContentsOperations. 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 19 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.14 Table of ContentsThe following table summarizes our natural gas liquids terminals and their throughput capacity:Facility Throughput Capacity(gallons per day)Rosemount, Minnesota 1,441,000Lebanon, Indiana 1,058,000West Memphis, Arkansas 1,058,000Dexter, Missouri 930,000East St. Louis, Illinois 883,000Jefferson City, Missouri 883,000St. Catharines, Ontario, Canada 700,000Janesville, Wisconsin 553,000Light, Arkansas 524,400Rixie, Arkansas 524,400West Springfield, Massachusetts 441,000Albuquerque, New Mexico 408,000Portland, Maine 360,000Vancouver, Washington 358,000Green Bay, Wisconsin 310,000Ritzville, Washington 198,000Thackerville, Oklahoma 180,000Shelton, Washington 161,000Superior, Montana (1) 120,000Total 11,090,800 (1)We own a terminal in Superior, Montana with throughput of 120,000 gallons per day that we are currently subleasing through October 2017 with anoption to extend or to purchase.We are currently building a rail terminal at the Port of Little Rock, Arkansas capable of receiving natural gas liquids by railcar, storing, and loadingout via truck. The throughput capacity for this terminal is expected to be 120,000 gallons per day. We expect this terminal to be operational by June 30,2016. Also, during the year ended March 31, 2016, we reached an agreement with the state of Maine’s Department of Transportation and, as of the end ofApril 2016, the Portland, Maine facility was shut down.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 twelve of the terminals are located and we either have easements or lease the land on whichseven of the terminals are located. The terminals in East St. Louis, Illinois and Jefferson City, Missouri have perpetual easements, and the terminal in St.Catharines, Ontario, Canada has a long-term lease that expires in 2022.We own an underground storage facility near Delta, Utah. This facility currently has capacity to store approximately 4.2 million barrels of naturalgas liquids. We have begun construction of a new cavern to expand the storage capacity, and we expect the new cavern to be operational in the secondquarter of fiscal year ending March 31, 2017. We lease storage to 15 customers, with lease terms ranging from one to three years. The facility is located onproperty for which we have a long-term lease.We lease 4,838 railcars, of which 765 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.15 Table of ContentsWe 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, Mississippi, Missouri, and Texas.The following table summarizes our significant leased storage space at natural gas liquids storage facilities and interconnects to those facilities: Leased Storage Space(gallons) Storage Facility BeginningApril 1,2016 AtMarch 31,2016 Storage InterconnectsConway, Kansas 64,890,000 64,940,000 Connected to Enterprise Mid-America and NuStar Pipelines; RailFacilityBorger, Texas 42,000,000 42,000,000 Connected to ConocoPhillips Blue Line PipelineCorunna, Ontario, Canada 15,800,000 2,100,000 Rail FacilityBushton, Kansas 12,600,000 12,600,000 Connected to ONEOK North System PipelineHattiesburg, Mississippi 9,660,000 6,300,000 Connected to Enterprise Dixie Pipeline; Rail FacilityCarthage, Missouri 7,560,000 7,560,000 Connected to Mid-America PipelineRedwater, Alberta, Canada 4,370,000 9,072,000 Connected to Cochin Pipeline; Rail FacilityMont Belvieu, Texas 2,940,000 2,940,000 Connected to Enterprise Texas Eastern Products PipelineNapoleonville, LA 2,407,000 — Connected to Enlink Pipeline; Rail FacilityAdamana, Arizona 1,680,000 1,680,000 Rail FacilitySt. Clair, Michigan — 6,300,000 Rail FacilityMarysville, Michigan — 2,100,000 Connected to Cochin PipelineTotal 163,907,000 157,592,000 During the typical heating season from September 15 through March 15 each year, we have the right to utilize ConocoPhillips’ capacity as a shipperon the Blue Line pipeline to transport natural gas liquids from our leased storage space to our terminals in East St. Louis, Illinois and Jefferson City, Missouri.During the remainder of the year, we have access to available capacity on the Blue Line pipeline on the same basis as other shippers.Customers. Our liquids business serves approximately 900 customers in 48 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 pipelines, rail terminals,refineries, and major United States propane storage hubs. During the year ended March 31, 2016, 34% of the revenues of our liquids segment were generatedfrom 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;16 Table of Contents•logistics capabilities, including the availability of railcars, and proprietary terminals;•long-term customer relationships; and•the acquisition of businesses.Pricing Policy. In our liquids business, we offer our customers three categories of contracts for propane sourced from common carrier pipelines:•customer pre-buys, which typically require deposits based on market pricing conditions;•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 up to 1,000,000gallons, and deliveries can occur over time periods extending from days to as long as a year. We perform credit analysis, require credit approvals, establishcredit limits, and follow monitoring procedures on our liquids customers. We believe the following procedures enhance our collection efforts with our liquidscustomers:•we require certain customers to prepay or place deposits for their purchases;•we require certain customers to post letters of credit or other forms of surety on a portion of our receivables;•we require certain customers to take delivery of their contracted volume ratably to help control the account balance rather than allowing them totake delivery of propane at their discretion;•we review receivable aging analyses regularly to identify issues or trends that may develop; and•we require our 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 PropaneOverview. 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, 2016, we sold 182.9 million gallons of propane and distillates, an average of501,000 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 113customer service locations and 98 satellite distribution locations, with aggregate propane storage capacity of 11.9 million gallons and aggregate distillatestorage capacity of 3.4 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.17 Table of ContentsOur customer service locations in Illinois and Indiana also rent over 17,000 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 summarizes the number of our customer service locations and satellite distribution locations by state:State Number of CustomerService Locations Number of SatelliteDistribution LocationsIllinois 22 20Maine 15 10Georgia 14 5Massachusetts 10 8North Carolina 10 1Pennsylvania 8 3Kansas 8 28Indiana 4 5Connecticut 4 2South Carolina 3 —New Hampshire 3 4Oregon 2 1Washington 2 —Mississippi 1 3Maryland 1 1Rhode Island 1 1Tennessee 1 1Utah 1 1Wyoming 1 1Colorado 1 —Vermont 1 2New Jersey — 1Total 113 98 We own 86 of our 113 customer service locations and 66 of our 98 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, 2016, 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, 2016, we owned a fleet of 440 bulk delivery trucks, 40 semi-tractors, 30 propane transport trailers and 520 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 from 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 at18 Table of Contentsour customer service locations, and then returned to the retail customer, or refilled at the customer’s location. Customers can also bring the cylinders to ourcustomer service centers to be refilled.Approximately 70% 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, 2016, 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, 2016.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 and electricity. The primary factors onwhich 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 level of service to our customers. We also believe that our overall service capabilities andcustomer responsiveness differentiate us from many of our competitors.Supply. Our retail propane segment purchases the majority of its propane from our liquids segment.19 Table of ContentsPricing 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 RenewablesOverview. Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. During the yearended March 31, 2016, we sold 99.0 million barrels of refined products, an average of 271,000 barrels per day.Operations. The refined products we handle include gasoline, diesel fuel, and heating oil. We purchase refined petroleum and renewable productsprimarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedule them for delivery primarily on the Colonial, Plantation, andMagellan pipelines. On certain interstate pipelines, demand for shipment exceeds the available capacity, and pipeline capacity is allocated to shippers basedon their historical shipment volumes. We hold allocated capacity on the Colonial and Plantation pipelines.A significant percentage of our business is priced on a back-to-back basis which minimizes our commodity price exposure. We sell our products tocommercial 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 terminals owned by third parties. As discussed above, on February 1, 2016, we sold our general partner interestin TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method ofaccounting. As part of this transaction, we entered into lease agreements whereby we will remain the long-term exclusive tenant in the TLP Southeastterminal system. In addition, we retained TransMontaigne’s marketing business, which is a significant part of our refined products and renewables segment,and TransMontaigne Product Services, LLC, its customer contracts and its line space on the Colonial and Plantation pipelines.20 Table of ContentsThe following table summarizes our leased storage space at refined products storage facilities:Locations Active Storage Capacity(shell barrels)Southeast Facilities Albany, Georgia 203,000Americus, Georgia 93,000Athens, Georgia 193,000Bainbridge, Georgia 372,000Birmingham, Alabama 178,000Charlotte, North Carolina 121,000Collins, Mississippi 200,000Collins/Purvis, Mississippi 94,000Doraville, Georgia 438,000Fairfax, Virginia 508,000Greensboro, North Carolina 436,000Griffin, Georgia 107,000Linden, New Jersey 400,000Lookout Mountain, Georgia 221,000Macon, Georgia 174,000Meridian, Mississippi 139,000Montvale, Virginia 503,000Nashville, Tennessee 11,000Norfolk, Virginia 1,336,000Port Everglades North, Florida 62,000Richmond, Virginia 444,000Rome, Georgia 152,000Selma, North Carolina 218,000Spartanburg, South Carolina 166,000Total Southeast Facilities Storage Capacity 6,769,000 Mid-Continent Facilities Magellan North system 202,000NuStar East Products system 150,000Total Mid-Continent Facilities Storage Capacity 352,000Total Facilities Storage Capacity 7,121,000We 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 67,000 barrels of biodiesel storage in Deer Park, Texas and have a biodiesel terminaling agreement at a fuel terminal in Phoenix, Arizonawith a minimum monthly throughput requirement. We lease 47 railcars for the transportation of renewables.Customers. Our refined products and renewables segment serves customers in 39 states. During the year ended March 31, 2016, 34% of the revenuesof our refined products and renewables segment were generated from our ten largest customers of the segment. 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 a21 Table of Contentsmajority of our contract sales is based on published index prices, and varies based on changes in the applicable indices. In addition, 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. However, the demand for diesel typically peaks during the fall and winter months due to colder temperatures in theMidwest and Northeast.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.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 priced on a back-to-back basis which minimizes our commodity priceexposure. For discretionary inventory, and for those instances where physical transactions cannot be appropriately matched, we utilize financial derivativesto 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 2015, the federal government passed a law to reinstate thetax credit retroactively to January 1, 2015, with the credit expiring on December 31, 2016. Changes in future22 Table of Contentsmandates and incentives, or decisions by the federal government related to future reinstatement of the biodiesel tax credit, could result in changes in demandfor 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 or other forms of surety 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.EmployeesAt March 31, 2016, we had 3,200 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 RegulationRegulation of the Oil and Natural Gas IndustriesRegulation 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 crude oil are subject to FERCregulation including reporting or other requirements. The Joint Pipeline currently under construction by Grand Mesa and Saddlehorn will have several pointsof origin in Colorado and will terminate in Cushing, Oklahoma. The transportation services on this pipeline will be subject to FERC regulation once thepipeline commences service. In addition, the intrastate transportation and storage of crude oil and natural gas is subject to regulation by the state in whichsuch facilities are located, and such regulation can affect the availability and price of our supply, and have both a direct and indirect effect on our business.Anti-Market Manipulation Rules. We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, as amended 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 market23 Table of Contentsmanipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,000,000 per violation. These agencies havepromulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The Commodity Futures Trading 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 and price manipulation in the commodity andfutures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per day per violation or triple the monetarygain to the violator for violations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reportingrequirements 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 maritime transportation through our barge fleetbetween locations in the United States, we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of oursubsidiaries that engage in maritime transportation and for taking any remedial action necessary to ensure that no violation of the Jones Act ownershiprestrictions occurs. The Jones Act also requires that all United States-flagged vessels be manned by United States citizens. Foreign-flagged seamen generallyreceive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of UnitedStates-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governments subsidize their nations’ shipyards. This resultsin lower shipyard costs both for new vessels and repairs than those paid by United States-flagged vessel owners. The United States Coast Guard and AmericanBureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance costs forUnited States-flagged operators than for owners of vessels registered under foreign flags of convenience.Environmental RegulationGeneral. 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 pollution24 Table of Contentsresulting from our operations; (v) require remedial measures to mitigate pollution from former or ongoing operations; and (vi) may result in the assessment ofadministrative, civil and criminal penalties for failure to comply with such laws. These laws include, among others, the Resource Conservation and RecoveryAct (“RCRA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the federal Clean Air Act, the HomelandSecurity Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act, the Safe Drinking Water Act, and comparable statestatutes. For example, as a flammable substance, 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 classified as hazardous. Persons who are or were responsible for releases of hazardous substances under CERCLA may besubject to strict and joint and several liability for the costs of investigating and cleaning up the hazardous substances that have been released into theenvironment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other thirdparties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal 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 consolidated results of operations andfinancial position.We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilizedoperating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on orunder the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment ordisposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could berequired to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminatedproperty (including contaminated groundwater) or to implement remedial measures to prevent or mitigate future contamination. We are not currently aware ofany facts, events or conditions relating to such requirements that could materially impact our consolidated results of operations or financial position.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 crude 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 consolidated results of operations or financial position. In 1973, the EPA adoptedoil pollution prevention regulations under the Clean Water Act. These oil pollution prevention regulations, as amended several times since their originaladoption, require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering,storing, processing, refining, transferring, distributing, using, or consuming crude oil and oil products, and which due to their location, could reasonably beexpected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility isrequired to prepare a written, site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. To be in compliance,the facility’s SPCC plan must satisfy all of the applicable requirements for drainage, bulk storage tanks, tank car and truck loading and unloading, transferoperations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and trainpersonnel in its execution. We maintain and implement such plans for our facilities.25 Table of ContentsAir 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 contamination of regulated waters in the event of a hydrocarbon or other constituent tank spill, rupture or leak. In addition, theClean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain typesof facilities. We have discharge permits in place for a number of our facilities. These permits may require us to monitor and sample the storm water runoff fromsuch facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwaterconditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or otherrequirements of the Clean Water Act and analogous state laws and regulations.Underground Injection Control. Our underground injection operations are subject to the Safe Drinking Water Act, as well as analogous state lawsand regulations, which establish requirements for permitting, testing, monitoring, record keeping, and reporting of injection well activities, as well as aprohibition against the migration of fluid containing any contaminant into underground sources of drinking water. Any leakage from the subsurface portionsof the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our permits, issuance of fines andpenalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties forproperty damages and personal injuries.Hydraulic Fracturing. The underground injection of crude 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’ crude oil and natural gas production is developed from unconventional sources that requirehydraulic fracturing as part of the completion process and our water solutions business treats and disposes of wastewater generated from natural gasproduction, including production utilizing hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure intothe formation 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 RegulationThere 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 enacted26 Table of Contentsby the 111th Congress. The ACES Act would have established an economy-wide cap on emissions of greenhouse gases in the United States and would haverequired most sources of greenhouse gas emissions to obtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. A steadystream of legislation regarding climate change continues to be introduced into Congress, but none of the proposed bills have received bipartisan support.Recently, Rep. Chris Van Hollen (D-MD) introduced H.R. 1027, which would cap greenhouse gas emissions and require the purchase of carbon permits. Thebill was referred to the Ways and Means Committee and the Energy and Commerce Committee on February 24, 2015 but has not yet advanced out ofcommittee. The ultimate outcome of any possible future federal legislative initiatives is uncertain. In addition, several states have already adopted some legalmeasures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regionalgreenhouse 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 United States Supreme Court invalidated the Tailoring Rule in Utility Air Regulatory Group v. EPA on June 23, 2014. Under theSupreme Court’s decision, sources are no longer required to obtain Prevention of Significant Deterioration or Title V permits based solely on theirgreenhouse gas emissions; however, installation of the best available control technology for greenhouse gases may be required at sources that emit more thana de minimis amount of greenhouse gases and are otherwise required to obtain Prevention of Significant Deterioration permits. On January 14, 2015, the EPAannounced its intention to propose regulations that would require reductions in methane and volatile organic compound emissions from the oil and gasindustry. The schedule for when these regulations will be proposed or finalized is not presently known. The EPA’s greenhouse gas regulations could requireus to incur costs to reduce emissions of greenhouse gases associated with our operations and also could adversely affect demand for the products that wetransport, 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 conducting business and consequently affecting our profitability. To the extent laws are enacted or other governmental actionis taken 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 TransportationAll 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 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.27 Table of ContentsWith 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 the Secretary of Transportation to evaluate the effectiveness of expanding pipeline integrity management and leak detectionrequirements, (iv) improving the way the DOT and pipeline operators provide information to the public and emergency responders, and (v) reforming theprocess by which pipeline operators notify federal, state and local officials of pipeline accidents.Railcar RegulationWe 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 RegulationsThe 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 WebsiteOur 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.28 Table of ContentsItem 1A. Risk FactorsRisks Related to Our BusinessWe 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•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.29 Table of ContentsOur future financial performance and growth may be limited by our ability to successfully complete accretive acquisitions on economically acceptableterms.Our ability to complete 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.While our business strategy includes expanding our existing retail propane operations through internal growth, our ability to expand our retailpropane business will primarily be dependent on our ability to successfully complete accretive acquisitions. There can be no assurances that we will be ableto identify suitable acquisition candidates or successfully complete acquisitions in this line of business. The propane industry is a mature industry, and weanticipate only limited growth in total national demand for propane in the near future. Increased competition from alternative energy sources has limitedgrowth in the propane industry, and year-to-year industry volumes are primarily impacted by fluctuations in weather and economic conditions.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 consolidated financial position, results of operationsor future growth.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, consolidated financial position or results ofoperations. In addition to the risks set forth above, new businesses will subject us to additional business and operating risks, such as the acquisitions notbeing accretive to our unitholders as a result of decreased profitability, increased interest expense related to debt we incur to make30 Table of Contentssuch acquisitions or an inability to successfully integrate those operations into our overall business operation. The realization of any of these risks couldhave a material adverse effect on our consolidated financial position or results of operations.Our substantial indebtedness may limit our flexibility to obtain financing and to pursue other business opportunities.At March 31, 2016, the face amount of our long-term debt was $2.9 billion. Our level of debt could have important consequences to us, includingthe following:•our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impairedor such financing may not be available on favorable terms;•our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flowrequired to make principal and interest payments on our debt;•we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and•our flexibility in responding to changing business and economic conditions may be limited.Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected byprevailing economic and weather conditions, and financial, business, regulatory and other factors, some of which are beyond our control. If our operatingresults are not sufficient to service our future indebtedness, we would be forced to take actions such as reducing distributions, reducing or delaying ourbusiness activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may be unable to effect any ofthese actions on satisfactory terms or at all. The agreements governing our indebtedness permit us to incur additional debt under certain circumstances, andwe will likely need to incur additional debt in order to implement our growth strategy. We may experience adverse consequences from increased levels ofdebt.Restrictions in our Credit Agreement, Note Purchase Agreement and Indentures could adversely affect our business, financial position, 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 Note 8 to our consolidated financial statements included in this Annual Report.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,31 Table of Contentsmay be triggered, and our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our 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. Spending on crude oil and natural gasexploration and production may be adversely affected by industry and financial market conditions that are beyond our control including, withoutlimitation, (1) prices for crude oil, condensate, and natural gas liquids, (2) crude oil and natural gas producers having success in their operations,(3) continued commercially viable areas in which to explore and produce crude oil and natural gas, (4) the availability of liquids-rich natural gas neededto 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 crude oiland natural gas in the United States and Canada, and to extract natural gas liquids from natural gas as well as the availability of necessary pipelinetransportation and storage capacity. Customers’ expectations of lower market prices for crude oil and natural gas, as well as the availability of capital foroperating and capital expenditures, may cause them to curtail spending, thereby reducing business opportunities and demand for our services and equipment.Actual market conditions and producers’ expectations of market conditions for crude oil, condensate and natural gas liquids may also cause producers tocurtail 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 crude oil and natural gas, the availability of liquids-rich natural gas needed to produce natural gas liquids, the supplyof and demand for crude oil and natural gas, environmental restrictions on the exploration and production of crude oil and natural gas, such as existing andproposed regulation of hydraulic fracturing, domestic and worldwide economic conditions, political instability in crude oil and natural gas producingcountries and merger and divestiture activity among our current or potential customers. The volatility of the oil and natural gas industry and the resultingimpact on exploration and production activity could adversely impact the level of drilling activity. This reduction may cause a decline in businessopportunities or the demand for our services, or adversely affect the price of our services. Reduced discovery rates of new crude oil and natural gas reserves inour market areas also may have a negative long-term impact on our business, even in an environment of stronger crude oil and natural gas prices, to the extentexisting production is not replaced.The crude oil and natural gas production industry tends to run in cycles and may, at any time, cycle into a downturn; if that occurs, 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 forcrude oil and natural gas have caused many customers to reduce capital budgets for future periods and have caused decreased demand for crude oil andnatural gas. Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause customersto make additional reductions to capital budgets in the future even if commodity prices increase from current levels. These cuts in spending may curtaildrilling programs and other discretionary spending, which could result in a reduction in business opportunities and demand for our services, the rates we cancharge and our utilization. In addition, certain of our customers could become unable to pay their suppliers, including us. Any of these conditions or eventscould materially and adversely affect our consolidated results of operations.32 Table of ContentsDeclining crude oil prices could adversely impact our water solutions and crude oil logistics businesses.Crude oil spot and forward prices experienced a sharp decline during the second half of calendar year 2014. During calendar year 2015, crude oilprices remained low and trended down during the second half of the year and into the first quarter of calendar year 2016. This had an unfavorable impact onthe 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 portion of the revenues of our water solutions business is generated from thesale of hydrocarbons that we recover when processing wastewater, and lower crude oil prices have an adverse impact on these revenues. A further decline incrude 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 the time of delivery or the current prices established at major storage points, creating the potential for sudden and drastic pricefluctuations. Sudden and extended wholesale price increases could reduce our margins and could, if continued over an extended period of time, reducedemand by encouraging retail customers to conserve or convert to alternative energy sources. Conversely, a prolonged decline in product prices couldpotentially result in a reduction of the borrowing base under our working capital facility, and we could be required to liquidate inventory that we havealready 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.33 Table of ContentsWe 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 consolidated 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 railcars aretransported. Any disruptions in the operations of these railroads could adversely impact our ability to deliver product to our customers.If we are unable to purchase product from our principal suppliers, our results of operations would be adversely affected.If we are unable to purchase product from significant suppliers, our failure to obtain alternate sources of supply at competitive prices and on a timelybasis would adversely affect our ability to satisfy customer demand, reduce our revenues and adversely affect our consolidated 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 “–Some of our operations could be subject to the jurisdiction of the FERC in the future,” below), we will be obligated to comply with theFERC’s regulations and policies. Any failure on our part to comply with the FERC’s regulations and policies at that time could result in the imposition ofcivil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material and adverse effect on our business,consolidated results of operations and financial position.34 Table of ContentsThe 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. These state regulations can have a material and adverse effect on that portion of our business,consolidated results of operations and financial position.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 corrected, the intervention escalates to on-site compliance audits and ultimately an “unsatisfactory” rating and the revocationof the company’s operating authority by the FMCSA, which could result in a material adverse effect on our business, consolidated results of operations andfinancial position and ability to make cash distributions 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 crude oil and natural gasproduced wastewater, 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 water solutions 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. Recent railcar accidents within the industry in Quebec, Alabama, North Dakota, Pennsylvaniaand Virginia, in each case involving trains carrying crude oil from the Bakken region (none of which directly involved any of our business operations), haveled to increased legislative and regulatory scrutiny over the safety of transporting crude oil by railcar. In 2015, the DOT, through the PHMSA, issued a ruleimplementing new railcar standards35 Table of Contentsand railroad operating procedures. The introduction of these or other regulations that result in new requirements addressing the type, design, specifications orconstruction of railcars used to transport crude oil could result in severe transportation capacity constraints during the period in which new railcars areretrofitted or constructed to meet new specifications. Our barge transportation operations are subject to the Jones Act, a federal law restricting marinetransportation in the United States to vessels built and registered in the United States, and manned and owned by United States citizens, as well as rules andregulations of the United States Coast Guard. Non-compliance with any of these regulations could result in increased costs related to the transportation of ourproducts 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 adversely impact us, and could result in increased operating costs and have a material and adverse effect on our activities and profitability. For example,new or proposed laws or regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wellsmay increase our costs for treatment of hydraulic fracturing 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 consolidated results of operationsand financial position.Furthermore, our customers in the oil and gas production industry are subject to certain environmental laws and regulations that may imposesignificant costs and liabilities on them, including as a result of changes in such laws and regulations causing them to become more stringent over time. Forexample, in April 2012, the EPA issued final rules that established new air emission controls for crude oil and natural gas production and gas processingoperations. The final rule includes a 95% reduction in volatile organic compounds (“VOCs”) (which contribute to smog) emitted during the completion ofnew and modified hydraulically fractured wells. In August 2013, the EPA updated its 2012 air emission standards for crude oil and natural gas storage tanksto extend the compliance date and allow an alternate emissions limit of less than four tons per year without emission controls. On September 18, 2015, theEPA proposed new source performance standards for the oil and gas sector, which would require reductions in methane and VOC emissions across the oil andgas industry if finalized. The schedule for when these regulations will be proposed or finalized is not presently known, although the EPA has indicated itsintention to finalize the regulations by the end of calendar year 2016. Any significant increased costs or restrictions placed on our customers to comply withenvironmental laws and regulations could affect their production output significantly. Such an effect could materially and adversely affect our utilizationand profitability, thus reducing demand for our midstream services. Such an effect on our customers could materially and adversely affect our utilization andprofitability. The adoption or implementation of any new regulations imposing additional reporting obligations on greenhouse gas emissions, or limitinggreenhouse 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 crude oil and natural gas fields in which our water solutions segment operates. Hydraulic fracturingis an important 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 hydraulic fracturing process couldadversely affect drinking water supplies. New laws or regulations, or changes to existing laws or regulations in response to this perceived threat mayadversely impact the oil and gas drilling industry. For instance, the EPA has asserted federal regulatory36 Table of Contentsauthority over certain hydraulic fracturing practices involving the use of diesel fuel under the Safe Drinking Water Act and its Underground Injection Controlprogram. In February 2014, the EPA issued technical guidance for the permitting of the underground injection of diesel fuel for hydraulic fracturingactivities. At the request of the United States Congress, the EPA is undertaking a study of the impact of hydraulic fracturing on drinking water resources. InJune 2015, the EPA released its draft assessment, which found that although hydraulic fracturing activities have the potential to impact drinking waterresources, there is no evidence that hydraulic fracturing has led to widespread, systemic impacts on drinking water resources in the United States. In addition,the United States Department of the Interior issued a final rule on March 20, 2015 updating existing regulation of hydraulic fracturing activities on federaland tribal lands, including requirements for disclosure of chemicals used in hydraulic fracturing to the Bureau of Land Management, well bore integrity andhandling of flowback water. Also, legislation has been introduced, but not adopted, in Congress to provide for federal regulation of hydraulic fracturing. Inaddition, some states have adopted and other states are considering adopting regulations that could restrict or regulate hydraulic fracturing in certaincircumstances. For example, some states have adopted legislation requiring the disclosure of hydraulic fracturing chemicals, which could make it easier forthird parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the hydraulicfracturing process could adversely affect groundwater. Other states, such as New York, have banned hydraulic fracturing. We cannot predict whether anyproposed federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require or prohibit. However,any restrictions on hydraulic fracturing could lead to operational delays or increased operating costs and regulatory burdens that could make it more difficultor costly to perform hydraulic fracturing which would negatively impact our customer base resulting in an adverse effect on our profitability.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 adversely 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.Seasonal weather conditions and natural or man-made disasters could severely disrupt normal operations and have an adverse effect on our business,financial position 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, consolidated financial position, 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 financialposition 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 theother37 Table of Contentshand. These policies and practices cannot, however, eliminate all risks. For example, any event that disrupts our anticipated physical supply of commoditiescould expose us to risk of loss resulting from the need to cover obligations required under contracts for forward sale. Additionally, we can provide noassurance that our processes and procedures will detect and/or prevent all violations of our risk management policies and procedures, particularly ifdeception 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 consolidated financial position 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 crude oil and natural gascommodities sector overall for an extended or near term period of time could result in counterparty defaults on our derivative and physical purchase and salecontracts. This could impair our ability to obtain supply to fulfill our sales delivery commitments or obtain supply at reasonable prices, which could result indecreased gross margins and profitability, thereby impairing our ability to make payments on our debt obligations or distributions to our unitholders.Our use of derivative financial instruments could have an adverse effect on our results of operations.We have used derivative financial instruments as a means to protect against commodity price risk or interest rate risk and expect to continue to 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 consolidated results of operations and impair our ability to make payments on our debt obligations ordistributions to our unitholders.Some of our operations could be subject to the jurisdiction of the FERC in the future.The Joint Pipeline currently under construction by Grand Mesa and Saddlehorn will have several points of origin in Colorado and will terminate inCushing, Oklahoma. The transportation services on this pipeline will be subject to FERC regulation once the pipeline commences service. Any of ourtransportation services could in the future become subject to the jurisdiction of the FERC, which could adversely affect the terms of service, rates andrevenues of such services. At the date of this Annual Report, our facilities do not fall under the FERC’s jurisdiction. Currently, the FERC regulates thetransportation of crude oil and refined products on interstate pipelines, among other things. Intrastate transportation and gathering pipelines that do notprovide interstate services are not subject to regulation by the FERC. However, the distinction between the FERC-regulated interstate pipeline transportationon the one hand and intrastate pipeline transportation on the other hand, is a fact-based determination.The classification and regulation of our crude oil pipelines are subject to change based on future determinations by the FERC, federal courts,Congress or regulatory commissions, courts or legislatures in the states in which we operate. Glass Mountain, one of our joint ventures, owns a pipeline inOklahoma that carries crude oil owned by us and by third parties. We believe that the pipeline segments on which Glass Mountain would provide service tothird parties and the services it would provide to third parties on this pipeline system meet the traditional tests that the FERC has used to determine that thepipeline services provided are not in interstate commerce. However, we cannot provide assurance that the FERC will not in the future, either at the request ofother entities or on its own initiative, determine that some or all of the pipeline and the services Glass Mountain will provide on that system are within itsjurisdiction, or that such a determination would not adversely affect Glass Mountain’s or our consolidated results of operations. If the FERC’s regulatoryreach was expanded to our other facilities, or if we expand our operations into areas that are subject to the FERC’s regulation, we may have to commitsubstantial capital to comply with such regulations and such expenditures could have a material and adverse effect on our consolidated results of operationsand cash flows.38 Table of ContentsVolumes 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 portion of revenues in our water solutions business is generated from the sale of hydrocarbons that we recover when processing wastewater. Ourability to recover sufficient volumes of hydrocarbons is dependent upon the residual crude oil content in the wastewater we treat, which is, among otherthings, a function of water temperature. Generally, where water temperature is higher, residual crude oil content is lower. Thus, our crude oil recovery duringthe winter season is substantially higher than our recovery during the summer season. Additionally, residual crude oil content will decrease if, among otherthings, producers begin recovering higher levels of crude oil in produced wastewater prior to delivering such water to us for treatment. Any reduction inresidual crude oil content in the wastewater we treat could materially and adversely affect our profitability.Competition from alternative energy sources may cause us to lose customers, thereby negatively impacting our financial position and results of operations.Propane competes with other sources of energy, some of which are less costly for equivalent energy value. We compete for customers 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.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 position 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 consolidated results of operations and financial position. Inaddition, adverse economic conditions in areas where our retail propane operations are concentrated may cause our residential customers to reduce their useof propane regardless of weather conditions. Localized warmer weather and/or economic downturns may have a significantly greater impact on ourconsolidated results of operations and financial position than if our retail propane business were less concentrated.39 Table of ContentsReduced 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 adversely 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 consolidatedresults of operations. The most significant of the federal and state incentives which benefit renewable products we market, such as ethanol and biodiesel, isthe RFS. The RFS requires that an increasing amount of renewable fuels must be blended with petroleum-based fuels each year in the United States. However,the EPA has authority to waive the requirements of the RFS, in whole or in part, provided one of two conditions is met. The conditions are: (1) there isinadequate domestic renewable fuel supply; or (2) implementation of the requirement would severely harm the economy or environment of a state, region orthe United States. Opponents of the RFS are seeking to force the EPA to reduce or eliminate the RFS. Further, several pieces of legislation have beenintroduced with the goal of significantly reducing or eliminating the RFS. While the outcome of these legislative efforts is uncertain, it is possible that theEPA could adjust the RFS requirements in the future. If the EPA were to adjust the RFS requirements in any material way, it could negatively impact demandfor the renewable fuel products we market, which could adversely impact our consolidated results of operations.The expiration of tax credits could adversely impact the demand for biodiesel, which could adversely impact our results of operationsThe 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. In December 2015, the federal government re-signed the law reinstating the tax credit retroactively to January 1,2015 to be effective through December 31, 2016. Currently no such tax credit exists for transactions subsequent to December 31, 2016, and there can be noassurance that the federal government will grant such tax credits in the future. If the federal government were to discontinue the practice of granting such taxcredits, 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.During the year ended March 31, 2016, 65% of the revenues of our crude oil logistics segment were generated from our ten largest customers of thesegment. During the year ended March 31, 2016, 23% of the water treatment and disposal revenues of our water solutions segment were generated from ourtwo largest customers of the segment. During the year ended March 31, 2016, 34% of the revenues of our liquids segment were generated from our ten largestcustomers of the segment (exclusive of sales to our retail propane segment). During the year ended March 31, 2016, 34% of the revenues of our refinedproducts and renewables segment were generated from our ten largest customers of the segment. We expect to continue to depend on key customers tosupport our revenues for the foreseeable future. The loss of key customers, failure to renew contracts upon expiration, or a sustained decrease in demand bykey customers could result in a substantial loss of revenues and could have a material and adverse effect on our consolidated results of operations.40 Table of ContentsCertain 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 consolidated results of operations, financial position 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. The Joint Pipeline currently under construction by Grand Mesa and Saddlehorn will have several points oforigin in Colorado and will terminate in Cushing, Oklahoma; and we expect that the transportation services on this pipeline to commence beginning in thethird quarter of fiscal year 2017. 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. Our revenues may not increase upon the expenditure of funds on a particular project. Moreover, we may undertakeexpansion projects to capture anticipated future growth in production in a region in which anticipated production growth does not materialize or for whichwe are unable to acquire new customers. We may also rely on estimates of proved, probable or possible reserves in our decision to undertake expansionprojects, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved, probable or possiblereserves. As a result, our new facilities and infrastructure may not be able to attract enough product to achieve our expected investment return, which couldmaterially and adversely affect our consolidated results of operations and financial position.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, consolidated results of operations, financial position 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 risks. Any future cyber security attacks that affectour facilities, our customers and any financial data could have a material adverse effect on our business. In addition, cyber attacks on our customer andemployee data may result in a financial41 Table of Contentsloss, including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which we rely could also sufferoperational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have anadverse effect on our financial results.We do not own all of the land on which our facilities are located, and instead lease certain facilities and equipment, and we, therefore, are 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, consolidated results of operations and financial position.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 consolidated 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. Regulatory requirements, including the FMCSA’s CSA initiative,and an improvement in the economy could reduce the number of eligible drivers or require us to pay more to attract and retain drivers. A shortage of qualifieddrivers and intense competition for drivers from other companies would create difficulties in increasing the number of our drivers in the event we choose toexpand our fleet of trucks. If we are unable to continue to attract and retain a sufficient number of qualified drivers, we could have difficulty meetingcustomer demands, any of which could materially and adversely affect our growth and profitability.If we fail to maintain an effective system of internal controls, including internal control 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 control. Any failure to maintain effective internal control over financial reporting and disclosure controls could harm our operatingresults or cause us to fail to meet our reporting obligations. These risks may be heightened after a business combination, during the phase when we areimplementing our internal control structure over the recently acquired business.Given the difficulties inherent in the design and operation of internal control over financial reporting, we can provide no assurance as to either ouror our independent registered public accounting firm’s conclusions about the effectiveness of internal controls in the future, and we may incur significantcosts in our efforts to comply with Section 404. Ineffective internal controls could subject us to regulatory scrutiny and a loss of confidence in our reportedfinancial information, which could have an adverse effect on our business and would likely have a negative effect on the market price of our common units.In the fourth quarter of fiscal year 2016, we identified a material weakness in our internal control over financial reporting that existed through December31, 2015. Our failure to establish and maintain effective internal control over financial reporting could result in material misstatements in our financialstatements and cause investors to lose confidence in our reported financial information, which in turn could cause the trading price of our common units todecline.42 Table of ContentsDuring the year ended March 31, 2016, we identified a material weakness in our internal control over financial reporting that existed throughDecember 31, 2015, related to the appropriate policies and procedures in place to properly identify and account for liabilities related to contingentconsideration payments in business combinations. We identified this material weakness in connection with the recording of business combinations in thefourth quarter of fiscal year 2016. As a result of such weakness, our Audit Committee, upon recommendation of management, determined to restate ourunaudited quarterly financial information for the quarters ended June 30, 2015, September 30, 2015 and December 31, 2015. For further informationregarding this matter, please refer to Item 9A. Controls and Procedures.Management’s ongoing assessment of internal control over financial reporting may in the future identify additional weaknesses and conditions thatneed to be addressed. Any failure to improve our internal control over financial reporting to address identified weaknesses in the future, if they were to occur,could prevent us from maintaining accurate accounting records and discovering material accounting errors, which in turn, could adversely affect our businessand the value of our common units.An impairment of goodwill and intangible assets could reduce our earnings.At March 31, 2016, we had goodwill and intangible assets of $2.5 billion. Such assets are subject to impairment reviews on an annual basis, or at aninterim date if information indicates that such asset values have been impaired. Any impairment we would be required to record in our financial statementswould 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 consolidated results of operations and potentially limit our ability to make payments on ourdebt obligations 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 lease refined products terminals. These facilities depend on pipeline and storage systems thatare owned and operated by third parties. Any interruption of service on a pipeline or lateral connections or adverse change in the terms and conditions ofservice could have a material adverse effect on our ability, and the ability of our customers, to transport product to and from our facilities and have acorresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from ourfacilities impact the utilization and value of our terminals. We have historically been able to pass through the costs of pipeline transportation to ourcustomers. However, if competing pipelines do not have similar annual tariff increases or service fee adjustments, such increases could affect our ability tocompete, 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.43 Table of ContentsA 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.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 consolidated resultsof operations.We depend on the leadership and involvement of key personnel for the success of our businesses.We have certain key individuals in our senior management who we believe are critical to the success of our business. The loss of leadership andinvolvement of those key management personnel could potentially have a material adverse impact on our business and possibly on the market value of ourunits.Risks Inherent in an Investment in UsOur 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 so longas it acted in good faith, meaning our general partner subjectively believed that the decision was in, or not opposed to, the best interests of thepartnership;•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 the44 Table of Contentstotality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us;and•provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any 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 general partner, conflicts of interest may arise between the NGL Energy GP Investor Group and itsaffiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner mayfavor its own interests and the interests of its affiliates over the interests of our unitholders (see “–Our partnership agreement limits the fiduciary duties of ourgeneral partner to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise bebreaches of fiduciary duty,” above). The risk to our unitholders due to such conflicts may arise because of the following factors, among others:•our general partner is allowed to take into account the interests of parties other than us, such as members of the NGL Energy GP Investor Group,in resolving conflicts of interest;•neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us;•except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;•our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities 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;45 Table of Contents•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.Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our generalpartner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction,agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any suchperson or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entitypursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or informationto us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of usand our unitholders.Even if our unitholders are dissatisfied, they have limited voting rights and are not entitled to elect our general partner or its directors.Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore,limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our generalpartner or its board of directors. The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Unlike publiclytraded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at 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.46 Table of ContentsThe 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;47 Table 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.48 Table of ContentsTax Risks to Common UnitholdersOur 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”) were to treat us as a corporation for federal incometax purposes, our cash available for distribution to our unitholders would be substantially reduced.The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income taxpurposes. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income taxpurposes.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 market 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 United States federal income tax purposes.49 Table of ContentsWe 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.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 market 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 our50 Table of Contentsunitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on themarket 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 were to successfully assert that our corporate subsidiaries havemore tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholderswould 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.51 Table of ContentsThe 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 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 ourtaxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Atechnical termination 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 CommentsNone.Item 2. PropertiesOverview. 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.52 Table of ContentsOther than as described below, we believe that we have all required material approvals, authorizations, orders, licenses, permits, franchises andconsents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local governmental andregulatory authorities that relate to ownership of our properties or the operations of our business.One of our facilities acquired in the High Sierra merger is operating with all but one of the required permits, as the State of Wyoming has not yetdeveloped a process for issuing permits of this type. We believe that the permit will ultimately be granted, but we are unable to determine the timing of anyaction by the State of Wyoming.Our corporate headquarters are in Tulsa, Oklahoma and are leased. We also lease corporate offices in Denver, Colorado and Houston, Texas.For additional information regarding our properties and the reportable segments in which they are used, see Part I, Item 1–“Business.”Item 3. Legal ProceedingsWe 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,” “Contractual Disputes,” and “Environmental Matters” 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 DisclosuresNot applicable.53 Table of ContentsPART IIItem 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity SecuritiesMarket InformationOur 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 23, 2016, there wereapproximately 245 common unitholders of record which does not include unitholders for whom common units may be held in “street name.”The following table summarizes the high and low sales prices per common unit for the periods indicated 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 Distribution2016 Fiscal Year Fourth Quarter $15.16 $5.57 $0.6400Third Quarter 23.33 8.04 0.6400Second Quarter 31.31 19.55 0.6325First Quarter 33.64 26.11 0.62502015 Fiscal Year Fourth Quarter $31.70 $24.88 $0.6175Third Quarter 40.58 22.57 0.6088Second Quarter 44.86 39.13 0.5888First Quarter 46.25 37.08 0.5513Cash Distribution PolicyAvailable CashOur 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.General Partner InterestOur 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 a reset of the IDRs) andour general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest.Incentive Distribution RightsThe general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level ofdistributions 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 partnership agreement.54 Table of ContentsThe 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 InDistributions Total QuarterlyDistribution Per Unit Unitholders General PartnerMinimum quarterly distribution $0.337500 99.9% 0.1%First target distribution above $0.337500 up to $0.388125 99.9% 0.1%Second target distribution above $0.388125 up to $0.421875 86.9% 13.1%Third target distribution above $0.421875 up to $0.506250 76.9% 23.1%Thereafter above $0.506250 51.9% 48.1%The maximum distribution of 48.1% does not include any distributions that our general partner may receive on common units that it owns.Restrictions on the Payment of DistributionsAs 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 SecuritiesDuring the year ended March 31, 2016, we completed two 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 October 2015, we issued 52,199 common units to the sellers of a retail propane business. During the year ended March 31, 2016, we issued 781,255common units to the sellers of two water treatment and disposal facilities.Common Unit Repurchase ProgramOn September 10, 2015, the Board of Directors of our general partner authorized a common unit repurchase program pursuant to which we couldrepurchase up to $45 million of our outstanding common units through March 31, 2016 from time to time in the open market or in other privately negotiatedtransactions. The following table summarizes the repurchase of common units during the three months ended March 31, 2016.Period Total Number ofCommon UnitsPurchased Average Price Paid PerCommon Unit Total Number ofCommon UnitsPurchased as Part of aPublicly AnnouncedProgram Approximate DollarValue of Common Unitsthat May Yet BePurchased Under theProgramJanuary 1-31, 2016 8,403 $11.02 — $37,272,180February 1-29, 2016 782,703 7.92 782,703 31,073,172March 1-31, 2016 442,960 8.67 442,960 27,232,709Total 1,234,066 $8.19 1,225,663 $—55 Table of ContentsThe common units not repurchased under the publicly announced program were surrendered by employees to pay tax withholding in connectionwith the vesting of restricted common units. As a result, we are including the common units surrendered in the “Total Number of Common Units Purchased”column.Securities Authorized for Issuance Under Equity Compensation PlansIn 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 DataThe following table summarizes selected historical financial and operating data for the periods and as of the dates indicated. The following tableshould be read in conjunction with Part I, Item 7–“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and thefinancial statements and related notes included in this Annual Report.The selected consolidated historical financial data (excluding volume information) at March 31, 2016 and 2015, and for each of the three years inthe period ended March 31, 2016 is derived from our audited historical consolidated financial statements included in this Annual Report. The selectedconsolidated historical financial data (excluding volume information) at March 31, 2014, 2013 and 2012 and for each of the two years in the period endedMarch 31, 2013 is derived from our audited historical consolidated financial statements not included in this Annual Report.Correction of ErrorWe have changed our previously issued consolidated balance sheet as of March 31, 2015 and consolidated statement of operations, consolidatedstatement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year ended March 31,2015 for the correction of an immaterial error (see Note 17 to our consolidated financial statements included in this Annual Report).56 Table of Contents Year Ended March 31, 2016 2015 2014 2013 2012 (in thousands, except per unit data)Income Statement Data (1)(2) Total revenues $11,742,110 $16,802,057 $9,699,274 $4,417,767 $1,310,473Total cost of sales 10,839,037 15,958,207 9,132,699 4,039,110 1,217,023Operating (loss) income (104,603) 107,420 106,565 87,307 15,030Interest expense 133,089 110,123 58,854 32,994 7,620(Gain) loss on early extinguishment of debt (28,532) — — 5,769 —Net (loss) income attributable to parent equity (198,929) 37,306 47,655 47,940 7,876Basic and diluted (loss) income per common unit (2.35) (0.05) 0.51 0.96 0.32Cash Flows Data (1)(2) Net cash provided by operating activities $351,495 $262,391 $85,236 $132,634 $90,329Net cash used in investing activities (445,327) (1,366,221) (1,455,373) (546,621) (296,897)Net cash provided by financing activities 80,705 1,134,693 1,369,016 417,716 198,063Cash distributions paid per common unit (subsequent to IPO) 2.54 2.37 2.01 1.69 0.85Cash distributions paid per common unit (prior to IPO) 0.35Balance Sheet Data - Period End (1)(2)(3) Total assets (4) $5,560,155 $6,655,792 $4,134,910 $2,290,901 $749,519Total long-term obligations, exclusive of debt issuance costsand current maturities (4) 3,160,073 2,842,493 1,628,173 741,924 199,389Total equity 1,694,065 2,693,432 1,531,853 889,418 405,329Volume Information (1) Retail propane sold (gallons) 152,238 169,279 162,361 144,379 78,236Distillates sold (gallons) 30,674 34,862 34,965 28,853 1,650Wholesale propane sold (gallons) (5) 1,244,529 1,285,707 1,190,106 912,625 659,921Wholesale other products sold (gallons) 843,922 825,514 786,671 505,529 134,999Crude oil sold (barrels) 67,211 83,864 46,107 24,373 —Water received (barrels) 208,440 161,664 75,451 25,009 —Refined products sold (barrels) 98,988 68,043 9,833 — —Renewable products sold (barrels) 5,794 5,318 3,593 — — (1)The acquisitions of businesses affect the comparability of this information.(2)On February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account forour limited partner investment in TLP using the equity method of accounting.(3)Certain balance sheet data at March 31, 2015 was adjusted to reflect the final acquisition accounting for certain business combinations (see Note 2to our consolidated financial statements included in this Annual Report).(4)Revised to reclassify debt issuance costs for our senior notes from intangible assets to long-term debt obligations for all balance sheet datespresented (see Note 2 to our consolidated financial statements included in this Annual Report).(5)Includes intercompany volumes sold to our retail propane segment.57 Table of ContentsItem 7. Management’s Discussion and Analysis of Financial Condition and Results of OperationsOverviewWe 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 numerousacquisitions, as described under Part I, Item 1–“Business–Acquisitions.” At March 31, 2016, our operations include:•Crude Oil Logistics•Water Solutions•Liquids•Retail Propane•Refined Products and RenewablesCorrection of ErrorWe have changed our previously issued consolidated balance sheet as of March 31, 2015 and consolidated statement of operations, consolidatedstatement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year ended March 31,2015 for the correction of an immaterial error (see Note 17 to our consolidated financial statements included in this Annual Report).Crude Oil LogisticsOur crude oil logistics segment purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injectionstations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. The assets of our crude oil logistics segment include ownedand leased crude oil storage terminals and pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of ownedbarges and towboats, and interests in two crude oil pipelines.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 attempt to reduce our exposure to price fluctuations by using back-to-back physical contracts whenever possible. When back-to-backphysical contracts are not optimal, we enter into financially settled derivative contracts as economic hedges of our physical inventory, physical sales andphysical purchase contracts. We use our transportation assets to move crude oil from the wellhead to the highest value market. Spreads between crude oilprices in different markets can fluctuate, which may expand or limit our opportunity to generate margins by transporting crude oil to different markets.The following table summarizes the range of low and high spot crude oil prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing,Oklahoma for the periods indicated and the prices at period end: Spot Price Per BarrelYear Ended March 31, Low High At Period End2016 $26.21 $61.43 $38.342015 43.46 107.26 47.602014 86.68 110.53 101.58We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.Our crude oil logistics segment generated an operating loss of $40.7 million during the year ended March 31, 2016, compared to an operating loss of$35.8 million during the year ended March 31, 2015. The operating loss during the year ended March 31, 2016 included a write-down of $47.7 millionrelated to pipe we no longer expect to use in the originally-planned Grand Mesa Pipeline.58 Table of ContentsWater SolutionsOur water solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production andfor the disposal of solids such as tank bottoms and drilling fluids and performs truck washouts. In addition, our water solutions segment sells the recycledwater and recovered hydrocarbons that result from performing these services. The assets of our water solutions segment include water pipelines, watertreatment and disposal facilities, washout facilities, and solid waste disposal facilities.Our water processing facilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting theprofitability of our water solutions segment is the extent of exploration and production in the areas near our facilities, which is generally based uponproducers’ expectations about the profitability of drilling new wells. The primary customer of our Wyoming facility has committed to deliver a specifiedminimum volume of water to our facility under a long-term contract. The primary customers of our Colorado facilities have committed to deliver allwastewater produced at wells in a designated area to our facilities. One customer in Texas has committed to deliver at least 50,000 barrels of wastewater perday to our facilities. Most customers of our other facilities are not under volume commitments, although certain of our facilities are connected to producerlocations by pipeline.Our water solutions segment generated an operating loss of $313.7 million during the year ended March 31, 2016, compared to operating income of$65.3 million during the year ended March 31, 2015. The operating loss during the year ended March 31, 2016 included a goodwill impairment of $380.2million as the decline in crude oil prices and crude oil production have had an unfavorable impact on our water solutions business.LiquidsOur liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells theproducts to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada. Our liquids segment owns 19 terminalsthroughout the United States and a salt dome storage facility in Utah, operates a fleet of leased railcars, and leases underground storage capacity. We attemptto reduce our exposure to price fluctuations by using back-to-back physical contracts and pre-sale agreements that allow us to lock in a margin on apercentage of our winter volumes. We also enter into financially settled derivative contracts as economic hedges of our physical inventory, physical sales andphysical purchase contracts.Our wholesale liquids business is a “cost-plus” business that can be affected by both price fluctuations and volume variations. We establish ourselling price based on a pass-through of our product supply, transportation, handling, storage, and capital costs plus an acceptable margin. The margin werealize in our wholesale liquids business is substantially less on a per gallon basis than the margin we realize 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 following table summarizes the range of low and high spot propane prices per gallon at Conway, Kansas, and Mt. Belvieu, Texas, two of ourmain pricing hubs, for the periods indicated and the prices at period end: Conway, Kansas Mt. Belvieu, Texas Spot Price Per Gallon Spot Price Per GallonYear Ended March 31, Low High At Period End Low High At Period End2016 $0.27 $0.51 $0.39 $0.30 $0.57 $0.442015 0.38 1.13 0.45 0.45 1.13 0.512014 0.77 4.33 1.03 0.81 1.73 1.0659 Table of ContentsThe range of low and high spot butane prices per gallon at Mt. Belvieu, Texas for the periods indicated and the prices at period end: Spot Price Per GallonYear Ended March 31, Low High At Period End2016 $0.42 $0.68 $0.532015 0.60 1.30 0.632014 1.08 1.64 1.26We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.Our liquids segment generated operating income of $76.2 million and $45.1 million during the years ended March 31, 2016 and 2015, respectively.During the year ended March 31, 2016, we wrote off assets of $14.6 million acquired as part of the Gavilon Energy acquisition that we deemed no longerrecoverable. Operating income during the year ended March 31, 2015 was reduced by a loss of $29.8 million on the sale of a natural gas liquids terminal.Additionally, Sawtooth NGL Caverns, LLC (“Sawtooth”), which we acquired in February 2015, generated $9.8 million of operating income during the yearended March 31, 2016.Retail PropaneOur 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 and to certain resellers in 25 states and the District of Columbia. Our retail propane segment purchases themajority of its propane from our liquids segment. Our retail propane segment generates margins based on the difference between the wholesale cost of productand the selling price of the product in the retail markets. These margins fluctuate over time due to supply and demand conditions. Weather conditions canhave 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 forhome heating purposes.A significant factor affecting the profitability of our retail propane segment is our ability to maintain our product margin. Product margin is thedifference between our sales prices and our total product costs, including transportation and storage. We monitor wholesale propane prices daily and adjustour retail prices accordingly. We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact ourfinancial 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.Our retail propane segment generated operating income of $44.1 million and $64.1 million during the years ended March 31, 2016 and 2015,respectively.Refined Products and RenewablesOur refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We purchase refined petroleumand renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedule them for delivery at various locations.As discussed in “Recent Developments” below, on February 1, 2016, we sold our general partner interest in TLP.We purchase refined petroleum products primarily in the Gulf Coast, Southeast, 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.60 Table of ContentsThe following table summarizes the range of low and high spot gasoline prices per barrel using NYMEX gasoline prompt-month futures for the periodsindicated and the prices at period end: Spot Price Per BarrelYear Ended March 31, Low High At Period End2016 $37.75 $90.15 $59.912015 53.34 131.46 74.762014 (1) 109.20 126.84 122.22 (1)Prices are for the four months ended March 31, 2014 as we acquired Gavilon, LLC (“Gavilon Energy”) on December 2, 2013.The following table summarizes the range of low and high spot diesel prices per barrel using NYMEX ULSD prompt-month futures for the periodsindicated and the prices at period end: Spot Price Per BarrelYear Ended March 31, Low High At Period End2016 $36.36 $84.68 $49.762015 68.04 128.10 72.242014 (1) 121.80 137.76 123.06 (1)Prices are for the four months ended March 31, 2014 as we acquired Gavilon Energy on December 2, 2013.Our refined products and renewables segment generated operating income of $227.0 million and $54.6 million during the years ended March 31,2016 and 2015, respectively. Our refined products and renewables segment was significantly expanded with our July 2014 acquisition of TransMontaigne.Operating income during the year ended March 31, 2016 was also increased by a gain of $130.4 million recorded on the sale of our general partner interest inTLP during the three months ended March 31, 2016, as discussed in “Recent Developments” below and Note 14 to our consolidated financial statementsincluded in this Annual Report.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 period from July 2014through March 2016 (the spot price for NYMEX West Texas Intermediate crude oil at Cushing, Oklahoma declined from $105.34 per barrel at July 1, 2014 to$38.34 per barrel at March 31, 2016). 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.Since January 2015, crude oil markets have been in contango (a condition in which forward crude oil prices are greater than spot prices). Our crudeoil logistics business benefits when the market is in contango, as higher forward prices result in inventory holding gains between the time we financiallyhedge a barrel in inventory and physically sell the same barrel. In addition, we are able to better use our storage assets when crude oil markets are incontango.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 since July 2014. At current market prices, drilling rigs and productionhave decreased and adversely impacted the volumes of our water solutions business. A portion of the revenues of our water solutions business is generatedfrom the sale of hydrocarbons that we recover when processing the wastewater. Because of this, lower crude oil prices result in lower per-barrel revenues forour water solutions business.An important element of our refined products and renewables segment relates to the marketing of refined products in the Southeast and East Coastregions. We purchase product in the Gulf Coast, transport the product on third party pipelines, and sell the product primarily at TLP’s refined productsterminals. Most of the contracts with these customers are one year in61 Table of Contentsduration, with pricing indexed to prices in the Gulf Coast at the date of sale plus a specified differential. To operate this business we maintain inventory intransit on the third party pipelines and at the destination terminals where we sell the product. The value of this inventory will increase or decrease as marketprices change. In order to mitigate this risk, we enter into futures contracts, which are only available based on New York Harbor pricing. Because ourcontracts are indexed to Gulf Coast prices and our futures contracts are based on New York Harbor prices, the futures contracts are not a perfect hedge againstour inventory holding risk. During any given quarter, spreads between prices in the Gulf Coast and New York Harbor could narrow or widen, which couldreduce the effectiveness of the futures contracts as a hedge of the inventory holding risk. The tenor of these futures contracts, which are typically six monthsto one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.During the year ended March 31, 2016, prices for refined products declined. Gulf Coast prices, on which our sales contracts are based, declined morethan the New York Harbor prices, on which our futures contracts are based, which had an adverse impact on our cost of sales. Based on historical experience,we generally expect the spreads between Gulf Coast and New York Harbor prices to be more consistent over the course of a contract year than during anyindividual quarter within the year, and that we should expect more volatility in cost of sales among quarters within a fiscal year than we would expect duringa full fiscal year.The decline in crude oil prices has had an adverse impact on many participants in the energy markets, and the inherent risk of customer orcounterparty nonperformance is higher when crude oil prices are low or in decline.SeasonalitySeasonality 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.”Recent DevelopmentsGrand Mesa PipelineIn 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”). In October 2014, we obtained ship-or-pay volume commitments from multiple shippers to begin construction of theGrand Mesa Pipeline, which will originate in Colorado and terminate in Cushing, Oklahoma. In November 2014, we acquired RimRock’s 50% ownershipinterest in Grand Mesa for $310.0 million in cash. In November 2015, Grand Mesa Pipeline entered into an agreement with Saddlehorn Pipeline Company,LLC (“Saddlehorn”), under which we acquired a 37.5% undivided interest in a crude oil pipeline currently under construction (the “Joint Pipeline”). TheJoint Pipeline will take receipt from Grand Mesa Pipeline’s origin in Colorado and will deliver to Cushing, Oklahoma. We will have the right to utilize150,000 barrels per day of capacity on the Joint Pipeline. Operating costs will be allocated to us based on our proportionate ownership interest andthroughput. We expect the Joint Pipeline to be operational beginning in the third quarter of fiscal year 2017.Through our undivided interest in the Joint Pipeline, we will have expanded capacity, sufficient to service our customer contracts at the same originand termination points with the ability to accept additional volume commitments. We will retain ownership of our previously-acquired easements for thepotential future development of transportation projects involving petroleum commodities other than crude oil and condensate. With the consent andparticipation of Saddlehorn, we and Saddlehorn may consider future opportunities using these easements for projects involving the transportation of crudeoil and condensate.We estimate that our share of the cost to construct the Joint Pipeline will be $250 million. We paid $211 million towards the construction of thepipeline during the year ended March 31, 2016, and we expect to pay the remaining $39 million during the fiscal year ending March 31, 2017. Also, as partof the Joint Pipeline project, we are constructing certain assets that will be connected to the Joint Pipeline. The estimated costs for these assets are $117.0million. We spent $36.4 million on the construction of these assets during the year ended March 31, 2016, and expect to pay the remaining $80.6 millionduring the fiscal year ending March 31, 2017.During the fourth quarter of fiscal year 2016, we recorded a write-down of $47.7 million related to pipe we no longer expect to use in the originally-planned Grand Mesa Pipeline, which is reported within loss on disposal or impairment of assets, net. In addition, during the six months ended March 31,2016, we reclassified $47.0 million of costs to acquire land, rights-of-62 Table of Contentsway and easements on the originally-planned Grand Mesa Pipeline route to intangible assets. As discussed above, we acquired an undivided interest in adifferent crude oil pipeline with the same origin and destination points as those of our originally-planned Grand Mesa Pipeline route. We will retain the land,rights-of-way and easements along the originally-planned Grand Mesa Pipeline route for potential future development.Sale of General Partner Interest in TLPOn February 1, 2016, we completed the sale of our general partner interest in TLP to an affiliate of ArcLight Capital Partners (“ArcLight”) for $350million in cash and recorded a gain on disposal of $329.9 million during the three months ended March 31, 2016. As a result, on February 1, 2016, wedeconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. As part of this transaction, weentered into lease agreements whereby we will remain the long-term exclusive tenant in the TLP Southeast terminal system. As a result of entering into theseleases, we deferred $204.6 million of the gain on the sale and will recognize this amount over our future lease payment obligations, which is approximatelyseven years. During the three months ended March 31, 2016, we recognized $5.0 million of the deferred gain in our consolidated statement of operations. Inaddition, we retained TransMontaigne’s marketing business, which is a significant part of our refined products and renewables segment, and TransMontaigneProduct Services, LLC, its customer contracts and its line space on the Colonial and Plantation pipelines.Subsequent EventsSale of TLP Common UnitsOn April 1, 2016, we sold all of the TLP common units we owned to ArcLight for approximately $112.4 million in cash.Class A Convertible Preferred UnitsOn April 21, 2016, we entered into an agreement to issue $200 million of 10.75% Class A Convertible Preferred Units (“Preferred Units”) to OaktreeCapital Management L.P. (“Oaktree”). Oaktree may acquire 16.6 million Preferred Units at a price of $12.03 per unit as well as 3.6 million warrants, which aresubject to certain vesting and exercise terms. We expect to use the net proceeds from the issuance of the Preferred Units to repay borrowings outstanding onour Revolving Credit Facility (as hereinafter defined), which may be re-borrowed in the future to fund capital expenditures and for other general partnershippurposes. The first closing of this transaction occurred on May 11, 2016 and we received gross proceeds of $100 million. We expect the second closing tooccur prior to June 30, 2016.AcquisitionsThe acquisitions disclosed in Part I, Item 1–“Business–Acquisitions” impact the comparability of our results of operations between our current andprior fiscal years.63 Table of ContentsConsolidated Results of OperationsThe following table summarizes our consolidated statements of operations for the periods indicated: Year Ended March 31, 2016 2015 2014 (in thousands)Total revenues $11,742,110 $16,802,057 $9,699,274Total cost of sales 10,839,037 15,958,207 9,132,699Operating expenses 401,118 364,131 259,799General and administrative expense 139,541 149,430 75,860Depreciation and amortization 228,924 193,949 120,754Loss on disposal or impairment of assets, net 320,766 41,184 3,597Revaluation of liabilities (82,673) (12,264) —Operating (loss) income (104,603) 107,420 106,565Equity in earnings of unconsolidated entities 16,121 12,103 1,898Interest expense (133,089) (110,123) (58,854)Gain on early extinguishment of debt 28,532 — —Other income, net 5,575 37,171 86(Loss) income before income taxes (187,464) 46,571 49,695Income tax benefit (expense) 367 3,622 (937)Net (loss) income (187,097) 50,193 48,758Less: Net income allocated to general partner (47,620) (45,700) (14,148)Less: Net income attributable to noncontrolling interests (11,832) (12,887) (1,103)Net (loss) income allocated to limited partners $(246,549) $(8,394) $33,507See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, and depreciation and amortizationexpense by segment below.Non-GAAP Financial MeasuresIn addition to financial results reported in accordance with accounting principles generally accepted in the United States (“GAAP”), we haveprovided the non-GAAP financial measures of EBITDA and Adjusted EBITDA. These non-GAAP financial measures are not intended to be a substitute forthose reported in accordance with GAAP. These measures may be different from non-GAAP financial measures used by other entities, even when similar termsare used to identify such measures.We define EBITDA as net income (loss) attributable to parent equity, plus interest expense, gain on early extinguishment of debt, income taxexpense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding net unrealized gains and losses onderivatives, lower of cost or market adjustments, gains and losses on disposal or impairment of assets, and equity-based compensation expense. We alsoinclude in Adjusted EBITDA certain inventory valuation adjustments related to our refined products and renewables segment, as described below. EBITDAand Adjusted EBITDA should not be considered alternatives to net income, income before income taxes, cash flows from operating activities, or any othermeasure of financial performance calculated in accordance with GAAP as those items are used to measure operating performance, liquidity or the ability toservice debt obligations. We believe that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions toour unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information to investors forevaluating our financial performance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and AdjustedEBITDA, as we define them, may not be comparable to EBITDA, Adjusted EBITDA, or similarly titled measures used by other entities.Other than for our refined products and renewables segment, for purposes of our Adjusted EBITDA calculation, we make a distinction betweenrealized and unrealized gains and losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of thederivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and recorda realized gain or loss. We do not64 Table of Contentsdraw such a distinction between realized and unrealized gains and losses on derivatives of our refined products and renewables segment. The primaryhedging strategy of our refined products and renewables segment is to hedge against the risk of declines in the value of inventory over the course of thecontract cycle, and many of the hedges are six months to one year in duration at inception. The “inventory valuation adjustment” row in the table belowreflects the difference between the market value of the inventory of our refined products and renewables segment at the balance sheet date and its cost. Weinclude this in Adjusted EBITDA because the gains and losses associated with derivative contracts of this segment, which are intended primarily to hedgeinventory holding risk, also impact Adjusted EBITDA.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 hydrocarbons we expect to recoverin future months. During the year ended March 31, 2016, we settled certain derivative contracts that related to crude oil we expect to recover in the monthsfrom April 2016 through December 2016 and realized a gain of $2.1 million. Of this gain, $0.9 million, $0.7 million and $0.5 million were attributable toderivatives with scheduled settlement dates during the quarters ending June 30, 2016, September 30, 2016, and December 31, 2016, respectively. During theyear ended March 31, 2015, we settled certain derivative contracts that related to crude oil we recovered in the months from April 2015 throughSeptember 2015 and realized a gain of $17.9 million. Of this gain, $9.4 million and $8.5 million were attributable to derivatives that settled during thequarters ending June 30, 2015 and September 30, 2015, respectively.The following table reconciles net (loss) income to our EBITDA and Adjusted EBITDA: Year Ended March 31, 2016 2015 2014 (in thousands)Net (loss) income $(187,097) $50,193 $48,758Less: Net income attributable to noncontrolling interests (11,832) (12,887) (1,103)Net (loss) income attributable to parent equity (198,929) 37,306 47,655Interest expense 126,514 106,594 58,871Gain on early extinguishment of debt (28,532) — —Income tax (benefit) expense (420) (3,676) 937Depreciation and amortization 217,893 191,998 127,821EBITDA 116,526 332,222 235,284Net unrealized losses (gains) on derivatives 1,255 7,559 (1,327)Inventory valuation adjustment 24,390 — —Lower of cost or market adjustments (5,932) 16,806 —Loss on disposal or impairment of assets, net 320,783 41,274 3,597Equity-based compensation expense (1) 58,816 42,890 17,804Acquisition expense (2) 2,002 23,198 15,109Revaluation of liabilities (3) (93,725) (20,645) —Adjusted EBITDA $424,115 $443,304 $270,467 (1)Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 11 to our consolidatedfinancial statements included in this Annual Report on Form 10-K (“Annual Report”). Amounts reported in the table above include expense accruals forbonuses expected to be paid in common units, whereas the amounts reported in Note 11 to our consolidated financial statements only include expensesassociated with equity-based awards that have been formally granted.(2)During the years ended March 31, 2016, 2015 and 2014, we recorded $2.0 million, $7.4 million and $6.9 million, respectively, of expense related tolegal and advisory costs associated with acquisitions. During the year ended March 31, 2015, we recorded $15.8 million of compensation expenseassociated with acquisitions (including certain bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon thesuccessful completion of the sale of the business, and compensation expense related to termination benefits for certain TransMontaigne Inc.(“TransMontaigne”) employees). During the year ended March 31, 2014, we recorded $8.2 million of compensation expense associated with acquisitions(including certain bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon the successful completion of the sale ofthe business).65 Table of Contents(3)Amount represents the non-cash valuation adjustment of contingent consideration liabilities, offset by the cash payments, related to royalty agreementsacquired as part of acquisitions in our Water Solutions segment. Amount includes $3.0 million and $0.3 million for the years ended March 31, 2016 and2015, respectively, related to the portion attributatble to noncontrolling interests.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 for the periods indicated: Year Ended March 31, 2016 2015 2014 (in thousands)Reconciliation to consolidated statements of operations: Depreciation and amortization per EBITDA table $217,893 $191,998 $127,821Intangible asset amortization recorded to cost of sales (6,700) (7,767) (6,172)Depreciation and amortization of unconsolidated entities (20,058) (18,979) (1,500)Depreciation and amortization attributable to noncontrolling interests 37,789 28,697 605Depreciation and amortization per consolidated statements of operations $228,924 $193,949 $120,754 Reconciliation to consolidated statements of cash flows: Depreciation and amortization per EBITDA table $217,893 $191,998 $127,821Amortization of debt issuance costs recorded to interest expense 13,587 8,759 5,727Depreciation and amortization of unconsolidated entities (20,058) (18,979) (1,500)Depreciation and amortization attributable to noncontrolling interests 37,789 28,697 605Depreciation and amortization per consolidated statements of cash flows $249,211 $210,475 $132,653 The following table reconciles interest expense per the EBITDA table above to interest expense reported in our consolidated statements ofoperations for the periods indicated: Year Ended March 31, 2016 2015 2014 (in thousands)Interest expense per EBITDA table $126,514 $106,594 $58,871Interest expense attributable to noncontrolling interests (1) 5,493 3,443 —Gain on extinguishment of debt of unconsolidated entities 693 — —Other (2) 389 86 (17)Interest expense per consolidated statements of operations $133,089 $110,123 $58,854 (1)Includes ten months of consolidated TLP interest expense.(2)Includes two months of TLP interest expense as an equity method investment.66 Table of ContentsThe following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated: Year Ended March 31, 2016 Crude OilLogistics WaterSolutions Liquids RetailPropane RefinedProductsandRenewables CorporateandOther Consolidated (in thousands)Operating (loss) income$(40,745) $(313,673) $76,173 $44,096 $226,951 $(97,405) $(104,603)Depreciation and amortization39,363 91,685 15,642 35,992 40,861 5,381 228,924Amortization recorded to cost of sales250 — 1,044 — 5,406 — 6,700Net unrealized losses (gains) on derivatives2,123 3,196 (4,008) (56) — — 1,255Inventory valuation adjustment— — — — 24,390 — 24,390Lower of cost or market adjustments(1,211) — — — (4,721) — (5,932)Loss (gain) on disposal or impairment of assets, net54,952 381,682 11,600 (137) (127,314) — 320,783Equity-based compensation expense— — — — 501 58,315 58,816Acquisition expense— — — 7 — 1,995 2,002Equity in earnings (losses) of unconsolidated entities3,547 (552) — (528) 13,654 — 16,121Other (expense) income, net(6,725) 2,144 281 1,055 179 8,641 5,575Depreciation and amortization of unconsolidated entities9,927 1,135 — 98 8,898 — 20,058Adjusted EBITDA attributable to noncontrolling interest— (518) — (1,324) (54,407) — (56,249)Revaluation of liabilities— (93,725) — — — — (93,725)Adjusted EBITDA$61,481 $71,374 $100,732 $79,203 $134,398 $(23,073) $424,115 Year Ended March 31, 2015 Crude OilLogistics WaterSolutions Liquids RetailPropane RefinedProductsandRenewables CorporateandOther Consolidated (in thousands)Operating (loss) income$(35,832) $65,340 $45,072 $64,075 $54,567 $(85,802) $107,420Depreciation and amortization38,626 73,618 13,513 31,827 32,948 3,417 193,949Amortization recorded to cost of sales102 — 1,931 — 4,057 1,677 7,767Net unrealized losses (gains) on derivatives7,421 (2,786) 2,921 3 — — 7,559Lower of cost or market adjustments10,744 — (51) — 6,113 — 16,806Loss (gain) on disposal or impairment of assets, net3,759 7,504 29,776 330 1 (96) 41,274Equity-based compensation expense— — — — 123 42,767 42,890Acquisition expense6,870 — — 45 8,510 7,773 23,198Equity in earnings (losses) of unconsolidated entities3,731 (29) — — 8,401 — 12,103Other income (expense), net27,305 3,360 31 1,644 (120) 4,951 37,171Depreciation and amortization of unconsolidated entities10,213 1,123 — — 7,643 — 18,979Adjusted EBITDA attributable to noncontrolling interest— (1,220) — (1,110) (42,837) — (45,167)Revaluation of liabilities— (20,645) — — — — (20,645)Adjusted EBITDA$72,939 $126,265 $93,193 $96,814 $79,406 $(25,313) $443,30467 Table of Contents Year Ended March 31, 2014 Crude OilLogistics WaterSolutions Liquids RetailPropane RefinedProductsandRenewables CorporateandOther Consolidated (in thousands)Operating income (loss)$678 $10,317 $71,888 $61,285 $6,514 $(44,117) $106,565Depreciation and amortization22,111 55,105 11,018 28,878 625 3,017 120,754Amortization recorded to cost of sales990 — 2,882 — 1,600 700 6,172Net unrealized losses (gains) on derivatives2,229 647 (4,217) 14 — — (1,327)(Gain) loss on disposal or impairment of assets, net(169) 2,994 5,305 1 — (4,534) 3,597Equity-based compensation expense— — — — — 17,804 17,804Acquisition expense3,500 — — 23 — 11,586 15,109Equity in (losses) earnings of unconsolidated entities(26) — — — — 1,924 1,898Other (expense) income, net(2,939) (266) (212) 1,308 51 2,144 86Depreciation and amortization of unconsolidated entities1,500 — — — — — 1,500Adjusted EBITDA attributable to noncontrolling interest— (631) — (163) (897) — (1,691)Adjusted EBITDA$27,874 $68,166 $86,664 $91,346 $7,893 $(11,476) $270,467 Segment Operating ResultsItems Impacting the Comparability of Our Financial ResultsOur current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to businesscombinations. We have expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of Crescent Terminals, LLCand Cierra Marine, LP and its affiliated companies (collectively, “Crescent”) in July 2013, and Gavilon Energy in December 2013. We have expanded ourwater solutions business considerably through numerous acquisitions of water treatment and disposal facilities. We have expanded our liquids businessthrough the February 2015 acquisition of Sawtooth. We have expanded our retail propane business through numerous acquisitions of retail propanebusinesses. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy and significantly expanded withour July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane businesses are impacted by seasonality, dueprimarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have asignificant impact on our sales volumes and revenues.68 Table of ContentsYear Ended March 31, 2016 Compared to Year Ended March 31, 2015Crude Oil Logistics The following table summarizes the operating results of our crude oil logistics segment for the periods indicated: Year Ended March 31, 2016 2015 (1) Change (in thousands, expect per barrel amounts)Revenues: Crude oil sales $3,170,891 $6,621,871 $(3,450,980)Crude oil transportation and other 55,882 43,349 12,533Total revenues (2) 3,226,773 6,665,220 (3,438,447)Expenses: Cost of sales 3,121,411 6,590,313 (3,468,902)Operating expenses 43,458 52,790 (9,332)General and administrative expenses 8,334 15,564 (7,230)Depreciation and amortization expense 39,363 38,626 737Loss on disposal or impairment of assets, net 54,952 3,759 51,193Total expenses 3,267,518 6,701,052 (3,433,534)Segment operating loss (3) $(40,745) $(35,832) $(4,913) Crude oil sold (barrels) 67,211 83,864 (16,653)Crude oil sold ($/barrel) $47.178 $78.960 $(31.782)Cost per crude oil sold ($/barrel) $46.442 $78.583 $(32.141)Crude oil product margin ($/barrel) $0.736 $0.377 $0.359 (1)During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to the categories shown in the table above.These changes did not impact total revenues. We have retrospectively adjusted previously reported amounts to conform to the current presentation.(2)Revenues include $9.7 million and $29.8 million of intersegment sales during the years ended March 31, 2016 and 2015, respectively, that areeliminated in our consolidated statements of operations.(3)In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to executingthese commitments, the producers requested to be released from the commitments. We agreed to release the producers from their commitments in returnfor a cash payment in March 2015 and additional cash payments over the next five years. Upon execution of these agreements in March 2015, werecorded a gain of $31.6 million to other income in our consolidated statement of operations, net of certain project abandonment costs. Since this gainwas reported in other income, it is not reflected in the table above.Crude Oil Sales. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices since July 2014. The decrease in oursales volumes was due primarily to a slowdown in crude oil production and new drilling of crude oil in the current crude oil price environment.Our cost of sales during the year ended March 31, 2016 was increased by $2.1 million of net unrealized losses on derivatives and reduced by $13.8million of net realized gains on derivatives. Our cost of sales during the year ended March 31, 2015 was increased by $7.4 million of net unrealized losses onderivatives and reduced by $37.4 million of net realized gains on derivatives. Due to the sharper decline in crude oil prices during the year ended March 31,2015 compared to the year ended March 31, 2016, realized gains on derivatives were higher during the year ended March 31, 2015. Our cost of sales duringthe year ended March 31, 2015 was also impacted by a lower of cost or market adjustment of $10.7 million recorded at March 31, 2015.Crude Oil Transportation and Other Revenues. The increase was due primarily to crude oil markets being in contango during the year endedMarch 31, 2016 (a condition in which forward crude oil prices are greater than spot prices), which allowed us to generate revenue from leasing our ownedstorage and subleasing our leased storage.69 Table of ContentsOperating Expenses. The decrease was due primarily to lower compensation expense due primarily to a reduction in headcount from organizationalchanges and lower repair and maintenance expense due to the timing of repairs.General and Administrative Expenses. The decrease was due primarily to $5.6 million of compensation expense during the year ended March 31,2015 related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business,which were paid in December 2014, and $1.3 million of compensation expense during the year ended March 31, 2015 related to termination benefits forcertain TransMontaigne employees.Depreciation and Amortization Expense. The increase was due primarily to capital additions during the year ended March 31, 2016.Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2016, we recorded a write-down of $47.7 million related to pipe weno longer expect to use in the originally-planned Grand Mesa Pipeline. Also, during the year ended March 31, 2016, (i) two previously-planned projects werecanceled and we recorded a loss of $3.1 million, (ii) we recorded an impairment of $2.4 million to the property, plant and equipment of two of our crude oilbarges and (iii) we sold and/or abandoned certain trucks, trailers and barges and recorded a loss of $1.4 million. During the year ended March 31, 2015, werecorded a write-off of project costs of $3.5 million related to a crude oil terminal project that has been discontinued.Water SolutionsThe following table summarizes the operating results of our water solutions segment for the periods indicated: Year Ended March 31, 2016 2015 Change (in thousands, except per barrel amounts)Revenues: Service fees $136,710 $105,682 $31,028Recovered hydrocarbons 41,090 81,762 (40,672)Water transportation — 10,760 (10,760)Other revenues 7,201 1,838 5,363Total revenues 185,001 200,042 (15,041)Expenses: Cost of sales-derivative gain (1) (7,095) (36,763) 29,668Cost of sales-other (241) 6,257 (6,498)Operating expenses 112,538 93,268 19,270General and administrative expenses 2,778 3,082 (304)Depreciation and amortization expense 91,685 73,618 18,067Loss on disposal or impairment of assets, net 381,682 7,504 374,178Revaluation of liabilities (82,673) (12,264) (70,409)Total expenses 498,674 134,702 363,972Segment operating (loss) income $(313,673) $65,340 $(379,013) Water received (barrels) 208,440 161,664 46,776Service fee for water processed ($/barrel) $0.66 $0.65 $0.01Recovered hydrocarbons for water processed ($/barrel) $0.20 $0.51 $(0.31) (1)Includes realized and unrealized (gains) losses.The following tables summarize activity separated between the following categories:•facilities we owned before March 31, 2014, which we refer to below as “existing facilities”; and•facilities we acquired or developed after March 31, 2014, which we refer to below as “recently acquired or developed facilities”.70 Table of ContentsService Fee Revenues. The following table summarizes our service fee revenues (in thousands, except per barrel amounts) for the periods indicated: Year Ended March 31, 2016 2015 ServiceFees WaterBarrelsProcessed Fees Per Water BarrelProcessed ServiceFees WaterBarrelsProcessed Fees Per Water BarrelProcessedExisting facilities $74,195 90,377 $0.82 $81,273 122,454 $0.66Recently acquired or developed facilities 62,515 118,063 0.53 24,409 39,210 0.62Total $136,710 208,440 0.66 $105,682 161,664 0.65The decrease in the volume processed at our existing facilities was due primarily to a slowdown in customer production as a result of the lower crudeoil prices, as well as migration of volumes from existing facilities to recently developed or acquired facilities due to the location of the new facilities. Theincrease in fees per water barrel processed at our existing facilities is partially due to an increase in the service fees in a certain basin and a favorable deliveror pay agreement with a customer where the customer has not been delivering water to our facilities.Recovered Hydrocarbon Revenues. The following table summarizes our recovered hydrocarbon revenues (in thousands, except per barrel amounts)for the periods indicated: Year Ended March 31, 2016 2015 RecoveredHydrocarbonRevenue WaterBarrelsProcessed Revenue Per Water BarrelProcessed RecoveredHydrocarbonRevenue WaterBarrelsProcessed Revenue Per Water BarrelProcessedExisting facilities $22,791 90,377 $0.25 $71,301 122,454 $0.58Recently acquired ordeveloped facilities 18,299 118,063 0.15 10,461 39,210 0.27Total $41,090 208,440 0.20 $81,762 161,664 0.51The decrease in revenue per barrel associated with recovered hydrocarbons was due primarily to the sharp decline in crude oil prices since July 2014and a decrease in the volume of hydrocarbons recovered per barrel of water processed.Water Transportation Revenues. The decrease was due to revenues related to our water transportation business during the year ended March 31,2015. We sold this business during September 2014.Other Revenues. The increase was due primarily to revenues related to the disposal of solids.Cost of Sales. We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbonswe expected to recover when processing the wastewater. Our cost of sales during the year ended March 31, 2016 included $10.3 million of net realized gainson derivatives, partially offset by $3.2 million of net unrealized losses on derivatives. Our cost of sales during the year ended March 31, 2015 included $2.8million of net unrealized gains on derivatives and $34.0 million of net realized gains on derivatives. In December 2015, we settled derivative contracts thathad scheduled settlement dates from January 2016 through December 2016, in order to lock in the gains on those derivatives. 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.The decrease in other cost of sales was due to costs related to our water transportation business during the year ended March 31, 2015. We sold thisbusiness during September 2014.71 Table of ContentsOperating Expenses. The following table summarizes our operating expenses for the periods indicated: Year Ended March 31, 2016 2015 Change (in thousands)Existing facilities $65,739 $73,533 $(7,794)Recently acquired or developed facilities 46,799 19,735 27,064Total $112,538 $93,268 $19,270The decrease in operating expenses for existing facilities was due primarily to lower operating costs of water disposal wells at existing facilities dueto lower volumes processed.Depreciation and Amortization Expense. Of the increase, $15.7 million related to recently acquired or developed water treatment and disposalfacilities and $3.4 million related to recently developed solids processing facilities.Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2016, we recorded an estimated goodwill impairment charge of$380.2 million as the decline in crude oil prices and crude oil production have had an unfavorable impact on our water solutions business (see Note 14 to ourconsolidated financial statements included in this Annual Report). During the year ended March 31, 2015, we sold our water transportation business andrecorded a loss of $4.0 million. Also, during the year ended March 31, 2015, we recorded a loss on abandonment of $3.1 million related to property, plant andequipment of water disposal facilities that we have retired.Revaluation of Liabilities. The revaluation of liabilities represents the valuation adjustment of contingent consideration liabilities related to royaltyagreements acquired as part of certain business combinations. The increase was due to additional acquisitions during the year ended March 31, 2016 offsetby changes in the fair value of the liability.72 Table of ContentsLiquidsThe following table summarizes the operating results of our liquids segment for the periods indicated: Year Ended March 31, 2016 2015 (1) Change (in thousands, except per gallon amounts)Propane sales: Revenues (2) $618,919 $1,265,262 $(646,343)Cost of sales 571,734 1,217,993 (646,259)Product margin 47,185 47,269 (84) Other product sales: Revenues (2) 620,175 1,111,834 (491,659)Cost of sales 532,136 1,038,324 (506,188)Product margin 88,039 73,510 14,529 Other revenues: Revenues (2) 35,943 28,745 7,198Cost of sales 13,806 17,313 (3,507)Product margin 22,137 11,432 10,705 Expenses: Operating expenses 45,140 35,580 9,560General and administrative expenses 8,806 8,271 535Depreciation and amortization expense 15,642 13,513 2,129Loss on disposal or impairment of assets, net 11,600 29,775 (18,175)Total expenses 81,188 87,139 (5,951)Segment operating income $76,173 $45,072 $31,101 Propane sold 1,244,529 1,285,707 (41,178)Propane sold ($/gallon) $0.497 $0.984 $(0.487)Cost per propane sold ($/gallon) $0.459 $0.947 $(0.488)Propane product margin ($/gallon) $0.038 $0.037 $0.001 Other products sold (gallons) 843,922 825,514 18,408Other products sold ($/gallon) $0.735 $1.347 $(0.612)Cost per other products sold ($/gallon) $0.631 $1.258 $(0.627)Other products product margin ($/gallon) $0.104 $0.089 $0.015 (1)During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to railcar cost of sales to the categoriesshown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reportedamounts to conform to the current presentation.(2)Revenues include $80.6 million and $162.0 million of intersegment sales during the years ended March 31, 2016 and 2015, respectively, that areeliminated in our consolidated statements of operations.Propane Sales. The decrease in volumes was due to significantly warmer temperatures in the current year. The decrease in selling price was due tolower commodity prices from oversupply in the market and decreased demand due to the significantly warmer temperatures in the current year winter.73 Table of ContentsOur cost of wholesale propane sales was reduced by $2.1 million of net unrealized gains on derivatives and increased by $4.6 million of netunrealized losses on derivatives for the years ended March 31, 2016 and 2015, respectively. Additionally, our cost of wholesale propane sales was increasedby $1.6 million of net realized losses on derivatives and $8.2 million of net realized losses on derivatives for the years ended March 31, 2016 and 2015,respectively.Product margins per gallon of propane sold were higher during the year ended March 31, 2016 than during the year ended March 31, 2015. Propaneprices declined during the year ended March 31, 2016, but not as sharply as they declined during the year ended March 31, 2015. Declining propane pricestypically have an adverse effect on our margins.We use a weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the locationof the inventory. 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 average cost of allinventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on thesesales. During periods of declining prices, this can result in lower margins on these sales. We would generally expect the impact of these two differentstrategies being in the same inventory costing pools to even out over the course of a full fiscal year.Other Products Sales. The increase in the volume of other wholesale products sold was due to expanded operations.Our cost of sales of other products during the year ended March 31, 2016 was reduced by $1.9 million of net unrealized gains on derivatives. Ourcost of sales of other products during the year ended March 31, 2015 was reduced by $1.7 million of net unrealized gains on derivatives. Additionally, ourcost of other products was reduced by $1.8 million of net realized gains on derivatives and increased by $5.4 million of net realized losses on derivatives forthe years ended March 31, 2016 and 2015, respectively.Product margins during the year ended March 31, 2016 benefited from a high level of butane supply in the market, which lowered our product cost.Other Revenues. This revenue includes storage, terminaling and transportation services income. The increase was due primarily to $21.1 million ofrevenue related to Sawtooth, which we acquired in February 2015, partially offset by a $10.0 million decrease in hauling revenues due to declining marketconditions.Operating Expenses. The increase was due primarily to $4.6 million of expenses related to Sawtooth, which we acquired in February 2015, as well asa shift in the recording of incentive compensation expense related to bonuses from the liquids segment to “corporate and other” during the year endedMarch 31, 2015. See further discussion within the “Corporate and Other” section below.General and Administrative Expenses. The increase was due primarily to $1.4 million of expenses related to Sawtooth, which we acquired inFebruary 2015.Depreciation and Amortization Expense. The increase was due to an additional $4.2 million of expense during the year ended March 31, 2016related to Sawtooth, which we acquired in February 2015, partially offset by $1.0 million of expense recorded during the year ended March 31, 2015 relatedto a natural gas liquids terminal that we sold in December 2014.Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2016, we wrote off assets of $14.6 million acquired as part of theGavilon Energy acquisition that we deemed no longer recoverable. During the year ended March 31, 2016, we received a payment of $3.0 million from thestate of Maine to relocate certain terminal assets. During the year ended March 31, 2015, we recorded a loss on disposal of assets of $29.8 million related tothe sale of a natural gas liquids terminal.74 Table of ContentsRetail PropaneThe following table summarizes the operating results of our retail propane segment for the periods indicated: Year Ended March 31, 2016 2015 Change (in thousands, except per gallon amounts)Propane sales: Revenues $248,673 $347,575 $(98,902)Cost of sales 95,191 181,655 (86,464)Product margin 153,482 165,920 (12,438) Distillate sales: Revenues 64,868 106,037 (41,169)Cost of sales 48,191 85,329 (37,138)Product margin 16,677 20,708 (4,031) Other revenues: Revenues 39,436 35,585 3,851Cost of sales 13,375 11,554 1,821Product margin 26,061 24,031 2,030 Expenses: Operating expenses 104,287 102,123 2,164General and administrative expenses 11,982 12,352 (370)Depreciation and amortization expense 35,992 31,827 4,165(Gain) loss on disposal or impairment of assets, net (137) 282 (419)Total expenses 152,124 146,584 5,540Segment operating income$44,096 $64,075 $(19,979) Propane sold (gallons) 152,238 169,279 (17,041)Propane sold ($/gallon) $1.633 $2.053 $(0.420)Cost per propane sold ($/gallon) $0.625 $1.073 $(0.448)Propane product margin ($/gallon) $1.008 $0.980 $0.028 Distillates sold (gallons) 30,674 34,862 (4,188)Distillates sold ($/gallon) $2.115 $3.042 $(0.927)Cost per distillates sold ($/gallon) $1.571 $2.448 $(0.877)Distillates product margin ($/gallon) $0.544 $0.594 $(0.050)Revenues. The decrease in both propane and distillate revenues was due to lower volumes as a result of significantly warmer winter temperatures inthe current year, as compared to the prior year. The decrease in selling price was due to an oversupply in the propane market lowering commodity prices aswell as the significantly warmer temperatures in the current year winter.Cost of Sales. Cost of sales decreased for both propane and distillates due to lower commodity prices.Operating Expenses. The increase was due primarily to increased compensation associated with acquisitions of retail propane businesses.General and Administrative Expenses. Our retail propane segment general and administrative expenses for the year ended March 31, 2016 wereconsistent with those of the prior year with the exception of bad debt expense which was lower due to lower sales.Depreciation and Amortization Expense. The increase was due primarily to acquisitions of retail propane businesses.75 Table of ContentsRefined Products and RenewablesThe following table summarizes the operating results of our refined products and renewables segment for the periods indicated. Our refined productsand renewables segment was significantly expanded with our July 2014 acquisition of TransMontaigne. On February 1, 2016, we sold our general partnerinterest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equitymethod of accounting. Year Ended March 31, 2016 2015 (1) Change (in thousands, except per barrel and gallon amounts)Refined products sales: Revenues (2) $6,294,008 $6,682,040 $(388,032)Cost of sales 6,161,243 6,574,545 (413,302)Product margin 132,765 107,495 25,270 Renewables sales: Revenues 390,753 473,885 (83,132)Cost of sales 380,212 461,996 (81,784)Product margin 10,541 11,889 (1,348) Service fee revenues 108,221 76,847 31,374 Expenses: Operating expenses 95,371 82,583 12,788General and administrative expenses 15,675 26,133 (10,458)Depreciation and amortization expense 40,861 32,948 7,913Gain on disposal or impairment of assets, net (127,331) — (127,331)Total expenses 24,576 141,664 (117,088)Segment operating income $226,951 $54,567 $172,384 Refined products sold (barrels) 98,988 68,043 30,945Refined products sold ($/barrel) $63.584 $98.203 $(34.619)Cost per refined products sold ($/barrel) $62.242 $96.623 $(34.381)Refined products product margin ($/barrel) $1.342 $1.580 $(0.238)Refined products product margin ($/gallon) $0.032 $0.038 $(0.006) Renewable products sold (barrels) 5,794 5,318 476Renewable products sold ($/barrel) $67.441 $89.110 $(21.669)Cost per renewable products sold ($/barrel) $65.622 $86.874 $(21.252)Renewable products product margin ($/barrel) $1.819 $2.236 $(0.417)Renewable products product margin ($/gallon) $0.043 $0.053 $(0.010) (1)During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues and cost of sales to the categories shown inthe table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts toconform to the current presentation.(2)Revenues include $0.9 million and $1.1 million of intersegment sales during the years ended March 31, 2016, and 2015, respectively, that areeliminated in our consolidated statement of operations.Refined Products and Renewables Sales. Our refined products and renewables segment was significantly expanded with our July 2014 acquisitionof TransMontaigne. The resultant increase in revenues and cost of sales was offset by a sharp decline in product prices. Also, the decrease in per-barrelrenewable product margins was due primarily to lower renewables76 Table of Contentsprices caused by increased import activity, partially offset by an increase in the amount we can claim for certain biodiesel tax credits from $5.8 million fortransactions during calendar year 2014 to $6.2 million for transactions in calendar year 2015.Operating Expenses. The increase was due primarily to the inclusion of TLP for ten months of the current fiscal year, compared to nine months of theprior fiscal year as TLP was deconsolidated on February 1, 2016. Also contributing to the increase was the inclusion of TransMontaigne for the entire currentfiscal year, compared to nine months of the prior fiscal year.General and Administrative Expenses. The decrease was due primarily to $8.0 million of compensation expense during the year ended March 31,2015 related to termination benefits for certain TransMontaigne employees. This decrease was partially offset by the inclusion of TransMontaigne for theentire current fiscal year, compared to nine months of the prior fiscal year.Depreciation and Amortization Expense. The increase was due primarily to the inclusion of TLP for ten months of the current fiscal year, comparedto nine months of the prior fiscal year as TLP was deconsolidated on February 1, 2016.Gain on Disposal or Impairment of Assets, Net. During the year ended March 31, 2016, we sold our general partner interest in TLP and recorded again on disposal of $329.9 million during the three months ended March 31, 2016. As part of this transaction, we entered into lease agreements whereby wewill remain the long-term exclusive tenant in the TLP Southeast terminal system. As a result of entering into these leases, we deferred $204.6 million of thegain on the sale and will recognize this amount over our future lease payment obligations, which is approximately seven years. During the three monthsended March 31, 2016, we recognized $5.0 million of the deferred gain in our consolidated statement of operations. See “Recent Developments” above for afurther discussion. During the year ended March 31, 2016, we recorded a loss of $1.8 million related to certain property, plant and equipment that we haveretired and we also sold certain tank bottoms and recorded a loss of $1.3 million.Corporate and OtherThe operating loss within “corporate and other” includes the following components for the periods indicated: Year Ended March 31, 2016 2015 Change (in thousands)Incentive compensation expense $(61,252) $(48,339) $(12,913)Acquisition expense (2,002) (7,382) 5,380Other corporate expenses (34,151) (30,081) (4,070)Total $(97,405) $(85,802) $(11,603)The expenses shown in the table above for incentive compensation include cash-based and equity-based compensation. Such incentivecompensation expenses were higher during the year ended March 31, 2016 than during the year ended March 31, 2015, due primarily to two factorsdescribed below.As part of its review of our executive compensation program, the Compensation Committee of the Board of Directors approved a new type of equity-based compensation award, under which the number of common units that vest is contingent upon the performance of our common units relative to theperformance of other entities in the Alerian MLP Index. During the year ended March 31, 2016, three tranches of these Performance Awards were granted,with vesting dates of July 1, 2015, July 1, 2016, and July 1, 2017, respectively. We recorded $16.4 million of expense related to the Performance Awardsduring the year ended March 31, 2016, $16.1 million of which related to awards that vested on July 1, 2015.We have also granted certain Service Awards, which vest contingent only on the continued service of the recipients. The number of outstandingService Awards was higher at March 31, 2016 than at March 31, 2015. This was due in part to the addition of new employees as our business has expanded,and was due in part to increases in the number of Service Awards granted to certain employees following the Compensation Committee’s review of ourcompensation program. The expense associated with these Service Awards (exclusive of accruals of annual bonuses paid or expected to be paid in commonunits) was $35.2 million during the year ended March 31, 2016, compared to $32.8 million during the year ended March 31, 2015.The expense associated with annual bonuses (a portion of which were paid or are expected to be paid in common units) was $2.9 million during theyear ended March 31, 2016, compared to $5.0 million during the year ended March 31, 2015.77 Table of ContentsWe record compensation expense related to common units within “corporate and other”, while compensation expense paid in cash is recorded within theindividual business segments.The expenses shown in the table above for acquisitions relate primarily to legal and advisory costs. We incurred $4.2 million of such expensesduring the year ended March 31, 2015 related to our acquisition of TransMontaigne.Equity in Earnings of Unconsolidated EntitiesEquity in earnings of unconsolidated entities was $16.1 million and $12.1 million during the years ended March 31, 2016 and 2015, respectively.The increase was due primarily to an increase of $7.1 million of earnings from TLP (including Battleground Oil Specialty Terminal Company LLC(“BOSTCO”) and Frontera Brownsville LLC (“Frontera”)) that we acquired as part of our July 2014 acquisition of TransMontaigne, and which wedeconsolidated when we sold our general partner interest in TLP as of February 1, 2016, partially offset by a decrease of $2.4 million in earnings from ourinvestments in an ethanol production facility and a water supply company.Interest ExpenseInterest expense includes interest expense on our revolving credit facilities and senior notes, amortization of debt issuance costs, letter of credit fees,interest on equipment financing notes, and accretion of interest on noninterest bearing debt obligations. Interest expense was $133.1 million and $110.1million during the years ended March 31, 2016 and 2015, respectively. The increase in interest expense was due primarily to (i) the increased level of debtoutstanding on our Revolving Credit Facility (the average balance outstanding on our Revolving Credit Facility was $1.7 billion during the year endedMarch 31, 2016, compared to $1.2 billion during year ended March 31, 2015), primarily to finance acquisitions and capital expenditures; (ii) the issuance of$400.0 million of fixed-rate notes during July 2014; and (iii) increased interest expense related to TLP’s credit facility (our interest in TLP was acquired inJuly 2014, and we sold our general partner interest in TLP as of February 1, 2016).Gain on Early Extinguishment of DebtDuring the fourth quarter of fiscal year 2016, we repurchased $73.2 million of our 2019 Notes and 2021 Notes for an aggregate purchase price of$43.4 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2019 Notes and 2021 Notes of$28.5 million (net of the write off of debt issuance costs of $1.3 million).Other Income, NetThe following table summarizes the components of other income, net for the periods indicated: Year Ended March 31, 2016 2015 (in thousands)Interest income (1)$12,004 $4,575Crude oil marketing arrangement (2)(6,726) (5,642)Crude oil rail transloading facility (3)— 31,600Other (4)297 6,638Other income, net$5,575 $37,171 (1)Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party andto a loan receivable from an equity method investee.(2)Represents another party’s share of the profits generated from a joint crude oil marketing arrangement.(3)In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to executingthese commitments, the producers requested to be released from the commitments. We agreed to release the producers from their commitments in returnfor a cash payment in March 2015 and additional cash payments over the next five years. In addition, one of the producers committed to pay us aspecified fee on each barrel78 Table of Contentsof 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 $31.6million to other income, net of certain project abandonment costs.(4)During the year ended March 31, 2015, we settled two separate contractual disputes and recorded $5.5 million of proceeds to other income. Also duringthe year ended March 31, 2015, we offered to settle another contractual dispute, and recorded $1.2 million to other expense as an estimate of theprobable loss. During the year ended March 31, 2016, we finalized the settlement of this contractual dispute and paid approximately $0.5 million at thedate of settlement and committed to pay approximately $1.1 million in equal annual installments over a period of 11 years beginning on October 15,2016 and ending in October 2026.Income Tax Expense (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. 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 2012 to 2015 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.Income tax benefit was $0.4 million and $3.6 million during the years ended March 31, 2016 and 2015, respectively. TransMontaigne was a taxablesubsidiary from July 1, 2014 (the date we acquired TransMontaigne) to December 30, 2014 (the date we converted TransMontaigne to a non-taxable entity).Income tax benefit during the year ended March 31, 2016 includes a benefit of $3.6 million related to a change in estimate of the income tax obligationpayable related to TransMontaigne. Income tax benefit during the year ended March 31, 2015 was attributable primarily to TransMontaigne.Noncontrolling InterestsWe 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 $11.8 million and $12.9 million during the years ended March 31, 2016 and 2015,respectively. The noncontrolling interests were due primarily to the July 2014 acquisition of TransMontaigne, in which we acquired the 2% general partnerinterest and a 19.7% limited partner interest in TLP. On February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, wedeconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting.79 Table of ContentsYear Ended March 31, 2015 Compared to Year Ended March 31, 2014Crude Oil LogisticsThe 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, expect per barrel amounts)Revenues: Crude oil sales $6,621,871 $4,559,923 $2,061,948Crude oil transportation and other 43,349 36,469 6,880Total revenues (1) 6,665,220 4,596,392 2,068,828Expenses: Cost of sales 6,590,313 4,515,244 2,075,069Operating expenses 52,790 54,043 (1,253)General and administrative expenses 15,564 4,487 11,077Depreciation and amortization expense 38,626 22,111 16,515Loss (gain) on disposal or impairment of assets, net 3,759 (171) 3,930Total expenses 6,701,052 4,595,714 2,105,338Segment operating (loss) income (2) $(35,832) $678 $(36,510) Crude oil sold (barrels) 83,864 46,107 37,757Crude oil sold ($/barrel) $78.960 $98.899 $(19.939)Cost per crude oil sold ($/barrel) $78.583 $97.930 $(19.347)Crude oil product margin ($/barrel) $0.377 $0.969 $(0.592) (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 to executingthese commitments, the producers requested to be released from the commitments. We agreed to release the producers from their commitments in returnfor a cash payment in March 2015 and additional cash payments over the next five years. Upon execution of these agreements in March 2015, werecorded a gain of $31.6 million to other income in our consolidated statement of operations, net of certain project abandonment costs. Since this gainwas reported in other income, it is not reflected in the table above.Crude Oil Sales. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices since July 2014. The most significantdriver of the increase in our sales volumes was the acquisition of Gavilon Energy in December 2013.Our cost of sales during the year ended March 31, 2015 was increased by $7.4 million of net unrealized losses on derivatives and reduced by $37.4million of net realized gains on derivatives. Our cost of sales during the year ended March 31, 2014 was increased by $2.2 million of net unrealized losses onderivatives and $5.1 million of net realized losses on derivatives.The decrease in product margins was due primarily to the sharp decline in crude oil prices since July 2014, which had an adverse impact on marginsdue to the 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 leasedstorage during most of the year ended March 31, 2015, as crude oil markets were backwardated for most of the year.Crude Oil Transportation and Other Revenues. The increase was due primarily to the Crescent acquisition in July 2013 and the Gavilon Energyacquisition in December 2013.80 Table of ContentsOperating Expenses. The decrease was due primarily to a shift in the recording of incentive compensation expense related to bonuses from the crudeoil logistics segment to “corporate and other” during the year ended March 31, 2015. See further discussion within the “Corporate and Other” section below.The decrease was also due to lower railcar lease expense as we purchased railcars beginning in January 2014 to utilize in our operations and lower relocationexpenses, partially offset by an increase due to the Gavilon Energy acquisition in December 2013.General and Administrative Expenses. The increase was due to the acquisitions of Gavilon Energy in December 2013 and TransMontaigne inJuly 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 of Gavilon Energy granted to employees, contingent upon successfulcompletion 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 to termination benefits for certain TransMontaigne employees.Depreciation and Amortization Expense. The increase was due primarily to acquisitions and capital expansions.Loss (Gain) on Disposal or Impairment of Assets, Net. During the year ended March 31, 2015, we recorded a write-off of project costs of $3.5 millionrelated to a crude oil terminal project that has been discontinued.Water SolutionsThe following table summarizes the operating results of our water solutions segment for the periods indicated: Year Ended March 31, 2015 2014 Change (in thousands, except per barrel amounts)Revenues: Service fees $105,682 $58,161 $47,521Recovered hydrocarbons 81,762 67,627 14,135Water transportation 10,760 17,312 (6,552)Other revenues 1,838 — 1,838Total revenues 200,042 143,100 56,942Expenses: Cost of sales-derivative (gain) loss (1) (36,763) 1,969 (38,732)Cost of sales-other 6,257 9,769 (3,512)Operating expenses 93,268 59,184 34,084General and administrative expenses 3,082 3,762 (680)Depreciation and amortization expense 73,618 55,105 18,513Loss on disposal or impairment of assets, net 7,504 2,994 4,510Revaluation of liabilities (12,264) — (12,264)Total expenses 134,702 132,783 1,919Segment operating income $65,340 $10,317 $55,023 Water received (barrels) 161,664 75,451 86,213Service fee for water processed ($/barrel) $0.65 $0.77 $(0.12)Recovered hydrocarbons for water processed ($/barrel) $0.51 $0.90 $(0.39) (1)Includes realized and unrealized (gains) losses.The following tables summarize activity separated between the following categories:•facilities we owned before March 31, 2013, which we refer to below as “existing facilities”; and•facilities we acquired or developed after March 31, 2013, which we refer to below as “recently acquired or developed facilities”.81 Table of ContentsService Fee Revenues. The following table summarizes our service fee revenues (in thousands, except per barrel amounts) for the periods indicated: Year Ended March 31, 2015 2014 ServiceFees WaterBarrelsProcessed Fees Per Water BarrelProcessed ServiceFees WaterBarrelsProcessed Fees Per Water BarrelProcessedExisting facilities $65,541 85,560 $0.77 $51,908 59,305 $0.88Recently acquired or developed facilities 40,141 76,104 0.53 6,253 16,146 0.39Total $105,682 161,664 0.65 $58,161 75,451 0.77The increase in the volume processed at our existing facilities was due primarily to increased demand from customers. Also, the average revenue perbarrel varies across the areas in which we operate due to market conditions in these areas. Per-barrel revenues are highest at our facility in Wyoming due tothe nature of the services required. The majority of the recently acquired facilities are in Texas, where market rates for disposal are lower.Recovered Hydrocarbon Revenues. The following table summarizes our recovered hydrocarbon revenues (in thousands, except per barrel amounts)for the periods indicated: Year Ended March 31, 2015 2014 RecoveredHydrocarbonRevenue WaterBarrelsProcessed Revenue Per Water BarrelProcessed RecoveredHydrocarbonRevenue WaterBarrelsProcessed Revenue Per Water BarrelProcessedExisting facilities $36,361 85,560 $0.42 $40,393 59,305 $0.68Recently acquired ordeveloped facilities 45,401 76,104 0.60 27,234 16,146 1.69Total $81,762 161,664 0.51 $67,627 75,451 0.90The decrease in revenue per barrel associated with recovered hydrocarbons was due primarily to the sharp decline in crude oil prices since July 2014.Water Transportation Revenues. The decrease resulted from the sale of our water transportation business during September 2014.Cost of Sales. We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbonswe expected to recover when processing the wastewater. Our cost of sales during the year ended March 31, 2015 included $2.8 million of net unrealized gainson derivatives and $34.0 million of net realized gains on derivatives. Our cost of sales during the year ended March 31, 2014 included $0.6 million of netunrealized losses on derivatives and $1.4 million of net realized losses on derivatives. In December 2014, we settled derivative contracts that had scheduledsettlement dates from April 2015 through September 2015, in order to lock in the gains on those derivatives.The decrease in other cost of sales resulted from the sale of our water transportation business during September 2014.Operating Expenses. The following table summarizes our operating expenses for the periods indicated: Year Ended March 31, 2015 2014 Change (in thousands)Existing facilities $41,167 $36,381 $4,786Recently acquired or developed facilities 52,101 22,803 29,298Total $93,268 $59,184 $34,084The increase in operating expenses for existing facilities was due primarily to increased costs associated with the construction and operation of newwater disposal wells at existing facilities.82 Table of ContentsDepreciation and Amortization Expense. Of this increase, $15.0 million related to acquisitions, which included $1.3 million of amortizationexpense related to trade name intangible assets. The remaining increase was due primarily to $1.8 million of amortization expense related to trade nameintangible assets. During the fourth quarter of the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-liveddefensive assets.Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2015, we sold our water transportation business and recorded a lossof $4.0 million. Also, during the year ended March 31, 2015, we recorded a loss on abandonment of $3.1 million related to property, plant and equipment ofwater disposal facilities that we have retired. During the year ended March 31, 2014, we recorded losses on disposal of property, plant and equipment of $2.0million as a result of property damage from lightning strikes at two of our facilities.Revaluation of Liabilities. The revaluation of liabilities represents the valuation adjustment of contingent consideration liabilities related to royaltyagreements acquired as part of certain business combinations during the year ended March 31, 2015.LiquidsThe following table summarizes the operating results of our liquids segment for the periods indicated: Year Ended March 31, 2015 2014 Change (in thousands, except per gallon amounts)Propane sales: Revenues (1) $1,265,262 $1,632,948 $(367,686)Cost of sales 1,217,993 1,559,266 (341,273)Product margin 47,269 73,682 (26,413) Other product sales: Revenues (1) 1,111,834 1,231,965 (120,131)Cost of sales 1,038,324 1,179,944 (141,620)Product margin 73,510 52,021 21,489 Other revenues: Revenues (1) 28,745 31,062 (2,317)Cost of sales 17,313 24,439 (7,126)Product margin 11,432 6,623 4,809 Expenses: Operating expenses 35,580 37,672 (2,092)General and administrative expenses 8,271 6,443 1,828Depreciation and amortization expense 13,513 11,018 2,495Loss on disposal or impairment of assets, net 29,775 5,305 24,470Total expenses 87,139 60,438 26,701Segment operating income $45,072 $71,888 $(26,816) Propane sold (gallon) 1,285,707 1,190,106 95,601Propane sold ($/gallon) $0.984 $1.372 $(0.388)Cost per propane sold ($/gallon) $0.947 $1.310 $(0.363)Propane product margin ($/gallon) $0.037 $0.062 $(0.025) Other products sold (gallon) 825,514 786,671 38,843Other products sold ($/gallon) $1.347 $1.566 $(0.219)Cost per other products sold ($/gallon) $1.258 $1.500 $(0.242)Other products product margin ($/gallon) $0.089 $0.066 $0.02383 Table 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, that areeliminated in our consolidated statements of operations.Propane Sales. The increase in the volume sold from the year ended March 31, 2014 to the year ended March 31, 2015 was due primarily to theinclusion of the natural gas liquids operations acquired from Gavilon Energy for a full fiscal year (compared to only four months of the prior fiscal year) andto the expansion of an agreement under which we market the majority of the production from a fractionation facility.Our cost of wholesale propane sales during the year ended March 31, 2015 was increased by $4.6 million of net unrealized losses on derivatives. Ourcost of wholesale propane sales during the year ended March 31, 2014 was increased by $1.6 million of net unrealized losses on derivatives.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.Other Products Sales. Our cost of sales of other products during the year ended March 31, 2015 was reduced by $1.7 million of net unrealized gainson derivatives. Our cost of sales of other products during the year ended March 31, 2014 was reduced by $5.8 million of net unrealized gains on derivatives.Operating Expenses. This decrease was due primarily to lower compensation expense, $5.0 million of which resulted from a shift in the recording ofincentive compensation expense related to bonuses from the liquids segment to “corporate and other” during the year ended March 31, 2015. See furtherdiscussion within the “Corporate and Other” section below.General and Administrative Expenses. This increase was due primarily to expanded operations.Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2015, we recorded a loss on disposal of assets of $29.9 millionrelated to the sale of a natural gas liquids terminal. During the year ended March 31, 2014, we recorded an impairment of $5.3 million to the value of theproperty, plant and equipment of another natural gas liquids terminal.84 Table of ContentsRetail PropaneThe following table summarizes the operating results of our retail propane segment for the periods indicated: Year Ended March 31, 2015 2014 Change (in thousands, except per gallon amounts)Propane sales: Revenues $347,575 $388,225 $(40,650)Cost of sales 181,655 233,110 (51,455)Product margin 165,920 155,115 10,805 Distillate sales: Revenues 106,037 127,672 (21,635)Cost of sales 85,329 109,058 (23,729)Product margin 20,708 18,614 2,094 Other product sales: Revenues 35,585 35,918 (333)Cost of sales 11,554 11,531 23Product margin 24,031 24,387 (356) Expenses: Operating expenses 102,123 96,936 5,187General and administrative expenses 12,352 11,017 1,335Depreciation and amortization expense 31,827 28,878 2,949Loss on disposal or impairment of assets, net 282 — 282Total expenses 146,584 136,831 9,753Segment operating income $64,075 $61,285 $2,790 Propane sold (gallons) 169,279 162,361 6,918Propane sold ($/gallon) $2.053 $2.391 $(0.338)Cost per propane sold ($/gallon) $1.073 $1.436 $(0.363)Propane product margin ($/gallon) $0.980 $0.955 $0.025 Distillates sold (gallons) 34,862 34,965 (103)Distillates sold ($/gallon) $3.042 $3.651 $(0.609)Cost per distillates sold ($/gallon) $2.448 $3.119 $(0.671)Distillates product margin ($/gallon) $0.594 $0.532 $0.062Revenues. Our retail propane revenues decreased due to the lower demand as the weather conditions were warmer in some markets in the winter ofthe year ended March 31, 2015 compared to the winter of the prior year. This was partially offset by an increase in volume sold due in part of the growth ofour business through acquisitions.Cost of Sales. Our retail propane segment cost of sales decreased due to the decline in commodity prices.Operating Expenses. The increase was due primarily to increased compensation expense resulting from 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, 2014.85 Table of ContentsRefined Products and RenewablesThe 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 significantly expanded with our July 2014 acquisition ofTransMontaigne. Year Ended March 31, 2015 2014 Change (in thousands, except per barrel and gallon amounts)Refined products sales: Revenues (1)$6,682,040 $1,180,895 $5,501,145Cost of sales6,574,545 1,172,754 5,401,791Product margin107,495 8,141 99,354 Renewables sales: Revenues473,885 176,781 297,104Cost of sales461,996 171,422 290,574Product margin11,889 5,359 6,530 Service fee revenues76,847 — 76,847 Expenses: Operating expenses82,583 6,205 76,378General and administrative expenses26,133 156 25,977Depreciation and amortization expense32,948 625 32,323Total expenses141,664 6,986 134,678Segment operating income$54,567 $6,514 $48,053 Refined products sold (barrels)68,043 9,833 58,210Refined products sold ($/barrel)$98.203 $120.095 $(21.892)Cost per refined products sold ($/barrel)$96.623 $119.267 $(22.644)Refined products product margin ($/barrel)$1.580 $0.828 $0.752Refined products product margin ($/gallon)$0.038 $0.020 $0.018 Renewable products sold (barrels)5,318 3,593 1,725Renewable products sold ($/barrel)$89.110 $49.202 $39.908Cost per renewable products sold ($/barrel)$86.874 $47.710 $39.164Renewable products product margin ($/barrel)$2.236 $1.492 $0.744Renewable products product margin ($/gallon)$0.053 $0.036 $0.017 (1)Revenues include $1.1 million of intersegment sales during the year ended March 31, 2015 that are eliminated in our consolidated statement ofoperations.Refined Products Revenues. Of the refined products revenues during the year ended March 31, 2015, $3.7 billion was attributable toTransMontaigne.Refined Products Cost of Sales. Of the refined products cost of sales during the year ended March 31, 2015, $3.6 billion was attributable toTransMontaigne.Renewables Sales. During December 2014, a federal law was passed that enabled us to claim certain biodiesel tax credits for transactions duringcalendar year 2014. During the year ended March 31, 2015, our cost of sales was reduced by $5.8 million related to these tax credits.86 Table of ContentsService Fee Revenues. Of the service fee revenues during the year ended March 31, 2015, $76.8 million was attributable to TLP.Operating Expenses. Of the operating expenses during the year ended March 31, 2015, $77.1 million was attributable to TransMontaigne (includingTLP).General and Administrative Expenses. General and administrative expenses during the year ended March 31, 2015 were increased by $8.0 million ofcompensation expense related to termination benefits for certain TransMontaigne employees. Of the general and administrative expenses during the yearended March 31, 2015, $19.2 million was attributable to TransMontaigne (including TLP).Depreciation and Amortization Expense. The increase was due primarily to depreciation on TLP’s terminal assets and amortization of customerrelationship intangible assets acquired in the business combination with TransMontaigne. Of the depreciation and amortization expense during the yearended March 31, 2015, $30.3 million was attributable to TransMontaigne (including TLP).Corporate and OtherThe operating loss within “corporate and other” includes the following components for the periods indicated: 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 expense (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 the businessin February 2014.(2)We acquired the natural gas business in our December 2013 acquisition of Gavilon Energy. We subsequently wound down the natural gas business and,as of March 31, 2014, this business has no revenue-generating activity.The increase in equity-based compensation 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 segment 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.The expenses shown in the table above for acquisitions relate primarily to legal and advisory costs. Acquisition expenses during the year endedMarch 31, 2015 related primarily to the acquisitions of TransMontaigne and Sawtooth. Acquisition expenses during the year ended March 31, 2014 relatedprimarily 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.87 Table of ContentsOperating 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.Equity in Earnings of Unconsolidated EntitiesEquity in earnings of unconsolidated entities was $12.1 million and $1.9 million during the years ended March 31, 2015 and 2014, respectively.The increase was due primarily to an increase of $5.5 million of earnings from BOSTCO and Frontera that we acquired as part of our July 2014 acquisition ofTransMontaigne, and an increase of $4.7 million of earnings from Glass Mountain and an ethanol production facility that we acquired as part of ourDecember 2013 acquisition of Gavilon Energy.Interest ExpenseInterest expense was $110.1 million and $58.9 million during the years ended March 31, 2015 and 2014, respectively. The increase in interestexpense was due primarily to (i) the increased level of debt outstanding on our Revolving Credit Facility (the average balance outstanding on our RevolvingCredit Facility was $1.2 billion during the year ended March 31, 2015, compared to $0.6 billion during year ended March 31, 2014), primarily to financeacquisitions and capital expenditures; (ii) the issuance of $450.0 million of fixed-rate notes during October 2013, which bear a higher interest rate than ourRevolving Credit Facility; and (iii) increased interest expense related to TLP’s credit facility (our interest in TLP was acquired in July 2014).Other Income, NetThe following table summarizes the components of other income, net for the periods indicated: Year Ended March 31, 2015 2014 (in thousands)Interest income (1)$4,575 $1,365Crude oil marketing arrangement (2)(5,642) (1,064)Crude oil rail transloading facility (3)31,600 —Other (4)6,638 (215)Other income, net$37,171 $86 (1)Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party andto a loan receivable from an equity method investee.(2)Represents another party’s share of the profits generated from a joint crude oil marketing arrangement.(3)In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to executingthese commitments, the producers requested to be released from the commitments. We agreed to release the producers from their commitments in returnfor a cash payment in March 2015 and additional cash payments over the next five years. In addition, one of the producers committed to pay us aspecified 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, net of certain project abandonment costs.(4)During the year ended March 31, 2015, we settled two separate contractual disputes and recorded $5.5 million of proceeds to other income. Also duringthe year ended March 31, 2015, we offered to settle another contractual dispute, and recorded $1.2 million to other expense as an estimate of theprobable loss.Income Tax Expense (Benefit)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 was subject to United States federal and state income taxes. On December 30, 2014, we converted TransMontaigne from a taxable entity to anon-taxable entity.88 Table of ContentsNoncontrolling InterestsNet income attributable to noncontrolling interests was $12.9 million and $1.1 million during the years ended March 31, 2015 and 2014,respectively. The increase was due primarily to the July 2014 acquisition of TransMontaigne, in which we acquired the 2% general partner interest and a19.7% limited partner interest in TLP.Liquidity, Sources of Capital and Capital Resource ActivitiesOur principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. See Note 8to our consolidated financial statements included in this Annual Report for a detailed description of our long-term debt. Our cash flows from operations arediscussed below.Our borrowing needs vary during the year due in part to the seasonal nature of our liquids business. Our greatest working capital borrowing needsgenerally occur during the period of June through December, when we are building our natural gas liquids inventories in anticipation of the heating season.Our working 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.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 or sell assets. Ourability to raise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances thatwe can raise additional capital to meet these needs (see Part I, Item 1A–“Risk Factors”). Commitments or expenditures, if any, we may make toward anyacquisition projects are at our discretion.We have historically pursued a strategy of growth through acquisitions. Under current market conditions, the cost of capital is much higher than ithas been in recent years; prospective lenders seek much higher interest rates than they have sought in the past, and at our prior distribution level of $0.64 percommon unit, the yield on our common units was much higher than it had been in the past. In April 2016, the board of directors of our general partnerdecided to reduce our distribution level from $0.64 per common unit to $0.39 per common unit, which it anticipates will continue for three additionalquarters under current market conditions. We expect the reduction in the distribution to provide us with approximately $170 million of annual cash savingsto enhance liquidity, repay indebtedness and/or invest in selected growth projects.Under current market conditions, we are much less likely to pursue acquisitions than we have been in the past. We continue to undertake certaincapital expansion projects, including the funding of our portion of the construction of the Joint Pipeline, our assets that will be connected to the JointPipeline and the continued development of Sawtooth natural gas liquids storage caverns, among others. We expect to be able to finance these projectsthrough available capacity on our Revolving Credit Facility, asset sales or other forms of financing.Other sources of liquidity during the three months ended March 31, 2016 and the month of April 2016 are discussed below.Sale of General Partner Interest in TLPOn February 1, 2016, we completed the sale of our general partner interest in TLP to an affiliate of ArcLight for $350 million in cash.Sale of TLP Common UnitsOn April 1, 2016, we sold all of the TLP common units we owned to ArcLight for approximately $112.4 million in cash.89 Table of ContentsClass A Convertible Preferred UnitsOn April 21, 2016, we entered into an agreement to issue $200 million of Preferred Units to Oaktree. Oaktree may acquire 16.6 million PreferredUnits at a price of $12.03 per unit as well as 3.6 million warrants, which are subject to certain vesting and exercise terms. We expect to use the net proceedsfrom the issuance of the Preferred Units to repay borrowings outstanding on our Revolving Credit Facility (as hereinafter defined), which may be re-borrowedin the future to fund capital expenditures and for other general partnership purposes. The first closing of this transaction occurred on May 11, 2016 and wereceived gross proceeds of $100 million. We expect the second closing to occur prior to June 30, 2016.Long-Term DebtCredit AgreementWe 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, 2016, ourRevolving Credit Facility had a total capacity of $2.484 billion. Our Revolving Credit Facility has an “accordion” feature that allows us to increase thecapacity by $150 million if new lenders wish to join the syndicate or if current lenders wish to increase their commitments.The Expansion Capital Facility had a total capacity of $1.446 billion for cash borrowings at March 31, 2016. At that date, we had outstandingborrowings of $1.230 billion on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.038 billion for cash borrowings andletters of credit at March 31, 2016. At that date, we had outstanding borrowings of $618.5 million and outstanding letters of credit of $45.4 million on theWorking Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our consolidated balance sheets, although theydecrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a“borrowing base” (as defined in the Credit Agreement), which is calculated based on the value of certain working capital items at any point in time.The commitments under the Credit Agreement expire on November 5, 2018. We have the right to 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.The Credit Agreement is secured by substantially all of our assets. In December 2015, we entered into an agreement with the banks to increase ourmaximum leverage ratio to 4.75 to 1 at any quarter end. At March 31, 2016, our leverage ratio was approximately 3.9 to 1. The Credit Agreement alsospecifies that our interest coverage ratio (as defined in the Credit Agreement) cannot be less than 2.75 to 1 at any quarter end. At March 31, 2016, our interestcoverage ratio was approximately 5.3 to 1.At March 31, 2016, we were in compliance with the covenants under the Credit Agreement.2019 NotesOn 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. During the fourthquarter of fiscal year 2016, we repurchased $11.5 million of our 2019 Notes for an aggregate purchase price of $7.0 million (excluding payments of accruedinterest). As a result, we recorded a gain on the early extinguishment of our 2019 Notes of $4.5 million (net of the write off of debt issuance costs of $0.1million)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 Notesbefore the maturity date, although we would be required to pay a premium for early redemption.At March 31, 2016, we were in compliance with the covenants under the indenture governing the 2019 Notes.2021 NotesOn 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. During the fourth quarter of fiscal year 2016, werepurchased $61.7 million of our 2021 Notes for an aggregate purchase price90 Table of Contentsof $36.4 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2021 Notes of $24.0 million (netof the write off of debt issuance costs of $1.2 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 before the maturity date, although we would be required to pay a premium for early redemption.At March 31, 2016, we were in compliance with the covenants under the indenture governing the 2021 Notes.2022 NotesOn 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. In December 2015,we amended the Note Purchase Agreement to change the covenants to mirror the changes made to the covenants in our Credit Agreement. In addition, weagreed to pay an additional 0.5% per year in interest if our leverage ratio exceeds 4.50 to 1. The 2022 Notes are required to be repaid in semi-annualinstallments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstandingprincipal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of our assets and rank equal in priority withborrowings under the Credit Agreement.At March 31, 2016, we were in compliance with the covenants under the Note Purchase Agreement.For a further discussion of our Revolving Credit Facility and Senior Notes, see Note 8 to our consolidated financial statements included in thisAnnual Report.Revolving Credit BalancesThe following table summarizes our Revolving Credit Facility borrowings: Average BalanceOutstanding LowestBalance HighestBalance (in thousands)Year Ended March 31, 2016: Expansion capital borrowings $1,067,549 $739,500 $1,380,000Working capital borrowings 640,928 469,000 756,000Year Ended March 31, 2015: Expansion capital borrowings $435,752 $114,000 $830,000Working capital borrowings 736,677 339,500 1,046,000TLP credit facility borrowings(from July 1, 2014 through March 31, 2015) 250,346 228,000 259,700Capital ExpendituresThe following table summarizes expansion and maintenance capital expenditures for the periods indicated. This information has been prepared onthe accrual basis, and excludes property, plant and equipment acquired in acquisitions. Capital ExpendituresYear Ended March 31, Expansion (1) Maintenance (2) Total (in thousands)2016 $613,598 42,001 $655,5992015 169,207 40,746 209,9532014 132,948 32,200 165,14891 Table of Contents (1)Includes expansion capital expenditures for TLP of $13.6 million and $3.7 million during the years ended March 31, 2016 and 2015, respectively.(2)Includes maintenance capital expenditures for TLP of $11.6 million and $9.8 million during the years ended March 31, 2016 and 2015, respectively.We currently expect our growth capital expenditures for fiscal year 2017 to be between $200 million and $300 million.AcquisitionsSubsequent to our IPO, we significantly expanded our operations through numerous acquisitions, as described under Part I, Item 1–“Business–Acquisitions.”Cash FlowsThe following table summarizes the sources (uses) of our cash flows for the periods indicated: Year Ended March 31,Cash Flows Provided by (Used in): 2016 2015 2014 (in thousands)Operating activities, before changes in operating assets and liabilities $226,881 $107,599 $243,576Changes in operating assets and liabilities 124,614 154,792 (158,340)Operating activities $351,495 $262,391 $85,236Investing activities (445,327) (1,366,221) (1,455,373)Financing activities 80,705 1,134,693 1,369,016Operating Activities. The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities.Increases in natural gas liquids prices typically reduce our operating cash flows due to higher cash requirements to fund increases in inventories, anddecreases in natural gas liquids prices typically increase our operating cash flows due to lower cash requirements to fund increases 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 and customers pay for natural gas liquids consumed during the heating season months. Weborrow under our Revolving Credit Facility to supplement our operating cash flows as necessary during our first and second fiscal quarters.Investing Activities. Net cash used in investing activities was $445.3 million and $1.4 billion during the years ended March 31, 2016 and 2015,respectively. The decrease in net cash used in investing activities was due primarily to:•a $726.3 million decrease in cash paid for acquisitions during the year ended March 31, 2016 as cash paid for acquisitions during the yearended March 31, 2015 included $580.7 million for the acquisition of TransMontaigne;•a $343.1 million increase due to proceeds received from the sale of the general partner interest in TLP during the year ended March 31, 2016;•a $310.0 million decrease for the purchase of the remaining equity interest in Grand Mesa during the year ended March 31, 2015;•a $59.6 million decrease related to a loan receivable associated with our financing of the construction of a natural gas liquids facility to beutilized by a third party; and•a $24.2 million decrease for the purchase of certain refined product pipeline capacity allocations from other shippers during the year endedMarch 31, 2015.92 Table of ContentsThese decreases in net cash used in investing activities were partially offset by:•an increase in capital expenditures from $203.8 million during the year ended March 31, 2015, $163.0 million of which was expansion capital(of this expansion capital, $3.7 million related to TLP) and $40.8 million of which was maintenance capital (of this maintenance capital, $9.8million related to TLP), to $536.9 million during the year ended March 31, 2016, $494.9 million of which was expansion capital (of thisexpansion capital, $13.6 million related to TLP) and $42.0 million of which was maintenance capital (of this maintenance capital, $11.6 millionrelated to TLP);•a $125.0 million increase due to the purchase of a 37.5% undivided interest in a crude oil pipeline from Colorado to Oklahoma (see “RecentDevelopments” above) during the year ended March 31, 2016; and•a $93.5 million decrease in cash flows from derivatives.Net cash used in investing activities was $1.4 billion and $1.5 billion during the years ended March 31, 2015 and 2014, respectively. The decreasein 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 cash flows from derivatives.These decreases in net cash used in investing activities were partially offset by:•a $310.0 million increase for 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;•an increase in capital expenditures from $165.1 million during the year ended March 31, 2014, $132.9 million of which was expansion capitaland $32.2 million of which was maintenance capital, to $203.8 million during the year ended March 31, 2015, $163.0 million of which wasexpansion capital (of this expansion capital, $3.7 million related to TLP) and $40.8 million of which was maintenance capital (of thismaintenance capital, $9.8 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.Financing Activities. Net cash provided by financing activities was $80.7 million and $1.1 billion during the years ended March 31, 2016 and 2015,respectively. The decrease in net cash provided by financing activities was due primarily to:•$541.1 million in proceeds received from the sale of our common units during the year ended March 31, 2015;•$400.0 million in proceeds received from the issuance of the 2019 Notes during the year ended March 31, 2015;•an $88.0 million increase in distributions paid to our partners and noncontrolling interest owners during the year ended March 31, 2016; and•$43.4 million in repurchases of a portion of our senior notes during the fourth quarter of fiscal year 2016.These decreases in net cash provided by financing activities were partially offset by an increase of $53.2 million in proceeds from other long-termdebt due primarily to equipment financing.Net cash provided by financing activities was $1.1 billion and $1.4 billion during the years ended March 31, 2015 and 2014, respectively. Thedecrease in net cash provided by financing activities was due primarily to:•a $123.8 million increase in distributions paid to our partners and noncontrolling interest owners during the year ended March 31, 2015;93 Table of Contents•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, 2015. To the extent our cash flows fromoperating activities are not sufficient to finance our required distributions to our partners and noncontrolling interest owners, we may be required to increaseborrowings under our Working Capital Facility.The following table summarizes distributions declared during the years ended March 31, 2016, 2015 and 2014:Date Declared Record Date Date Paid AmountPer Unit Amount Paid ToLimited Partners Amount Paid ToGeneral Partner (in thousands) (in thousands)April 25, 2013 May 6, 2013 May 15, 2013 $0.4775 $25,605 $1,189July 25, 2013 August 5, 2013 August 14, 2013 0.4938 31,725 1,739October 23, 2013 November 4, 2013 November 14, 2013 0.5113 35,908 2,491January 24, 2014 February 4, 2014 February 14, 2014 0.5313 42,150 4,283April 24, 2014 May 5, 2014 May 15, 2014 0.5513 43,737 5,754July 24, 2014 August 4, 2014 August 14, 2014 0.5888 52,036 9,481October 24, 2014 November 4, 2014 November 14, 2014 0.6088 53,902 11,141January 26, 2015 February 6, 2015 February 13, 2015 0.6175 54,684 11,860April 24, 2015 May 5, 2015 May 15, 2015 0.6250 59,651 13,446July 23, 2015 August 3, 2015 August 14, 2015 0.6325 66,248 15,483October 22, 2015 November 3, 2015 November 13, 2015 0.6400 67,313 16,277January 21, 2016 February 3, 2016 February 15, 2016 0.6400 67,310 16,279April 21, 2016 May 3, 2016 May 13, 2016 0.3900 40,626 70The following table summarizes distributions declared by TLP after our acquisition of general and limited partner interests in TLP (exclusive of thedistribution declared in July 2014, the proceeds of which we remitted to the former owners of TransMontaigne, pursuant to agreements entered into at thetime of the business combination. On February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLPand began to account for our limited partner investment in TLP using the equity method of accounting.Date Declared Record Date Date Paid AmountPer Unit Amount Paid To NGL Amount Paid ToNoncontrollingInterest Owners (in thousands) (in thousands)October 13, 2014 October 31, 2014 November 7, 2014 $0.6650 $4,010 $8,614January 8, 2015 January 30, 2015 February 6, 2015 0.6650 4,010 8,614April 13, 2015 April 30, 2015 May 7, 2015 0.6650 4,007 8,617July 13, 2015 July 31, 2015 August 7, 2015 0.6650 4,007 8,617October 12, 2015 October 30, 2015 November 6, 2015 0.6650 4,007 8,617January 19, 2016 January 29, 2016 February 8, 2016 0.6700 4,104 8,681Common Unit Repurchase ProgramOn September 10, 2015, the Board of Directors of our general partner authorized a common unit repurchase program pursuant to which we couldrepurchase up to $45 million of our outstanding common units through March 31, 2016 from time to time in the open market or in other privately negotiatedtransactions. During the year ended March 31, 2016, we repurchased 1,623,804 common units for an aggregate price of $17.7 million.94 Table of ContentsContractual ObligationsThe following table summarizes our contractual obligations at March 31, 2016 for our fiscal years ending thereafter: Years Ending March 31, Total 2017 2018 2019 2020 2021 Thereafter (in thousands)Principal payments on long-term debt— Expansion capital borrowings $1,229,500 $— $— $1,229,500 $— $— $—Working capital borrowings 618,500 — — 618,500 — — —2019 Notes 388,467 — — — 388,467 — —2021 Notes 388,289 — — — — — 388,2892022 Notes 250,000 — 25,000 50,000 50,000 50,000 75,000Other long-term debt 61,488 7,899 7,143 6,053 5,621 34,671 101Interest payments on long-term debt — Revolving Credit Facility (1) 149,937 57,668 57,668 34,601 — — —2019 Notes 70,639 20,226 20,165 20,165 10,083 — —2021 Notes 160,731 27,256 26,695 26,695 26,695 26,695 26,6952022 Notes 66,500 16,625 16,209 13,300 9,975 6,650 3,741Other long-term debt 14,257 3,739 3,323 2,908 2,521 1,762 4Letters of credit 45,418 — — 45,418 — — —Future minimum lease payments undernoncancelable operating leases 647,759 136,065 120,723 98,266 87,569 77,821 127,315Future minimum throughput paymentsunder noncancelable agreements (2) 200,734 53,024 53,042 52,250 42,418 — —Construction commitments (3) 126,800 126,800 — — — — —Fixed-price commodity purchasecommitments (4) 50,249 50,047 202 — — — —Index-price commodity purchasecommitments (5) 883,908 685,092 92,891 73,928 31,997 — —Total contractual obligations $5,353,176 $1,184,441 $423,061 $2,271,584 $655,346 $197,599 $621,145 (1)The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at March 31, 2016. See Note 8to our consolidated financial statements included in this Annual Report for additional information on our Credit Agreement.(2)We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthly shippingcapacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity.(3)At March 31, 2016, we had the following construction commitments:•As discussed above, in November 2015, we reached an agreement with Saddlehorn to jointly construct, own and operate the Joint Pipeline. AtMarch 31, 2016, our share of the remaining total construction costs for the Joint Pipeline is approximately $39 million. We expect the Joint Pipelineto be operational beginning in the third quarter of fiscal year 2017.•As part of the Joint Pipeline project, we will have some assets connected to the Joint Pipeline. At March 31, 2016, the remaining costs for theseassets are approximately $80.6 million. We expect these assets to be completed during the third quarter of fiscal year 2017.•In February 2015, we acquired Sawtooth, which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to westernUnited States markets and entered into a construction agreement to expand the storage95 Table of Contentscapacity of the facility. At March 31, 2016, the remaining costs for this project are $7.2 million. We expect this project to be completed by the endof the second quarter of fiscal year 2017.(4) At March 31, 2016, we had the following fixed-price purchase commitments (in thousands): Crude Oil Natural Gas Liquids Value Volume(in barrels) Value Volume(in gallons)2017$41,756 1,077 $8,291 21,5742018— — 202 504Total$41,756 1,077 $8,493 22,078(5) At March 31, 2016, we had the following index-price purchase commitments (in thousands): Crude Oil Natural Gas Liquids Value Volume(in barrels) Value Volume(in gallons)2017$319,761 9,187 $365,331 855,645201892,745 2,640 146 300201973,928 1,825 — —202031,997 1,070 — —Total$518,431 14,722 $365,477 855,945Index prices are based on a forward price curve at March 31, 2016. A theoretical change of $0.10 per gallon in the underlying commodity price atMarch 31, 2016 would result in a change of $85.6 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of$1.00 per barrel in the underlying commodity price at March 31, 2016 would result in a change of $14.7 million in the value of our index-price crude oilpurchase commitments.Sales ContractsWe have entered into product sales contracts for which we expect the parties to physically settle the inventory in future periods. At March 31, 2016,we had the following sales contract volumes (in thousands):Natural gas liquids fixed-price (gallons) 85,162Natural gas liquids index-price (gallons) 312,198Crude oil fixed-price (barrels) 2,107Crude oil index-price (barrels) 18,754Off-Balance Sheet ArrangementsWe 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 LegislationPlease see Part I, Item 1–“Business–Government Regulation–Greenhouse Gas Regulation” for a discussion of proposed environmental legislationand regulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure or outcome ofany future legislation or regulations or the eventual cost we could incur in compliance.Recent Accounting PronouncementsFor a discussion of recent accounting pronouncements that are applicable to us, see Note 2 to our consolidated financial statements included in thisAnnual Report.96 Table of ContentsCritical Accounting PoliciesThe preparation of financial statements and related disclosures in conformity 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 consolidated financial position and results of operations. Theapplication of these accounting policies, which requires subjective or complex judgments regarding estimates and projected outcomes of future events, andchanges in these accounting policies, could have a material effect on our consolidated financial statements.Revenue RecognitionWe record product sales revenues when title to the product transfers to the purchaser, which typically occurs when the purchaser receives theproduct. We record terminaling, transportation, storage, and service revenues when the service is performed, and we record tank and other rental revenuesover the lease term. Several of our terminaling service agreements with throughput customers, allow us to receive the product volume gained resulting fromdifferences between the measurement of product volumes received and distributed at our terminaling facilities. Such differences are due to the inherentvariances in measurement devices and methodology. We record revenues for the net proceeds from the sale of the product gained. Revenues for our watersolutions segment are recognized when we obtain 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. We include amounts billed tocustomers for shipping and handling costs 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 at the same time and in contemplation of each other, we record therevenues for these transactions net of cost of sales.Derivative Financial InstrumentsWe record all derivative financial instrument contracts at fair value in our consolidated balance sheets except for certain contracts that qualify forthe normal purchase and normal sale election. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date;instead, we record the purchase or sale at the contracted value once the delivery occurs.We have not designated any financial instruments as hedges for accounting purposes. All changes in the fair value of our commodity derivativeinstruments that do not qualify as normal purchases and normal sales (whether cash transactions or non-cash mark-to-market adjustments) are reported withincost of sales 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 attempt to reduce our exposure to price fluctuations. We do not enter intosuch contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in marketprices, newly originated transactions, and the timing of settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timingof performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated marketmovements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that thevalue of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss fromnonperformance by suppliers, customers or financial counterparties to a contract. Procedures and limits for managing commodity price risks and credit risksare specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and arereported 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 master netting agreements that allow for offsetting counterparty receivable and payablebalances for certain transactions.Impairment of Long-Lived AssetsWe evaluate the carrying value of our long-lived assets (property, plant and equipment and amortizable intangible assets) for potential impairmentwhen events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flowsfrom the use and eventual disposition of the asset group is less than its carrying value. We compare the carrying value of the long-lived asset to the estimatedundiscounted future cash flows97 Table of Contentsexpected to be generated from that asset. Estimates of future net cash flows include estimating future volumes, future margins or tariff rates, future operatingcosts and other estimates and assumptions consistent with our business plans. If we determine that an asset’s unamortized cost may not be recoverable due toimpairment, we may be required to reduce the carrying value and the subsequent useful life of the asset. Any such write-down of the value and unfavorablechange in the useful life of a long-lived assets would increase costs and expenses at that time.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.Impairment of GoodwillGoodwill 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. For each reporting unit, we perform a qualitative assessment of relevant events andcircumstances about the likelihood of goodwill impairment. If it is deemed more likely than not the fair value of the reporting unit is less than its carryingamount, we calculate the fair value of the reporting unit. Otherwise, further testing is not required. The qualitative assessment is based on reviewing thetotality of several factors, including macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other entityspecific events (for example, changes in management) or other events such as selling or disposing of a reporting unit. The determination of a reporting unit’sfair value is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include (i) discrete financialforecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins, (ii) long-term growth rates for cashflows beyond the discrete forecast period, (iii) appropriate discount rates and (iv) estimates of the cash flow multiples to apply in estimating the market valueof our reporting units. If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, a charge to earnings may berequired to reduce the carrying value of goodwill to its implied fair value. If future results are not consistent with our estimates, we could be exposed to futureimpairment losses that could be material to our results of operations. We monitor the markets for our products and services, in addition to the overall market,to determine if a triggering event occurs that would indicate that the fair value of a reporting unit is less than its carrying value.Asset Retirement ObligationsWe 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 estimates and assumptions are very subjective and can vary over time. Our consolidated balancesheet at March 31, 2016 includes a liability of $5.6 million related to asset retirement obligations, which is reported within other noncurrent liabilities. Wehave contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when theassets are retired. Our liability for asset retirement obligations is discounted to present value. To calculate the liability, we make estimates and assumptionsabout the retirement cost and the timing of retirement. Changes in our assumptions and estimates may occur as a result of the passage of time and theoccurrence of future events.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 EquipmentDepreciation expense is the systematic write-off of the cost of our property, plant and equipment, net of residual or salvage value (if any), to theresults of operations for the quarterly and annual periods during which the assets are used. We depreciate the majority of our property, plant and equipmentusing the straight-line method, which results in our recording depreciation expense evenly over the estimated life of the individual asset. The estimate ofdepreciation expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. When we acquire and place ourproperty, plant and equipment in service, we develop assumptions about the useful economic lives and residual values of such98 Table of Contentsassets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, whichwould change our depreciation expense prospectively. Examples of such circumstances include changes in laws and regulations that limit the estimatedeconomic life of an asset, changes in technology that render an asset obsolete, or changes in expected salvage values.Amortization of Intangible AssetsAmortization expense is the systematic write-off of the cost of our amortizable intangible assets to the results of operations for the quarterly andannual periods during which the assets are used. We amortize the majority of these intangible assets using the straight-line method, which results in ourrecording amortization expense evenly over the estimated life of the individual asset. The estimate of amortization expense requires us to make assumptionsregarding the useful economic lives of our assets. When we acquire intangible assets, we develop assumptions about the useful economic lives 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 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 BottomsTank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost within either noncurrent assets orproperty, plant and equipment on our consolidated balance sheets. We recover tank bottoms when the storage tanks are removed from service. See Note 2 andNote 5 to our consolidated financial statements included in this Annual Report.LinefillWe have entered into long-term shipment commitments for 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. See Note 2 to our consolidated financial statements includedin this Annual Report.Business CombinationsWe record business combinations using the “acquisition method,” in which the assets acquired and liabilities assumed in a business combination attheir acquisition date fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve engaging anindependent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identifyand include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by theacquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. Theestimates also include the fair value of contracts including commodity purchase and sale agreements, storage contracts, and transportation contracts. Theexcess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but is reviewedannually for impairment. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary toidentify and measure the value of the assets acquired and liabilities assumed in a business combination.InventoriesOur 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 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.We are unable to control changes in the market value of these commodities and are unable to determine whether write-downs will be required in futureperiods. In addition, write-downs at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal yearend.99 Table of ContentsEquity-Based CompensationOur general partner has granted certain restricted units to employees and directors under a long-term incentive plan. The restricted units includeawards that vest contingent on the continued service of the recipients through the vesting date (the “Service Awards”). The restricted units also includeawards that are contingent both on the continued service of the recipients through the vesting date and also on the performance of our common units relativeto other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”). The awards may also vest in the event of achange in control, at the discretion of the board of directors.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 estimatedfair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New YorkStock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vestingperiod. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptionsthat a market participant might make about future distributions.We record the expense for each of the tranches of the Performance Awards on a straight-line basis over the period beginning with the grant date andending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of theawards at the balance sheet date. We calculate the fair value of the awards using a Monte Carlo simulation.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 RiskInterest Rate RiskA 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 31,2016, we had $1.8 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.94%. A change in interest rates of 0.125% wouldresult in an increase or decrease of our annual interest expense of $2.3 million, based on borrowings outstanding at March 31, 2016.Commodity Price and Credit RiskOur 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 masternetting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. At March 31, 2016,our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.The crude oil, natural gas liquids, and refined products industries are “margin-based” and “cost-plus” businesses in which gross profits depend onthe differential of sales prices over supply costs. We have no control over market conditions. As a result, our profitability may be impacted by sudden andsignificant changes in the price of crude oil, natural gas liquids, and refined products.100 Table of ContentsWe 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, 2016 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)$(6,163)Crude oil (water solutions segment)(2,656)Propane (liquids segment)963Other products (liquids segment)(296)Refined products (refined products and renewables segment)(24,736)Renewables (refined products and renewables segment)(4,508)Canadian dollars (liquids segment)945Fair ValueWe 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.Item 8. Financial Statements and Supplementary DataOur 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 DisclosureNone.Item 9A. Controls and ProceduresEvaluation of Disclosure Controls and ProceduresWe 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 as of March 31,2016. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31,2016, such disclosure controls and procedures were effective to provide the reasonable assurance described above.101 Table of ContentsManagement’s Report on Internal Control Over Financial ReportingThe 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 of SponsoringOrganizations of the Treadway Commission, or the COSO framework.Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective asof March 31, 2016.Our internal control over financial reporting as of March 31, 2016 has been audited by Grant Thornton LLP, an independent registered publicaccounting firm, as stated in their report, which appears in Part IV, Item 15 - “Exhibits, Financial Statement Schedules” in this Annual Report.Changes in Internal Control Over Financial ReportingThe Partnership had a change in key personnel and controls in the fourth quarter of its 2016 fiscal year. More specifically, the Partnership’s generalpartner hired a new Chief Accounting Officer and a new Chief Financial Officer. These personnel additions (1) changed the design of the Chief AccountingOfficer’s review control over business combination accounting, and (2) added a new and incremental control encompassing the Chief Financial Officerreview of business combination accounting for accuracy and the fair value measurements for reasonableness. Both of these internal control modificationsbegan in the fourth quarter of fiscal 2016. Through execution of these controls over the recording of business combinations that occurred in the fourth quarterof fiscal 2016, the Chief Accounting Officer and Chief Financial Officer identified certain contingent consideration liabilities in connection with the fourthquarter 2016 business combinations, and determined that the Partnership had failed to record similar liabilities for contingent consideration related to certainprevious business combinations that had occurred prior to the fourth quarter of fiscal year 2016. Such liabilities should have been recorded at the acquisitiondate and subsequently revalued to estimated fair value at each reporting period with the offset to current earnings. Based on the determination that thePartnership had not properly accounted for these prior acquisitions, management determined that a material weakness in internal control existed throughDecember 31, 2015, specifically related to the identification and review of accounting for assets acquired and liabilities assumed in business combinations.As described above in “Management’s Report on Internal Control Over Financial Reporting”, the Partnership concluded that its internal control overfinancial reporting was effective as of March 31, 2016 based, in part, on the effectiveness of the changed and new controls implemented in the fourth quarterof fiscal year 2016.Other than changes that have been described above, there have been no changes in our internal controls over financial reporting (as defined in Rule13(a)-15(f) of the Exchange Act) during the three months ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect,our internal controls over financial reporting.Item 9B. Other InformationNone.102 Table of ContentsPART IIIItem 10. Directors, Executive Officers and Corporate GovernanceBoard of Directors of our General PartnerNGL 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.103 Table of ContentsDirectors and Executive OfficersDirectors 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 summarizes information regarding the current directors of our general partner and our executiveofficers. Name Age Position with NGL Energy Holdings LLCH. Michael Krimbill 62 Chief Executive Officer and DirectorRobert W. Karlovich III 39 Chief Financial Officer and TreasurerJames J. Burke 60 President and DirectorShawn W. Coady 54 President and Chief Operating Officer, Retail Division and DirectorVincent J. Osterman 59 President, Eastern Retail Propane Operations and DirectorChristopher Beall 41 DirectorJames M. Collingsworth 61 DirectorStephen L. Cropper 66 DirectorBryan K. Guderian 56 DirectorJames C. Kneale 64 DirectorJohn T. Raymond 45 DirectorPatrick Wade 46 DirectorH. 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 his prior service as a chief financial officer. Mr. Krimbill’s experience serving on other public companyboards is also a valuable asset to our board of directors.Robert W. Karlovich III. Mr. Karlovich was appointed as our Chief Financial Officer in February 2016. Prior to joining NGL, Mr. Karlovich servedas Chief Financial Officer of Targa Pipeline Partners, a subsidiary of Targa Resources Partners, LP, from February 2015 through February 2016, and as SeniorVice President of Commercial and Business Development for Targa Resources Partners LP from November 2015 to February 2016. Mr. Karlovich served invarious roles at Atlas Pipeline Partners, L.P. and its subsidiaries (“APL”) from September 2006 to February 2015 when APL merged with Targa ResourcesPartners, LP. Mr. Karlovich served in various roles at Syntroleum Corporation from February 2004 to September 2006. Prior to that, Mr. Karlovich worked atArthur Andersen LLP and Grant Thornton LLP. Mr. Karlovich is a certified public accountant.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 until NGL’s acquisition of High Sierra in June 2012. From July 2004 to September 2010,Mr. Burke was the Managing Director of High Sierra’s general partner. Mr. Burke, along with three other entrepreneurs, co-founded Petro Source Partners, LP,where he ran six business units throughout the United States and Canada for the company over a 17-year span. Prior to that, Mr. Burke served as Manager ofCrude Oil Acquisitions at Asamera Oil (United States) Inc. from 1981 to 1984. Mr. Burke began his career as a Crude Oil Representative at PermianCorporation, where he worked from 1978 to 1981. Mr. Burke also serves as the Managing Director of Impact Energy Services, LLC.104 Table of ContentsMr. Burke brings valuable executive and operational experience in the crude oil marketing business and water solutions business to the board andprovides expertise in both acquisitions and organic growth strategies.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 Hicksgas LLC, and the membership interests in HicksgasLLC were contributed to us as part of our formation transactions. Dr. Coady was also the President of Hicksgas Gifford, Inc. from March 1989 until themembership interests in the company were contributed to us as part of our formation transactions. Dr. Coady has served as a director for the National PropaneGas Association since 2004 and as a member of the executive committee of the Illinois Propane Gas Association from 2004 to March 2015.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 industry 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 currently serves on the board of directors of Energi Holdings, Inc. and onthe Board of Advisors of the Gaudette Insurance Agency.With his long tenure as President of the Osterman Associated Companies, Mr. Osterman brings valuable executive and operational experience in theretail propane businesses to the board. Mr. Osterman also provides insight into developments and trends in the propane industry through his leadership rolesin industry associations.Christopher Beall. Mr. Beall has served on the board of directors of our general partner since May 2016. Mr. Beall is a Managing Director and Co-Portfolio Manager of Oaktree Capital Management L.P.’s (“Oaktree”) Infrastructure Investing Strategy. Mr. Beall has over 16 years of experience in directinvestments, investment banking and finance. Mr. Beall served as a key investment professional for Highstar Capital for ten years prior to joining Oaktree in2014 and continues to serve as a Partner of Highstar Capital for certain legal funds not managed by Oaktree. Prior to joining Highstar Capital in 2004, heworked in the Global Natural Resources Group at Lehman Brothers, Inc., and in operations and engineering at Koch Pipeline Company, a natural gastransmission pipeline owned by Koch Industries, Inc. Mr. Beall currently serves on the board of directors of Northstar Transloading, ADS Waste Holding, Inc.,Ports America Companies, Wespac Midstream and Amtrak.Mr. Beall brings considerable experience in the energy business and in financial markets. As a director for other public companies, Mr. Beall alsoprovides cross board experience.James M. Collingsworth. Mr. Collingsworth has served on the board of directors of our general partner since January 2015. Mr. Collingsworthpreviously served as a Senior Vice President of the general partner of Enterprise Products Partners L.P. from November 2001 through September 2012. Prior tothat, Mr. Collingsworth served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991to 2001 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-depth industry experience to the Partnership. Mr. Collingsworth has worked in all facets of the midstreamand 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 Finance105 Table of ContentsCorp., a subsidiary of Dollar Thrifty 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 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.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 also currently serves 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.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 Rocky Mountains. From 2005 to 2007, Mr. Wade was a ManagingDirector at Bear Energy LP, responsible for investments in natural gas midstream infrastructure, as well as contracting for a diverse portfolio of natural gasstorage capacity. In 2008, Mr. Wade joined EMG as a Managing Director in the Houston office. EMG is the management company for a series of specializedprivate equity funds. EMG focuses on investing across various facets of the global natural resource industry including the upstream and midstream segmentsof the energy complex. EMG is the managing partner of EMG NGL HC LLC. Mr. Wade’s primary focus is making direct investments across the naturalresources industry. Mr. Wade served as a director of MarkWest Liberty Midstream & Resources from 2009 through 2011. In addition, Mr. Wade currentlyserves on the board of directors of Medallion Midstream, L.L.C., Ferus Inc., and Lodestar Energy Group, LLC.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.106 Table of ContentsDirector Appointment RightsThe 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 John T.Raymond 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 OversightThe 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 CommitteeThe 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;•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 and Exchange Act rules.107 Table of ContentsCompensation CommitteeThe 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 ComplianceSection 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who own more than 10% of a registeredclass of our equity securities, to file initial reports of beneficial ownership and reports of changes in beneficial ownership of our common units and otherequity securities with the SEC. Directors, officers and greater than 10% unitholders are required by SEC regulations to furnish to us copies of allSection 16(a) forms they file with the SEC.To our knowledge, based solely on a review of the copies of such reports furnished to us and written representations by our directors and officers, webelieve that all reporting obligations of our general partner’s directors and officers and our greater than 10% unitholders under Section 16(a) were satisfiedduring the year ended March 31, 2016, except for the purchase of stock by Shawn W. Coady on August 17, 2015 and by James Collingsworth on February12, 2016 which were both late by one day. Also, a Form 3 for Robert W. Karlovich III, who became an executive officer on February 22, 2016, was not fileduntil March 9, 2016. Mr. Karlovich’s receipt of a grant of restricted common units on February 22, 2016 was not reported on a Form 4 until March 10, 2016.Corporate GovernanceThe 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 DirectorsAt 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.108 Table of ContentsUnitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board, anyindependent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of ourSecretary at the following address: Name of the Director(s), c/o Secretary, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma74136. Communications are distributed to the board, committee, or director as appropriate, depending on the facts and circumstances outlined in thecommunication.Item 11. Executive CompensationCompensation Discussion and AnalysisThe year “2016” in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2016.IntroductionThe 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 2016 were:•H. Michael Krimbill–Chief Executive Officer•Robert W. Karlovich III–Chief Financial Officer (effective February 22, 2016)•James J. Burke–President•Shawn W. Coady–President and Chief Operating Officer, Retail Division•Vincent J. Osterman–President, Eastern Retail Propane Operations•Atanas H. Atanasov–Chief Financial Officer and Treasurer (resigned effective February 5, 2016)Compensation PhilosophyOur 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.109 Table of ContentsRecent AchievementsOur compensation structure is designed to reward our officers for achieving above-market returns for our unitholders. Our achievements during theyear ended March 31, 2016 included the following:•Entered into an agreement with Saddlehorn Pipeline Company, LLC to combine pipeline projects to transport crude oil from Weld County,Colorado to Cushing Oklahoma, of which we will own a 37.5% undivided interest in the pipeline; and•We sold our general partner interest in TLP for $350 million.Compensation Highlights•We paid no cash bonuses to our named executive officers during fiscal year 2016.•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 unitsexceeds the median returns for a specified peer group over specified periods of time. Factors Enhancing Alignment with Unitholder Interests•Majority of officer pay is at risk incentive compensation 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 2016, 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 year2016:◦PM&P did not provide any services to the Partnership or management other than compensation consulting services requested by or with theapproval of the compensation committee;◦PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or humanresource outsourcing;◦PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and procedures designed toensure independence;◦Fees paid to PM&P by the Partnership during fiscal year 2016 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 compensation committeemembers;110 Table of Contents◦None of the PM&P consultants working on Partnership matters (or any consultants at PM&P) had any business or personal relationship withany 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 2016 compensation program.Elements of Executive CompensationAs 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. The following table summarizes the primary elements of compensation in our executivecompensation program: Objective SupportedElement Primary Purpose How Amount Determined Attract &Retain Motivate &Pay forPerformance UnitholderAlignment Base Salary ž Fixed income to compensateexecutive officers for their level ofresponsibility, expertise andexperience ž Based on competition in themarketplace for executive talent andabilities X Cash BonusAwards ž Rewards achievement of specificannual financial and operationalperformance goals ž Based on the named executiveofficer’s relative contribution toachieving or exceeding annual goals X X X ž Recognizes individualcontributions to our performance Long-TermEquityIncentiveAwards ž Motivates and rewards theachievement of long-termperformance goals, includingincreasing the market price of ourcommon units and the quarterlydistributions to our unitholders ž Based on the named executiveofficer’s expected contribution tolong-term performance goals X X X ž Provides a forfeitable long-termincentive to encourage executiveretention Base SalaryThe 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 of111 Table of ContentsDirectors increased Mr. Krimbill’s salary to $350,000, in consideration of the fact that his salary was low relative to the benchmark peer group(and remains below the 25th percentile of the peer group).•Mr. Karlovich’s base salary of $400,000 was negotiated prior to his joining our management team in February 2016.•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 that his salary is higher relative to the benchmark peer groupthan the other named executive officers (his current salary is close to the 50th 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.•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.Cash Bonus AwardsNone of the named executive officers is subject to a formal cash bonus plan, and any cash bonuses are at the discretion of the CompensationCommittee or the Board of Directors, (in the case of Mr. Krimbill) or the Compensation Committee (in the case of the other named executive officers).Long-Term Equity Incentive AwardsCertain 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”). The following table summarizes grants of Service Award units granted, vested and/or forfeited during fiscal year2016 with respect to the named executive officers: Unvested Unitsat March 31, 2015 Units Granted Units Vested Units Forfeited Unvested Unitsat March 31, 2016H. Michael Krimbill (1) — 213,573 (71,191) — 142,382Robert W. Karlovich III (2) — 75,000 — — 75,000James J. Burke (3) 45,000 25,000 (25,000) — 45,000Shawn W. Coady (3) 45,000 25,000 (25,000) — 45,000Vincent J. Osterman (3) 45,000 25,000 (25,000) — 45,000Atanas H. Atanasov (4) 36,000 8,333 (20,333) (24,000) — (1)Mr. Krimbill was granted 213,573 Service Awards on April 23, 2015.(2)Mr. Karlovich was granted 75,000 Service Awards on February 22, 2016.(3)Mr. Burke, Dr. Coady and Mr. Osterman were each granted 10,000 Service Awards on July 1, 2015 and 15,000 Service Awards on February 18, 2016.(4)Mr. Atanasov was granted 8,333 Service Awards on July 1, 2015 and forfeited all outstanding Service Awards upon his resignation from employment.The number of Service Award units granted to Mr. Krimbill was calculated based on the median value of equity award units granted to chiefexecutive officers in the benchmark peer group.112 Table of ContentsThe Service Award units granted in July 2015 were intended as discretionary bonuses for performance during fiscal year 2015.The Service Award units granted to Mr. Karlovich were negotiated prior to his joining our management team in February 2016.The Service Award units granted to in February 2016 were intended for retention.The following table summarizes the vesting dates of the unvested Service Award units at March 31, 2016: Service Award Units by Vesting Date TotalUnvested Units July 1, 2016 July 1, 2017 July 1, 2018 at March 31, 2016H. Michael Krimbill 71,191 71,191 — 142,382Robert W. Karlovich III 25,000 25,000 25,000 75,000James J. Burke 30,000 15,000 — 45,000Shawn W. Coady 30,000 15,000 — 45,000Vincent J. Osterman 30,000 15,000 — 45,000During 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 Performance Awards represent hypothetical units and are not actual common units. The Performance Awards settle in common units rather thancash. The right to receive common units with respect to the Performance Awards depends on (i) the level of total unitholder return attained by us over theapplicable performance periods, as measured against our peer group and as described in the Performance Unit Agreement, provided that the number ofcommon units that may be earned in respect of the Performance Awards will either be 0% of the Performance Awards, for performance at anything less thanthe 50th percentile of the performance peer group, or in a range of 50% to 200% of the Performance Awards, for performance from the 50th percentile to the90th percentile of the performance peer group over the same performance period (such number of earned Performance Awards are referred to, and defined inthe Performance Unit Agreement, as, "Earned Performance Awards"), and (ii) the satisfaction of a continued service requirement.The following table summarizes the maximum number of units that could vest on the Performance Awards granted to each named executive officer: Maximum Performance Award Unitsby Vesting Date July 1, 2015 July 1, 2016 July 1, 2017 TotalH. Michael Krimbill 142,382 142,382 142,382 427,146Atanas H. Atanasov 24,000 24,000 24,000 72,000James J. Burke 30,000 30,000 30,000 90,000Shawn W. Coady 30,000 30,000 30,000 90,000Vincent J. Osterman 30,000 30,000 30,000 90,000The 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, 2015 July 1, 2012 through June 30, 2015July 1, 2016 July 1, 2013 through June 30, 2016July 1, 2017 July 1, 2014 through June 30, 2017 113 Table of ContentsThe following table summarizes the percentage of the maximum Performance Award units that will vest depending on the percentage of entities inthe Index that NGL outperforms: Our Relative TUR Percentile Ranking Payout (% of Target Units)Less than 50th percentile —%Between the 50th and 75th percentile 50%–100%Between the 75th and 90th percentile 100%–200%Above the 90% percentile 200%The Performance Award units were granted 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.Severance and Change in Control BenefitsWe 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 at March 31, 2016” table below.401(k) PlanWe 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 a maximum employer matching contribution equal to 3.5% of the employee’s eligible compensation (as defined in the plan) that isnot in excess of 6% of the employee’s eligible compensation (subject to annual Internal Revenue Service contribution limits). Our matching contributionsprior to January 1, 2015 vest over 5 years and, effective January 1, 2015, our matching contributions vest over 2 years.Other BenefitsWe 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 OfficersCertain 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 2016 Compensation ProgramDuring fiscal year 2016, 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; and114 Table of Contents•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 LP Enbridge Energy Partners, L.P. Crosstex Energy LPFerrellgas Partners LP NuStar Energy L.P. DCP Midstream Partners LPStar Gas Partners, L.P. Targa Resources Partners LP Martin Midstream Partners LPSuburban Propane Partners, L.P. Buckeye Partners, L.P. Regency Energy Partners LPONEOK Partners, L.P. Genesis Energy LP Boardwalk Pipeline Partners, LPKinder Morgan Energy Partners, L.P. Crestwood Midstream Partners LP Western 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 2016 and in determining the number of Service Award and Performance Award units to grant to the namedexecutive officers.Employment AgreementsWe do not have employment agreements with any of our named executive officers.Deductibility of CompensationWe 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 ReportThe Compensation Committee of the board of directors of our general partner has reviewed and discussed the Compensation Discussion andAnalysis set forth above with management. Based on this review and discussion, the Compensation Committee recommended to the board of directors of ourgeneral partner 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. KnealeRelation of Compensation Policies and Practices to Risk ManagementOur 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 ParticipationDuring fiscal year 2016, 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 2016. Shawn W. Coady is an executive officer and a memberof the board of directors of our general partner. Dr. Coady also serves on the board of directors of HOH, a family-owned company, and in this capacityDr. Coady participates in the compensation setting process of the HOH board of directors.115 Table of ContentsSummary Compensation Table for 2016The following table summarizes the compensation earned by our named executive officers for fiscal years 2014 through 2016. Name and Position FiscalYear Salary($) Bonus (1)($) RestrictedUnitAwards (Serviceand PerformanceAwards) (2)($) All OtherCompensation (3)($) Total($)H. Michael Krimbill 2016 350,000 — 8,319,437 7,539 8,676,976Chief Executive Officer 2015 292,500 — — 9,319 301,819 2014 117,693 475,000 — 6,493 599,186 Robert W. Karlovich III 2016 30,769 — 419,250 — 450,019Chief Financial Officer James J. Burke (4) 2016 375,000 — 1,047,241 27,898 1,450,139President 2015 381,750 — 602,270 26,467 1,010,487 2014 367,385 450,000 — 24,651 842,036 Shawn W. Coady 2016 315,000 — 1,047,241 9,329 1,371,570President and Chief Operating 2015 311,250 — 1,331,501 19,153 1,661,904Officer, Retail Division 2014 300,000 200,000 — 19,630 519,630 Vincent J. Osterman (5) 2016 250,000 — 1,047,241 30,906 1,328,147President, Eastern Retail 2015 250,000 — 1,331,501 31,763 1,613,264Propane Operations Atanas H. Atanasov (6) 2016 265,385 50,000 752,755 8,885 1,077,025Former Chief Financial Officer 2015 287,500 — 864,664 9,346 1,161,510 2014 232,500 195,000 259,696 7,038 694,234 (1)Amounts for fiscal year 2014 include discretionary bonuses paid in fiscal year 2014 based on contributions of the individuals since the time they joinedthe 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 common units on the grantdates, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lackof distribution rights during the vesting period was estimated using the value of the most recent distribution prior to the grant date and assumptions thata market participant might make about future distribution growth. This calculation of fair value is consistent with the provisions of AccountingStandards Codification 718 Stock Compensation. The following table summarizes these amounts:116 Table of ContentsName Service AwardGrant DateFair Value Performance AwardGrant DateFair Value TotalGrant DateFair Value Performance Awardsat Maximum ValueH. Michael Krimbill $4,624,567 $3,694,870 $8,319,437 $7,389,740Robert W. Karlovich III 419,250 — 419,250 —James J. Burke 413,050 650,591 1,063,641 1,301,181Shawn W. Coady 413,050 650,591 1,063,641 1,301,181Vincent J. Osterman 413,050 650,591 1,063,641 1,301,181Atanas H. Atanasov 245,949 520,472 766,421 1,040,945(3)The amounts in this column include matching contributions to our 401(k) plan. Amounts for Mr. Burke include a club membership and a car allowance.Amounts for Dr. Coady include the incremental cost of the use of a company car, including depreciation, maintenance, insurance, and fuel. Amounts forMr. Osterman include propane provided to him and to members of his family (valued for this purpose at the cost of the propane to NGL). The followingtable summarizes these amounts:Name FiscalYear 401(k)Match CarAllowance ClubMembership Propane Total OtherCompensationJames J. Burke 2016 $10,774 $9,000 $8,124 $— $27,898 2015 9,343 9,000 8,124 — 26,467 2014 7,527 9,000 8,124 — 24,651 Shawn W. Coady 2016 9,329 — — — 9,329 2015 9,796 9,357 — — 19,153 2014 8,750 10,880 — — 19,630 Vincent J. Osterman 2016 4,038 — — 26,868 30,906 2015 18,468 — — 13,295 31,763(4)Mr. Burke joined our management team upon completion of our merger with High Sierra on June 19, 2012.(5)Mr. Osterman was not a named executive officer prior to fiscal year 2015.(6)Mr. Atanasov resigned as Chief Financial Officer effective February 5, 2016.Restricted Unit AwardsDuring fiscal year 2016, the Committee granted awards for which units vest at specified dates, contingent only on the continued service of therecipient through the service date (the “Service Awards”) and awards that vest at specific dates, contingent on both the performance of our common unitsrelative to the performance of other entities and on the continued service of the recipient through the vesting (the “Performance Units”).117 Table of Contents2016 Grants of Plan Based Awards TableThe following table summarizes the number of restricted Service and Performance Award units granted to our named executive officers, and theirgrant date fair values: Estimated Future Payouts Under PerformanceAwards (1) Name Grant Date Total Number ofService Award Units Threshold(#) 50% Target(#) 100% Maximum(#) 200% Grant DateFair Value ofService Award Units($)(2)(3)H. Michael Krimbill April 23, 2015 213,573 4,624,567 April 23, 2015 106,786 213,573 427,146 3,694,870Robert W. Karlovich III February 22, 2016 75,000 419,250James J. Burke April 17, 2015 22,500 45,000 90,000 650,591 July 1, 2015 10,000 295,150 February 18, 2016 15,000 117,900Shawn W. Coady April 17, 2015 22,500 45,000 90,000 650,591 July 1, 2015 10,000 295,150 February 18, 2016 15,000 117,900Vincent J. Osterman April 17, 2015 22,500 45,000 90,000 650,591 July 1, 2015 10,000 295,150 February 18, 2016 15,000 117,900Atanas H. Atanasov April 17, 2015 18,000 36,000 72,000 520,472 July 1, 2015 8,333 245,949 (1)Amounts reported in the (a) “Threshold” column reflect the threshold number of Performance Awards (at 50% of target) that may be earned (assuming arelative TUR at the 50th percentile), (b) “Target” column reflect the target number of performance awards, or 100%, that may be earned (assuming arelative TUR at the 75th percentile) and (c) “Maximum” column reflect 200% of the target performance awards that may be earned (assuming a relativeTUR greater than the 90th percentile). The number of common units actually received by a named executive officer with respect to a Performance Awardmay vary based on the Partnership’s relative TUP as compared to the TUR of the performance peer group. The Performance Awards are described aboveunder “Long-Term Equity Incentive Awards” in the Compensation Discussion and Analysis.(2)The disclosure reflects the aggregate grant date fair value of the Performance Awards, computed in accordance with FASB ASC Topic 718 based onprobably achievement of the performance conditions, which is consistent with the estimate of aggregate compensation to be recognized over the serviceperiod, excluding the effect of estimated forfeitures.(3)The fair value of the restricted Service Award units shown in the table above were calculated based on the closing market price of our common units onthe 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.118 Table of ContentsOutstanding Equity Awards at March 31, 2016The following table summarizes the number of unvested Service Award and Performance Awards outstanding and their fair values at March 31,2016: Service Awards Performance Awards Number of UnitsThat Have NotYet Vested Market Value of Units thatHave Not Vested Number of UnitsThat Have NotYet Vested Market Value of Units thatHave Not VestedName #(1) ($)(2) #(3) ($)(2)H. Michael Krimbill 142,382 1,070,713 142,382 1,070,713Robert W. Karlovich III 75,000 564,000 — —James J. Burke 45,000 338,400 30,000 225,600Shawn W. Coady 45,000 338,400 30,000 225,600Vincent J. Osterman 45,000 338,400 30,000 225,600Atanas H. Atanasov (4) N/A N/A N/A N/A (1)Reflects Service Awards that have not vested and are held by each named executive officer.(2)Calculated based on the closing market price of our common units at March 31, 2016 of $7.52. No adjustments were made to reflect the fact that therestricted units are not entitled to distributions during the vesting period.(3)Reflects the target number of Performance Awards granted to each named executive officer that have not vested. Vesting of the Performance Awards arecontingent upon our relative TUR as measured against the performance peer group and satisfaction of a continued service requirement.(4)Mr. Atanasov resigned effective February 5, 2016 resulting in the forfeiture of his Service Awards and Performance Awards. As a result, Mr. Atanasov didnot have any outstanding equity awards as of March 31, 2016.2016 Units VestedDuring fiscal year 2016, certain of the restricted Service Award units and Performance Award units vested. The following table summarizes the valueof the awards on the vesting date which was calculated based of the closing market price per common unit on the vesting dates. Service Awards Performance AwardsName Number of UnitsAcquired on Vesting Value Realizedon Vesting($) Number of UnitsAcquired on Vesting Value Realizedon Vesting($)H. Michael Krimbill 71,191 2,174,885 108,014 3,299,828Robert W. Karlovich III — — — —James J. Burke 25,000 717,100 22,759 695,287Shawn W. Coady 25,000 717,100 22,759 695,287Vincent J. Osterman 25,000 717,100 22,759 695,287Atanas H. Atanasov 20,333 582,300 18,207 556,224119 Table of ContentsUpon vesting, certain of the named executive officers elected for us to remit payments to taxing authorities in lieu of issuing common units. Thefollowing table summarizes the number of common units issued and the number of common units withheld for taxes:Name Number of UnitsIssued Number of UnitsWithheld TotalH. Michael Krimbill 128,226 50,979 179,205James J. Burke 28,357 19,402 47,759Shawn W. Coady 27,679 20,080 47,759Vincent J. Osterman 26,805 20,954 47,759Atanas H. Atanasov 24,468 14,072 38,540Subsequent to vesting, regularly-scheduled distributions were paid on the common units. The following table summarizes the distributions paidduring fiscal year 2015 on the common units that vested and were issued during fiscal year 2016:Name DistributionsH. Michael Krimbill $245,232James J. Burke 50,854Shawn W. Coady 49,502Vincent J. Osterman 47,919Atanas H. Atanasov 44,012Director CompensationOfficers 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 $5,000 for each member of the audit committee other than the chairman.In addition, each director who is not an officer or an employee of our general partner has been granted awards of restricted units. In April 2015, suchdirectors were granted 15,000 restricted units that vest in tranches of 5,000 units each on July 1, 2015, July 1, 2016, and July 1, 2017.All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Eachdirector is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.Director Compensation for Fiscal Year 2016The following table summarizes the compensation earned during fiscal year 2016 by each director who is not an officer or employee of our generalpartner or its affiliates:Name Fees Earned orPaid in Cash($) Restricted UnitAwards($) Total($)James M. Collingsworth 70,000 324,800 394,800Stephen L. Cropper 75,000 324,800 399,800Bryan K. Guderian 65,000 324,800 389,800James C. Kneale 70,000 324,800 394,800During fiscal year 2016, a tranche of 5,000 units vested for each of these directors. Subsequent to the vesting, these individuals receiveddistributions of $1.91 on each of the vested units.120 Table of ContentsAs of March 31, 2016, each of the directors listed in the table above has 10,000 unvested restricted units.Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder MattersSecurity Ownership of Certain Beneficial Owners and ManagementThe following table summarizes the beneficial ownership, as of May 20, 2016 of our common units by:•each person or group of persons known by us to be a beneficial owner of more than 5% of our outstanding common units;•each director of our general partner;•each named executive officer of our general partner; and•all directors and executive officers of our general partner as a group.Beneficial Owners Common UnitsBeneficiallyOwned Percentage ofCommon UnitsBeneficiallyOwned (1)5% or greater unitholders (other than officers and directors): Oppenheimer Funds, Inc. (2) 10,745,300 10.32%Magnum NGL HoldCo LLC (3) 7,396,973 7.10%ALPS Advisors, Inc. (4) 7,202,476 6.91%Salient Capital Advisors, LLC (5) 6,286,363 6.03% Directors and named executive officers: Atanas H. Atanasov 54,189 *James J. Burke (6) 324,642 *Shawn W. Coady (7) 2,531,910 2.43%James M. Collingsworth (8) 46,750 *Stephen L. Cropper (9) 35,000 *Bryan K. Guderian 32,500 *Robert W. Karlovich III 25,000 *James C. Kneale (10) 32,000 *H. Michael Krimbill (11) 1,877,820 1.87%Vincent J. Osterman (12) 3,972,900 3.81%John T. Raymond (13) 176,634 *Patrick Wade — —All directors and executive officers as a group (11 persons) (14) 9,109,345 8.74% * Less than 1.0%(1)Based on 104,169,573 common units outstanding at May 23, 2016. (2)The mailing address for OppenheimerFunds, Inc. is 225 Liberty Street, New York, NY 10281. OppenheimerFunds, Inc. reported shared voting anddispositive power with respect to all common units beneficially owned. This information related to OppenheimerFunds, Inc. is based upon itsSchedule 13G/A filed with the SEC on April 8, 2016. (3)The mailing address for Magnum NGL HoldCo LLC is 2603 Augusta, Suite 900, Houston, TX 77057. Magnum NGL HoldCo LLC reported sharedvoting and dispositive power with respect to all common units beneficially owned. This information related to Magnum NGL HoldCo LLC is basedupon its Schedule 13G filed with the SEC on February 27, 2015. (4)The mailing address for ALPS Advisors, Inc. is 1290 Broadway, Suite 1100, Denver, CO 80203. ALPS Advisors, Inc. reported shared voting anddispositive power with respect to all common units beneficially owned. This information related to ALPS Advisors, Inc. is based upon its Schedule 13Gfiled with the SEC on February 3, 2016. 121 Table of Contents(5)The mailing address for Salient Capital Advisors, LLC is 4265 San Felipe, 8th Floor, Houston, TX 77027. Salient Capital Advisors, LLC reported sharedvoting and dispositive power with respect to all common units beneficially owned. This information related to Salient Capital Advisors, LLC is basedupon its Schedule 13G filed with the SEC on January 12, 2016. (6)Mr. Burke owns 290,770 of these common units which includes 30,000 units that will vest on July 1, 2016, which were reported on Mr. Burke’s mostrecent Form 4, but does not include 15,000 unvested units which were reported on Mr. Burke’s most recent Form 4. Impact Development, LLC owns33,872 of these common units. Impact Development, LLC is solely owned by James J. Burke, who may be deemed to have sole voting and investmentpower over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. Impact Development, LLC alsoowns a 2.87% interest in our general partner.(7)Dr. Shawn W. Coady owns 52,019 of these common units which includes 30,000 units that will vest on July 1, 2016, which were reported on Dr.Coady’s most recent Form 4. SWC Family Partnership LP owns 2,320,391 of these common units. SWC Family Partnership LP is solely owned by SWCGeneral Partner, LLC, of which Dr. Coady is the sole partner. Dr. Coady may be deemed to have sole voting and investment power over these units, butdisclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady Irrevocable Insurance Trust,which was established for the benefit of Shawn W. Coady’s children, owns 135,000 of these common units. Dr. Coady may be deemed to have solevoting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The TaraNicole Coady Trust II, of which the reporting person is the trustee, owns 12,250 common units. The Colleen Blair Coady Trust, of which the reportingperson is the trustee, owns 12,250 common units. Dr. Coady also owns a 12.27% interest in our general partner through Coady Enterprises, LLC, ofwhich he owns 100% of the membership interests. (8)Mr. Collingsworth owns 44,500 of these common units which includes 5,000 units that will vest on July 1, 2016, which were reported on Mr.Collingsworth’s most recent Form 4, but does not include 5,000 unvested units which were reported on Mr. Collingworth’s most recent Form 4. Mr.Collingsworth holds 2,000 of these common units jointly with his spouse, Cindy Collingsworth. Cindy Collingsworth and her sister jointly own 2,250of these common units.(9)Mr. Cropper owns 10,000 of these common units which includes 5,000 units that will vest on July 1, 2016, which were reported on Mr. Cropper’s mostrecent Form 4, but does not include 5,000 unvested units which were reported on Mr. Cropper’s most recent Form 4. The Donna L. Cropper LivingTrust, of which Stephen L. Cropper and his spouse, Donna L. Cropper, are the trustees, owns 25,000 of these common units.(10)Mr. Kneale owns 5,000 of these common units which includes 5,000 units that will vest on July 1, 2016, which were reported on Mr. Kneale’s mostrecent Form 4, but does not include 5,000 unvested units which were reported on Mr. Kneale’s most recent Form 4. The Suzanne and Jim Kneale LivingTrust, of whom Mr. Kneale and his wife are trustees, owns 27,000 of these common units.(11)Mr. H. Michael Krimbill owns 489,417 of these common units which includes 71,191 units that will vest on July 1, 2016, which were reported on Mr.Krimbill’s most recent Form 4, but does not include 71,191 unvested units which were reported on Mr. Krimbill’s most recent Form 4. Krim2010, LLCowns 904,484 of these common units. Krimbill Enterprises LP, H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06% ofKrim2010, LLC, respectively. Krimbill Enterprises LP owns 120,000 of these common units. Krimbill Enterprises LP is controlled by H. MichaelKrimbill via his ownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to have sole voting and investmentpower over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. KrimGP2010 LLC owns 363,555of these common units. KrimGP2010 LLC is solely owned by H. Michael Krimbill. H. Michael Krimbill may be deemed to have sole voting andinvestment power over these units. H. Michael Krimbill also owns a 14.81% interest in our general partner through KrimGP2010, LLC, of which heowns 100% of the membership interests and Krimbill Capital Group, LLC, which is owned 100% by the H. Michael Krimbill Revocable Trust.(12)Mr. Osterman owns 118,263 of these common units which includes 30,000 units that will vest on July 1, 2016, which were reported on Mr. Osterman’smost recent Form 4. The remaining common units are owned by AO Energy, Inc. (110,587 common units), E. Osterman, Inc. (394,350 common units),E. Osterman Gas Services, Inc. (301,700 common units), E. Osterman Propane, Inc. (669,300 common units), Milford Propane, Inc. (559,784 commonunits), Osterman Family Foundation (122,016 common units), Osterman Propane, Inc. (1,445,850 common units), Propane Gas, Inc. (36,450 commonunits) and Saveway Propane Gas Service, Inc. (214,600 common units). Each of these holding entities may be deemed to have sole voting andinvestment power over its own common units and Propane Gas, LLC, as sole shareholder of Propane Gas, Inc., may be deemed to have sole voting andinvestment power over those common units. Vincent J. Osterman is a director, executive officer and shareholder or member of each of these entities andmay be deemed to have sole voting and investment power over 787,563 common units and shared voting and investment power122 Table of Contents(with his father, Ernest Osterman) over 3,185,337 common units, but disclaims beneficial ownership except to the extent of his pecuniary interesttherein. Vincent J. Osterman also owns a 1.65% interest in our general partner through VE Properties XI LLC.(13)EMG NGL HC, LLC owns all of the 176,634 common units. John T. Raymond is the Chief Executive Officer and Managing Partner of NGP MR GPLLC, the general partner of NGP MR, LP, the general partner of NGP Midstream & Resources, LLC, a member holding a majority interest in EMG NGLHC LLC. John T. Raymond may be deemed to have shared voting and investment power over these units, but disclaims beneficial ownership except tothe extent of his pecuniary interest therein. EMG I NGL GP Holdings, LLC, an affiliate of EMG NGL HC LLC, owns a 5.73% interest in our generalpartner. EMG II NGL GP Holdings, LLC, an affiliate of EMG NGL HC LLC, owns a 5.36% interest in our general partner.(14)The directors and executive officers of our general partner also collectively own a 48.11% 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.Securities Authorized for Issuance Under Equity Compensation PlanThe following table summarizes information regarding the securities that may be issued under the LTIP at March 31, 2016. Number of Securities to beIssued upon Exercise ofOutstanding Options,Warrants and Rights Weighted-averageExercise Price ofOutstanding Options,Warrants and Rights Number of SecuritiesRemaining Available forFuture Issuances UnderEquity Compensation Plans(Excluding SecuritiesReflected in Column (a))Plan Category (a) (b) (c)(1)Equity Compensation Plans Approved bySecurity Holders — — —Equity Compensation Plans Not Approvedby Security Holders (2) 2,297,132 — 4,640,927Total 2,297,132 — 4,640,927 (1)The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of our issued and outstanding common units.The maximum number of common units deliverable under the LTIP automatically increases to 10% of the issued and outstanding common unitsimmediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by alesser amount.(2)Our general partner adopted the LTIP in connection with the completion of our initial public offering (“IPO”) in May 2011. The adoption of the LTIP didnot require the approval of our unitholders.Item 13. Certain Relationships and Related Transactions, and Director IndependenceOur directors, executive officers, and greater than 5% unitholders collectively own an aggregate of 40,740,457 common units, representing anaggregate 38.70% 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 AffiliatesOur 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 and123 Table of Contentspayments were determined by and among affiliated entities before our IPO and, consequently, are not the result of arm’s length negotiations.Operation Stage Distributions of available cash to our directors, officers, and greaterthan 5% owners and our general partner We generally make cash distributions 99.9% to our unitholders pro rata,including our directors, officers, and greater than 5% owners as the holders ofan aggregate 40,740,457 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 2016 ($0.39 per unit), our general partner would receive an annualdistribution of $0.3 million on its general partner interest and incentivedistribution rights, and our directors, officers, and greater than 5% ownerswould receive an aggregate annual distribution of $72.2 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 affiliates Our general partner and its affiliates do not receive any management fee orother compensation for the management of our business and affairs, but theyare reimbursed for all expenses that they incur on our behalf, includinggeneral and administrative expenses. As the sole purpose of the generalpartner is to act as our general partner, substantially all of the expenses of ourgeneral partner are incurred on our behalf and reimbursed by us or oursubsidiaries. Our general partner determines the amount of these expenses. Withdrawal or removal of our general partner If 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 convertedinto common units, in each case for an amount equal to the fair market valueof those interests. Liquidation Stage Liquidation Upon our liquidation, our partners, including our general partner, will beentitled to receive liquidating distributions according to their respectivecapital account balances.Transactions With Related PersonsSemGroupSemGroup 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, respectively, in our consolidated statements of operations (certain of the purchases and sales thatwere entered into in contemplation of each other are recorded on a net basis within revenues in our consolidated statement of operations). We also lease crudeoil storage from SemGroup. The following table summarizes transactions with SemGroup for the year ended March 31, 2016 (in thousands):Sales to SemGroup$109,557Purchases from SemGroup117,538124 Table of ContentsWPXBryan K. 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). The following table summarizes transactions with WPX for the year ended March 31, 2016 (in thousands):Sales to WPX$101,052Purchases from WPX169,648Other TransactionsWe purchase goods and services from certain entities that are partially owned by our executive officers. The following table summarizes thesetransactions for the year ended March 31, 2016:Entity Nature of Purchases AmountPurchased Ownership Interestin Entity (in thousands) Shawn W. Coady Hicks Motor Sales Vehicle purchases $640 50%Vincent J. Osterman VE Properties III, LLC Office space rental 153 100%H. Michael Krimbill Pinnacle Aviation 2007, LLC Aircraft rental 81 50%H. Michael Krimbill KAIR2014 LLC Aircraft rental 47 50%We provide goods and services to certain entities that are partially owned by our executive officers. The following table summarizes thesetransactions for the year ended March 31, 2016:Entity Nature of Services RevenuesGenerated Ownership Interestin Entity (in thousands) James J. Burke Impact Energy Services, LLC Truck transportation services $314 50%Todd M. Coady, an officer and employee of the Partnership, is the brother of Shawn W. Coady, who is an officer of the Partnership and a member ofthe board of directors. Todd M. Coady’s annual base compensation is $250,000. Todd M. Coady reduced his hours in January 2016, and his annual base ofcompensation is $125,000. Todd M. Coady was also eligible to participate in the Partnership’s 401(k) plan, and he received $5,889 of employer matchingcontributions during the year ended March 31, 2016. In April 2015, Todd M. Coady was granted 24,000 Performance Units that vested on July 1, 2015. Theaggregate grant date fair value of these awards was $346,982. In July 2015, Todd M. Coady was granted a bonus of 6,666 restricted units that vested duringAugust 2015. The grant date fair value of this bonus was $185,815. Todd M. Coady was also granted 8,000 Service Award units that are scheduled to vest onJuly 1, 2016. The aggregate grant date fair value of this award was $62,880.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, 2016 was $110,000. In July 2015, Timothy Osterman wasgranted a bonus of 6,069 restricted units that vested during August 2015. The grant date fair value of this bonus was $169,174. Timothy Osterman was alsoeligible to participate in the Partnership’s 401(k) plan, and he received $3,850 of employer matching contributions during the year ended March 31, 2016. InMarch 2015, Timothy Osterman was granted 2,000 units of which 1,000 units vested on July 1, 2015 and the other 1,000 units will vest on July 1, 2016. Theaggregate grant date fair value of this award was $45,220. Timothy Osterman was also granted 5,000 Service Award units in February 2016, that arescheduled to vest on July 1, 2016. The aggregate grant date fair value of this award was $39,300.125 Table of ContentsRegistration Rights AgreementWe 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 nine 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 PartiesThe 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;•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.126 Table of ContentsDirector IndependenceThe 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 Accounting Fees and ServicesWe 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 periods indicated: March 31, 2016 2015Audit fees (1) $2,676,038 $2,762,764Audit-related fees — —Tax fees (2) — 30,000All other fees — —Total $2,676,038 $2,792,764 (1)Includes fees for audits of the Partnership’s financial statements, reviews of the related quarterly financial statements, and services that are normallyprovided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed withthe 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 ServicesThe 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.127 Table of ContentsPART IVItem 15. Exhibits, Financial Statement Schedules(a)The following documents are filed as part of this Annual Report:1.Financial Statements. Please see the accompanying Index to Financial Statements.2.Financial Statement Schedules. All schedules have been omitted because they are either not applicable, not required or the information required insuch schedules appears in the financial statements or the related notes.3.Exhibits.Exhibit NumberDescription2.1 LLC 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 (incorporated byreference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.2 LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWLKarnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated byreference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.3 LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC, TerryBailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated byreference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.4 LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, TerryBailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated byreference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.5 LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWL Operating,LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High SierraTransportation, LLC (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed with theSEC on August 7, 2013) 2.6 Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP,Gavilon, LLC and Gavilon Energy Intermediate, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on December 5, 2013) 3.1 Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Registration Statement onForm S-1 (File No. 333-172186) filed on April 15, 2011) 3.2 Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.2 tothe Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.3 Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011) 3.4 First Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 26, 2011) 3.5 Second Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012) 3.6 Third Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 26, 2012) 128 Table of ContentsExhibit NumberDescription3.7 Fourth Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 2012) 3.8 Certificate 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) 3.9 Certificate of Amendment to Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.5 to theRegistration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.10 Third 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) 3.11 Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as ofAugust 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onAugust 7, 2013) 3.12 Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as ofJune 27, 2014 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onJuly 3, 2014) 4.1 First Amended and Restated Registration Rights Agreement, dated October 3, 2011, by and among the Partnership, Hicks Oils &Hicksgas, Incorporated, NGL Holdings, Inc., Krim2010, LLC, Infrastructure Capital Management, LLC, Atkinson Investors, LLC, E.Osterman Propane, Inc. and the other holders party thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K(File No. 001-35172) filed on October 7, 2011) 4.2 Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 by andamong the Partnership and SemStream (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on November 4, 2011) 4.3 Amendment No. 2 and Joinder to First Amended and Restated Registration Rights Agreement, dated January 3, 2012, by and amongNGL Energy Holdings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-PortlandPropane, L.L.C., Pacer Propane (Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C. (incorporated byreference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012) 4.4 Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGLEnergy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on May 4, 2012) 4.5 Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and betweenNGL Energy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K(File No. 001-35172) filed with the SEC on June 25, 2012) 4.6 Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and betweenNGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on October 3, 2012) 4.7 Amendment 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) 4.8 Amendment 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) 4.9 Amendment No. 8 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of February 17, 2015, by andamong NGL Energy Holdings LLC and Magnum NGL Holdco LLC (incorporated by reference to Exhibit 4.9 to the Annual Report onForm 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015) 129 Table of ContentsExhibit NumberDescription4.10* Amendment No. 9 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of February 25, 2016, by andamong NGL Energy Holdings LLC and Magnum NGL Holdco LLC 4.11 Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by reference toExhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 4.12 Amendment No. 1 to Note Purchase Agreement, dated as of January 15, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18,2013) 4.13 Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 9, 2013) 4.14 Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K(File No. 001-35172) filed with the SEC on October 3, 2013) 4.15 Amendment No. 4 to Note Purchase Agreement, dated as of November 5, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8,2013) 4.16 Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 2013, among the Partnership and the purchasers 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) 4.17 Amendment No. 6 to Note Purchase Agreement, dated as of June 30, 2014, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 3, 2014) 4.18 Amendment 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) 4.19 Amendment No. 8 to Note Purchase Agreement, dated as of May 1, 2015, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.18 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015filed with the SEC on June 1, 2015) 4.20 Amendment No. 9 to Note Purchase Agreement, dated as of December 23, 2015, among the Partnership and the purchasers namedtherein (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter endedDecember 31, 2015 filed with the SEC on February 9, 2016) 4.21* Amendment No. 10 to Note Purchase Agreement, dated as of February 9, 2016, among the Partnership and the purchasers named therein 4.22 Indenture, 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) 4.23 Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013) 4.24 First Supplemental Indenture, dated as of December 2, 2013, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated byreference to Exhibit 4.19 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with theSEC on May 30, 2014) 4.25 Second Supplemental Indenture, dated as of April 22, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiary party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated byreference to Exhibit 4.20 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with theSEC on May 30, 2014) 4.26 Third 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 to theQuarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with the SEC on November 10,2014) 130 Table of ContentsExhibit NumberDescription4.27 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 (incorporated byreference to Exhibit 4.25 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with theSEC on June 1, 2015) 4.28 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 (incorporated byreference to Exhibit 4.26 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with theSEC on June 1, 2015) 4.29 Sixth Supplemental Indenture, dated as of August 21, 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 (incorporated byreference to Exhibit 4.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed withthe SEC on November 9, 2015) 4.30 Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., theGuarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporatedby reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013) 4.31 Registration Rights Agreement, dated December 2, 2013, by and among NGL Energy Partners LP and the purchasers set forth onSchedule A thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with theSEC on December 5, 2013) 4.32 Indenture, dated as of July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party theretoand U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on July 9, 2014) 4.33 Forms of 5.125% Senior Notes due 2019 (incorporated by reference and included as Exhibits A1 and A2 to Exhibit 4.1 to the CurrentReport on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014) 4.34 Registration Rights Agreement, dated July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantorslisted therein on Exhibit A and RBS Securities Inc. as representative of the several initial purchasers (incorporated by reference toExhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014) 4.35 First Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the GuaranteeingSubsidiaries party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.5 to the QuarterlyReport on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with the SEC on November 10, 2014) 4.36 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 (incorporated byreference to Exhibit 4.32 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with theSEC on June 1, 2015) 4.37 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 (incorporated byreference to Exhibit 4.33 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with theSEC on June 1, 2015) 4.38 Fourth Supplemental Indenture, dated as of August 21, 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 (incorporated byreference to Exhibit 4.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed withthe SEC on November 9, 2015) 10.1 Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders party theretoand Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to the Current Reporton Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 10.2 Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP, DeutscheBank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012) 131 Table of ContentsExhibit NumberDescription10.3 Amendment No. 1 to Credit Agreement, dated as of January 15, 2013, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18,2013) 10.4 Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K (File No 001-35172) filed on May 9, 2013) 10.5 Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, eachsubsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank TrustCompany Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “IssuingBank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onOctober 3, 2013) 10.6 Amendment No. 4 to Credit Agreement, dated as of November 5, 2013, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8,2013) 10.7 Amendment No. 5 to Credit Agreement, dated as of December 23, 2013, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank and Trust Company Americas and the other financial institutions party thereto(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30,2013) 10.8 Facility 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 on Form 8-K(File No. 001-35172) filed with the SEC on January 3, 2014) 10.9 Amendment No. 6 to Credit Agreement, dated as of June 12, 2014, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 16, 2014) 10.10 Amendment No. 7 to Credit Agreement, dated as of June 27, 2014, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 3, 2014) 10.11 Facility Increase Agreement, dated December 1, 2014, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americasand the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on December 1, 2014) 10.12 Amendment No. 8 to Credit Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, among NGL EnergyOperating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financialinstitutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed onJanuary 2, 2015) 10.13 Amendment No. 9 to Credit Agreement, dated as of May 1, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.13 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with theSEC on June 1, 2015) 10.14 Amendment No. 10 to Credit Agreement, dated as of July 31, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 4, 2015) 10.15 Facility Increase Agreement, dated October 7, 2015, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas andthe other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q (File No.001-35172) for the quarter ended December 31, 2015 filed with the SEC on February 9, 2016) 132 Table of ContentsExhibit NumberDescription10.16 Amendment No. 11 to Credit Agreement, dated as of December 23, 2015, 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 10.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter endedDecember 31, 2015 filed with the SEC on February 9, 2016) 10.17* Amendment No. 12 to Credit Agreement, dated as of February 9, 2016, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto 10.18 Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed onSchedule A thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with theSEC on December 5, 2013) 10.19+ 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) 10.20+ NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K(File No. 001-35172) filed on May 17, 2011) 10.21+ Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated byreference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended June 30, 2012 filed with theSEC on August 14, 2012 ) 10.22 NGL Performance Unit Program (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K (File No. 001-35172)for the year ended March 31, 2015 filed with the SEC on June 1, 2015) 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-OxleyAct 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-OxleyAct 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, 2016 and2015, (ii) Consolidated Statements of Operations for the years ended March 31, 2016, 2015, and 2014, (iii) Consolidated Statements of ComprehensiveIncome (Loss) for the years ended March 31, 2016, 2015, and 2014, (iv) Consolidated Statements of Changes in Equity for the years ended March 31,2016, 2015, and 2014, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2016, 2015, and 2014, and (vi) Notes to ConsolidatedFinancial Statements.+Management contracts or compensatory plans or arrangements.133 Table of ContentsSIGNATURESPursuant to the requirements of Section 13 or 15(d) Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to besigned on its behalf by the undersigned, thereunto duly authorized on May 31, 2016. NGL ENERGY PARTNERS LP By:NGL Energy Holdings LLC, its general partner By:/s/ H. Michael Krimbill H. Michael Krimbill Chief Executive OfficerPursuant 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 Title Date /s/ H. Michael Krimbill Chief Executive Officer and Director May 31, 2016H. Michael Krimbill (Principal Executive Officer) /s/ Robert W. Karlovich III Chief Financial Officer May 31, 2016Robert W. Karlovich III (Principal Financial Officer) /s/ Lawrence W. Thuillier Chief Accounting Officer May 31, 2016Lawrence W. Thuillier (Principal Accounting Officer) /s/ Christopher Beall Director May 31, 2016Christopher Beall /s/ James J. Burke Director May 31, 2016James J. Burke /s/ Shawn W. Coady Director May 31, 2016Shawn W. Coady /s/ James M. Collingsworth Director May 31, 2016James M. Collingsworth /s/ Stephen L. Cropper Director May 31, 2016Stephen L. Cropper /s/ Bryan K. Guderian Director May 31, 2016Bryan K. Guderian /s/ James C. Kneale Director May 31, 2016James C. Kneale /s/ Vincent J. Osterman Director May 31, 2016Vincent J. Osterman Director May 31, 2016John T. Raymond Director May 31, 2016Patrick Wade 134 Table of ContentsINDEX TO FINANCIAL STATEMENTS NGL ENERGY PARTNERS LP Report of Independent Registered Public Accounting FirmF-2 Consolidated Balance Sheets at March 31, 2016 and 2015F-4 Consolidated Statements of Operations for the years ended March 31, 2016, 2015, and 2014F-5 Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2016, 2015, and 2014F-6 Consolidated Statements of Changes in Equity for the years ended March 31, 2016, 2015, and 2014F-7 Consolidated Statements of Cash Flows for the years ended March 31, 2016, 2015, and 2014F-8 Notes to Consolidated Financial StatementsF-10F-1 Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMPartnersNGL Energy Partners LPWe have audited the accompanying consolidated balance sheets of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the“Partnership”) as of March 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), changes in equity, andcash flows for each of the three years in the period ended March 31, 2016. These financial statements are the responsibility of the Partnership’s management.Our responsibility is to express an opinion on these financial statements based on our audits.We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those 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, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the periodended March 31, 2016 in conformity with accounting principles generally accepted in the United States of America.As discussed in Note 1 to the consolidated financial statements, the Partnership adopted new accounting guidance in 2016 and 2015 related to thepresentation of debt issuance costs.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, 2016, based on criteria established in the 2013 Internal Control-Integrated Framework issued by theCommittee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 31, 2016 expressed an unqualified opinion./s/ GRANT THORNTON LLP Tulsa, Oklahoma May 31, 2016 F-2 Table of ContentsREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMPartnersNGL Energy Partners LPWe 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, 2016, 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.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, 2016, 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, 2016, and our report dated May 31, 2016 expressed an unqualified opinion onthose financial statements./s/ GRANT THORNTON LLP Tulsa, Oklahoma May 31, 2016 F-3 Table of ContentsNGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Balance Sheets(U.S. Dollars in Thousands, except unit amounts) March 31, 2016 2015ASSETS CURRENT ASSETS: Cash and cash equivalents$28,176 $41,303Accounts receivable-trade, net of allowance for doubtful accounts of $6,928 and $4,367, respectively521,014 1,025,763Accounts receivable-affiliates15,625 17,198Inventories367,806 442,025Prepaid expenses and other current assets95,859 121,207Total current assets1,028,480 1,647,496 PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $266,491 and $202,959, respectively1,649,572 1,624,016GOODWILL1,315,362 1,558,233INTANGIBLE ASSETS, net of accumulated amortization of $316,878 and $216,493, respectively1,148,890 1,232,308INVESTMENTS IN UNCONSOLIDATED ENTITIES219,550 472,673LOAN RECEIVABLE-AFFILIATE22,262 8,154OTHER NONCURRENT ASSETS176,039 112,912Total assets$5,560,155 $6,655,792 LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable-trade$420,306 $833,018Accounts payable-affiliates7,193 25,794Accrued expenses and other payables214,426 202,349Advance payments received from customers56,185 54,234Current maturities of long-term debt7,907 4,472Total current liabilities706,017 1,119,867 LONG-TERM DEBT, net of debt issuance costs of $15,500 and $17,835, respectively, and current maturities2,912,837 2,727,464OTHER NONCURRENT LIABILITIES247,236 115,029 COMMITMENTS AND CONTINGENCIES (NOTE 10)0 0 EQUITY: General partner, representing a 0.1% interest, 104,274 and 103,899 notional units, respectively(50,811) (37,000)Limited partners, representing a 99.9% interest, 104,169,573 and 103,794,870 common units issued andoutstanding, respectively1,707,326 2,183,551Accumulated other comprehensive loss(157) (109)Noncontrolling interests37,707 546,990Total equity1,694,065 2,693,432Total liabilities and equity$5,560,155 $6,655,792The accompanying notes are an integral part of these consolidated financial statements.F-4 Table of ContentsNGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Operations(U.S. Dollars in Thousands, except unit and per unit amounts) Year Ended March 31, 2016 2015 2014REVENUES: Crude oil logistics$3,217,079 $6,635,384 $4,558,545Water solutions185,001 200,042 143,100Liquids1,194,479 2,243,825 2,650,425Retail propane352,977 489,197 551,815Refined products and renewables6,792,112 7,231,693 1,357,676Other462 1,916 437,713Total Revenues11,742,110 16,802,057 9,699,274 COST OF SALES: Crude oil logistics3,111,717 6,560,506 4,477,397Water solutions(7,336) (30,506) 11,738Liquids1,037,118 2,111,614 2,518,099Retail propane156,757 278,538 354,676Refined products and renewables6,540,599 7,035,472 1,344,176Other182 2,583 426,613Total Cost of Sales10,839,037 15,958,207 9,132,699 OPERATING COSTS AND EXPENSES: Operating401,118 364,131 259,799General and administrative139,541 149,430 75,860Depreciation and amortization228,924 193,949 120,754Loss on disposal or impairment of assets, net320,766 41,184 3,597Revaluation of liabilities(82,673) (12,264) —Operating (Loss) Income(104,603) 107,420 106,565 OTHER INCOME (EXPENSE): Equity in earnings of unconsolidated entities16,121 12,103 1,898Interest expense(133,089) (110,123) (58,854)Gain on early extinguishment of debt28,532 — —Other income, net5,575 37,171 86(Loss) Income Before Income Taxes(187,464) 46,571 49,695 INCOME TAX BENEFIT (EXPENSE)367 3,622 (937) Net (Loss) Income(187,097) 50,193 48,758 LESS: NET INCOME ALLOCATED TO GENERAL PARTNER(47,620) (45,700) (14,148)LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS(11,832) (12,887) (1,103)NET (LOSS) INCOME ALLOCATED TO LIMITED PARTNERS$(246,549) $(8,394) $33,507 BASIC AND DILUTED (LOSS) INCOME PER COMMON UNIT$(2.35) $(0.05) $0.51BASIC AND DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING104,838,886 86,359,300 61,970,471 The accompanying notes are an integral part of these consolidated financial statements.F-5 Table of ContentsNGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Comprehensive Income (Loss)(U.S. Dollars in Thousands) Year Ended March 31, 2016 2015 2014Net (loss) income$(187,097) $50,193 $48,758Other comprehensive (loss) income(48) 127 (260)Comprehensive (loss) income$(187,145) $50,320 $48,498The accompanying notes are an integral part of these consolidated financial statements.F-6 Table of ContentsNGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Changes in EquityFor the Years Ended March 31, 2016, 2015, and 2014(U.S. Dollars in Thousands, except unit amounts) Limited Partners GeneralPartner CommonUnits Amount SubordinatedUnits Amount AccumulatedOtherComprehensiveIncome (Loss) NoncontrollingInterests TotalEquityBALANCES AT MARCH 31, 2013$(50,497) 47,703,313 $920,998 5,919,346 $13,153 $24 $5,740 $889,418Distributions(9,703) — (123,467) — (11,920) — (840) (145,930)Contributions765 — — — — — 2,060 2,825Business combinations— 2,860,879 80,591 — — — — 80,591Sales of units, net of offeringcosts— 22,560,848 650,155 — — — — 650,155Equity issued pursuant toincentive compensation plan— 296,269 9,085 — — — — 9,085Disposal of noncontrollinginterest— — — — — — (2,789) (2,789)Net income14,148 — 32,712 — 795 — 1,103 48,758Other comprehensive loss— — — — — (260) — (260)BALANCES AT MARCH 31, 2014(45,287) 73,421,309 1,570,074 5,919,346 2,028 (236) 5,274 1,531,853Distributions(38,236) — (197,611) — (6,748) — (27,147) (269,742)Contributions823 — — — — — 9,433 10,256Business combinations— 8,851,105 259,937 — — — 546,740 806,677Sales of units, net of offeringcosts— 15,017,100 541,128 — — — — 541,128Equity issued pursuant toincentive compensation plan— 586,010 23,134 — — — — 23,134Net income (loss)45,700 — (4,479) — (3,915) — 12,887 50,193Other comprehensive income— — — — — 127 — 127Conversion of subordinated unitsto common units— 5,919,346 (8,635) (5,919,346) 8,635 — — —Other— — 3 — — — (197) (194)BALANCES AT MARCH 31, 2015(37,000) 103,794,870 2,183,551 — — (109) 546,990 2,693,432Distributions(61,485) — (260,522) — — — (35,720) (357,727)Contributions54 — (3,829) — — — 15,376 11,601Business combinations— 833,454 19,108 — — — 9,248 28,356Equity issued pursuant toincentive compensation plan— 1,165,053 33,290 — — — — 33,290Common unit repurchases— (1,623,804) (17,680) — — — — (17,680)Net income (loss)47,620 — (246,549) — — — 11,832 (187,097)Deconsolidation of TLP— — — — — — (511,291) (511,291)Other comprehensive loss— — — — — (48) — (48)TLP equity-based compensation— — — — — — 1,301 1,301Other— — (43) — — — (29) (72)BALANCES AT MARCH 31, 2016$(50,811) 104,169,573 $1,707,326 — $— $(157) $37,707 $1,694,065The accompanying notes are an integral part of these consolidated financial statements.F-7 Table of ContentsNGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Cash Flows(U.S. Dollars in Thousands) Year Ended March 31, 2016 2015 2014OPERATING ACTIVITIES: Net (loss) income$(187,097) $50,193 $48,758Adjustments to reconcile net (loss) income to net cash provided by operating activities: Depreciation and amortization, including amortization of debt issuance costs249,211 210,475 132,653Gain on early extinguishment of debt(28,532) — —Non-cash equity-based compensation expense51,565 32,767 14,054Loss on disposal or impairment of assets, net320,766 41,184 3,597Revaluation of liabilities(82,673) (12,264) —Provision for doubtful accounts5,628 4,105 2,445Net commodity derivative (gain) loss(103,223) (219,421) 43,655Equity in earnings of unconsolidated entities(16,121) (12,103) (1,898)Distributions of earnings from unconsolidated entities17,404 12,539 —Other(47) 124 312Changes in operating assets and liabilities, exclusive of acquisitions: Accounts receivable-trade497,560 50,620 21,115Accounts receivable-affiliates7,980 (9,225) 18,002Inventories74,686 243,292 (73,321)Prepaid expenses and other assets10,572 (34,505) 20,308Accounts payable-trade(421,210) (1,965) (167,060)Accounts payable-affiliates(18,499) (51,121) 67,361Accrued expenses and other liabilities(26,665) (61,889) (41,671)Advance payments received from customers190 19,585 (3,074)Net cash provided by operating activities351,495 262,391 85,236 INVESTING ACTIVITIES: Purchases of long-lived assets(661,885) (203,760) (165,148)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(234,652) (960,922) (1,268,810)Cash flows from commodity derivatives105,662 199,165 (35,956)Proceeds from sales of assets8,455 26,262 24,660Proceeds from sale of general partner interest in TLP, net343,135 — —Investments in unconsolidated entities(11,431) (33,528) (11,515)Distributions of capital from unconsolidated entities15,792 10,823 1,591Loan for natural gas liquids facility(3,913) (63,518) —Payments on loan for natural gas liquids facility7,618 1,625 —Loan to affiliate(15,621) (8,154) —Payments on loan to affiliate1,513 — —Other— 4 (195)Net cash used in investing activities(445,327) (1,366,221) (1,455,373) FINANCING ACTIVITIES: Proceeds from borrowings under revolving credit facilities2,602,500 3,764,500 2,545,500Payments on revolving credit facilities(2,133,000) (3,280,000) (2,101,000)Issuances of notes— 400,000 450,000Repurchases of senior notes(43,421) — —Proceeds from borrowings under other long-term debt53,223 — 880Payments on other long-term debt(5,087) (6,688) (8,819)Debt issuance costs(10,237) (11,076) (24,595)F-8 Table of ContentsContributions from general partner54 823 765Contributions from limited partner(3,829) — —Contributions from noncontrolling interest owners15,376 9,433 2,060Distributions to partners(322,007) (242,595) (145,090)Distributions to noncontrolling interest owners(35,720) (27,147) (840)Taxes paid on behalf of equity incentive plan participants(19,395) (13,491) —Common unit repurchases(17,680) — —Proceeds from sale of common units, net of offering costs— 541,128 650,155Other(72) (194) —Net cash provided by financing activities80,705 1,134,693 1,369,016Net (decrease) increase in cash and cash equivalents(13,127) 30,863 (1,121)Cash and cash equivalents, beginning of period41,303 10,440 11,561Cash and cash equivalents, end of period$28,176 $41,303 $10,440The accompanying notes are an integral part of these consolidated financial statements.F-9 Table of ContentsNGL ENERGY PARTNERS LP AND SUBSIDIARIESNotes to Consolidated Financial StatementsAt March 31, 2016 and 2015, and for the Years Ended March 31, 2016, 2015, and 2014Note 1—Nature of Operations and OrganizationNGL 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 discussed in Note 4. At March 31, 2016, our operations include:•Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals and pipeline injection stations, a fleetof owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests in two crude oil pipelines.Our crude oil logistics segment purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipelineinjection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.•Our water solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solidwaste disposal facilities. Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oiland natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck washouts. In addition, ourwater solutions segment sells the recycled water and recovered hydrocarbons that result from performing these services.•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 and storage services through its 19 owned terminals throughout the UnitedStates, its salt dome storage facility in Utah, and its leased storage and railcar transportation services through its fleet of leased railcars.•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 purchaserefined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedule themfor delivery at various locations. See Note 14 for a discussion of our interests in TransMontaigne Partners L.P. (“TLP”).Recent DevelopmentsOn February 1, 2016, we completed the sale of our general partner interest in TLP to an affiliate of ArcLight Capital Partners (“ArcLight”). As aresult, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting.See Note 14 for a discussion of the sale. Our investment in TLP is included in investments in unconsolidated entities in our consolidated balance sheet. AsTLP was previously a consolidated entity, our consolidated statement of operations includes ten months of TLP’s operations and income attributable to thenoncontrolling interests of TLP, and two months of our equity in earnings of TLP, the period after the deconsolidation. Note 2—Significant Accounting PoliciesBasis of PresentationOur consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). Theaccompanying consolidated financial statements include our accounts and those of our controlled subsidiaries. All significant intercompany transactions andaccount balances have been eliminated in consolidation. Investments we cannot control, but can exercise significant influence over, are accounted for usingthe equity method of accounting. We also own an undivided interest in a crude oil pipeline (see Note 16). We will include our proportionate share of assets,liabilities, and expenses related to this pipeline in our consolidated financial statements.We have reclassified certain prior period financial statement information to be consistent with the classification methods used in the current fiscalyear. These reclassifications did not impact previously reported amounts of equity, net income, or cash flows. In addition, certain balances at March 31, 2015were adjusted to reflect the final acquisition accounting for certain business combinations.F-10 Table of ContentsIn the fourth quarter of fiscal year 2016, we identified an immaterial error in our previously issued financial statements for the year ended March 31,2015. We have changed our previously issued consolidated balance sheet as of March 31, 2015 and consolidated statements of operations, consolidatedstatement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year ended March 31,2015 for the correction of this immaterial error. The impact of this error correction is more specifically described in Note 17.Use of EstimatesThe preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the amountof assets and liabilities reported at the date of the consolidated financial statements and the amount of revenues and expenses reported during the periodspresented.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 assets, 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 MeasurementsWe record our commodity derivative instruments and assets and liabilities acquired in business combinations at fair value. Fair value is defined asthe price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at themeasurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability. We use the following fair valuehierarchy, which prioritizes valuation technique inputs used to measure fair value into three broad levels:•Level 1—Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date.•Level 2—Inputs (other than quoted prices included within Level 1) that are either directly or indirectly observable for the asset or liability,including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities ininactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability, and (iv) inputs that are derived fromobservable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts. We determine the fair value of all of our derivative financial instruments utilizingpricing models for similar instruments. Inputs to the pricing models include publicly available prices and forward curves generated from acompilation of data gathered from third parties.•Level 3—Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.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 a fair value measurementrequires judgment, considering factors specific to the asset or liability.Derivative Financial InstrumentsWe record all derivative financial instrument contracts at fair value in our consolidated balance sheets except for certain contracts that qualify forthe normal purchase and normal sale election. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date;instead, we record the purchase or sale at the contracted value once the delivery occurs.We have not designated any financial instruments as hedges for accounting purposes. All changes in the fair value of our commodity derivativeinstruments that do not qualify as normal purchases and normal sales (whether cash transactions or non-cash mark-to-market adjustments) are reported withincost of sales in our consolidated statements of operations, regardless of whether the contract is physically or financially settled.F-11 Table of ContentsWe utilize various commodity derivative financial instrument contracts to attempt to reduce our exposure to price fluctuations. We do not enter intosuch contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in marketprices, newly originated transactions, and the timing of settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timingof performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated marketmovements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that thevalue of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss fromnonperformance by suppliers, customers or financial counterparties to a contract. Procedures and limits for managing commodity price risks and credit risksare specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and arereported 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 master netting agreements that allow for offsetting counterparty receivable and payablebalances for certain transactions.Revenue RecognitionWe record product sales revenues when title to the product transfers to the purchaser, which typically occurs when the purchaser receives theproduct. We record terminaling, transportation, storage, and service revenues when the service is performed, and we record tank and other rental revenuesover the lease term. Several of our terminaling service agreements with throughput customers, allow us to receive the product volume gained resulting fromdifferences between the measurement of product volumes received and distributed at our terminaling facilities. Such differences are due to the inherentvariances in measurement devices and methodology. We record revenues for the net proceeds from the sale of the product gained. Revenues for our watersolutions segment are recognized when we obtain 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. We include amounts billed tocustomers for shipping and handling costs in revenues in our consolidated statements of operations. We enter into certain contracts whereby we agree topurchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements areentered into at the same time and in contemplation of each other, we record the revenues for these transactions net of cost of sales.Revenues include $5.8 million and $0.7 million during the years ended March 31, 2016 and 2015, respectively, associated with the amortization ofa liability recorded in the acquisition accounting for an acquired business related to certain out-of-market revenue contracts.Cost of SalesWe include all costs we incur to acquire products, including the costs of purchasing, terminaling, and transporting inventory, prior to delivery to ourcustomers, in cost of sales. Cost of sales excludes depreciation of our property, plant and equipment. Cost of sales includes amortization of certain contract-based intangible assets of $6.7 million, $7.8 million, and $6.2 million during the years ended March 31, 2016, 2015, and 2014, respectively.Depreciation and AmortizationDepreciation 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 EquivalentsCash 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.F-12 Table of ContentsSupplemental Cash Flow InformationSupplemental cash flow information is as follows for the periods indicated: Year Ended March 31, 2016 2015 2014 (in thousands)Interest paid, exclusive of debt issuance costs and letter of credit fees $117,185 $90,556 $31,827Income taxes paid (net of income tax refunds) $2,300 $22,816 $1,639Cash 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 operating activities.Accounts Receivable and Concentration of Credit RiskWe 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 at the dates indicated: March 31, 2016 March 31, 2015Segment GrossReceivable Allowance forDoubtful Accounts GrossReceivable Allowance forDoubtful Accounts (in thousands)Crude oil logistics $175,341 $8 $600,896 $382Water solutions 34,952 4,514 38,689 709Liquids 73,478 505 99,699 1,133Retail propane 31,583 965 55,147 1,619Refined products and renewables 211,259 936 234,802 524Other 1,329 — 897 —Total $527,942 $6,928 $1,030,130 $4,367Changes in the allowance for doubtful accounts are as follows for the periods indicated: Year Ended March 31, 2016 2015 2014 (in thousands)Allowance for doubtful accounts, beginning of period $4,367 $2,822 $1,760Provision for doubtful accounts 5,628 4,105 2,445Write off of uncollectible accounts (3,067) (2,560) (1,383)Allowance for doubtful accounts, end of period $6,928 $4,367 $2,822We did not have any customers that represented over 10% of consolidated revenues for fiscal years 2016, 2015 and 2014.F-13 Table of ContentsInventoriesWe 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 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, 2016 and 2015, our inventory values were reduced by$13.3 million and $16.8 million, respectively, of lower of cost or market adjustments.Inventories consist of the following at the dates indicated: March 31, 2016 2015 (in thousands)Crude oil $84,030 $145,412Natural gas liquids— Propane 28,639 44,798Butane 8,461 8,668Other 6,011 3,874Refined products— Gasoline 80,569 128,092Diesel 99,398 59,097Renewables 52,458 44,668Other 8,240 7,416Total $367,806 $442,025Investments in Unconsolidated EntitiesWe own noncontrolling interests in certain entities. We account for these investments using the equity method of accounting. Under the equitymethod, we do not report the individual assets and liabilities of these entities on our consolidated balance sheets; instead, our ownership interests arereported within investments in unconsolidated entities on our consolidated balance sheets. Under the equity method, the investment is recorded atacquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of anylosses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds ourproportionate share of the historical net book value of the net assets of the investee.As discussed below, on February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP andbegan to account for our limited partner investment in TLP using the equity method of accounting. Also, as part of the deconsolidation of TLP, our previousinvestments in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”), which owns a refined products storage facility, and Frontera BrownsvilleLLC (“Frontera”) are no longer disclosed as investments in unconsolidated entities.F-14 Table of ContentsOur investments in unconsolidated entities consist of the following at the dates indicated: Ownership Date Acquired March 31,Entity Segment Interest or Formed 2016 2015 (in thousands)Glass Mountain (1) Crude oil logistics 50.0% December 2013 $179,594 $187,590TLP (2) Refined products andrenewables 19.6% July 2014 8,301 —BOSTCO (3) Refined products andrenewables 42.5% July 2014 — 238,146Frontera (3) Refined products andrenewables 50.0% July 2014 — 16,927Water supply company Water solutions 35.0% June 2014 15,875 16,471Water treatment and disposal facility Water solutions 50.0% August 2015 2,238 —Ethanol production facility Refined products andrenewables 19.0% December 2013 12,570 13,539Retail propane company Retail propane 50.0% April 2015 972 —Total $219,550 $472,673 (1)When we acquired Gavilon Energy, we recorded the investment in Glass Mountain, which owns a crude oil pipeline in Oklahoma, at fair value. Ourinvestment in Glass Mountain exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $74.6 million atMarch 31, 2016. This difference relates primarily to goodwill and customer relationships.(2)On February 1, 2016, we deconsolidated TLP (see Note 1 and Note 14), and as a result, we recorded our equity method investment in TLP. On April 1,2016, we sold all of the TLP common units that we held (see Note 19).(3)As part of the deconsolidation of TLP on February 1, 2016, our previous investments in BOSTCO and Frontera are no longer disclosed as investments inunconsolidated entities.The following table summarizes the cumulative earnings (loss) from our unconsolidated entities and cumulative distributions received from ourunconsolidated entities at March 31, 2016:Entity Cumulative Earnings (Loss) FromUnconsolidated Entities Cumulative DistributionsReceived From UnconsolidatedEntities (in thousands)Glass Mountain $7,251 $23,260TLP 807 —BOSTCO 13,432 23,491Frontera 3,779 4,274Water supply company (625) —Water treatment and disposal facility 44 96Ethanol production facility 5,961 7,028Retail propane company (528) —F-15 Table of ContentsSummarized financial information of our unconsolidated entities is as follows for the dates and periods indicated:Balance sheets - Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities March 31, 2016 2015 2016 2015 2016 2015 2016 2015 (in thousands)Glass Mountain$7,248 $8,456 $204,020 $214,494 $1,268 $1,080 $24 $37TLP10,419 — 652,309 — 18,812 — 267,373 —BOSTCO— 13,710 — 507,655 — 11,189 — —Frontera— 4,608 — 43,805 — 1,370 — —Water supply company2,589 3,160 28,150 32,447 2,923 644 20,746 26,251Water treatment and disposal facility91 — 4,476 — 124 — — —Ethanol production facility34,477 38,607 90,310 85,277 14,616 15,755 30,730 21,403Retail propane company700 — 2,248 — 555 — 449 —Statements of operations - Revenues Cost of Sales Net Income (Loss) March 31, 2016 2015 2014 2016 2015 2014 2016 2015 2014 (in thousands)Glass Mountain$35,978 $37,539 $3,979 $1,943 2,771 $— $11,227 $12,345 $445TLP28,258 — — — — — 6,083 — —BOSTCO60,420 45,067 — — — — 21,987 11,074 —Frontera14,114 10,643 — — — — 4,091 1,352 —Water supply company4,062 8,326 — — — — (1,618) (104) —Water treatment and disposal facility777 — — — — — 85 — —Ethanol production facility129,533 159,148 61,929 105,161 117,222 39,449 5,796 24,607 17,599Retail propane company715 — — 321 — — (1,056) — —Other Noncurrent AssetsOther noncurrent assets consist of the following at the dates indicated: March 31, 2016 2015 (in thousands)Loan receivable (1) $49,827 $58,050Linefill (2) 35,060 35,060Tank bottoms (3) 42,044 —Other 49,108 19,802Total $176,039 $112,912 (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 shipment commitments. AtMarch 31, 2016, linefill consisted of 487,104 barrels of crude oil.F-16 Table of Contents(3)Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when thestorage tanks are removed from service. At March 31, 2016, tank bottoms held in third party terminals consisted of 366,212 barrels of refined products.Tank bottoms held in terminals we own are included within property, plant and equipment (see Note 5).Accrued Expenses and Other PayablesAccrued expenses and other payables consist of the following at the dates indicated: March 31, 2016 2015 (in thousands)Accrued compensation and benefits $40,517 $52,078Excise and other tax liabilities 59,455 43,847Derivative liabilities 28,612 27,950Accrued interest 20,543 23,065Product exchange liabilities 5,843 15,480Deferred gain on sale of general partner interest in TLP 30,113 —Other 29,343 39,929Total $214,426 $202,349Property, Plant and EquipmentWe 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).We evaluate the carrying value of our property, plant and equipment for potential impairment when events and circumstances warrant such a review.A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset groupis less than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group (seeNote 14).Intangible AssetsOur 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 associated with our revolving credit facilities. 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 less 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.F-17 Table of ContentsDebt Issuance CostsIn April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Simplifying thePresentation of Debt Issuance Costs.” On March 31, 2016, we adopted this ASU, which requires certain debt issuance costs to be reported as a reduction to thecarrying amount of the long-term debt. This ASU does not apply to debt issuance costs related to revolving credit facilities, and we continue to report suchdebt issuance costs as intangible assets. We have applied this ASU retrospectively to our March 31, 2015 consolidated balance sheet. The following tablecompares the intangible asset and long-term debt balances as currently reported to the amounts that would have been reported under the old accountingstandard: At March 31, 2016 2015 Current Standard Previous Standard Current Standard Previous Standard (in thousands)Intangible assets $1,148,890 $1,164,390 $1,232,308 $1,250,143Long-term debt 2,912,837 2,928,337 2,727,464 2,745,299GoodwillGoodwill 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, 2016 is deductible for income tax purposes.Goodwill and indefinite-lived intangible assets are not amortized, but instead are evaluated for impairment periodically. We perform our annualassessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant.To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unitexceeds its carrying amount. If we conclude that it is more likely than not that the fair value of a reporting unit exceeds its carrying amount, we perform thefollowing two-step goodwill impairment test:•In the first step of the goodwill impairment test, we compare the fair value of the reporting unit with its carrying amount, including goodwill. Ifthe fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amountof a reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of impairment loss,if any.•In the second step of the goodwill impairment test, we compare the implied fair value of reporting unit goodwill with the carrying amount ofthat 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. See Note 14 further a furtherdiscussion and analysis of our goodwill impairment assessment.Product ExchangesQuantities 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-18 Table of ContentsAdvance Payments Received from CustomersWe record customer advances on product purchases as a liability in our consolidated balance sheets.Noncontrolling InterestsWe 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.As previously reported, as part of our acquisition of TransMontaigne on July 1, 2014, we acquired the 2% general partner interest and a 19.7%limited partner interest in TLP. We attributed net earnings allocable to TLP’s limited partners to the controlling and noncontrolling interests based on therelative ownership interests in TLP. Earnings allocable to TLP’s limited partners were net of the earnings allocable to TLP’s general partner interest. Earningsallocable to TLP’s general partner interest include the distributions of cash attributable to the period to TLP’s general partner interest and incentivedistribution rights, net of adjustments for TLP’s general partner’s proportionate share of undistributed earnings. Undistributed earnings were allocated toTLP’s limited partners and TLP’s general partner interest based on their ownership percentages of 98% and 2%, respectively. On February 1, 2016, we soldour general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLPusing the equity method of accounting. See Note 14 for a further discussion of the sale of the TLP general partner.Business Combination Measurement PeriodWe 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 are still within this measurement period, and as a result, theacquisition 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, 2016 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, 2015. We retrospectively adjusted theMarch 31, 2015 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, 2015 for these measurement period adjustments.Recent Accounting PronouncementsIn February 2016, the FASB issued ASU No. 2016-02, “Leases.” The ASU will replace previous lease accounting guidance in GAAP. The ASUrequires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The ASU retains a distinction betweenfinance leases and operating leases. The ASU is effective for the Partnership beginning April 1, 2019, and requires a modified retrospective method ofadoption. We are in the process of assessing the impact of this ASU on our consolidated financial statements.In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” The ASU requires that inventory within the scope ofthe guidance be measured at the lower of cost or net realizable value. The ASU is effective for the Partnership beginning April 1, 2017, and requires aprospective method of adoption, although early adoption is permitted. We do not expect the adoption of this ASU to have a material impact on ourconsolidated financial position or results of operations.In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The ASU 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, 2018, 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-19 Table of ContentsNote 3—Income (Loss) Per Common UnitOur income (loss) per common unit is as follows for the periods indicated: Year Ended March 31, 2016 2015 2014 (in thousands, except unit and per unit amounts)Net (loss) income $(187,097) $50,193 $48,758Less: Net income attributable to noncontrolling interests (11,832) (12,887) (1,103)Net (loss) income attributable to parent equity (198,929) 37,306 47,655Less: Net income allocated to general partner (1) (47,620) (45,700) (14,148)Less: Net loss (income) allocated to subordinated unitholders (2) — 3,915 (1,893)Net (loss) income allocated to common unitholders $(246,549) $(4,479) $31,614 Basic and diluted (loss) income per common unit $(2.35) $(0.05) $0.51Basic and diluted weighted average common units outstanding 104,838,886 86,359,300 61,970,471 (1)Net income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are describedin Note 11.(2)All outstanding subordinated units converted to common units in August 2014. Since the subordinated units did not share in the distribution of cashgenerated after June 30, 2014, we did not allocate any income or loss after that date to the subordinated unitholders. During the three months ended June30, 2014, 5,919,346 subordinated units were outstanding and the loss per subordinated unit was $(0.68). During the year ended March 31, 2014,5,919,346 subordinated units were outstanding and income per subordinated unit was $0.32.The restricted units (as described in Note 11) were considered antidilutive for the years ended March 31, 2016, 2015, and 2014.Note 4—AcquisitionsYear Ended March 31, 2016Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify andmeasure the value of the assets acquired and liabilities assumed in a business combination. The business combinations for which this measurement periodwas still open as of March 31, 2016 are summarized below.F-20 Table of ContentsWater Pipeline CompanyOn January 7, 2016, we acquired a 57.125% interest in an existing produced water pipeline company operating in the Delaware Basin portion ofWest Texas for $12.3 million of cash. In addition, we have recorded contingent consideration liabilities, recorded within accrued expenses and otherpayables and noncurrent liabilities, related to future royalty payments to the sellers of this company for the life of the pipelines. We estimated the contingentconsideration based on the contracted royalty rate, which is a flat rate per barrel, multiplied by the expected disposal volumes to flow through the pipelinesduring the life of the pipelines. This amount was then discounted back to present value using a weighted average cost of capital. As of the acquisition date werecorded a contingent liability of $2.6 million. We are in the process of identifying and determining the fair values of the assets acquired and liabilitiesassumed in this business combination, and as a result, the estimates of fair value at March 31, 2016 are subject to change. We expect to complete this processbefore we issue our financial statements for the three months ending December 31, 2016. The following table summarizes the preliminary estimates of the fairvalues of the assets acquired (and useful lives) and liabilities assumed (in thousands):Accounts receivable-affiliates$1,000Prepaid expenses and other current assets50Property, plant and equipment: Water treatment facilities and equipment (3-30 years)12,154Vehicles (5 years)54Goodwill5,561Intangible assets: Customer relationships (9 years)6,000Non-compete agreements (32 years)350Accrued expenses and other payables(1,000)Noncurrent liabilities(2,600)Noncontrolling interest(9,248)Fair value of net assets acquired$12,321Delaware Basin Water Solutions FacilitiesOn August 24, 2015, we acquired four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the DelawareBasin of the Permian Basin in Texas for $50.0 million of cash. In addition, we have recorded contingent consideration liabilities, recorded within accruedexpenses and other payables and noncurrent liabilities, related to future royalty payments due to the sellers of these facilities. We estimated the contingentconsideration based on the contracted royalty rate, which is a flat rate per disposal barrel and a percentage of the oil revenues, multiplied by the expecteddisposal volumes and oil revenue for the life of the facility and disposal well. This amount was then discounted back to present value using a weightedaverage cost of capital. As of the acquisition date we recorded a contingent liability of $11.0 million. We are in the process of identifying and determiningthe fair values of the assets acquired and liabilities assumed in this business combination, and as a result, the estimates of fair value at March 31, 2016 aresubject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2016. The followingtable summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed (in thousands):Property, plant and equipment: Water treatment facilities and equipment (3-30 years)$18,902Vehicles (5 years)148Goodwill23,776Intangible asset: Customer relationships (6 years)16,000Investments in unconsolidated entities2,290Accrued expenses and other payables(861)Noncurrent liabilities(10,255)Fair value of net assets acquired$50,000F-21 Table of ContentsWater Solutions FacilitiesWe are party to a development agreement that requires us to purchase water solutions facilities developed by the other party to the agreement.During the year ended March 31, 2016, we purchased 15 water treatment and disposal facilities under this development agreement. We also purchased oneadditional water treatment and disposal facility in December 2015 from a different seller. On a combined basis, we paid $146.5 million of cash and issued781,255 common units, valued at $18.1 million, in exchange for these facilities. In addition, we have recorded contingent consideration liabilities, recordedwithin accrued expenses and other payables and noncurrent liabilities, related to future royalty payments due to the sellers of these facilities. We estimatedthe contingent consideration based on the contracted royalty rate, which is a flat rate per disposal barrel and percentage of oil revenues, multiplied by theexpected disposal volumes and oil revenue for the life of the facility and disposal well. This amount was then discounted back to present value using aweighted average cost of capital. As of the acquisition date we recorded a contingent liability of $47.6 million.During the year ended March 31, 2016, we completed the acquisition accounting for six of these water treatment and disposal facilities. Thefollowing table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed (in thousands):Property, plant and equipment: Water treatment facilities and equipment (3-30 years)$27,065Buildings and leasehold improvements (7-30 years)6,879Land1,070Other (5 years)32Goodwill62,105Accrued expenses and other payables(2,512)Noncurrent liabilities(21,462)Fair value of net assets acquired$73,177We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for the other ten water treatmentand disposal facilities, and as a result, the estimates of fair value at March 31, 2016 are subject to change. We expect to complete this process before we issueour financial statements for the three months ending December 31, 2016. The following table summarizes the preliminary estimates of the fair values of theassets acquired (and useful lives) and liabilities assumed (in thousands):Property, plant and equipment: Water treatment facilities and equipment (3-30 years)$48,465Buildings and leasehold improvements (7-30 years)8,214Land3,907Other (5 years)21Goodwill55,880Accrued expenses and other payables(2,861)Noncurrent liabilities(22,198)Fair value of net assets acquired$91,428For all water solutions acquisitions during the year ended March 31, 2016, goodwill represents the excess of the consideration paid for the acquiredbusiness over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to expand our operations intooilfield production basins not previously serviced by us, to expand the number of our disposal sites in oilfield production basins currently serviced by us,thereby enhancing our competitive position as a provider of disposal services in these oilfield production basins, and to expand and strengthen our pre-existing customer relationships with key oilfield producers. We estimate that all of the goodwill will be deductible for federal income tax purposes.Retail Propane BusinessesDuring the year ended March 31, 2016, we acquired six retail propane businesses. On a combined basis, we paid $25.9 million of cash and issued52,199 common units, valued at $1.0 million, in exchange for these assets and operations. The agreements for these acquisitions contemplate post-closingpayments for certain working capital items. We are in the process ofF-22 Table of Contentsidentifying and determining the fair values of the assets acquired and liabilities assumed in these business combinations, and as a result, the estimates of fairvalue at March 31, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months endingDecember 31, 2016.Year Ended March 31, 2015Natural Gas Liquids Storage FacilityIn February 2015, we acquired Sawtooth, NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah withrail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility. We paid $97.6million of cash, net of cash acquired, and issued 7,396,973 common units, valued at $218.5 million, in exchange for these assets and operations. During thethree months ended December 31, 2015, we completed the acquisition accounting for this business combination. The following table summarizes the finalcalculation of the fair values of the assets acquired (and useful lives) and liabilities assumed: Final Estimated AtMarch 31,2015 Change (in thousands)Accounts receivable-trade$42 $42 $—Inventories263 — 263Prepaid expenses and other current assets843 600 243Property, plant and equipment: Natural gas liquids terminal and storage assets (2-30 years)61,130 62,205 (1,075)Vehicles and railcars (3-25 years)78 75 3Land69 68 1Other17 32 (15)Construction in progress19,525 19,525 —Goodwill183,096 151,853 31,243Intangible assets: Customer relationships (20 years)61,500 85,000 (23,500)Non-compete agreements (24 years)5,100 12,000 (6,900)Accounts payable-trade(931) (931) —Accrued expenses and other payables(6,774) (6,511) (263)Advance payments received from customers(1,015) (1,015) —Other noncurrent liabilities(6,817) (6,817) —Fair value of net assets acquired$316,126 $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 represents a premium paid to gain entry to a new fee-based liquids storage business by acquiring underground storage assets ina new and competitively advantaged location, which also provides us with an additional strategically located facility from which to expand the currentmarketing efforts of our liquids business in that area. Goodwill also represents the premium paid for the potential expansion of the facilities. At the time ofacquisition, the facility had two salt domes in operation and two salt domes under construction with the long-term possibility of adding four additional saltdomes. We estimate that all of the goodwill will be deductible for federal income tax purposes.We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert 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 Table of ContentsThe acquisition method of accounting requires that executory contracts with unfavorable terms relative to market conditions at the acquisition datebe recorded as assets or liabilities in the acquisition accounting. Since certain storage leases were at unfavorable terms relative to acquisition date marketconditions, we recorded a liability of $12.8 million related to these leases in the acquisition accounting, a portion of which we recorded to accrued expensesand other payables and a portion of which we recorded to other noncurrent liabilities. We amortized $5.8 million of this balance as an increase to revenuesduring the year ended March 31, 2016. We will amortize the remainder of this liability over the term of the leases. The following table summarizes the futureamortization of this liability (in thousands):Year Ending March 31,2017$4,80520181,306201988Bakken Water Solutions FacilitiesOn November 21, 2014, we acquired two saltwater disposal facilities in the Bakken shale play in North Dakota for $34.6 million of cash. In addition,we have recorded contingent consideration liabilities, recorded within accrued expenses and other payables and noncurrent liabilities, related to futureroyalty payments due to the sellers of these facilities. We estimated the contingent consideration based on the contracted royalty rate, which is a flat rate perbarrel, multiplied by the expected disposal volumes over the life of the facility and disposal well. This amount was then discounted back to present valueusing a weighted average cost of capital. As of the acquisition date we recorded a contingent liability of $3.5 million. During the three months endedSeptember 30, 2015, we completed the acquisition accounting for these water treatment and disposal facilities. The following table summarizes the finalcalculation of the fair values of the assets acquired (and useful lives) and liabilities assumed: Final Estimated AtMarch 31,2015 ChangeProperty, plant and equipment:(in thousands)Vehicles (10 years)$63 $63 $—Water treatment facilities and equipment (3-30 years)5,815 5,815 —Buildings and leasehold improvements (7-30 years)130 130 —Land100 100 —Goodwill7,946 10,085 (2,139)Intangible asset: Customer relationships (7 years)24,300 22,000 2,300Other noncurrent assets75 — 75Accrued expenses and other payables(395) (395) —Other noncurrent liabilities(3,434) (3,198) (236)Fair value of net assets acquired$34,600 $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 represents a premium paid to expand our operations into oilfield production basins not previously serviced by us andstrengthen our pre-existing customer relationships with key oilfield producers. We estimate that all of the goodwill will be deductible for federal income taxpurposes.We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert futureamounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current marketexpectations about those future amounts.TransMontaigne Inc.As previously reported, on July 1, 2014, we acquired TransMontaigne for $200.3 million of cash, net of cash acquired (including $174.1 millionpaid at closing and $26.2 million paid upon completion of the working capital settlement). As part of this transaction, we also purchased $380.4 million ofinventory from the previous owner of TransMontaigne (including $346.9F-24 Table of Contentsmillion paid at closing and $33.5 million subsequently paid as the working capital settlement process progressed). The operations of TransMontaigneinclude the marketing of refined products. As part of this transaction, we acquired the 2% general partner interest, the incentive distribution rights, a 19.7%limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne.During the three months ended June 30, 2015, we completed the acquisition accounting for this business combination. The following tablesummarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed: Final Estimated AtMarch 31,2015 Change (in thousands)Cash and cash equivalents$1,469 $1,469 $—Accounts receivable-trade199,366 197,829 1,537Accounts receivable-affiliates528 528 —Inventories373,870 373,870 —Prepaid expenses and other current assets15,110 15,001 109Property, plant and equipment: Refined products terminal assets and equipment (20 years)415,317 399,323 15,994Vehicles1,696 1,698 (2)Crude oil tanks and related equipment (20 years)1,085 1,058 27Information technology equipment7,253 7,253 —Buildings and leasehold improvements (20 years)15,323 14,770 553Land61,329 70,529 (9,200)Tank bottoms (indefinite life)46,900 46,900 —Other15,536 15,534 2Construction in progress4,487 4,487 —Goodwill30,169 28,074 2,095Intangible assets: Customer relationships (15 years)66,000 76,100 (10,100)Pipeline capacity rights (30 years)87,618 87,618 —Investments in unconsolidated entities240,583 240,583 —Other noncurrent assets3,911 3,911 —Accounts payable-trade(113,103) (113,066) (37)Accounts payable-affiliates(69) (69) —Accrued expenses and other payables(79,405) (78,427) (978)Advance payments received from customers(1,919) (1,919) —Long-term debt(234,000) (234,000) —Other noncurrent liabilities(33,227) (33,227) —Noncontrolling interests(545,120) (545,120) —Fair value of net assets acquired$580,707 $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 represents a premium paid to acquire the skilled workforce, expand the scale of our existing refined and renewables productlines and expand the scale of our existing refined and renewables businesses by gaining control and access to TransMontaigne’s network of terminals andpipeline capacity. We estimate that all of the goodwill will be deductible for federal income tax purposes.We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert 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 Table of ContentsThe 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.As discussed in Note 2, on February 1, 2016, we sold our general partner interest in TLP and on April 1, 2016, we sold all of the TLP units we ownedto ArcLight. See Note 1, Note 14 and Note 19 for a further discussion.Water Solutions FacilitiesWe are party to a development agreement that requires us to purchase water solutions facilities developed by the other party to the agreement.During the year ended March 31, 2015, we purchased 16 water treatment and disposal facilities under this development agreement. 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. In addition, we have recorded contingent considerationliabilities, recorded within accrued expenses and other payables and noncurrent liabilities, related to future royalty payments due to the sellers of thesefacilities. We estimated the contingent consideration based on the contracted royalty rate, which is a flat rate per disposal barrel and a percentage of oilrevenue, multiplied by the expected disposal volumes and oil revenue over the life of the facility and disposal well. This amount was then discounted back topresent value using a weighted average cost of capital. As of the acquisition date we recorded a contingent liability of $121.5 million.During the three months ended December 31, 2015, we completed the acquisition accounting for all of these water treatment and disposal facilities.The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed: Final Estimated AtMarch 31,2015 Change (in thousands)Accounts receivable-trade$939 $939 $—Inventories253 253 —Prepaid expenses and other current assets62 62 —Property, plant and equipment: Water treatment facilities and equipment (3-30 years)79,982 79,706 276Buildings and leasehold improvements (7-30 years)10,690 10,250 440Land3,127 3,109 18Other (5 years)132 129 3Goodwill253,517 254,255 (738)Intangible asset: Customer relationships (4 years)10,000 10,000 —Other noncurrent assets50 50 —Accounts payable-trade(58) (58) —Accrued expenses and other payables(15,785) (15,786) 1Other noncurrent liabilities(109,373) (109,373) —Noncontrolling interest(5,775) (5,775) —Fair value of net assets acquired$227,761 $227,761 $—For these water solutions acquisitions, goodwill represents the excess of the consideration paid for the acquired business over the fair value of theindividual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to expand the number of our disposal sites in oilfield productionbasins currently serviced by us, thereby enhancing our competitive position as a provider of disposal services in these oilfield production basins, and toexpand and strengthen our pre-existing customer relationships with key oilfield producers. We estimate that all of the goodwill will be deductible for federalincome tax purposes.F-26 Table of ContentsRetail Propane BusinessesDuring the year ended March 31, 2015, we acquired eight retail propane businesses. On a combined basis, we paid $39.1 million of cash and issued132,100 common units, valued at $3.7 million, in exchange for these assets and operations.During the three months ended September 30, 2015, we completed the acquisition accounting for all of these business combinations. The followingtable summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed: Final Estimated AtMarch 31,2015 Change (in thousands)Accounts receivable-trade$2,237 $2,237 $—Inventories771 771 —Prepaid expenses and other current assets110 110 —Property, plant and equipment: Retail propane equipment (15-20 years)13,177 13,177 —Vehicles and railcars (5-7 years)2,332 2,332 —Buildings and leasehold improvements (30 years)534 784 (250)Land505 655 (150)Other (5-7 years)118 116 2Goodwill8,097 8,097 —Intangible assets: Customer relationships (10-15 years)17,563 17,563 —Non-compete agreements (5-7 years)500 500 —Trade names (3-12 years)950 950 —Accounts payable-trade(1,523) (1,921) 398Advance payments received from customers(1,750) (1,750) —Current maturities of long-term debt(78) (78) —Long-term debt, net of current maturities(760) (760) —Fair value of net assets acquired$42,783 $42,783 $—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 represents a premium paid to acquire the skilled workforce of each of the businesses acquired. We estimate that all of thegoodwill will be deductible for federal income tax purposes.We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert 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-27 Table of ContentsNote 5—Property, Plant and EquipmentOur property, plant and equipment consists of the following at the dates indicated: Estimated March 31,Description Useful Lives 2016 2015 (in thousands)Natural gas liquids terminal and storage assets 2-30 years $169,758 $131,776Refined products terminal assets and equipment 20 years 6,844 419,603Retail propane equipment 2-30 years 201,312 181,140Vehicles and railcars 3-25 years 185,547 180,680Water treatment facilities and equipment 3-30 years 508,239 317,593Crude oil tanks and related equipment 2-40 years 137,894 109,936Barges and towboats 5-40 years 86,731 59,848Information technology equipment 3-7 years 38,653 34,915Buildings and leasehold improvements 3-40 years 118,885 99,732Land 47,114 97,767Tank bottoms (1) 20,355 62,656Other 3-30 years 11,699 34,407Construction in progress 383,032 96,922 1,916,063 1,826,975Accumulated depreciation (266,491) (202,959)Net property, plant and equipment $1,649,572 $1,624,016 (1)Due to the deconsolidation of TLP in February 2016 (see Note 1), the tank bottoms for the TLP terminals were reclassified to noncurrent assets.The following table summarizes depreciation expense and capitalized interest expense for the periods indicated: Year Ended March 31, 2016 2015 2014 (in thousands)Depreciation expense$136,938 $105,687 $59,899Capitalized interest expense4,012 113 774Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms whenthe storage tanks are removed from service. The following table summarizes the tank bottoms included in the table above at the dates indicated: March 31, 2016 March 31, 2015Product Volume(in barrels)(in thousands) Value(in thousands) Volume(in barrels)(in thousands) Value(in thousands)Gasoline — $— 219 $25,710Crude oil 231 19,348 184 16,835Diesel — — 124 15,153Renewables — — 41 4,220Other 24 1,007 12 738Total $20,355 $62,656F-28 Table of ContentsNote 6—GoodwillThe following table summarizes changes in goodwill by segment for the periods indicated (in thousands): Crude OilLogistics WaterSolutions Liquids RetailPropane RefinedProducts andRenewables TotalBalances at March 31, 2014, asretrospectively adjusted$579,846 $264,127 $91,135 $114,285 $36,000 $1,085,393Disposals (Note 14)— (1,797) (8,185) — — (9,982)Acquisitions (Note 4)— 261,460 183,096 8,097 30,169 482,822Balances at March 31, 2015, asretrospectively adjusted579,846 523,790 266,046 122,382 66,169 1,558,233Acquisitions (Note 4)— 147,322 — 5,046 — 152,368Disposals (Note 14)— — — — (15,042) (15,042)Impairment (Note 14)— (380,197) — — — (380,197)Balances at March 31, 2016$579,846 $290,915 $266,046 $127,428 $51,127 $1,315,362 Note 7—Intangible AssetsOur intangible assets consist of the following at the dates indicated: March 31, 2016 March 31, 2015 AmortizableLives Gross CarryingAmount AccumulatedAmortization Gross CarryingAmount AccumulatedAmortization (in thousands)Amortizable- Customer relationships 3-20 years $852,118 $233,838 $890,118 $159,215Pipeline capacity rights 30 years 119,636 6,559 119,636 2,571Water facility development agreement 5 years 14,000 7,700 14,000 4,900Executory contracts and other agreements 2-10 years 23,920 21,075 23,920 18,387Non-compete agreements 2-32 years 20,903 13,564 19,762 10,408Trade names 1-10 years 15,439 12,034 15,439 7,569Debt issuance costs (1) 3 years 39,942 22,108 33,306 13,443Total amortizable 1,085,958 316,878 1,116,181 216,493Non-amortizable- Customer commitments 310,000 — 310,000 —Rights-of-way and easements (2) 47,190 — — —Trade names 22,620 — 22,620 —Total non-amortizable 379,810 — 332,620 —Total $1,465,768 $316,878 $1,448,801 $216,493 (1)Includes debt issuance costs related to revolving credit facilities. Debt issuance costs related to fixed-rate notes are reported as a reduction of the carryingamount of long-term debt.(2)See Note 16 for a discussion of acquired rights-of-way and easements along a planned pipeline route.The weighted-average remaining amortization period for intangible assets is approximately 13 years.As described in Note 1, on February 1, 2016 due to the sale of our interest in TLP general partner to ArcLight, we deconsolidated TLP and began toaccount for our investment in TLP using the equity method of accounting. See Note 14 for a discussion of the sale.F-29 Table of ContentsAmortization expense is as follows for the periods indicated: Year Ended March 31,Recorded In 2016 2015 2014 (in thousands)Depreciation and amortization $91,986 $88,262 $60,855Cost of sales 6,700 7,767 6,172Interest expense 8,942 5,722 4,800Total $107,628 $101,751 $71,827Expected amortization of our intangible assets, exclusive of assets that are not yet amortizable, is as follows (in thousands):Year Ending March 31,2017$96,155201893,734201983,981202077,558202165,717Thereafter351,935Total$769,080 Note 8—Long-Term DebtOur long-term debt consists of the following at the dates indicated: March 31, 2016 March 31, 2015 FaceAmount UnamortizedDebt IssuanceCosts (1) BookValue FaceAmount UnamortizedDebt IssuanceCosts (1) BookValue (in thousands)Revolving credit facility — Expansion capital borrowings $1,229,500 $— $1,229,500 $702,500 $— $702,500Working capital borrowings 618,500 — 618,500 688,000 — 688,0005.125% Notes due 2019 388,467 (4,681) 383,786 400,000 (6,242) 393,7586.875% Notes due 2021 388,289 (7,545) 380,744 450,000 (10,280) 439,7206.650% Notes due 2022 250,000 (3,166) 246,834 250,000 (1,313) 248,687TLP credit facility (2) — — — 250,000 — 250,000Other long-term debt 61,488 (108) 61,380 9,271 — 9,271 2,936,244 (15,500) 2,920,744 2,749,771 (17,835) 2,731,936Less: Current maturities 7,907 — 7,907 4,472 — 4,472Long-term debt $2,928,337 $(15,500) $2,912,837 $2,745,299 $(17,835) $2,727,464 (1)Debt issuance costs related to revolving credit facilities are reported within intangible assets, rather than as a reduction of the carrying amount of long-term debt.(2)Due to the sale of the general partner interest in TLP, TLP was deconsolidated as of February 1, 2016 (see Note 1 and Note 14).F-30 Table of ContentsAmortization expense for debt issuance costs related to the Senior Notes is as follows for the periods indicated:Year Ended March 31,2016 2015 2014(in thousands)$4,645 $3,037 $927Expected amortization of debt issuance costs is as follows (in thousands):Year Ending March 31, 2017 $3,4102018 3,3002019 3,2962020 2,2832021 1,865Thereafter 1,346Total $15,500Credit AgreementWe 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, 2016, ourRevolving Credit Facility had a total capacity of $2.484 billion. Our Revolving Credit Facility has an “accordion” feature that allows us to increase thecapacity by $150 million if new lenders wish to join the syndicate or if current lenders wish to increase their commitments.The Expansion Capital Facility had a total capacity of $1.446 billion for cash borrowings at March 31, 2016. At that date, we had outstandingborrowings of $1.230 billion on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.038 billion for cash borrowings andletters of credit at March 31, 2016. At that date, we had outstanding borrowings of $618.5 million and outstanding letters of credit of $45.4 million on theWorking Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our consolidated balance sheets, although theydecrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a“borrowing base” (as defined in the Credit Agreement), which is calculated based on the value of certain working capital items at any point in time.The commitments under the Credit Agreement expire on November 5, 2018. We have the right to 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 either (i) an alternate base rate plus a margin of 0.50% to 1.50% per year or(ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per year. The applicable margin is determined based on our consolidated leverage ratio (asdefined in the Credit Agreement). At March 31, 2016, the borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at March 31,2016 of 2.94%, calculated as the LIBOR rate of 0.94% plus a margin of 2.0%. At March 31, 2016, 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.The Credit Agreement is secured by substantially all of our assets. In December 2015, we entered into an agreement with the banks to increase ourmaximum leverage ratio to 4.75 to 1 at any quarter end. At March 31, 2016, our leverage ratio was approximately 3.9 to 1. The Credit Agreement alsospecifies that our interest coverage ratio (as defined in the Credit Agreement) cannot be less than 2.75 to 1 at any quarter end. At March 31, 2016, our interestcoverage ratio was approximately 5.3 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 anyF-31 Table of Contentsmaterial representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.At March 31, 2016, we were in compliance with the covenants under the Credit Agreement.2019 NotesOn July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”). During the fourth quarter of fiscal year 2016, werepurchased $11.5 million of our 2019 Notes for an aggregate purchase price of $7.0 million (excluding payments of accrued interest). As a result, werecorded a gain on the early extinguishment of our 2019 Notes of $4.5 million (net of the write off of debt issuance costs of $0.1 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 Notesbefore 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, 2016, we were in compliance with the covenants under the indenture governing the 2019 Notes. 2021 NotesOn October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”). During the fourth quarter of fiscal year 2016,we repurchased $61.7 million of our 2021 Notes for an aggregate purchase price of $36.4 million (excluding payments of accrued interest). As a result, werecorded a gain on the early extinguishment of our 2021 Notes of $24.0 million (net of the write off of debt issuance costs of $1.2 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 before 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, 2016, we were in compliance with the covenants under the indenture governing the 2021 Notes.2022 NotesOn 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,theF-32 Table of ContentsNote Purchase Agreement contains similar leverage ratio and interest coverage ratio requirements to those of our Credit Agreement, which is described above.In December 2015, we amended the Note Purchase Agreement to change the covenants to mirror the changes made to the covenants in our Credit Agreement.In addition, we agreed to pay an additional 0.5% per year in interest if our leverage ratio exceeds 4.25 to 1.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, 2016, we were in compliance with the covenants under the Note Purchase Agreement.Other Long-Term DebtWe 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. These instruments have a combined principal balance of $61.5million at March 31, 2016, and the interest rates on these instruments range from 1.17% to 7.08% per year.Debt Maturity ScheduleThe scheduled maturities of our long-term debt are as follows at March 31, 2016:Year Ending March 31, RevolvingCreditFacility 2019Notes 2021Notes 2022Notes OtherLong-TermDebt Total (in thousands)2017 $— $— $— $— $7,899 $7,8992018 — — — 25,000 7,143 32,1432019 1,848,000 — — 50,000 6,053 1,904,0532020 — 388,467 — 50,000 5,621 444,0882021 — — — 50,000 34,671 84,671Thereafter — — 388,289 75,000 101 463,390Total $1,848,000 $388,467 $388,289 $250,000 $61,488 $2,936,244Note 9—Income TaxesWe 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 2012 to 2015 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-33 Table of ContentsA 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, 2016 or 2015.Note 10—Commitments and ContingenciesLegal ContingenciesWe 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, is notexpected to 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.Contractual DisputesDuring 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. During the year ended March 31, 2016, we finalized the settlement of this contractual dispute and paidapproximately $0.5 million at the date of settlement and committed to pay approximately $1.1 million in equal annual installments over a period of 11 yearsbeginning on October 15, 2016 and ending in October 2026.Environmental MattersOur consolidated balance sheet at March 31, 2016 includes a liability, measured on an undiscounted basis, of $2.3 million related to environmentalmatters, which is reported within accrued expenses and other payables. Our operations are subject to extensive federal, state, and local environmental lawsand regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additionalcosts and liabilities are inherent in our business, and there can be no assurance that we will not incur significant costs. Moreover, it is possible that otherdevelopments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property orpersons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas ofpollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent materialenvironmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage isinherent in our business.The U.S. Environmental Protection Agency (“EPA”) has informed NGL Crude Logistics, LLC (“NGL Crude”; formerly known as Gavilon Energyprior to its acquisition by us in December 2013) of alleged violations in 2011 by Gavilon Energy of the Clean Air Act’s renewable fuel standards regulations.The EPA’s allegations relate to transactions between Gavilon Energy and one of its suppliers and the generation of biodiesel renewable identificationnumbers sold by such supplier to Gavilon Energy in 2011. We have vigorously denied the allegations. In an effort to resolve this matter, the parties haverecently commenced settlement negotiations, which are ongoing.At this time, we are unable to ascertain whether the settlement discussions will produce a resolution satisfactory to us or whether the EPA will seekresolution of the matter through an enforcement action. As a result, we are also unable to determine the likely terms of any resolution or their significance tous. Although we believe we have legal defenses, it is reasonably possible that we may agree to pay the EPA some amount to settle the matter.F-34 Table of ContentsAsset Retirement ObligationsWe have contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activitieswhen the assets are retired. Our liability for asset retirement obligations is discounted to present value. To calculate the liability, we make estimates andassumptions about the retirement cost and the timing of retirement. Changes in our assumptions and estimates may occur as a result of the passage of time andthe occurrence of future events. The following table is a rollforward of our asset retirement obligation, which is reported within other noncurrent liabilities inour consolidated balance sheets (in thousands):Balance at March 31, 2014 $2,261Liabilities incurred 1,695Liabilities settled (390)Accretion expense 333Balance at March 31, 2015 3,899Liabilities incurred 1,486Liabilities settled (191)Accretion expense 380Balance at March 31, 2016 $5,574In 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 LeasesWe have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment.The following table summarizes future minimum lease payments under these agreements at March 31, 2016 (in thousands):Year Ending March 31, 2017$136,0652018120,723201998,266202087,569202177,821Thereafter127,315Total$647,759Rental expense relating to operating leases was $125.5 million, $125.5 million, and $98.3 million during the years ended March 31, 2016, 2015,and 2014, respectively.Pipeline Capacity AgreementsWe have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthlyshipping capacity on the pipelines. As a result, we are required to pay the minimum shipping fees if actual shipments are less than our allotted capacity. Thefollowing table summarizes future minimum throughput payments under these agreements at March 31, 2016 (in thousands):Year Ending March 31,2017$53,024201853,042201952,250202042,418Total$200,734F-35 Table of ContentsSales and Purchase ContractsWe have entered into product sales and purchase contracts for which we expect the parties to physically settle and deliver the inventory in futureperiods. The following table summarizes such commitments at March 31, 2016: Volume Value (in thousands)Purchase commitments: Natural gas liquids fixed-price (gallons) 22,078 $8,493Natural gas liquids index-price (gallons) 855,945 365,477Crude oil fixed-price (barrels) 1,077 41,756Crude oil index-price (barrels) 14,722 518,431Sale commitments: Natural gas liquids fixed-price (gallons) 85,162 52,633Natural gas liquids index-price (gallons) 312,198 197,861Crude oil fixed-price (barrels) 2,107 92,469Crude oil index-price (barrels) 18,754 730,583We 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 $31.5 million of our prepaid expenses and other current assets and $25.2 million of our accrued expenses and other payables at March 31, 2016.Note 11—EquityPartnership EquityThe Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Ourgeneral partner is not required to make any additional capital contributions or to guarantee or pay any of our debts and obligations.Equity IssuancesThe following table summarizes our equity issuances for fiscal years 2015 and 2014 (in millions, except unit amounts). There were no equityissuances during fiscal year 2016.Issuance Date Type ofOffering Number of Common UnitsIssued GrossProceeds UnderwritingDiscounts andCommissions OfferingCosts NetProceedsMarch 11, 2015 Public Offering 6,250,000 $172.3 $1.4 $0.2 $170.7June 23, 2014 Public Offering 8,767,100 383.2 12.3 0.5 370.4December 2, 2013 Private Placement 8,110,848 240.0 — 4.9 235.1September 25, 2013 Public Offering 4,100,000 132.8 5.0 0.2 127.6July 5, 2013 Public Offering 10,350,000 300.2 12.0 0.7 287.5Common Unit Repurchase ProgramOn September 10, 2015, the Board of Directors of our general partner authorized a common unit repurchase program pursuant to which we couldrepurchase up to $45 million of our outstanding common units through March 31, 2016 from timeF-36 Table of Contentsto time in the open market or in other privately negotiated transactions. During the year ended March 31, 2016, we repurchased 1,623,804 common units foran aggregate price of $17.7 million.DistributionsThe following table summarizes distributions declared for the last three fiscal years:Date Declared Record Date Date Paid AmountPer Unit Amount Paid toLimited Partners Amount Paid ToGeneral Partner (in thousands)April 25, 2013 May 6, 2013 May 15, 2013 $0.4775 $25,605 $1,189July 25, 2013 August 5, 2013 August 14, 2013 0.4938 31,725 1,739October 23, 2013 November 4, 2013 November 14, 2013 0.5113 35,908 2,491January 24, 2014 February 4, 2014 February 14, 2014 0.5313 42,150 4,283April 24, 2014 May 5, 2014 May 15, 2014 0.5513 43,737 5,754July 24, 2014 August 4, 2014 August 14, 2014 0.5888 52,036 9,481October 24, 2014 November 4, 2014 November 14, 2014 0.6088 53,902 11,141January 26, 2015 February 6, 2015 February 13, 2015 0.6175 54,684 11,860April 24, 2015 May 5, 2015 May 15, 2015 0.6250 59,651 13,446July 23, 2015 August 3, 2015 August 14, 2015 0.6325 66,248 15,483October 22, 2015 November 3, 2015 November 13, 2015 0.6400 67,313 16,277January 21, 2016 February 3, 2016 February 15, 2016 0.6400 67,310 16,279April 21, 2016 May 3, 2016 May 13, 2016 0.3900 40,626 70Several 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:Record Date Equivalent UnitsNot EligibleNovember 4, 2013 979,886February 6, 2015 132,100May 5, 2015 8,352,902February 3, 2016 223,077TLP’s DistributionsThe following table summarizes distributions declared by TLP after our acquisition of general and limited partner interests in TLP (exclusive of thedistribution declared in July 2014, the proceeds of which we remitted to the former owners of TransMontaigne, pursuant to agreements entered into at thetime of the business combination) through February 1, 2016, the date TLP was deconsolidated:Date Declared Record Date Date Paid AmountPer Unit Amount PaidTo NGL Amount Paid ToOther Partners (in thousands)October 13, 2014 October 31, 2014 November 7, 2014 $0.6650 $4,010 $8,614January 8, 2015 January 30, 2015 February 6, 2015 0.6650 4,010 8,614April 13, 2015 April 30, 2015 May 7, 2015 0.6650 4,007 8,617July 13, 2015 July 31, 2015 August 7, 2015 0.6650 4,007 8,617October 12, 2015 October 30, 2015 November 6, 2015 0.6650 4,007 8,617January 19, 2016 January 29, 2016 February 8, 2016 0.6700 4,104 8,681F-37 Table of ContentsEquity-Based Incentive CompensationOur 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, 2016, 2015 and 2014:Unvested Service Award units at March 31, 2013 1,444,900Units granted 494,000Units vested and issued (296,269)Units withheld for employee taxes (122,531)Units forfeited (209,000)Unvested Service Award units at March 31, 2014 1,311,100Units granted 2,093,139Units vested and issued (586,010)Units withheld for employee taxes (354,829)Units forfeited (203,000)Unvested Service Award units at March 31, 2015 2,260,400Units granted 1,484,412Units vested and issued (844,626)Units withheld for employee taxes (464,054)Units forfeited (139,000)Unvested Service Award units at March 31, 2016 2,297,132The following table summarizes the scheduled vesting of our unvested Service Award units:Year Ending March 31, Number of Units2017 1,369,4912018 763,1412019 142,5002020 21,0002021 1,000Unvested Service Award units at March 31, 2016 2,297,132We 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 estimatedfair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New YorkStock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vestingperiod. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptionsthat a market participant might make about future distributions.F-38 Table of ContentsThe following table summarizes the estimated future expense we expect to record on the unvested Service Award units at March 31, 2016 (inthousands), after taking into consideration estimated forfeitures of approximately 210,808 units. For purposes of this calculation, we used the closing price ofour common units on March 31, 2016, which was $7.52.Year Ending March 31, 2017 $8,4262018 2,0292019 4622020 452021 2Total $10,964The following table is a rollforward of the liability related to the Service Award units, which is reported within accrued expenses and other payablesin our consolidated balance sheets (in thousands):March 31, 2013 $5,043Expense recorded 17,804Value of units vested and issued (9,085)Taxes paid on behalf of participants (3,750)March 31, 2014 10,012Expense recorded 32,767Value of units vested and issued (23,134)Taxes paid on behalf of participants (13,491)March 31, 2015 6,154Expense recorded 35,177Value of units vested and issued (23,631)Taxes paid on behalf of participants (12,975)March 31, 2016 $4,725The weighted-average fair value of the Service Award units at March 31, 2016 was $5.61 per common unit, which was calculated as the closing priceof the common units on March 31, 2016, adjusted 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.During April 2015, our general partner granted 1,041,073 Performance Award units to certain employees. The number of Performance Award unitsthat will vest is contingent on the performance of our common units relative to the performance of the other entities in the Alerian Index. Performance will becalculated based on the total unitholder return (“TUR”) on our common units (including changes in the market price of the common units and distributionspaid during the performance period) relative to the TUR on the common units of the other entities in the Alerian Index. The following table presents thenumber of units granted per tranche, vesting dates and the period over which performance will be measured:Performance Units Granted Per Tranche Vesting Date of Tranche Performance Period for Tranche349,691 July 1, 2015July 1, 2012 through June 30, 2015347,691 July 1, 2016 July 1, 2013 through June 30, 2016343,691 July 1, 2017 July 1, 2014 through June 30, 2017The following table summarizes the percentage of the maximum Performance Award units that will vest will depend on the percentage of entities inthe Index that NGL outperforms:Our Relative TUR Percentile Ranking Payout (% of Target Units)Less than 50th percentile 0%Between the 50th and 75th percentile 50%–100%Between the 75th and 90th percentile 100%–200%Above the 90% percentile 200%F-39 Table of ContentsThe April 2015 Performance Award grants included a tranche that vested on July 1, 2015. During the July 1, 2012 through June 30, 2015performance period, the return on our common units exceeded the return on 83% of our peer companies in the Index. As a result, the July 1, 2015 tranche ofthe Performance Awards vested at 151% of the maximum number of awards, and 530,564 common units vested on July 1, 2015. Of these units, recipientselected for us to withhold 210,137 common units for employee taxes, valued at $6.4 million. We issued the remaining 320,427 common units, valued at $9.7million, on July 1, 2015.The following table summarizes the maximum number of units that could vest on these Performance Awards for each vesting tranche, taking intoconsideration any Performance Awards that have been forfeited since the grant date:Vesting Date of Tranche Maximum PerformanceAward UnitsJuly 1, 2016 641,382July 1, 2017 633,382Total 1,274,764The following table summarizes the estimated fair value for each unvested tranche at March 31, 2016, without consideration of estimated forfeitures:Vesting Date of Tranche Fair Value ofUnvested Awards (in thousands)July 1, 2016 $263July 1, 2017 285Total $548We record the expense for each of the tranches of the Performance Awards on a straight-line basis over the period beginning with the grant date andending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of theawards at the balance sheet date. We calculate the fair value of the awards using a Monte Carlo simulation. The following table summarizes the expenserecorded during the year ended March 31, 2016 (in thousands):Vesting Date of Tranche July 1, 2015 $16,077July 1, 2016 197July 1, 2017 114Total $16,388The following table is a rollforward of the liability related to the Performance Awards units, which is reported within accrued expenses and otherpayables in our consolidated balance sheet (in thousands):Balance at March 31, 2015 $—Expense recorded 16,388Value of units vested and issued (9,659)Taxes paid on behalf of participants (6,420)Balance at March 31, 2016 $309The 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, 2016, approximately 4.6 million common units remain available for issuance under the LTIP.F-40 Table of ContentsNote 12—Fair Value of Financial InstrumentsOur 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 DerivativesThe following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported in our consolidated balancesheet at the dates indicated: March 31, 2016 March 31, 2015 DerivativeAssets DerivativeLiabilities DerivativeAssets DerivativeLiabilities (in thousands)Level 1 measurements $47,361 $(3,983) $83,779 $(3,969)Level 2 measurements 32,700 (28,612) 34,963 (28,764) 80,061 (32,595) 118,742 (32,733) Netting of counterparty contracts (1) (3,384) 3,384 (1,804) 1,804Net cash collateral provided (held) (18,176) 599 (56,660) 2,979Commodity derivatives in consolidated balance sheet $58,501 $(28,612) $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 netting arrangement with thecounterparty.The following table summarizes the accounts that include our commodity derivative assets and liabilities in our consolidated balance sheets: March 31, 2016 2015 (in thousands)Prepaid expenses and other current assets $58,501 $60,278Accrued expenses and other payables (28,612) (27,950)Net commodity derivative asset $29,889 $32,328F-41 Table of ContentsThe following table summarizes our open commodity derivative contract positions at the dates indicated. We do not account for these derivatives ashedges.Contracts Settlement Period Net Long(Short)Notional(Barrels) Fair ValueofNet Assets(Liabilities) (in thousands)At March 31, 2016- Cross-commodity (1) April 2016–March 2017 251 $1,663Crude oil fixed-price (2) April 2016–December 2016 (1,583) (3,655)Propane fixed-price (2) April 2016–December 2017 540 (592)Refined products fixed-price (2) April 2016–June 2017 (5,355) 48,557Other April 2016–March 2017 1,493 47,466Net cash collateral held (17,577)Net commodity derivatives in consolidated balance sheet $29,889 At March 31, 2015- Cross-commodity (1) April 2015–March 2016 98 $(105)Crude oil fixed-price (2) April 2015–June 2015 (1,113) (171)Crude oil index-price (3) April 2015–July 2015 751 1,835Propane fixed-price (2) April 2015–December 2016 193 (2,842)Refined products fixed-price (2) April 2015–December 2015 (3,005) 84,996Other April 2015–December 2015 2,296 86,009Net cash collateral held (53,681)Net commodity derivatives in consolidated balance sheet $32,328 (1)Cross-commodity - We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodityprice indices. These contracts are derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative toanother commodity price.(2)Commodity fixed-price - We may have fixed price physical purchases, including inventory, offset by floating price physical sales or floating pricephysical purchases offset by fixed price physical sales. These contracts are derivatives we have entered into as an economic hedge against the risk ofmismatches between fixed and floating price physical obligations.(3)Commodity fixed-price - We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different indices.These indices may vary in the commodity grade or location, or in the timing of delivery within a given month. These contracts are derivatives we haveentered into as an economic hedge against the risk of one index moving relative to another index.The following table summarizes the net gains (losses) recorded from our commodity derivatives to cost of sales for the periods indicated (inthousands):Year Ending March 31, 2016 $103,2232015 219,4212014 (43,655)F-42 Table of ContentsCredit RiskWe have credit policies that we believe minimize our overall credit risk, including an evaluation of potential counterparties’ financial position(including credit ratings), collateral requirements under certain circumstances, and the use of industry standard master netting agreements, which allow foroffsetting counterparty receivable and payable balances for certain transactions. At March 31, 2016, our primary counterparties were retailers, resellers,energy marketers, producers, refiners, and dealers. This concentration of counterparties may impact our overall exposure to credit risk, either positively ornegatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a counterparty does not perform on acontract, we may not realize amounts that have been recorded in our consolidated balance sheets and recognized in our net income.Interest Rate RiskOur Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31,2016, we had $1.8 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.94%.Fair Value of Fixed-Rate NotesThe following table summarizes fair values estimates of our fixed-rate notes at March 31, 2016 (in thousands):5.125% Notes due 2019 $235,0236.875% Notes due 2021 233,6216.650% Notes due 2022 156,638For the 2019 Notes and the 2021 Notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1in the fair value hierarchy. For the 2022 Notes, the fair value estimate was developed using observed yields on publicly traded notes issued by us, adjustedfor differences 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 theissuer, 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 thefair value hierarchy.Note 13—SegmentsThe following table summarizes certain financial data related to our segments. Transactions between segments are recorded based on pricesnegotiated between the segments.Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and significantly expanded with ourJuly 2014 acquisition of TransMontaigne. On February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, wedeconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting.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 not allocated to the reportable segments.F-43 Table of Contents Year Ended March 31, 2016 2015 2014 (in thousands)Revenues (1): Crude oil logistics- Crude oil sales $3,170,891 $6,621,871 $4,559,923Crude oil transportation and other 55,882 43,349 36,469Elimination of intersegment sales (9,694) (29,836) (37,847)Total crude oil logistics revenues 3,217,079 6,635,384 4,558,545Water solutions- Service fees 136,710 105,682 58,161Recovered hydrocarbons 41,090 81,762 67,627Water transportation — 10,760 17,312Other revenues 7,201 1,838 —Total water solutions revenues 185,001 200,042 143,100Liquids- Propane sales 618,919 1,265,262 1,632,948Other product sales 620,175 1,111,834 1,231,965Other revenues 35,943 28,745 31,062Elimination of intersegment sales (80,558) (162,016) (245,550)Total liquids revenues 1,194,479 2,243,825 2,650,425Retail propane- Propane sales 248,673 347,575 388,225Distillate sales 64,868 106,037 127,672Other revenues 39,436 35,585 35,918Total retail propane revenues 352,977 489,197 551,815Refined products and renewables- Refined products sales 6,294,008 6,682,040 1,180,895Renewables sales 390,753 473,885 176,781Service fees 108,221 76,847 —Elimination of intersegment sales (870) (1,079) —Total refined products and renewables revenues 6,792,112 7,231,693 1,357,676Corporate and other 462 1,916 437,713Total revenues $11,742,110 $16,802,057 $9,699,274Depreciation and Amortization: Crude oil logistics $39,363 $38,626 $22,111Water solutions 91,685 73,618 55,105Liquids 15,642 13,513 11,018Retail propane 35,992 31,827 28,878Refined products and renewables 40,861 32,948 625Corporate and other 5,381 3,417 3,017Total depreciation and amortization $228,924 $193,949 $120,754Operating Income (Loss): Crude oil logistics $(40,745) $(35,832) $678Water solutions (313,673) 65,340 10,317Liquids 76,173 45,072 71,888Retail propane 44,096 64,075 61,285Refined products and renewables 226,951 54,567 6,514Corporate and other (97,405) (85,802) (44,117)Total operating (loss) income $(104,603) $107,420 $106,565 (1)During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to the categories shown in the table above.These changes did not impact total revenues. We have retrospectively adjusted previously reported amounts to conform to the current presentation.F-44 Table of ContentsThe following table summarizes additions to property, plant and equipment by segment. This information has been prepared on the accrual basis,and includes property, plant and equipment acquired in acquisitions. Year Ended March 31, 2016 2015 2014 (in thousands)Additions to property, plant and equipment: Crude oil logistics $447,952 $58,747 $204,642Water solutions 211,080 186,007 100,877Liquids 50,533 114,180 52,560Retail propane 41,235 35,602 24,430Refined products and renewables 25,147 573,954 1,238Corporate and other 15,172 1,286 7,242Total $791,119 $969,776 $390,989The following tables summarize long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets bysegment: March 31, 2016 2015 (in thousands)Long-lived assets, net: Crude oil logistics $1,679,027 $1,327,538Water solutions 1,162,405 1,244,965Liquids 572,081 534,317Retail propane 483,330 467,254Refined products and renewables 180,783 808,126Corporate and other 36,198 32,357Total $4,113,824 $4,414,557 Total assets: Crude oil logistics $2,197,113 $2,337,188Water solutions 1,236,875 1,311,175Liquids 693,872 713,810Retail propane 538,267 542,078Refined products and renewables 765,806 1,669,851Corporate and other 128,222 81,690Total $5,560,155 $6,655,792 F-45 Table of ContentsNote 14—Disposals and ImpairmentsSale of General Partner Interest in TLPOn February 1, 2016, we completed the sale of our general partner interest in TLP to ArcLight for $350 million in cash and recorded a gain ondisposal of $329.9 million during the three months ended March 31, 2016. As part of this transaction, we entered into lease agreements whereby we willremain the long-term exclusive tenant in the TLP Southeast terminal system. As a result of entering into these leases, we deferred $204.6 million of the gainon the sale and will recognize this amount over our future lease payment obligations, which is approximately seven years. During the three months endedMarch 31, 2016, we recognized $5.0 million of the deferred gain in our consolidated statement of operations. Expected amortization of the deferred gain is asfollows (in thousands):Year Ending March 31,2017$30,113201830,113201930,113202030,113202129,593Thereafter49,487Total$199,532Within our consolidated balance sheet, the current portion of the deferred gain, $30.1 million, is recorded in accrued expenses and other payablesand the long-term portion, $169.4 million, is recorded in other noncurrent liabilities. In addition, we retained TransMontaigne’s marketing business, which isa significant part of our refined products and renewables segment, and TransMontaigne Product Services, LLC, its customer contracts and its line space on theColonial and Plantation pipelines. See Note 19 for a discussion of the sale of all common units we held in TLP to an affiliate of ArcLight.Other DisposalsDuring the year ended March 31, 2016 in our crude oil logistics segment, (i) two previously-planned projects were canceled and we recorded a lossof $3.1 million and (ii) we sold and/or abandoned certain trucks, trailers and barges and recorded a loss of $1.4 million. These losses are reported within losson disposal or impairment of assets, net in our consolidated statement of operations.During the year ended March 31, 2016 in our refined products and renewables segment, we recorded a loss of $1.8 million related to certainproperty, plant and equipment that we have retired and we also sold certain tank bottoms and recorded a loss of $1.3 million. These losses are reported withinloss on disposal or impairment of assets, net in our consolidated statement of operations.During the year ended March 31, 2016, we received a payment of $3.0 million from the state of Maine to relocate certain terminal assets in ourliquids segment. This payment 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 a natural gas liquids terminal and recorded a loss in our consolidated statement of operations of$29.8 million, which included a loss on property, plant and equipment of $21.7 million and a loss of $8.1 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 in 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.F-46 Table of ContentsDuring 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 in our water solutions segment. This loss is reported within loss on disposal or impairment of assets, net in ourconsolidated statement of operations.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.Long-lived Asset ImpairmentsDuring the fourth quarter of fiscal year 2016, we recorded a write-down of $47.7 million related to pipe we no longer expect to use in the originally-planned Grand Mesa Pipeline, which is reported within loss on disposal or impairment of assets, net.During the year ended March 31, 2016, we recorded an impairment of $2.4 million to the property, plant and equipment of two of our crude oilbarges in our crude oil logistics 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, 2016, we wrote off assets of $14.6 million acquired as part of the Gavilon Energy acquisition that we deemed nolonger recoverable 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, 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.Goodwill ImpairmentDue to the continued decline in crude oil prices and crude oil production, we tested the goodwill within our water solutions reporting unit forimpairment at December 31, 2015. At December 31, 2015, our water solutions reporting unit had a goodwill balance of $660.8 million. We estimated the fairvalue of our water solutions reporting unit based on the income approach, also known as the discounted cash flow method, which utilizes the present value ofcash flows to estimate the fair value. The future cash flows of our water solutions reporting unit were projected based upon estimates as of the test date offuture revenues, operating expenses and cash outflows necessary to support these cash flows, including working capital and maintenance capitalexpenditures. We also considered expectations regarding: (i) expected disposal volumes, which have continued in spite of the lower crude oil priceenvironment as oilfield producers have focused on their most productive properties and have continued to deliver disposal volumes to our facilities, and (ii)the crude oil price environment as reflected in crude oil forward prices as of the test date. In performing the discounted cash flow analysis, we utilized reportsissued by independent third parties projecting crude oil prices through 2018. We assumed an approximate $1/barrel increase each quarter for the periodsbeyond those represented in the reports, with crude oil reaching $65/barrel by the fourth quarter of 2021. WeF-47 Table of Contentsused a price of $32/barrel for the fourth quarter of 2016, the starting point of our cash flow projections. We kept prices constant at $65/barrel for periods inour model beyond 2021. Consistent with observed disposal volume trends, the disposal volumes were based on an expectation of a certain amount ofproduction returning at certain crude oil price levels. For expenses, we assumed an increase consistent with the increase in disposal volumes. The discountrate used in our discounted cash flow method was calculated by using the average of the range of discount rates from a recent water solutions transactionsimilar in size to our water solutions reporting unit. The discounted cash flow results indicated that the estimated fair value of our water solutions reportingunit was greater than its carrying value by approximately 9% at December 31, 2015.As a result of the continued decline in crude oil production, its continued adverse impact on our water solutions reporting unit and the completionof our annual budget process we decided to test the goodwill within our water solutions reporting unit for impairment as of March 31, 2016 as it was morelikely than not that the fair value of our water solutions reporting unit was less than the carry amount. Similar to the testing performed as of December 31,2015, fair value of the water solutions reporting unit was based on the income approach, which utilizes the present value of cash flows to estimate the fairvalue. We utilized the same pricing, expense and discount rate assumptions in our current model as described above but adjusted our expected water volumesand percentage recovered hydrocarbons to match what we have budgeted for our fiscal year 2017. Volumes budgeted for fiscal year 2017 were heavilyinfluenced by the reporting unit’s fourth quarter 2017 operating results. We utilized the same assumptions related to anticipated volume growth as above.The discounted cash flow results indicated that the estimated fair value of our water business was less than its carrying value by approximately 11% atMarch 31, 2016.During the year ended March 31, 2016, we recorded an estimated goodwill impairment charge of $380.2 million, which is recorded within loss ondisposal or impairment of assets in our consolidated statements of operations. We plan to finalize our goodwill impairment analysis prior to issuing ourfinancial statements for the quarter ending June 30, 2016, and will adjust our estimated impairment as needed. At March 31, 2016 our water solutionsreporting units had a goodwill balance of $290.9 million.Our estimated fair value is predicated upon crude oil prices increasing over the next six years based on the third party forecasts utilized andmanagement’s assumption of a price recovery to $65/barrel by 2021. We used this increase in crude oil prices to estimate the volume of wastewater to beprocessed at our facilities, based on the expected increased production by our customers, and the revenue generated by selling the hydrocarbons extractedfrom the wastewater. The projected prices we used were from reports generated by independent third parties and were based on their assessment of the marketand their expectation of the market going forward. Due to the current volatility in the crude oil market, we believe that it is reasonably possible that crude oilprices could decline. Further declines in crude oil prices would negatively affect the timing of the recovery of crude oil prices and the estimated waterdisposal volumes we used in our estimates, such that our estimate of fair value could change and result in further impairment of the goodwill in our watersolutions reporting unit.For our other reporting units, we performed a qualitative assessment as of January 1, 2016 to determine whether it is more likely than not that the fairvalue of each reporting unit is greater than the book value of the reporting unit. Based on these qualitative assessments we determined that the fair value ofeach of these reporting units was more likely than not greater than the carrying value of the reporting units.We did not record any goodwill impairments during the years ended March 31, 2015 and March 31, 2014.Note 15—Transactions with AffiliatesSemGroup 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, respectively, in our consolidated statements of operations. We also lease crude oilstorage from SemGroup.We purchase ethanol from an equity method investee. These transactions are reported within cost of sales in our consolidated statements ofoperations.Certain members of our management and members of their families own interests in entities from which we have purchased products and services andto which we have sold products and services. During the year ended March 31, 2016, $32.7 million of these transactions were capital expenditures and wererecorded as increases to property, plant and equipment.F-48 Table of ContentsThe following table summarizes these related party transactions: Year Ended March 31, 2016 2015 2014 (in thousands)Sales to SemGroup $43,825 $88,276 $160,993Purchases from SemGroup 53,209 130,134 300,164Sales to equity method investees 14,836 14,493 —Purchases from equity method investees 113,780 149,828 47,731Sales to entities affiliated with management 318 2,151 110,824Purchases from entities affiliated with management 45,197 29,419 120,038Accounts receivable from affiliates consist of the following at the dates indicated: March 31, 2016 2015 (in thousands)Receivables from SemGroup $1,166 $13,443Receivables from equity method investees 14,446 652Receivables from entities affiliated with management 13 3,103Total $15,625 $17,198Accounts payable to affiliates consist of the following at the dates indicated: March 31, 2016 2015 (in thousands)Payables to SemGroup $1,823 $11,546Payables to equity method investees 3,947 6,788Payables to entities affiliated with management 1,423 7,460Total $7,193 $25,794We also have a loan receivable of $22.3 million at March 31, 2016 from an equity method investee. During the year ended March 31, 2016, wereceived loan payments of $1.5 million from our investee in accordance with the loan agreement. The investee makes loan payments from time to time inaccordance with the loan agreement and is required to make monthly principal payments beginning on June 1, 2018 with the remaining principal balancedue on May 31, 2020.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.Note 16—Other MattersGrand Mesa PipelineIn 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”). In October 2014, we obtained ship-or-pay volume commitments from multiple shippers to begin construction of theGrand Mesa Pipeline, which will originate in Colorado and terminate in Cushing, Oklahoma. In November 2014, we acquired RimRock’s 50% ownershipinterest in Grand Mesa for $310.0 million in cash. In November 2015, Grand Mesa Pipeline entered into an agreement with Saddlehorn Pipeline Company,LLC (“Saddlehorn”), under which we acquired a 37.5% undivided interest in a crude oil pipeline currently under construction (the “Joint Pipeline”). TheJoint Pipeline will take receipt from Grand Mesa Pipeline’s origin in Colorado and will deliver to Cushing, Oklahoma. We will have the right to utilize150,000 barrels per day of capacity on the Joint Pipeline. Operating costs will be allocated to us based on our proportionate ownership interest andthroughput. We expect the Joint Pipeline to be operational beginning in the third quarter of fiscal year 2017.F-49 Table of ContentsThrough our undivided interest in the Joint Pipeline, we will have expanded capacity, sufficient to service our customer contracts at the same originand termination points with the ability to accept additional volume commitments. We will retain ownership of our previously-acquired easements for thepotential future development of transportation projects involving petroleum commodities other than crude oil and condensate. With the consent andparticipation of Saddlehorn, we and Saddlehorn may consider future opportunities using these easements for projects involving the transportation of crudeoil and condensate.During the six months ended March 31, 2016, we reclassified $47.0 million of costs to acquire land, rights-of-way and easements on the originally-planned Grand Mesa Pipeline route to intangible assets. As discussed above, we acquired an undivided interest in a different crude oil pipeline with the sameorigin and destination points as those of our originally-planned Grand Mesa Pipeline route. We will retain the land, rights-of-way and easements along theoriginally-planned Grand Mesa Pipeline route for potential future development.Purchase of Pipeline Capacity AllocationsOn 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 FacilityIn 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 a cash payment in March 2015 and additional cash payments over the next five years. In addition, one of the producers committed to pay us aspecified 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, werecorded a gain of $31.6 million to other income in our consolidated statement of operations, net of certain project abandonment costs.Note 17—Error CorrectionSubsequent to the issuance of certain previously issued financial statements, we determined that there were errors in those financial statements fromnot recording certain contingent consideration liabilities related to royalty agreements assumed as part of acquisitions in our water solutions segment. Theeffect of the error was material to the financial statements for each of the first three fiscal quarters of 2016 so those quarters have been restated for the effects ofthe error correction. The effect of the error was not material to the financial statements for the fiscal year 2015 or for the quarters within fiscal year 2015. As aresult, fiscal year 2015 and the quarters within fiscal year 2015 have been changed for the correction of an immaterial error in accordance with themethodology described in SAB Topic 1N, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current YearFinancial Statements.We have changed our previously issued (i) consolidated balance sheet at March 31, 2015, (ii) consolidated statement of operations, consolidatedstatement of comprehensive income, consolidated statement of changes in equity and consolidated statement of cash flows for the year ended March 31,2015, and (iii) unaudited financial information for the quarters within fiscal year 2015. We are restating our previously issued unaudited financialinformation for the first three fiscal quarters of 2016. The following tables summarize the impact of the error correction on our consolidated financialstatements, each as compared with the amounts presented in previously issued financial statements. Certain of the as previously reported balances includepurchase accounting adjustments and the adoption of ASU 2015-03 related to debt issuance costs (see Note 2).The following tables summarize the as previously reported balances, adjustments, and corrected and restated balances on our consolidated balancesheets by financial statement line item (in thousands):F-50 Table of Contents December 31, 2015 (Unaudited) As Reported Adjustment As RestatedGoodwill$1,522,644 $177,509 $1,700,153Total assets6,547,043 177,509 6,724,552Accrued expenses and other payables193,295 4,563 197,858Total current liabilities796,908 4,563 801,471Other noncurrent liabilities13,232 99,692 112,924Equity - general partner interest(34,431) 77 (34,354)Equity - limited partners interest1,920,528 71,734 1,992,262Equity - noncontrolling interests544,890 1,443 546,333Total equity2,430,839 73,254 2,504,093Total liabilities and equity6,547,043 177,509 6,724,552 September 30, 2015 (Unaudited) As Reported Adjustment As RestatedGoodwill$1,490,928 $167,309 $1,658,237Total assets6,433,747 167,309 6,601,056Accrued expenses and other payables164,433 5,469 169,902Total current liabilities852,170 5,469 857,639Other noncurrent liabilities17,679 109,960 127,639Equity - general partner interest(34,380) 55 (34,325)Equity - limited partners interest1,976,663 51,080 2,027,743Equity - noncontrolling interests544,147 745 544,892Total equity2,486,294 51,880 2,538,174Total liabilities and equity6,433,747 167,309 6,601,056 June 30, 2015 (Unaudited) As Reported Adjustment As RestatedGoodwill$1,451,654 $148,809 $1,600,463Total assets6,625,715 148,809 6,774,524Accrued expenses and other payables237,407 5,898 243,305Total current liabilities1,088,700 5,898 1,094,598Other noncurrent liabilities17,082 109,083 126,165Equity - general partner interest(35,097) 36 (35,061)Equity - limited partners interest2,056,852 33,653 2,090,505Equity - noncontrolling interests547,162 139 547,301Total equity2,568,800 33,828 2,602,628Total liabilities and equity6,625,715 148,809 6,774,524F-51 Table of Contents March 31, 2015 As Reported Adjustment As CorrectedGoodwill$1,433,224 $125,009 $1,558,233Total assets6,530,783 125,009 6,655,792Accrued expenses and other payables196,357 5,992 202,349Total current liabilities1,113,875 5,992 1,119,867Other noncurrent liabilities16,321 98,708 115,029Equity - general partner interest(37,021) 21 (37,000)Equity - limited partners interest2,162,924 20,624 2,183,551Equity - noncontrolling interests547,326 (336) 546,990Total equity2,673,120 20,309 2,693,432Total liabilities and equity6,530,783 125,009 6,655,792 December 31, 2014 (Unaudited) As Reported Adjustment As CorrectedGoodwill$1,250,239 $111,308 $1,361,547Total assets6,905,902 111,308 7,017,210Accrued expenses and other payables277,304 5,661 282,965Total current liabilities1,901,168 5,661 1,906,829Other noncurrent liabilities11,811 99,805 111,616Equity - general partner interest(39,035) 6 (39,029)Equity - limited partners interest1,709,150 5,638 1,714,788Equity - noncontrolling interests569,575 198 569,773Total equity2,239,601 5,842 2,245,443Total liabilities and equity6,905,902 111,308 7,017,210 September 30, 2014 (Unaudited) As Reported Adjustment As CorrectedGoodwill$1,170,490 $83,783 $1,254,273Total assets6,551,679 83,783 6,635,462Accrued expenses and other payables218,482 4,922 223,404Total current liabilities1,759,980 4,922 1,764,902Other noncurrent liabilities39,518 75,211 114,729Equity - general partner interest(39,690) 4 (39,686)Equity - limited partners interest1,785,823 3,550 1,789,373Equity - noncontrolling interests568,770 96 568,866Total equity2,314,830 3,650 2,318,480Total liabilities and equity6,551,679 83,783 6,635,462F-52 Table of Contents June 30, 2014 (Unaudited) As Reported Adjustment As CorrectedGoodwill$1,101,471 $56,830 $1,158,301Total assets4,265,502 56,830 4,322,332Accrued expenses and other payables123,939 4,621 128,560Total current liabilities1,034,335 4,621 1,038,956Other noncurrent liabilities8,000 50,862 58,862Equity - general partner interest(41,308) 1 (41,307)Equity - limited partners interest1,822,572 1,223 1,823,795Equity - subordinated interest(5,248) 98 (5,150)Equity - noncontrolling interests5,327 25 5,352Total equity1,781,292 1,347 1,782,639Total liabilities and equity4,265,502 56,830 4,322,332The following tables summarize the as previously reported balances, adjustments and corrected and restated balances on our consolidated statementsof operations by financial statement line item for the periods ended (in thousands, except per unit amounts): Three Months Ended December 31, 2015 (Unaudited) As Reported Adjustment As RestatedOperating expenses$106,783 $(2,062) $104,721Revaluation of liabilities— (19,312) (19,312)Income before income taxes30,023 21,374 51,397Net income29,621 21,374 50,995Net income allocated to general partner16,217 22 16,239Net income attributable to noncontrolling interests6,140 698 6,838Net income allocated to limited partners7,264 20,654 27,918Basic income per common unit0.07 0.20 0.27Diluted income per common unit0.03 0.19 0.22 Three Months Ended September 30, 2015 (Unaudited) As Reported Adjustment As RestatedOperating expenses$99,773 $(2,143) $97,630Revaluation of liabilities— (15,909) (15,909)Loss before income taxes(26,938) 18,052 (8,886)Net loss(24,152) 18,052 (6,100)Net income allocated to general partner16,166 19 16,185Net income attributable to noncontrolling interests2,891 606 3,497Net loss allocated to limited partners(43,209) 17,427 (25,782)Basic and diluted loss per common unit(0.41) 0.16 (0.25)F-53 Table of Contents Three Months Ended June 30, 2015 (Unaudited) As Reported Adjustment As RestatedOperating expenses$107,914 $(2,324) $105,590Revaluation of liabilities— (11,195) (11,195)Loss before income taxes(37,988) 13,519 (24,469)Net loss(38,526) 13,519 (25,007)Net income allocated to general partner15,359 15 15,374Net income attributable to noncontrolling interests3,875 475 4,350Net loss allocated to limited partners(57,760) 13,029 (44,731)Basic and diluted loss per common unit(0.56) 0.13 (0.43) Three Months Ended March 31, 2015 (Unaudited) As Reported Adjustment As CorrectedOperating expenses$109,560 $(2,203) $107,357Revaluation of liabilities— (12,264) (12,264)Income before income taxes90,297 14,467 104,764Net income90,942 14,467 105,409Net income allocated to general partner13,459 15 13,474Net income attributable to noncontrolling interests4,164 (534) 3,630Net income allocated to limited partners73,319 14,986 88,305Basic and diluted income per common unit0.78 0.15 0.93 Three Months Ended December 31, 2014 (Unaudited) As Reported Adjustment As CorrectedOperating expenses$97,761 $(2,192) $95,569Loss before income taxes(7,359) 2,192 (5,167)Net loss(5,269) 2,192 (3,077)Net income allocated to general partner11,783 2 11,785Net income attributable to noncontrolling interests5,649 102 5,751Net loss allocated to limited partners(22,701) 2,088 (20,613)Basic and diluted loss per common unit(0.26) 0.03 (0.23)F-54 Table of Contents Three Months Ended September 30, 2014 (Unaudited) As Reported Adjustment As CorrectedOperating expenses$97,419 $(2,303) $95,116Loss before income taxes(17,801) 2,303 (15,498)Net loss(15,879) 2,303 (13,576)Net income allocated to general partner11,056 3 11,059Net income attributable to noncontrolling interests3,345 71 3,416Net loss allocated to limited partners(30,280) 2,229 (28,051)Basic and diluted loss per common unit(0.34) 0.02 (0.32) Three Months Ended June 30, 2014 (Unaudited) As Reported Adjustment As CorrectedOperating expenses$67,436 $(1,347) $66,089Loss before income taxes(38,875) 1,347 (37,528)Net loss(39,910) 1,347 (38,563)Net income allocated to general partner9,381 1 9,382Net income attributable to noncontrolling interests65 25 90Net loss allocated to limited partners(49,356) 1,321 (48,035)Basic and diluted loss per common unit(0.61) 0.01 (0.60) Six Months Ended September 30, 2015 (Unaudited) As Reported Adjustment As RestatedOperating expenses$207,687 $(4,467) $203,220Revaluation of liabilities— (27,104) (27,104)Loss before income taxes(64,926) 31,571 (33,355)Net loss(62,678) 31,571 (31,107)Net income allocated to general partner31,525 34 31,559Net income attributable to noncontrolling interests6,766 1,081 7,847Net loss allocated to limited partners(100,969) 30,456 (70,513)Basic and diluted loss per common unit(0.97) 0.30 (0.67)F-55 Table of Contents Six Months Ended September 30, 2014 (Unaudited) As Reported Adjustment As CorrectedOperating expenses$164,855 $(3,650) $161,205Loss before income taxes(56,676) 3,650 (53,026)Net loss(55,789) 3,650 (52,139)Net income allocated to general partner20,437 4 20,441Net income attributable to noncontrolling interests3,410 96 3,506Net loss allocated to limited partners(79,636) 3,550 (76,086)Basic and diluted loss per common unit(0.93) 0.04 (0.89) Nine Months Ended December 31, 2015 (Unaudited) As Reported Adjustment As RestatedOperating expenses$314,470 $(6,529) $307,941Revaluation of liabilities— (46,416) (46,416)(Loss) income before income taxes(34,903) 52,945 18,042Net (loss) income(33,057) 52,945 19,888Net income allocated to general partner47,742 56 47,798Net income attributable to noncontrolling interests12,906 1,779 14,685Net loss allocated to limited partners(93,705) 51,110 (42,595)Basic and diluted loss per common unit(0.90) 0.49 (0.41) Nine Months Ended December 31, 2014 (Unaudited) As Reported Adjustment As CorrectedOperating expenses$262,616 $(5,842) $256,774Loss before income taxes(64,035) 5,842 (58,193)Net loss(61,058) 5,842 (55,216)Net income allocated to general partner32,220 6 32,226Net income attributable to noncontrolling interests9,059 198 9,257Net loss allocated to limited partners(102,337) 5,638 (96,699)Basic and diluted loss per common unit(1.17) 0.06 (1.11)F-56 Table of Contents Year Ended March 31, 2015 As Reported Adjustment As CorrectedOperating expenses$372,176 $(8,045) $364,131Revaluation of liabilities— (12,264) (12,264)Income before income taxes26,262 20,309 46,571Net income29,884 20,309 50,193Net income allocated to general partner45,679 21 45,700Net income attributable to noncontrolling interests13,223 (336) 12,887Net loss allocated to limited partners(29,018) 20,624 (8,394)Basic and diluted loss per common unit(0.29) 0.24 (0.05)The following table summarizes the as previously reported balances, adjustments and corrected balances on the consolidated statement ofcomprehensive income by financial statement line item for the year ended March 31, 2015 (in thousands): Year Ended March 31, 2015 As Reported Adjustment As CorrectedNet income$29,884 $20,309 $50,193Comprehensive income30,011 20,309 50,320The only changes to the consolidated statements of comprehensive income for all periods, including the interim periods for fiscal 2015 and 2016,are the changes to net income (loss) shown in the tables above.The following table summarizes the as previously reported balances, adjustments and corrected balances on our consolidated statement of changesin equity by financial statement line item for the year ended March 31, 2015 (in thousands): Year Ended March 31, 2015 As Reported Adjustment As CorrectedNet income allocated to general partner$45,679 $21 $45,700Net income attributable to noncontrolling interests13,223 (336) 12,887Net loss allocated to limited partners(29,018) 20,624 (8,394)Net income29,884 20,309 50,193Equity - general partner interest(37,021) 21 (37,000)Equity - limited partners interest2,162,924 20,624 2,183,551Equity - noncontrolling interests547,326 (336) 546,990Total equity2,673,120 20,309 2,693,432The following table summarizes the as previously reported balances, adjustments and corrected balances on our consolidated statement of cash flowsby financial statement line item for the year ended March 31, 2015 (in thousands):F-57 Table of Contents Year Ended March 31, 2015 As Reported Adjustment As CorrectedNet income$29,884 $20,309 $50,193Revaluation of liabilities— (12,264) (12,264)Accrued expenses and other liabilities(53,844) (8,045) (61,889)The only changes to the consolidated statements of cash flows for all periods, including the interim periods for fiscal 2015 and 2016, are the changesto net income (loss) and the reconciling items from net income (loss) to cash flows from operations: revaluation of liabilities and changes in accrued expensesand other liabilities. Total cash flows from operating, investing and financing activities are unchanged for all periods.Note 18—Quarterly Information (Unaudited) (As Corrected and Restated)The following tables summarize our corrected and restated historical consolidated balance sheets and consolidated statements of operations for theinterim quarters impacted by the changes discussed in Note 17. Certain of the as corrected and restated balances include purchase accounting adjustmentsand the adoption of ASU 2015-03 related to debt issuance costs (see Note 2). The computation of net income (loss) per common unit is done separately byquarter and year. The total of net income (loss) per common unit of the individual quarters may not equal net income (loss) 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. The numbers in the tables below, with the exception of the units outstanding andthe per unit numbers are represented in thousands.F-58 Table of Contents As Restated March 31, December 31, September 30, June 30, 2016 2015 2015 2015ASSETS CURRENT ASSETS: Cash and cash equivalents$28,176 $25,179 $30,053 $43,506Accounts receivable-trade, net of allowance for doubtful accounts521,014 581,621 712,025 905,196Accounts receivable-affiliates15,625 3,812 6,345 18,740Inventories367,806 414,088 408,374 489,064Prepaid expenses and other current assets95,859 117,476 120,122 130,889Assets held for sale— 87,383 — —Total current assets1,028,480 1,229,559 1,276,919 1,587,395 PROPERTY, PLANT AND EQUIPMENT, net of accumulateddepreciation1,649,572 1,972,925 1,845,112 1,743,584GOODWILL1,315,362 1,700,153 1,658,237 1,600,463INTANGIBLE ASSETS, net of accumulated amortization1,148,890 1,225,012 1,215,102 1,234,542INVESTMENTS IN UNCONSOLIDATED ENTITIES219,550 467,559 473,239 474,221LOAN RECEIVABLE-AFFILIATE22,262 23,258 23,775 23,775OTHER NONCURRENT ASSETS176,039 106,086 108,672 110,544Total assets$5,560,155 $6,724,552 $6,601,056 $6,774,524 LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable-trade$420,306 $511,309 $568,523 $755,062Accounts payable-affiliates7,193 11,042 18,794 25,592Accrued expenses and other payables214,426 197,858 169,902 243,305Advance payments received from customers56,185 73,662 96,380 66,706Current maturities of long-term debt7,907 7,600 4,040 3,933Total current liabilities706,017 801,471 857,639 1,094,598 LONG-TERM DEBT, net of debt issuance costs and current maturities2,912,837 3,306,064 3,077,604 2,951,133OTHER NONCURRENT LIABILITIES247,236 112,924 127,639 126,165 COMMITMENTS AND CONTINGENCIES— — — — EQUITY: General partner, representing a 0.1% interest(50,811) (34,354) (34,325) (35,061)Limited partners, representing a 99.9% interest1,707,326 1,992,262 2,027,743 2,090,505Accumulated other comprehensive loss(157) (148) (136) (117)Noncontrolling interests37,707 546,333 544,892 547,301Total equity1,694,065 2,504,093 2,538,174 2,602,628Total liabilities and equity$5,560,155 $6,724,552 $6,601,056 $6,774,524F-59 Table of Contents As Corrected March 31, December 31, September 30, June 30, 2015 2014 2014 2014ASSETS CURRENT ASSETS: Cash and cash equivalents$41,303 $30,556 $11,823 $39,679Accounts receivable-trade, net of allowance for doubtfulaccounts1,025,763 1,664,039 1,433,117 903,011Accounts receivable-affiliates17,198 42,549 41,706 1,110Inventories442,025 535,928 941,589 373,633Prepaid expenses and other current assets121,207 184,675 156,818 58,613Total current assets1,647,496 2,457,747 2,585,053 1,376,046 PROPERTY, PLANT AND EQUIPMENT, net of accumulateddepreciation1,624,016 1,472,295 1,433,313 863,457GOODWILL1,558,233 1,361,547 1,254,273 1,158,301INTANGIBLE ASSETS, net of accumulated amortization1,232,308 1,153,028 838,088 699,315INVESTMENTS IN UNCONSOLIDATED ENTITIES472,673 478,444 482,644 211,480LOAN RECEIVABLE-AFFILIATE8,154 — — —OTHER NONCURRENT ASSETS112,912 94,149 42,091 13,733Total assets$6,655,792 $7,017,210 $6,635,462 $4,322,332 LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable-trade$833,018 $1,534,568 $1,345,024 $810,149Accounts payable-affiliates25,794 12,766 85,307 37,706Accrued expenses and other payables202,349 282,965 223,404 128,560Advance payments received from customers54,234 72,075 106,105 56,373Current maturities of long-term debt4,472 4,455 5,062 6,168Total current liabilities1,119,867 1,906,829 1,764,902 1,038,956 LONG-TERM DEBT, net of debt issuance costs and currentmaturities2,727,464 2,753,322 2,437,351 1,441,875OTHER NONCURRENT LIABILITIES115,029 111,616 114,729 58,862 COMMITMENTS AND CONTINGENCIES0 0 0 0 EQUITY: General partner, representing a 0.1% interest(37,000) (39,029) (39,686) (41,307)Limited partners, representing a 99.9% interest2,183,551 1,714,788 1,789,373 1,823,795Subordinated units— — — (5,150)Accumulated other comprehensive loss(109) (89) (73) (51)Noncontrolling interests546,990 569,773 568,866 5,352Total equity2,693,432 2,245,443 2,318,480 1,782,639Total liabilities and equity$6,655,792 $7,017,210 $6,635,462 $4,322,332F-60 Table of Contents As Restated Three Months Ended March 31, December 31, September 30, June 30, 2016 2015 2015 2015REVENUES: Crude oil logistics$362,292 $519,425 $1,007,578 $1,327,784Water solutions37,776 45,438 47,494 54,293Liquids332,975 353,527 258,992 248,985Retail propane135,179 100,145 53,206 64,447Refined products and renewables1,456,756 1,666,471 1,825,925 1,842,960Other462 — — —Total Revenues2,325,440 2,685,006 3,193,195 3,538,469 COST OF SALES: Crude oil logistics341,477 495,529 982,719 1,291,992Water solutions752 (3,128) (8,567) 3,607Liquids282,961 300,766 221,115 232,276Retail propane60,340 45,974 20,879 29,564Refined products and renewables1,391,448 1,594,359 1,789,680 1,765,112Other182 — — —Total Cost of Sales2,077,160 2,433,500 3,005,826 3,322,551 OPERATING COSTS AND EXPENSES: Operating93,177 104,721 97,630 105,590General and administrative24,727 23,035 29,298 62,481Depreciation and amortization53,152 59,180 56,761 59,831Loss on disposal or impairment of assets, net317,726 1,328 1,291 421Revaluation of liabilities(36,257) (19,312) (15,909) (11,195)Operating (Loss) Income(204,245) 82,554 18,298 (1,210) OTHER INCOME (EXPENSE): Equity in earnings of unconsolidated entities2,113 2,858 2,432 8,718Interest expense(34,540) (36,176) (31,571) (30,802)Gain on early extinguishment of debt28,532 — — —Other income (expense), net2,634 2,161 1,955 (1,175)(Loss) Income Before Income Taxes(205,506) 51,397 (8,886) (24,469) INCOME TAX (EXPENSE) BENEFIT(1,479) (402) 2,786 (538) Net (Loss) Income(206,985) 50,995 (6,100) (25,007) LESS: NET LOSS (INCOME) ALLOCATED TO GENERALPARTNER178 (16,239) (16,185) (15,374)LESS: NET LOSS (INCOME) ATTRIBUTABLE TONONCONTROLLING INTERESTS2,853 (6,838) (3,497) (4,350)NET (LOSS) INCOME ALLOCATED TO LIMITED PARTNERS$(203,954) $27,918 $(25,782) $(44,731)BASIC (LOSS) INCOME PER COMMON UNIT$(1.94) $0.27 $(0.25) $(0.43)DILUTED (LOSS) INCOME PER COMMON UNIT$(1.94) $0.22 $(0.25) $(0.43)BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING104,930,260 105,338,200 105,189,463 103,888,281DILUTED WEIGHTED AVERAGE COMMON UNITSOUTSTANDING104,930,260 106,194,547 105,189,463 103,888,281F-61 Table of Contents As Corrected Three Months Ended March 31, December 31, September 30, June 30, 2015 2014 2014 2014REVENUES: Crude oil logistics$900,077 $1,694,881 $2,111,143 $1,929,283Water solutions49,768 50,241 52,719 47,314Liquids543,819 685,096 539,753 475,157Retail propane203,172 139,765 68,358 77,902Refined products and renewables1,523,532 1,983,444 2,607,220 1,117,497Other403 (1,281) 1,333 1,461Total Revenues3,220,771 4,552,146 5,380,526 3,648,614 COST OF SALES: Crude oil logistics881,781 1,697,374 2,083,712 1,897,639Water solutions(2,555) (29,085) (9,439) 10,573Liquids478,524 657,010 514,064 462,016Retail propane109,948 81,172 39,894 47,524Refined products and renewables1,465,287 1,905,021 2,550,851 1,114,313Other36 176 383 1,988Total Cost of Sales2,933,021 4,311,668 5,179,465 3,534,053 OPERATING COSTS AND EXPENSES: Operating107,357 95,569 95,116 66,089General and administrative35,688 44,230 41,639 27,873Depreciation and amortization54,140 50,335 50,099 39,375Loss on disposal or impairment of assets, net6,545 30,073 4,134 432Revaluation of liabilities(12,264) — — —Operating Income (Loss)96,284 20,271 10,073 (19,208) OTHER INCOME (EXPENSE): Equity in earnings of unconsolidated entities4,599 1,242 3,697 2,565Interest expense(30,927) (30,051) (28,651) (20,494)Other income (expense), net34,808 3,371 (617) (391)Income (Loss) Before Income Taxes104,764 (5,167) (15,498) (37,528) INCOME TAX BENEFIT (EXPENSE)645 2,090 1,922 (1,035) Net Income (Loss)105,409 (3,077) (13,576) (38,563) LESS: NET INCOME ALLOCATED TO GENERAL PARTNER(13,474) (11,785) (11,059) (9,382)LESS: NET INCOME ATTRIBUTABLE TONONCONTROLLING INTERESTS(3,630) (5,751) (3,416) (90)NET INCOME (LOSS) ALLOCATED TO LIMITEDPARTNERS$88,305 $(20,613) $(28,051) $(48,035)BASIC INCOME (LOSS) PER COMMON UNIT$0.93 $(0.23) $(0.32) $(0.60)DILUTED INCOME (LOSS) PER COMMON UNIT$0.93 $(0.23) $(0.32) $(0.60)BASIC WEIGHTED AVERAGE COMMON UNITSOUTSTANDING94,447,339 88,545,764 88,331,653 74,126,205DILUTED WEIGHTED AVERAGE COMMON UNITSOUTSTANDING94,447,339 88,545,764 88,331,653 74,126,205F-62 Table of ContentsOn February 1, 2016, we completed the sale of our general partner interest in TLP to ArcLight and recognized a gain of $130.4 million in ourconsolidated statement of operations (see Note 14 for a further discussion).During the fourth quarter of fiscal year 2016, we recorded an estimated goodwill impairment charge of $380.2 million as the decline in crude oilprices and crude oil production have had an unfavorable impact on our water solutions business. Also, during the fourth quarter of fiscal year 2016, werecorded write-downs and impairments of certain property, plant and equipment of $64.7 million (see Note 14 for a further discussion).During the fourth quarter of fiscal year 2016, we repurchased a portion of our 2019 Notes and 2021 Notes and recorded a gain on the earlyextinguishment of debt of $28.5 million (see Note 8 for a further discussion).As described in Note 16, in March 2015, we agreed to release certain producers from certain commitments in return for a cash payment inMarch 2015 and additional cash payments over the next five years. Upon execution of these agreements in March 2015, we recorded a gain of $31.6 millionto other income in our consolidated statement of operations, net of certain project abandonment costs.Note 19—Subsequent EventsSale of TLP Common UnitsOn April 1, 2016, we sold all of the TLP common units we owned to ArcLight for approximately $112.4 million in cash. Repurchases of Senior NotesDuring April 2016, we repurchased $5.0 million of our 2019 Notes and $19.2 million of our 2021 Notes for an aggregate purchase price of $15.1million (excluding payments of accrued interest). As a result, we expect to record a gain on the early extinguishment of these notes of $8.6 million (net of thewrite off of debt issuance costs of $0.5 million) during the three months ended June 30, 2016.Class A Convertible Preferred UnitsOn April 21, 2016, we entered into an agreement to issue $200 million of 10.75% Class A Convertible Preferred Units (“Preferred Units”) to OaktreeCapital Management L.P. (“Oaktree”). Oaktree may acquire 16.6 million Preferred Units at a price of $12.03 per unit as well as 3.6 million warrants, which aresubject to certain vesting and exercise terms. We expect to use the net proceeds from the issuance of the Preferred Units to repay borrowings outstanding onour Revolving Credit Facility, which may be re-borrowed in the future to fund capital expenditures and for other general partnership purposes.Note 20—Consolidating Guarantor and Non-Guarantor Financial InformationCertain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and the 2021 Notes (seeNote 8). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the consolidating financial information for NGL Energy 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 guarantor subsidiaries on acombined 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 that prevent the parent or any of the guarantor subsidiaries from obtaining funds from their respectivesubsidiaries by dividend or loan. None of the assets of the guarantor subsidiaries (other than the investments in non-guarantor subsidiaries) are restricted netassets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.F-63 Table of ContentsFor 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 (from) consolidated entities are reportedon a net basis within net changes in advances with consolidated entities in the consolidating statement of cash flow tables below.F-64 Table of ContentsNGL ENERGY PARTNERS LPConsolidating Balance Sheet(U.S. Dollars in Thousands) March 31, 2016 NGL EnergyPartners LP(Parent)(1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments ConsolidatedASSETS CURRENT ASSETS: Cash and cash equivalents $25,749 $— $784 $1,643 $— $28,176Accounts receivable-trade, net ofallowance for doubtful accounts — — 516,362 4,652 — 521,014Accounts receivable-affiliates — — 15,625 — — 15,625Inventories — — 367,250 556 — 367,806Prepaid expenses and other currentassets — — 94,426 1,433 — 95,859Total current assets 25,749 — 994,447 8,284 — 1,028,480 PROPERTY, PLANT ANDEQUIPMENT, net of accumulateddepreciation — — 1,568,488 81,084 — 1,649,572GOODWILL — — 1,313,364 1,998 — 1,315,362INTANGIBLE ASSETS, net ofaccumulated amortization — — 1,146,355 2,535 — 1,148,890INVESTMENTS INUNCONSOLIDATED ENTITIES — — 219,550 — — 219,550NET INTERCOMPANYRECEIVABLES (PAYABLES) 1,404,479 — (1,402,360) (2,119) — —INVESTMENTS IN CONSOLIDATEDSUBSIDIARIES 1,254,383 — 42,227 — (1,296,610) —LOAN RECEIVABLE-AFFILIATE — — 22,262 — — 22,262OTHER NONCURRENT ASSETS — — 175,512 527 — 176,039Total assets $2,684,611 $— $4,079,845 $92,309 $(1,296,610) $5,560,155 LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable-trade $— $— $417,707 $2,599 $— $420,306Accounts payable-affiliates 1 — 7,190 2 — 7,193Accrued expenses and other payables 16,887 — 196,596 943 — 214,426Advance payments received fromcustomers — — 55,737 448 — 56,185Current maturities of long-term debt — — 7,109 798 — 7,907Total current liabilities 16,888 — 684,339 4,790 — 706,017 LONG-TERM DEBT, net of debtissuance costs and current maturities 1,011,365 — 1,894,428 7,044 — 2,912,837OTHER NONCURRENT LIABILITIES — — 246,695 541 — 247,236 EQUITY Partners’ equity 1,656,358 — 1,254,384 80,090 (1,334,317) 1,656,515Accumulated other comprehensiveloss — — (1) (156) — (157)Noncontrolling interests — — — — 37,707 37,707Total equity 1,656,358 — 1,254,383 79,934 (1,296,610) 1,694,065Total liabilities and equity $2,684,611 $— $4,079,845 $92,309 $(1,296,610) $5,560,155 (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 the issuance ofthe 2019 Notes and 2021 Notes, all activity has been reflected in the parent column.F-65 Table of ContentsNGL ENERGY PARTNERS LPConsolidating Balance Sheet(U.S. Dollars in Thousands) March 31, 2015 NGL EnergyPartners LP(Parent)(1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments ConsolidatedASSETS CURRENT ASSETS: Cash and cash equivalents $29,115 $— $9,757 $2,431 $— $41,303Accounts receivable-trade, net ofallowance for doubtful accounts — — 1,007,001 18,762 — 1,025,763Accounts receivable-affiliates 5 — 16,610 583 — 17,198Inventories — — 440,289 1,736 — 442,025Prepaid expenses and other current assets — — 104,771 16,436 — 121,207Total current assets 29,120 — 1,578,428 39,948 — 1,647,496 PROPERTY, PLANT AND EQUIPMENT,net of accumulated depreciation — — 1,092,271 531,745 — 1,624,016GOODWILL — — 1,526,067 32,166 — 1,558,233INTANGIBLE ASSETS, net ofaccumulated amortization — — 1,167,795 64,513 — 1,232,308INVESTMENTS IN UNCONSOLIDATEDENTITIES — — 217,600 255,073 — 472,673NET INTERCOMPANY RECEIVABLES(PAYABLES) 1,363,792 — (1,319,388) (44,404) — —INVESTMENTS IN CONSOLIDATEDSUBSIDIARIES 1,855,386 — 56,690 — (1,912,076) —LOAN RECEIVABLE-AFFILIATE — — 8,154 — — 8,154OTHER NONCURRENT ASSETS — — 110,195 2,717 — 112,912Total assets $3,248,298 $— $4,437,812 $881,758 $(1,912,076) $6,655,792 LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable-trade $— $— $820,042 $12,976 $— $833,018Accounts payable-affiliates — — 25,690 104 — 25,794Accrued expenses and other payables 19,690 — 172,074 10,585 — 202,349Advance payments received fromcustomers — — 53,903 331 — 54,234Current maturities of long-term debt — — 4,413 59 — 4,472Total current liabilities 19,690 — 1,076,122 24,055 — 1,119,867 LONG-TERM DEBT, net of debt issuancecosts and current maturities (2) 1,082,166 — 1,395,099 250,199 — 2,727,464OTHER NONCURRENT LIABILITIES — — 111,205 3,824 — 115,029 EQUITY Partners’ equity 2,146,442 — 1,855,386 603,789 (2,459,066) 2,146,551Accumulated other comprehensive loss — — — (109) — (109)Noncontrolling interests — — — — 546,990 546,990Total equity 2,146,442 — 1,855,386 603,680 (1,912,076) 2,693,432Total liabilities and equity $3,248,298 $— $4,437,812 $881,758 $(1,912,076) $6,655,792 (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 the issuance ofthe 2019 Notes and 2021 Notes, all activity has been reflected in the parent column.(2)The carrying value of long-term debt in the NGL Energy Partners LP (Parent) column has been reduced by $17.8 million of debt issuance costs.F-66 Table of ContentsNGL ENERGY PARTNERS LPConsolidating Statement of Operations(U.S. Dollars in Thousands) Year Ended March 31, 2016 NGL EnergyPartners LP(Parent) (1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated REVENUES $— $— $11,593,272 $182,175 $(33,337) $11,742,110 COST OF SALES — — 10,843,937 28,237 (33,137) 10,839,037 OPERATING COSTS AND EXPENSES: Operating — — 327,377 73,941 (200) 401,118General and administrative — — 122,196 17,345 — 139,541Depreciation and amortization — — 184,091 44,833 — 228,924Loss on disposal or impairment of assets,net — — 303,422 17,344 — 320,766Revaluation of liabilities — — (82,673) — — (82,673) Operating (Loss) Income — — (105,078) 475 — (104,603) OTHER INCOME (EXPENSE): Equity in earnings of unconsolidatedentities — — 4,374 11,747 — 16,121Interest expense (43,493) — (82,360) (7,546) 310 (133,089)Gain on early extinguishment of debt — — 28,532 — — 28,532Other income, net — — 5,533 352 (310) 5,575 (Loss) Income Before Income Taxes (43,493) — (148,999) 5,028 — (187,464) INCOME TAX BENEFIT (EXPENSE) — — 574 (207) — 367 EQUITY IN NET LOSS OFCONSOLIDATED SUBSIDIARIES (155,436) — (7,011) — 162,447 — Net (Loss) Income (198,929) — (155,436) 4,821 162,447 (187,097) LESS: NET INCOME ALLOCATED TOGENERAL PARTNER (47,620) (47,620) LESS: NET INCOME ATTRIBUTABLE TONONCONTROLLING INTERESTS (11,832) (11,832) NET (LOSS) INCOME ALLOCATED TOLIMITED PARTNERS $(198,929) $— $(155,436) $4,821 $102,995 $(246,549) (1)The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.F-67 Table of ContentsNGL ENERGY PARTNERS LPConsolidating Statement of Operations(U.S. Dollars in Thousands) Year Ended March 31, 2015 NGL EnergyPartners LP(Parent) (1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated REVENUES $— $— $16,648,382 $189,979 $(36,304) $16,802,057 COST OF SALES — — 15,934,529 59,825 (36,147) 15,958,207 OPERATING COSTS AND EXPENSES: Operating — — 306,576 57,555 — 364,131General and administrative — — 131,898 17,532 — 149,430Depreciation and amortization — — 161,906 32,043 — 193,949Loss on disposal or impairment of assets,net — — 11,619 29,565 — 41,184Revaluation of liabilities — — (12,264) — — (12,264) Operating Income (Loss) — — 114,118 (6,541) (157) 107,420 OTHER INCOME (EXPENSE): Equity in earnings of unconsolidatedentities — — 6,640 5,463 — 12,103Interest expense (65,723) — (39,023) (5,423) 46 (110,123)Other income, net — — 36,953 264 (46) 37,171 (Loss) Income Before Income Taxes (65,723) — 118,688 (6,237) (157) 46,571 INCOME TAX BENEFIT (EXPENSE) — — 3,795 (173) — 3,622 EQUITY IN NET INCOME (LOSS) OFCONSOLIDATED SUBSIDIARIES 103,029 — (19,297) — (83,732) — Net Income (Loss) 37,306 — 103,186 (6,410) (83,889) 50,193 LESS: NET INCOME ALLOCATED TOGENERAL PARTNER (45,700) (45,700) LESS: NET INCOME ATTRIBUTABLE TONONCONTROLLING INTERESTS (12,887) (12,887) NET INCOME (LOSS) ALLOCATED TOLIMITED PARTNERS $37,306 $— $103,186 $(6,410) $(142,476) $(8,394) (1)The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.F-68 Table of ContentsNGL ENERGY PARTNERS LPConsolidating Statement of Operations(U.S. Dollars in Thousands) Year Ended March 31, 2014 NGL EnergyPartners LP(Parent) (1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated REVENUES $— $— $9,560,124 $139,519 $(369) $9,699,274 COST OF SALES — — 9,011,011 122,057 (369) 9,132,699 OPERATING COSTS AND EXPENSES: Operating — — 250,841 8,958 — 259,799General and administrative — — 73,756 2,104 — 75,860Depreciation and amortization — — 117,573 3,181 — 120,754Loss (gain) on disposal or impairmentof assets, net — — 6,373 (2,776) — 3,597 Operating Income — — 100,570 5,995 — 106,565 OTHER INCOME (EXPENSE): Equity in earnings of unconsolidatedentities — — 1,898 — — 1,898Interest expense (31,818) — (27,031) (51) 46 (58,854)Other income (expense), net — — 202 (70) (46) 86 (Loss) Income Before Income Taxes (31,818) — 75,639 5,874 — 49,695 INCOME TAX EXPENSE — — (937) — — (937) EQUITY IN NET INCOME OFCONSOLIDATED SUBSIDIARIES 79,473 — 4,771 — (84,244) — Net Income 47,655 — 79,473 5,874 (84,244) 48,758 LESS: NET INCOME ALLOCATED TOGENERAL PARTNER (14,148) (14,148) LESS: NET INCOME ATTRIBUTABLETO NONCONTROLLING 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 2019 Notes and 2021 Notes.F-69 Table of ContentsNGL ENERGY PARTNERS LPConsolidating Statements of Comprehensive Income (Loss)(U.S. Dollars in Thousands) Year Ended March 31, 2016 NGL EnergyPartners LP(Parent) (1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated Net (loss) income $(198,929) $— $(155,436) $4,821 $162,447 $(187,097) Other comprehensive loss — — — (48) — (48) Comprehensive (loss) income $(198,929) $— $(155,436) $4,773 $162,447 $(187,145) (1)The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Year Ended March 31, 2015 NGL EnergyPartners LP(Parent) (1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated Net income (loss) $37,306 $— $103,186 $(6,410) $(83,889) $50,193 Other comprehensive income (loss) — — 189 (62) — 127 Comprehensive income (loss) $37,306 $— $103,375 $(6,472) $(83,889) $50,320 (1)The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Year Ended March 31, 2014 NGL EnergyPartners LP(Parent) (1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments 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 (1)The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.F-70 Table of ContentsNGL ENERGY PARTNERS LPConsolidating Statement of Cash Flows(U.S. Dollars in Thousands) Year Ended March 31, 2016 NGL EnergyPartners LP(Parent) (1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries Consolidated OPERATING ACTIVITIES: Net cash (used in) provided by operating activities $(74,822) $— $360,851 $65,466 $351,495 INVESTING ACTIVITIES: Purchases of long-lived assets — — (604,214) (57,671) (661,885)Acquisitions of businesses, including acquired working capital,net of cash acquired (624) — (232,148) (1,880) (234,652)Cash flows from commodity derivatives — — 105,662 — 105,662Proceeds from sales of assets — — 8,453 2 8,455Proceeds from sale of general partner interest in TLP, net — — 343,135 — 343,135Investments in unconsolidated entities — — (4,480) (6,951) (11,431)Distributions of capital from unconsolidated entities — — 11,031 4,761 15,792Loan for natural gas liquids facility — — (3,913) — (3,913)Payments on loan for natural gas liquids facility — — 7,618 — 7,618Loan to affiliate — — (15,621) — (15,621)Payments on loan to affiliate — — 1,513 — 1,513Net cash used in investing activities (624) — (382,964) (61,739) (445,327) FINANCING ACTIVITIES: Proceeds from borrowings under revolving credit facilities — — 2,499,000 103,500 2,602,500Payments on revolving credit facilities — — (2,041,500) (91,500) (2,133,000)Repurchases of senior notes (43,421) — — — (43,421)Proceeds from borrowings under other long-term debt — — 45,873 7,350 53,223Payments on other long-term debt — — (4,762) (325) (5,087)Debt issuance costs (3,493) — (6,744) — (10,237)Contributions from general partner 54 — — — 54Contributions from limited partner (3,829) — — — (3,829)Contributions from noncontrolling interest owners — — — 15,376 15,376Distributions to partners (322,007) — — — (322,007)Distributions to noncontrolling interest owners — — — (35,720) (35,720)Taxes paid on behalf of equity incentive plan participants — — (19,395) — (19,395)Common unit repurchases (17,680) — — — (17,680)Net changes in advances with consolidated entities 462,456 — (459,289) (3,167) —Other — — (43) (29) (72)Net cash provided by (used in) financing activities 72,080 — 13,140 (4,515) 80,705 Net decrease in cash and cash equivalents (3,366) — (8,973) (788) (13,127)Cash and cash equivalents, beginning of period 29,115 — 9,757 2,431 41,303Cash and cash equivalents, end of period $25,749 $— $784 $1,643 $28,176 (1)The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.F-71 Table of ContentsNGL ENERGY PARTNERS LPConsolidating Statement of Cash Flows(U.S. Dollars in Thousands) Year Ended March 31, 2015 NGL EnergyPartners LP(Parent) (1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries Consolidated OPERATING ACTIVITIES: Net cash (used in) provided by operating activities $(59,448) $— $287,953 $33,886 $262,391 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 Mesa Pipeline — — (310,000) — (310,000)Acquisitions of businesses, including acquired working 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 — — 11,806 14,456 26,262Investments in unconsolidated entities — — (13,244) (20,284) (33,528)Distributions of capital from unconsolidated entities — — 5,030 5,793 10,823Loan for natural gas liquids facility — — (63,518) — (63,518)Payments on loan for natural gas liquids facility — — 1,625 — 1,625Loan to affiliate — — (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 credit facilities — — 3,663,000 101,500 3,764,500Payments on revolving credit facilities — — (3,194,500) (85,500) (3,280,000)Issuances of notes 400,000 — — — 400,000Payments on other long-term debt — — (6,666) (22) (6,688)Debt issuance costs (8,150) — (2,926) — (11,076)Contributions from general partner 823 — — — 823Contributions from noncontrolling interest owners — — — 9,433 9,433Distributions to partners (242,595) — — — (242,595)Distributions to noncontrolling interest owners — — — (27,147) (27,147)Proceeds from sale of common units, net of offering costs 541,128 — — — 541,128Taxes paid on behalf of equity incentive plan participants — — (13,491) — (13,491)Net changes in advances with consolidated entities (479,543) — 499,709 (20,166) —Other — — (194) — (194)Net cash provided by (used in) financing activities 211,663 — 944,932 (21,902) 1,134,693 Net increase in cash and cash equivalents 27,934 — 1,029 1,900 30,863Cash and cash equivalents, beginning of period 1,181 — 8,728 531 10,440Cash 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-72 Table of ContentsNGL ENERGY PARTNERS LPConsolidating Statement of Cash Flows(U.S. Dollars in Thousands) Year Ended March 31, 2014 NGL EnergyPartners LP(Parent) (1) NGL EnergyFinance Corp. (1) GuarantorSubsidiaries Non-GuarantorSubsidiaries Consolidated OPERATING ACTIVITIES: Net cash (used in) provided by operating activities $(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 acquired working 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 — — 12,884 11,776 24,660Investments in unconsolidated entities — — (11,515) — (11,515)Distributions of capital from unconsolidated entities — — 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 credit facilities — — 2,545,500 — 2,545,500Payments on revolving credit facilities — — (2,101,000) — (2,101,000)Issuances of notes 450,000 — — — 450,000Proceeds from borrowings under other long-term debt — — 780 100 880Payments on other long-term debt — — (8,802) (17) (8,819)Debt issuance costs (12,931) — (11,664) — (24,595)Contributions from general partner 765 — — — 765Contributions from noncontrolling interest owners — — — 2,060 2,060Distributions to partners (145,090) — — — (145,090)Distributions to noncontrolling interest owners — — — (840) (840)Proceeds from sale of common units, net of offering costs 650,155 — — — 650,155Net changes in advances with consolidated entities (590,939) — 556,238 34,701 —Net cash provided by financing activities 351,960 — 981,052 36,004 1,369,016 Net increase (decrease) in cash and cash equivalents 1,181 — (2,478) 176 (1,121)Cash and cash equivalents, beginning of period — — 11,206 355 11,561Cash 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 2019 Notes and 2021 Notes.F-73 Table of ContentsINDEX TO EXHIBITSExhibit NumberDescription2.1 LLC 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 (incorporated byreference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.2 LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL KarnesSWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference toExhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.3 LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Cotulla SWD, LLC, TerryBailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated byreference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.4 LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, TerryBailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated byreference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 2.5 LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWL Operating,LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High SierraTransportation, LLC (incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed with the SECon August 7, 2013) 2.6 Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP, Gavilon,LLC and Gavilon Energy Intermediate, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013) 3.1 Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Registration Statement onForm S-1 (File No. 333-172186) filed on April 15, 2011) 3.2 Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.2 to theRegistration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.3 Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 tothe Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011) 3.4 First Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 26, 2011) 3.5 Second Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012) 3.6 Third Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 26, 2012) 3.7 Fourth Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated byreference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 2012) 3.8 Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.9 Certificate of Amendment to Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.5 to theRegistration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 3.10 Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC (incorporated by reference toExhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on February 28, 2013)F-74 Table of ContentsExhibit NumberDescription3.11 Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as ofAugust 6, 2013 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onAugust 7, 2013) 3.12 Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as ofJune 27, 2014 (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onJuly 3, 2014) 4.1 First Amended and Restated Registration Rights Agreement, dated October 3, 2011, by and among the Partnership, Hicks Oils &Hicksgas, Incorporated, NGL Holdings, Inc., Krim2010, LLC, Infrastructure Capital Management, LLC, Atkinson Investors, LLC, E.Osterman Propane, Inc. and the other holders party thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K(File No. 001-35172) filed on October 7, 2011) 4.2 Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 by andamong the Partnership and SemStream (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172)filed on November 4, 2011) 4.3 Amendment No. 2 and Joinder to First Amended and Restated Registration Rights Agreement, dated January 3, 2012, by and among NGLEnergy 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 toExhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012) 4.4 Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGLEnergy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on May 4, 2012) 4.5 Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and between NGLEnergy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on June 25, 2012) 4.6 Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and betweenNGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2012) 4.7 Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by and betweenNGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, AnimosusTrust 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 SECon November 19, 2012) 4.8 Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by and amongNGL Energy Holdings LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to the Current Reporton Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013) 4.9 Amendment No. 8 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of February 17, 2015, by andamong NGL Energy Holdings LLC and Magnum NGL Holdco LLC (incorporated by reference to Exhibit 4.9 to the Annual Report onForm 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015) 4.10* Amendment No. 9 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of February 25, 2016, by andamong NGL Energy Holdings LLC and Magnum NGL Holdco LLC 4.11 Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by reference toExhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 4.12 Amendment No. 1 to Note Purchase Agreement, dated as of January 15, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18,2013) F-75 Table of ContentsExhibit NumberDescription4.13 Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 9, 2013) 4.14 Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (FileNo. 001-35172) filed with the SEC on October 3, 2013) 4.15 Amendment No. 4 to Note Purchase Agreement, dated as of November 5, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8,2013) 4.16 Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 2013, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30,2013) 4.17 Amendment No. 6 to Note Purchase Agreement, dated as of June 30, 2014, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 3, 2014) 4.18 Amendment 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 (File No. 001-35172) filed on January 2, 2015) 4.19 Amendment No. 8 to Note Purchase Agreement, dated as of May 1, 2015, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.18 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015filed with the SEC on June 1, 2015) 4.20 Amendment No. 9 to Note Purchase Agreement, dated as of December 23, 2015, among the Partnership and the purchasers named therein(incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended December 31,2015 filed with the SEC on February 9, 2016) 4.21* Amendment No. 10 to Note Purchase Agreement, dated as of February 9, 2016, among the Partnership and the purchasers named therein 4.22 Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party theretoand 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) 4.23 Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013) 4.24 First Supplemental Indenture, dated as of December 2, 2013, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated byreference to Exhibit 4.19 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with the SECon May 30, 2014) 4.25 Second Supplemental Indenture, dated as of April 22, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., theGuaranteeing Subsidiary party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated byreference to Exhibit 4.20 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with the SECon May 30, 2014) 4.26 Third Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the GuaranteeingSubsidiary party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.6 to the Quarterly Reporton Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with the SEC on November 10, 2014) 4.27 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 (incorporated byreference to Exhibit 4.25 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SECon June 1, 2015) 4.28 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 (incorporated byreference to Exhibit 4.26 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SECon June 1, 2015)F-76 Table of ContentsExhibit NumberDescription4.29 Sixth Supplemental Indenture, dated as of August 21, 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 (incorporated byreference to Exhibit 4.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed withthe SEC on November 9, 2015) 4.30 Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., theGuarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporated byreference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013) 4.31 Registration Rights Agreement, dated December 2, 2013, by and among NGL Energy Partners LP and the purchasers set forth on ScheduleA thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onDecember 5, 2013) 4.32 Indenture, dated as of July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party thereto andU.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) 4.33 Forms of 5.125% Senior Notes due 2019 (incorporated by reference and included as Exhibits A1 and A2 to Exhibit 4.1 to the CurrentReport on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014) 4.34 Registration Rights Agreement, dated July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantorslisted therein on Exhibit A and RBS Securities Inc. as representative of the several initial purchasers (incorporated by reference toExhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014) 4.35 First Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the GuaranteeingSubsidiaries party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.5 to the QuarterlyReport on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with the SEC on November 10, 2014) 4.36 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 (incorporated byreference to Exhibit 4.32 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SECon June 1, 2015) 4.37 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 (incorporated byreference to Exhibit 4.33 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SECon June 1, 2015) 4.38 Fourth Supplemental Indenture, dated as of August 21, 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 (incorporated byreference to Exhibit 4.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed withthe SEC on November 9, 2015) 10.1 Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders party thereto andDeutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on June 25, 2012) 10.2 Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP, Deutsche BankTrust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the CurrentReport on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012) 10.3 Amendment No. 1 to Credit Agreement, dated as of January 15, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18, 2013) 10.4 Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K (File No 001-35172) filed on May 9, 2013) F-77 Table of ContentsExhibit NumberDescription10.5 Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, eachsubsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank TrustCompany Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “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 onOctober 3, 2013) 10.6 Amendment No. 4 to Credit Agreement, dated as of November 5, 2013, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8,2013) 10.7 Amendment No. 5 to Credit Agreement, dated as of December 23, 2013, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank and Trust Company Americas and the other financial institutions party thereto(incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30,2013) 10.8 Facility 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 on Form 8-K(File No. 001-35172) filed with the SEC on January 3, 2014) 10.9 Amendment No. 6 to Credit Agreement, dated as of June 12, 2014, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 16, 2014) 10.10 Amendment No. 7 to Credit Agreement, dated as of June 27, 2014, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 3, 2014) 10.11 Facility Increase Agreement, dated December 1, 2014, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas andthe other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 1, 2014) 10.12 Amendment No. 8 to Credit Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, among NGL EnergyOperating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financialinstitutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed onJanuary 2, 2015) 10.13 Amendment No. 9 to Credit Agreement, dated as of May 1, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.13 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SECon June 1, 2015) 10.14 Amendment No. 10 to Credit Agreement, dated as of July 31, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiaryborrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated byreference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 4, 2015) 10.15 Facility Increase Agreement, dated October 7, 2015, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas andthe other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q (File No.001-35172) for the quarter ended December 31, 2015 filed with the SEC on February 9, 2016) 10.16 Amendment No. 11 to Credit Agreement, dated as of December 23, 2015, 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 10.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended December 31,2015 filed with the SEC on February 9, 2016) 10.17* Amendment No. 12 to Credit Agreement, dated as of February 9, 2016, among NGL Energy Operating LLC, the Partnership, thesubsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto F-78 Table of ContentsExhibit NumberDescription10.18 Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed onSchedule A thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SECon December 5, 2013) 10.19+ Letter Agreement among Silverthorne Energy Holdings LLC, Shawn W. Coady and Todd M. Coady dated October 14, 2010 (incorporatedby reference to Exhibit 10.11 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011) 10.20+ NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K(File No. 001-35172) filed on May 17, 2011) 10.21+ Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by referenceto Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended June 30, 2012 filed with the SEC onAugust 14, 2012 ) 10.22 NGL Performance Unit Program (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K (File No. 001-35172) forthe year ended March 31, 2015 filed with the SEC on June 1, 2015) 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-OxleyAct 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 Actof 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, 2016and 2015, (ii) Consolidated Statements of Operations for the years ended March 31, 2016, 2015, and 2014, (iii) Consolidated Statements ofComprehensive Income (Loss) for the years ended March 31, 2016, 2015, and 2014, (iv) Consolidated Statements of Changes in Equity for the yearsended March 31, 2016, 2015, and 2014, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2016, 2015, and 2014, and(vi) Notes to Consolidated Financial Statements.+Management contracts or compensatory plans or arrangements.F-79 Exhibit 4.10AMENDMENT NO. 9 TO First Amended and Restated Registration Rights AgreementThis Amendment No. 9 to First Amended and Restated Registration Rights Agreement (this “Amendment”) is dated as of February 25, 2016, by andamong NGL Energy Holdings LLC, a Delaware limited liability company (the “General Partner”), and Magnum NGL HoldCo LLC, a Delaware limitedliability company (the “Magnum Investor”). Capitalized terms used but not defined herein have the meanings ascribed to them in the Registration RightsAgreement (as defined below).R E C I T A L SWHEREAS, NGL Energy Partners LP, a Delaware limited partnership (the “Partnership”), acting through the General Partner, is party to that certainFirst Amended and Restated Registration Rights Agreement dated as of October 3, 2011 (the “Registration Rights Agreement”);WHEREAS, reference is hereby made to Amendment No. 8 and Joinder to First Amended and Restated Registration Rights Agreement (“AmendmentNo. 8”), dated as of February 17, 2015, by and among the General Partner and the Magnum Investor, pursuant to which the Magnum Investor was joined as aparty to the Registration Rights Agreement;WHEREAS, the General Partner and the Magnum Investor have agreed to modify certain rights granted to, and relating to the inclusion of, theMagnum Investor as a party to the Registration Rights Agreement;WHEREAS, pursuant to Section 6(c) of the Registration Rights Agreement, the General Partner may amend the Registration Rights Agreement in itssole discretion and without any further approval rights or action by or on behalf of the Holders to effect certain changes relating to the inclusion of additionalparties to the Registration Rights Agreement; andWHEREAS, the General Partner desires to amend the Registration Rights Agreement as set forth below.NOW, THEREFORE, for good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged, the parties hereby covenantand agree:1.Amendment of Registration Rights Agreement. (a)The definition of “Significant Holder” set forth in Section 1 of the Registration Rights Agreement is hereby amended andrestated in its 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 so longas the Magnum Investor holds Common Units constituting at least 1% of the outstanding Common Units. Notwithstanding anything to the contraryset forth in this Agreement, (1) the Registrable Securities held by the Magnum Investor shall be determined without the application of clause (iii) ofthe definition of “Registrable Securities” until such time as the Magnum Investor holds less than 1% of the outstanding Common Units and (2) thePartnership may not postpone or defer any Demand Registration by the Magnum Investor pursuant to Section 2(a)(iv) for more than an aggregate ofninety (90) days.2.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 Agreement as amended hereby. (b)Except as specifically set forth above, the Registration Rights Agreement shall remain unaltered and in full force and effect andthe respective 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] IN WITNESS WHEREOF, the parties hereto have executed and deliver this Amendment No. 1 and Joinder to First Amended and RestatedRegistration Rights Agreement on the date first written above.NGL Energy Holdings LLCBy: /s/ H. Michael KrimbillName: /s/ H. Michael KrimbillTitle: Chief Executive OfficerMAGNUM NGL HOLDCO LLCBy: /s/ M. Scott JonesName: /s/ M. Scott JonesTitle: ManagerSignature Page to Amendment No. 9 to Registration Rights Agreement Exhibit 4.21AMENDMENT NO. 10 TO NOTE PURCHASE AGREEMENTTHIS AMENDMENT NO. 10 TO NOTE PURCHASE AGREEMENT, dated as of February 9, 2016, but effective as of the Effective Date (as definedin Section 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 thereto dated as of June 30, 2014, AmendmentNo. 7 thereto dated as of December 19, 2014, Amendment No. 8 thereto dated as of May 1, 2015, and Amendment No. 9 thereto dated as of December 28,2015 (such note purchase agreement, as so amended, being referred to herein as the “Existing Note Purchase Agreement” and as the same shall be furtheramended hereby, the “Note Purchase Agreement”), is among NGL Energy Partners LP, a Delaware limited partnership (the “Company”), the Guarantors(solely with respect to Section 5(c) hereof) and the holders of Notes listed on the signature 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 used andnot 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 conditionsset forth herein and in reliance upon the representations and warranties of the Company herein contained, the Company and the Noteholders hereby agree toamend the Existing Note Purchase Agreement as set forth below, effective as of the Effective Date:(a)Amendment to Section 10.12(a) of the Existing Note Purchase Agreement. Section 10.12(a) of the Existing Note Purchase Agreement ishereby amended by (i) deleting in its entirety the text “(provided that for the fiscal year ending March 31, 2016, the Company shall be permitted to redeemcommon units of the Company for an aggregate amount not to exceed $45,000,000)” and (ii) adding the following text immediately after the text “thisSection 10.12(a))”:“; provided that, notwithstanding the foregoing, (A) during the Increased Permitted Redemption Period and to the extent that both (I) theTransMontaigne GP Disposition has been consummated in accordance with its terms and (II) the Company has obtained aggregate net cash proceedsof not less than $200,000,000 from any combination of unsecured Indebtedness permitted by Section 10.7(m) and the Company’s issuance of EquityInterests, in each case incurred or issued on or after the Amendment No. 10 Effective Date, the Company shall be permitted to redeem, purchase,retire or otherwise acquire common units of the Company in an aggregate amount not to exceed $75,000,000 (such amount not to be in addition toany other limit set forth in this Section 10.12(a)(i)), and (B) after the expiration of the Increased Permitted Redemption Period, (x) the limits set forthin this Section 10.12(a)(i) (without giving effect to this proviso) shall apply and all of the redemptions, repurchases, retirements or other acquisitionsof Equity Interests that occurred during the Increased Permitted Redemption Period shall reduce the available amounts otherwise permitted underSection 10.12(a)(i) (for the avoidance of doubt, redemptions, repurchases, retirements and acquisitions of Equity Interests made during the IncreasedPermitted Redemption Period that were permitted by clause (A) of this proviso shall not be deemed a breach of the limits set forth in Section 10.12(a)(i) after the expiration of such Increased Permitted Redemption Period), and (y) if the Company redeems, repurchases, retires or otherwise acquirescommon units of the Company in an aggregate amount in excess of $45,000,000 during the Increased Permitted Redemption Period, no Note Party shall be permitted toredeem, purchase, retire or otherwise acquire any Equity Interests of the Company prior to January 1, 2019 unless the Company has delivered acertificate of a Financial Officer of the Company pursuant to Section 7.2 of this Agreement evidencing that the Leverage Ratio of the Note Parties asof the last day of the most recently ended fiscal quarter ending after December 31, 2015 is not greater than 3.50 to 1.00,”(b) Amendments to Schedule B to the Existing Note Purchase Agreement. Schedule B to the Existing Note Purchase Agreement is hereby amendedby adding the following definitions in appropriate alphabetical order to read in their entirety as follows:“Amendment No. 10 Effective Date” means February 9, 2016.“Increased Permitted Redemption Period” means the period from and including the Amendment No. 10 Effective Date to but excludingSeptember 15, 2016.“TransMontaigne GP Disposition” means the sale of all of the Equity Interests in TransMontaigne GP LLC, a Delaware limited liabilitycompany, by TransMontaigne Services LLC, a Delaware limited liability company, to Gulf TLP Holding, LLC, a Delaware limited liability company(or an Affiliate thereof), for aggregate gross cash consideration of approximately $350,000,000 on or before March 31, 2016, which such cashconsideration shall be applied promptly upon receipt thereof as follows: (i) $250,000,000 of such cash consideration to prepay outstandingAcquisition Revolving Loans (as defined in the Credit Agreement) and (ii) the remainder of such cash consideration (net of costs, expenses, fees andother similar payments made in connection with such sale) to be applied to prepay outstanding Working Capital Revolving Loans (as defined in theCredit Agreement).(c) Amendment to Schedule B to the Existing Note Purchase Agreement. Schedule B to the Existing Note Purchase Agreement is hereby furtheramended by amending the definition of “Indebtedness” by (i) deleting the text “and” immediately prior to clause (k) and (ii) deleting the period at the end ofsuch definition and inserting in lieu thereof the text “; and (l) all mandatory obligations of such Person to purchase, redeem, retire or defease any EquityInterests in such Person or any other Person prior to June 20, 2022, valued, in the case of a redeemable preferred interest, at the greater of its voluntary orinvoluntary liquidation preference plus accrued and unpaid dividends.”(d) Amendments to Schedule 5.4 to the Existing Note Purchase Agreement. Schedule 5.4 to the Existing Note Purchase Agreement is herebyamended by deleting such Schedule in its entirety and replacing it with Schedule 5.4 attached hereto as Annex A.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 anddelivered by 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,dated on or prior to the date hereof, in form and substance satisfactory to the Required Holders and executed and delivered by the Note Parties, theAdministrative Agent and the Required Lenders (as defined in the Credit Agreement).(d)Payment of Amendment Fee. The Company shall have paid a fee to each Noteholder equal to 0.10% multiplied by the aggregateoutstanding principal amount of the Notes held by such Noteholder.(e)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, its representations and warranties contained in the Note Purchase Agreement are true and correct inall material respects (except for those representations and warranties qualified by “materiality,” “Material Adverse Effect” or a like qualification, which shallbe correct in all respects) on and as of the Effective Date with the same effect as though made on and as of the Effective Date, 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 (except for those representations and warranties qualified by “materiality,” “Material Adverse Effect” or a like qualification, which were true in allrespects) as of such earlier date), (ii) represents and warrants to the Noteholders that in connection with this Amendment and all other documents delivered inconnection herewith it (x) has the requisite power and authority to make, deliver and perform the same, (y) has taken all necessary limited partnership actionto authorize its execution, delivery and performance of the same, and (z) has duly executed and delivered the same and (iii) except to the extent waivedherein, certifies that no Default or Event of Default exists under any of the Note Documents (both immediately before and after giving effect to thisAmendment) 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 ofwhich when so executed and delivered shall be deemed an original, but all such counterparts together shall constitute but one and the same instrument. Eachcounterpart may consist of a number of copies hereof, each signed by less than all, but together signed by all, the parties hereto. Delivery of this Amendmentmay be made by telecopy or electronic transmission of a duly executed counterpart copy hereof; provided that any such delivery by electronic transmissionshall be effective only if transmitted in .pdf format, .tif format or other format in which the text is not readily modifiable by any recipient 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. Except as expressly provided hereby, all of the terms and provisions of the Note Purchase Agreement and the other Note Documentsare and shall remain in full force and effect. The amendments contained herein shall not be construed as a waiver or amendment of any other provision of theNote Purchase Agreement or any other Note Document or for any purpose, except as expressly set forth herein, or a consent to any further or future action onthe part of any Note Party that would require the waiver or consent of the Noteholders.(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 LPBy: NGL Energy Holdings LLC,its general partnerBy: /s/ H. Michael KrimbillName: /s/ H. Michael KrimbillTitle: Chief Executive OfficerSignature Page to Amendment No. 10 to Note Purchase Agreement The foregoing is hereby agreed to as of the date hereof:NOTEHOLDERS:THE PRUDENTIAL INSURANCE COMPANYOF AMERICA, as a NoteholderBy: /s/ Brian N. ThomasName: /s/ Brian N. ThomasTitle: Vice PresidentPRUCO LIFE INSURANCE COMPANY,as a NoteholderBy: /s/ Brian N. ThomasName: /s/ Brian N. ThomasTitle: Assistant Vice PresidentUNIVERSAL PRUDENTIAL ARIZONAREINSURANCE COMPANY, as a NoteholderBy: PGIM, Inc.,as investment managerBy: /s/ Brian N. ThomasName: /s/ Brian N. ThomasTitle: Vice PresidentPRUDENTIAL ARIZONA REINSURANCECAPTIVE COMPANY, as a NoteholderBy: PGIM, Inc.,as investment managerBy: /s/ Brian N. ThomasName: /s/ Brian N. ThomasTitle: Vice PresidentSignature Page to Amendment No. 10 to Note Purchase Agreement PRUDENTIAL ARIZONA REINSURANCEUNIVERSAL COMPANY, as a NoteholderBy: PGIM, Inc.,as investment managerBy: /s/ Brian N. ThomasName: /s/ Brian N. ThomasTitle: Vice PresidentPRUDENTIAL RETIREMENT INSURANCE ANDANNUITY COMPANY, as a NoteholderBy: PGIM, Inc.,as investment managerBy: /s/ Brian N. ThomasName: /s/ Brian N. ThomasTitle: Vice PresidentSignature Page to Amendment No. 10 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 AdviserBy: /s/ Curtis F. SullivanName: Curtis F. Sullivan Title: Vice PresidentSignature Page to Amendment No. 10 to Note Purchase Agreement TEACHERS INSURANCE AND ANNUITY ASSOCIATION OFAMERICA, as a NoteholderBy: /s/ Andrew M. LeicesterName: Andrew M. LeicesterTitle: Senior DirectorSignature Page to Amendment No. 10 to Note Purchase Agreement SUN LIFE ASSURANCE COMPANY OF CANADA,as a NoteholderBy: /s/ Keith CressmanName: Keith Cressman Title: Senior Managing DirectorPrivate Fixed IncomeBy: /s/ Jeffery MayerName: Jeffery MayerTitle: Managing Director, Private Securitization FinancePrivate Fixed IncomeSignature Page to Amendment No. 10 to Note Purchase Agreement Agreed to and acknowledged by the undersigned solely with respect to Section 5(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, its general 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 LLCSAWTOOTH NGL CAVERNS, LLCNGL SUPPLY TERMINAL SOLUTIONSMINING, LLCBy: /s/ H. Michael KrimbillName: /s/ H. Michael KrimbillTitle: Chief Executive OfficerSignature Page to Amendment No. 10 to Note Purchase Agreement ANNEX ASCHEDULE 5.4SUBSIDIARIES OF THE COMPANY AND OWNERSHIP OF SUBSIDIARY EQUITY INTERESTPart (a)(i) and (a)(ii).1 Corporate NameJurisdiction of OrganizationOrganizational ID NumbersNGL Energy Partners LP†Delaware4864184TransMontaigne LLC†Delaware2247557NGL Energy Finance Corp.*Delaware5408790NGL Energy Operating LLC†Delaware4864186NGL Energy Equipment LLC*Colorado20151651011Atlantic Propane LLC*Oklahoma3512344730High Sierra Energy GP, LLC*Colorado20041398052High Sierra Energy Shared Services, LLC*Colorado20071516948NGL Crude Logistics, LLC†Delaware2577845NGL Propane, LLC†Delaware4883225NGL Liquids, LLC†Delaware4883449NGL Water Solutions, LLC†Colorado20061397887High Sierra Energy, LP†Delaware3882384High Sierra Energy Operating, LLC†Colorado20041399037 High Sierra Energy Marketing, LLC†Colorado20051254557 NGL Solids Solutions, LLC*Colorado20141596966TransMontaigne Product Services LLC†Delaware2956958TransMontaigne Services LLC†Delaware4456325TransMontaigne Partners LP2 Delaware3898774NGL Crude Transportation, LLC†Colorado20141192981NGL Crude Cushing, LLC†Oklahoma3512295163E Energy Adams, LLC3 Nebraska10070006High Sierra Crude Oil & Marketing, LLC†Colorado20061507661NGL Crude Pipelines, LLC†Oklahoma3512273166NGL Energy Logistics, LLC†Delaware5351758NGL Energy Holdings II, LLC†Delaware4823380NGL Shipping and Trading, LLC†Delaware3463063 1 Each entity denoted by a † is a Note Party as of the Amendment No. 10 Effective Date. Each entity denoted by an * has been designated by the Note Partiesto be an Immaterial Subsidiary as of the Amendment No. 10 Effective Date.2 Specifically carved out of the “Subsidiary” definition, but included here for completeness.3 Does not meet the definition of “Subsidiary”, but included here for completeness.5.4-1 Corporate NameJurisdiction of OrganizationOrganizational ID NumbersNGL Milan Investments, LLC†Colorado20,141,558,772NGL Crude Terminals, LLC†Delaware4,900,064NGL Marine, LLC†Texas800,583,414NGL Crude Canada Holdings, LLC†Colorado20,131,042,653Glass Mountain Pipeline, LLC4 Delaware5,137,966Grand Mesa Pipeline, LLC†Delaware5,566,971NGL Crude Canada ULCAlberta, Canada2,017,241,023Blue Grama Land Corporation†Colorado20,141,693,614Osterman Propane, LLC†Delaware5,039,933Hicksgas, LLC†Delaware4,878,365NGL-NE Real Estate, LLC†Delaware5,098,953NGL-MA Real Estate, LLC†Delaware5,098,942NGL-MA, LLC†Delaware5,098,945Victory Propane, LLC5Oklahoma3,512,492,428Centennial Energy, LLC†Colorado19,951,007,685NGL Gateway Terminals, Inc.*Canada6,132,171NGL Supply Terminal Company, LLC†Delaware4,883,227NGL Supply Wholesale, LLC†Delaware4,883,230Centennial Gas Liquids, ULC†Alberta, Canada2,012,308,413Sawtooth NGL Caverns, LLC†Delaware5,037,140NGL Supply Terminal Solution Mining, LLC†Utah8615504-0160NGL Water Solutions Bakken, LLC†Colorado20,141,630,310NGL Water Solutions Mid-Continent, LLC†Colorado20,141,598,926Anticline Disposal, LLC†Wyoming2001-000419488NGL Water Solutions DJ, LLC†Colorado201,111,160,724NGL Water Solutions Eagle Ford, LLC†Delaware5,212,015NGL Water Solutions Permian, LLC†Colorado20,131,347,695Grassland Water Solutions LLC6 Delaware5,396,940High Sierra Water Services Midcontinent, LLC*Oklahoma3,512,151,390Indigo Injection #3-1, LLC*Delaware5,214,855Choya Operating, LLC*Texas801,760,203Andrews Oil Buyers, Inc.†Texas115,251,800NGL Hutch, LLC*Delaware5,187,973 4 Does not meet the definition of “Subsidiary”, but included here for completeness.5 Does not meet the definition of “Subsidiary”, but included here for completeness.6 Does not meet the definition of “Subsidiary”, but included here for completeness.5.4-2 Note PartyOwnership InterestNumber of SharesHeld% of total SharesNGL Energy Holdings LLCNGL Energy Partners LP†N/A0.1% GP Interest99.9% LP InterestNGL Energy Partners LPTransMontaigne LLC†N/A100%NGL Energy Partners LPNGL Energy Finance Corp.*N/A100%NGL Energy Partners LPNGL Energy Operating LLC†N/A100%NGL Energy Partners LPNGL Energy Equipment LLC*N/A100%NGL Energy Partners LPAtlantic Propane LLC*N/A60%NGL Energy Partners, LPHigh Sierra Energy GP, LLC*N/A100%High Sierra Energy GP, LLCHigh Sierra Shared Services, LLC*N/A98%High Sierra Energy, LPHigh Sierra Shared Services, LLC*N/A2%NGL Energy Partners LPTransMontaigne Partners LP7450,000 LP Units2.7350%NGL Energy Operating LLCNGL Crude Logistics, LLC†N/A100%NGL Energy Operating LLCNGL Propane, LLC†N/A100%NGL Energy Operating LLCNGL Liquids, LLC†N/A100%NGL Energy Operating LLCNGL Water Solutions, LLC†N/A100%NGL Energy Partners, LPHigh Sierra Energy, LP†N/A98%High Sierra Energy GP, LLCHigh Sierra Energy, LP†N/A2%High Sierra Energy, LPHigh Sierra Energy Operating, LLC†N/A100%High Sierra Energy Operating, LLCHigh Sierra Energy Marketing, LLC†N/A100%TransMontaigne LLCTransMontaigne Product Services LLC†N/A100%TransMontaigne Product Services LLCTransMontaigne Services LLC†N/A100%TransMontaigne Services LLCTransMontaigne Partners LP8 2,716,704 LP Units16.5384% LP InterestNGL Crude Logistics, LLCNGL Crude Transportation, LLC†N/A100%NGL Crude Logistics, LLCNGL Crude Cushing, LLC†N/A100% 7 Specifically carved out of the “Subsidiary” definition, but included here for completeness.8 Specifically carved out of the “Subsidiary” definition, but included here for completeness. Note PartyOwnership InterestNumber of SharesHeld% of total SharesNGL Crude Logistics, LLCE Energy Adams, LLC9N/A17.9%NGL Crude Logistics, LLCHigh Sierra Crude Oil & Marketing, LLC†N/A100%NGL Crude Logistics, LLCNGL Crude Pipelines, LLC†N/A100%NGL Crude Logistics, LLCNGL Energy Logistics, LLC†N/A100%NGL Crude Logistics, LLCNGL Energy Holdings II, LLC†N/A100%NGL Crude Logistics, LLCNGL Shipping and Trading, LLC†N/A100%NGL Crude Transportation, LLCNGL Milan Investments, LLC†N/A100%NGL Crude Transportation, LLCNGL Crude Terminals, LLC†N/A100%NGL Crude Transportation, LLCNGL Marine, LLC†N/A100%NGL Crude Terminals, LLCGrand Mesa Pipeline, LLC†N/A100%Grand Mesa Pipeline, LLCBlue Grama Land Corporation†N/A100%High Sierra Crude Oil & Marketing, LLCNGL Crude Canada Holdings, LLC†N/A100%NGL Crude Canada Holdings, LLCNGL Crude Canada ULCN/A100%NGL Energy Holdings II, LLCGlass Mountain Pipeline, LLC10N/A50%NGL Propane, LLCOsterman Propane, LLC†N/A100%NGL Propane, LLCHicksgas, LLC†N/A100%NGL Propane, LLCNGL-NE Real Estate, LLC†N/A100%NGL Propane, LLCNGL-MA Real Estate, LLC†N/A100%NGL Propane, LLCNGL-MA, LLC†N/A100%Osterman Propane, LLCVictory Propane, LLC11N/A50%NGL Liquids, LLCCentennial Energy, LLC†N/A100%NGL Liquids, LLCNGL Gateway Terminals, Inc.*N/A100%NGL Liquids, LLCNGL Supply Terminal Company, LLC†N/A100%NGL Liquids, LLCNGL Supply Wholesale, LLC†N/A100%Centennial Energy, LLCCentennial Gas Liquids, ULC†N/A100%NGL Supply Terminal Company, LLCSawtooth NGL Caverns, LLC†N/A100%NGL Supply Terminal Company, LLCNGL Hutch, LLC*N/A100%Sawtooth NGL Caverns, LLCNGL Supply Terminal Solution Mining, LLC†N/A100%NGL Water Solutions, LLCNGL Solids Solutions, LLC*N/A50%NGL Water Solutions, LLCNGL Water Solutions Bakken, LLC†N/A100%NGL Water Solutions, LLCNGL Water Solutions Mid-Continent, LLC†N/A100%NGL Water Solutions, LLCAnticline Disposal, LLC†N/A100%NGL Water Solutions, LLCNGL Water Solutions DJ, LLC†N/A100%NGL Water Solutions, LLCNGL Water Solutions Eagle Ford, LLC†N/A100%NGL Water Solutions, LLCNGL Water Solutions Permian, LLC†N/A100% 9 Does not meet the definition of “Subsidiary”, but included here for completeness.10 Does not meet the definition of “Subsidiary”, but included here for completeness.11 Does not meet the definition of “Subsidiary”, but included here for completeness. Note PartyOwnership InterestNumber of SharesHeld% of total SharesNGL Water Solutions DJ, LLCGrassland Water Solutions LLC12N/A27.78%NGL Water Solutions, LLCHigh Sierra Water Services Midcontinent, LLC*N/A100%NGL Water Solutions Eagle Ford, LLCIndigo Injection #3-1, LLC*N/A75%NGL Water Solutions Eagle Ford, LLCChoya Operating, LLC*N/A75%High Sierra Crude Oil & Marketing, LLCAndrews Oil Buyers, Inc.†200100%Part (a)(iii).Directors of NGL Energy Holdings LLC, the General Partner of NGL Energy Partners LP•H. Michael Krimbill•Stephen L. Cropper•James C. Kneale•Shawn W. Coady•Vincent J. Osterman•John Raymond•Bryan K. Guderian•Patrick Wade•James J. Burke•James M. CollingsworthSenior Officers of NGL Energy Holdings LLC, the General Partner of NGL Energy Partners LP•H. Michael Krimbill Chief Executive Officer and Interim Chief Financial Officer•Larry Thuillier Chief Accounting Officer, SVP Accounting•James J. Burke President•Vincent J. Osterman President, Eastern Retail Operations•Shawn W. Coady President, Retail Division•Jack Eberhart EVP, NGL Liquids•Don Robinson EVP, NGL Crude Logistics•Brian Cannon VP, Marketing•Christian Dobrauc SVP, Mergers & Acquisitions•Greg Blais SVP, Business Development•James F. Winter VP, NGL Water Solutions•Doug White SVP, NGL Water Solutions•Aaron Reece SVP, NGL Liquids•Jay Furman SVP, NGL Liquids•Todd Tanory SVP, NGL Asset Management•Grant Vangilder SVP, Bio Diesel•Don Jensen SVP, NGL Refined Products•Ben Borgen SVP, NGL Ethanol•Todd M. Coady SVP Administration•Sharra Straight SVP Accounting and Corporate Controller•Kurston P. McMurray Secretary & VP Legal 12 Does not meet the definition of “Subsidiary”, but included here for completeness. Exhibit 10.17Amendment No. 12 to Credit AgreementAMENDMENT NO. 12 TO CREDIT AGREEMENT, dated as of February 9, 2016 (this “Amendment”) to the Credit Agreement dated as of June19, 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. 3thereto dated 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, Amendment No. 8 thereto dated as of December 19,2014, Amendment No. 9 thereto dated May 1, 2015, Amendment No. 10 thereto dated as of July 31, 2015 and Amendment No. 11 thereto dated as ofDecember 28, 2015 (the credit agreement, as so amended and as otherwise amended, supplemented and modified from time to time, the “Credit Agreement”)among NGL 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” andcollectively, the “Borrowers”), Deutsche Bank AG, New York Branch, as technical agent (in such capacity, together with its successors in such capacity, the“Technical Agent”) and Deutsche Bank Trust Company Americas (“DBTCA”), as administrative agent for the Secured Parties (in such capacity, togetherwith its successors in such capacity, the “Administrative Agent”) and as collateral agent for the Secured Parties (in such capacity, together with its successorsin such capacity, the “Collateral Agent”) and each financial institution identified as a “Lender” or an “Issuing Bank” under the Credit Agreement (each, a“Lender” and together with the Technical Agent, the Administrative Agent and the Collateral Agent, the “Secured Parties”).RECITALSWHEREAS, the Borrowers have requested certain amendments to the Credit Agreement; andWHEREAS, 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.Amendment to Section 1.1 (Defined Terms) of the Credit Agreement. Section 1.1 of the Credit Agreement is hereby amended by addingthe following terms to Section 1.1 of the Credit Agreement as new defined terms in the appropriate alphabetical order:““Amendment No. 12 Effective Date” means February 9, 2016”““Bail-In Action” means the exercise of any Write-Down and Conversion Powers by the applicable EEA Resolution Authority in respect ofany liability of an EEA Financial Institution.”““Bail-In Legislation” means, with respect to any EEA Member Country implementing Article 55 of Directive 2014/59/EU of theEuropean Parliament and of the Council of the European Union, the implementing law for such EEA Member Country from time to timewhich is described in the EU Bail-In Legislation Schedule.”““EEA Financial Institution” means (a) any credit institution or investment firm established in any EEA Member Country which is subjectto the supervision of an EEA Resolution Authority, (b) any entity established in an EEA Member Country which is a parent of aninstitution described in clause (a) of this definition, or (c) any financial institution established in an EEA Member Country which is asubsidiary of an institution described in clauses (a) or (b) of this definition and is subject to consolidated supervision with its parent.”““EEA Member Country” means any of the member states of the European Union, Iceland, Liechtenstein, and Norway.”““EEA Resolution Authority” means any public administrative authority or any person entrusted with public administrative authority ofany EEA Member Country (including any delegee) having responsibility for the resolution of any EEA Financial Institution.” ““EU Bail-In Legislation Schedule” means the EU Bail-In Legislation Schedule published by the Loan Market Association (or anysuccessor person), as in effect from time to time.”““Increased Permitted Redemption Period” means the period from and including the Amendment No. 12 Effective Date to but excludingSeptember 15, 2016.““TransMontaigne GP Disposition” means the sale of all of the Equity Interests in TransMontaigne GP LLC, a Delaware limited liabilitycompany, by TransMontaigne Services LLC, a Delaware limited liability company, to Gulf TLP Holding, LLC, a Delaware limited liabilitycompany (or an Affiliate thereof), for aggregate gross cash consideration of approximately $350,000,000 on or before March 31, 2016, whichcash consideration shall be applied promptly upon receipt thereof as follows: (i) $250,000,000 of such cash consideration to prepayoutstanding Acquisition Revolving Loans and (ii) the remainder of such cash consideration (net of costs, expenses, fees and other similarpayments made in connection with such sale) to be applied to prepay outstanding Working Capital Revolving Loans.““Write-Down and Conversion Powers” means, with respect to any EEA Resolution Authority, the write-down and conversion powers ofsuch EEA Resolution Authority from time to time under the Bail-In Legislation for the applicable EEA Member Country, which write-downand conversion powers are described in the EU Bail-In Legislation Schedule.”3. Amendments to Section 1.1 (Defined Terms) of the Credit Agreement. Section 1.1 of the Credit Agreement is hereby further amended as follows:(a)The definition of “Change of Control” is hereby amended by deleting the phrase “on Schedule 5.8 as in effect on the ClosingDate” as it appears in clause (a) of such defined term immediately following the phrase “the percentage of the Equity Interests of each Credit Party asset forth” and immediately before the phrase “(other than as a result of a Permitted Disposition)” with the following phrase, “in Part B of Schedule5.7 on the Amendment No. 12 Effective Date”.(b)Clause (d) of the definition of “Defaulting Lender” is hereby amended by deleting the word “or” as it appears following thephrase “under any Debtor Relief Law,” at the end of clause (i) therein, and by adding the following phrase immediately after the phrase “any otherstate or federal regulatory authority acting in such a capacity,” at the end of clause (ii) therein:“or (iii) becomes the subject of a Bail-In Action”.(c)The definition of “Indebtedness” is hereby amended by (i) deleting the word “and” as it appears immediately prior to clause (k)and (ii) deleting the period at the end of such definition and inserting in lieu thereof, the following:“and (l) all mandatory obligations of such Person to purchase, redeem, retire or defease any Equity Interests in such Person or any other Personprior to June 20, 2022, valued, in the case of a redeemable preferred interest, at the greater of its voluntary or involuntary liquidation preferenceplus accrued and unpaid dividends.”4. Amendments to Section 7.10(a) (Redemption, Dividends, Equity Issuance, Distributions and Payments) of the Credit Agreement. Section 7.10(a)of the Credit Agreement is hereby amended by deleting in its entirety the proviso at the end of clause (i) thereof as it appears immediately before the phrase“or (ii) redemption in connection with a Permitted Acquisition” and inserting in lieu thereof, the following:“; provided that, notwithstanding the foregoing, (A) during the Increased Permitted Redemption Period and to the extent that both (i) theTransMontaigne GP Disposition has been consummated in accordance with its terms and (ii) the Parent has obtained aggregate net cashproceeds of not less than $200,000,000 from any combination of unsecured Indebtedness permitted by Section 7.1(l) of this Agreement and theParent’s issuance of Equity Interests in the Parent, in each case incurred or issued on or after the Amendment No. 12 Effective Date, the Parentshall be permitted to redeem, purchase, retire or otherwise acquire common units of the Parent in an aggregate amount not to exceed$75,000,000 (such amount not to be in addition to any other limit set forth in this Section 7.10(a)(i)), and (B) after the expiration of theIncreased Permitted Redemption Period, (x) the limits set forth in this Section 7.10(a)(i) (without giving effect to this proviso) shall apply andall of the redemptions, repurchases, retirements or other acquisitions of Equity Interests that occurred during the Increased PermittedRedemption Period shall reduce the available amounts otherwise permitted under Section 7.10(a)(i) (for the avoidance of doubt, redemptions,repurchases, retirements or other acquisitions of Equity Interests made during the Increased Permitted Redemptions Period that were permittedby clause (A) of this proviso shall not be deemed a breach of the limits set forth in Section 7.10(a)(i) after the2 expiration of such Increased Permitted Redemption Period), and (y) if the Parent redeems, repurchases, retires or otherwise acquires commonunits of the Parent in an aggregate amount in excess of $45,000,000 during the Increased Permitted Redemption Period, no Credit Party shall bepermitted to redeem, repurchase, retire or otherwise acquire any Equity Interests of the Company prior to January 1, 2019 unless the Parent hasdelivered a certificate of a Financial Officer of the Parent pursuant to Section 6.3 of this Agreement evidencing that the Leverage Ratio of theCredit Parties as of the last day of the most recently ended fiscal quarter ending after December 31, 2015 is not greater than 3.50 to 1.00”.5. Amendment to Article X (Miscellaneous) of the Credit Agreement. Article X of the Credit Agreement is hereby amended by adding the below asnew Section 10.27 (Acknowledgement and Consent to Bail-In of EEA Financial Institutions) at the end of such Article clause:“Section 10.27 Acknowledgement and Consent to Bail-In of EEA Financial Institutions. Notwithstanding anything to the contrary in any LoanDocument or in any other agreement, arrangement or understanding among any such parties, each party hereto acknowledges that any liabilityof any EEA Financial Institution arising under any Loan Document, to the extent such liability is unsecured, may be subject to the write-downand conversion powers of an EEA Resolution Authority and agrees and consents to, and acknowledges and agrees to be bound by:(a)the application of any Write-Down and Conversion Powers by an EEA Resolution Authority to any such liabilitiesarising hereunder that may be payable to it by any party hereto that is an EEA Financial Institution; and(b)the effects of any Bail-in Action on any such liability, including, if applicable:(i)a reduction in full or in part or cancellation of any such liability;(ii)a conversion of all, or a portion of, such liability into shares or other instruments of ownership in such EEAFinancial Institution, its parent undertaking, or a bridge institution that may be issued to it or otherwise conferred on it, and that suchshares or other instruments of ownership will be accepted by it in lieu of any rights with respect to any such liability under thisAgreement or any other Loan Document; or(iii)the variation of the terms of such liability in connection with the exercise of the write-down and conversionpowers of any EEA Resolution Authority.6. Amendment to Schedule 5.7 of the Credit Agreement (Subsidiaries, Jurisdictions of Foreign Qualification; Capitalization). Schedule 5.7 of theCredit Agreement is hereby amended by deleting such Schedule in its entirety and replacing it with the Schedule 5.7 attached hereto as Annex A.7. Representations and Warranties; No Default. To induce the Lenders to enter into this Amendment, each Credit Party that is a party hereto (bydelivery of its respective counterpart to this Amendment) hereby (i) represents and warrants to each Agent and the Lenders that after giving effect to thisAmendment, its representations and warranties contained in the Credit Agreement and other Loan Documents are true and correct in all material respects onand as of the date hereof with the same effect as though made on and as of the date hereof, except to the extent such representations and warranties expresslyrelate to an earlier date (in which case such representations and warranties were true and correct in all material respects as of such earlier date); (ii) representsand warrants to the Administrative Agent and the Lenders that in connection with this Amendment and all other documents delivered in connection herewithit (x) has the requisite power and authority to make, deliver and perform the same; (y) has taken all necessary corporate, limited liability company, limitedpartnership 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 tothis Amendment) or will result from the making of this Amendment.8. Conditions to Effectiveness. This Amendment shall become effective upon the first date on which each of the following conditions has beensatisfied:(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.3 (b) Fees and Expenses. The Borrowers shall have paid to the Administrative Agent for the account of (i) the Agents and Lenders theamount of any and all reasonable fees, costs and expenses that are for the account of the Borrowers pursuant to Section 10.9 of the Credit Agreement(including without limitation in connection with this Amendment) and (ii) each Lender that delivers an executed counterpart to this Amendment tothe Technical Agent prior to noon (New York time) February 8, 2016, a fee equal to 0.05% multiplied by the aggregate amount of such Lender’sCommitment at such time under the Credit Agreement.(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.9. Limited Effect. Except as expressly provided hereby, all of the terms and provisions of the Credit Agreement and the other Loan Documents areand shall remain in full force and effect. The amendments contained herein shall not be construed as a waiver or amendment of any other provision of theCredit Agreement or the other Loan Documents or for any purpose, except as expressly set forth herein, or a consent to any further or future action on the partof any Credit Party that would require the waiver or consent of the Lenders. This Amendment shall constitute a “Loan Document” for all purposes of theCredit Agreement and the other Loan Documents.10. GOVERNING LAW. THIS AMENDMENT AND THE RIGHTS AND OBLIGATIONS OF THE PARTIES UNDER THIS AMENDMENTSHALL BE GOVERNED BY AND CONSTRUED IN ACCORDANCE WITH THE SUBSTANTIVE LAW OF THE STATE OF NEW YORK.11. Counterparts. This Amendment may be executed in any number of counterparts, all of which taken together shall constitute one and the sameagreement, 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.12. Headings. Section or other headings contained in this Amendment are for reference purposes only and shall not in any way affect the meaningor interpretation of this Amendment.13. Guarantor Acknowledgement. Each Guarantor party hereto hereby (i) consents to the modifications to the Credit Agreement contemplated bythis Amendment and (ii) acknowledges and agrees that its guaranty pursuant to Section 10.18 of the Credit Agreement is, and shall remain, in full force andeffect after giving effect to the Amendment.14. 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.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 LLCBy: /s/ H. Michael KrimbillName: H. Michael KrimbillTitle: Chief Executive OfficerGUARANTOR:NGL ENERGY PARTNERS LPBy: NGL Energy Holdings LLC,its general partnerBy: /s/ H. Michael KrimbillName: H. Michael KrimbillTitle: Chief Executive Officer[Signature Page to Amendment No. 12 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 general 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 TERMINAL SOLUTION MINING, 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, LLCSAWTOOTH NGL CAVERNS, LLCTRANSMONTAIGNE LLCTRANSMONTAIGNE PRODUCT SERVICES LLCTRANSMONTAIGNE SERVICES LLCBy: /s/ H. Michael KrimbillName: H. Michael KrimbillTitle: Chief Executive Officer[Signature Page to Amendment No. 12 to Credit Agreement] SECURED PARTIES:DEUTSCHE BANK TRUST COMPANY AMERICAS, as Administrative Agent and as Collateral AgentBy: /s/ Jennifer Van DyneName: Jennifer Van DyneTitle: Assistant Vice PresidentBy: /s/ David McGuireName: David McGuireTitle: Assistant Vice PresidentDEUTSCHE BANK AG, NEW YORK BRANCH,as a Lender, as Swingline Lender, as an Issuing Bank and asTechnical AgentBy: /s/ Chris ChapmanName: Chris ChapmanTitle: DirectorBy: /s/ Shai BandnerName: Shai BandnerTitle: Vice President[Signature Page to Amendment No. 12 to Credit Agreement] ROYAL BANK OF CANADA,as a LenderBy: /s/ Jason S. YorkName: Jason S. YorkTitle: Authorized Signatory[Signature Page to Amendment No. 12 to Credit Agreement] BNP PARIBAS,as a Lender and Issuing BankBy: /s/ Christine Dirringer Name: Christine DirringerTitle: Managing DirectorBy: /s/ Pauline BlandinName: Pauline BlandinTitle: Associate[Signature Page to Amendment No. 12 to Credit Agreement] THE BANK OF TOKYO-MITSUBISHI UFJ, LTD.,as LenderBy: Name:Title:[Signature Page to Amendment No. 12 to Credit Agreement] PNC BANK, NATIONAL ASSOCIATION,as a Lender and Issuing BankBy: /s/ Jessica McGuireName: Jessica McGuireTitle: Assistant Vice President[Signature Page to Amendment No. 12 to Credit Agreement] THE ROYAL BANK OF SCOTLAND PLC,as a LenderBy: Name:Title:[Signature Page to Amendment No. 12 to Credit Agreement] RAYMOND JAMES BANK, N.A.,as a LenderBy: /s/ Scott G. AxelrodName: Scott G. AxelrodTitle: Senior Vice President[Signature Page to Amendment No. 12 to Credit Agreement] ABN AMRO CAPITAL USA LLC,as a LenderBy: /s/ Darrell HolleyName: Darrell HolleyTitle: Managing DirectorBy: /s/ Kaylan HopsonName: Kaylan HopsonTitle: Vice President[Signature Page to Amendment No. 12 to Credit Agreement] BANK OF AMERICA, N.A.,as a Lender and as an Issuing BankBy: /s/ Michael Clayborne Name: Michael ClayborneTitle: Director[Signature Page to Amendment No. 12 to Credit Agreement] SUNTRUST BANK,as a LenderBy: /s/ Carmen MaliziaName: Carmen MaliziaTitle: Director[Signature Page to Amendment No. 12 to Credit Agreement] UBS AG, STAMFORD BRANCH,as a LenderBy: /s/ Darlene AriasName: Darlene AriasTitle: DirectorBy: /s/ Denise BusheeName: Denise BusheeTitle: Associate Director[Signature Page to Amendment No. 12 to Credit Agreement] COMMERCE BANK, N.A.,as a LenderBy: /s/ David D. SchererName: David D. SchererTitle: Vice President[Signature Page to Amendment No. 12 to Credit Agreement] GOLDMAN SACHS BANK USA,as a LenderBy: /s/ Jerry LiName: Jerry LiTitle: Authorized Signatory[Signature Page to Amendment No. 12 to Credit Agreement] MACQUARIE BANK LIMITED,as a LenderBy: /s/ Andrew McGrathName: Andrew McGrathTitle: Executive DirectorBy: /s/ Nathan BookerName: Nathan BookerTitle: Division Director[Signature Page to Amendment No. 12 to Credit Agreement] KEYBANK NATIONAL ASSOCIATION,as a LenderBy: Name:Title:[Signature Page to Amendment No. 12 to Credit Agreement] WELLS FARGO BANK, NATIONAL ASSOCIATION,as a LenderBy: /s/ Andrew OstrovName: Andrew OstrovTitle: Director[Signature Page to Amendment No. 12 to Credit Agreement] BARCLAYS BANK PLC,as a LenderBy: /s/ Vanessa KurbatskiyName: Vanessa KurbatskiyTitle: Vice President[Signature Page to Amendment No. 12 to Credit Agreement] SOCIETE GENERALEas a LenderBy: /s/ Michiel V.M. Van Der VoorName: Michiel V.M. Van Der VoortTitle: Managing Director[Signature Page to Amendment No. 12 to Credit Agreement] TORONTO DOMINION (TEXAS) LLC,as a LenderBy: /s/ Savo BozicName: Savo BozicTitle: Authorized Signatory[Signature Page to Amendment No. 12 to Credit Agreement] MIZUHO BANK, LTD.,as a LenderBy: /s/ Leon MoName: Leon MoTitle: Authorized Signatory[Signature Page to Amendment No. 12 to Credit Agreement] CITIZENS BANK, N.A.,as a LenderBy: /s/ Scott DonaldsonName: Scott DonaldsonTitle: Senior Vice President[Signature Page to Amendment No. 12 to Credit Agreement] CREDIT SUISSE AG, CAYMAN ISLANDS BRANCH,as a LenderBy: /s/ Nupur KumarName: Nupur KumarTitle: Authorized SignatoryBy: /s/ Warren Van HeystName: Warren Van HeystTitle: Authorized Signatory[Signature Page to Amendment No. 12 to Credit Agreement] ZB, N.A. dba AMEGY BANK,as a LenderBy: /s/ Kevin DonaldsonName: Kevin DonaldsonTitle: Senior Vice President[Signature Page to Amendment No. 12 to Credit Agreement] ANNEX A TOAMENDMENT NO. 12SCHEDULE 5.7SUBSIDIARIES and CAPITALIZATIONPart A. 1 Corporate NameJurisdiction of OrganizationOrganizational ID NumbersNGL Energy Partners LP†Delaware4864184TransMontaigne LLC†Delaware2247557NGL Energy Finance Corp.*Delaware5408790NGL Energy Operating LLC†Delaware4864186NGL Energy Equipment LLC*Colorado20151651011Atlantic Propane LLC*Oklahoma3512344730High Sierra Energy GP, LLC*Colorado20041398052High Sierra Energy Shared Services, LLC*Colorado20071516948NGL Crude Logistics, LLC†Delaware2577845NGL Propane, LLC†Delaware4883225NGL Liquids, LLC†Delaware4883449NGL Water Solutions, LLC†Colorado20061397887High Sierra Energy, LP†Delaware3882384High Sierra Energy Operating, LLC†Colorado20041399037High Sierra Energy Marketing, LLC†Colorado20051254557NGL Solids Solutions, LLC*Colorado20141596966TransMontaigne Product Services LLC†Delaware2956958TransMontaigne Services LLC†Delaware4456325TransMontaigne Partners LP2Delaware3898774NGL Crude Transportation, LLC†Colorado20141192981NGL Crude Cushing, LLC†Oklahoma3512295163E Energy Adams, LLC3Nebraska10070006High Sierra Crude Oil & Marketing, LLC†Colorado20061507661NGL Crude Pipelines, LLC†Oklahoma3512273166NGL Energy Logistics, LLC†Delaware5351758NGL Energy Holdings II, LLC†Delaware4823380NGL Shipping and Trading, LLC†Delaware3463063NGL Milan Investments, LLC†Colorado20141558772NGL Crude Terminals, LLC†Delaware4900064NGL Marine, LLC†Texas800583414 1 Each entity denoted by a † is a Credit Party as of the Amendment No. 12 Effective Date. Each entity denoted by an * has been designated by the CreditParties to be an Immaterial Subsidiary as of the Amendment No. 12 Effective Date.2 Specifically carved out of the “Subsidiary” definition, but included here for completeness.3 Does not meet the definition of “Subsidiary”, but included here for completeness.5.7-30 ANNEX A TOAMENDMENT NO. 12Corporate NameJurisdiction of OrganizationOrganizational ID NumbersNGL Crude Canada Holdings, LLC†Colorado20131042653Glass Mountain Pipeline, LLC4Delaware5137966Grand Mesa Pipeline, LLC†Delaware5566971NGL Crude Canada ULCAlberta, Canada2017241023Blue Grama Land Corporation†Colorado20141693614Osterman Propane, LLC†Delaware5039933Hicksgas, LLC†Delaware4878365NGL-NE Real Estate, LLC†Delaware5098953NGL-MA Real Estate, LLC†Delaware5098942NGL-MA, LLC†Delaware5098945Victory Propane, LLC5Oklahoma3512492428Centennial Energy, LLC†Colorado19951007685NGL Gateway Terminals, Inc.*Canada6132171NGL Supply Terminal Company, LLC†Delaware4883227NGL Supply Wholesale, LLC†Delaware4883230Centennial Gas Liquids, ULC†Alberta, Canada2012308413Sawtooth NGL Caverns, LLC†Delaware5037140NGL Supply Terminal Solution Mining, LLC†Utah8615504-0160NGL Water Solutions Bakken, LLC†Colorado20141630310NGL Water Solutions Mid-Continent, LLC†Colorado20141598926Anticline Disposal, LLC†Wyoming2001-000419488NGL Water Solutions DJ, LLC†Colorado201111160724NGL Water Solutions Eagle Ford, LLC†Delaware5212015NGL Water Solutions Permian, LLC†Colorado20131347695Grassland Water Solutions LLC6Delaware5396940High Sierra Water Services Midcontinent, LLC*Oklahoma3512151390Indigo Injection #3-1, LLC*Delaware5214855Choya Operating, LLC*Texas801760203Andrews Oil Buyers, Inc.†Texas115251800NGL Hutch, LLC*Delaware5187973 4 Does not meet the definition of “Subsidiary”, but included here for completeness.5 Does not meet the definition of “Subsidiary”, but included here for completeness.6 Does not meet the definition of “Subsidiary”, but included here for completeness.5.7-31 ANNEX A TOAMENDMENT NO. 12Part B. 7 Credit PartyOwnership InterestNumber of Shares Held% of total SharesNGL Energy Holdings LLCNGL Energy Partners LP†N/A0.1% GP Interest99.9% LP InterestNGL Energy Partners LPTransMontaigne LLC†N/A100%NGL Energy Partners LPNGL Energy Finance Corp.*N/A100%NGL Energy Partners LPNGL Energy Operating LLC†N/A100%NGL Energy Partners LPNGL Energy Equipment LLC*N/A100%NGL Energy Partners LPAtlantic Propane LLC*N/A60%NGL Energy Partners, LPHigh Sierra Energy GP, LLC*N/A100%High Sierra Energy GP, LLCHigh Sierra Shared Services, LLC*N/A98%High Sierra Energy, LPHigh Sierra Shared Services, LLC*N/A2%NGL Energy Partners LPTransMontaigne Partners LP8450,000 LP Units2.7350%NGL Energy Operating LLCNGL Crude Logistics, LLC†N/A100%NGL Energy Operating LLCNGL Propane, LLC†N/A100%NGL Energy Operating LLCNGL Liquids, LLC†N/A100%NGL Energy Operating LLCNGL Water Solutions, LLC†N/A100%NGL Energy Partners, LPHigh Sierra Energy, LP†N/A98%High Sierra Energy GP, LLCHigh Sierra Energy, LP†N/A2%High Sierra Energy, LPHigh Sierra Energy Operating, LLC†N/A100%High Sierra Energy Operating, LLCHigh Sierra Energy Marketing, LLC†N/A100%TransMontaigne LLCTransMontaigne Product Services LLC†N/A100% 7 Each entity denoted by a † is a Credit Party as of the Amendment No. 12 Effective Date. Each entity denoted by an * has been designated by the CreditParties to be an Immaterial Subsidiary as of the Amendment No. 12 Effective Date.8 Specifically carved out of the “Subsidiary” definition, but included here for completeness. ANNEX A TOAMENDMENT NO. 12Credit PartyOwnership InterestNumber of Shares Held% of total SharesTransMontaigne Product Services LLCTransMontaigne Services LLC†N/A100%TransMontaigne Services LLCTransMontaigne Partners LP92,716,704 LP Units16.5384% LP InterestNGL Crude Logistics, LLCNGL Crude Transportation, LLC†N/A100%NGL Crude Logistics, LLCNGL Crude Cushing, LLC†N/A100%NGL Crude Logistics, LLCE Energy Adams, LLC10N/A17.9%NGL Crude Logistics, LLCHigh Sierra Crude Oil & Marketing, LLC†N/A100%NGL Crude Logistics, LLCNGL Crude Pipelines, LLC†N/A100%NGL Crude Logistics, LLCNGL Energy Logistics, LLC†N/A100%NGL Crude Logistics, LLCNGL Energy Holdings II, LLC†N/A100%NGL Crude Logistics, LLCNGL Shipping and Trading, LLC†N/A100%NGL Crude Transportation, LLCNGL Milan Investments, LLC†N/A100%NGL Crude Transportation, LLCNGL Crude Terminals, LLC†N/A100%NGL Crude Transportation, LLCNGL Marine, LLC†N/A100%NGL Crude Terminals, LLCGrand Mesa Pipeline, LLC†N/A100%Grand Mesa Pipeline, LLCBlue Grama Land Corporation†N/A100%High Sierra Crude Oil & Marketing, LLCNGL Crude Canada Holdings, LLC†N/A100%NGL Crude Canada Holdings, LLCNGL Crude Canada ULCN/A100%NGL Energy Holdings II, LLCGlass Mountain Pipeline, LLC11N/A50%NGL Propane, LLCOsterman Propane, LLC†N/A100%NGL Propane, LLCHicksgas, LLC†N/A100%NGL Propane, LLCNGL-NE Real Estate, LLC†N/A100%NGL Propane, LLCNGL-MA Real Estate, LLC†N/A100%NGL Propane, LLCNGL-MA, LLC†N/A100% 9 Specifically carved out of the “Subsidiary” definition, but included here for completeness.10 Does not meet the definition of “Subsidiary”, but included here for completeness.11 Does not meet the definition of “Subsidiary”, but included here for completeness. ANNEX A TOAMENDMENT NO. 12Credit PartyOwnership InterestNumber of Shares Held% of total SharesOsterman Propane, LLCVictory Propane, LLC12N/A50%NGL Liquids, LLCCentennial Energy, LLC†N/A100%NGL Liquids, LLCNGL Gateway Terminals, Inc.*N/A100%NGL Liquids, LLCNGL Supply Terminal Company, LLC†N/A100%NGL Liquids, LLCNGL Supply Wholesale, LLC†N/A100%Centennial Energy, LLCCentennial Gas Liquids, ULC†N/A100%NGL Supply Terminal Company, LLCSawtooth NGL Caverns, LLC†N/A100%NGL Supply Terminal Company, LLCNGL Hutch, LLC*N/A100%Sawtooth NGL Caverns, LLCNGL Supply Terminal Solution Mining,LLC†N/A100%NGL Water Solutions, LLCNGL Solids Solutions, LLC*N/A50%NGL Water Solutions, LLCNGL Water Solutions Bakken, LLC†N/A100%NGL Water Solutions, LLCNGL Water Solutions Mid-Continent, LLC†N/A100%NGL Water Solutions, LLCAnticline Disposal, LLC†N/A100%NGL Water Solutions, LLCNGL Water Solutions DJ, LLC†N/A100%NGL Water Solutions, LLCNGL Water Solutions Eagle Ford, LLC†N/A100%NGL Water Solutions, LLCNGL Water Solutions Permian, LLC†N/A100%NGL Water Solutions DJ, LLCGrassland Water Solutions LLC13N/A27.78%NGL Water Solutions, LLCHigh Sierra Water Services Midcontinent,LLC*N/A100%NGL Water Solutions Eagle Ford, LLCIndigo Injection #3-1, LLC*N/A75%NGL Water Solutions Eagle Ford, LLCChoya Operating, LLC*N/A75%High Sierra Crude Oil & Marketing, LLCAndrews Oil Buyers, Inc.†200100% 12 Does not meet the definition of “Subsidiary”, but included here for completeness.13 Does not meet the definition of “Subsidiary”, but included here for completeness. Exhibit 12.1NGL ENERGY PARTNERS LP AND SUBSIDIARIESCOMPUTATION OF RATIOS OF (LOSS) EARNINGS TO FIXED CHARGES(In thousands, except ratio amounts) Year Ended March 31, 2016 2015 (1) 2014 2013 2012 (LOSS) EARNINGS: (Loss) income before income taxes $(187,464) $46,571 $49,695 $50,065 $8,465(Income) loss before income taxes attributable to noncontrolling interests (11,832) (12,887) (1,103) (250) 12Fixed charges 146,401 151,956 91,622 66,824 9,354Total (loss) earnings $(52,895) $185,640 $140,214 $116,639 $17,831 FIXED CHARGES: Interest expense $133,089 $110,123 $58,854 $32,994 $7,620(Gain) loss on early extinguishment of debt (28,532) — — 5,769 —Portion of rental expense estimated to relate to interest (2) 41,844 41,833 32,768 28,061 1,734Fixed charges $146,401 $151,956 $91,622 $66,824 $9,354 Ratio of earnings to fixed charges (3) — 1.22 1.53 1.75 1.91 (1) We have changed our previously issued consolidated balance sheet as of March 31, 2015 and consolidated statement of operations, consolidatedstatement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year ended March 31,2015 for the correction of an immaterial error (see Note 17 to our consolidated financial statements included in this Annual Report).(2)Represents one-third of the total operating lease rental expense, which is that portion estimated to represent interest.(3)The ratio was less than 1:1 for the year ended March 31, 2016. NGL Energy Partners LP would have needed to generate an additional $199.3 million ofearnings to achieve a ratio of 1:1. Exhibit 21.1 LIST OF SUBSIDIARIES OF NGL ENERGY PARTNERS LPSubsidiaryJurisdiction of OrganizationNGL Energy Operating LLCDelawareNGL Energy Finance Corp.DelawareTransMontaigne LLCDelawareNGL Energy Equipment LLC ColoradoAtlantic Propane, LLC (1)OklahomaNGL Crude Logistics, LLC DelawareNGL Crude Transportation, LLCColoradoNGL Crude Terminals, LLC DelawareNGL Marine, LLCTexasNGL Milan Investments, LLC ColoradoGrand Mesa Pipeline, LLC DelawareBlue Grama Land CorporationColoradoNGL 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, LLCDelawareNGL 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, LLC DelawareNGL Water Solutions, LLCColoradoNGL Water Solutions Bakken, LLCColoradoNGL Water Solutions Mid-Continent, LLCColoradoNGL Water Pipelines, LLCTexasNGL Solids Solutions, LLC (5)ColoradoAntiCline Disposal, LLCWyoming SubsidiaryJurisdiction of OrganizationNGL 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 LLCDelawareHigh 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 a 19% member 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 35% 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. Exhibit 23.1 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We have issued our reports dated May 31, 2016, with respect to the consolidated financial statements and internal control overfinancial reporting included in the Annual Report of NGL Energy Partners LP on Form 10-K for the year ended March 31, 2016. Wehereby consent to the incorporation by reference of said reports in the Registration Statements of NGL Energy Partners LP on Form S-8(File No. 333-185068) and on Forms S-3 (File No. 333-189842 and File No. 333-194035) /s/ GRANT THORNTON LLP Tulsa, Oklahoma May 31, 2016 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 : May 31, 2016/s/ H. Michael Krimbill H. Michael Krimbill Chief Executive Officer of NGL Energy Holdings LLC, the general partner ofNGL Energy Partners LP Exhibit 31.2 CERTIFICATION I, Robert W. Karlovich III, 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 : May 31, 2016/s/ Robert W. Karlovich III Robert W. Karlovich III Chief Financial Officer of NGL Energy Holdings LLC, the general partner ofNGL Energy Partners LP Exhibit 32.1CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 In connection with the Annual Report of NGL Energy Partners LP (the “Partnership”) on Form 10-K for the fiscal year ended March 31, 2016 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 : May 31, 2016/s/ H. Michael Krimbill H. Michael Krimbill Chief Executive Officer of NGL Energy Holdings LLC, the general partner ofNGL 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 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350 In connection with the Annual Report of NGL Energy Partners LP (the “Partnership”) on Form 10-K for the fiscal year ended March 31, 2016 asfiled with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert W. Karlovich III, Chief Financial Officer of NGL EnergyHoldings LLC, the general partner of the Partnership, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-OxleyAct of 2002 (“Section 906”), that, to my knowledge: 1. The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of thePartnership. Date : May 31, 2016/s/ Robert W. Karlovich III Robert W. Karlovich III Chief Financial Officer of NGL Energy Holdings LLC, the general partner ofNGL 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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