NGL Energy Partners
Annual Report 2017

Plain-text annual report

Table of ContentsUNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549Form 10-K(Mark One)x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934For the fiscal year ended March 31, 2017ORo 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 Avenue, Suite 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 x 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 xIndicate 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 x NooIndicate 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 x 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, smaller reporting company, or an emerging growthcompany. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth 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 oEmerging growth company o If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financialaccounting standards provided pursuant to Section 13(a) of the Exchange Act. oIndicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No xThe aggregate market value at September 30, 2016 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 ($18.84 per Common Unit) was $1.7 billion. For purposes of this computation, all executive officers, directors and 10% beneficialowners of the registrant are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers, directors and 10% beneficial owners areaffiliates.At May 23, 2017, there were 120,787,060 common units issued and outstanding.Table of ContentsTABLE OF CONTENTSPART I Item 1.Business3Item 1A.Risk Factors28Item 1B.Unresolved Staff Comments52Item 2.Properties52Item 3.Legal Proceedings52Item 4.Mine Safety Disclosures52 PART II Item 5.Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities53Item 6.Selected Financial Data54Item 7.Management’s Discussion and Analysis of Financial Condition and Results of Operations56Item 7A.Quantitative and Qualitative Disclosures About Market Risk97Item 8.Financial Statements and Supplementary Data98Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure98Item 9A.Controls and Procedures98Item 9B.Other Information99 PART III Item 10.Directors, Executive Officers and Corporate Governance100Item 11.Executive Compensation105Item 12.Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters117Item 13.Certain Relationships and Related Transactions, and Director Independence118Item 14.Principal Accounting Fees and Services122 PART IV Item 15.Exhibits, Financial Statement Schedules123i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 affect our consolidated financial position and results of operations are:•the prices of crude oil, natural gas liquids, gasoline, diesel, 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, gasoline, diesel, ethanol, and biodiesel;•the availability of supply of crude oil, natural gas liquids, gasoline, diesel, 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 affects 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, gasoline, diesel, 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 effect of energy conservation efforts on product demand;•energy efficiencies and technological trends;•governmental regulation and taxation;•the effect of legislative and regulatory actions on hydraulic fracturing, wastewater disposal, and the treatment of flowback and produced water;•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, wastewater disposal, recycling, and dischargeservices;•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 complete accretive 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 interpretationsby regulatory agencies concerning such laws and regulations and the effect 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;•changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our pipeline assets; and•other risks and uncertainties, including those discussed under Part I, Item 1A–“Risk Factors.”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 may be required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-lookingstatements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks discussed underPart I, Item 1A–“Risk Factors.”2Table of ContentsPART IReferences 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, 2017. Unless otherwise indicated, this data is as ofMarch 31, 2017. 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, 2017, our operations include:•Our Crude Oil Logistics segment purchases crude oil from producers and transports it to refineries or for resale at pipeline injection stations,storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.•Our Water Solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas productionand for the disposal of solids such as tank bottoms and drilling fluids and performs truck and frac tank washouts. In addition, our WaterSolutions segment sells the recovered hydrocarbons that result from performing these services.•Our Liquids segment supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and inCanada using its leased underground storage and fleet of leased railcars, markets regionally through its 21 owned terminals throughout theUnited States, and provides terminaling and storage services at its salt dome storage facility in Utah.•Our Retail Propane segment sells propane, distillates, equipment and supplies to end users consisting of residential, agricultural, commercial,and industrial customers and to certain resellers in 30 states and the District of Columbia.•Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refinedpetroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedules them fordelivery at various locations throughout the country.For more information regarding our reportable segments, 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. The following summarizes ouracquisitions over the past five fiscal years.Year Ended March 31, 2013•In May 2012, we completed a business combination with Downeast Energy Corp., whereby we acquired retail propane and distillate operationsprimarily in the northeastern United States.•In June 2012, we completed a business combination with High Sierra Energy, LP and High Sierra Energy GP, LLC (collectively, “High Sierra”),whereby we acquired all of the ownership interests in High Sierra. High Sierra’s businesses included crude oil gathering, transportation andmarketing; water treatment, disposal, and transportation; and natural gas liquids transportation and marketing.3Table of Contents•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 consisted 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 consisted 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 required 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 included 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 included 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 inE Energy Adams, LLC, an ethanol production facility in the Midwest. The operations of Gavilon Energy included the marketing of crude oil,refined products, ethanol, biodiesel, and natural gas liquids, and also included crude oil storage in Cushing, Oklahoma.Year Ended March 31, 2015•In July 2014, we acquired TransMontaigne Inc. (“TransMontaigne”). The operations of TransMontaigne included the marketing of refinedproducts. As part of this transaction, we also purchased inventory from the previous owner of TransMontaigne, the 2% general partner interest,the incentive distribution rights, a 19.7% limited partner interest in TransMontaigne Partners L.P. (“TLP”), and assumed certain terminalingservice agreements with TLP from an affiliate of the previous owner of TransMontaigne. See “Dispositions” below for a discussion of the sale ofthe general and limited partner interests in TLP.•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.4Table of Contents•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.Year Ended March 31, 2017•In June 2016, we acquired an additional 24.5% interest in an existing produced water pipeline company operating in the Delaware Basinportion of West Texas.•In June 2016, we acquired the remaining 65% ownership interest in Grassland Water Solutions, LLC (“Grassland”), which we subsequently soldin November 2016 (see “Dispositions” below for a discussion of the sale).•In September 2016, we acquired the remaining 25% ownership interest in three water solutions facilities in the Eagle Ford shale play in Texas.•In January 2017, we acquired a natural gas liquids terminal that supports refined products blending in Port Hudson, Louisiana, and a natural gasliquids and condensate facility in Kingfisher, Oklahoma.•During the year ended March 31, 2017, we acquired three water solutions facilities.•During the year ended March 31, 2017, we acquired four retail propane businesses.DispositionsSale of General Partner Interest in TLPOn February 1, 2016, we sold our general partner interest in TLP to an affiliate of ArcLight Capital Partners (“ArcLight”) for $350 million in cash. Asa result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting.As part of this transaction, we entered into lease agreements whereby we will remain the long-term exclusive tenant in the TLP Southeast terminal system. Inaddition, we retained TransMontaigne Product Services, LLC, including its marketing business, customer contracts and its line space on the Colonial andPlantation pipelines, which is a significant part of our Refined Products and Renewables segment. See Note 2 to our consolidated financial statementsincluded in this Annual Report for a further discussion.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. See Note 2 to ourconsolidated financial statements included in this Annual Report for a further discussion.Sale of GrasslandOn November 29, 2016, we sold Grassland. We received proceeds of $22.0 million and recorded a loss on the sale of $2.3 million during the yearended March 31, 2017. See Note 4 to our consolidated financial statements included in this Annual Report for a further discussion5Table of ContentsPrimary Service AreasThe following map shows the primary service areas of our businesses at March 31, 2017:6Table of ContentsOrganizational ChartThe following chart provides a summarized view of our legal entity structure at March 31, 2017: (1)Includes (i) NGL Crude Logistics, LLC, which includes the operations of our Crude Oil Logistics and a portion of our Refined Products and Renewables businesses, (ii) NGLWater Solutions, LLC, which includes the operations of our Water Solutions business, (iii) NGL Liquids, LLC, which includes the operations of our Liquids business, (iv)NGL Propane, LLC, which includes the operations of our Retail Propane business, and (v) TransMontaigne, LLC, which includes the remaining portion of the RefinedProducts and Renewables businesses.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 invested and expect tocontinue to invest within our existing businesses, particularly within our Crude Oil Logistics, Water Solutions, and Refined Products businessesas we grow these 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 cash distribution policy that complements our leverage, acquisition and organic growth strategies. We target leveragelevels that are consistent with those of investment grade companies. Through our disciplined approach to leverage, we expect to maintainsufficient liquidity to manage existing and future capital requirements and to take advantage of market opportunities.Our Competitive StrengthsWe believe that we are well positioned to successfully execute our business strategies and achieve our principal business objectives 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 business unitsare diversified by geography, customer-base and commodity sensitivities which we believe provides us with the ability to maintain cash flowsthroughout typical commodity cycles. For example, 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 business benefits from lower energy prices driving increased customer demand, which can offset the downward pressure on ourCrude Oil Logistics and Water Solutions 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 and contracted pipeline capacity, provide access to a widerange of customers and markets. We use this expansive network of transportation assets to deliver crude oil to the optimal markets.•Our water processing facilities, which are strategically located near areas of high crude oil and natural gas production. Our water processingfacilities are located among the most prolific crude oil and natural gas producing areas in the United States, including the Permian Basin, the DJBasin, the Eagle Ford shale play, the8Table of ContentsBakken shale play, and the Pinedale Anticline. In addition, we believe that the technological capabilities of our Water Solutions business canbe quickly implemented at new facilities and locations.•Our network of natural gas liquids transportation, terminal, and storage assets, which allows 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 proprietaryaccess to refined 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 pipeline injectionstations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. We also lease space and capacity in our owned assets, suchas storage tanks, pipelines, trucks, barges, and railcars, to third parties for a fee. Our operations are centered near areas of high crude oil production, such asthe Bakken shale play in North Dakota, the DJ Basin in Colorado, the Permian Basin in Texas and New Mexico, the Eagle Ford shale play in Texas, theAnadarko Basin, including the STACK, SCOOP, Granite Wash and Mississippi Lime plays in Oklahoma and Texas, and southern Louisiana at the Gulf ofMexico.We own a 550-mile pipeline that transports crude oil from its origin in Colorado to Cushing, Oklahoma (the “Grand Mesa Pipeline”). Grand MesaPipeline commenced operations on November 1, 2016, and the main line portion of this pipe is comprised of a 37.5% undivided interest in a crude oilpipeline jointly owned with Saddlehorn Pipeline Company, LLC (“Saddlehorn”) where we have the right to utilize 150,000 barrels per day of capacity.During the period from November 1, 2016 through March 31, 2017, there were approximately 42,000 barrels per day transported on the Grand Mesa Pipeline.Operating costs are allocated to us based on our proportionate ownership interest and throughput. We also own 970,000 barrels of operational tankage relatedto the Grand Mesa Pipeline.Through our undivided interest in the Grand Mesa Pipeline, we have capacity sufficient to service our customer contracts at the same origin andtermination points with the ability to accept additional volume commitments. We retained ownership of our previously-acquired easements for the potentialfuture development of transportation projects involving petroleum commodities other than crude oil and condensate. With the consent and participation ofSaddlehorn, we and Saddlehorn may consider future opportunities using these easements for projects involving the transportation of crude oil andcondensate.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.9Table of ContentsWe currently transport crude oil using the following assets:•215 owned trucks and 260 owned trailers operating primarily in the Mid-Continent, Permian Basin, Eagle Ford shale play, and Rocky Mountainregions;•400 owned railcars and 397 leased railcars operating primarily in Colorado, New Mexico, North Dakota, Oklahoma, Wyoming, and West Texas;and•10 owned towboats and 20 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 397 leased railcars, 310 are compliantwith these standards (see Part I, Item 1A–“Risk Factors).We contract for truck, rail, and barge transportation services from third parties and ship on 16 common carrier pipelines. We own 29 pipelineinjection stations, the locations of which are summarized below.State Number of Pipeline Injection StationsTexas 14Oklahoma 7New Mexico 5Kansas 2Montana 1Total 29We also have commitments on several interstate pipelines for transportation of crude oil.We own eight storage terminal facilities. The largest of these is a terminal in Cushing, Oklahoma with a storage capacity of 4,600,000 barrels, ofwhich 1,000,000 barrels are owned by Glass Mountain. The combined storage capacity of the other seven terminals is 1,259,400 barrels. In April 2017, arecently constructed Gulf Coast terminal facility became operational with a total storage capacity of 350,000 barrels.We lease 2,165,000 barrels of capacity at two storage terminal facilities. Of this leased storage capacity, 2,000,000 barrels are at Cushing, Oklahoma.Effective April 1, 2017, our leased storage capacity at Cushing, Oklahoma was reduced to 950,000 barrels per our lease agreement.We own a 50% interest in Glass Mountain, which owns a 210-mile crude oil pipeline that originates in western Oklahoma and terminates inCushing, Oklahoma. This pipeline, which became operational in February 2014, has a capacity of 147,000 barrels per day.Customers. Our customers include crude oil refiners, producers, and marketers. During the year ended March 31, 2017, 70% 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,we also 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, someof which are larger and have greater financial resources than we do. The primary factors on which we compete are:•price;•availability of supply;•reliability of service;•logistics capabilities, including the availability of railcars, proprietary terminals, and owned pipelines, barges, railcars, trucks, and towboats;•long-term customer relationships; and•the acquisition of businesses.10Table of ContentsSupply. We obtain crude oil from a large base of suppliers, which consists primarily of crude oil producers. We currently purchase crude oil fromapproximately 250 producers at approximately 3,000 leases.Pricing Policy. Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets such asCushing, Oklahoma. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by 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 Logisticsbusiness benefits when the market is in contango, as increasing prices result in inventory holding gains during the time between when we purchase inventoryand when we sell it. In addition, we are able to better utilize our storage assets when crude oil markets are in contango. When markets are backwardated,falling prices typically have an unfavorable impact on our margins.Billing and Collection Procedures. Our Crude Oil Logistics customers consist primarily of crude oil refiners, producers, and marketers. We typicallyinvoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures onthese customers. We believe the following procedures enhance our collection efforts with these 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 and frac tank washouts. In addition, our Water Solutionssegment sells the recovered hydrocarbons that result from performing these services. Our water processing facilities are strategically located near areas of highcrude oil and natural gas production, including the Permian Basin in Texas and New Mexico, the DJ Basin in Colorado, the Eagle Ford shale play in Texas,the Bakken shale play in North Dakota, and the Pinedale Anticline in Wyoming. During the year ended March 31, 2017, we took delivery of 183.2 millionbarrels of wastewater, an average of 502,000 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 72 water treatment and disposal facilities, including 94 wells. The location of the facilities and the processing capacities atwhich the facilities currently operate and whether the facilities are located on lands we own or lease are summarized below. Processing Capacity (barrels per day)Location Own Lease TotalPinedale Anticline (1) - Wyoming — 62,500 62,500 DJ Basin (2) - Colorado 214,500 72,500 287,000 Permian Basin (3)(4) - Texas and New Mexico 685,000 40,000 725,000 Eagle Ford (3)(5) - Texas 316,000 157,000 473,000 Eaglebine - Texas 20,000 — 20,000 Granite Wash (3) - Texas 52,000 — 52,000 Bakken - North Dakota 30,000 16,000 46,000 Total-All Facilities 1,317,500 348,000 1,665,500 (1)This facility has a disposal capacity of 2,500 barrels per day and a design capacity of 60,000 barrels per day to process water to a recycle standard, which includes a designcapacity of 15,000 barrels per day to process water to a discharge standard.(2)Reflects the total processing capacity of facilities at this location, which includes two facilities that have a combined design capacity of 20,000 barrels per day to process waterto 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.(4)Includes one facility with a processing capacity of 16,000 barrels per day in which we own a 50% interest.(5)Includes one facility with a processing capacity of 28,000 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 facilities in Colorado, Texas and North Dakota dispose of wastewater primarily into deep underground formations via injection wells. One of ourfacilities in Colorado has 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 drillingoperations.Our facility servicing the Pinedale Anticline in Wyoming has the assets and technology needed to treat the water more extensively than a typicaldisposal facility. At this facility, the water is recycled, rather than being disposed of in an injection well. We either process the water to the point where it canbe 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 thestandards for drinking water, and can be returned to the ecosystem (discharge quality water). Recycling offers producers an alternative to the use of freshwater in hydraulic fracturing operations. This minimizes the impact on aquifers, particularly in arid regions of the United States. Since June 2012, we haverecycled approximately 16.5 million barrels (693 million gallons) of recycle quality water, have returned approximately 8.9 million barrels (374 milliongallons) of discharge quality water back to New Fork River, which is a tributary of the Colorado River, and have returned approximately 2.6 million barrels(109 million gallons) of water to the ecosystem through an agricultural irrigation system. We also make discharge quality water available to producers andthe surrounding community for other purposes such as dust control.At our disposal facilities, we use proprietary well maintenance programs to enhance injection rates and extend the service lives of the wells.12Table of ContentsCustomers. 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, 2017, 26%of the water treatment and disposal revenues of our Water Solutions segment were generated from our two largest customers of the segment, and 60% 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 smallerwater transportation companies. We typically invoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establishcredit limits, and follow monitoring procedures on these customers. We believe the following procedures enhance our collection efforts with these 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 believe that the technological capabilities of our Water Solutions businesscan be quickly implemented at new facilities and 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 supplies the majority of the propane for our Retail Propane business as well as other retail propanebusinesses. We also sell butanes and natural gasolines to refiners and producers for use as blending stocks and diluent and assist refineries by managing theirseasonal butane supply needs. During the year ended March 31, 2017, we sold 2.1 billion gallons of natural gas liquids, an average of 5.66 million gallonsper day.Operations. We procure natural gas liquids from refiners, gas processing plants, producers and other resellers for delivery to leased or owned storagespace, common carrier pipelines, railcar terminals, and direct to certain customers. Our customers take delivery by loading natural gas liquids into transportvehicles from common carrier pipeline terminals, private terminals, our terminals, directly from refineries and rail terminals, and by railcar.A portion of our wholesale propane gallons are presold to third-party retailers and wholesalers at a fixed price under back-to-back contracts. Back-to-back contracts, in which we balance our contractual portfolio by buying propane supply when we have a matching purchase commitment from our wholesalecustomers, protect our margins and mitigate commodity price risk. Presales also reduce the impact of warm weather because the customer is required to takedelivery of the propane13Table of Contentsregardless of the weather or any other factors. 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 as well assubleasing railcars to certain customers.We own 21 natural gas liquids terminals and we lease a fleet of approximately 5,000 high-pressure and general purpose railcars. These assets give usthe opportunity to access wholesale markets throughout the United States, and to move product to locations where demand is highest. We utilize theseterminals and railcars primarily in the service of our wholesale, butane and asphalt operations, although we also provide transportation, storage, andthroughput services to other parties to a lesser extent.The location of the facilities and their throughput capacity are summarized below:Facility Throughput Capacity(gallons per day) Terminal InterconnectsArkansas 2,226,800 Connected to Enterprise Texas Eastern Products Pipeline; Rail FacilityMissouri 1,813,000 Connected to Phillips66 Blue Line PipelineMinnesota 1,441,000 Connected to Enterprise Mid-America Pipeline; Rail FacilityIndiana 1,058,000 Connected to Enterprise Texas Eastern Products Pipeline; Rail FacilityIllinois 883,000 Connected to Phillips66 Blue Line PipelineWisconsin 863,000 Rail FacilityWashington 717,000 Rail FacilityLouisiana 600,000 Truck FacilityOklahoma 600,000 Connected to Phillips66 Chisholm Pipeline; Rail FacilityMassachusetts 441,000 Rail FacilityNew Mexico 408,000 Rail FacilityMontana (1) 120,000 Rail FacilityUnited States Total 11,170,800 Ontario, Canada 700,000 Truck FacilityCanada Total 700,000 Total 11,870,800 (1)Currently subleased to a third party through October 2017 with an option to extend or to purchase.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 November 2017 and we are currently innegotiations to renew this agreement. The terminal in St. Catherines, Ontario, Canada is operated by a third party under a year-to-year agreement.We own the land on which 14 of the 21 natural gas liquids terminals are located and we either have easements or lease the land on which theremaining terminals are located. The terminals in East St. Louis, Illinois and Jefferson City, Missouri have perpetual easements, and the terminal in St.Catherines, Ontario, Canada has a long-term lease that expires in 2022.14Table of ContentsWe own an underground storage facility near Delta, Utah. This facility currently has capacity to store approximately 6.0 million barrels of naturalgas liquids. We lease storage to approximately 15 customers, with lease terms ranging from one to three years. The facility is located on property for which wehave a long-term lease.In January 2017, we acquired a natural gas liquids terminal that supports refined products blending in Port Hudson, Louisiana, and a natural gasliquids and condensate facility in Kingfisher, Oklahoma. The Port Hudson Terminal is located near Baton Rouge, Louisiana, and is in proximity to otherrefined products infrastructure along the Colonial Pipeline. This truck unloading and storage facility allows for the aggregation and supply of butane andnaphtha for motor fuel blending and consists of storage tanks with total capacity of 720,000 gallons. The Kingfisher Facility is a natural gas liquids andcondensate facility located in Kingfisher, Oklahoma, which is located in the middle of the STACK shale play. The facility connects to the Chisholm NGLPipeline and the Conway Fractionation complex and consists of 450,000 gallons of storage capacity, a methanol extraction tower and a 5,000-barrel per daycondensate splitter.We own 23 transloading units, which enable customers to transfer product from railcars to trucks. These transloading units can be moved tolocations along a railroad where it is most convenient for customers to transfer their product.We lease natural gas liquids storage space to accommodate the supply requirements and contractual needs of our retail and wholesale customers. Welease storage space for natural gas liquids in various storage hubs in Kansas, Texas, Mississippi, Missouri, Louisiana, Arizona, Indiana, and Canada.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 1,2017 AtMarch 31,2017 Storage InterconnectsKansas 75,390,000 77,490,000 Connected to Enterprise Mid-America, NuStar Pipelines and ONEOK NorthSystem Pipeline; Rail Facility; Truck FacilityTexas 50,400,000 44,940,000 Connected to Phillips66 Blue Line Pipeline and Enterprise Texas EasternProducts Pipeline; Truck FacilityMississippi 7,560,000 9,660,000 Connected to Enterprise Dixie Pipeline; Rail FacilityMissouri 7,560,000 7,560,000 Truck FacilityLouisiana 6,300,000 2,407,000 Connected to Enlink Pipe; Rail FacilityArizona — 1,680,000 Rail FacilityIndiana 210,000 — Connected to Enterprise Texas Eastern Products Pipeline; Rail FacilityUnited States Total 147,420,000 143,737,000 Ontario, Canada 23,179,000 15,800,000 Rail FacilityAlberta, Canada 5,162,000 4,370,000 Connected to Cochin Pipeline; Rail FacilityCanada Total 28,341,000 20,170,000 Total 175,761,000 163,907,000 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, 2017, 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).15Table of ContentsSeasonality. Our wholesale Liquids 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 of the product regardless of the weather.Competition. Our Liquids business faces significant competition, as many entities, including other natural gas liquids wholesalers and companiesinvolved in the natural gas liquids midstream industry (such as terminal and refinery operations), are engaged in the liquids business, some of which havegreater financial resources than we do. The primary factors on which we compete are:•price;•availability of supply;•reliability of service;•available space on common carrier pipelines;•storage availability;•logistics capabilities, including the availability of railcars, and proprietary terminals;•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 are notbe matched with a purchase commitment.We generally require deposits from our customers for fixed priced future delivery of propane if the delivery date is more than 30 days after the 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 these customers. We believe the following procedures enhance our collection efforts with these customers:•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 analysis 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.16Table of ContentsTrade 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 leaseof propane tanks, equipment and supplies, to more than 350,000 residential, agricultural, commercial and industrial customers. We also sell propane tocertain resellers. We purchase the majority of the propane sold in our Retail Propane business from our Liquids business, which provides our Retail Propanebusiness with a stable and secure supply of propane. During the year ended March 31, 2017, we sold 207.6 million gallons of propane and distillates, anaverage of 569,000 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 128customer service locations and 119 satellite distribution locations, with aggregate propane storage capacity of 17.5 million gallons and aggregate distillatestorage capacity of 5.6 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.Our customer service locations in Illinois and Indiana also rent over 16,500 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 andwater conditioning have significant overlap, providing the opportunity to cross-sell both products between those customer bases.17Table of ContentsThe following table summarizes the number of our customer service locations and satellite distribution locations by state:State Number of CustomerService Locations Number of SatelliteDistribution LocationsGeorgia 23 10Illinois 22 20North Carolina 14 1Maine 12 25Massachusetts 12 8Pennsylvania 9 4Kansas 8 26Connecticut 4 2Indiana 4 5New Hampshire 3 3Oregon 2 1South Carolina 2 2Tennessee 2 1Washington 2 —Alabama 1 —Colorado 1 1Florida 1 —Maryland 1 1Mississippi 1 3Rhode Island 1 1Utah 1 1Vermont 1 2Wyoming 1 1New Jersey — 1Total 128 119 We own 84 of our 128 customer service locations and 75 of our 119 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, 2017, we owned thefollowing propane storage tanks:•over 500 bulk storage tanks with capacities ranging from 2,000 to 90,000 gallons; and•over 400,000 stationary customer storage tanks with capacities ranging from 7 to 30,000 gallons.We also lease an additional 20 bulk storage tanks ranging from 5,000 to 61,500 gallons.At March 31, 2017, we owned a fleet of 590 bulk delivery trucks, 40 semi-tractors, 40 propane transport trailers and 630 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 2,200 to 5,000 gallons, into a storage tank at the customer’s premises. The capacity of these storage tanks ranges from 50 to 30,000gallons. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 25 gallons. These cylinders are eitherpicked up on a delivery route, refilled at our customer service locations, and then returned to the retail customer, or refilled at the customer’s location.Customers can also bring the cylinders to our customer service centers to be refilled.Approximately 71% 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 system18Table of Contentsutilizes a customer’s historical consumption patterns combined with current weather conditions to more accurately predict the optimal time to refill thecustomer’s tank. The delivery information is then uploaded to routing software to calculate the most cost effective delivery route. Our automatic deliveryprogram promotes customer retention by providing an uninterrupted supply of propane and enables us to efficiently conduct route deliveries on a regularbasis. Some of our purchase plans, such as level payment billing, fixed price, and price cap programs, further promote our automatic delivery program.Customers. Our retail propane and distillate customers fall into three broad categories: residential, commercial and industrial, and agricultural. AtMarch 31, 2017, our retail propane and distillate customers were comprised of:•72% residential customers;•27% 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, 2017.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.Pricing Policy. Our pricing policy is an essential element in the successful marketing of retail propane and distillates. We protect our margin byadjusting our retail propane pricing based on, among other things, prevailing supply costs, local market conditions, and input from management at ourcustomer service locations. We rely on our regional management to set prices based on these factors. Our regional managers are advised regularly of anychanges in the delivered cost of propane and distillates, potential supply disruptions, changes in industry inventory levels, and possible trends in the futurecost of propane19Table of Contentsand distillates. We believe the market intelligence provided by our Liquids business, combined with our propane and distillate pricing methods allows us torespond 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 Anthem Propane Exchange, Brantley Gas, Coastal Energy,Downeast Energy, Eastern Propane, Gas Inc., Hicksgas, Lumber River Propane, Osterman Propane, Pacer Propane, Proflame, Propane Central, StallingsPropane, Stokes & Congleton Carolina Energies, Triad Propane, Woodstock Gas, and Yadkin Propane among others. We typically retain and continue to usethe names of the companies that we acquire and believe that this helps maintain the local identification of these companies and contributes to their continuedsuccess. We regard our trademarks, trade names, and other proprietary rights as valuable assets and believe that they have significant value in the marketingof 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, 2017, we sold 91.0 million barrels of gasoline, 49.8 million barrels of diesel, 4.6 million barrels of ethanol and 2.4 million barrels ofbiodiesel.Operations. The refined products we handle include gasoline, diesel, 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 at various locations throughout the country.On certain interstate refined products pipelines, shipment demand exceeds available capacity, and capacity is allocated to shippers based on their historicalshipment 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 terminals owned by third parties. As discussed above, on February 1, 2016, we sold our general partner interest in TLP. As a result, onFebruary 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. As part ofthis transaction, we entered into lease agreements whereby we will remain the long-term exclusive tenant in the TLP Southeast terminal system. In addition,we retained TransMontaigne Product Services, LLC, including its marketing business, customer contracts and its line space on the Colonial and Plantationpipelines, which is a significant part of our Refined Products and Renewables segment.20Table of ContentsThe following table summarizes our leased storage space at refined products storage facilities:Locations Active Storage Capacity(shell barrels)Southeast Facilities Virginia 2,791,000Georgia 2,553,000Mississippi 1,588,516North Carolina 775,000New Jersey 468,850Alabama 178,000South Carolina 166,000Florida 62,000New York 40,800Total Southeast Facilities Storage Capacity 8,623,166 Mid-Continent Facilities Magellan North system 329,000NuStar East Products system 240,000Explorer Pipeline 50,000Total Mid-Continent Facilities Storage Capacity 619,000 West Facilities Kinder Morgan (Phoenix, Arizona) 50,000 Total Facilities Storage Capacity 9,292,166We 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 third party terminals. We market and handle logistics for third-party ethanol manufacturers for aservice fee. We primarily purchase biodiesel from production facilities in the Midwest and in Houston, Texas, and transport the biodiesel via railcar to sell tocustomers. We lease a total of 127,080 barrels of biodiesel storage in Deer Park, Texas and Brownsville, Texas and have a biodiesel terminaling agreement ata fuel terminal in Phoenix, Arizona with a minimum monthly throughput requirement. We lease 47 railcars for the transportation of renewables.Customers. Our Refined Products and Renewables segment serves customers in 40 states. During the year ended March 31, 2017, 35% of therevenues of our Refined Products and Renewables segment were generated from our ten largest customers of the segment. We sell to customers via rack spotsales, 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 third party truck racks. The pricing ofthe product delivered under a majority of our contract sales is based on published index prices, and varies based on changes in the applicable indices. Inaddition, at the customer’s option, the contract price may be fixed at a stipulated price per gallon.Rack spot sales are sales that do not involve continuing contractual obligations to purchase or deliver product. Rack spot sales are priced anddelivered on a daily basis through truck loading racks. At the end of each day for each of the terminals that we market from, we establish the next day sellingprice for each product for each of our delivery locations. We announce or “post” to customers via website, e-mail, and telephone communications the rackspot sale price of various products for the following morning. Typical rack spot sale purchasers include commercial and industrial end users, independentretailers and small, independent marketers who resell product to retail gasoline stations or other end users. Our selling price of a particular product on aparticular day is a function of our supply at that delivery location or terminal, our estimate of the costs to replenish the product at that delivery location, andour desire to reduce inventory levels at that particular location that day.21Table of ContentsBulk 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 minimum commodity price exposure through a combination of purchase contracts, sales contractsand financial derivatives. A significant percentage of our business is priced on a back-to-back basis which minimizes our commodity price exposure. Fordiscretionary inventory, and for those instances where physical transactions cannot be appropriately matched, we utilize financial derivatives to mitigatecommodity 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 future mandates and incentives, or decisions by thefederal government related to future reinstatement of the biodiesel tax credit, could result in changes in demand for ethanol and biodiesel.Billing and Collection Procedures. Our Refined Products and Renewables customers consist primarily of commercial and industrial end users,independent retailers, distributors, marketers, government entities, and other wholesalers of refined petroleum products. We perform credit analysis, requirecredit approvals, establish credit limits, and follow monitoring procedures on our Refined Products and Renewables customers. We believe the followingprocedures 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;22Table of Contents•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, 2017, we had 2,700 full-time employees. Eleven 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 Federal Energy Regulatory Commission (“FERC”), which has authority under the Natural GasAct to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for allnatural gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or the FERC (with respect tothe resale of natural gas in interstate commerce), however, could re-impose price controls in the future.Exploration and production operations are subject to various types of federal, state and local regulation, including, but not limited to, permitting,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. The Grand Mesa Pipeline became operational on November 1, 2016 and has several points of origin in Colorado, runs fromthose origin points through Kansas and terminates in Cushing, Oklahoma. The transportation services on the Grand Mesa Pipeline are subject to FERCregulation. Additionally, contracts we enter into for the interstate transportation or storage of crude oil or natural gas may be subject to FERC regulationincluding reporting or other requirements. In addition, the intrastate transportation and storage of crude oil and natural gas is subject to regulation by thestate in which such facilities are located, and such regulation can affect the availability and price of our supply, and have both a direct and indirect effect onour business.Anti-Market Manipulation. We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, which authorizes theFERC to impose fines of up to $1 million per day per violation of the Natural Gas Act, the NGPA, or their implementing regulations. In addition, the FederalTrade Commission (“FTC”) holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market manipulation in petroleummarkets, including the authority to request that a court impose fines of up to $1 million per violation. These agencies have promulgated broad rules andregulations prohibiting fraud and manipulation in oil and gas markets. The Commodity Futures Trading Commission (“CFTC”) is directed under theCommodity Exchange Act to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutoryauthority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. TheCFTC also has statutory authority to seek civil penalties of up to the greater of $1 million per day per violation or triple the monetary gain to the violator forviolations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reporting requirements that are designedto 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 we23Table of Contentsengage in maritime transportation through our barge fleet between locations in the United States, we are subject to the provisions of the law. As a result, weare responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to ensurethat no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all United States-flagged vessels be manned by United Statescitizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirementsignificantly increases operating costs of United States-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governmentssubsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by United States-flagged vesselowners. The United States Coast Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tendsto result in higher regulatory compliance costs for United States-flagged operators than for owners of vessels registered under foreign flags of convenience.Environmental 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 pollution resulting from our operations; (v) require remedialmeasures to mitigate pollution from former or ongoing operations; and (vi) may result in the assessment of administrative, civil and criminal penalties forfailure to comply with such laws. These laws include, among others, the Resource Conservation and Recovery Act (“RCRA”), the ComprehensiveEnvironmental Response, Compensation and Liability Act (“CERCLA”), the federal Clean Air Act, the Homeland Security Act of 2002, the EmergencyPlanning and Community Right to Know Act, the Clean Water Act, the Safe Drinking Water Act, and comparable state statutes. For example, as a flammablesubstance, propane is subject to risk management plan requirements under section 112(r) of the federal Clean Air Act.CERCLA, also known as the “Superfund” law, and similar state laws impose liability, without regard to fault or the legality of the original conduct,on certain classes of potentially responsible persons that are considered to have contributed to the release of a “hazardous substance” into the environment.These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of ahazardous substance released at24Table of Contentsthe site. While natural gas liquids are not a hazardous substance within the meaning of CERCLA, other chemicals used in or generated by our operations maybe classified as hazardous. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict and joint andseveral liability for the costs of investigating and cleaning up the hazardous substances that have been released into the environment, for damages to naturalresources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personalinjury and property damage allegedly caused by the hazardous substances released into the environment.RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal andcleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes inconjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penaltiesfor alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of oil and natural gas, as well ascertain types of petroleum-contaminated media and debris, are excluded from regulation as hazardous waste under Subtitle C of RCRA. These wastes, instead,are regulated under RCRA’s less stringent solid waste provisions, state laws or other federal laws. It is possible, however, that certain wastes now classified asnon-hazardous could be classified as hazardous wastes in the future and therefore be subject to more rigorous and costly disposal requirements. Indeed,legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas wastes as “hazardous wastes.” Any such change couldresult in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our 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.Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws andregulations regulate emissions of air pollutants from various industrial sources, and also impose various monitoring and reporting requirements. Such lawsand regulations may require that we obtain permits prior to the construction or modification of certain projects or facilities expected to produce orsignificantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specificemission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions,conditions or restrictions on operations and, potentially, criminal enforcement actions. Furthermore, we may be required to incur certain capital expendituresin the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We areaware of planned EPA rulemakings concerning air emissions from the oil and gas industry, but the EPA’s schedule for proposing and finalizing theseupcoming rulemakings is not presently known.25Table of ContentsWater 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. SPCC requirements of federal laws require appropriate containment berms and similar structures to help prevent the contaminationof regulated waters in the event of a hydrocarbon or other constituent tank spill, rupture or leak. In addition, the Clean Water Act and analogous state lawsrequire individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. We have discharge permits inplace for a number of our facilities. These permits may require us to monitor and sample the storm water runoff from such facilities. Some states also maintaingroundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatoryagencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act andanalogous 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 Congress. Congress will likelycontinue to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act’s UndergroundInjection Control Program and/or to require disclosure of chemicals used in the hydraulic fracturing process. Federal agencies, including the EPA and theUnited States Department of the Interior, have asserted their regulatory authority to, for example, study the potential impacts of hydraulic fracturing on theenvironment, and initiate rulemakings to compel disclosure of the chemicals used in hydraulic fracturing operations, and establish pretreatment standards forwastewater from hydraulic fracturing operations. In addition, some states have also proposed or adopted legislative or regulatory restrictions on hydraulicfracturing, which include additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and/or temporary orpermanent 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. A steady stream of legislation regarding climate change is regularly introduced into Congress, but none of theproposed bills have received bipartisan support. For example, Sen. Richard Durbin (D-IL) introduced the Climate Change Adapt America Fund Act of 2017 inthe Senate on April 24, 2017 as S. 922, and Rep. Theodore Deutch (D-FL) introduced same bill in the House of Representatives on April 25, 2017 as H.R.2129. The bills seek to establish the Climate Change Advisory Commission to develop recommendations, frameworks and guidelines for projects to respondto the impacts of climate change and to issue federal obligations, the proceeds of which would be used to fund projects that aid in adaptation to climatechange, among other things. Neither bill has advanced out of committee. The ultimate outcome of any possible future federal legislative initiatives isuncertain. In addition, several states have already adopted some legal measures to reduce emissions of greenhouse gases, primarily through the planneddevelopment of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs.On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present anendangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’satmosphere and other climatic changes. These findings allowed26Table of Contentsthe EPA to adopt and implement regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. On May 12,2016, the EPA finalized three rules that regulate greenhouse gas emissions from certain sources in the oil and natural gas industry, which became effective onAugust 2, 2016. On April 18, 2017, the EPA announced its intention to reconsider certain aspects of these rules in response to several administrativereconsideration opinions and stayed the compliance deadline for certain fugitive emissions monitoring requirements by 90 days to June 3, 2017. Theschedule for when these regulations will be reconsidered, and if appropriate, amended or withdrawn is not presently known. The EPA’s greenhouse gasregulations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations and also could adversely affect demand forthe products that we transport, store, process, or otherwise handle in connection with our services.Some scientists have suggested climate change from greenhouse gases could increase the severity of extreme weather, such as increased hurricanesand floods, which could damage our facilities. Another possible consequence of climate change is increased volatility in seasonal temperatures. The marketfor our natural gas liquids is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate couldaffect the market for our products and services. If there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on ourbusiness.Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, new climate change regulations mayprovide us with a competitive advantage over other sources of energy, such as fuel oil and coal.The trend of more expansive and stringent environmental legislation and regulations, including greenhouse gas regulation, could continue,resulting in increased costs of 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.With respect to the transportation of propane, distillates, crude oil, and water, we are subject to regulations promulgated under federal legislation,including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security andtransportation of hazardous materials and are administered by the United States Department of Transportation (“DOT”). Specifically, crude oil pipelines aresubject to regulation by the DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Hazardous Liquid PipelineSafety Act of 1979 (“HLPSA”), which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the storage and transportationof hazardous liquids by and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management ofpipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with suchregulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary ofTransportation. These regulations include potential fines and penalties for violations.The Pipeline Safety Act of 1992 added the environment to the list of statutory factors that must be considered in establishing safety standards forhazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteriafor operators to use in identifying and inspecting pipelines located in high consequence areas (“HCAs”), defined as those areas that are unusually sensitive toenvironmental damage, that cross a navigable waterway, or that have a high population density. In the Pipeline Inspection, Protection, Enforcement, andSafety Act of 2006, Congress required mandatory inspections for certain United States crude oil and natural gas transmission pipelines in HCAs andmandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management. In January 2012, the federalgovernment passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”). This act provides for additionalregulatory oversight of the nation’s pipelines,27Table of Contentsincreases the penalties for violations of pipeline safety rules, and complements the DOT’s other initiatives. The 2011 Pipeline Safety Act increases themaximum fine for the most serious pipeline safety violations involving deaths, injuries or major environmental harm from $1 million to $2 million. Inaddition, this law established additional safety requirements for newly constructed pipelines. The law also provides for (i) additional pipeline damageprevention measures; (ii) allowing the Secretary of Transportation to require automatic and remote-controlled shut-off valves on new pipelines; (iii) requiringthe Secretary of Transportation to evaluate the effectiveness of expanding pipeline integrity management and leak detection requirements; (iv) improving theway the DOT and pipeline operators provide information to the public and emergency responders; and (v) reforming the process by which pipeline operatorsnotify federal, state and local officials of pipeline accidents. On June 22, 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of2016 was enacted, further strengthening PHMSA’s safety authority.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.Item 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 to enable us to pay the minimum quarterly distribution. These distributions may only be made from cash availablefor distribution after the preferred quarterly distribution to which our preferred units are entitled. The amount of cash we can distribute on our unitsprincipally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:•weather conditions in our operating areas;•the cost of crude oil, natural gas liquids, gasoline, diesel, ethanol, and biodiesel that we buy for resale and whether we are able to pass along costincreases to our customers;•the volume of wastewater delivered to our processing facilities;28Table of Contents•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 “Senior Secured Notes Purchase Agreement”), the indentures governing our outstanding 5.125% senior notes due2019, 6.875% senior notes due 2021, 7.50% senior notes due 2023, and 6.125% senior notes due 2025 (collectively, the “Indentures”) andother debt service requirements;•fluctuations in working capital needs;•our ability to borrow funds and access capital markets;•the amount, if any, of cash reserves established by our general partner; and•other business risks discussed in this Annual Report that may affect our cash levels.The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow rather than on our profitability, which mayprevent us from making distributions, even during periods in which we realize net income.The amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which will be affected bynon-cash items. As a result, we might make cash distributions during periods when we record net losses for financial accounting purposes and we might notmake cash distributions during periods when we record net income for financial accounting purposes.Our future financial performance and growth may be limited by our ability to successfully grow organically and complete accretive acquisitions oneconomically acceptable terms.Our ability to complete accretive 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, Senior Secured Notes Purchase Agreement and Indentures that limit the amount and types of indebtednessthat we may incur to finance acquisitions and which may adversely affect our ability to make distributions to our unitholders;•lack of available cash or external capital or limitations on our ability to issue equity to pay for acquisitions; and•possible unwillingness of prospective sellers to accept our common units as consideration and the potential dilutive effect to our existingunitholders caused by an issuance of common units in an acquisition.There can be no assurance that we will identify attractive acquisition candidates in the future, that we will be able to acquire such businesses oneconomically acceptable terms, that any acquisitions will not be dilutive to earnings and distributions or that any additional debt that we incur to finance anacquisition will not adversely affect our ability to make distributions to unitholders. Furthermore, if we consummate any future acquisitions, ourcapitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and otherrelevant information that we will consider in determining the application of these funds and other resources.29Table of ContentsWe 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, debt or synergies;•mistaken assumptions about sales volume, margin or operational expenses;•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 associatedwith a particular acquisition. Even when an issue or risk is identified, we may be unable to obtain adequate contractual protection from the seller. Therealization of any of these risks could have a material adverse effect on the success of a particular acquisition or our consolidated financial position, results ofoperations or 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 make such acquisitions or aninability to successfully integrate those operations into our overall business operations. The realization of any of these risks could have a material adverseeffect 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, 2017, the face amount of our long-term debt was $3.0 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.30Table of ContentsRestrictions in our Credit Agreement, Senior Secured Notes Purchase Agreement and Indentures could adversely affect our business, financial position,results of operations, ability to make distributions to unitholders and the value of our common units.Our Credit Agreement, Senior Secured Notes 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, Senior Secured Notes Purchase Agreement and Indentures aslong as no default or event of default exists both immediately before and after giving effect to the declaration and payment of the distribution and thedistribution does not exceed available cash for the applicable quarterly period. Our Credit Agreement, Senior Secured Notes Purchase Agreement andIndentures also contain covenants requiring us to maintain certain financial ratios. See Note 8 to our consolidated financial statements included in thisAnnual Report for a further discussion.The provisions of our Credit Agreement, Senior Secured Notes Purchase Agreement and Indentures may affect our ability to obtain future financingand pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure tocomply with the provisions of our Credit Agreement could result in a covenant violation, default or an event of default that could enable our lenders, subjectto the terms and conditions of our Credit Agreement, to declare the outstanding principal of that debt, together with accrued and unpaid interest, to beimmediately due and payable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral we granted them to secureour debts. If the payment of our debt is accelerated, defaults under our other debt instruments, if any then exist, may be triggered, and our assets may beinsufficient 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 common unit price, our ability to issue equity or incur debt for acquisitions or other purposes, andour ability to make cash distributions at our intended levels.Interest rates may increase in the future. As a result, interest rates on our existing and future credit facilities and debt offerings could be higher thancurrent levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our common unit price will be impacted by ourlevel of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities forinvestment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors whoinvest in our common units, and a rising interest rate environment could have an adverse impact on our common unit price and our ability to issue equity orincur debt for acquisitions or other purposes and to make payments on our debt obligations and cash distributions at our intended levels.31Table of ContentsOur business depends on the availability of crude oil, natural gas liquids, and refined products in the United States and Canada, which is dependent on theability and willingness of other parties to explore for and produce crude oil and natural gas. Spending on crude oil and natural gas exploration andproduction may be adversely affected by industry and financial market conditions that are beyond our control.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.Declining 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. While crude oil prices have reboundedfrom the lows experienced during the first three months of calendar year 2016, they are still well below the prices from the first half of calendar year 2014.This has had an unfavorable impact on the revenues of our Water Solutions business. The volume of water we process is driven in part by the level of crudeoil production, and the lower crude oil prices have given producers less incentive to expand production. In addition, a portion of the revenues in our WaterSolutions business is generated from the sale of hydrocarbons that we recover when processing wastewater, and lower crude oil prices have an adverse impacton these revenues. A further decline in crude oil prices or a prolonged period of low crude oil prices could have an adverse effect on our Water Solutionsbusiness.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, and Refined Products and Renewables businesses are “margin-based” businesses in which ourrealized margins depend on the differential of sales prices over our total supply costs. Our32Table of Contentsprofitability is therefore sensitive to changes in product prices caused by changes in supply, pipeline transportation and storage capacity or other marketconditions.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 resources than we do.We experience competition in all of our segments. In our Liquids segment, we compete for natural gas liquids 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 alsoface competition from trucking companies for incremental and marginal volumes in the areas we serve. Further, our crude oil terminals compete withterminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies withmarketing and trading operations.Our Water Solutions segment is in direct and indirect competition with other businesses, including disposal and other wastewater treatmentbusinesses.We face strong competition in the market for the sale of retail propane and distillates. Our competitors vary from retail propane companies who arelarger and have greater financial resources than we do to small independent retail propane distributors, agricultural cooperatives and fuel oil distributors whohave entered the market due to a low barrier to entry. The actions of our retail propane and distillate competitors and the impact of imports/exports, couldlead to lower 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 forcustomers for our services.We can make no assurance that we will compete successfully in each of our lines of business. If a competitor attempts to increase market share byreducing 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 or railroads 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. We transport crude oil,natural gas liquids, ethanol, and biodiesel by railcar. We do not own33Table of Contentsor operate the railroads on which these railcars are transported. Any disruptions in the operations of these railroads could adversely impact our ability todeliver product to our customers.The fees charged to customers under our agreements with them for the transportation and marketing of crude oil, condensate, natural gas liquids,gasoline, diesel, ethanol, and biodiesel may not escalate sufficiently to cover increases in costs and the agreements may be suspended in somecircumstances, which would affect our profitability.Our costs may increase more rapidly than the fees that we charge to customers 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 ourcontrol, including force majeure events wherein the supply of crude oil, condensate, and/or natural gas liquids are curtailed or cut off. Force majeure eventsinclude (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God,explosions, mechanical or physical failures of our equipment or facilities of our customers. If the escalation of fees is insufficient to cover increased costs, orif any customer suspends or terminates its contracts with us, our profitability could be materially and adversely affected.Our sales of crude oil, condensate, natural gas liquids, gasoline, diesel, 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.With regard to our physical sales of energy commodities, and any related transportation and/or hedging activities that we undertake, we are required toobserve the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certainreporting and other requirements. Additionally, some of our operations are currently subject to the FERC regulations obligating us to comply with theFERC’s regulations and policies applicable to those assets and operations. Other of our operations may become subject to the FERC’s jurisdiction in thefuture (see “–Some of our operations are subject to the jurisdiction of the FERC and other operations may become subject in the future,” below). Any failureon our part to comply with the FERC’s regulations and policies at that time could result in the imposition of civil and criminal penalties. Failure to complywith such regulations, as interpreted and enforced, could have a material and adverse effect on our business, consolidated results of operations and financialposition.The intrastate transportation or storage of crude oil and refined products is subject to regulation by the state in which the facilities are located andtransactions occur. Compliance with these state regulations could have a material and adverse effect on that portion of our business, consolidated results ofoperations 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, refined and renewable products, and natural gas hedging transactions. Certain transactions will be required to becleared on exchanges and cash collateral will have to be posted. The Dodd-Frank Act provides for a potential exemption from these clearing and cashcollateral requirements for commercial end users and it includes a number of defined terms that will be used in determining how this exemption applies toparticular derivative transactions and the parties to those transactions. Since the Dodd-Frank Act mandates the CFTC to promulgate rules to define theseterms, the full impact of the Dodd-Frank Act on our hedging activities is uncertain at this time. However, new legislation and any new regulations couldsignificantly increase the cost of derivative contracts (including through requirements to post collateral which could adversely affect our available liquidity),materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks that we encounter, reduce our ability tomonetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. The Dodd-Frank Act may alsomaterially affect our customers and materially and adversely 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 a34Table of Contentsmaterial adverse effect on our business, consolidated results of operations and financial 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 due to handling of wastewater and hydrocarbons, such as crude oil, condensate, natural gas liquids, gasoline,diesel, ethanol, and biodiesel. For instance, our Water Solutions business carries with it environmental risks, including leakage from the treatment plants tosurface or subsurface soils, surface water or groundwater, or accidental spills. Our Crude Oil Logistics, Liquids, and Refined Products and Renewablesbusinesses carry similar risks of leakage and sudden or accidental spills of crude oil, natural gas liquids, and hydrocarbons. Liability under, or violation of,environmental laws and regulations could result in, among other things, the impairment or cancellation of operations, injunctions, fines and penalties,reputational damage, expenditures for remediation and liability for natural resource damages, property damage and personal injuries.We use various modes of transportation to carry propane, distillates, crude oil, refined and renewable products and water, including trucks, railcars,barges, and pipelines, each of which is subject to regulation. With respect to transportation by truck, we are subject to regulations promulgated under federallegislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002, which cover the security and transportation of hazardousmaterials and are administered by the DOT. We also own and lease a fleet of railcars, the operation of which is subject to the regulatory jurisdiction of theFederal Railroad Administration of the DOT, as well as other federal and state regulatory agencies. Railcar accidents within the industry involving trainscarrying crude oil from the Bakken region (none of which directly involved any of our business operations), have led to increased legislative and regulatoryscrutiny over the safety of transporting crude oil by railcar. The introduction of regulations that result in new requirements addressing the type, design,specifications or construction of railcars used to transport crude oil could result in severe transportation capacity constraints during the period in whichnew railcars are retrofitted or constructed to meet new specifications. Our barge transportation operations are subject to the Jones Act, a federal law generallyrestricting marine transportation in the United States to vessels built and registered in the United States, and manned/owned by United States citizens, as wellas setting forth the rules and regulations of the United States Coast Guard. Non-compliance with any of these regulations could result in increased costsrelated to the transportation of our products and could have an adverse effect on our business.In addition, under certain environmental laws, we could be subject to strict and/or joint and several liability for the investigation, removal orremediation of previously released materials. As a result, these laws could cause us to become liable for the conduct of others, such as prior owners oroperators of our facilities, or for consequences of our or our predecessor’s actions, regardless of whether we were responsible for the release or if such actionswere in compliance with all applicable laws at the time of those actions. Also, upon closure of certain facilities, such as at the end of their useful life, we havebeen and may be required to undertake environmental evaluations or cleanups.Additionally, in order to conduct our operations, we must obtain and maintain numerous permits, approvals and other authorizations from variousfederal, state, provincial and local governmental authorities relating to wastewater handling, discharge and disposal, air emissions, transportation and otherenvironmental matters. These authorizations subject us to terms and conditions which may be onerous or costly to comply with, and that may require costlyoperational modifications to attain and maintain compliance. The renewal, amendment or modification of these permits, approvals and other authorizationsmay involve the imposition of even more stringent and burdensome terms and conditions with attendant higher costs and more significant effects upon ouroperations.Changes in environmental laws and regulations occur frequently. New laws or regulations, changes to existing laws or regulations, such as morestringent pollution control requirements or additional safety requirements, or more stringent interpretation or enforcement of existing laws and regulations,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.35Table of ContentsFurthermore, 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. Any significant increased costs or restrictions placed on our customers to comply with environmental laws andregulations could affect their production output significantly. Such an effect on our customers could materially and adversely affect our utilization andprofitability by reducing demand for our midstream services. The adoption or implementation of any new regulations imposing additional reportingobligations on greenhouse gas emissions, or limiting greenhouse gas emissions from our equipment and operations, could require us to incur significantcosts.State legislation and regulatory initiatives relating to our hydraulic fracturing customers could result 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. Any current or proposed restrictions on hydraulic fracturing could lead to operational delays or increasedoperating costs and regulatory burdens that could make it more difficult or costly to perform hydraulic fracturing which would negatively impact ourcustomer 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 scrutiny from sectionsof the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increased seismic activity. Newlaws or regulations, or changes to existing laws or regulations, in response to this perceived threat may adversely impact the water disposal industry.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 a36Table of Contentsposition that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on the other hand. These policies andpractices cannot, however, eliminate all risks. For example, any event that disrupts our anticipated physical supply of commodities could expose us to risk ofloss resulting from the need to cover obligations required under contracts for forward sale. Additionally, we can provide no assurance that our processes andprocedures will detect and/or prevent all violations of our risk management policies and procedures, particularly if deception or other intentional misconductis 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 the price of such physical inventory declines over time. Basis risk cannot be entirely eliminated, andbasis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our consolidated financial position and results ofoperations.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 are subject to the jurisdiction of the FERC and other operations may become subject in the future.The FERC regulates the transportation of crude oil and refined products on interstate pipelines, among other things. Intrastate transportation andgathering pipelines that do not provide interstate services are not subject to regulation by the FERC. The distinction between the FERC-regulated interstatepipeline transportation on the one hand and intrastate pipeline transportation on the other hand, is a fact-based determination. The Grand Mesa Pipelinebecame operational on November 1, 2016 and has several points of origin in Colorado, runs from those origin points through Kansas and terminates inCushing, Oklahoma. The transportation services on the Grand Mesa Pipeline are subject to FERC regulation. Other of our transportation services could in thefuture become subject to the jurisdiction of the FERC, which could adversely affect the terms of service, rates and revenues of such services.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.37Table of ContentsVolumes of hydrocarbons recovered during the wastewater treatment process can vary. Any significant reduction in residual crude oil content inwastewater we treat will affect our recovery of hydrocarbons and, therefore, our profitability.A portion of the revenues in our Water Solutions business is generated from the sale of hydrocarbons that we recover when processing wastewater.Our ability 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, natural gas and renewables, has increasedas a result of reduced regulation of many utilities. Electricity is a major competitor of propane, but propane in some regions has historically had a competitiveprice advantage over electricity. Except for some industrial and commercial applications, propane is generally not competitive with natural gas in areaswhere natural gas pipelines already exist because such pipelines generally make it possible for the delivered cost of natural gas to be less expensive than thebulk delivery of propane. The expansion of natural gas into traditional propane markets has historically been inhibited by the capital cost required to expanddistribution and pipeline systems; however, the gradual expansion of the nation’s natural gas distribution systems has resulted in natural gas being availablein areas that previously depended on propane, which could cause us to lose customers, thereby reducing our revenues. Although propane is similar to fuel oilin some applications and market demand, propane and fuel oil compete to a lesser extent primarily because of the cost of converting from one to the other.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 appliances, has adversely affected the demand for propane and distillates by retail customers. Future conservation measuresor technological 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 geographically concentrated and localized warmer weather and/or economic downturns may adverselyaffect demand for propane, 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.38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, if certain conditions are met. Opponents of the RFS have sought, and maycontinue to seek, to force the EPA to reduce or eliminate the RFS. Further, legislation has been introduced with the goal of significantly reducing oreliminating the RFS. While the outcome of these legislative efforts is uncertain, it is possible that the EPA could adjust the RFS requirements in the future. Ifthe EPA were to adjust the RFS requirements in any material way, it could negatively impact demand for the renewable fuel products we market, which couldadversely 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.We expect to continue to depend on key customers to support our revenues for the foreseeable future. The loss of key customers, failure to renewcontracts upon expiration, or a sustained decrease in demand by key customers could result in a substantial loss of revenues and could have a material andadverse effect on our consolidated results of operations. During the year ended March 31, 2017, a significant portion of our revenues was dependent on keycustomers as summarized below:•70% of the revenues of our Crude Oil Logistics segment were generated from our ten largest customers of the segment;•26% of the water treatment and disposal revenues of our Water Solutions segment were generated from our two largest customers of the segment;•34% of the revenues of our Liquids segment were generated from our ten largest customers of the segment (exclusive of sales to our RetailPropane segment); and39Table of Contents•35% of the revenues of our Refined Products and Renewables segment were generated from our ten largest customers of the segment.Certain of our operations are conducted through joint ventures which have unique risks.Certain of our operations are conducted through joint ventures. With respect to our joint ventures, we share ownership and managementresponsibilities with partners that may not share our goals and objectives. Differences in views among the partners may result in delayed decisions or failuresto agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, amongothers. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the jointventure. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our businessand operations. From time to time, our joint ventures may be involved in disputes or legal proceedings which may negatively affect our investments.Accordingly, any such occurrences could adversely affect our 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. These expansion projects require the expenditure of significant amounts of capital, which may exceed ourresources, and involve numerous regulatory, environmental, political and legal uncertainties, including political opposition by landowners, environmentalactivists and other. There can be no assurance that we will complete these projects on schedule or at all or at the budgeted cost. Our revenues may notincrease upon the expenditure of funds on a particular project. Moreover, we may undertake expansion projects to capture anticipated future growth inproduction in a region in which anticipated production growth does not materialize or for which we are unable to acquire new customers. We may also relyon estimates of proved, probable or possible reserves in our decision to undertake expansion projects, which may prove to be inaccurate. As a result, our newfacilities and infrastructure may not be able to attract enough product to achieve our expected investment return, which could materially and adversely affectour consolidated results of operations and financial position.We may face opposition to the operation of our pipelines and facilities from various groups.We may face opposition to the operation of our pipelines and facilities from environmental groups, landowners, tribal groups, local groups and otheradvocates. Such opposition could take many forms, including organized protests, attempts to block or sabotage our operations, intervention in regulatory oradministrative proceedings involving our assets, or lawsuits or other actions designed to prevent, disrupt or delay the operation of our assets and business.For example, repairing our pipelines often involves securing consent from individual landowners to access their property; one or more landowners may resistour efforts to make needed repairs, which could lead to an interruption in the operation of the affected pipeline or facility for a period of time that issignificantly longer than would have otherwise been the case. In addition, acts of sabotage or eco-terrorism could cause significant damage or injury topeople, property or the environment or lead to extended interruptions of our operations. Any such event that interrupts the revenues generated by ouroperations, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying distributions to ourpartners and, accordingly, adversely affect our financial condition and the market price of our securities.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 litigation, 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. Our failure to maintain adequate insurance coverage or successfully defendagainst product liability claims could materially and adversely affect our business, consolidated results of operations, financial position and cash flows.40Table of ContentsA 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 oroperational systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adverselyaffected if an employee causes our systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our systems. Inaddition, dependence upon automated systems may further increase the risk related to operational system flaws, and employee tampering or manipulation ofthose systems will result in losses that are difficult to detect.Due to increased technology advances, we have become more reliant on technology to increase efficiency in our business. We use various systems inour financial and operations sectors, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, ourcustomers and any financial data could have a material adverse effect on our business. In addition, cyber attacks on our customer and employee data mayresult in a financial loss, including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which werely could also suffer operational system failure. Any of these occurrences could disrupt our business, resulting in potential liability or reputational damageor otherwise have an adverse effect on our financial results.We lease certain facilities and equipment and therefore are subject to the possibility of increased costs to retain necessary land and equipment use.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 flowsDifficulty 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, which could materially and adversely affect our growth and profitability.If we fail to maintain an effective system of internal control, 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 of 2002 to engage our independent registered public accounting firm to attest to the effectiveness of our internalcontrol over financial reporting.Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly tradedpartnership. Our efforts to maintain our internal controls may be unsuccessful, and we may be unable to maintain effective internal control over financialreporting, including our disclosure control. Any failure to maintain effective internal control over financial reporting and disclosure controls could harm ouroperating results or cause us to fail to meet our reporting obligations. These risks may be heightened after a business combination, during the phase when weare implementing our internal control structure over the recently acquired business.41Table of ContentsGiven the difficulties inherent in the design and operation of internal control over financial reporting, as well as future growth of our businesses, wecan provide no assurance as to either our or our independent registered public accounting firm’s conclusions about the effectiveness of internal controls inthe future, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls could subject us to regulatory scrutinyand a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect onthe market price of our common units.An impairment of goodwill and long-lived assets could reduce our earnings.At March 31, 2017, we had goodwill and long-lived assets of $4.4 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 various forms of transportation for receipt and delivery of crude oil, natural gas liquids and refined products.We own natural gas liquids and crude oil terminals and lease refined products terminals. The facilities depend on pipelines, railroads, trucktransports, and storage systems that are owned and operated by third parties. Any interruption of service on pipeline, railroad or lateral connections or adversechange in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport product to andfrom our facilities and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines fortransportation to and from our facilities impact the utilization and value of our terminals. We have historically been able to pass through the costs of pipelinetransportation to our customers. However, if competing pipelines do not have similar annual tariff increases or service fee adjustments, such increases couldaffect our ability to compete, thereby adversely affecting our revenues.Our marketing operations depend on the availability of transportation and storage capacity.Our product supply is transported and stored in facilities owned and operated by third parties. Any interruption of service on the pipeline or storagecompanies or adverse change in the terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, totransport products and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines fortransportation affects the profitability of our operations.The financial results of our natural gas liquids businesses are seasonal and generally lower in the first and second quarters of our fiscal year, which mayrequire us to borrow money to make distributions to our unitholders during these quarters.The natural gas liquids inventory we have presold to customers is highest during summer months, and our cash receipts are lowest during summermonths. As a result, our cash available for distribution for the summer is much lower than for the winter. With lower cash flow during the first and secondfiscal quarters, we may be required to borrow money to pay distributions to our unitholders during these quarters. Any restrictions on our ability to borrowmoney could restrict our ability to pay the minimum quarterly distributions to our unitholders.A significant increase in fuel prices may adversely affect our transportation costs.Fuel is a significant operating expense for us in connection with the delivery of products to our customers. A significant increase in fuel prices willresult in increased transportation costs to us. The price and supply of fuel is unpredictable and fluctuates based on events we cannot control, such asgeopolitical developments, supply and demand for oil and gas,42Table of Contentsactions by oil and gas producers, war and unrest in oil producing countries and regions, regional production patterns and weather concerns. As a result, anyincreases 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, which could have a material impact on both availability and price. Terrorist attacks in the areas of our operations could negatively impact ourability to transport propane to our locations. These risks could potentially negatively impact our consolidated results of operations.We depend on the leadership and involvement of key personnel for the success of our businesses.We have certain key individuals in our senior management who we believe are critical to the success of our business. The loss of leadership andinvolvement of those key management personnel could potentially have a material adverse impact on our business and possibly on the market value of ourcommon units.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 the totality of the relationships between the parties involved, including other transactions that may be particularly favorable oradvantageous to us; and•provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any actsor omissions unless there has been a final and non-appealable judgment entered by a43Table of Contentscourt of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willfulmisconduct.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;•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 the44Table of Contentsboard of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certainsituations.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.The IDRs of our general partner may be transferred to a third party.Prior to the first day of the first quarter beginning after the 10th anniversary of the closing date of our IPO, a transfer of IDRs by our general partnerrequires (except in certain limited circumstances) the consent of a majority of our outstanding common units (excluding common units held by our generalpartner and its affiliates). However, after the expiration of this period, our general partner may transfer its IDRs to a third party at any time without the consentof our unitholders. If our general partner transfers its IDRs to a third party but retains its general partner interest, our general partner may not have the45Table of Contentssame incentive 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;•the relative voting strength of each previously outstanding unit may be diminished; and•the market price of the common units may decline.46Table of ContentsOur 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 our unitholders if the distribution would cause our liabilities to exceed the fair value of our assets.Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and whoknew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limitedpartners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at thetime it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement.Neither liabilities to partners on account of their partnership interests nor liabilities that are nonrecourse to the partnership are counted for purposes ofdetermining whether a distribution is permitted. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware LP Actprovides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnershiponly to the extent that the fair value of that property exceeds the nonrecourse liability.The Preferred Units give the holders thereof liquidation and distribution preferences, certain rights relating to our business and management, and theability to convert such units into our common units, potentially causing dilution to our common unitholders.In June 2016, we issued 19,942,169 10.75% Class A Convertible Preferred Units (“Preferred Units”), which rank senior to the common units withrespect to distribution rights and rights upon liquidation. Subject to certain exceptions, as long as any Preferred Units remain outstanding, we may notdeclare any distribution on our common units unless all accumulated and unpaid distributions have been declared and paid on the Preferred Units. In theevent of our liquidation, winding-up or47Table of Contentsdissolution, the holders of the Preferred Units would have the right to receive proceeds from any such transaction before the holders of the common units. Thepayment of the liquidation preference could result in common unitholders not receiving any consideration if we were to liquidate, dissolve or wind up, eithervoluntarily or involuntarily. Additionally, the existence of the liquidation preference may reduce the value of the common units, make it harder for us to sellcommon units in offerings in the future, or prevent or delay a change of control.In connection with the issuance of the Preferred Units, we entered into an agreement with Oaktree Capital Management L.P. (“Oaktree”) pursuant towhich we granted them the right to appoint one member to the board of directors of our general partner. In addition, the holders of the Preferred Units havethe right to vote, under certain conditions, on an as-converted basis with our common unitholders on matters submitted to a unitholder vote. Also, as long asany Preferred Units are outstanding, subject to certain exceptions, the affirmative vote or consent of the holders of at least a majority of the outstandingPreferred Units, voting together as a separate class, will be necessary for effecting or validating, among other things: (i) any action to be taken that adverselyaffects any of the rights, preferences or privileges of the Preferred Units, (ii) amending the terms of the Preferred Units, (iii) the issuance of any additionalPreferred Units or equity security senior in right of distribution or in liquidation to the Preferred Units, (iv) any issuance of preferred equity securities by anyof our consolidated controlled subsidiaries of any issued or authorized amount of, any specific class or series of securities, (v) any issuance by us of parityunits, subject to certain exceptions and (vi) the ability to incur funded indebtedness for borrowed money if pro forma for such incurrence, the adjustedleverage ratio (as defined in the Credit Agreement) would exceed 5.50. These restrictions may adversely affect our ability to finance future operations orcapital needs or to engage in other business activities.Furthermore, the conversion of the Preferred Units into common units, as early as three years from the issuance date of the Preferred Units, may causesubstantial dilution to holders of the common units. Because the board of directors of our general partner is entitled to designate the powers and preferencesof Preferred Units without a vote of our unitholders, subject to New York Stock Exchange rules and regulations, our unitholders will have no control overwhat designations and preferences our future preferred units, if any, will have.The issuance of common units upon exercise of the warrants may cause dilution to existing common unitholders and may place downward pressure on thetrading price of our common units.In connection with our issuance of Preferred Units in June 2016, we issued warrants exercisable into a maximum of 4,375,112 common units, with anexercise price of $0.01 per common unit. One-third of the warrants are exercisable beginning on or after the first anniversary of the original issue date, anotherone-third of the warrant units from and after the second anniversary of the original issue date and the final one-third may be converted from and after the thirdanniversary. The future exercise of the warrants by the holders of those securities may cause a reduction in the relative voting power and percentageownership interests of our other common unitholders, and may place downward pressure on the trading price of our common units.Tax 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 federalincome tax purposes. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federalincome tax purposes.Despite the fact that we are a limited partnership under Delaware law, a publicly traded partnership such as us will be treated as a corporation forfederal income tax purposes unless, for each taxable year, 90% or more of its gross income is “qualifying income” under Section 7704 of the InternalRevenue Code of 1986, as amended (the “Internal Revenue Code”). “Qualifying income” includes income and gains derived from the exploration,development, production, processing, transportation, storage and marketing of natural gas, natural gas products, and crude oil or other passive types ofincome such as certain interest and dividends and gains from the sale or other disposition of capital assets held for the production of income that otherwiseconstitutes qualifying income. Although we do not believe based upon our current operations that we are treated as a corporation, we could be treated as acorporation for federal income tax purposes or otherwise subject to taxation as an entity if our gross income is not properly classified as qualifying income,there is a change in our business or there is a change in current law.48Table of ContentsIf 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 Congress propose and consider substantivechanges to the existing United States federal income tax laws that affect the tax treatment of publicly traded partnerships, including as a result of anyfundamental tax reform.We are unable to predict whether any such change or other proposals will ultimately be enacted or will affect our tax treatment. Any modification tothe income tax laws and interpretations thereof may or may not be applied retroactively and could, among other things, cause us to be treated as a corporationfor federal income tax purposes or otherwise subject us to entity-level taxation. Moreover, such modifications and change in interpretations may affect orcause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our incomeand adversely affect an investment in our common units. Although we are unable to predict whether any of these changes, or other proposals, will ultimatelybe enacted, any such changes could negatively impact the value of an investment in our common units.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.49Table of ContentsTax 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 our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have anegative impact on the market 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 business day of each month, instead of on the basis of the date a particular unit is transferred. The U.S. Department of the Treasury recentlyadopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However,such regulations do not specifically authorize all aspects of the proration method we have adopted. If the IRS were to challenge our proration method, wemay be required to change the allocation of items of income, gain, loss and deduction among our unitholders.50Table of ContentsA unitholder whose units are loaned to a “short seller” to affect a short sale of units may be considered as having disposed of those common units. If so,such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loanand may recognize gain or loss from the disposition.Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of the loanedunits, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and theunitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss ordeduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could befully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller areurged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers fromborrowing their units.We have adopted certain valuation methodologies and monthly conventions for United States federal income tax purposes that may result in a shift ofincome, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect thevalue of our common units.When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate anyunrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed asunderstating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner,which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greaterportion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. TheIRS may challenge our valuation methods, or our allocation of the Internal Revenue Code Section 743(b) adjustment attributable to our tangible andintangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of our unitholders.A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to ourunitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of thecommon units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnershipfor federal income tax purposes.We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the totalinterests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of thesame unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, amongother things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive twoSchedules K-1 if relief was not available, as described below) for one fiscal year and could result in a significant deferral of depreciation deductions allowablein 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 other51Table of Contentspassive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by aunitholder include 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. PropertiesWe believe that we have satisfactory title or valid rights to use all of our material properties. Although some of these properties are subject toliabilities 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 facility and our senior secured notes are secured byliens and mortgages on substantially all of our real and personal property.Other than as described below, we believe that we have all required material approvals, authorizations, orders, licenses, permits, franchises andconsents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local governmental andregulatory authorities that relate to ownership of our properties or the operations of our business.One of our facilities is operating with all but one of the required permits, as the State of Wyoming has not yet developed a process for issuing permitsof this type. We believe that the permit will ultimately be granted, but we are unable to determine the timing of any action by the State of Wyoming.Our corporate headquarters are in Tulsa, Oklahoma and are leased. We also lease corporate offices in Denver, Colorado 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, 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.52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, 2017, there wereapproximately 170 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 Distribution2017 Fiscal Year Fourth Quarter $25.80 $20.56 $0.3900Third Quarter $21.50 $14.65 $0.3900Second Quarter $20.00 $16.75 $0.3900First Quarter $20.06 $7.10 $0.39002016 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 $0.6250Cash 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(defined herein)) and our 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.The following table illustrates the percentage allocations of available cash from operating surplus between our unitholders and our general partnerbased on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentage interests ofour general partner and our unitholders in any available53Table of Contentscash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” untilavailable cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for our unitholders andour general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterlydistribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest, and assume that our general partner hascontributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred 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 and Senior Secured Notescontain covenants limiting our ability to pay distributions if we are in default under the Credit Agreement and the Senior Secured Notes and to paydistributions that are in excess of available cash, as defined in the Credit Agreement. In addition, quarterly distributions on the preferred units must be fullypaid for all preceding fiscal quarters before we are permitted to declare or pay any distributions on our common units.Sales of Unregistered SecuritiesOn August 17, 2016, we completed one acquisition in which we issued 218,617 unregistered common units as partial consideration. All of theseunits were issued in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act of 1933, as amended (“Securities Act”), asthe units were issued to the owners of businesses acquired in privately negotiated transactions not involving any public offering or solicitation.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. 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 consolidated historical financial 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 at March 31, 2017 and 2016, and for each of the three years in the period ended March 31, 2017is derived from our audited historical consolidated financial statements included in this Annual Report. The selected consolidated historical financial data atMarch 31, 2015, 2014 and 2013 and for each of the two years in the period ended March 31, 2014 is derived from our audited historical consolidatedfinancial statements not included in this Annual Report.54Table of Contents Year Ended March 31, 2017 2016 2015 2014 2013 (in thousands, except per unit data)Income Statement Data (1)(2) Total revenues $13,022,228 $11,742,110 $16,802,057 $9,699,274 $4,417,767Total cost of sales $12,321,909 $10,839,037 $15,958,207 $9,132,699 $4,039,110Operating income (loss) $255,083 $(104,603) $107,420 $106,565 $87,307Interest expense $150,478 $133,089 $110,123 $58,854 $32,994(Gain) loss on early extinguishment of liabilities, net $(24,727) $(28,532) $— $— $5,769Net income (loss) attributable to NGL Energy Partners LP $137,042 $(198,929) $37,306 $47,655 $47,940Basic income (loss) per common unit $0.99 $(2.35) $(0.05) $0.51 $0.96Diluted income (loss) per common unit $0.95 $(2.35) $(0.05) $0.51 $0.96Cash Flows Data (1)(2) Net cash (used in) provided by operating activities $(26,824) $351,495 $262,391 $85,236 $132,634Net cash used in investing activities $(363,126) $(445,327) $(1,366,221) $(1,455,373) $(546,621)Net cash provided by financing activities $374,038 $80,705 $1,134,693 $1,369,016 $417,716Cash distributions paid per common unit $1.56 $2.54 $2.37 $2.01 $1.69Balance Sheet Data - Period End (1)(2) Total assets $6,320,379 $5,560,155 $6,655,792 $4,134,910 $2,290,901Total long-term obligations, exclusive of debt issuance costs andcurrent maturities $3,148,017 $3,160,073 $2,842,493 $1,628,173 $741,924Total equity $2,166,802 $1,694,065 $2,693,432 $1,531,853 $889,418 (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 for our limited partnerinvestment in TLP using the equity method of accounting. On April 1, 2016, we sold all of the TLP common units we owned.55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 discussed in Part I, Item 1–“Business–Acquisitions.” At March 31, 2017, our operations include:•Crude Oil Logistics•Water Solutions•Liquids•Retail Propane•Refined Products and RenewablesCrude Oil LogisticsOur Crude Oil Logistics segment purchases crude oil from producers and transports it to refineries or for resale at pipeline injection stations, storageterminals, barge loading facilities, rail facilities, refineries, and other trade hubs.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: Crude Oil Spot Price Per BarrelYear Ended March 31, Low High At Period End2017 $35.70 $54.45 $50.602016 $26.21 $61.43 $38.342015 $43.46 $107.26 $47.60We 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 operating losses of $17.5 million and $40.7 million during the years ended March 31, 2017 and 2016,respectively. The operating loss during the year ended March 31, 2016 included a write-down of $47.7 million related to pipe we no longer expected to usein the originally-planned Grand Mesa Pipeline.Water 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 and frac tank washouts. In addition, our Water Solutions segment sellsthe recovered hydrocarbons that result from performing these services.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 at56Table of Contentswells 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. Mostcustomers of our other facilities are not under volume commitments, although certain of our facilities are connected to producer locations by pipeline.Our Water Solutions segment generated operating income of $44.6 million during the year ended March 31, 2017, which includes an adjustment of$124.7 million of the previously recorded $380.2 million estimated goodwill impairment charge recorded during the three months ended March 31, 2016(see Note 6 to our consolidated financial statements included in this Annual Report). Our Water Solutions segment generated an operating loss of $313.7million during the year ended March 31, 2016, which included a goodwill impairment of $380.2 million as the decline in crude oil prices and crude oilproduction 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 21 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 Propane Spot Price Per Gallon Propane Spot Price Per GallonYear Ended March 31, Low High At Period End Low High At Period End2017 $0.35 $0.89 $0.56 $0.42 $0.93 $0.612016 $0.27 $0.51 $0.39 $0.30 $0.57 $0.442015 $0.38 $1.13 $0.45 $0.45 $1.13 $0.51The following table summarizes the range of low and high spot butane prices per gallon at Mt. Belvieu, Texas for the periods indicated and theprices at period end: Butane Spot Price Per GallonYear Ended March 31, Low High At Period End2017 $0.52 $1.42 $0.752016 $0.42 $0.68 $0.532015 $0.60 $1.30 $0.63We 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 $43.3 million and $76.2 million during the years ended March 31, 2017 and 2016, respectively.During the year ended March 31, 2016, we wrote off assets of $14.6 million acquired as part of the Gavilon, LLC (“Gavilon Energy”) acquisition that wedeemed no longer recoverable.57Table of ContentsRetail PropaneOur Retail Propane segment is a “cost-plus” business that sells propane, distillates, equipment and supplies to end users consisting of residential,agricultural, commercial, and industrial customers and to certain resellers in 30 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 aproduct and the selling price of the product in the retail markets. These margins fluctuate over time due to supply and demand conditions. Weatherconditions can have a significant impact on our sales volumes and prices, as a large portion of our sales are to residential customers who purchase propaneand distillates for home heating purposes.A significant factor affecting the profitability of our Retail Propane segment is our ability to maintain our product margin. Product margin is 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 $49.3 million and $44.1 million during the years ended March 31, 2017 and 2016,respectively.Refined Products and RenewablesOur Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refined petroleumand renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedules them for delivery at various locationsthroughout the country. We sell our products to commercial and industrial end users, independent retailers, distributors, marketers, government entities, andother wholesalers of refined petroleum products. We sell our products at terminals owned by third parties.The following table summarizes the range of low and high spot Gulf Coast gasoline prices per barrel using NYMEX gasoline prompt-month futuresfor the periods indicated and the prices at period end: Gasoline Spot Price Per BarrelYear Ended March 31, Low High At Period End2017 $53.44 $71.40 $71.402016 $37.75 $90.15 $59.912015 $53.34 $131.46 $74.76The 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: Diesel Spot Price Per BarrelYear Ended March 31, Low High At Period End2017 $45.13 $71.58 $66.092016 $36.36 $84.68 $49.762015 $68.04 $128.10 $72.24Our Refined Products and Renewables segment generated operating income of $222.5 million during the year ended March 31, 2017, whichincludes a gain of $104.1 million recorded on the sale of all of the TransMontaigne Partners L.P. (“TLP”) common units we owned during the year endedMarch 31, 2017. Our Refined Products and Renewables segment generated operating income of $227.0 million during the year ended March 31, 2016, whichincluded a gain of $130.4 million recorded on the sale of our general partner interest in TLP during the three months ended March 31, 2016, as discussed inNote 2 to our consolidated financial statements included in this Annual Report.58Table of ContentsTrendsCrude 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. At March 31, 2017, the spot price for NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma was $50.60 per barrel. Whilecrude oil production in the United States has been strong in recent years, the sharp decline in crude oil prices has reduced the incentive for producers toexpand production. If crude oil prices remain low, resultant declines in crude oil production may adversely impact volumes and margins in our Crude OilLogistics business. 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.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 but have increased since March 31, 2016. Also, drillingrigs and production have increased since March 31, 2016, particularly in the Permian and DJ Basins which has positively impacted the volumes of our WaterSolutions business (during the three months ended March 31, 2017 we processed 536,000 barrels of wastewater per day, compared to 479,000 barrels ofwastewater per day during the three months ended March 31, 2016). A portion of the revenues in our Water Solutions business is generated from the sale ofhydrocarbons that we recover when processing wastewater. These recovered hydrocarbon revenues have decreased due to lower realized prices as well asproducers recovering higher levels of crude oil in produced wastewater prior to delivering such water to us for treatment. These two factors have resulted inlower per-barrel revenues for our 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 at terminals owned by third parties. Mostof the contracts with these customers are one year in duration, 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 in transit on the third party pipelines and at the destination terminals where we sell the product. The value ofthis inventory will increase or decrease as market prices change. In order to mitigate this risk, we enter into futures contracts, which are only available basedon New York Harbor pricing. Because our contracts are indexed to Gulf Coast prices and our futures contracts are based on New York Harbor prices, thefutures contracts are not a perfect hedge against our inventory holding risk. During any given period, spreads between prices in the Gulf Coast and New YorkHarbor could narrow or widen, which could reduce the effectiveness of the futures contracts as a hedge of the inventory holding risk. The tenor of thesefutures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarterswithin a fiscal year.During the year ended March 31, 2017, prices for refined products increased. Gulf Coast prices, on which our sales contracts are based, increasedmore than the New York Harbor prices, on which our futures contracts are based, which had a favorable impact on our cost of sales. Based on historicalexperience, we generally expect the spreads between Gulf Coast and New York Harbor prices to be more consistent over the course of a contract year thanduring any individual quarter within the year, and that we should expect more volatility in cost of sales among quarters within a fiscal year than we wouldexpect during a full fiscal year.SeasonalitySeasonality impacts our Liquids and Retail Propane segments. A large portion of our Retail Propane business is in the residential market wherepropane is used primarily for home heating purposes. Consequently, for these two segments, revenues, operating profits and operating cash flows aregenerated mostly in the third and fourth quarters of each fiscal year. See “–Liquidity, Sources of Capital and Capital Resource Activities–Cash Flows.”59Table of ContentsRecent DevelopmentsTransactions during the Three Months Ended March 31, 2017Credit AgreementIn February 2017, we amended and restated our Credit Agreement (as defined herein) with a syndicate of banks, decreasing our initial borrowingcapacity from $2.484 billion to $1.765 billion and extending the term of our facility to October 2021. See Note 8 to our consolidated financial statementsincluded in this Annual Report for a further description of our Credit Agreement.Senior Secured NotesIn March 2017, we amended and restated our Senior Secured Notes Purchase Agreement with an effective date of December 31, 2016, whichconforms to the amended terms of the Credit Agreement.2025 NotesOn February 22, 2017, we issued $500.0 million of Senior Notes (the “2025 Notes”) in a private placement. The 2025 Notes bear interest at 6.125%and mature on March 1, 2025. See Note 8 to our consolidated financial statements included in this Annual Report for a further description of these notes.Equity IssuanceOn February 22, 2017, we issued 10,120,000 common units representing limited partner interests and received net proceeds of $222.5 million. SeeNote 11 to our consolidated financial statements included in this Annual Report for a further description of this equity issuance.AcquisitionsAs discussed below, we completed numerous acquisitions during the years ended March 31, 2017 and 2016. These acquisitions impact thecomparability of our results of operations between our current and prior fiscal years.During the year ended March 31, 2017, in our Water Solutions segment, we acquired (i) three water solutions facilities, (ii) the remaining 25%ownership interest in three water solutions facilities, (iii) an additional 24.5% interest in an existing produced water pipeline company, and (iv) the remaining65% ownership interest in Grassland Water Solutions, LLC (“Grassland”), which we subsequently sold 100% of our interest. During the year ended March 31,2017, in our Retail Propane segment, we acquired four retail propane businesses. During the year ended March 31, 2017, in our Liquids segment, we acquiredcertain natural gas liquids facilities. See Note 4 to our consolidated financial statements included in this Annual Report for a further discussion of eachacquisition.During the year ended March 31, 2016, in our Water Solutions segment, we acquired (i) a 57.125% interest in an existing produced water pipelinecompany and (ii) 20 water solutions facilities and a 50% interest in an additional facility. During the year ended March 31, 2016, in our Retail Propanesegment, we acquired six retail propane businesses. See Note 4 to our consolidated financial statements included in this Annual Report for a furtherdiscussion.DispositionsSale of GrasslandOn November 29, 2016, we sold Grassland, for $22.0 million and recorded a loss on the sale of $2.3 million during the year ended March 31, 2017.See Note 4 to our consolidated financial statements included in this Annual Report for a further discussion of this disposition.60Table of ContentsConsolidated Results of OperationsThe following table summarizes our consolidated statements of operations for the periods indicated: Year Ended March 31, 2017 2016 2015 (in thousands)Total revenues $13,022,228 $11,742,110 $16,802,057Total cost of sales 12,321,909 10,839,037 15,958,207Operating expenses 307,925 401,118 364,131General and administrative expense 116,566 139,541 149,430Depreciation and amortization 223,205 228,924 193,949(Gain) loss on disposal or impairment of assets, net (209,177) 320,766 41,184Revaluation of liabilities 6,717 (82,673) (12,264)Operating income (loss) 255,083 (104,603) 107,420Equity in earnings of unconsolidated entities 3,084 16,121 12,103Revaluation of investments (14,365) — —Interest expense (150,478) (133,089) (110,123)Gain on early extinguishment of liabilities, net 24,727 28,532 —Other income, net 27,762 5,575 37,171Income (loss) before income taxes 145,813 (187,464) 46,571Income tax (expense) benefit (1,939) 367 3,622Net income (loss) 143,874 (187,097) 50,193Less: Net income attributable to noncontrolling interests (6,832) (11,832) (12,887)Net income (loss) attributable to NGL Energy Partners LP 137,042 (198,929) 37,306Less: Distributions to preferred unitholders (30,142) — —Less: Net income allocated to general partner (232) (47,620) (45,700)Net income (loss) allocated to common unitholders $106,668 $(246,549) $(8,394)Items 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 variousbusiness combinations. We have expanded our Water Solutions business considerably through numerous acquisitions of water treatment and disposalfacilities. We have expanded our Liquids business through the February 2015 acquisition of Sawtooth and the natural gas liquid terminals in January 2017.We have expanded our Retail Propane business through numerous acquisitions of retail propane businesses. As previously reported, on February 1, 2016, wesold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment inTLP using the equity method of accounting. On April 1, 2016, we sold all of the TLP common units that we owned. See the detailed discussion of itemsaffecting operating income (loss) 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 NGL Energy Partners LP, plus interest expense, income tax expense (benefit), anddepreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding net unrealized gains and losses on derivatives, lower of cost ormarket adjustments, gains and losses on disposal or impairment of assets, gain on early extinguishment of liabilities, revaluation of investments, equity-basedcompensation expense, acquisition expense and other. We also include in Adjusted EBITDA certain inventory valuation adjustments related to our RefinedProducts and Renewables segment, as discussed below. EBITDA and Adjusted EBITDA should not be considered alternatives to net income, income beforeincome taxes, cash flows from operating activities, or any other measure of financial performance61Table of Contentscalculated in accordance with GAAP, as those items are used to measure operating performance, liquidity or the ability to service debt obligations. Webelieve that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions to our unitholders, and it ispresented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information to investors for evaluating our financialperformance without regard to our financing methods, capital structure and historical cost basis. Further, EBITDA and Adjusted EBITDA, as we define them,may not be comparable to EBITDA, 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 not draw such a distinction between realized and unrealized gains and losses on derivatives of our Refined Products andRenewables segment. The primary hedging strategy of our Refined Products and Renewables segment is to hedge against the risk of declines in the value ofinventory over the course of the contract cycle, and many of the hedges are six months to one year in duration at inception. The “inventory valuationadjustment” row in the reconciliation table reflects the difference between the market value of the inventory of our Refined Products and Renewablessegment at the balance sheet date and its cost. We include this in Adjusted EBITDA because the unrealized gains and losses associated with derivativecontracts associated with the inventory of this segment, which are intended primarily to hedge inventory holding risk and are included in net income, alsoaffect Adjusted EBITDA.A portion of the revenues in our Water Solutions business is generated from the sale of hydrocarbons that we recover when processing wastewater.We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expect to recoverwhen processing the wastewater. During the year ended March 31, 2016, we settled certain derivative contracts that related to crude oil we recovered in themonths from 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 wereattributable to derivatives that settled during the quarters ended June 30, 2016, September 30, 2016, and December 31, 2016, respectively. During the yearended March 31, 2015, we settled certain derivative contracts that related to crude oil we recovered in the months from April 2015 through September 2015and realized a gain of $17.9 million. Of this gain, $9.4 million and $8.5 million were attributable to derivatives that settled during the quarters endedJune 30, 2015 and September 30, 2015, respectively.The following table reconciles net income (loss) to EBITDA and Adjusted EBITDA: Year Ended March 31, 2017 2016 2015 (in thousands)Net income (loss) $143,874 $(187,097) $50,193Less: Net income attributable to noncontrolling interests (6,832) (11,832) (12,887)Net income (loss) attributable to NGL Energy Partners LP 137,042 (198,929) 37,306Interest expense 150,504 126,514 106,594Income tax expense (benefit) 1,939 (420) (3,676)Depreciation and amortization 238,583 217,893 191,998EBITDA 528,068 145,058 332,222Net unrealized (gains) losses on derivatives (3,338) 1,255 7,559Inventory valuation adjustment (1) 7,368 24,390 —Lower of cost or market adjustments (1,283) (5,932) 16,806(Gain) loss on disposal or impairment of assets, net (209,213) 320,783 41,274Gain on early extinguishment of liabilities, net (24,727) (28,532) —Revaluation of investments 14,365 — —Equity-based compensation expense (2) 53,102 58,816 42,890Acquisition expense (3) 1,771 2,002 23,198Other (4) 14,687 (93,725) (20,645)Adjusted EBITDA $380,800 $424,115 $443,304 (1)Amount reflects the difference between the market value of the inventory of our Refined Products and Renewables segment at the balance sheet date and its cost. See “Non-GAAP Financial Measures” section above for a further discussion.62Table of Contents(2)Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 11 to our consolidated financial statementsincluded in this Annual Report on Form 10-K (“Annual Report”). Amounts reported in the table above include expense accruals for bonuses expected to be paid in commonunits, whereas the amounts reported in Note 11 to our consolidated financial statements only include expenses associated with equity-based awards that have been formallygranted.(3)During the years ended March 31, 2017, 2016 and 2015, we incurred expenses related to legal and advisory costs associated with acquisitions. During the year endedMarch 31, 2015, we recorded $15.8 million of compensation expense associated with acquisitions (including certain bonuses that the previous owners of Gavilon Energygranted to employees, contingent upon the successful completion of the sale of the business, and compensation expense related to termination benefits for certainTransMontaigne Inc. (“TransMontaigne”) employees).(4)The amount for the year ended March 31, 2017 represents non-cash operating expenses related to our Grand Mesa Pipeline project and also includes adjustments related tononcontrolling interests. Amounts for the years ended March 31, 2016 and 2015 represent the non-cash valuation adjustment of contingent consideration liabilities, offset bythe cash payments, related to royalty agreements acquired as part of acquisitions in our Water Solutions segment, and amounts attributable 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, 2017 2016 2015 (in thousands)Reconciliation to consolidated statements of operations: Depreciation and amortization per EBITDA table $238,583 $217,893 $191,998Intangible asset amortization recorded to cost of sales (6,828) (6,700) (7,767)Depreciation and amortization of unconsolidated entities (12,136) (14,814) (14,982)Depreciation and amortization attributable to noncontrolling interests 3,586 32,545 24,700Depreciation and amortization per consolidated statements of operations $223,205 $228,924 $193,949 Reconciliation to consolidated statements of cash flows: Depreciation and amortization per EBITDA table $238,583 $217,893 $191,998Amortization of debt issuance costs recorded to interest expense 7,762 13,587 8,759Depreciation and amortization of unconsolidated entities (12,136) (14,814) (14,982)Depreciation and amortization attributable to noncontrolling interests 3,586 32,545 24,700Depreciation and amortization per consolidated statements of cash flows $237,795 $249,211 $210,475 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, 2017 2016 2015 (in thousands)Interest expense per EBITDA table $150,504 $126,514 $106,594Interest expense attributable to noncontrolling interests (1) 26 5,315 4,139Interest expense attributable to unconsolidated entities (2) (52) 567 (610)Gain on extinguishment of debt of unconsolidated entities — 693 —Interest expense per consolidated statements of operations $150,478 $133,089 $110,123 (1)Includes ten months of consolidated TLP interest expense during the year ended March 31, 2016.(2)Includes two months of TLP interest expense as an equity method investment during the year ended March 31, 2016.63Table of ContentsThe following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated. We have reclassified certain priorperiod information to be consistent with the classification methods used in the current fiscal year. Year Ended March 31, 2017 Crude OilLogistics WaterSolutions Liquids RetailPropane RefinedProductsandRenewables CorporateandOther Consolidated (in thousands)Operating (loss) income $(17,475) $44,587 $43,252 $49,255 $222,546 $(87,082) $255,083Depreciation and amortization 54,144 101,758 19,163 42,966 1,562 3,612 223,205Amortization recorded to cost of sales 384 — 781 — 5,663 — 6,828Net unrealized (gains) losses on derivatives (1,513) (2,088) 216 47 — — (3,338)Inventory valuation adjustment — — — — 7,368 — 7,368Lower of cost or market adjustments — — — — (1,283) — (1,283)Loss (gain) on disposal or impairment ofassets, net 10,704 (85,560) 92 (287) (134,125) (1) (209,177)Equity-based compensation expense — — — — — 53,102 53,102Acquisition expense — — — — — 1,771 1,771Other (expense) income, net (412) 739 73 504 19,263 7,595 27,762Adjusted EBITDA attributable tounconsolidated entities 11,589 106 — (427) 3,975 — 15,243Adjusted EBITDA attributable tononcontrolling interest — (3,166) — (1,241) — — (4,407)Other 1,926 6,717 — — — — 8,643Adjusted EBITDA $59,347 $63,093 $63,577 $90,817 $124,969 $(21,003) $380,800 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 amortization 39,363 91,685 15,642 35,992 40,861 5,381 228,924Amortization recorded to cost of sales 250 — 1,044 — 5,406 — 6,700Net unrealized losses (gains) on derivatives 2,123 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 ofassets, net 54,952 381,682 11,600 (137) (127,331) — 320,766Equity-based compensation expense — — — — 877 58,315 59,192Acquisition expense — — — 7 — 1,995 2,002Other (expense) income, net (6,725) 2,144 281 791 443 8,641 5,575Adjusted EBITDA attributable tounconsolidated entities 13,474 (701) — (425) 17,960 — 30,308Adjusted EBITDA attributable tononcontrolling interest — (2,259) — (1,065) (50,438) — (53,762)Other — (90,700) — — — — (90,700)Adjusted EBITDA $61,481 $71,374 $100,732 $79,203 $134,398 $(23,073) $424,11564Table of Contents 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 amortization 38,626 73,618 13,513 31,827 32,948 3,417 193,949Amortization recorded to cost of sales 102 — 1,931 — 4,057 1,677 7,767Net unrealized losses (gains) on derivatives 7,421 (2,786) 2,921 3 — — 7,559Lower of cost or market adjustments 10,744 — (51) — 6,113 — 16,806Loss (gain) on disposal or impairment ofassets, net 3,759 7,504 29,775 282 — (136) 41,184Equity-based compensation expense — — — — 572 42,767 43,339Acquisition expense 6,870 — — 45 8,510 7,773 23,198Other income (expense), net 27,305 3,360 31 1,526 (44) 4,993 37,171Adjusted EBITDA attributable tounconsolidated entities 13,944 1,613 — — 12,178 — 27,735Adjusted EBITDA attributable tononcontrolling interest — (2,075) — (944) (39,496) — (42,515)Other — (20,309) — — — — (20,309)Adjusted EBITDA $72,939 $126,265 $93,192 $96,814 $79,405 $(25,311) $443,304 65Table of ContentsSegment Operating Results for the Years Ended March 31, 2017 and 2016Crude Oil Logistics The following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated: Year Ended March 31, 2017 2016 Change (in thousands, except per barrel amounts)Revenues: Crude oil sales $1,603,667 $3,170,891 $(1,567,224)Crude oil transportation and other 70,027 55,882 14,145Total revenues (1) 1,673,694 3,226,773 (1,553,079)Expenses: Cost of sales 1,578,825 3,121,411 (1,542,586)Operating expenses 41,535 43,458 (1,923)General and administrative expenses 5,961 8,334 (2,373)Depreciation and amortization expense 54,144 39,363 14,781Loss on disposal or impairment of assets, net 10,704 54,952 (44,248)Total expenses 1,691,169 3,267,518 (1,576,349)Segment operating loss $(17,475) $(40,745) $23,270 Crude oil sold (barrels) 34,212 67,211 (32,999)Crude oil transported on owned pipelines (barrels) 6,365 — 6,365Crude oil storage capacity - owned and leased (barrels) (2) 7,024 6,115 909Crude oil storage capacity sub-leased to third parties (barrels) (2) 1,400 2,000 (600)Crude oil inventory (barrels) (2) 2,844 2,123 721Crude oil sold ($/barrel) $46.874 $47.178 $(0.304)Cost per crude oil sold ($/barrel) $46.148 $46.442 $(0.294)Crude oil product margin ($/barrel) $0.726 $0.736 $(0.010) (1)Revenues include $6.8 million and $9.7 million of intersegment sales during the years ended March 31, 2017 and 2016, respectively, that are eliminated in our consolidatedstatements of operations.(2)Information is presented as of March 31, 2017 or March 31, 2016.Crude Oil Sales. The decrease in our sales volumes was due primarily to increased competition. In addition, we also had an increase in buy/selltransactions during the year ended March 31, 2017, compared to the year ended March 31, 2016. These are transactions in which we transact to purchaseproduct from a counterparty and sell the same volumes of product to the same counterparty at a different location or time. As the revenues and costs of salesare netted for these transaction, so are the volumes.Crude Oil Transportation and Other Revenues. The increase was due primarily to our Grand Mesa Pipeline project becoming operational onNovember 1, 2016 with revenues of $29.2 million, partially offset by the flattening of the contango curve for crude oil (a condition in which forward crudeoil prices are greater than spot prices) during the year ended March 31, 2017, compared to the year ended March 31, 2016, and lower revenues in our truckingand barge operations during the year ended March 31, 2017 due to a general slowdown in demand for transportation services, compared to the year endedMarch 31, 2016.Cost of Sales. During the year ended March 31, 2017, our cost of sales decreased due to the decline in crude oil prices and the decrease in volumesdue to increased competition. Our cost of sales during the year ended March 31, 2017 was increased by $7.1 million of net realized losses on derivatives andreduced by $1.5 million of net unrealized gains on derivatives. Our cost of sales during the year ended March 31, 2016 was reduced by $13.8 million of netrealized gains on derivatives and increased by $2.1 million of net unrealized losses on derivatives.66Table of ContentsOperating and General and Administrative Expenses. The decrease was due primarily to lower compensation expense related to a reduction in thenumber of employees as a result of organizational changes, lower repair and maintenance expense related to trucking operations resulting from a generalslowdown in demand for transportation services, and lower repair and maintenance expense related to having a newer fleet of barges and the timing of repairs,partially offset by our Grand Mesa Pipeline project becoming operational on November 1, 2016 which incurred operating expenses of $4.8 million.Depreciation and Amortization Expense. The increase was due primarily to our Grand Mesa Pipeline project becoming operational on November 1,2016, partially offset by certain intangible assets being fully amortized during the year ended March 31, 2016.Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2017, we recorded a net loss of $6.5 million on the sales of certainassets and a loss of $4.2 million due to the write-down of certain other assets. During the year ended March 31, 2016, we recorded a loss of $50.1 million dueto the write-down of certain assets, a loss of $3.1 million due to the cancellation of two previously-planned projects and a loss of $1.8 million on the sales ofcertain other assets.Water SolutionsThe following table summarizes the operating results of our Water Solutions segment for the periods indicated: Year Ended March 31, 2017 2016 Change (in thousands, except per barrel and per day amounts)Revenues: Service fees $110,049 $136,710 $(26,661)Recovered hydrocarbons 31,103 41,090 (9,987)Other revenues 18,449 7,201 11,248Total revenues 159,601 185,001 (25,400)Expenses: Cost of sales-derivative loss (gain) 1,997 (7,095) 9,092Cost of sales-other 2,071 (241) 2,312Operating expenses 85,562 112,538 (26,976)General and administrative expenses 2,469 2,778 (309)Depreciation and amortization expense 101,758 91,685 10,073(Gain) loss on disposal or impairment of assets, net (85,560) 381,682 (467,242)Revaluation of liabilities 6,717 (82,673) 89,390Total expenses 115,014 498,674 (383,660)Segment operating income (loss) $44,587 $(313,673) $358,260 Water processed (barrels per day) Eagle Ford Basin 208,649 236,792 (28,143)Permian Basin 184,702 179,413 5,289DJ Basin 68,253 107,353 (39,100)Other Basins 40,185 45,949 (5,764)Total 501,789 569,507 (67,718)Solids processed (barrels per day) 3,056 3,149 (93)Skim oil sold (barrels per day) 1,989 2,935 (946)Service fee for water processed ($/barrel) $0.60 $0.66 $(0.06)Recovered hydrocarbons for water processed ($/barrel) $0.17 $0.20 $(0.03)Operating expenses for water processed ($/barrel) $0.47 $0.54 $(0.07)Service Fee Revenues. The decrease was due primarily to a decrease in the volume processed from a slowdown in customer production anddevelopment activity and a lower price per barrel received in current market conditions from new facilities being operational during the year endedMarch 31, 2017.67Table of ContentsRecovered Hydrocarbon Revenues. The decrease was due primarily to a decrease in the volume of wastewater processed and a decrease in theamount of hydrocarbons per barrel of wastewater processed.Other Revenues. Other revenues primarily include solids disposal revenues, freshwater revenues, and water pipeline revenues. The increase was dueprimarily to an increase in revenues in the freshwater and water pipeline businesses as well as revenue from trucking wastewater to certain of our watersolutions facilities. See the below discussion of the loss on the sale of Grassland.Cost of Sales-Derivatives. We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of thehydrocarbons we expect to recover when processing the wastewater. Our cost of sales during the year ended March 31, 2017 included $4.1 million of netrealized losses on derivatives and the reversal of $2.1 million of net unrealized losses on derivatives at March 31, 2016 as there were no open derivatives atMarch 31, 2017. Our cost of sales during the year ended March 31, 2016 included $10.3 million of net realized gains on derivatives and $3.2 million of netunrealized losses on derivatives. In December 2015, we settled derivative contracts that had scheduled settlement dates from January 2016 through December2016, in order to lock in the gains on those derivatives.Cost of Sales-Other. The increase was due to trucking expenses to bring wastewater to certain of our water solutions facilities.Operating Expenses. The decrease was due primarily to lower operating costs of water disposal wells due to lower volumes processed and costreduction efforts.Depreciation and Amortization Expense. The increase was due primarily to acquisitions and developed facilities, partially offset by loweramortization expense from the write-off of an intangible asset as well as certain intangible assets being fully amortized during the years ended March 31,2017 and March 31, 2016 (see Note 7 to our consolidated financial statements included in this Annual Report).(Gain) Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2017, we recorded:•an adjustment of $124.7 million of the previously recorded $380.2 million estimated goodwill impairment charge recorded during the threemonths ended March 31, 2016 (see Note 6 to our consolidated financial statements included in this Annual Report);•a write-off of $5.2 million related to the value of an indefinite-lived trade name intangible asset in conjunction with finalizing our goodwillimpairment analysis (see Note 7 to our consolidated financial statements included in this Annual Report);•a loss of $22.7 million related to the termination of the development agreement, which included the carrying value of the developmentagreement asset that was written off (see Note 16 to our consolidated financial statements included in this Annual Report);•an impairment charge of $1.7 million to write down a loan receivable in June 2016 (see Note 14 to our consolidated financial statementsincluded in this Annual Report); and•a loss of $9.5 million on the sales of certain assets, including the sale of Grassland (see Note 4 to our consolidated financial statements includedin this Annual Report for a discussion of the sale of Grassland).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 unfavorableimpact on our Water Solutions business (see Note 6 to our consolidated financial statements included in this Annual Report); and•a loss of $1.5 million on the sales of certain other assets.Revaluation of Liabilities. The revaluation of liabilities represents the change in the valuation of our contingent consideration liabilities related toroyalty agreements acquired as part of certain business combinations during the years ended March 31, 2017 and 2016. The increase in the expense in thecurrent year was due primarily to the reduction in the liability recorded in the prior year due to lower anticipated production and development activity due tolower commodity prices.68Table of ContentsLiquidsThe following table summarizes the operating results of our Liquids segment for the periods indicated: Year Ended March 31, 2017 2016 Change (in thousands, except per gallon amounts)Propane sales: Revenues (1) $807,172 $618,919 $188,253Cost of sales 770,238 571,734 198,504Product margin 36,934 47,185 (10,251) Butane sales: Revenues (1) 391,265 317,994 73,271Cost of sales 361,995 265,218 96,777Product margin 29,270 52,776 (23,506) Other product sales: Revenues (1) 308,031 302,181 5,850Cost of sales 289,018 266,918 22,100Product margin 19,013 35,263 (16,250) Other revenues: Revenues (1) 32,648 35,943 (3,295)Cost of sales 12,893 13,806 (913)Product margin 19,755 22,137 (2,382) Expenses: Operating expenses 37,634 45,140 (7,506)General and administrative expenses 4,831 8,806 (3,975)Depreciation and amortization expense 19,163 15,642 3,521Loss on disposal or impairment of assets, net 92 11,600 (11,508)Total expenses 61,720 81,188 (19,468)Segment operating income $43,252 $76,173 $(32,921) Storage capacity leased and owned (gallons) (2) 358,537 292,110 66,427 Propane sold (gallons) 1,267,076 1,244,529 22,547Propane sold ($/gallon) $0.637 $0.497 $0.140Cost per propane sold ($/gallon) $0.608 $0.459 $0.149Propane product margin ($/gallon) $0.029 $0.038 $(0.009)Propane inventory (gallons) (2) 48,351 56,584 (8,233)Propane storage capacity sub-leased to third parties - leased and owned (gallons) (2) 33,495 33,264 231 Butane sold (gallons) 456,586 483,206 (26,620)Butane sold ($/gallon) $0.857 $0.658 $0.199Cost per butane sold ($/gallon) $0.793 $0.549 $0.244Butane product margin ($/gallon) $0.064 $0.109 $(0.045)Butane inventory (gallons) (2) 9,438 14,629 (5,191)Butane storage capacity sub-leased to third parties - leased and owned (gallons) (2) 80,346 72,450 7,896 Other products sold (gallons) 343,365 360,716 (17,351)Other products sold ($/gallon) $0.897 $0.838 $0.059Cost per other products sold ($/gallon) $0.842 $0.740 $0.102Other products product margin ($/gallon) $0.055 $0.098 $(0.043)Other products inventory (gallons) (2) 6,426 6,297 12969Table of Contents (1)Revenues include $100.0 million and $80.6 million of intersegment sales during the years ended March 31, 2017 and 2016, respectively, that are eliminated in our consolidatedstatements of operations.(2)Information is presented as of March 31, 2017 or March 31, 2016.Propane Sales. The increase in revenues was due to higher commodity prices, partially offset by warmer winter temperatures, as compared to theprior year, experienced by certain regions in which we operate.Our cost of wholesale propane sales was reduced by $1.5 million and $2.1 million, respectively, of net unrealized gains on derivatives for the yearsended March 31, 2017 and 2016. Additionally, our cost of wholesale propane sales was reduced by $1.1 million of net realized gains on derivatives andincreased by $3.4 million of net realized losses on derivatives for the years ended March 31, 2017 and 2016, respectively.Product margins per gallon of propane sold were lower during the year ended March 31, 2017 than during the year ended March 31, 2016. Propaneprices declined significantly during February and March of 2017. Declining propane prices typically have an adverse effect on our margins as we were unableto fully recoup fixed storage fees and railcar lease costs.Butane Sales. The increase in revenues and cost of sales was primarily a function of higher commodity prices.Our cost of butane sales during the year ended March 31, 2017 was increased by $2.0 million of net unrealized losses on derivatives, as compared toa reduction of $1.9 million of net unrealized gains on derivatives during the year ended March 31, 2016. Additionally, our cost of butane sales was increasedby $5.9 million of net realized losses on derivatives and reduced by $2.2 million of net realized gains on derivatives for the years ended March 31, 2017 and2016, respectively.Product margins per gallon of butane sold were lower during the year ended March 31, 2017 than during the year ended March 31, 2016 primarilydue to underutilization of our leased railcar fleet.Other Products Sales. The decrease in revenues was primarily due to lower volumes as a result of decreases in production related to a customer’scontract.Our cost of sales of other products during the year ended March 31, 2017 was reduced by $0.2 million of net unrealized gains on derivatives, ascompared to less than $0.1 million of net unrealized losses on derivatives during the year ended March 31, 2016. Additionally, our cost of other products wasreduced by $1.3 million of net realized gains on derivatives and increased by $0.4 million of net realized losses on derivatives for the years ended March 31,2017 and 2016, respectively.Product margins during the year ended March 31, 2017 decreased primarily due to a decline in the margin on sales of asphalt, as commodity priceswhich correlate with crude oil prices have declined.Other Revenues. This revenue includes storage, terminaling and transportation services income. Other revenues decreased due to the increasedavailability of transportation services and storage capacity in the market. While railcars costs have held steady, the value we are able to realize for the railcarin the market has dropped significantly year over year, resulting in lower revenues and volumes, however costs have remained consistent.Operating and General and Administrative Expenses. The decrease was due primarily to a reduction in overall compensation expenses due to lowerincentive compensation and commission expense as well as continued cost management monitoring which focuses on expense reductions.Depreciation and Amortization Expense. The increase was due to expansion of existing terminals and acquisition of two new terminals.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.70Table of ContentsRetail PropaneThe following table summarizes the operating results of our Retail Propane segment for the periods indicated: Year Ended March 31, 2017 2016 Change (in thousands, except per gallon amounts)Propane sales: Revenues (1) $308,919 $248,673 $60,246Cost of sales 132,818 95,191 37,627Product margin 176,101 153,482 22,619 Distillate sales: Revenues (1) 64,249 64,868 (619)Cost of sales 46,503 48,191 (1,688)Product margin 17,746 16,677 1,069 Other revenues: Revenues (1) 40,038 39,436 602Cost of sales 12,268 13,375 (1,107)Product margin 27,770 26,061 1,709 Expenses: Operating expenses 118,922 104,287 14,635General and administrative expenses 10,761 11,982 (1,221)Depreciation and amortization expense 42,966 35,992 6,974Gain on disposal or impairment of assets, net (287) (137) (150)Total expenses 172,362 152,124 20,238Segment operating income$49,255 $44,096 $5,159 Propane sold (gallons) 177,599 152,238 25,361Propane sold ($/gallon) $1.739 $1.633 $0.106Cost per propane sold ($/gallon) $0.748 $0.625 $0.123Propane product margin ($/gallon) $0.991 $1.008 $(0.017)Propane inventory (gallons) (2) 8,180 7,314 866 Distillates sold (gallons) 30,001 30,674 (673)Distillates sold ($/gallon) $2.142 $2.115 $0.027Cost per distillates sold ($/gallon) $1.550 $1.571 $(0.021)Distillates product margin ($/gallon) $0.592 $0.544 $0.048Distillates inventory (gallons) (2) 1,148 1,223 (75) (1)Revenues include $0.1 million of intersegment sales during the year ended March 31, 2017 that are eliminated in our consolidated statement of operations.(2)Information is presented as of March 31, 2017 or March 31, 2016.Revenues. The increase in propane revenues was primarily due to the four acquisitions in fiscal year 2017, partially offset by warmer wintertemperatures, as compared to the prior year, experienced by certain regions in which we operate.Cost of Sales. The increase in propane cost of sales was due to the acquisitions in fiscal year 2017 as well as an increase in commodity prices. Thedecrease in distillates cost of sales was due to lower commodity prices in the first and second quarter of fiscal year 2017.Operating and General and Administrative Expenses. The increase was due primarily to increased expenses associated with acquisitions of retailpropane businesses.71Table of ContentsDepreciation and Amortization Expense. The increase was due primarily to acquisitions of retail propane businesses.Refined Products and Renewables The following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated. As previouslyreported, 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. Also, on April 1, 2016, we sold all of the TLP common units we owned. Year Ended March 31, 2017 2016 Change (in thousands, except per barrel amounts)Refined products sales: Revenues (1) $8,884,976 $6,294,008 $2,590,968Cost of sales 8,775,670 6,161,243 2,614,427Product margin 109,306 132,765 (23,459) Renewables sales: Revenues 447,232 390,753 56,479Cost of sales 444,520 380,212 64,308Product margin 2,712 10,541 (7,829) Service fee revenues 10,963 108,221 (97,258) Expenses: Operating expenses 23,177 95,371 (72,194)General and administrative expenses 9,821 15,675 (5,854)Depreciation and amortization expense 1,562 40,861 (39,299)Gain on disposal or impairment of assets, net (134,125) (127,331) (6,794)Total (income) expense, net (99,565) 24,576 (124,141)Segment operating income $222,546 $226,951 $(4,405) Gasoline sold (barrels) 91,004 58,650 32,354Diesel sold (barrels) 49,817 40,338 9,479Ethanol sold (barrels) 4,605 4,199 406Biodiesel sold (barrels) 2,413 1,595 818Storage capacity - leased (barrels) (2) 9,419 7,188 2,231Storage capacity sub-leased to third parties (barrels) (2) 1,043 713 330Gasoline inventory (barrels) (2) 2,993 1,602 1,391Diesel inventory (barrels) (2) 1,464 2,059 (595)Ethanol inventory (barrels) (2) 727 766 (39)Biodiesel inventory (barrels) (2) 471 350 121Refined products sold ($/barrel) $63.094 $63.584 $(0.490)Cost per refined products sold ($/barrel) $62.318 $62.242 $0.076Refined products product margin ($/barrel) $0.776 $1.342 $(0.566)Renewable products sold ($/barrel) $63.726 $67.441 $(3.715)Cost per renewable products sold ($/barrel) $63.340 $65.622 $(2.282)Renewable products product margin ($/barrel) $0.386 $1.819 $(1.433) (1)Revenues include $0.5 million and $0.9 million of intersegment sales during the years ended March 31, 2017, and 2016, respectively, that are eliminated in our consolidatedstatements of operations.(2)Information is presented as of March 31, 2017 or March 31, 2016.72Table of ContentsRefined Products Sales and Cost of Sales. The increases in revenues and cost of sales were due primarily to increased volumes from additionalpipeline capacity rights purchased during the years ended March 31, 2017 and 2016, an expansion of our refined products operations, and the continueddemand for motor fuels in the current low gasoline price environment. These increases were partially offset by a decrease in refined products sale pricesduring the year ended March 31, 2017 as well as storage fees paid to TLP no longer being eliminated as TLP was deconsolidated on February 1, 2016.Renewables Sales and Cost of Sales. The increases in revenues and cost of sales were due primarily to increased volumes from being able toliquidate storage volumes as the renewables markets shifted from being in contango (a condition in which forward renewables prices are greater than spotprices) to being backwardated (a condition in which forward renewables prices are lower than spot prices) during the year ended March 31, 2017. Theseincreases were partially offset by a decrease in renewables sale prices and a decrease in the cost of renewables purchased during the year ended March 31,2017. Margins for biodiesel are impacted by a biodiesel tax credit. When the tax credit is passed at the end of the calendar year and retroactive for the entirecalendar year, it allows for more optionality and trading in the market and allows us to enter into deals that could provide for a positive upside if that credit ispassed. Product margins were lower during the year ended March 31, 2017, compared to the year ended March 31, 2016 as a result of the biodiesel tax creditbeing in place for the entire 2016 calendar year, compared to being reinstated in December 2015 for the 2015 calendar year.Service Fee Revenues, Operating Expenses, General and Administrative Expenses, Depreciation and Amortization Expense. The decrease in each ofthese line items was due primarily to the inclusion of TLP for ten months of the year ended March 31, 2016 with no comparable activity in the current fiscalyear, as TLP was deconsolidated on February 1, 2016.Gain on Disposal or Impairment of Assets, Net. During the year ended March 31, 2017, we recorded:•a $104.1 million gain from the sale of all of the TLP units we owned (see Note 2 to our consolidated financial statements included in thisAnnual Report for a further discussion);•$30.1 million of the deferred gain from the sale of the general partner in interest in TLP in February 2016 (see Note 2 to our consolidatedfinancial statements included in this Annual Report for a further discussion); and•a loss of $0.1 million on the sales of certain assets.During the year ended March 31, 2016, we recorded:•a gain on disposal of our general partner interest in TLP of $329.9 million, of which $204.6 million was deferred and $5.0 million of thedeferred gain was recorded during the year ended March 31, 2016 (see Note 2 to our consolidated financial statements included in this AnnualReport for a further discussion);•a loss of $1.8 million related to certain property, plant and equipment that we have retired; and•a loss of $1.3 million related to the sale of certain tank bottoms.73Table of ContentsCorporate and OtherThe operating loss within “Corporate and Other” includes the following components for the periods indicated: Year Ended March 31, 2017 2016 Change (in thousands)Other revenues: Revenues $844 $462 $382Cost of sales 400 182 218Margin 444 280 164 Expenses: Operating expenses 1,192 338 854General and administrative expenses 82,723 91,966 (9,243)Depreciation and amortization expense 3,612 5,381 (1,769)Gain on disposal or impairment of assets, net (1) — (1)Total expenses 87,526 97,685 (10,159)Operating loss $(87,082) $(97,405) $10,323General and Administrative Expenses. The decrease was due primarily to lower equity-based compensation expense. We recorded expense of $7.2million for the year ended March 31, 2017, compared to $16.4 million for the year ended March 31, 2016. The year ended March 31, 2016 included theinitial grant of the performance units as well as the vesting of the first tranche. The expense associated with the service award units (exclusive of accruals ofannual bonuses paid or expected to be paid in common units) was $37.2 million during the year ended March 31, 2017, compared to $35.2 million duringthe year ended March 31, 2016. The increase was due primarily to a change in our process for the withholding of taxes on vesting which no longer requires usto revalue our unvested units each period. During the year ended March 31, 2016, the value of the unvested units was reduced due to declines in our unitprice and resulted in the reversal of previously recorded compensation expense. See Note 11 to our consolidated financial statements included in this AnnualReport for a further discussion.Equity in Earnings of Unconsolidated EntitiesThe decrease of $13.0 million during the year ended March 31, 2017 was due primarily to a decrease of $12.6 million as a result of deconsolidatingTLP on February 1, 2016 and selling all of the TLP common units we owned on April 1, 2016 (see Note 2 to our consolidated financial statements includedin this Annual Report).Revaluation of InvestmentsOn June 3, 2016, we acquired the remaining 65% ownership interest in Grassland. Prior to the completion of this transaction, we accounted for ourpreviously held 35% ownership interest in Grassland using the equity method of accounting (see Note 2 to our consolidated financial statements included inthis Annual Report). As we owned a controlling interest in Grassland, we revalued our previously held 35% ownership interest to fair value and recorded aloss of $14.9 million. As the amount paid (cash plus the fair value of our previously held ownership interest) was less than the fair value of the assets acquiredand liabilities assumed, we recorded a bargain purchase gain of $0.6 million (see Note 4 to our consolidated financial statements included in this AnnualReport).Interest ExpenseInterest expense includes interest charged on our revolving credit facilities, senior secured notes, and senior notes, as well as amortization of debtissuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations. The increase of$17.4 million during the year ended March 31, 2017 was due primarily to the issuance of the 2023 Notes (as defined herein) and 2025 Notes (as definedherein) which have higher interest rates than our revolving credit facility, partially offset by lower interest expense related to TLP’s credit facility (our interestin TLP was acquired in July 2014, and we deconsolidated TLP as of February 1, 2016) and lower interest expense as we repurchased a portion of the 2019Notes (as defined herein) and 2021 Notes (as defined herein) during the years ended March 31, 2017 and 2016.74Table of ContentsGain on Early Extinguishment of Liabilities, NetThe following table summarizes the components of gain on early extinguishment of liabilities, net for the periods indicated: Year Ended March 31, 2017 2016 (in thousands)Release of contingent consideration liabilities (1)$22,278 $—Early extinguishment of long-term debt (2)6,922 28,532Write-off deferred debt issuance costs (3)(4,473) —Gain on early extinguishment of liabilities, net$24,727 $28,532 (1)Relates primarily to the release of certain contingent consideration liabilities in conjunction with the termination of the development agreement (see Note 16 to our consolidatedfinancial statements included in this Annual Report for a further discussion).(2)Relates to gains on the early extinguishment of a portion of the 2019 Notes and 2021 Notes and certain equipment loans (see Note 8 to our consolidated financial statementsincluded in this Annual Report for a further discussion).(3)Relates to the write off of certain deferred debt issuance costs in connection with the amendment and restatement of our Credit Agreement (as defined herein) (see Note 7 toour consolidated financial statements included in this Annual Report for a further discussion).Other Income, NetThe following table summarizes the components of other income, net for the periods indicated: Year Ended March 31, 2017 2016 (in thousands)Interest income (1)$8,605 $12,004Crude oil marketing arrangement (2)(1,500) (6,726)Termination of storage sublease agreement (3)16,205 —Other (4)4,452 297Other income, net$27,762 $5,575 (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 and to loan receivables fromequity method investees (see Note 2 and Note 14, respectively, to our consolidated financial statements included in this Annual Report for a further discussion). On June 3,2016, we acquired the remaining 65% ownership interest in Grassland and all interest income on that receivable has been eliminated in consolidation subsequent to that date.(2)Represents another party’s share of the profits and losses generated from a joint crude oil marketing arrangement.(3)Represents a gain from the termination of a storage sublease agreement (see Note 16 to our consolidated financial statements included in this Annual Report for a furtherdiscussion).(4)During the year ended March 31, 2017, this relates primarily to a distribution from TLP pursuant to the agreement to sell all of the TLP common units we owned in April2016, a gain on insurance settlement related to business interruption insurance coverage on a facility in our Water Solutions segment and a payment received related to acontract termination.Income Tax Expense (Benefit)Income tax expense was $1.9 million during the year ended March 31, 2017, compared to an income tax benefit of $0.4 million during the yearended March 31, 2016. Income tax benefit during the year ended March 31, 2016 included a benefit of $3.6 million related to a change in estimate of theincome tax obligation payable related to TransMontaigne. See Note 9 to our consolidated financial statements included in this Annual Report for a furtherdiscussion.75Table of ContentsNoncontrolling InterestsNoncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. The decrease of $5.0 millionduring the year ended March 31, 2017 was due primarily to the deconsolidation of TLP on February 1, 2016 as a result of the sale of our general partnerinterest in TLP, partially offset by adjustments related to noncontrolling interests.Segment Operating Results for the Years Ended March 31, 2016 and 2015Crude Oil LogisticsThe following table summarizes the operating results of our Crude Oil Logistics segment for the periods indicated: Year Ended March 31, 2016 2015 Change (in thousands, except 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 (1) 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 (2) $(40,745) $(35,832) $(4,913) Crude oil sold (barrels) 67,211 83,864 (16,653)Crude oil storage capacity - owned and leased (barrels) (3) 6,115 7,306 (1,191)Crude oil storage capacity sub-leased to third parties (barrels) (3) 2,000 1,300 700Crude oil inventory (barrels) (3) 2,123 2,973 (850)Crude oil sold ($/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)Revenues include $9.7 million and $29.8 million of intersegment sales during the years ended March 31, 2016 and 2015, respectively, that are eliminated in our consolidatedstatements of operations.(2)In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to executing these commitments,the producers requested to be released from the commitments. We agreed to release the producers from their commitments in return for a cash payment in March 2015 andadditional cash payments over the next five years. Upon execution of these agreements in March 2015, we recorded a gain of $31.6 million to other income, net in ourconsolidated statement of operations, net of certain project abandonment costs. Since this gain was reported in other income, net, it is not reflected in the table above.(3)Information is presented as of March 31, 2016 or March 31, 2015.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.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.76Table of ContentsCost of Sales. Our cost of sales during the year ended March 31, 2016 was reduced by $13.8 million of net realized gains on derivatives andincreased by $2.1 million of net unrealized losses on derivatives. Our cost of sales during the year ended March 31, 2015 was reduced by $37.4 million of netrealized gains on derivatives and increased by $7.4 million of net unrealized losses on derivatives. Due to the sharper decline in crude oil prices during theyear 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 during the 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.Operating and General and Administrative Expenses. The decrease was due primarily to lower compensation expense related to a reduction in thenumber of employees as a result of organizational changes, $5.6 million of compensation expense during the year ended March 31, 2015 related to bonusesthat the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business, which were paid inDecember 2014, $1.3 million of compensation expense during the year ended March 31, 2015 related to termination benefits for certain TransMontaigneemployees, and lower repair and maintenance expense due to the timing of repairs.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 loss of $50.1 million due to the write-down ofcertain assets, a loss of $3.1 million due to the cancellation of two previously-planned projects and a loss of $1.8 million on the sales of certain other assets.During the year ended March 31, 2015, we recorded a write-off of project costs of $3.5 million related to a crude oil terminal project that has beendiscontinued. Also, during the year ended March 31, 2015, we recorded a loss of $0.3 million on the sales of certain other assets.77Table of ContentsWater 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 and per day 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 (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 $(379,013) Water processed (barrels per day) Eagle Ford Basin 236,792 210,283 26,509Permian Basin 179,413 109,154 70,259DJ Basin 107,353 94,045 13,308Other Basins 45,949 29,433 16,516Total 569,507 442,915 126,592Solids processed (barrels per day) (1) 3,149 2,740 409Skim oil sold (barrels per day) 2,935 3,170 (235)Service fee for water processed ($/barrel) $0.66 $0.65 $0.01Recovered hydrocarbons for water processed ($/barrel) $0.20 $0.51 $(0.31)Operating expenses for water processed ($/barrel) $0.54 $0.58 $(0.04) (1)Our solids disposal business began in January 2015.Service Fee Revenues. The increase was due primarily to an increase in the service fees in a certain basin and a favorable deliver or pay agreementwith a customer where the customer has not been delivering water to our facilities as well as an increase in the volume processed primarily from acquisitions.Recovered Hydrocarbon Revenues. The decrease was due primarily to the sharp decline in crude oil prices since July 2014 and a decrease in thevolume of hydrocarbons recovered per barrel of wastewater 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-Derivatives. We enter into derivatives in our Water Solutions segment to protect against the risk of a decline in the market price of thehydrocarbons we expect to recover when processing the wastewater. Our cost of sales during the year ended March 31, 2016 included $10.3 million of netrealized gains on derivatives and $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 on78Table of Contentsderivatives and $34.0 million of net realized gains on derivatives. In December 2015, we settled derivative contracts that had scheduled settlement dates fromJanuary 2016 through December 2016, in order to lock in the gains on those derivatives. In December 2014, we settled derivative contracts that hadscheduled settlement dates from April 2015 through September 2015, in order to lock in the gains on those derivatives.Cost of Sales-Other. The decrease was due to costs related to our water transportation business during the year ended March 31, 2015. We sold thisbusiness during September 2014.Operating Expenses. The increase was due primarily to an increase in the volume processed primarily from acquisitions and the higher operatingcosts of water disposal.Depreciation and Amortization Expense. The increase was due primarily to acquisitions and developed 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 unfavorableimpact on our Water Solutions business (see Note 6 to our consolidated financial statements included in this Annual Report); and•a loss of $1.5 million on the sales of certain other assets.During the year ended March 31, 2015, we recorded:•a loss of $4.0 million related to the sale of our water transportation business;•a loss on abandonment of $3.1 million related to property, plant and equipment of water disposal facilities that we have retired; and•a loss of $0.4 million on the sales of certain other assets.Revaluation of Liabilities. The revaluation of liabilities represents the change in the valuation of our contingent consideration liabilities related toroyalty agreements acquired as part of certain business combinations. The increase was due to additional acquisitions during the year ended March 31, 2016offset by changes in the fair value of the liability.79Table of ContentsLiquidsThe following table summarizes the operating results of our Liquids segment for the periods indicated: Year Ended March 31, 2016 2015 Change (in thousands, except per gallon amounts)Propane sales: Revenues (1) $618,919 $1,265,262 $(646,343)Cost of sales 571,734 1,217,993 (646,259)Product margin 47,185 47,269 (84) Butane sales: Revenues (1) 317,994 531,548 (213,554)Cost of sales 265,218 474,402 (209,184)Product margin 52,776 57,146 (4,370) Other product sales: Revenues (1) 302,181 580,286 (278,105)Cost of sales 266,918 563,922 (297,004)Product margin 35,263 16,364 18,899 Other revenues: Revenues (1) 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 $31,101 Storage capacity leased and owned (gallons) (2) 292,110 176,630 115,480 Propane sold (gallons) 1,244,529 1,285,707 (41,178)Propane sold ($/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 $0.001Propane inventory (gallons) (2) 56,584 63,095 (6,511)Propane storage capacity sub-leased to third parties - leased and owned (gallons) (2) 33,264 31,500 1,764 Butane sold (gallons) 483,206 430,775 52,431Butane sold ($/gallon) $0.658 $1.234 $(0.576)Cost per butane sold ($/gallon) $0.549 $1.101 $(0.552)Butane product margin ($/gallon) $0.109 $0.133 $(0.024)Butane inventory (gallons) (2) 14,629 10,483 4,146Butane storage capacity sub-leased to third parties - leased and owned (gallons) (2) 72,450 72,450 — Other products sold (gallons) 360,716 394,740 (34,024)Other products sold ($/gallon) $0.838 $1.470 $(0.632)Cost per other products sold ($/gallon) $0.740 $1.429 $(0.689)Other products product margin ($/gallon) $0.098 $0.041 $0.057Other products inventory (gallons) (2) 6,297 8,114 (1,817) (1)Revenues include $80.6 million and $162.0 million of intersegment sales during the years ended March 31, 2016 and 2015, respectively, that are eliminated in our consolidatedstatements of operations.80Table of Contents(2)Information is presented as of March 31, 2016 or March 31, 2015.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.Our 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 $3.4 million 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.Butane Sales. The decrease in revenues and cost of sales was primarily a function of lower commodity prices.Our cost of butane sales was reduced by $1.9 million and $1.7 million of net unrealized gains on derivatives for the years ended March 31, 2016 and2015, respectively. Additionally, our cost of butane sales was reduced by $2.2 million of net realized gains on derivatives and increased by $6.1 million ofnet realized losses on derivatives for the years ended March 31, 2016 and 2015, respectively.Product margins per gallon of butane sold were lower during the year ended March 31, 2016 than during the year ended March 31, 2015 primarilydue to underutilization of our leased railcar fleet.Other Products Sales. The decrease in the volume of other wholesale products sold was due to decreases in production related to a customer’scontract.Our cost of sales of other products had less than $0.1 million of unrealized losses on derivatives during the years ended March 31, 2016 and 2015.Additionally, our cost of sales of other products was increased by $0.4 million of net realized losses on derivatives and reduced by $0.7 million of netrealized gains on derivatives for the years ended March 31, 2016 and 2015, respectively.Other Revenues. The increase was due primarily to $21.1 million of revenue related to Sawtooth, which we acquired in February 2015, partiallyoffset by a $10.0 million decrease in hauling revenues due to declining market conditions.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 2014.81Table of ContentsLoss 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.Retail 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 product sales: 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 $0.028Propane inventory (gallons) (1) 7,314 6,071 1,243 Distillates sold (gallons) 30,674 34,862 (4,188)Distillates sold ($/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)Distillates inventory (gallons) (1) 1,223 1,160 63 (1)Information is presented as of March 31, 2016 or March 31, 2015.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 an82Table of Contentsoversupply in the propane market lowering commodity prices as well 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.83Table of ContentsRefined Products and RenewablesThe following table summarizes the operating results of our Refined Products and Renewables segment for the periods indicated. Our RefinedProducts and Renewables segment was significantly expanded with our July 2014 acquisition of TransMontaigne. On February 1, 2016, we sold our generalpartner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using theequity method of accounting. Year Ended March 31, 2016 2015 Change (in thousands, except per barrel amounts)Refined products sales: Revenues (1) $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 $172,384 Gasoline and diesel sold (barrels) 98,988 68,043 30,945Ethanol and biodiesel sold (barrels) 5,794 5,318 476Storage capacity - leased (barrels) (2) 7,188 30,685 (23,497)Storage capacity sub-leased to third parties (barrels) (2) 713 461 252Gasoline inventory (barrels) (2) 1,602 2,073 (471)Diesel inventory (barrels) (2) 2,059 777 1,282Ethanol inventory (barrels) (2) 766 590 176Biodiesel inventory (barrels) (2) 350 145 205Refined products sold ($/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 $(0.238)Renewable products sold ($/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) (1)Revenues include $0.9 million and $1.1 million of intersegment sales during the years ended March 31, 2016 and 2015, respectively, that are eliminated in our consolidatedstatements of operations.(2)Information is presented as of March 31, 2016 or March 31, 2015.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 renewables84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 year ended March 31, 2016, compared to ninemonths of the year ended March 31, 2015 as TLP was deconsolidated on February 1, 2016. Also contributing to the increase was the inclusion ofTransMontaigne for the entire year ended March 31, 2016, compared to nine months of the year ended March 31, 2015.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 year ended March 31, 2016, compared to nine months of the year ended March 31, 2015.Depreciation and Amortization Expense. The increase was due primarily to the inclusion of TLP for ten months of the year ended March 31, 2016,compared to nine months of the year ended March 31, 2015 as TLP was deconsolidated on February 1, 2016.Gain on Disposal or Impairment of Assets, Net. During the year ended March 31, 2016, we recorded:•a gain on disposal of our general partner interest in TLP of $329.9 million, of which $204.6 million was deferred and $5.0 million of thedeferred gain was recorded during the year ended March 31, 2016 (see Note 2 to our consolidated financial statements included in this AnnualReport for a further discussion);•a loss of $1.8 million related to certain property, plant and equipment that we have retired; and•a loss of $1.3 million related to the sale of certain tank bottoms.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)Other revenues: Revenues $462 $1,916 $(1,454)Cost of sales 182 2,583 (2,401)Margin 280 (667) 947 Expenses: Operating expenses 338 (2,174) 2,512General and administrative expenses 91,966 84,028 7,938Depreciation and amortization expense 5,381 3,417 1,964Gain on disposal or impairment of assets, net — (136) 136Total expenses 97,685 85,135 12,550Operating loss $(97,405) $(85,802) $(11,603)General and Administrative Expenses. The increase is primarily attributable to an increase in incentive compensation. As part of its review of ourexecutive compensation program, the Compensation Committee of the Board of Directors approved a new type of equity-based compensation award, underwhich the number of common units that vest is contingent upon the performance of our common units relative to the performance of other entities in theAlerian MLP Index. During the year ended March 31, 2016, three tranches of these Performance Awards were granted, with vesting dates of July 1, 2015, July1, 2016, and July 1, 2017, respectively. We recorded $16.4 million of expense related to the Performance Awards during 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 the85Table of Contentsaddition of new employees as our business has expanded, and was due in part to increases in the number of Service Awards granted to certain employeesfollowing the Compensation Committee’s review of our compensation program. The expense associated with these Service Awards (exclusive of accruals ofannual bonuses paid or expected to be paid in common units) was $35.2 million during the year ended March 31, 2016, compared to $32.8 million duringthe 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. We record compensation expense related to common unitswithin “Corporate and Other”, while compensation expense paid in cash is recorded within the individual business segments.Equity in Earnings of Unconsolidated EntitiesThe increase of $4.0 million during the year ended March 31, 2016 was due primarily to an increase of $7.1 million of earnings from TLP that weacquired as part of our July 2014 acquisition of TransMontaigne. On February 1, 2016, we deconsolidated TLP when we sold our general partner interest inTLP (see Note 2 to our consolidated financial statements included in this Annual Report). Partially offsetting this increase was a decrease of $2.4 million inearnings from certain other investments in unconsolidated entities.Interest ExpenseThe increase of $23.0 million was due primarily to the increased level of debt outstanding on our Revolving Credit Facility (as defined herein) (theaverage balance outstanding on our Revolving Credit Facility was $1.7 billion during the year ended March 31, 2016, compared to $1.2 billion during theyear ended March 31, 2015), primarily to finance acquisitions and capital expenditures, the issuance of the 2019 Notes (as defined herein), and increasedinterest expense related to TLP’s credit facility (our interest in TLP was acquired in July 2014 and we sold our general partner interest in TLP as of February1, 2016).Gain on Early Extinguishment of Liabilities, NetDuring the fourth quarter of fiscal year 2016, we repurchased a portion of the 2019 Notes (as defined herein) and 2021 Notes (as defined herein) andrecorded a gain on the early extinguishment of these notes of $28.5 million (see Note 8 to our consolidated financial statements included in this AnnualReport for a further discussion).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 and to a loan receivablefrom an equity method investee (see Note 2 and Note 14, respectively, to our consolidated financial statements included in this Annual Report for a further discussion).(2)Represents another party’s share of the profits and losses generated from a joint crude oil marketing arrangement.(3)Represents a gain from the release of certain producer commitments related to a crude oil transloading facility (see Note 16 to our consolidated financial statements included inthis Annual Report for a further discussion).(4)Amount during the year ended March 31, 2015 primarily relates to other income for the settlement of two separate contractual disputes, partially offset by other expense relatedto an offer to settle another contractual dispute (see Note 10 to our consolidated financial statements included in this Annual Report for a further discussion).86Table of ContentsIncome Tax Expense (Benefit)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 included 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. See Note 9 toour consolidated financial statements included in this Annual Report for a further discussion.Noncontrolling InterestsThe decrease of $1.1 million during the year ended March 31, 2016 was due primarily to adjustments related to noncontrolling interests, partiallyoffset by an increase in noncontrolling interest related to TLP prior to the deconsolidation of TLP on February 1, 2016 as a result of the sale of our generalpartner interest in TLP.Liquidity, Sources of Capital and Capital Resource ActivitiesOur principal sources of liquidity and capital are the cash flows from our operations, borrowings under our Revolving Credit Facility and accessingcapital markets. See Note 8 to our consolidated financial statements included in this Annual Report for a detailed description of our long-term debt. Our cashflows from operations are discussed below.Our borrowing needs vary during the year due in part to the seasonal nature of our Liquids, Retail Propane and Refined Products & Renewablesbusinesses. Our greatest working capital borrowing needs generally occur during the period of June through December, when we are building our natural gasliquids inventories in anticipation of the heating season as well as building our gasoline inventories in anticipation of the winter gasoline contango andblending season. Our working capital borrowing needs generally decline during the period of January through March, when the cash flows from our RetailPropane and Liquids segments are the greatest and gasolines inventories need to be minimized due to certain inventory requirements.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.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 Glass Mountain Pipeline, LLC (“Glass Mountain”) extension, among others. We expect to be able to finance theseprojects through available capacity on our Revolving Credit Facility, asset sales or other forms of financing.Other sources of liquidity during the year ended March 31, 2017 are discussed below.Sale of TLP Common UnitsOn April 1, 2016, we sold all of the TLP common units we owned to an affiliate of ArcLight Capital Partners for approximately $112.4 million incash and recorded a gain on disposal of $104.1 million during the year ended March 31, 2017. See Note 2 to our consolidated financial statements includedin this Annual Report for a further discussion.87Table of ContentsClass A Convertible Preferred UnitsDuring the year ended March 31, 2017, we issued $240 million of 10.75% Class A Convertible Preferred Units (“Preferred Units”) to Oaktree CapitalManagement L.P. and its co-investors. See Note 11 to our consolidated financial statements included in this Annual Report for a further description of thePreferred Units.At-The-Market ProgramOn August 24, 2016, we entered into an equity distribution agreement in connection with an at-the-market program (the “ATM Program”) pursuantto which we may issue and sell common units for up to $200.0 million in gross proceeds. We are under no obligation to issue equity under the ATM Program.During the year ended March 31, 2017, we sold 3,321,135 common units for net proceeds of $64.4 million (net of offering costs of $0.9 million). We used thenet proceeds from the sales under the ATM Program to repay outstanding indebtedness.Senior Note OfferingsSee below under “Long-Term Debt” and Note 8 to our consolidated financial statements included in this Annual Report for a further description ofthese note offerings. Net proceeds were used to reduce the outstanding balance on our Revolving Credit Facility (as defined herein).Equity IssuanceOn February 22, 2017, we issued 10,120,000 common units representing limited partner interests. We received net proceeds of $222.5 million,which were used to reduce the outstanding balance on our Revolving Credit Facility (as defined herein). See Note 11 to our consolidated financial statementsincluded in this Annual Report for a further description of this equity issuance.Long-Term DebtCredit AgreementIn February 2017, we amended and restated our credit agreement (the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includesa revolving 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, 2017, ourRevolving Credit Facility had a total capacity of $1.765 billion. Our Revolving Credit Facility includes an “accordion” feature that allows us to increase thecapacity by $300 million if new lenders wish to join the syndicate or if current lenders wish to increase their commitments and also allows us to reallocateamounts between the Expansion Capital Facility and Working Capital Facility. The commitments under the Credit Agreement expire on October 5, 2021.At March 31, 2017, we were in compliance with the covenants under the Credit Agreement.Senior Secured NotesOn June 19, 2012, we entered into the Senior Secured Notes Purchase Agreement whereby we issued $250.0 million of Senior Secured Notes in aprivate placement (the “Senior Secured Notes”). The Senior Secured Notes bear interest at a fixed rate of 6.65% which is payable quarterly. The SeniorSecured Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date ofJune 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. In March 2017, we amended and restatedour Senior Secured Notes Purchase Agreement with an effective date of December 31, 2016, which conforms to the amended terms of the Credit Agreement.At March 31, 2017, we were in compliance with the covenants under the Senior Secured Notes Purchase Agreement.Senior Unsecured NotesThe Senior Notes include, as defined below, the 2019 Notes, 2021 Notes, 2023 Notes, and the 2025 Notes (collectively, the “Senior Notes”).88Table of ContentsIssuancesOn October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”). The 2021 Notes mature on October 15, 2021.Interest is payable on April 15 and October 15 of each year.On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”). The 2019 Notes mature on July 15, 2019. Interestis payable on January 15 and July 15 of each year.On October 24, 2016, we issued $700.0 million of Senior Notes (the “2023 Notes”) in a private placement. The 2023 Notes bear interest at 7.50%,which is payable on May 1 and November 1 of each year, beginning on May 1, 2017. The 2023 Notes mature on November 1, 2023.On February 22, 2017, we issued $500.0 million of Senior Notes (the “2025 Notes”) in a private placement. The 2025 Notes bear interest at 6.125%,which is payable on March 1 and September 1 of each year, beginning on September 1, 2017. The 2025 Notes mature on March 1, 2025.RepurchasesDuring the year ended March 31, 2017, we repurchased $9.0 million of the 2019 Notes and $21.2 million of the 2021 Notes. See Note 8 to ourconsolidated financial statements included in this Annual Report for a further discussion of the repurchases and a detail of repurchases made in fiscal year2016).ComplianceAt March 31, 2017, we were in compliance with the covenants under all of the Senior Note indentures.For a further discussion of our Revolving Credit Facility, Senior Secured Notes and Senior Notes, see Note 8 to our consolidated financial statementsincluded in this Annual Report.Revolving Credit BalancesThe following table summarizes our Revolving Credit Facility borrowings for the periods indicated: Average BalanceOutstanding LowestBalance HighestBalance (in thousands)Year Ended March 31, 2017 Expansion capital borrowings $970,678 $— $1,359,000Working capital borrowings $686,456 $465,500 $875,500Year Ended March 31, 2016 Expansion capital borrowings $1,067,549 $739,500 $1,380,000Working capital borrowings $640,928 $469,000 $756,000Capital 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 and intangible assets acquired in acquisitions. Capital ExpendituresYear Ended March 31, Expansion (1) Maintenance (2) Total (in thousands)2017 $334,383 $26,073 $360,4562016 $613,792 $42,001 $655,7932015 $169,207 $40,746 $209,95389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 to spend approximately $150 million to $200 million on growth capital expenditures during fiscal year 2018.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): 2017 2016 2015 (in thousands)Operating activities, before changes in operating assets and liabilities $258,573 $221,074 $106,898Changes in operating assets and liabilities (285,397) 130,421 155,493Operating activities $(26,824) $351,495 $262,391Investing activities $(363,126) $(445,327) $(1,366,221)Financing activities $374,038 $80,705 $1,134,693Operating 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 ourLiquids and Retail Propane businesses, we typically experience operating losses or lower operating income during our first and second quarters, or the sixmonths ending September 30, as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcomingheating season. The heating season runs through the six months ending March 31. The seasonal motor fuel blending impacts the value of our gasolineinventory in our Refined Products and Renewables business and also represents a period when we build inventory into our system. We borrow under ourRevolving Credit Facility to supplement our operating cash flows during the periods in which we are building inventory. Our operations, and as a result ourcash flows, are also impacted by positive and negative movements in commodity prices, which cause fluctuations in the value of inventory, accountsreceivable and payables, due to increases and decrease in revenues and cost of sales. The increase in net cash used in operating activities during the yearended March 31, 2017 was primarily a result of the increase in inventory balances in our Refined Products and Renewables segment. This increase was aresult of expanding our operations through the purchase of additional pipeline capacity rights at the beginning of the year and higher commodity prices. Theincrease in cash provided by operating activities during the year ended March 31, 2016 was due primarily to the acquisition of TLP in July 2014.Investing Activities. Net cash used in investing activities was $363.1 million during the year ended March 31, 2017, compared to $445.3 millionduring the year ended March 31, 2016. The decrease in net cash used in investing activities was due primarily to:•a decrease in capital expenditures from $536.9 million during the year ended March 31, 2016 to $363.9 million during the year endedMarch 31, 2017;•$125.0 million related to the purchase of a 37.5% undivided interest in Grand Mesa Pipeline during the year ended March 31, 2016;•$112.4 million in proceeds received from the sale of the TLP common units we owned during the year ended March 31, 2017;•a $111.8 million decrease in cash paid for acquisitions during the year ended March 31, 2017;•$22.0 million in proceeds received from the sale of Grassland during the year ended March 31, 2017; and•a $15.6 million decrease for a loan to Grassland during the year ended March 31, 2016.90Table of ContentsThese decreases in net cash used in investing activities were partially offset by:•$343.1 million in proceeds received from the sale of the general partner interest in TLP during the year ended March 31, 2016;•a $143.1 million decrease in cash flows from derivatives; and•a $16.9 million payment to terminate the development agreement (see Note 16 to our consolidated financial statements included in this AnnualReport).Net cash used in investing activities was $445.3 million during the year ended March 31, 2016, compared to $1.4 billion during the year endedMarch 31, 2015. 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;•$343.1 million in proceeds received from the sale of the general partner interest in TLP during the year ended March 31, 2016;•$310.0 million for the purchase of the remaining equity interest in Grand Mesa Pipeline during the year ended March 31, 2015; and•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.These decreases in net cash used in investing activities were partially offset by:•an increase in capital expenditures from $228.0 million during the year ended March 31, 2015 to $536.9 million during the year endedMarch 31, 2016;•$125.0 million related to the purchase of a 37.5% undivided interest in Grand Mesa Pipeline during the year ended March 31, 2016; and•a $93.5 million decrease in cash flows from derivatives.Financing Activities. Net cash provided by financing activities was $374.0 million during the year ended March 31, 2017, compared to $80.7million during the year ended March 31, 2016. The increase in net cash provided by financing activities was due primarily to:•$1.2 billion in proceeds received from the issuance of the 2023 Notes and 2025 Notes during the year ended March 31, 2017;•$287.1 million in proceeds received from the sale of our common units during the year ended March 31, 2017;•$235.0 million in proceeds received (net of offering costs) from the sale of our Preferred Units and warrants during the year ended March 31,2017; and•a decrease of $172.9 million in distributions paid to our partners and noncontrolling interest owners during the year ended March 31, 2017.These increases in net cash provided by financing activities were partially offset by:•an $1.5 billion decrease in borrowings on our revolving credit facilities (net of repayments) during the year ended March 31, 2017;•$53.2 million in proceeds received from other long-term debt during the year ended March 31, 2016 due primarily to equipment financing; and•a $25.9 million release of contingent consideration liabilities related to the termination of the development agreement during the year endedMarch 31, 2017 (see Note 16 to our consolidated financial statements included in this Annual Report).Net cash provided by financing activities was $80.7 million during the year ended March 31, 2016, compared to $1.1 billion during the year endedMarch 31, 2015. The decrease in net cash provided by financing activities was due primarily to:91Table of Contents•$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 outstanding senior notes during the three months ended March 31, 2016.These decreases in net cash provided by financing activities were partially offset by $53.2 million in proceeds received from other long-term debtduring the year ended March 31, 2016 due primarily to equipment financing.Distributions DeclaredOur 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. See further discussion of our cash distribution policy in Item 5. Market for Registrant’s CommonEquity, Related Unitholder Matters and Issuer Purchases of Equity Securities included in this Annual Report.In April 2016, the board of directors of our general partner made the decision to reduce the common unit distribution to $1.56 per unit on anannualized basis in order to focus on strengthening the balance sheet, which included foregoing approximately $64 million of annual general partnerdistributions. We had anticipated considering an increase in distributions for the quarter ended March 31, 2017, but in light of current market conditions,particularly fluctuating commodity prices and their anticipated impact on our results, the board of directors of our general partner has chosen to defer thisincrease in distributions for up to an additional three quarters.On April 24, 2017, the board of directors of our general partner declared a distribution of $0.39 per common unit to the unitholders of record on May8, 2017. In addition, the board of directors declared a distribution to the holders of the Class A Preferred Units. The distributions were paid to both thecommon unitholders and the holders of the Class A Preferred Units on May 15, 2017. See Note 11 to our consolidated financial statements included in thisAnnual Report for a detailed description of the distributions declared and paid for the years ended March 31, 2017, 2016 and 2015.92Table of ContentsContractual ObligationsThe following table summarizes our contractual obligations at March 31, 2017 for our fiscal years ending thereafter: Years Ending March 31, Total 2018 2019 2020 2021 2022 Thereafter Principal payments on long-term debt: Expansion capital borrowings $— $— $— $— $— $— $—Working capital borrowings 814,500 — — — — 814,500 —Senior Secured Notes 250,000 25,000 50,000 50,000 50,000 50,000 25,000Senior Notes 1,946,506 — — 379,458 — 367,048 1,200,000Other long-term debt 15,525 4,590 3,036 2,207 5,395 238 59Interest payments on long-term debt: Revolving Credit Facility (1) 164,491 35,759 35,759 35,759 35,759 21,455 —Senior Secured Notes 49,875 16,209 13,300 9,975 6,650 3,325 416Senior Notes 789,077 129,593 127,807 118,083 108,360 108,360 196,874Other long-term debt 1,701 736 479 328 147 10 1Letters of credit 89,200 — — — — 89,200 —Future minimum lease payments undernoncancelable operating leases 587,232 138,434 114,524 103,186 89,051 62,213 79,824Future minimum throughput paymentsunder noncancelable agreements (2) 154,067 54,486 53,688 43,856 1,438 599 —Construction commitments (3) 30,531 30,087 444 — — — —Fixed-price commodity purchasecommitments Crude oil 165,101 165,101 — — — — —Natural gas liquids 10,824 10,824 — — — — —Index-price commodity purchasecommitments (4) —Crude oil 2,026,822 986,080 338,938 298,309 253,558 149,937 —Natural gas liquids 553,838 553,838 — — — — —Total contractual obligations $7,649,290 $2,150,737 $737,975 $1,041,161 $550,358 $1,666,885 $1,502,174 (1)The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at March 31, 2017. See Note 8 to our consolidatedfinancial 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 shipping 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. Under certain agreements we can recover these paymentsby delivering more than our allotted capacity.(3)At March 31, 2017, construction commitments relate to the Glass Mountain pipeline extension, certain crude oil terminals and an expansion of a salt dome cavern.(4)Index prices are based on a forward price curve at March 31, 2017. A theoretical change of $0.10 per gallon in the underlying commodity price at March 31, 2017 would resultin a change of $87.5 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodityprice at March 31, 2017 would result in a change of $39.3 million in the value of our index-price crude oil purchase commitments. See Note 10 to our consolidated financialstatements included in this Annual Report for further detail of the commitments.Off-Balance Sheet ArrangementsWe do not have any off balance sheet arrangements other than the operating leases discussed in Note 10 to our consolidated financial statementsincluded in this Annual Report.93Table of ContentsEnvironmental LegislationSee Part I, Item 1–“Business–Government Regulation–Greenhouse Gas Regulation” for a discussion of proposed environmental legislation andregulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure or outcome of anyfuture 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.Critical 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. Revenues for our Water Solutions segment are recognized when we obtain the wastewater at our treatment and disposal facilities.The tariffs we charge for our pipeline transportation systems are primarily regulated by the Federal Energy Regulatory Commission. Ourtariffs include provisions which allow us to deduct from our customer’s inventory a small percentage of the products our customers transport on our pipelinesystems. We refer to these product quantities as pipeline loss allowance. We receive pipeline loss allowances from our customers as consideration for productlosses during the transportation of their crude oil within our pipeline system. Our customers are guaranteed delivery of the amount of their injected volumes,net of pipeline loss allowance, irrespective of what our actual product losses may be during the delivery process.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 commodity price risk and credit risk. Commodity price risk isthe risk that the market value of crude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response tochanging market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Proceduresand limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commoditypositions and market price changes are monitored daily and are reported to senior management and to marketing94Table of Contentsoperations 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 payable balances 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 flows expected to be generated from that asset. Estimates of future net cash flows include estimating future volumes, future marginsor tariff rates, future operating costs and other estimates and assumptions consistent with our business plans. If we determine that an asset’s unamortized costmay not be recoverable due to impairment, we may be required to reduce the carrying value and the subsequent useful life of the asset. Any such write-downof the value and unfavorable change in the useful life of a long-lived asset 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 and record animpairment 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 that the fair value of the reporting unit is less than itscarrying amount, we calculate the fair value of the reporting unit. Otherwise, further testing is not required. The qualitative assessment is based on reviewingthe totality of several factors, including macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, otherentity specific events (for example, changes in management) or other events such as selling or disposing of a reporting unit. The determination of a reportingunit’s fair value is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include (i) discretefinancial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins, (ii) long-term growth ratesfor cash flows beyond the discrete forecast period, (iii) appropriate discount rates and (iv) estimates of the cash flow multiples to apply in estimating themarket value of our reporting units. If the fair value of the reporting unit (including its inherent goodwill) is less than its carrying value, a charge to earningsmay be required to reduce the carrying value of goodwill to its implied fair value. If future results are not consistent with our estimates, we could be exposedto future impairment losses that could be material to our results of operations. We monitor the markets for our products and services, in addition to the overallmarket, to determine if a triggering event occurs that would indicate that the fair value of a reporting unit is less than its carrying value. See Note 6 to ourconsolidated financial statements included in this Annual Report for a further discussion of our goodwill impairment assessment.Asset 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. We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value canbe made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projectedcash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantlyimpact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. Ourconsolidated balance sheet at March 31, 2017 includes a liability of $8.2 million related to asset retirement obligations, which is reported within othernoncurrent liabilities.In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certainother assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates areindeterminable. We will record an asset retirement obligation for these assets in the periods in which settlement dates are reasonably determinable.95Table of ContentsDepreciation and Amortization Methods and Estimated Useful Lives of Property, Plant and Equipment and Intangible AssetsDepreciation and amortization expense is the systematic write-off of the cost of our property, plant and equipment (net of residual or salvage value,if any) and the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are used. Wedepreciate our property, plant and equipment and amortize the majority of our intangible assets using the straight-line method, which results in our recordingdepreciation and amortization expense evenly over the estimated life of the individual asset. The estimate of depreciation and amortization expense requiresus to make assumptions regarding the useful economic lives and residual values of our assets. When we acquire and place our property, plant and equipmentin service or acquire intangible assets, we develop assumptions about the useful economic lives and residual values of such assets that we believe to bereasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciationand amortization expense prospectively. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of anasset, changes in technology that render an asset obsolete, changes in expected salvage values or changes in customer attrition rates.Business CombinationsWe record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Fair values of assets acquiredand liabilities assumed are based upon available information and may involve engaging an independent third party to perform an appraisal. Estimating fairvalues can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangibleassets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property,plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commoditypurchase and sale agreements, storage contracts, and transportation contracts. The excess of the purchase price over the net fair value of acquired assets andassumed liabilities is recorded as goodwill, which is not amortized but instead is evaluated for impairment at least annually. 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 fair value of the assets acquiredand liabilities assumed in a business combination.InventoriesOur inventories consist primarily of crude oil, natural gas liquids, gasoline, diesel, 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. See Note 2 for a discussion of an accounting standard we adopted beginning April 1, 2017 related to the measurement of inventory.Equity-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 upon a changeof control, at the discretion of the board of directors of our general partner.Service Awards are valued at the closing price as of the grant date less the present value of the expected distribution stream over the vesting periodusing a risk-free interest rate. We record the expense for each Service Award on a straight-line basis over the requisite period for the entire award (that is, overthe requisite service period of the last separately vesting96Table of Contentsportion of the award), ensuring that the amount of compensation cost recognized at any date at least equals the portion of the grant-date value of the awardthat is vested at that date.The fair value of the Performance Awards is estimated using a Monte Carlo simulation at the grant date. We record the expense for each of thetranches of the Performance Awards on a straight-line basis over the period beginning with the grant date and ending with the vesting date of the tranche.Any Performance Awards that do not become earned Performance Awards shall terminate, expire and otherwise be forfeited by the participants.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 our 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 31,2017, we had $814.5 million of outstanding borrowings under our Revolving Credit Facility at a weighted average interest rate of 3.72%. A change ininterest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.0 million, based on borrowings outstanding at March 31,2017.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, or refined and renewables products will change, either favorably or unfavorably, in response to changing marketconditions. Credit risk 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. At March 31, 2017, our primarycounterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.The crude oil, natural gas liquids, and refined and renewables products industries are “margin-based” and “cost-plus” businesses in which grossprofits depend on the differential of sales prices over supply costs. We have no control over market conditions. As a result, our profitability may be impactedby sudden and significant changes in the price of crude oil, natural gas liquids, and refined and renewables products.We engage in various types of forward contracts and financial derivative transactions to reduce the effect of price volatility on our product costs, toprotect the value of our inventory positions, and to help ensure the availability of product during periods of short supply. We attempt to balance ourcontractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. We may experiencenet unbalanced positions from time to time. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, onan ongoing basis, to track and report the market value of our derivative portfolio.97Table of ContentsAlthough 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 in ourconsolidated statements of operations. The following table summarizes the hypothetical impact on the March 31, 2017 fair value of our commodityderivatives of an increase of 10% in the value of the underlying commodity (in thousands): Increase(Decrease)To Fair ValueCrude oil (Crude Oil Logistics segment)$(4,053)Propane (Liquids segment)$555Other products (Liquids segment)$(173)Gasoline (Refined Products and Renewables segment)$(13,837)Diesel (Refined Products and Renewables segment)$(1,227)Ethanol (Refined Products and Renewables segment)$(4,151)Biodiesel (Refined Products and Renewables segment)$586Canadian dollars (Liquids segment)$775Fair 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 at March 31, 2017.Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31, 2017, suchdisclosure controls and procedures were effective to provide the reasonable assurance described above.Management’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.98Table of ContentsBased on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective asof March 31, 2017.Our internal control over financial reporting as of March 31, 2017 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 ReportingOther than changes that have resulted or may result from our business combinations during the year ended March 31, 2017, as discussed below, therehave been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) of the Exchange Act) during the three months endedMarch 31, 2017 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.We closed several business combinations during the year ended March 31, 2017, as described in Note 4 to our consolidated financial statementsincluded in this Annual Report. At this time, we continue to evaluate the business and internal controls and processes of these acquired businesses and aremaking various changes to their operating and organizational structure based on our business plan. We are in the process of implementing our internalcontrol structure over these acquired businesses. We expect that our evaluation and integration efforts related to those combined operations will continueinto future fiscal quarters.Item 9B. Other InformationNone.99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. JamesC. Kneale, Mr. Stephen L. Cropper, and Mr. James M. Collingsworth satisfy the New York Stock Exchange (“NYSE”) and SEC independence requirements.The NYSE does not require a listed publicly traded limited partnership like us to have a majority of independent directors on the board of directors of ourgeneral partner. In addition, we are not required to have a nominating and corporate governance committee.In evaluating director candidates, the NGL Energy GP Investor Group assesses whether a candidate possesses the integrity, judgment, knowledge,experience, skill and expertise that are likely to enhance the ability of the board of directors of our general partner to manage and direct our affairs andbusiness, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. Our general partner has no minimumqualifications for director candidates. In general, however, the NGL Energy GP Investor Group reviews and evaluates both incumbent and potential newdirectors in an effort to achieve diversity of skills and experience among the directors of our general partner and in light of the following criteria:•experience in business, government, education, technology or public interests;•high-level managerial experience in large organizations;•breadth of knowledge regarding our business and industry;•specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution ortransportation, government, policy, finance or law;•moral character and integrity;•commitment to our unitholders’ interests;•ability to provide insights and practical wisdom based on experience and expertise;•ability to read and understand financial statements; and•ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on partnershipmatters.Although our general partner does not have a formal policy in regard to the consideration of diversity in identifying director nominees, qualifiedcandidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.100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 63 Chief Executive Officer and DirectorRobert W. Karlovich III 40 Chief Financial Officer and TreasurerShawn W. Coady 55 President and Chief Operating Officer, Retail Division and DirectorVincent J. Osterman 60 President, Eastern Retail Propane Operations and DirectorKurston P. McMurray 45 General Counsel and Corporate SecretaryLawrence J. Thuillier 46 Chief Accounting OfficerJames M. Collingsworth 62 DirectorStephen L. Cropper 67 DirectorBryan K. Guderian 57 DirectorJames C. Kneale 65 DirectorJared Parker 35 DirectorJohn T. Raymond 46 DirectorPatrick Wade 47 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 has served as our Chief Financial Officer since February 2016. Prior to joining NGL, Mr. Karlovich served asChief 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.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 from 2004 to 2015 and as a member of the executive committee of the Illinois Propane Gas Association from 2004 to March 2015.101Table of ContentsDr. 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.Kurston P. McMurray. Mr. McMurray has served as our General Counsel and Corporate Secretary since October 2016. Mr. McMurray joined NGL inFebruary 2015 as Vice President, Legal and Corporate Secretary. Prior to joining NGL, Mr. McMurray practiced law in the Tulsa, Oklahoma area since 1998and was a founding shareholder of Wilkin/McMurray PLLC. Mr. McMurray’s private practice specialized in business transactions, real estate, healthcare,banking, corporate governance, corporate management and commercial litigation.Lawrence J. Thuillier. Mr. Thuillier has served as our Chief Accounting Officer since January 2016. Prior to joining NGL, Mr. Thuillier served invarious roles at Eagle Rock Energy Partners, L.P. from December 2007 through October 2015, most recently as Vice President of Financial Reporting andCorporate Controller. Mr. Thuillier served as Assistant Corporate Controller for Exterran Holdings, Inc. (formerly Universal Compression) from November2006 through November 2007. Prior to that, Mr. Thuillier served in various roles at Deloitte & Touche LLP, most recently as Audit Senior Manager.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 January 2014. 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 Finance Corp., a subsidiary of DollarThrifty Automotive Group. Mr. Cropper currently serves on the board of directors of QuikTrip Corporation and Wawa Inc.Mr. Cropper brings substantial experience in the energy business and in the marketing of energy products to the board. With his significantmanagement and governance experience, Mr. Cropper provides important skills in identifying, assessing and addressing various business issues. As a directorfor other public companies, Mr. Cropper also provides cross board experience.Bryan K. Guderian. Mr. Guderian joined the board of directors of our general partner in May 2012. Mr. Guderian has served as Senior Vice Presidentof Business Development of WPX Energy, Inc. (“WPX”) since October 2014. Mr. Guderian served as Senior Vice President of Operations of WPX fromAugust 2011 to October 2014. Mr. Guderian previously served as Vice President of the Exploration & Production unit of The Williams Companies, Inc. from1998 until August 2011, where he102Table of Contentshad responsibility for overseeing international operations. Mr. Guderian served as a director of Apco Oil & Gas International Inc., from 2002 to 2015 and as adirector of Petrolera Entre Lomas S.A. from 2003 to 2015.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.Jared Parker. Mr. Parker joined the board of directors of our general partner in January 2017. Mr. Parker had previously been an observer on theboard since May 2016. Mr. Parker is a Managing Director of Oaktree Capital Management L.P.’s (“Oaktree”) Infrastructure Investing Strategy. Mr. Parkerjoined Oaktree in August 2014 from Highstar Capital and has over 13 years of experience in private equity, operational leadership, investment banking andfinance. Mr. Parker currently serves as a director on the board of ADS Waste Holdings, Inc. Previously Mr. Parker served on the boards of London City Airportand the Ports America Companies and as an observer to the boards of InterGen and Northern Star Generation. Mr. Parker served as president of Ports AmericaStevedoring, the largest business unit inside Ports America from 2010 through 2013. Prior to joining Highstar Capital in 2005, Mr. Parker worked as anadvisor to the Highstar Capital Team on several transactions as an investment banker at Deutsche Bank. While at Deutsche Bank, Mr. Parker adviseddomestic and power generation companies and financial sponsors on merger and acquisitions and financings.Mr. Parker brings experience in operational leadership and finance. As a director for other public companies, Mr. Parker also provides cross boardexperience.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 as 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, PAA GP Holdings LLC, TallgrassMLP GP LLC and Tallgrass Management, LLC. Mr. Raymond manages various private investments through personally held Lynx Holdings, LLC.Mr. Raymond brings extensive financial and industry experience to the board. As a director for other public companies, Mr. Raymond also providescross board experience.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 June 2012. Mr. Wade has 23 years of experience in the energy sector. In 2002, Mr. Wade co-founded Tiger Midstream Investments, anatural gas midstream development and investment company that was involved primarily in the Rocky Mountains. From 2005 to 2008, Mr. Wade was aManaging Director at Bear Energy LP, responsible for investments in natural gas midstream infrastructure, as well as contracting for a diverse portfolio ofnatural gas storage capacity. In 2008, Mr. Wade joined EMG as a Managing Director in the Houston office. EMG is the management company for a series ofspecialized private equity funds. EMG focuses on investing across various facets of the global natural resource industry including the upstream andmidstream segments of the energy complex. EMG is the managing partner of EMG NGL HC LLC. Mr. Wade’s primary focus is making direct investmentsacross the natural resources industry. Mr. Wade served as a director of MarkWest Liberty Midstream & Resources from 2009 through 2011. In addition,Mr. Wade currently serves on the board of directors of Medallion Midstream, LLC, Ferus Inc., and Lodestar Energy Group, LLC.103Table of ContentsMr. Wade brings extensive financial and industry experience to the board. With 20 years of experience in the energy sector, Mr. Wade providesvaluable insight into our business.Director Appointment 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. Oaktree has the right to designate one person to serve on the board of directors,and has designated Jared Parker.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.Compensation 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; and104Table of Contents•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, 2017, except for the correction of shares for James Burke (who resigned from his position as President of NGL WaterSolutions, LLC and as a member of the board of directors of our general partner effective July 15, 2016) filed on July 11, 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.Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board, anyindependent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of ourSecretary at the following address: Name of the Director(s), c/o Secretary, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, 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 “2017” in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2017.105Table of ContentsIntroductionThe 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 2017 were:•H. Michael Krimbill–Chief Executive Officer•Robert W. Karlovich III–Chief Financial Officer•Shawn W. Coady–President and Chief Operating Officer, Retail Division•Vincent J. Osterman–President, Eastern Retail Propane Operations•Lawrence J. Thuillier–Chief Accounting OfficerCompensation 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.Recent AchievementsOur compensation structure is designed to reward our officers for achieving above-market returns for our unitholders. Our achievements during theyear ended March 31, 2017 included the following:•We sold our common units in TLP for $112 million;•Issued $240 million of 10.75% Class A Convertible Preferred Units;•Launched a $200 million at-the-market equity program;•Issued $700 million senior unsecured notes that bear interest at 7.50% and mature on November 1, 2023;•Amended and restated our revolving credit facility which extended the maturity date to October 2021;•Issued $500 million senior unsecured notes that bear interest at 6.125% and mature on March 1, 2025;•Issued 10,120,000 common units for net proceeds of $222.5 million in an equity offering in February 2017; and•The Grand Mesa Pipeline project commenced operations in November 2016.106Table of ContentsCompensation Highlights•We paid no cash bonuses to our named executive officers during fiscal year 2017.•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. 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 2017, 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 year2017:◦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 2017 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;◦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 2017 compensation program.107Table of ContentsElements 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 compensate executiveofficers for their level of responsibility,expertise and experience ž Based on competition in the marketplacefor executive talent and abilities X Discretionary CashBonus Awards ž Rewards achievement of specificannual financial and operationalperformance goals ž Based on the named executive officer’srelative contribution to achieving orexceeding annual goals X X X ž Recognizes individual contributions toour performance Long-Term EquityIncentive Awards ž Motivates and rewards theachievement of long-term performancegoals, including increasing the marketprice of our common units and thequarterly distributions to our unitholders ž Based on the named executive officer’sexpected contribution to long-termperformance goals X X X ž Provides a forfeitable long-termincentive to encourage executive retention 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, the boardof directors 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.•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 $200,000108Table of Contentsin January 2013, to $250,000 in July 2013 and increased to $315,000 effective April 2, 2017, in consideration of the fact that his salary was lowrelative to the benchmark peer group.•Mr. Thuillier’s base salary of $250,000 was negotiated prior to his joining our management team in January 2016. Effective April 1, 2017, Mr.Thuillier’s base salary was increased to $260,000.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). Nocash bonuses were paid to the named executive officers during fiscal year 2017.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 Service Award units granted, vested and/or forfeited during fiscal year 2017 withrespect to the named executive officers: Unvested Unitsat March 31, 2016 Units Granted Units Vested Units Forfeited Unvested Unitsat March 31, 2017H. Michael Krimbill (1) 142,382 228,809 (71,191) — 300,000Robert W. Karlovich III (2) 75,000 25,000 (25,000) — 75,000Shawn W. Coady (3) 45,000 58,302 (43,302) — 60,000Vincent J. Osterman (3) 45,000 58,302 (43,302) — 60,000Lawrence J. Thuillier (4) 30,000 12,661 (12,661) — 30,000 (1)Mr. Krimbill vested 71,191 Service Awards on July 1, 2016 and was granted 228,809 Service Awards on July 15, 2016. The Service Awards granted on July 15, 2016 vest28,809 on July 10, 2017, 100,000 on July 9, 2018 and 100,000 on July 8, 2019.(2)Mr. Karlovich vested 25,000 Service Awards on July 1, 2016 and was granted 25,000 Service Awards on July 15, 2016, which vest on July 8, 2019.(3)Dr. Coady and Mr. Osterman each vested Service Awards totaling 30,000 and 13,302, respectively, on July 1, 2016 and August 15, 2016, and each were granted ServiceAwards totaling 45,000 and 13,302, respectively, on July 15, 2016 and August 15, 2016. For both Dr. Coady and Mr. Osterman, the Service Awards granted on July 15,2016 vest 5,000 on July 10, 2017, 20,000 on July 9, 2018 and 20,000 on July 8, 2019.(4)Mr. Thuillier vested Service Awards of 10,000 on July 1, 2016 and 2,661 on August 15, 2016, and was granted 10,000 Service Awards on July 15, 2016, which vest on July8, 2019, and 2,661 on August 15, 2016.The number of Service Award units granted to Mr. Krimbill was calculated based on utilizing peer group focused, market-based benchmarkscompiled by PM&P.The Service Award units granted to the other Named Executive Officers was determined in reference to our peer group and the market-basedbenchmarks compiled by PM&P and based on the Named Executive Officers total compensation falling between the 25th and 50th percentile of the peergroup.The Service Award units granted in August 2016 were intended as discretionary bonuses for performance during fiscal year 2016.109Table of ContentsThe following table summarizes the vesting dates of the unvested Service Award units at March 31, 2017: Service Award Units by Vesting Date TotalUnvested Units July 10, 2017 July 9, 2018 July 8, 2019 at March 31, 2017H. Michael Krimbill 100,000 100,000 100,000 300,000Robert W. Karlovich III 25,000 25,000 25,000 75,000Shawn W. Coady 20,000 20,000 20,000 60,000Vincent J. Osterman 20,000 20,000 20,000 60,000Lawrence J. Thuillier 10,000 10,000 10,000 30,000During 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 (“TUR”) attained by usover the applicable performance periods, as measured against our peer group and as described in the Performance Unit Agreement, provided that the numberof common 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 officerduring the fiscal year ended March 31, 2017: Maximum Performance Award Unitsby Vesting Date July 1, 2017 July 1, 2018 July 1, 2019 TotalH. Michael Krimbill 57,618 200,000 200,000 457,618Robert W. Karlovich III — — 50,000 50,000Shawn W. Coady 10,000 40,000 40,000 90,000Vincent J. Osterman 10,000 40,000 40,000 90,000Lawrence J. Thuillier — — 20,000 20,000The 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. As of March 31, 2017,performance will be measured over the following periods:Vesting Date of Tranche Performance Period for TrancheJuly 1, 2017 July 1, 2014 through June 30, 2017July 1, 2018 July 1, 2015 through June 30, 2018July 1, 2019 July 1, 2016 through June 30, 2019 The 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 Total Unitholder Return 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 90th percentile 200%110Table of ContentsThe 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, 2017” 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. For every dollar that employees contribute up to 1% of their eligible compensation (as defined in the plan), we contribute one dollar, plus 50cents for every dollar employees contribute between 1% and 6% of their eligible compensation (as defined in the plan). Our matching contributions prior toJanuary 1, 2015 vest over five years and, effective January 1, 2015, our matching contributions vest over two 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 2017 Compensation ProgramDuring fiscal year 2017, PM&P conducted a competitive review of our executive compensation program and provided input to the compensationcommittee regarding competitive compensation levels and compensation program design. In order to provide guidance to the compensation committeeregarding competitive rates of compensation, PM&P collected pay data from the following sources:•Compensation surveys including data from published compensation surveys representative of other energy industry and broader generalindustry companies with revenues of between $1 billion and $6 billion; and•Peer group data including pay data from 10-K and proxy filings for a group of 20 publicly traded midstream oil & gas partnerships of similarsize and scope to us.111Table of ContentsCompensation Peer Group Companies AmeriGas Partners LP NuStar Energy L.P. Martin Midstream Partners LPFerrellgas Partners LP Targa Resources Partners LP Regency Energy Partners LPStar Gas Partners, L.P. Buckeye Partners, L.P. Boardwalk Pipeline Partners, LPSuburban Propane Partners, L.P. Genesis Energy LP Western Gas Partners LPONEOK Partners, L.P. Crestwood Midstream Partners LP Williams Partners L.P. Magellan Midstream Partners LP Enbridge Energy Partners, L.P. DCP 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 2017 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 2017, 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 2017. 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.112Table of ContentsSummary Compensation Table for 2017The following table summarizes the compensation earned by our named executive officers for fiscal years 2015 through 2017. Name and Position FiscalYear Salary($) Bonus($) RestrictedUnitAwards (Serviceand PerformanceAwards) (1)($) All OtherCompensation (2)($) Total($)H. Michael Krimbill 2017 350,000 — 7,174,094 10,463 7,534,557Chief Executive Officer 2016 350,000 — 8,319,437 7,539 8,676,976 2015 292,500 — — 9,319 301,819 Robert W. Karlovich III (3) 2017 400,000 — 809,985 5,510 1,215,495Chief Financial Officer 2016 30,769 — 419,250 — 450,019 Shawn W. Coady 2017 315,000 — 1,662,027 9,275 1,986,302President and Chief Operating 2016 315,000 — 1,047,241 9,329 1,371,570Officer, Retail Division 2015 311,250 — 1,331,501 19,153 1,661,904 Vincent J. Osterman 2017 250,000 — 1,662,027 36,831 1,948,858President, Eastern Retail 2016 250,000 — 1,047,241 30,906 1,328,147Propane Operations 2015 250,000 — 1,331,501 31,763 1,613,264 Lawrence J. Thuillier (4) 2017 250,000 — 374,007 43,469 667,476Chief Accounting Officer (1)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 grant dates, with adjustmentsmade to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting periodwas estimated using the value of the most recent distribution prior to the grant date and assumptions that a market participant might make about future distribution growth. Thiscalculation of fair value is consistent with the provisions of Accounting Standards Codification (“ASC”) 718 Stock Compensation. The following table summarizes theseamounts:Name Service AwardGrant DateFair Value Performance AwardGrant DateFair Value TotalGrant DateFair Value Performance Awardsat Maximum ValueH. Michael Krimbill $3,540,710 $3,633,384 $7,174,094 $7,266,768Robert W. Karlovich III $360,485 $449,500 $809,985 $899,000Shawn W. Coady $944,827 $717,200 $1,662,027 $1,434,400Vincent J. Osterman $944,827 $717,200 $1,662,027 $1,434,400Lawrence J. Thuillier $194,207 $179,800 $374,007 $359,600(2)The amounts in this column include matching contributions to our 401(k) plan. Amounts for Dr. Coady include the incremental cost of the use of a company car, includingdepreciation, maintenance, insurance, and fuel. Amounts for Mr. Osterman include propane provided to him and to members of his family (valued for this purpose at the costof the propane to NGL). Amounts for Mr. Thuillier include moving expenses. The following table summarizes these amounts:113Table of ContentsName FiscalYear 401(k)Match CarAllowance Moving Expenses Propane Total OtherCompensationShawn W. Coady 2017 $9,275 $— $— $— $9,275 2016 $9,329 $— $— $— $9,329 2015 $9,796 $9,357 $— $— $19,153 Vincent J. Osterman 2017 $5,721 $— $— $31,110 $36,831 2016 $4,038 $— $— $26,868 $30,906 2015 $18,468 $— $— $13,295 $31,763 Lawrence J. Thuillier 2017 $5,721 $— $37,748 $— $43,469(3)Mr. Karlovich was not a named executive officer prior to fiscal year 2016.(4)Mr. Thuillier was not a named executive officer prior to fiscal year 2017.Restricted Unit AwardsDuring fiscal year 2017, the Committee granted awards for which units vest at specified dates, contingent only on the continued service of therecipient through the service date (the “Service Awards”) and awards that vest at specific dates, contingent on both the performance of our common unitsrelative to the performance of other entities and on the continued service of the recipient through the vesting (the “Performance Units”).114Table of Contents2017 Grants of Plan Based Awards TableThe following table summarizes the number of restricted Service and Performance Award units granted to our named executive officers, and theirgrant date fair values: Estimated Future Payouts Under Performance Awards(1) Name Grant Date Total Number ofService Award Units Threshold(#) 50% Target(#) 100% Maximum(#) 200% Grant DateFair Value ofUnit Awards($)(2)(3)H. Michael Krimbill July 15, 2016 228,809 3,540,710 July 15, 2016 114,404 228,809 457,618 3,633,384Robert W. Karlovich III July 15, 2016 25,000 360,485 July 15, 2016 12,500 25,000 50,000 449,500Shawn W. Coady July 15, 2016 45,000 694,815 July 15, 2016 22,500 45,000 90,000 717,200 August 15, 2016 13,302 250,011Vincent J. Osterman July 15, 2016 45,000 694,815 July 15, 2016 22,500 45,000 90,000 717,200 August 15, 2016 13,302 250,011Lawrence J. Thuillier July 15, 2016 10,000 144,194 July 15, 2016 5,000 10,000 20,000 179,800 August 15, 2016 2,661 50,014 (1)Amounts reported in the (a) “Threshold” column reflect the threshold number of Performance Awards (at 50% of target) that may be earned (assuming a relative TUR at the50th percentile), (b) “Target” column reflect the target number of performance awards, or 100%, that may be earned (assuming a relative TUR at the 75th percentile) and (c)“Maximum” column reflect 200% of the target performance awards that may be earned (assuming a relative TUR greater than the 90th percentile). The number of commonunits actually received by a named executive officer with respect to a Performance Award may vary based on the Partnership’s relative TUR as compared to the TUR of theperformance peer group. The Performance Awards are described above under “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 on probable achievement ofthe performance conditions, which is consistent with the estimate of aggregate compensation to be recognized over the service period, excluding the effect of estimatedforfeitures.(3)The fair value of the restricted Service Award units shown in the table above was calculated based on the closing market price of our common units on the grant dates, withadjustments made to reflect the fact that restricted units are not entitled to distributions during the vesting period.We record the expense for each Service Award on a straight-line basis over the requisite period for the entire award (that is, over the requisite serviceperiod of the last separately vesting portion of the award), ensuring that the amount of compensation cost recognized at any date at least equals the portion ofthe grant-date value of the award that is vested at that date. The fair value of the Performance Awards is estimated using a Monte Carlo simulation at the grantdate. 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. Any Performance Awards that do not become earned Performance Awards shall terminate, expire and otherwise beforfeited by the participants. The amounts reported in the table above for restricted units and performance units is the grant date fair value for financialreporting purposes under ASC 718 and does not represent the amount actually realized by the executive at vesting, which may be less or more than theamount reported in the table above.115Table of ContentsOutstanding Equity Awards at March 31, 2017The following table summarizes the number of unvested Service Award and Performance Awards outstanding and their fair values at March 31,2017: Service Awards Performance Awards Number of UnitsThat Have Not Yet Vested Market Value of Units thatHave Not Vested Number of UnitsThat Have Not Yet Vested Market Value of Units thatHave Not VestedName #(1) ($)(2) #(3) ($)(2)H. Michael Krimbill 300,000 6,780,000 300,000 6,780,000Robert W. Karlovich III 75,000 1,695,000 75,000 1,695,000Shawn W. Coady 60,000 1,356,000 60,000 1,356,000Vincent J. Osterman 60,000 1,356,000 60,000 1,356,000Lawrence J. Thuillier 30,000 678,000 30,000 678,000 (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, 2017 of $22.60. No adjustments were made to reflect the fact that the restricted units are notentitled to distributions during the vesting period.(3)Reflects the target number of Performance Awards granted to each named executive officer that have not vested. Vesting of the Performance Awards is contingent upon ourrelative TUR as measured against the performance peer group and satisfaction of a continued service requirement.2017 Units VestedDuring fiscal year 2017, certain of the restricted Service Award units and Performance Award units vested. The following table summarizes the valueof the awards on the vesting date which was calculated based of the closing market price per common unit on the vesting dates. Service AwardsName Number of UnitsAcquired on Vesting Value Realizedon Vesting($)H. Michael Krimbill (1) 71,191 1,392,852Robert W. Karlovich III (2) 25,000 489,125Shawn W. Coady (3) 43,302 836,961Vincent J. Osterman (3) 43,302 836,961Lawrence J. Thuillier (4) 12,661 245,664 (1)Mr. Krimbill vested 71,191 Service Awards on July 1, 2016.(2)Mr. Karlovich vested 25,000 Service Awards on July 1, 2016.(3)Dr. Coady and Mr. Osterman each vested 30,000 and 13,302 Service Awards on July 1, 2016 and August 15, 2016, respectively.(4)Mr. Thuillier vested 10,000 and 2,661 Service Awards on July 1, 2016 and August 15, 2016, respectively.Potential Payments Upon Termination or Change in ControlWe 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, 2017” table above (in the “Market Value of Units that Have Not Yet Vested” columns).116Table of ContentsDirector 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 chairmen of the audit and compensation committees; and•an annual retainer of $5,000 for each member of the audit and compensation committees other than the chairman.Special committees are convened by the board of directors from time to time to review specific transactions. Compensation paid to the members ofthese committees varies depending on the transaction and the expected time commitment of the committee members.In addition, each director who is not an officer or an employee of our general partner has been granted awards of restricted units. In July 2016, suchdirectors were granted 19,000 restricted units that vest in tranches of 3,000 units on July 10, 2017 and 8,000 units on each of July 9, 2018 and July 8, 2019.All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Eachdirector is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.Director Compensation for Fiscal Year 2017The following table summarizes the compensation earned during fiscal year 2017 by each director who is not an officer or employee of our generalpartner or its affiliates:Name Fees Earned orPaid in Cash($) Restricted UnitAwards($) Total($)James M. Collingsworth 65,000 295,420 360,420Stephen L. Cropper 75,000 295,420 370,420Bryan K. Guderian 65,000 295,420 360,420James C. Kneale 75,000 295,420 370,420On July 1, 2016, a tranche of 5,000 units vested for each of these directors.As of March 31, 2017, each of the directors listed in the table above has 24,000 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 23, 2017 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) 13,154,725 10.95%Swank Capital, LLC (3) 8,825,224 7.34%ALPS Advisors, Inc. (4) 6,645,046 5.53% Directors and named executive officers: Shawn W. Coady (5) 2,546,394 2.12%James M. Collingsworth (6) 71,750 *Stephen L. Cropper (7) 40,000 *Bryan K. Guderian 37,500 *Robert W. Karlovich III 39,320 *James C. Kneale (8) 37,000 *H. Michael Krimbill (9) 2,027,820 1.69%Vincent J. Osterman (10) 3,986,780 3.32%Jared Parker — John T. Raymond (11) 176,634 *Patrick Wade — —Lawrence Thuillier 15,000 —All directors and executive officers as a group (12 persons) (12) 8,978,198 7.46% * Less than 1.0%(1)Based on 120,787,060 common units outstanding at May 23, 2017.(2)The mailing address for OppenheimerFunds, Inc. is 225 Liberty Street, New York, NY 10281. OppenheimerFunds, Inc. reported shared voting and dispositive power withrespect to all common units beneficially owned. This information related to OppenheimerFunds, Inc. is based upon its Schedule 13G/A filed with the SEC on January 26,2017.(3) The mailing address for Swank Capital, L.L.C. is 8117 Preston Road, Suite 440, Dallas, TX 75225. Swank Capital, LLC, reported shared voting and dispositive power withrespect to all common units beneficially owned. This information related to Swank Capital LLC is based upon its Schedule 13G filed with the SEC on February 14, 2017.(4)The mailing address for ALPS Advisors, Inc. is 1290 Broadway, Suite 1100, Denver, CO 80203. ALPS Advisors, Inc. reported shared voting and dispositive power withrespect to all common units beneficially owned. This information related to ALPS Advisors, Inc. is based upon its Schedule 13G/A filed with the SEC on January 26, 2017. (5)Dr. Shawn W. Coady owns 66,503 of these common units, which includes 20,000 units that will vest on July 10, 2017, does not include 40,000 unvested units which werereported on Dr. Coady’s Form 4 which will vest ratably on July 9, 2018 and July 8, 2019. SWC Family Partnership LP owns 2,320,391 of these common units. SWCFamily Partnership LP is solely owned by SWC General Partner, LLC, of which Dr. Coady is the sole member. Dr. Coady may be deemed to have sole voting andinvestment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady IrrevocableInsurance 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 sole votingand investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The Tara Nicole Coady Trust II, ofwhich the reporting person is the trustee, owns 12,250 common units. The Colleen Blair Coady Trust, of which the reporting person is the trustee, owns 12,250 commonunits. Dr. Coady also owns a 12.27% interest in our general partner through Coady Enterprises, LLC, of which he owns 100% of the membership interests. (6)Mr. Collingsworth owns 47,500 of these common units which includes 5,000 units that will vest on July 10, 2017. Mr. Collingsworth holds 22,000 of these common unitsjointly with his spouse, Cindy Collingsworth. Cindy Collingsworth and her sister jointly own 2,250 of these common units.(7)Mr. Cropper owns 15,000 of these common units which includes 5,000 units that will vest on July 10, 2017. The Donna L. Cropper Living Trust, of which Mr. Cropper andhis spouse, Donna L. Cropper, are the trustees, owns 25,000 of these common units.(8)Mr. Kneale owns 5,000 of these common units which will vest on July 10, 2017. The Suzanne and Jim Kneale Living Trust, of whom Mr. Kneale and his wife are trustees,owns 32,000 of these common units.(9)Mr. H. Michael Krimbill owns 789,417 of these common units, which includes 100,000 units that will vest on July 10, 2017, does not include 200,000 unvested units whichwill vest ratably on July 9, 2018 and July 8, 2019 that were reported on Mr. Krimbill’s most117Table of Contentsrecent Form 4, Krim2010, LLC owns 904,848 of these common units. Krimbill Enterprises LP, H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06%of Krim2010, LLC, respectively. Krimbill Enterprises LP also owns 170,000 of these common units. Krimbill Enterprises LP is controlled by H. Michael Krimbill via hisownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaimssuch beneficial ownership except to the extent of his pecuniary interest therein. KrimGP2010 LLC owns 363,555 of these common units. KrimGP2010 LLC is solely ownedby H. Michael Krimbill. H. Michael Krimbill may be deemed to have sole voting and investment power over these units. H. Michael Krimbill also owns a 14.81% interest inour general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests and Krimbill Capital Group, LLC, which is owned 100% by the H.Michael Krimbill Revocable Trust, of which Mr. Krimbill is the trustee.(10)Mr. Osterman owns 172,143 of these common units which includes 20,000 units that will vest on July 10, 2017, which were reported on Mr. Osterman’s most recent Form4, but does not include 40,000 unvested units which will vest ratably on July 9, 2018 and July 8, 2019 that were reported on Mr. Osterman’s most recent Form 4. Theremaining common units are owned by AO Energy, Inc. (110,587 common units), E. Osterman, Inc. (394,350 common units), E. Osterman Gas Services, Inc. (301,700common units), E. Osterman Propane, Inc. (669,300 common units), Milford Propane, Inc. (559,784 common units), Osterman Family Foundation (122,016 common units),Osterman Propane, Inc. (1,445,850 common units), Propane Gas, Inc. (36,450 common units) and Saveway Propane Gas Service, Inc. (214,600 common units). Each ofthese holding entities may be deemed to have sole voting and investment power over its own common units and Propane Gas, LLC, as sole shareholder of Propane Gas, Inc.,may be deemed to have sole voting and investment power over those common units. Vincent J. Osterman is a director, executive officer and shareholder or member of eachof these entities and may be deemed to have sole voting and investment power over 861,443 common units and shared voting and investment power (with his father, ErnestOsterman) over 3,185,337 common units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. Vincent J. Osterman also owns a 1.65%interest in our general partner through VE Properties XI LLC.(11)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 GP LLC, the generalpartner of NGP MR, LP, the general partner of NGP Midstream & Resources, LLC, a member holding a majority interest in EMG NGL HC LLC. John T. Raymond may bedeemed to have shared voting and investment power over these units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. EMG I NGLGP Holdings, LLC, an affiliate of EMG NGL HC LLC, owns a 5.73% interest in our general partner. EMG II NGL GP Holdings, LLC, an affiliate of EMG NGL HC LLC,owns a 5.36% interest in our general partner.(12)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, 2017. 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 Approved bySecurity Holders (2) 2,708,500 — 2,377,224Total 2,708,500 — 2,377,224 (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 numberof common units deliverable under the LTIP automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units,unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount.(2)Our general partner adopted the LTIP in connection with the completion of our initial public offering (“IPO”) in May 2011. The adoption of the LTIP did not require theapproval of our unitholders.Item 13. Certain Relationships and Related Transactions, and Director Independence118Table of ContentsOur directors, executive officers, and greater than 5% unitholders collectively own an aggregate of 37,603,193 common units, representing anaggregate 31.13% 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 and payments were determined by and among affiliatedentities 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 37,603,193 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 2017 ($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 $58.7 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.119Table of ContentsTransactions 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, 2017 (in thousands):Sales to SemGroup$66,077Purchases from SemGroup$74,921WPXBryan 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). We also treat and dispose of wastewater and solids received from WPX. The following table summarizes transactions with WPX forthe year ended March 31, 2017 (in thousands):Sales to WPX$3,981Purchases from WPX$76,681Other 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, 2017:Entity Nature of Purchases AmountPurchased Ownership Interestin Entity (in thousands) Shawn W. Coady Hicks Motor Sales Vehicle purchases $971 50%Vincent J. Osterman VE Properties III, LLC Office space rental $153 100%H. Michael Krimbill KAIR2014 LLC Aircraft rental $90 50%H. Michael Krimbill Pinnacle Aviation 2007, LLC Aircraft rental $89 50%Todd M. Coady, an officer and employee of the Partnership, is the brother of Shawn W. Coady, who is an executive officer of the Partnership and amember of the board of directors. Todd M. Coady’s annual base compensation is $125,000. Todd M. Coady was also eligible to participate in thePartnership’s 401(k) plan, and he received $4,375 of employer matching contributions during the year ended March 31, 2017. In July 2016, Todd M. Coadywas granted 16,000 Services Awards, which are ratably scheduled to vest on July 9, 2018 and July 8, 2019. The grant date fair value of these award was$242,939. In July 2016, Todd M. Coady was also granted 16,000 Performance Units, of which 8,000 potentially vest on July 1, 2018 and 8,000 potentiallyvest on July 1, 2019. The aggregate grant date fair value of these awards was $262,000. In August 2016, Todd M. Coady was granted a bonus of 6,651Service Awards that vested immediately. The grant date fair value of this bonus was $125,005.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 received salary payments during the year ended March 31, 2017 of $130,774. Timothy Osterman was also eligibleto participate in the Partnership’s 401(k) plan, and he received $4,577 of employer matching contributions during the year ended March 31, 2017. In July2016, Timothy Osterman was granted 18,000 Service Awards, which are ratably scheduled to vest on July 10, 2017, July 9, 2018 and July 8, 2019. The120Table of Contentsgrant date fair value of this award was $287,165. In August 2016, Timothy Osterman was granted a bonus of 6,651 Service Awards that vested immediately.The grant date fair value of this bonus was $125,005.Registration 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 owned by theparties to the Registration Rights Agreement. In connection with our IPO, we granted registration rights to the NGL Energy LP Investor Group, andsubsequently, we have granted registration rights in connection with several acquisitions. We will not be required to register such common units if anexemption from the registration requirements of the Securities Act is available with respect to the number of common units desired to be sold. Subject tolimitations specified in the Registration Rights Agreement, the registration rights of the registration rights parties include the following:•Demand Registration Rights. Certain registration rights parties deemed “Significant Holders” under the agreement may, to the extent that theycontinue to own more than 4% of our common units, require us to file a registration statement with the 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.121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, see Part III, Item 10–“Directors, Executive Officers andCorporate 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, 2017 2016Audit fees (1) $2,646,096 $2,676,038Audit-related fees — —Tax fees — —All other fees — —Total $2,646,096 $2,676,038 (1)Includes fees for audits of the Partnership’s financial statements, reviews of the related quarterly financial statements, and services that are normally provided by theindependent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and the preparation of letters tounderwriters and other requesting parties.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.122Table of ContentsPART IVItem 15. Exhibits, Financial Statement Schedules(a)The following documents are filed as part of this Annual Report:1.Financial Statements. 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, OWL Pearsall SWD, LLC,OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.1 to the CurrentReport 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 Karnes SWD, LLC,OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.2 to the CurrentReport 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, Terry Bailey, as trusteeof the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.3 to the CurrentReport 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, Terry Bailey, as trusteeof the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.4 to the CurrentReport 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, LotusOilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High Sierra Transportation, LLC(incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)2.6 Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP, Gavilon, LLC andGavilon 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 SECon 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 on Form S-1 (FileNo. 333-172186) filed with the SEC on April 15, 2011)3.2 Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.2 to the RegistrationStatement on Form S-1 (File No. 333-172186) filed with the SEC on April 15, 2011)3.3 Third Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the CurrentReport on Form 8-K (File No. 001-35172) filed with the SEC on June 28, 2016)3.4 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 with the SEC on April 15, 2011)3.5 Certificate of Amendment to Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.5 to the RegistrationStatement on Form S-1 (File No. 333-172186) filed with the SEC on April 15, 2011)3.6 Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on February 28, 2013)3.7 Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of August 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 on August 7, 2013)3.8 Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of June 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 on July 3, 2014)3.9 Amendment No. 3 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of June 24, 2016(incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 28, 2016)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 otherholders party 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 7,2011)4.2 Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 by and among thePartnership and SemStream (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onNovember 4, 2011)123Table of ContentsExhibit NumberDescription4.3 Amendment No. 2 and Joinder to First Amended and Restated Registration Rights Agreement, dated January 3, 2012, by and among NGL EnergyHoldings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-Portland Propane, L.L.C., Pacer Propane(Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C. (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on January 9, 2012)4.4 Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGL Energy HoldingsLLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onMay 4, 2012)4.5 Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and between NGL EnergyHoldings 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 withthe SEC on June 25, 2012)4.6 Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and between NGL EnergyHoldings 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 onOctober 3, 2012)4.7 Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by and between NGL EnergyHoldings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust and Nitor Trust(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 19, 2012)4.8 Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by and among NGL EnergyHoldings LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to the Current 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 and among NGL EnergyHoldings LLC and Magnum NGL Holdco LLC (incorporated by reference to Exhibit 4.9 to the Annual Report on Form 10-K (File No. 001-35172) for theyear 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 and among NGL EnergyHoldings LLC and Magnum NGL Holdco LLC (incorporated by reference to Exhibit 4.10 to the Annual Report on Form 10-K (File No. 001-35172) forthe year ended March 31, 2016 filed with the SEC on May 31, 2016)4.11 Amended and Restated Note Purchase Agreement, dated March 31, 2017 and effective as of December 31, 2016, by and among NGL Energy Partners LPand 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 onApril 4, 2017)4.12 Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party thereto and U.S. BankNational 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 onOctober 16, 2013)4.13 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 theSEC on October 16, 2013)4.14 Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listedtherein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)4.15 First Supplemental Indenture, dated as of December 2, 2013, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiariesparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.19 to the Annual Reporton Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with the SEC on May 30, 2014)4.16 Second Supplemental Indenture, dated as of April 22, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaryparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.20 to the Annual Reporton Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with the SEC on May 30, 2014)4.17 Third Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiary partythereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with the SEC on November 10, 2014)4.18 Fourth Supplemental Indenture, dated as of December 1, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the GuaranteeingSubsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.25 to theAnnual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)4.19 Fifth Supplemental Indenture, dated as of February 17, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiariesparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.26 to the Annual Reporton Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)4.20 Sixth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiariesparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Quarterly Reporton Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed with the SEC on November 9, 2015)124Table of ContentsExhibit NumberDescription4.21 Registration Rights Agreement, dated December 2, 2013, by and among NGL Energy Partners LP and the purchasers set forth on Schedule A 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 December 5, 2013)4.22 Indenture, dated as of July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party thereto and U.S. BankNational 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 onJuly 9, 2014)4.23 Forms of 5.125% Senior Notes due 2019 (incorporated by reference and included as Exhibits A1 and A2 to Exhibit 4.1 to the Current Report on Form 8-K(File No. 001-35172) filed with the SEC on July 9, 2014)4.24 Registration Rights Agreement, dated July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listed therein onExhibit A and RBS Securities Inc. as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on July 9, 2014)4.25 First Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiariesparty thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q (FileNo. 001-35172) for the quarter ended September 30, 2014 filed with the SEC on November 10, 2014)4.26 Second Supplemental Indenture, dated as of December 1, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the GuaranteeingSubsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.32 to theAnnual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)4.27 Third Supplemental Indenture, dated as of February 17, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the GuaranteeingSubsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.33 to theAnnual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)4.28 Fourth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiariesparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Reporton Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed with the SEC on November 9, 2015)4.29 Registration Rights Agreement, dated May 11, 2016, by and among NGL Energy Partners LP and Highstar NGL Prism/IV-A Interco LLC and HighstarNGL Main Interco 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 June 28,2016)4.30 Amendment to Registration Rights Agreement, dated June 24, 2016, by and among NGL Energy Partners LP and Highstar NGL Prism/IV-A Interco LLC,Highstar NGL Main Interco LLC and NGL CIV A, 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 28, 2016)4.31 Indenture, dated as of October 24, 2016, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors party thereto and U.S. BankNational 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 onOctober 24, 2016)4.32 Forms of 7.5% Senior Notes due 2023 (incorporated by reference to Exhibit 4.2 and included as Exhibits A1 and A2 to Exhibit 4.1 to the Current Reporton Form 8-K (File No. 001-35172) filed with the SEC on October 24, 2016)4.33 Registration Rights Agreement, dated as of October 24, 2016, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors listedtherein on Exhibit A and Barclays Capital Inc. as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the CurrentReport on Form 8-K (File No. 001-35172) filed with the SEC on October 24, 2016)4.34 Indenture, dated as of February 22, 2017, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors party thereto 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 theSEC on February 22, 2017)4.35 Forms of 6.125% Senior Notes due 2025 (included as Exhibits A1 and A2 to Exhibit 4.1 of this Current Report on Form 8-K) (incorporated by referenceto Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on February 22, 2017)4.36 Registration Rights Agreement, dated as of February 22, 2017, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors listedtherein on Exhibit A and RBC Capital Markets, LLC and Deutsche Bank Securities Inc., as representatives 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 February 22, 2017)10.1 Amended and Restated Credit Agreement, dated as of February 14, 2017, by and among NGL Energy Partners LP, NGL Energy Operating LLC, thesubsidiary guarantors party thereto, Deutsche Bank Trust Company Americas, Deutsche Bank AG, New York Branch, and the other financial institutionsparty 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 February 15, 2017)10.2 Amendment No. 1 to Amended and Restated Credit Agreement, dated as of March 31, 2017, among the NGL Energy Partners LP, NGL Energy OperatingLLC, the other subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas, and the other financial institutions party thereto (incorporatedby reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on April 5, 2017)10.3 Class A Convertible Preferred Unit and Warrant Purchase Agreement, dated as of April 21, 2016, by and among NGL Energy Partners LP, Highstar NGLPrism/IV-A Interco LLC and Highstar NGL Main Interco LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No.001-35172) filed with the SEC on April 27, 2016)125Table of ContentsExhibit NumberDescription10.4 Amendment to Class A Convertible Preferred Unit and Warrant Purchase Agreement, dated as of June 23, 2016, by and among NGL Energy Partners LPand Highstar NGL Prism/IV-A Interco LLC, Highstar NGL Main Interco LLC and NGL CIV A, LLC (incorporated by reference to Exhibit 10.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on June 28, 2016)10.5 Form of Warrant (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-35172) filed on June 28, 2016)10.6 Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed on Schedule A 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 5, 2013)10.7+ Letter Agreement among Silverthorne Energy Holdings LLC, Shawn W. Coady and Todd M. Coady dated October 14, 2010 (incorporated by reference toExhibit 10.11 to the Registration Statement on Form S-1 (File No. 333-172186) filed with the SEC on April 15, 2011)10.8+ 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 with the SEC on May 17, 2011)10.9+ Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 tothe Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended June 30, 2012 filed with the SEC on August 14, 2012 )10.10 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 endedMarch 31, 2015 filed with the SEC on June 1, 2015)12.1*Computation of ratios of earnings to fixed charges and combined fixed charges and preferred unit distributions21.1*List of Subsidiaries of NGL Energy Partners LP23.1*Consent of Grant Thornton LLP31.1*Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 200231.2*Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 200232.1*Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 200232.2*Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002101.INS**XBRL Instance Document101.SCH**XBRL Schema Document101.CAL**XBRL Calculation Linkbase Document101.DEF**XBRL Definition Linkbase Document101.LAB**XBRL Label Linkbase Document101.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, 2017 and 2016, (ii) ConsolidatedStatements of Operations for the years ended March 31, 2017, 2016, and 2015, (iii) Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31,2017, 2016, and 2015, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2017, 2016, and 2015, (v) Consolidated Statements of Cash Flowsfor the years ended March 31, 2017, 2016, and 2015, and (vi) Notes to Consolidated Financial Statements.+Management contracts or compensatory plans or arrangements.126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 26, 2017. 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 26, 2017H. Michael Krimbill (Principal Executive Officer) /s/ Robert W. Karlovich III Chief Financial Officer May 26, 2017Robert W. Karlovich III (Principal Financial Officer) /s/ Lawrence W. Thuillier Chief Accounting Officer May 26, 2017Lawrence W. Thuillier (Principal Accounting Officer) /s/ Shawn W. Coady Director May 26, 2017Shawn W. Coady /s/ James M. Collingsworth Director May 26, 2017James M. Collingsworth /s/ Stephen L. Cropper Director May 26, 2017Stephen L. Cropper /s/ Bryan K. Guderian Director May 26, 2017Bryan K. Guderian /s/ James C. Kneale Director May 26, 2017James C. Kneale /s/ Vincent J. Osterman Director May 26, 2017Vincent J. Osterman /s/ Jared Parker Director May 26, 2017Jared Parker /s/ John T. Raymond Director May 26, 2017John T. Raymond /s/ Patrick Wade Director May 26, 2017Patrick Wade 127Table of ContentsINDEX TO FINANCIAL STATEMENTS NGL ENERGY PARTNERS LP Reports of Independent Registered Public Accounting FirmF-2 Consolidated Balance Sheets at March 31, 2017 and 2016F-4 Consolidated Statements of Operations for the years ended March 31, 2017, 2016, and 2015F-5 Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2017, 2016, and 2015F-6 Consolidated Statements of Changes in Equity for the years ended March 31, 2017, 2016, and 2015F-7 Consolidated Statements of Cash Flows for the years ended March 31, 2017, 2016, and 2015F-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, 2017 and 2016, 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, 2017. 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, 2017 and 2016, and the results of their operations and their cash flows for each of the three years in the periodended March 31, 2017 in conformity with accounting principles generally accepted in the United States of America.We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’sinternal control over financial reporting as of March 31, 2017, 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 26, 2017 expressed an unqualified opinion./s/ GRANT THORNTON LLP Tulsa, Oklahoma May 26, 2017 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, 2017, 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, 2017, 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, 2017, and our report dated May 26, 2017 expressed an unqualified opinion onthose financial statements./s/ GRANT THORNTON LLP Tulsa, Oklahoma May 26, 2017 F-3Table of ContentsNGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Balance Sheets(in Thousands, except unit amounts) March 31, 2017 2016ASSETS CURRENT ASSETS: Cash and cash equivalents$12,264 $28,176Accounts receivable-trade, net of allowance for doubtful accounts of $5,234 and $6,928, respectively800,607 521,014Accounts receivable-affiliates6,711 15,625Inventories561,432 367,806Prepaid expenses and other current assets103,193 95,859Total current assets1,484,207 1,028,480PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $375,594 and $266,491, respectively1,790,273 1,649,572GOODWILL1,451,716 1,315,362INTANGIBLE ASSETS, net of accumulated amortization of $414,605 and $316,878, respectively1,163,956 1,148,890INVESTMENTS IN UNCONSOLIDATED ENTITIES187,423 219,550LOAN RECEIVABLE-AFFILIATE3,200 22,262OTHER NONCURRENT ASSETS239,604 176,039Total assets$6,320,379 $5,560,155LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable-trade$658,021 $420,306Accounts payable-affiliates7,918 7,193Accrued expenses and other payables207,125 214,426Advance payments received from customers35,944 56,185Current maturities of long-term debt29,590 7,907Total current liabilities938,598 706,017LONG-TERM DEBT, net of debt issuance costs of $33,458 and $15,500, respectively, and current maturities2,963,483 2,912,837OTHER NONCURRENT LIABILITIES184,534 247,236COMMITMENTS AND CONTINGENCIES (NOTE 10) CLASS A 10.75% CONVERTIBLE PREFERRED UNITS, 19,942,169 and 0 preferred units issued and outstanding, respectively63,890 —REDEEMABLE NONCONTROLLING INTEREST3,072 — EQUITY: General partner, representing a 0.1% interest, 120,300 and 104,274 notional units, respectively(50,529) (50,811)Limited partners, representing a 99.9% interest, 120,179,407 and 104,169,573 common units issued and outstanding, respectively2,192,413 1,707,326Accumulated other comprehensive loss(1,828) (157)Noncontrolling interests26,746 37,707Total equity2,166,802 1,694,065Total liabilities and equity$6,320,379 $5,560,155The accompanying notes are an integral part of these consolidated financial statements.F-4Table of ContentsNGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Operations(in Thousands, except unit and per unit amounts) Year Ended March 31, 2017 2016 2015REVENUES: Crude Oil Logistics$1,666,884 $3,217,079 $6,635,384Water Solutions159,601 185,001 200,042Liquids1,439,088 1,194,479 2,243,825Retail Propane413,109 352,977 489,197Refined Products and Renewables9,342,702 6,792,112 7,231,693Other844 462 1,916Total Revenues13,022,228 11,742,110 16,802,057COST OF SALES: Crude Oil Logistics1,572,015 3,111,717 6,560,506Water Solutions4,068 (7,336) (30,506)Liquids1,334,116 1,037,118 2,111,614Retail Propane191,589 156,757 278,538Refined Products and Renewables9,219,721 6,540,599 7,035,472Other400 182 2,583Total Cost of Sales12,321,909 10,839,037 15,958,207OPERATING COSTS AND EXPENSES: Operating307,925 401,118 364,131General and administrative116,566 139,541 149,430Depreciation and amortization223,205 228,924 193,949(Gain) loss on disposal or impairment of assets, net(209,177) 320,766 41,184Revaluation of liabilities6,717 (82,673) (12,264)Operating Income (Loss)255,083 (104,603) 107,420OTHER INCOME (EXPENSE): Equity in earnings of unconsolidated entities3,084 16,121 12,103Revaluation of investments(14,365) — —Interest expense(150,478) (133,089) (110,123)Gain on early extinguishment of liabilities, net24,727 28,532 —Other income, net27,762 5,575 37,171Income (Loss) Before Income Taxes145,813 (187,464) 46,571INCOME TAX (EXPENSE) BENEFIT(1,939) 367 3,622Net Income (Loss)143,874 (187,097) 50,193LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS(6,832) (11,832) (12,887)NET INCOME (LOSS) ATTRIBUTABLE TO NGL ENERGY PARTNERS LP137,042 (198,929) 37,306LESS: DISTRIBUTIONS TO PREFERRED UNITHOLDERS(30,142) — —LESS: NET INCOME ALLOCATED TO GENERAL PARTNER(232) (47,620) (45,700)NET INCOME (LOSS) ALLOCATED TO COMMON UNITHOLDERS$106,668 $(246,549) $(8,394)BASIC INCOME (LOSS) PER COMMON UNIT$0.99 $(2.35) $(0.05)DILUTED INCOME (LOSS) PER COMMON UNIT$0.95 $(2.35) $(0.05)BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING108,091,486 104,838,886 86,359,300DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING111,850,621 104,838,886 86,359,300 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)(in Thousands) Year Ended March 31, 2017 2016 2015Net income (loss)$143,874 $(187,097) $50,193Other comprehensive (loss) income(1,671) (48) 127Comprehensive income (loss)$142,203 $(187,145) $50,320The accompanying notes are an integral part of these consolidated financial statements.F-6Table of ContentsNGL ENERGY PARTNERS LP AND SUBSIDIARIESConsolidated Statements of Changes in EquityFor the Years Ended March 31, 2017, 2016, and 2015(in Thousands, except unit amounts) Limited Partners GeneralPartner CommonUnits Amount SubordinatedUnits Amount AccumulatedOtherComprehensiveIncome (Loss) NoncontrollingInterests TotalEquityBALANCES AT MARCH 31, 2014$(45,287) 73,421,309 $1,570,074 5,919,346 $2,028 $(236) $5,274 $1,531,853Distributions to partners(38,236) — (197,611) — (6,748) — — (242,595)Distributions to noncontrolling interest owners— — — — — — (27,147) (27,147)Contributions823 — — — — — 9,433 10,256Business combinations— 8,851,105 259,937 — — — 546,740 806,677Common units issued, net of offering costs— 15,017,100 541,128 — — — — 541,128Equity issued pursuant to incentivecompensation 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 units to commonunits— 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 to partners(61,485) — (260,522) — — — — (322,007)Distributions to noncontrolling interest owners— — — — — — (35,720) (35,720)Contributions54 — (3,829) — — — 15,376 11,601Business combinations— 833,454 19,108 — — — 9,248 28,356Equity issued pursuant to incentivecompensation 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 1,694,065Distributions to partners(287) — (181,294) — — — — (181,581)Distributions to noncontrolling interest owners— — — — — — (3,292) (3,292)Contributions49 — (501) — — — 1,173 721Business combinations— 218,617 3,940 — — — — 3,940Purchase of noncontrolling interest (Notes 4 and16)— — (215) — — — (12,602) (12,817)Equity issued pursuant to incentivecompensation plan— 2,350,082 68,414 — — — — 68,414Common units issued, net of offering costs288 13,441,135 286,848 — — — — 287,136Allocation of value to beneficial conversionfeature of Class A convertible preferred units— — 131,534 — — — — 131,534Issuance of warrants— — 48,550 — — — — 48,550Accretion of beneficial conversion feature ofClass A convertible preferred units— — (8,999) — — — — (8,999)Transfer of redeemable noncontrolling interest— — — — — — (3,072) (3,072)Net income232 — 136,810 — — — 6,832 143,874Other comprehensive loss— — — — — (1,671) — (1,671)BALANCES AT MARCH 31, 2017$(50,529) 120,179,407 $2,192,413 — $— $(1,828) $26,746 $2,166,802The 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(in Thousands) Year Ended March 31, 2017 2016 2015OPERATING ACTIVITIES: Net income (loss)$143,874 $(187,097) $50,193Adjustments to reconcile net income (loss) to net cash (used in) provided by operating activities: Depreciation and amortization, including amortization of debt issuance costs237,795 249,211 210,475Gain on early extinguishment or revaluation of liabilities, net(18,010) (111,205) (12,264)Gain on termination of a storage sublease agreement(16,205) — —Non-cash equity-based compensation expense53,102 51,565 32,767(Gain) loss on disposal or impairment of assets, net(209,177) 320,766 41,184Provision for doubtful accounts1,029 5,628 4,105Net adjustments to fair value of commodity derivatives56,356 (103,223) (219,421)Equity in earnings of unconsolidated entities(3,084) (16,121) (12,103)Distributions of earnings from unconsolidated entities3,564 17,404 12,539Revaluation of investments14,365 — —Other(5,036) (5,854) (577)Changes in operating assets and liabilities, exclusive of acquisitions: Accounts receivable-trade and affiliates(269,425) 505,540 41,395Inventories(192,190) 74,686 243,292Other current and noncurrent assets(53,173) 10,572 (34,505)Accounts payable-trade and affiliates239,047 (439,709) (53,086)Other current and noncurrent liabilities(9,656) (20,668) (41,603)Net cash (used in) provided by operating activities(26,824) 351,495 262,391INVESTING ACTIVITIES: Capital expenditures(363,871) (661,885) (227,978)Purchase of equity interest in Grand Mesa Pipeline— — (310,000)Acquisitions, net of cash acquired(122,832) (234,652) (960,922)Cash flows from settlements of commodity derivatives(37,442) 105,662 199,165Proceeds from sales of assets29,566 8,455 26,262Proceeds from sale of TLP common units112,370 — —Proceeds from sale of Grassland22,000 — —Proceeds from sale of general partner interest in TLP, net— 343,135 —Investments in unconsolidated entities(2,105) (11,431) (33,528)Distributions of capital from unconsolidated entities9,692 15,792 10,823Loan for natural gas liquids facility— (3,913) (63,518)Payments on loan for natural gas liquids facility8,916 7,618 1,625Loan to affiliate(3,200) (15,621) (8,154)Payments on loan to affiliate655 1,513 —Payment to terminate development agreement(16,875) — —Other— — 4Net cash used in investing activities(363,126) (445,327) (1,366,221)FINANCING ACTIVITIES: Proceeds from borrowings under revolving credit facilities1,700,000 2,602,500 3,764,500Payments on revolving credit facilities(2,733,500) (2,133,000) (3,280,000)Issuance of senior notes1,200,000 — 400,000Repurchases of senior notes(21,193) (43,421) —Proceeds from borrowings under other long-term debt— 53,223 —Payments on other long-term debt(49,786) (5,087) (6,688)Debt issuance costs(33,558) (10,237) (11,076)Contributions from general partner49 54 823F-8Table of ContentsContributions from noncontrolling interest owners, net672 11,547 9,433Distributions to partners(181,581) (322,007) (242,595)Distributions to noncontrolling interest owners(3,292) (35,720) (27,147)Proceeds from sale of convertible preferred units and warrants, net of offering costs234,975 — —Proceeds from sale of common units, net of offering costs287,136 — 541,128Payments for the early extinguishment of liabilities(25,884) — —Taxes paid on behalf of equity incentive plan participants— (19,395) (13,491)Common unit repurchases— (17,680) —Other— (72) (194)Net cash provided by financing activities374,038 80,705 1,134,693Net (decrease) increase in cash and cash equivalents(15,912) (13,127) 30,863Cash and cash equivalents, beginning of period28,176 41,303 10,440Cash and cash equivalents, end of period$12,264 $28,176 $41,303Supplemental cash flow information: Cash interest paid$117,912 $117,185 $90,556Income taxes paid (net of income tax refunds)$2,022 $2,300 $22,816Supplemental non-cash investing and financing activities: Value of common units issued in business combinations$3,940 $19,108 $259,937Accrued capital expenditures$1,758 $1,907 $7,999The 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, 2017 and 2016, and for the Years Ended March 31, 2017, 2016, and 2015Note 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, 2017, our operations include:•Our Crude Oil Logistics segment purchases crude oil from producers and transports it to refineries or for resale at pipeline injection stations,storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.•Our Water Solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas productionand for the disposal of solids such as tank bottoms and drilling fluids and performs truck and frac tank washouts. In addition, our WaterSolutions segment sells the recovered hydrocarbons that result from performing these services.•Our Liquids segment supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and inCanada using its leased underground storage and fleet of leased railcars, markets regionally through its 21 owned terminals throughout theUnited States, and provides terminaling and storage services at its salt dome storage facility in Utah.•Our Retail Propane segment sells propane, distillates, equipment and supplies to end users consisting of residential, agricultural, commercial,and industrial customers and to certain resellers in 30 states and the District of Columbia.•Our Refined Products and Renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations, purchases refinedpetroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedules them fordelivery at various locations throughout the country. 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. Intercompany transactions and accountbalances have been eliminated in consolidation. Investments we cannot control, but can exercise significant influence over, are accounted for using theequity method of accounting. We also own an undivided interest in a crude oil pipeline, and include our proportionate share of assets, liabilities, andexpenses related to this pipeline in our consolidated financial statements.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, among others, determining the fair value of assets andliabilities acquired in business combinations, the collectibility of accounts receivable, the recoverability of inventories, useful lives and recoverability ofproperty, plant and equipment and amortizable intangible assets, the impairment of assets, the fair value of asset retirement obligations, the value of equity-based compensation, and accruals for environmental matters. Although we believe these estimates are reasonable, actual results could differ from thoseestimates.Fair Value MeasurementsFair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction betweenmarket participants at the measurement date. Fair value is based upon assumptions that marketF-10Table of Contentsparticipants would use when pricing an asset or liability. We use the following fair value hierarchy, which prioritizes valuation technique inputs used tomeasure 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 and forward commodity contracts. We determine the fair value of all of our derivativefinancial instruments utilizing pricing models for similar instruments. Inputs to the pricing models include publicly available prices and forwardcurves generated from a compilation of data gathered from third parties.•Level 3: Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable inputs (Level3). 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.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 commodity price risk and credit risk. Commodity price risk isthe risk that the market value of crude oil, natural gas liquids, or refined and renewables products will change, either favorably or unfavorably, in response tochanging market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. Proceduresand limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commoditypositions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. Credit risk ismonitored daily and exposure is minimized through customer deposits, restrictions on product liftings, letters of credit, and entering into master nettingagreements that allow for offsetting counterparty receivable and payable balances 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. Revenues for our Water Solutions segment are recognized when we obtain the wastewater at our treatment and disposal facilities.F-11Table of ContentsThe tariffs we charge for our pipeline transportation systems are primarily regulated by the Federal Energy Regulatory Commission. Ourtariffs include provisions which allow us to deduct from our customer’s inventory a small percentage of the products our customers transport on our pipelinesystems. We refer to these product quantities as pipeline loss allowance. We receive pipeline loss allowances from our customers as consideration for productlosses during the transportation of their crude oil within our pipeline system. Our customers are guaranteed delivery of the amount of their injected volumes,net of pipeline loss allowance, irrespective of what our actual product losses may be during the delivery process.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 within 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 during the years ended March 31, 2017, 2016 and 2015 include $4.9 million, $5.8 million and $0.7 million, respectively, associated withthe amortization of a 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 $6.8 million, $6.7 million, and $7.8 million during the years ended March 31, 2017, 2016, and 2015, 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.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 collectibility 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.F-12Table of ContentsOur accounts receivable consist of the following at the dates indicated: March 31, 2017 March 31, 2016Segment GrossReceivable Allowance forDoubtful Accounts GrossReceivable Allowance forDoubtful Accounts (in thousands)Crude Oil Logistics $345,049 $3 $175,341 $8Water Solutions 34,335 2,789 34,952 4,514Liquids 94,390 293 73,478 505Retail Propane 46,329 1,280 31,583 965Refined Products and Renewables 285,664 869 211,259 936Corporate and Other 74 — 1,329 —Total $805,841 $5,234 $527,942 $6,928Changes in the allowance for doubtful accounts are as follows for the periods indicated: Year Ended March 31, 2017 2016 2015 (in thousands)Allowance for doubtful accounts, beginning of period $6,928 $4,367 $2,822Provision for doubtful accounts 1,029 5,628 4,105Write off of uncollectible accounts (2,723) (3,067) (2,560)Allowance for doubtful accounts, end of period $5,234 $6,928 $4,367We did not have any customers that represented over 10% of consolidated revenues for fiscal years 2017, 2016 and 2015.InventoriesWe 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.Inventories consist of the following at the dates indicated: March 31, 2017 2016 (in thousands)Crude oil $146,857 $84,030Natural gas liquids: Propane 38,631 28,639Butane 5,992 8,461Other 6,035 6,011Refined products: Gasoline 193,051 80,569Diesel 98,237 99,398Renewables Ethanol 42,009 40,505Biodiesel 21,410 11,953Other 9,210 8,240Total $561,432 $367,806F-13Table of ContentsInvestments in Unconsolidated EntitiesInvestments we cannot control, but can exercise significant influence over, are accounted for using the equity method of accounting. Investments inpartnerships and limited liability companies, unless our investment is considered to be minor, and investments in unincorporated joint ventures are alsoaccounted for using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on ourconsolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our consolidated balance sheets.Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capitalcontributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is theamount by which our total investment exceeds our proportionate share of the historical net book value of the net assets of the investee. We use thecumulative earnings approach to classify distributions received from unconsolidated entities as either operating activities or investing activities in ourconsolidated statements of cash flows.On April 1, 2016, we sold all of the TransMontaigne Partners L.P. (“TLP”) common units we owned to an affiliate of ArcLight Capital Partners(“ArcLight”) for approximately $112.4 million in cash and recorded a gain on disposal of $104.1 million during the year ended March 31, 2017. Asdiscussed below, on February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began toaccount for our limited partner investment in TLP using the equity method of accounting. Our investment in TLP was included within investments inunconsolidated entities in our March 31, 2016 consolidated balance sheet. As TLP was previously a consolidated entity, our consolidated statement ofoperations for the year ended March 31, 2016 included ten months of TLP’s operations and income attributable to the noncontrolling interests of TLP, andtwo months of our equity in earnings of TLP, the period after the deconsolidation. Also, as part of the deconsolidation of TLP, our previous investments inBattleground Oil Specialty Terminal Company LLC (“BOSTCO”), which owns a refined products storage facility, and Frontera Brownsville LLC (“Frontera”)are no longer disclosed as investments in unconsolidated entities.Our investments in unconsolidated entities consist of the following at the dates indicated: Ownership Date Acquired March 31,Entity Segment Interest (1) or Formed 2017 2016 (in thousands)Glass Mountain Pipeline, LLC (2) Crude Oil Logistics 50% December 2013 $172,098 $179,594E Energy Adams, LLC Refined Products andRenewables 19% December 2013 12,952 12,570Water treatment and disposal facility (3) Water Solutions 50% August 2015 2,147 2,238Victory Propane, LLC Retail Propane 50% April 2015 226 972TLP (4) Refined Products andRenewables 0% July 2014 — 8,301Grassland Water Solutions, LLC (5) Water Solutions 0% June 2014 — 15,875Total $187,423 $219,550 (1)Ownership interest percentages are at March 31, 2017.(2)When we acquired Gavilon, LLC (“Gavilon Energy”), we recorded the investment in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline inOklahoma, at fair value. Our investment in Glass Mountain exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $72.5 million atMarch 31, 2017. This difference relates primarily to goodwill and customer relationships. We amortize the value of the customer relationships and record the expense withinequity in earnings of unconsolidated entities in the consolidated statement of operations.(3)This is an investment in an unincorporated joint venture.(4)On April 1, 2016, we sold all of the TLP common units we owned.(5)On June 3, 2016, we acquired the remaining 65% ownership interest in Grassland Water Solutions, LLC (“Grassland”), and as a result, Grassland was consolidated in ourconsolidated financial statements (see Note 4). On November 29, 2016, we sold Grassland.F-14Table of ContentsThe following table summarizes the cumulative earnings (loss) from our unconsolidated entities and cumulative distributions received from ourunconsolidated entities at March 31, 2017:Entity Cumulative Earnings (Loss) FromUnconsolidated Entities Cumulative DistributionsReceived From Unconsolidated Entities (in thousands)Glass Mountain $8,794 $34,404E Energy Adams, LLC $8,409 $9,094Water treatment and disposal facility $(1) $142Victory Propane, LLC $(1,274) $—Summarized 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, 2017 2016 2017 2016 2017 2016 2017 2016 (in thousands)Glass Mountain$7,450 $7,248 $192,903 $204,020 $1,225 $1,268 $9 $24E Energy Adams, LLC$20,159 $34,477 $94,115 $90,310 $19,204 $14,616 $13,533 $30,730Water treatment and disposal facility$207 $91 $4,082 $4,476 $24 $124 $— $—Victory Propane, LLC$734 $700 $3,605 $2,248 $311 $555 $3,577 $449TLP$— $10,419 $— $652,309 $— $18,812 $— $267,373Grassland$— $2,589 $— $28,150 $— $2,923 $— $20,746Statements of operations: Revenues Cost of Sales Net Income (Loss) March 31, 2017 2016 2015 2017 2016 2015 2017 2016 2015 (in thousands)Glass Mountain$32,622 $35,978 $37,539 $1,797 $1,943 $2,771 $7,219 $11,227 $12,345E Energy Adams, LLC$145,181 $129,533 $159,148 $112,519 $105,161 $117,222 $12,661 $5,796 $24,607Water treatment and disposal facility$1,739 $777 $— $— $— $— $(86) $85 $—Victory Propane, LLC$3,070 $715 $— $1,580 $321 $— $(1,493) $(1,056) $—TLP$— $28,258 $— $— $— $— $— $6,083 $—BOSTCO$— $60,420 $45,067 $— $— $— $— $21,987 $11,074Frontera$— $14,114 $10,643 $— $— $— $— $4,091 $1,352Grassland$1,090 $4,062 $8,326 $— $— $— $(332) $(1,618) $(104)F-15Table of ContentsOther Noncurrent AssetsOther noncurrent assets consist of the following at the dates indicated: March 31, 2017 2016 (in thousands)Loan receivable (1) $40,684 $49,827Line fill (2) 30,628 35,060Tank bottoms (3) 42,044 42,044Other 126,248 49,108Total $239,604 $176,039 (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. At March 31, 2017 and2016, line fill consisted of 427,193 barrels and 487,104 barrels of crude oil, respectively.(3)Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks areremoved from service. At March 31, 2017 and 2016, tank bottoms held in third party terminals consisted of 366,212 barrels and 366,212 barrels of refined products,respectively. 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, 2017 2016 (in thousands)Accrued compensation and benefits $22,227 $40,517Excise and other tax liabilities 64,051 59,455Derivative liabilities 27,622 28,612Accrued interest 44,418 20,543Product exchange liabilities 1,693 5,843Deferred gain on sale of general partner interest in TLP 30,113 30,113Other 17,001 29,343Total $207,125 $214,426F-16Table of ContentsSale of General Partner Interest in TLPAs previously reported, on February 1, 2016, we sold 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 years ended March 31,2017 and 2016, we recognized $30.1 million and $5.0 million, respectively, of the deferred gain in our consolidated statements of operations. Expectedamortization of the remaining deferred gain is as follows (in thousands):Year Ending March 31, 2018$30,113201930,113202030,113202129,593202226,993Thereafter22,494Total$169,419Within 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, $139.3 million, is recorded in other noncurrent liabilities. In addition, we retained TransMontaigne Product Services, LLC,including its marketing business, customer contracts and its line space on the Colonial and Plantation pipelines, which is a significant part of our RefinedProducts and Renewables segment.Property, 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 (gain) loss on disposal or impairment of assets, net. We compute depreciation expense of our property, plant and equipment usingthe straight-line method over the estimated useful lives of the assets (see Note 5).Intangible AssetsOur intangible assets include contracts and arrangements acquired in business combinations, including customer relationships, customercommitments, pipeline capacity rights, rights-of-way and easements, a water facility development agreement, executory contracts and other agreements,covenants not to compete, and trade names. In addition, we capitalize certain debt issuance costs associated with our revolving credit facilities. We amortizethe majority of our intangible assets on a straight-line basis over the estimated useful lives of the assets (see Note 7). We amortize debt issuance costs over theterms of the related debt using a method that approximates the effective interest method.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. In that event, we recognize a loss equal to the amount by which thecarrying 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 relieffrom royalty method and we begin amortizing the trade name over its estimated useful life as a defensive asset. See Note 5 and Note 7 for a further discussionof long-lived asset impairments recognized in the consolidated financial statements.We evaluate equity method investments for impairment when we believe the current fair value may be less than the carrying amount and record animpairment if we believe the decline in value is other than temporary.F-17Table of ContentsGoodwillGoodwill represents the excess of the consideration paid for the acquired businesses over the fair value of the individual assets acquired, net ofliabilities assumed. Business combinations are accounted for using the “acquisition method” (see Note 4). We expect that all of our goodwill at March 31,2017 is deductible for income tax purposes.Goodwill and indefinite-lived intangible assets are not amortized, but instead are evaluated for impairment at least annually. 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 first consider qualitative factors to determine whether it is more likely than not that the fair value of each reportingunit exceeds its carrying amount. If we conclude that it is more likely than not that the fair value of a reporting unit does not exceed its carrying amount, wecalculate the fair value for the reporting unit and compare the amount to its carrying amount, including goodwill. If the fair value of a reporting unit exceedsits carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amount of a reporting unit exceeds its fair value, goodwill isconsidered to be impaired and the goodwill balance is reduced by the difference between the fair value and carrying amount of the reporting unit.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 goodwill impairment assessment included market participant considerations and futureforecasted operating results. Changes in operating results and other assumptions could materially affect these estimates. See Note 6 for a further discussionand 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 and 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.Advance Payments Received from CustomersWe record customer advances on product purchases as a current liability in our consolidated balance sheets.Noncontrolling InterestsNoncontrolling interests represent the portion of certain consolidated subsidiaries that are owned by third parties. Amounts are adjusted by thenoncontrolling interest holder’s proportionate share of the subsidiaries’ earnings or losses each period and any distributions that are paid. Noncontrollinginterests are reported as a component of equity, unless the noncontrolling interest is considered redeemable, in which case the noncontrolling interest isrecorded between liabilities and equity (mezzanine or temporary equity) in our consolidated balance sheet.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 fair value of the assets acquiredand liabilities assumed in a business combination. As discussed in Note 4, certain of our acquisitions are still within this measurement period, and as a result,the acquisition date fair values we have recorded for the assets acquired and liabilities assumed are subject to change.Also as discussed in Note 4, we made certain adjustments during the year ended March 31, 2017 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, 2016.In September 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-16, “Simplifyingthe Accounting Adjustments for Measurement-Period Adjustments.” The ASU requires that an acquirer recognize adjustments to provisional amounts that areidentified during the measurement period in the reporting period in which the adjustment amounts are determined. This ASU requires that the acquirer record,in the sameF-18Table of Contentsperiod’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to theprovisional amounts, calculated as if the accounting had been completed at the acquisition date. The ASU was effective for the Partnership beginning April 1,2016, and required a prospective method of adoption.ReclassificationsCertain line items in our consolidated statement of cash flows were combined and the prior period amounts were combined to be consistent with theclassification methods used in the current fiscal year. These reclassifications did not impact previously reported amounts of cash flows from operating,investing and financing activities in the consolidated statement of cash flows.Recent Accounting PronouncementsIn January 2017, the FASB issued ASU No. 2017-04, “Intangibles-Goodwill and Other.” The ASU simplifies how an entity is required to testgoodwill for impairment by eliminating Step 2 from the goodwill impairment test. Step 2 measures a goodwill impairment loss by comparing the implied fairvalue of a reporting unit’s goodwill with the carrying amount of that goodwill. Rather, we will be required to perform our annual goodwill impairment test bycomparing the fair value of a reporting unit with its carrying amount. In the event the carrying amount exceeds the reporting unit’s fair value, a goodwillimpairment charge for the excess will be recorded (not exceeding the recorded amount of the reporting unit’s goodwill). The ASU is effective for thePartnership beginning April 1, 2020, and requires a prospective method of adoption, although early adoption is permitted for annual goodwill impairmenttests performed on testing dates on or after January 1, 2017. We adopted this ASU effective January 1, 2017 and the adoption did not have any impact on ourgoodwill impairment assessment performed as of January 1, 2017 (see Note 6). In January 2017, the FASB issued ASU No. 2017-01, “Business Combinations.” The ASU clarifies the definition of a business with the objective ofadding guidance to assist entities with evaluating whether acquisition transactions should be accounted for as an asset acquisition or a business combination.The ASU is effective for the Partnership beginning April 1, 2018, and requires a prospective method of adoption, although early adoption is permitted forperiods in which financial statements have not been issued. We adopted this ASU effective January 1, 2017 and applied this guidance to all acquisitiontransactions made after January 1, 2017 (see Note 4).In June 2016, the FASB issued ASU No. 2016-13, “Financial Instruments-Credit Losses.” The ASU requires a financial asset (or a group of financialassets) measured at amortized cost to be presented at the net amount expected to be collected, which would include accounts receivable. The measurement ofexpected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportableforecasts that affect the collectibility of the reported amount. The ASU is effective for the Partnership beginning April 1, 2020, and requires a modifiedretrospective method of adoption, although early adoption is permitted. We are currently in the process of assessing the impact of this ASU on ourconsolidated financial statements.In March 2016, the FASB issued ASU No. 2016-09, “Improvements to Employee Share-Based Payment Accounting.” The ASU simplifies severalaspects of the accounting for share-based payment award transactions, including the classification of awards as either equity or liabilities, classification ofcertain related payments on the statement of cash flows and allowing entities to make a policy decision to either estimate forfeitures each period, as currentlyrequired, or to account for forfeitures as they occur. The ASU is effective for interim and annual periods beginning after December 15, 2016. We adopted thisASU effective April 1, 2017 and elected to account for forfeitures as they occur, utilizing the modified retrospective method of adoption. The adoption didnot have a material impact on our consolidated financial statements.In 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 currently in the process of compiling a database of leases and analyzing each lease to assess the impact under this ASU on our consolidatedfinancial 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. We adopted this ASU effective April 1, 2017. The adoption did not have a materialimpact on our consolidated financial statements.F-19Table of ContentsIn 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 methods of adoption.We are in the process of evaluating our revenue contracts by segment and type to determine the potential impact of adopting this ASU. At this pointin our evaluation process, we have determined that the timing and/or amount of revenue that we recognize on certain contracts may be impacted by theadoption of this ASU; however, we are still in the process of quantifying these impacts and cannot say whether or not they would be material to ourconsolidated financial statements. In addition, we are in the process of implementing appropriate changes to our business processes, systems and controls tosupport recognition and disclosure under this ASU. We continue to monitor additional authoritative or interpretive guidance related to this ASU as itbecomes available, as well as comparing our conclusions on specific interpretative issues to other peers in our industry, to the extent that such information isavailable to us. We currently anticipate utilizing a modified retrospective adoption as of April 1, 2018.Note 3—Income (Loss) Per Common UnitThe following table presents our calculation of basic and diluted weighted average units outstanding for the periods indicated: Year Ended March 31, 2017 2016 2015Weighted average units outstanding during the period: Common units - Basic 108,091,486 104,838,886 86,359,300Effect of Dilutive Securities: Performance units 173,087 — —Warrants 3,586,048 — —Common units - Diluted 111,850,621 104,838,886 86,359,300For the year ended March 31, 2017, the Preferred Units (as defined herein) were considered antidilutive and for the years ended March 31 2017,2016 and 2015, the Service Awards (as defined herein) were considered antidilutive.Our income (loss) per common unit is as follows for the periods indicated: Year Ended March 31, 2017 2016 2015 (in thousands, except unit and per unit amounts)Net income (loss) $143,874 $(187,097) $50,193Less: Net income attributable to noncontrolling interests (6,832) (11,832) (12,887)Net income (loss) attributable to NGL Energy Partners LP 137,042 (198,929) 37,306Less: Distributions to preferred unitholders (30,142) — —Less: Net income allocated to general partner (1) (232) (47,620) (45,700)Less: Net loss allocated to subordinated unitholders (2) — — 3,915Net income (loss) allocated to common unitholders (basic and diluted) $106,668 $(246,549) $(4,479)Basic income (loss) per common unit $0.99 $(2.35) $(0.05)Diluted income (loss) per common unit $0.95 $(2.35) $(0.05)Basic weighted average common units outstanding 108,091,486 104,838,886 86,359,300Diluted weighted average common units outstanding 111,850,621 104,838,886 86,359,300 (1)Net income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are described in Note 11.(2)All outstanding subordinated units converted to common units in August 2014. Since the subordinated units did not share in the distribution of cash generated after June 30,2014, we did not allocate any income or loss after that date to the subordinated unitholders.F-20Table of ContentsDuring the three months ended June 30, 2014, 5,919,346 subordinated units were outstanding and the loss per subordinated unit was $0.68.Note 4—AcquisitionsThe following summarizes our business combinations made during the year ended March 31, 2017:Water Solutions FacilitiesDuring the year ended March 31, 2017, we acquired three water solutions facilities and paid $26.9 million of cash. In addition, we have recordedcontingent consideration liabilities within accrued expenses and other payables and other noncurrent liabilities in our consolidated balance sheet related tofuture royalty payments due to the sellers of one of these facilities. We estimated the contingent consideration based on the contracted royalty rate, which is aflat rate per disposal barrel and percentage of oil revenues, multiplied by the expected disposal volumes and oil revenue for the expected useful life of thefacility and disposal well. This amount was then discounted to present value using our weighted average cost of capital plus a premium representative of theuncertainty associated with the expected disposal volumes and oil revenue. As of the acquisition date, we recorded a contingent liability of $2.6 million.We assumed a land lease with a royalty component as part of the acquisition of one of the facilities. The acquisition method of accounting requiresthat executory contracts with unfavorable terms relative to market conditions at the acquisition date be recorded as liabilities in the acquisition accounting.We recorded a liability to other noncurrent liabilities of $2.8 million related to this lease due to the royalty terms being deemed unfavorable. We willamortize this liability based on the volumes processed by the facility.During the year ended March 31, 2017, we completed the acquisition accounting for one of these water solutions facilities. The following tablesummarizes the final calculation of the fair values of the assets acquired and liabilities assumed (in thousands):Property, plant and equipment$4,436Goodwill8,188Current liabilities(280)Other noncurrent liabilities(2,344)Fair value of net assets acquired$10,000We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for the other two water solutionsfacilities, and as a result, the estimates of fair value at March 31, 2017 are subject to change. The following table summarizes the preliminary estimates of thefair values of the assets acquired and liabilities assumed (in thousands):Property, plant and equipment$14,315Goodwill1,615Intangible assets3,878Current liabilities(34)Other noncurrent liabilities(2,878)Fair value of net assets acquired$16,896Goodwill represents the excess of the consideration paid for the acquired businesses over the fair value of the individual assets acquired, net ofliabilities assumed. Goodwill represents a premium paid to expand the number of our disposal sites in an oilfield production basin currently serviced by us,thereby enhancing our competitive position as a provider of disposal services in this oilfield production basin. We expect that all of the goodwill will bedeductible for federal income tax purposes.The operations of these water solutions facilities have been included in our consolidated statement of operations since their acquisition date. Ourconsolidated statement of operations for the year ended March 31, 2017 includes revenues of $6.2 million and operating income of $2.7 million that weregenerated by the operations of these water solutions facilities.F-21Table of ContentsAcquisition of Remaining Interest in Water Solutions FacilitiesOn September 15, 2016, we acquired the remaining 25% ownership interest in three water solutions facilities and paid $10.0 million of cash. Theacquisition of the remaining interest was accounted for as an equity transaction, no gain or loss was recorded and the carrying value of the noncontrollinginterest was adjusted to reflect the change in ownership interest of the subsidiary. As of the date of the transaction, the 25% interest had a carrying value of$7.4 million.Water Pipeline CompanyAs discussed below, on January 7, 2016, we acquired a 57.125% interest in an existing produced water pipeline company operating in the DelawareBasin portion of West Texas. On June 3, 2016, we acquired an additional 24.5% interest in this water pipeline company as part of the purchase and saleagreement discussed in Note 16. As we control this entity (and continue to retain our controlling financial interest), the acquisition of the additional interestwas accounted for as an equity transaction, no gain or loss was recorded and the carrying value of the noncontrolling interest was adjusted to reflect thechange in ownership interest of the subsidiary. As of the date of the transaction, the 24.5% interest had a carrying value of $5.2 million.GrasslandOn June 3, 2016, we acquired the remaining 65% ownership interest in Grassland (see Note 2). In exchange for this additional interest, we paid $1.0million of cash and assumed an outstanding note payable, which relates to money Grassland previously borrowed from us. Prior to the completion of thistransaction, we accounted for our previously held 35% ownership interest in Grassland using the equity method of accounting (see Note 2). As we owned acontrolling interest in Grassland, we revalued our previously held 35% ownership interest to fair value of $0.8 million and recorded a loss of $14.9 million,which is recorded within revaluation of investments in our consolidated statement of operations. As the amount paid (cash plus the fair value of ourpreviously held ownership interest) was less than the fair value of the assets acquired and liabilities assumed, we recorded a bargain purchase gain of $0.6million within revaluation of investments in our consolidated statement of operations.The following table summarizes the fair values of the assets acquired and liabilities assumed (in thousands):Current assets$1,713Property, plant and equipment8,874Intangible assets14,472Current liabilities(2,765)Notes payable-affiliate(19,900)Fair value of net assets acquired$2,394On November 29, 2016, we sold Grassland. We received proceeds of $22.0 million and recorded a loss on the sale of $2.3 million within (gain) losson disposal or impairment of assets, net in our consolidated statement of operations during the year ended March 31, 2017. The operations of Grassland havebeen included in our consolidated statement of operations for the period from June 3, 2016 to November 29, 2016. Our consolidated statement of operationsfor the year ended March 31, 2017 includes revenues of $6.1 million and operating income of $5.1 million that were generated by the operations ofGrassland.Retail Propane BusinessesDuring the year ended March 31, 2017, we acquired four retail propane businesses and paid $80.6 million of cash and issued 218,617 common units,valued at $3.9 million. The agreements for these acquisitions contemplate post-closing payments for certain working capital items.F-22Table of ContentsDuring the year ended March 31, 2017, we completed the acquisition accounting for one of these retail propane businesses. The following tablesummarizes the final calculation of the fair values of the assets acquired and liabilities assumed (in thousands):Current assets$153Property, plant and equipment933Goodwill159Intangible assets500Current liabilities(59)Other noncurrent liabilities(62)Fair value of net assets acquired$1,624We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for the other three retail propanebusinesses, and as a result, the estimates of fair value at March 31, 2017 are subject to change. The following table summarizes the preliminary estimates ofthe fair values of the assets acquired and liabilities assumed (in thousands):Current assets$2,825Property, plant and equipment38,047Goodwill2,896Intangible assets46,830Current liabilities(5,621)Other noncurrent liabilities(2,145)Fair value of net assets acquired$82,832Goodwill represents the excess of the consideration paid for the acquired businesses 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 and the ability to expand intonew markets. We expect that all of the goodwill will be deductible for federal income tax purposes.The operations of these retail propane businesses have been included in our consolidated statement of operations since their acquisition date. Ourconsolidated statement of operations for the year ended March 31, 2017 includes revenues of $33.9 million and operating income of $4.8 million that weregenerated by the operations of three of these retail propane businesses. The revenues and operating income of the fourth retail propane business acquisitionare not considered material and have been included with existing businesses.The following summarizes our significant asset acquisitions made during the year ended March 31, 2017:Natural Gas Liquids FacilitiesOn January 9, 2017, we acquired a natural gas liquids terminal that supports refined products blending in Port Hudson, Louisiana, and a natural gasliquids and condensate facility in Kingfisher, Oklahoma and paid $50.6 million of cash.We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in this acquisition, and as a result,the estimates of fair value at March 31, 2017 are subject to change. The following table summarizes the preliminary estimates of the fair values of the assetsacquired and liabilities assumed (in thousands):Property, plant and equipment$27,725Land637Intangible assets22,245Fair value of net assets acquired$50,607The following summarizes certain adjustments made during the year ended March 31, 2017 to the preliminary purchase price allocation of acquisitions madeprior to April 1, 2016:F-23Table of ContentsWater Pipeline CompanyDuring the year ended March 31, 2017, we finalized the purchase price accounting for the 57.125% interest acquired in a water pipeline company onJanuary 7, 2016. The following table summarizes adjustments made to the preliminary estimates as well as the final amounts of the fair values of the assetsacquired and liabilities assumed (in thousands): Final AtMarch 31, 2017 Estimated AtMarch 31, 2016 ChangeProperty, plant and equipment (1)$11,066 $12,208 $(1,142)Goodwill (2)$5,866 $5,561 $305Intangible assets (1)$7,492 $6,350 $1,142Current liabilities (3)$(1,152) $(1,000) $(152)Other noncurrent liabilities (2)(3)$(2,753) $(2,600) $(153) (1)During the year ended March 31, 2017, we recorded an adjustment to reclassify property, plant and equipment to intangible assets, in order to present the fair value of theacquired rights-of-way as a finite-lived asset, which is consistent with our historical accounting policies.(2)During the year ended March 31, 2017, we recorded an adjustment to other noncurrent liabilities and goodwill to recognize an asset retirement obligation.(3)During the year ended March 31, 2017, we recorded an adjustment to reclassify other noncurrent liabilities to current liabilities for the current portion of a contingentconsideration liability.In addition, we paid $1.0 million in cash to the seller during the year ended March 31, 2017 for consideration that was held back at the acquisitiondate, which we recorded as a liability within accrued expenses and other payables in our consolidated balance sheet. There were no other adjustments to thefair value of assets acquired and liabilities assumed during the year ended March 31, 2017.Delaware Basin Water Solutions FacilitiesDuring the year ended March 31, 2017, we finalized the purchase price accounting for the four saltwater disposal facilities and a 50% interest in anadditional saltwater disposal facility in the Delaware Basin of the Permian Basin in Texas we acquired on August 24, 2015. There were no adjustments to thefair value of assets acquired and liabilities assumed during the year ended March 31, 2017.Water Solutions FacilitiesDuring the year ended March 31, 2017, we finalized the purchase price accounting for ten water facilities acquired under the developmentagreement during the year ended March 31, 2016. During the year ended March 31, 2017, we received additional information and recorded an adjustment of$1.4 million to property, plant and equipment and goodwill to recognize the fair value of additional assets that we acquired. In addition, we paid $1.0 millionin cash to the seller during the year ended March 31, 2017 for consideration that was held back at the acquisition date, which we recorded as a liability withinaccrued expenses and other payables in our consolidated balance sheet. There were no other adjustments to the fair value of assets acquired and liabilitiesassumed during the year ended March 31, 2017.Retail Propane BusinessesDuring the year ended March 31, 2017, we finalized the purchase price accounting for six retail propane businesses we acquired during the yearended March 31, 2016. During the year ended March 31, 2017, we received additional information and recorded an adjustment of $0.1 million to workingcapital, property, plant and equipment and goodwill to recognize the fair value of additional assets that we acquired. In addition, we paid $1.1 million in cashto the sellers during the year ended March 31, 2017 for consideration that was held back at the acquisition date, which we recorded as a liability withinaccrued expenses and other payables in our consolidated balance sheet.F-24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 2017 2016 (in thousands)Natural gas liquids terminal and storage assets 2-30 years $207,825 $169,758Pipeline and related facilities 30-40 years 248,582 —Refined products terminal assets and equipment 20 years 6,736 6,844Retail propane equipment 2-30 years 239,417 201,312Vehicles and railcars 3-25 years 198,480 185,547Water treatment facilities and equipment 3-30 years 557,100 508,239Crude oil tanks and related equipment 2-40 years 203,003 137,894Barges and towboats 5-40 years 91,037 86,731Information technology equipment 3-7 years 43,880 38,653Buildings and leasehold improvements 3-40 years 161,957 118,885Land 56,545 47,114Tank bottoms and line fill (1) 24,462 20,355Other 3-30 years 39,132 11,699Construction in progress 87,711 383,032 2,165,867 1,916,063Accumulated depreciation (375,594) (266,491)Net property, plant and equipment $1,790,273 $1,649,572 (1)Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost. We recover tank bottoms when the storage tanks areremoved from service. Line fill, which represents our portion of the product volume required for the operation of the proportionate share of a pipeline we own, is recorded athistorical cost.The following table summarizes depreciation expense and capitalized interest expense for the periods indicated: Year Ended March 31, 2017 2016 2015 (in thousands)Depreciation expense $119,707 $136,938 $105,687Capitalized interest expense $6,887 $4,012 $113F-25Table of ContentsWe record losses (gains) from the sales of property, plant and equipment and any write-downs in value due to impairment within (gain) loss ondisposal or impairment of assets, net in our consolidated statement of operations. The following table summarizes the losses (gains) on the disposal orimpairment of property, plant and equipment, by segment, for the periods indicated: Year Ended March 31, 2017 2016 2015 (in thousands)Crude Oil Logistics (1) $8,124 $54,952 $3,759Water Solutions 7,169 1,485 5,707Liquids (2) 92 (2,992) 21,590Retail Propane (287) (137) 282Refined Products and Renewables 91 3,080 —Corporate (1) — (136)Total $15,188 $56,388 $31,202 (1)Amounts for the year ended March 31, 2017 primarily relate to losses from the sale of certain assets, including excess pipe. Amounts for the year ended March 31, 2016primarily relate to the write-down of pipe we no longer expected to use in our originally planned pipeline from Colorado to Oklahoma.(2)Amounts for the year ended March 31, 2015 primarily relate to the sale of a natural gas liquid terminal.Note 6—GoodwillThe following table summarizes changes in goodwill by segment for the periods indicated (in thousands): Crude OilLogistics WaterSolutions Liquids RetailPropane RefinedProducts andRenewables Total (in thousands)Balances at March 31, 2015$579,846 $523,790 $266,046 $122,382 $66,169 $1,558,233Acquisitions (Note 4)— 147,322 — 5,046 — 152,368Disposals (Note 2)— — — — (15,042) (15,042)Initial impairment estimate— (380,197) — — — (380,197)Balances at March 31, 2016579,846 290,915 266,046 127,428 51,127 1,315,362Revisions to acquisition accounting (Note 4)— (1,110) — (56) — (1,166)Acquisitions (Note 4)— 9,803 — 3,055 — 12,858Adjustment to initial impairment estimate— 124,662 — — — 124,662Balances at March 31, 2017$579,846 $424,270 $266,046 $130,427 $51,127 $1,451,716Fiscal Year 2017 Goodwill Impairment AssessmentWe performed a qualitative assessment as of January 1, 2017 to determine whether it was more likely than not that the fair value of each reportingunit was greater than the carrying value of the reporting unit. Based on these qualitative assessments, we determined that the fair value of each of thesereporting units was more likely than not greater than the carrying value of the reporting units.Fiscal Year 2016 Goodwill Impairment AssessmentDue 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 valueof cash 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 andF-26Table of Contentsmaintenance capital expenditures. We also considered expectations regarding: (i) expected disposal volumes, which have continued in spite of the lowercrude oil price environment as oilfield producers have focused on their most productive properties and have continued to deliver disposal volumes to ourfacilities, 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 reports issued by independent third parties projecting crude oil prices through 2018. We assumed an approximate $1/barrel increase each quarterfor the periods beyond those represented in the reports, with crude oil reaching $65/barrel by the fourth quarter of 2021. We used a price of $32/barrel for thefourth quarter of 2016, the starting point of our cash flow projections. We kept prices constant at $65/barrel for periods in our model beyond 2021. Consistentwith observed disposal volume trends, the disposal volumes were based on an expectation of a certain amount of production returning at certain crude oilprice levels. For expenses, we assumed an increase consistent with the increase in disposal volumes. The discount rate used in our discounted cash flowmethod was calculated by using the average of the range of discount rates from a recent water solutions transaction similar in size to our Water Solutionsreporting unit. The discounted cash flow results indicated that the estimated fair value of our Water Solutions reporting unit was greater than its carryingvalue 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 carrying 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 Solutions reporting unit was less than its carrying value byapproximately 11% at March 31, 2016.During the year ended March 31, 2016, we recorded an estimated goodwill impairment charge of $380.2 million, which was recorded within (gain)loss on disposal or impairment of assets, net in our consolidated statements of operations. This was an initial estimate pending the completion of valuationwork being performed for us by a third party valuation firm. At March 31, 2016, our Water Solutions reporting units had a goodwill balance of $290.9million.During the three months ended June 30, 2016, we finalized our goodwill impairment analysis, with the assistance of a third party valuation firm. As aresult of finalizing our analysis, we determined that we needed to reverse $124.7 million of the previously recorded goodwill impairment estimate recordedduring the year ended March 31, 2016. The adjustment was due primarily to the change in the fair value of our customer relationship intangible assets. Withthe assistance of the third party valuation firm, inputs such as revenue growth rates and attrition rates related to existing customers were refined to bettercorrelate with our historical revenue growth and attrition rates of our existing customers in our Water Solutions reporting unit. This change resulted in a lowerfair value allocated to customer relationships and higher value to goodwill than in our preliminary calculation. We recorded the adjustment within (gain) losson disposal or impairment of assets, net in our consolidated statement of operations. At June 30, 2016, our Water Solutions reporting units had a goodwillbalance of $423.7 million.For our other reporting units, we performed a qualitative assessment as of January 1, 2016 to determine whether it was more likely than not that thefair value of each reporting unit was greater than the carrying value of the reporting unit. Based on these qualitative assessments, we determined that the fairvalue of each of these reporting units was more likely than not greater than the carrying value of the reporting units.F-27Table of ContentsNote 7—Intangible AssetsOur intangible assets consist of the following at the dates indicated: March 31, 2017 March 31, 2016Description AmortizableLives Gross CarryingAmount AccumulatedAmortization Net Gross CarryingAmount AccumulatedAmortization Net (in thousands)Amortizable: Customer relationships 3-20 years $906,782 $316,242 $590,540 $852,118 $233,838 $618,280Customer commitments 10 years 310,000 12,917 297,083 — — —Pipeline capacity rights 30 years 161,785 11,652 150,133 119,636 6,559 113,077Rights-of-way and easements 1-40 years 63,402 2,154 61,248 — — —Water facility developmentagreement 5 years — — — 14,000 7,700 6,300Executory contracts and otheragreements 3-30 years 29,036 20,457 8,579 23,920 21,075 2,845Non-compete agreements 2-32 years 32,984 17,762 15,222 20,903 13,564 7,339Trade names 1-10 years 15,439 13,396 2,043 15,439 12,034 3,405Debt issuance costs (1) 5 years 38,983 20,025 18,958 39,942 22,108 17,834Total amortizable 1,558,411 414,605 1,143,806 1,085,958 316,878 769,080Non-amortizable: Customer commitments (2) — — — 310,000 — 310,000Rights-of-way and easements(2) — — — 47,190 — 47,190Trade names 20,150 — 20,150 22,620 — 22,620Total non-amortizable 20,150 — 20,150 379,810 — 379,810Total $1,578,561 $414,605 $1,163,956 $1,465,768 $316,878 $1,148,890(1)Includes debt issuance costs related to the Revolving Credit Facility (as defined herein). Debt issuance costs related to fixed-rate notes are reported as a reduction of thecarrying amount of long-term debt. We incurred $9.7 million in debt issuance costs related to the February 2017 amendment and restatement of our Credit Agreement (asdefined herein).(2)Amounts moved to the amortizable section above due to the related assets being placed in service during the year ended March 31, 2017.The weighted-average remaining amortization period for intangible assets is approximately 12 years.Write off of Intangible AssetsIn connection with the amendment and restatement of our Credit Agreement (as defined herein) in February 2017, we wrote off $4.5 million ofdeferred debt issuance costs (see Note 8). This loss is reported within gain on early extinguishment of liabilities, net in our consolidated statement ofoperations. During the year ended March 31, 2017, we wrote-off $5.2 million related to the value of an indefinite-lived trade name intangible asset inconjunction with finalizing our goodwill impairment analysis (see Note 6). In addition, as a result of terminating the development agreement in the WaterSolutions segment in June 2016 (see Note 16), we incurred a loss of $5.8 million to write off the water facility development agreement. These two losses arereported within (gain) loss on disposal or impairment of assets, net in our consolidated statement of operations.Amortization expense is as follows for the periods indicated: Year Ended March 31,Recorded In 2017 2016 2015 (in thousands)Depreciation and amortization $103,498 $91,986 $88,262Cost of sales 6,828 6,700 7,767Interest expense 4,471 8,942 5,722Total $114,797 $107,628 $101,751F-28Table of ContentsExpected amortization of our intangible assets is as follows (in thousands):Year Ending March 31, 2018$135,4722019128,4822020124,8222021111,714202296,814Thereafter546,502Total$1,143,806 Note 8—Long-Term DebtOur long-term debt consists of the following at the dates indicated: March 31, 2017 March 31, 2016 FaceAmount UnamortizedDebt IssuanceCosts (1) BookValue FaceAmount UnamortizedDebt IssuanceCosts (1) BookValue (in thousands)Revolving credit facility: Expansion capital borrowings $— $— $— $1,229,500 $— $1,229,500Working capital borrowings 814,500 — 814,500 618,500 — 618,500Senior secured notes 250,000 (4,559) 245,441 250,000 (3,166) 246,834Senior notes 5.125% Notes due 2019 379,458 (3,191) 376,267 388,467 (4,681) 383,7866.875% Notes due 2021 367,048 (5,812) 361,236 388,289 (7,545) 380,7447.500% Notes due 2023 700,000 (11,329) 688,671 — — —6.125% Notes due 2025 500,000 (8,567) 491,433 — — —Other long-term debt 15,525 — 15,525 61,488 (108) 61,380 3,026,531 (33,458) 2,993,073 2,936,244 (15,500) 2,920,744Less: Current maturities 29,590 — 29,590 7,907 — 7,907Long-term debt $2,996,941 $(33,458) $2,963,483 $2,928,337 $(15,500) $2,912,837 (1)Debt issuance costs related to the Revolving Credit Facility (as defined herein) are reported within intangible assets, rather than as a reduction of the carrying amount of long-term debt.Amortization expense for debt issuance costs related to long-term debt in the table above was $3.3 million, $4.6 million and $3.0 million during theyears ended March 31, 2017, 2016, and 2015.Expected amortization of debt issuance costs is as follows (in thousands):Year Ending March 31, 2018 $6,4522019 6,3102020 5,3372021 4,9372022 4,355Thereafter 6,067Total $33,458F-29Table of ContentsCredit AgreementIn February 2017, we amended and restated our credit agreement (the “Credit Agreement”) with a syndicate of banks, decreasing our initialborrowing capacity from $2.484 billion to $1.765 billion and extending the term of our facility to October 2021. The Credit Agreement includes a revolvingcredit facility to fund working capital needs (the “Working Capital Facility”) and a revolving credit facility to fund acquisitions and expansion projects (the“Expansion Capital Facility,” and together with the Working Capital Facility, the “Revolving Credit Facility”). Our Revolving Credit Facility includes an“accordion” feature that allows us to increase the capacity by $300 million if new lenders wish to join the syndicate or if current lenders wish to increase theircommitments and also allows us to reallocate amounts between the Expansion Capital Facility and Working Capital Facility. The amended facility alsoincludes a new senior secured leverage ratio which cannot be greater than 3.5 to 1 as of the last day of the fiscal quarter. The deferred debt issuance costsassociated with this amendment and restatement were $9.7 million and are recorded as part of our intangible assets (see Note 7). On March 31, 2017, weamended our Credit Agreement and reduced the maximum senior secured leverage ratio to 3.25 to 1.The Expansion Capital Facility had a total capacity of $765.0 million for cash borrowings at March 31, 2017. At that date, we had no outstandingborrowings on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.0 billion for cash borrowings and letters of credit atMarch 31, 2017. At that date, we had outstanding borrowings of $814.5 million and outstanding letters of credit of $89.2 million on the Working CapitalFacility. Amounts outstanding for letters of credit are not recorded as long-term debt on our consolidated balance sheets, although they decrease ourborrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base” (asdefined 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 October 5, 2021. 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 1.75% per year or(ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.75% per year. The applicable margin is determined based on our consolidated leverage ratio (asdefined in the Credit Agreement). At March 31, 2017, the borrowings under the Credit Agreement had a weighted average interest rate of 3.72%, calculated asthe weighted LIBOR rate of 0.97% plus a margin of 2.50% for the LIBOR and the prime rate of 4.00% plus a margin of 1.50% on alternate base rateborrowings. At March 31, 2017, the interest rate in effect on letters of credit was 2.50%. Commitment fees are charged at a rate ranging from 0.375% to 0.50%on any unused capacity.The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our leverage ratio (as defined in the CreditAgreement) cannot be more than 4.75 to 1 at any quarter end. At March 31, 2017, our leverage ratio was approximately 4.65 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, 2017, our interestcoverage ratio was approximately 3.20 to 1. The Credit Agreement also specifies that our senior secured leverage ratio (as defined in the Credit Agreement)cannot be greater than 3.25 to 1. At March 31, 2017, our senior secured leverage ratio was approximately 0.54 to 1.The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitationson fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain eventsof default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by thePartnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcyor insolvency.At March 31, 2017, we were in compliance with the covenants under the Credit Agreement.Senior Secured NotesOn June 19, 2012, we entered into the Note Purchase Agreement (as amended, the “Senior Secured Notes Purchase Agreement”) whereby we issued$250.0 million of Senior Secured Notes in a private placement (the “Senior Secured Notes”). The Senior Secured Notes bear interest at a fixed rate of 6.65%which is payable quarterly. The Senior Secured Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. InDecember 2015, we amended the Senior Secured Notes Purchase Agreement to change the covenants to mirror the changesF-30Table of Contentsmade 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 1plus an additional 0.5% if our leverage ratio exceeds 4.50 to 1. On March 31, 2017, we amended and restated our Senior Secured Notes Purchase Agreementwith an effective date of December 31, 2016, which conforms to the amended terms of the Credit Agreement. The Senior Secured Notes are secured bysubstantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.The Senior Secured Notes Purchase Agreement contains various customary representations, warranties, and additional covenants that, among otherthings, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create orpermit 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) enterinto transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion ofour assets. In addition, the Senior Secured Notes Purchase Agreement contains similar leverage ratio and interest coverage ratio requirements to those of ourCredit Agreement, which is described above.The Senior Secured Notes Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases tocustomary grace and cure periods): (i) nonpayment of principal or interest, (ii) breach of certain covenants contained in the Senior Secured Notes PurchaseAgreement, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of suchindebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) thefailure of the Senior Secured Notes Purchase Agreement, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respectsand (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of atleast 50.1% in aggregate principal amount of the then outstanding Senior Secured Notes of any series may declare all of the Senior Secured Notes of suchseries to be due and payable immediately.At March 31, 2017, we were in compliance with the covenants under the Senior Secured Notes Purchase Agreement.Senior NotesThe Senior Notes include, as defined below, the 2019 Notes, 2021 Notes, 2023 Notes, and the 2025 Notes (collectively, the “Senior Notes”).IssuancesOn October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”). Interest is payable on April 15 and October 15of each year. We have the right to redeem the 2021 Notes before the maturity date, although we would be required to pay a premium for early redemption.The registration of the 2021 Notes became effective on January 13, 2015. The 2021 Notes mature on October 15, 2021. We have the right to redeem the 2021Notes before the maturity date, although we would be required to pay a premium for early redemption.On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”). Interest is payable on January 15 and July 15 ofeach year. We have the right to redeem the 2019 Notes before the maturity date, although we would be required to pay a premium for early redemption. Theregistration of the 2019 Notes became effective January 13, 2015. The 2019 Notes mature on July 15, 2019. We have the right to redeem the 2019 Notesbefore the maturity date, although we would be required to pay a premium for early redemption.On October 24, 2016, we issued $700.0 million of Senior Notes Due 2023 (the “2023 Notes”) in a private placement. The 2023 Notes bear interest at7.50%, which is payable on May 1 and November 1 of each year, beginning on May 1, 2017. We received net proceeds of $687.9 million, after the initialpurchasers’ discount of $10.5 million and offering costs of $1.6 million. The 2023 Notes mature on November 1, 2023.We have the right to redeem all or a portion of the 2023 Notes at any time on or after November 1, 2019 at 100% of the principal amount of the 2023Notes redeemed plus accrued and unpaid interest. Prior to November 1, 2019, we may redeem all or a portion of the 2023 Notes at a price equal to the “makewhole price” specified in the indenture, plus accrued and unpaid interest.On February 22, 2017, we issued $500.0 million of Senior Notes (the “2025 Notes”) in a private placement. The 2025 Notes bear interest at 6.125%,which is payable on March 1 and September 1 of each year, beginning on September 1, 2017. We received net proceeds of $491.3 million, after the initialpurchasers’ discount of $7.5 million and offering costs of $1.2 million. The 2025 Notes mature on March 1, 2025.F-31Table of ContentsWe have the right to redeem all or a portion of the 2025 Notes at any time on or after March 1, 2020 at fixed redemption prices specified in theindenture, plus accrued and unpaid interest. Prior to March 1, 2020, we may redeem all or a portion of the 2025 Notes at a price equal to the “make wholeprice” specified in the indenture, plus accrued and unpaid interest.The Partnership and NGL Energy Finance Corp. are co-issuers of the Senior Notes, and the obligations under the Senior Notes are fully andunconditionally guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our otherindebtedness, including the Revolving Credit Facility. The indentures governing the Senior Notes contains various customary covenants, including, (i) paydistributions on, purchase or redeem our common equity or purchase or redeem our subordinated debt, (ii) incur or guarantee additional indebtedness or issuepreferred units, (iii) create or incur certain liens, (iv) enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us,(v) consolidate, merge or transfer all or substantially all of our assets, and (vi) engage in transactions with affiliates.Our obligations under the Senior Notes may be accelerated following certain events of default (subject to applicable cure periods), including,without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certainevents of bankruptcy or insolvency.Registration RightsIn connection with the closing of the offering of the 2023 Notes and the 2025 Notes, the Partnership entered into registration rights agreements (the“Registration Rights Agreements”). Under the Registration Rights Agreements, the Partnership agreed to file registration statements with the Securities andExchange Commission (“SEC”) so that holders can exchange the 2023 Notes and the 2025 Notes for registered notes that have substantially identical termsand evidence the same indebtedness as the 2023 Notes and the 2025 Notes. In addition, the subsidiary guarantors agreed to exchange the guarantees relatedto the 2023 Notes and 2025 Notes for registered guarantees having substantially the same terms as the original guarantees. The Partnership is obligated to usetheir commercially reasonable efforts to file exchange offer registration statements with respect to the exchange notes and the exchange guarantees and causesuch exchange offer registration statements to become effective on or prior to 365 days after the closing of these offerings. If the Partnership fails to satisfythese obligations, it will be required to pay to the holders liquidated damages in an amount equal to 0.25% per year on the principal amount held by suchholder during the 90-day period immediately following the occurrence of such registration default, and such amount shall increase by 0.25% per year at theend of such 90-day period.Repurchases of Senior NotesThe following table summarizes repurchases of Senior Notes for the periods indicated: Year Ended March 31, 2017 2016 (in thousands)2019 Notes Notes repurchased $9,009 $11,533Cash paid (excluding payments of accrued interest) $7,099 $6,972Gain on early extinguishment of debt (1) $1,759 $4,483 2021 Notes Notes repurchased $21,241 $61,711Cash paid (excluding payments of accrued interest) $14,094 $36,449Gain on early extinguishment of debt (2) $6,748 $24,049 (1)Gains on the early extinguishment of debt for the 2019 Notes during the years ended March 31, 2017 and 2016 are net of debt issuance costs of $0.2 million and $0.1 million,respectively.(2)Gains on the early extinguishment of debt for the 2021 Notes during the years ended March 31, 2017 and 2016 are net of debt issuance costs of $0.4 million and $1.2 million,respectively.F-32Table of ContentsComplianceAt March 31, 2017, we were in compliance with the covenants under all of the Senior Note indentures.Other Long-Term DebtWe have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection withacquisitions of businesses. These instruments have a principal balance of $8.9 million at March 31, 2017. The implied interest rates of these instrumentsrange from 1.17% to 7.00% per year. We also have certain notes payable related to equipment financing. These instruments have a principal balance of $6.6million at March 31, 2017, and the interest rates on these instruments range from 4.13% to 7.10% per year. Equipment loans totaling $41.7 million were paidoff on March 30, 2017, resulting in a loss on the early extinguishment of debt of $1.6 million, which included $0.1 million of debt issuance costs and $1.5million of prepayment penalties.Debt Maturity ScheduleThe scheduled maturities of our debt are as follows at March 31, 2017:Year Ending March 31, RevolvingCredit Facility Senior Secured Notes Senior Notes OtherLong-TermDebt Total (in thousands)2018 $— $25,000 $— $4,590 $29,5902019 — 50,000 — 3,036 53,0362020 — 50,000 379,458 2,207 431,6652021 — 50,000 — 5,395 55,3952022 814,500 50,000 367,048 238 1,231,786Thereafter — 25,000 1,200,000 59 1,225,059Total $814,500 $250,000 $1,946,506 $15,525 $3,026,531Note 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 2013 to 2016 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.A publicly traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certainqualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinelygenerate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income foreach of the calendar years since our IPO.We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, wedetermine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals orlitigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount ofbenefit to be recognized in the consolidated financial statements. We had no significant uncertain tax positions that required recognition in our consolidatedfinancial statements at March 31, 2017 or 2016.F-33Table of ContentsNote 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, 2016, we finalized the settlement of a contractual dispute and paid approximately $0.5 million at the date ofsettlement and committed to pay approximately $1.1 million in equal annual installments over a period of 11 years beginning on October 15, 2016 andending in October 2026. The next annual installment of this liability is recorded within accrued expenses and other payables and the remaining amount ofthis liability is recorded within other noncurrent liabilities in our consolidated balance sheet.Environmental MattersOur consolidated balance sheet at March 31, 2017 includes a liability, measured on an undiscounted basis, of $2.5 million related to environmentalmatters, which is recorded within accrued expenses and other payables in our consolidated balance sheet. Our operations are subject to extensive federal,state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental lawsand regulations, risks of additional costs 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 other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, andclaims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices,and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materialsdesigned to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk ofenvironmental or other damage is inherent in our business.As previously disclosed, the U.S. Environmental Protection Agency (“EPA”) had informed NGL Crude Logistics, LLC, formerly known as GavilonEnergy, of alleged violations in 2011 by Gavilon Energy of the Clean Air Act’s renewable fuel standards regulations (prior to its acquisition by us inDecember 2013). On October 4, 2016, the U.S. Department of Justice, acting at the request of the EPA, filed a civil complaint in the Northern District of Iowaagainst Gavilon Energy and one of its then suppliers, Western Dubuque Biodiesel LLC (“Western Dubuque”). Consistent with the earlier allegations by theEPA, the civil complaint related to transactions between Gavilon Energy and Western Dubuque and the generation of biodiesel renewable identificationnumbers (“RINs”) sold by Western Dubuque to Gavilon Energy in 2011. On December 19, 2016, we filed a motion to dismiss the complaint. On January 9,2017, the EPA filed an amended complaint. The amended complaint seeks an order declaring Western Dubuque’s RINs invalid and requiring the defendantsto retire an equivalent number of valid RINs and that the defendants pay statutory civil penalties. On January 23, 2017, we filed a motion to dismiss theamended complaint, which was denied on May 24, 2017. Consistent with our position against the previous EPA allegations, and the original complaint, wedeny the allegations in this amended civil complaint and intend to continue vigorously defending ourselves in the civil action. However, at this time we areunable to determine the outcome of this action or its significance to us.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 summarizes changes in our asset retirement obligation, which is reported within other noncurrentliabilities in our consolidated balance sheets (in thousands):Balance at March 31, 2015 $3,899Liabilities incurred 1,486Liabilities settled (191)Accretion expense 380Balance at March 31, 2016 5,574Liabilities incurred 1,703Liabilities assumed in acquisitions 406Liabilities settled (19)Accretion expense 517Balance at March 31, 2017 $8,181In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certainother assets. However, the fair value of the asset retirement obligation cannot currently be reasonably estimated because the settlement dates areindeterminable. We will record an asset retirement obligation for these assets in the periods in which settlement dates are reasonably determinable.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, 2017 (in thousands):Year Ending March 31, 2018$138,4342019114,5242020103,186202189,051202262,213Thereafter79,824Total$587,232Rental expense relating to operating leases was $124.3 million, $125.5 million, and $125.5 million during the years ended March 31, 2017, 2016,and 2015, respectively.F-35Table of ContentsPipeline 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.Under certain agreements we can recover these payments by delivering more than our allotted capacity. The following table summarizes future minimumthroughput payments under these agreements at March 31, 2017 (in thousands):Year Ending March 31, 2018$54,486201953,688202043,85620211,4382022599Total$154,067Construction CommitmentsAt March 31, 2017, we had construction commitments of $30.5 million.Sales 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.At March 31, 2017, we had the following purchase commitments (in thousands): Crude Oil Natural Gas Liquids Value Volume(in barrels) Value Volume(in gallons)Fixed-Price Purchase Commitments 2018 $165,101 3,234 $10,824 23,394 Index-Price Purchase Commitments 2018 $986,080 21,151 $553,838 875,4632019 338,938 7,572 — —2020 298,309 6,833 — —2021 253,558 5,747 — —2022 149,937 3,369 — —Total $2,026,822 44,672 $553,838 875,463F-36Table of ContentsAt March 31, 2017, we had the following sale commitments (in thousands): Crude Oil Natural Gas Liquids Value Volume(in barrels) Value Volume(in gallons)Fixed-Price Sale Commitments 2018 $258,412 4,943 $45,500 71,3042019 — — 1,415 2,1642020 — — 36 59Total $258,412 4,943 $46,951 73,527 Index-Price Sale Commitments 2018 $815,737 16,235 $379,745 488,1322019 94,424 1,825 467 7712020 53,767 1,070 — —Total $963,928 19,130 $380,212 488,903We account for the contracts shown in the tables above using the 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.Contracts in the tables 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 tables above. These contracts are included in the derivative disclosures in Note 12,and represent $38.7 million of our prepaid expenses and other current assets and $27.6 million of our accrued expenses and other payables at March 31,2017.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 has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. Ourgeneral partner is not required to guarantee or pay any of our debts or obligations.General Partner ContributionsIn connection with the issuance of common units for the vesting of restricted units, ATM Program (as definedherein) and the equity issuance in February 2017, as discussed within this note, as well as common units issued for a retail propane acquisition (see Note 4)during the year ended March 31, 2017, we issued 16,026 notional units to our general partner for $0.3 million in order to maintain its 0.1% interest in us.F-37Table of ContentsEquity IssuancesOn August 24, 2016, we entered into an equity distribution agreement in connection with an at-the-market program (the “ATM Program”) pursuantto which we may issue and sell common units for up to $200.0 million in gross proceeds. This ATM Program is registered with the SEC on an effectiveregistration statement on Form S-3. During the year ended March 31, 2017, we sold 3,321,135 common units for net proceeds of $64.4 million (net of offeringcosts of $0.9 million). As of March 31, 2017, approximately $134.7 million remained available for sale under the Partnership’s ATM Program.The following table summarizes our equity issuances (except for issuances under the ATM program described above) for fiscal years 2017 and 2015(in millions, except unit amounts). There were no equity issuances during fiscal year 2016.Issuance Date Type ofOffering Number of Common UnitsIssued GrossProceeds UnderwritingDiscounts andCommissions OfferingCosts NetProceedsJune 23, 2014 Public Offering 8,767,100 $383.2 $12.3 $0.5 $370.4March 11, 2015 Public Offering 6,250,000 $172.3 $1.4 $0.2 $170.7February 22, 2017 Public Offering 10,120,000 $234.3 $11.6 $0.2 $222.5Common 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 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. As the program endedon March 31, 2016, no repurchases were made subsequent to that date.Our DistributionsThe following table summarizes distributions declared on our common units for the last three fiscal years:Date Declared Record Date Payment Date AmountPer Unit Amount Paid toLimited Partners Amount Paid toGeneral Partner (in thousands)April 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 $70July 22, 2016 August 4, 2016 August 12, 2016 $0.3900 $41,146 $71October 20, 2016 November 4, 2016 November 14, 2016 $0.3900 $41,907 $72January 19, 2017 February 3, 2017 February 14, 2017 $0.3900 $42,923 $74April 24, 2017 May 8, 2017 May 15, 2017 $0.3900 $46,870 $80F-38Table of ContentsSeveral 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 EligibleFebruary 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 Payment Date 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 $8,681Class A Convertible Preferred UnitsOn April 21, 2016, we entered into a private placement agreement to issue $200 million of 10.75% Class A Convertible Preferred Units (“PreferredUnits”) to Oaktree Capital Management L.P. and its co-investors (“Oaktree”). On June 23, 2016, the private placement agreement was amended to increasethe aggregate principal amount from $200 million to $240 million. On May 11, 2016, we received an initial $100 million (“initial closing date”) and Oaktreereceived 8,309,237 Preferred Units, and on June 24, 2016, we received the remaining $140 million (“second closing date”) and Oaktree received 11,632,932Preferred Units. In addition, Oaktree received 4,375,112 warrants (1,822,963 at the initial closing date and 2,552,149 at the second closing date) to purchasecommon units at an exercise price of $0.01 per common unit.We will pay a cumulative, quarterly distribution in arrears at an annual rate of 10.75% on the Preferred Units then outstanding in cash, to the extentdeclared by the board of directors of our general partner. To the extent declared, such distributions will be paid for each such quarter within 45 days after eachquarter end.Date Declared Payment Date Amount Paid To Preferred Unitholders (in thousands)July 22, 2016 August 12, 2016 $1,795October 20, 2016 November 14, 2016 $6,449January 19, 2017 February 14, 2017 $6,449April 24, 2017 May 15, 2017 $6,449If the Preferred Unit quarterly distribution is not made in full in cash for any quarter, the Preferred Unit distribution rate will increase by one quarterof a percentage point (0.25%) per year beginning with distributions for the first six-month period that a payment default is in effect, and will further increaseby an additional one quarter of a percentage point (0.25%) beginning with distributions for the next six-month period during which a payment defaultremains in effect. The deficiency rate shall not exceed 11.25% per year; as long as the default is occurring, the amount of accrued but unpaid Preferred Unitquarterly distributions shall increase at an annual rate of 10.75%, compounded quarterly, until paid in full.F-39Table of ContentsThe Preferred Units have no mandatory redemption date but are redeemable, at our election, any time after the first anniversary of the closing date.We have the right to redeem all of the outstanding Preferred Units at a price per Preferred Unit equal to the purchase price multiplied by the redemptionmultiple then in effect. The redemption multiple means (a) 140% for redemptions occurring on or after the first, but prior to the second anniversary of theclosing date, (b) 115% for redemptions occurring on or after the second, but prior to the third anniversary of the closing date, (c) 110% for redemptionsoccurring on or after the third, but prior to the eighth anniversary of the closing date and (d) 101% for redemptions occurring on or after the eighthanniversary of the closing date.At any time after the third anniversary of the initial closing date, the Preferred Unit holders shall have the right to convert all of the outstandingPreferred Units at a price per Preferred Unit equal to the purchase price multiplied by the conversion multiple then in effect, which may be settled in commonunits, cash or a combination, at our discretion. The conversion multiple means if our common units are trading at or above $12.035 (“the initial conversionprice”), the conversion price is not adjusted. However, if the conversion price is less than the initial conversion price, the conversion price will be reset to thegreater of (i) the adjusted volume weighted average price of our common units for the 15 trading days immediately preceding the third anniversary of theclosing date or (ii) $5.00.Upon a change of control of the Partnership, each Preferred Unit holder shall have the right, at its election, to either (i) elect to have its PreferredUnits converted to common units; (ii) if we are the surviving entity of such change of control, it can elect to continue to hold its Preferred Units; or (iii)require us to redeem its Preferred Units for cash equal to (a) prior to the first anniversary of the closing date, 140% of the unit purchase price; (b) on or afterthe first but prior to the second anniversary of the closing date, 130% of the unit purchase price; (c) on or after the second anniversary of the closing date,120% of the unit purchase price; and (d) thereafter, 101% of the unit purchase price. In each case, this amount will include any accrued but unpaiddistributions at the redemption date.Under the private placement agreement, we are required to file within 180 days of the initial closing date a registration statement registering theresales of common units issued or to be issued upon conversion of the Preferred Units or exercise of the warrants and have the registration statement declaredeffective within 360 days after the closing date. We are required to continue to maintain the effectiveness of the registration statement until all securities havebeen sold. The Partnership’s registration statement was declared effective by the SEC on November 23, 2016.The warrants have an eight year term, after which unexercised warrants will expire. The holders of the warrants may convert one-third of the warrantsfrom and after the first anniversary of the original issue date, another one-third of the warrants from and after the second anniversary of the original issue dateand the final one-third may be converted from and after the third anniversary. Upon a change of control or in the event we exercise our redemption right withrespect to the Preferred Units, all unvested warrants shall immediately vest and be exercisable in full.We received net proceeds of $235.0 million (net of offering costs of $5.0 million) in connection with the issuance of the Preferred Units andwarrants. We allocated these net proceeds, on a relative fair value basis, to the Preferred Units ($186.4 million), which includes the value of the beneficialconversion feature, and warrants ($48.6 million). As discussed below, $131.5 million of the amount allocated to the Preferred Units was allocated to theintrinsic value of the beneficial conversion feature. A beneficial conversion feature is defined as a nondetachable conversion feature that is in the money atthe commitment date. Per the applicable accounting guidance, we are required to allocate a portion of the proceeds allocated to the Preferred Units to thebeneficial conversion feature based on the intrinsic value of the beneficial conversion feature. The intrinsic value is calculated at the commitment date basedon the difference between the fair value of the common units at the issuance date (number of common units issuable at conversion multiplied by the per unitvalue of our common units at the issuance date) and the proceeds attributed to the Preferred Units. We record the accretion attributable to the beneficialconversion feature as a deemed distribution using the effective interest method over the three year period prior to the effective dates of the holders’conversion right. Accretion for the beneficial conversion feature was $9.0 million for the year ended March 31, 2017.As discussed above, the Preferred Units are not mandatorily redeemable but are redeemable upon a change of control, which was not certain to occurat the issuance of the Preferred Units. Due to the redemption being conditioned upon an event that is not certain to occur or that is not under our control, weare required to record the value allocated to the Preferred Units, excluding the value of the beneficial conversion feature, between liabilities and equity(mezzanine or temporary equity) in our consolidated balance sheet. The value allocated to the warrants and the beneficial conversion feature was recordedwithin Limited Partners’ equity in our consolidated balance sheet.F-40Table of ContentsAmended and Restated Partnership AgreementOn June 24, 2016, NGL Energy Holdings LLC executed the Third Amended and Restated Agreement of Limited Partnership. The preferences, rights,powers and duties of holders of the Preferred Units are defined in the amended and restated partnership agreement. The Preferred Units rank senior to thecommon units, with respect to the payment of distributions and distribution of assets upon liquidation, dissolution and winding up. The Preferred Units haveno stated maturity and are not subject to mandatory redemption or any sinking fund and will remain outstanding indefinitely unless redeemed by thePartnership or converted into common units at the election of the Partnership or the Preferred Unit holders or in connection with a change of control.Equity-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 upon a change of control, at the discretion of the board of directors of our general partner. No distributions accrue to or are paid on therestricted units during 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”).During the three months ended September 30, 2016, we changed our process for how taxes are withheld upon the vesting of restricted units.Previously, employees could choose to pay cash for their portion of the taxes or have us withhold enough units to meet their tax withholding requirements.Employees could also elect to have the units withheld to exceed the statutory minimums. Now, employees will still be able to pay cash to satisfy their taxobligation or they can elect to sell enough units, through a broker assisted cashless exercise program, to meet their tax obligation. As a result of this changein process, the unvested restricted units and future grants are eligible for equity classification. Prior to this change in process, we classified any ServiceAwards or Performance Awards granted as liabilities and were required to recalculate the fair value of the award at each reporting date. Awards classified asequity are valued only at their grant date and are not revalued at each reporting date. As of June 30, 2016, we had liabilities related to our Service Awards andPerformance Awards of $25.6 million and $1.8 million, respectively, which we reclassified to equity.The following table summarizes the Service Award activity during the years ended March 31, 2017, 2016 and 2015: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 2,297,132Units granted 3,124,600Units vested and issued (2,350,082)Units forfeited (363,150)Unvested Service Award units at March 31, 2017 2,708,500F-41Table of ContentsThe following table summarizes the scheduled vesting of our unvested Service Award units at March 31, 2017:Year Ending March 31, Number of Units2018 878,5002019 915,9502020 911,5502021 2,500Total 2,708,500Service Awards are valued at the closing price as of the grant date less the present value of the expected distribution stream over the vesting periodusing a risk-free interest rate. We record the expense for each Service Award on a straight-line basis over the requisite period for the entire award (that is, overthe requisite service period of the last separately vesting portion of the award), ensuring that the amount of compensation cost recognized at any date at leastequals the portion of the grant-date value of the award that is vested at that date. During the years ended March 31, 2017, 2016 and 2015, we recordedcompensation expense related to Service Award units of $56.2 million, $35.2 million and $32.8 million, respectively.Of the restricted units granted and vested during the year ended March 31, 2017, 1,008,091 units were granted as a bonus for performance during theyear ended March 31, 2016. We accrued expense of $16.8 million during the year ended March 31, 2016 as an estimate of the value of such bonus units thatwould be granted. During the year ended March 31, 2017, we recorded an additional $2.2 million to true up the estimate to the $19.0 million of actualexpense associated with these bonuses. Since the units were not formally granted until August 2016, the full $19.0 million is reflected in the expense duringthe year ended March 31, 2017 in the amounts in the preceding paragraph above.The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at March 31, 2017 (inthousands):Year Ending March 31, 2018 $12,6642019 9,2002020 2,4232021 9Total $24,296During April 2015, our general partner granted Performance Award units to certain employees. The number of Performance Award units that will vestis contingent on the performance of our common units relative to the performance of the other entities in the Index. Performance will be calculated based onthe return on our common units (including changes in the market price of the common units and distributions paid during the performance period) relative tothe returns on the common units of the other entities in the Index. As of March 31, 2017, performance will be measured over the following periods:Vesting Date of Tranche Performance Period for TrancheJuly 1, 2017 July 1, 2014 through June 30, 2017July 1, 2018 July 1, 2015 through June 30, 2018July 1, 2019 July 1, 2016 through June 30, 2019The 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 Total Unitholder Return 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 90th percentile 200%F-42Table of ContentsThe following table summarizes the Performance Award activity for the years ended March 31, 2017, 2016, and 2015:Unvested Performance Award units at March 31, 2015 —Units granted 1,041,073Units vested and issued (349,691)Units forfeited (54,000)Unvested Performance Award units at March 31, 2016 637,382Units granted 932,309Units forfeited (380,691)Unvested Performance Award units at March 31, 2017 1,189,000During the July 1, 2013 through June 30, 2016 performance period, the return on our common units was below the return of the 50th percentile ofour peer companies in the Index. As a result, no units vested on July 1, 2016 and all units with such performance period are considered to be forfeited.The fair value of the Performance Awards is estimated using a Monte Carlo simulation at the grant date. We record the expense for each of thetranches of the Performance Awards on a straight-line basis over the period beginning with the grant date and ending with the vesting date of the tranche.Any Performance Awards that do not become earned Performance Awards shall terminate, expire and otherwise be forfeited by the participants. During theyears ended March 31, 2017 and 2016, we recorded compensation expense related to Performance Award units of $7.2 million and $16.4 million,respectively.The following table summarizes the estimated future expense we expect to record on the unvested Performance Award units at March 31, 2017 (inthousands):Year Ending March 31, 2018 $6,1972019 3,2322020 655Total $10,084The 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 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 a lesseramount. Units withheld 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 awardsunder the LTIP. At March 31, 2017, approximately 2.4 million common units remain available for issuance under the LTIP.Note 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.F-43Table of ContentsCommodity 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, 2017 March 31, 2016 DerivativeAssets DerivativeLiabilities DerivativeAssets DerivativeLiabilities (in thousands)Level 1 measurements $2,590 $(21,113) $47,361 $(3,983)Level 2 measurements 38,729 (27,799) 32,700 (28,612) 41,319 (48,912) 80,061 (32,595) Netting of counterparty contracts (1) (1,508) 1,508 (3,384) 3,384Net cash collateral provided (held) (1,035) 19,604 (18,176) 599Commodity derivatives $38,776 $(27,800) $58,501 $(28,612) (1)Relates to commodity derivative assets and liabilities that are expected to be net settled on an exchange or through a netting arrangement with the counterparty.The following table summarizes the accounts that include our commodity derivative assets and liabilities in our consolidated balance sheets at thedates indicated: March 31, 2017 2016 (in thousands)Prepaid expenses and other current assets $38,711 $58,501Other noncurrent assets 65 —Accrued expenses and other payables (27,622) (28,612)Other noncurrent liabilities (178) —Net commodity derivative asset $10,976 $29,889F-44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 Units(in barrels) Fair ValueofNet Assets(Liabilities) (in thousands)At March 31, 2017: Crude oil fixed-price (1) April 2017–May 2017 (800) $(55)Propane fixed-price (1) April 2017–December 2018 220 1,082Refined products fixed-price (1) April 2017–January 2019 (4,682) (7,729)Refined products index (1) April 2017–December 2017 (18) (103)Other April 2017–March 2022 (788) (7,593)Net cash collateral provided 18,569Net commodity derivative asset $10,976 At March 31, 2016: Cross-commodity (2) April 2016–March 2017 251 $1,663Crude oil fixed-price (1) April 2016–December 2016 (1,583) (3,655)Propane fixed-price (1) April 2016–December 2017 540 (592)Refined products fixed-price (1) April 2016–June 2017 (5,355) 48,557Other April 2016–March 2017 1,493 47,466Net cash collateral held (17,577)Net commodity derivative asset $29,889 (1)We may have fixed price physical purchases, including inventory, offset by floating price physical sales or floating price physical purchases offset by fixed price physicalsales. These contracts are derivatives we have entered into as an economic hedge against the risk of mismatches between fixed and floating price physical obligations.(2)We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. These contracts are derivativeswe have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.The following table summarizes the net (losses) gains recorded from our commodity derivatives to cost of sales in our consolidated statements ofoperations for the periods indicated (in thousands):Year Ended March 31, 2017 $(56,356)2016 $103,2232015 $219,421Credit 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, 2017, 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.F-45Table of ContentsInterest 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 31,2017, we had $814.5 million of outstanding borrowings under our Revolving Credit Facility at a weighted average interest rate of 3.72%.Fair Value of Fixed-Rate NotesThe following table provides fair values estimates of our fixed-rate notes at March 31, 2017 (in thousands):Senior Secured Notes$265,475Senior Notes 2019 Notes$381,5922021 Notes$374,6182023 Notes$723,1882025 Notes$488,333For the Senior Secured Notes, the fair value estimate was developed using observed yields on publicly traded notes issued by us, adjusted fordifferences in the key terms of those notes and the key terms of our notes (examples include differences in the tenor of the debt, credit standing of the issuer,whether the notes are publicly traded, and whether the notes are secured or unsecured). This fair value estimate would be classified as Level 3 in the fair valuehierarchy. For the Senior Notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1 in the fair valuehierarchy.Note 13—SegmentsThe following table summarizes certain financial data related to our segments. Transactions between segments are recorded based on pricesnegotiated between the segments.The “Corporate and Other” category in the table below includes certain corporate expenses that are not allocated to the reportable segments.F-46Table of Contents Year Ended March 31, 2017 2016 2015 (in thousands)Revenues: Crude Oil Logistics: Crude oil sales $1,603,667 $3,170,891 $6,621,871Crude oil transportation and other 70,027 55,882 43,349Elimination of intersegment sales (6,810) (9,694) (29,836)Total Crude Oil Logistics revenues 1,666,884 3,217,079 6,635,384Water Solutions: Service fees 110,049 136,710 105,682Recovered hydrocarbons 31,103 41,090 81,762Water transportation — — 10,760Other revenues 18,449 7,201 1,838Total Water Solutions revenues 159,601 185,001 200,042Liquids: Propane sales 807,172 618,919 1,265,262Butane sales 391,265 317,994 531,548Other product sales 308,031 302,181 580,286Other revenues 32,648 35,943 28,745Elimination of intersegment sales (100,028) (80,558) (162,016)Total Liquids revenues 1,439,088 1,194,479 2,243,825Retail Propane: Propane sales 308,919 248,673 347,575Distillate sales 64,249 64,868 106,037Other revenues 40,038 39,436 35,585Elimination of intersegment sales (97) — —Total Retail Propane revenues 413,109 352,977 489,197Refined Products and Renewables: Refined products sales 8,884,976 6,294,008 6,682,040Renewables sales 447,232 390,753 473,885Service fees 10,963 108,221 76,847Elimination of intersegment sales (469) (870) (1,079)Total Refined Products and Renewables revenues 9,342,702 6,792,112 7,231,693Corporate and Other 844 462 1,916Total revenues $13,022,228 $11,742,110 $16,802,057Depreciation and Amortization: Crude Oil Logistics $54,144 $39,363 $38,626Water Solutions 101,758 91,685 73,618Liquids 19,163 15,642 13,513Retail Propane 42,966 35,992 31,827Refined Products and Renewables 1,562 40,861 32,948Corporate and Other 3,612 5,381 3,417Total depreciation and amortization $223,205 $228,924 $193,949Operating Income (Loss): Crude Oil Logistics $(17,475) $(40,745) $(35,832)Water Solutions 44,587 (313,673) 65,340Liquids 43,252 76,173 45,072Retail Propane 49,255 44,096 64,075Refined Products and Renewables 222,546 226,951 54,567Corporate and Other (87,082) (97,405) (85,802)Total operating income (loss) $255,083 $(104,603) $107,420F-47Table of ContentsThe following table summarizes additions to property, plant and equipment and intangible assets by segment for the periods indicated. Thisinformation has been prepared on the accrual basis, and includes property, plant and equipment and intangible assets acquired in acquisitions. Year Ended March 31, 2017 2016 2015 (in thousands)Crude Oil Logistics $168,053 $447,952 $58,747Water Solutions 109,008 243,308 218,007Liquids 66,864 50,533 211,180Retail Propane 105,476 48,026 54,615Refined Products and Renewables 42,175 25,147 737,672Corporate and Other 2,825 15,172 1,286Total $494,401 $830,138 $1,281,507The following tables summarize long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets bysegment at the dates indicated: March 31, 2017 2016 (in thousands)Long-lived assets, net: Crude Oil Logistics $1,724,805 $1,679,027Water Solutions 1,261,944 1,162,405Liquids 619,204 572,081Retail Propane 547,960 483,330Refined Products and Renewables 215,637 180,783Corporate and Other 36,395 36,198Total $4,405,945 $4,113,824 Total assets: Crude Oil Logistics $2,538,768 $2,197,113Water Solutions 1,301,415 1,236,875Liquids 767,597 693,872Retail Propane 622,859 538,267Refined Products and Renewables 988,073 765,806Corporate and Other 101,667 128,222Total $6,320,379 $5,560,155 Note 14—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 E Energy Adams, LLC. These transactions are reported within cost of sales in our consolidated statements of operations.Certain members of our management and members of their families as well as other associated parties own interests in entities from which we havepurchased products and services and to which we have sold products and services. During the year ended March 31, 2017, $13.4 million of these transactionswere capital expenditures and were recorded as increases to property, plant and equipment.F-48Table of ContentsThe following table summarizes these related party transactions for the periods indicated: Year Ended March 31, 2017 2016 2015 (in thousands)Sales to SemGroup $3,866 $43,825 $88,276Purchases from SemGroup $12,254 $53,209 $130,134Sales to equity method investees $692 $14,836 $14,493Purchases from equity method investees $121,336 $113,780 $149,828Sales to entities affiliated with management $290 $318 $2,151Purchases from entities affiliated with management $15,209 $45,197 $29,419Accounts receivable from affiliates consist of the following at the dates indicated: March 31, 2017 2016 (in thousands)Receivables from SemGroup $6,668 $1,166Receivables from equity method investees 15 14,446Receivables from entities affiliated with management 28 13Total $6,711 $15,625Accounts payable to affiliates consist of the following at the dates indicated: March 31, 2017 2016 (in thousands)Payables to SemGroup $6,571 $1,823Payables to equity method investees 1,306 3,947Payables to entities affiliated with management 41 1,423Total $7,918 $7,193We have a loan receivable of $3.2 million at March 31, 2017 from Victory Propane, LLC with an initial maturity date of March 31, 2021, which canbe extended for successive one-year periods unless one of the parties terminates the loan agreement.We had a loan receivable of $22.3 million at March 31, 2016 from Grassland. During the three months ended June 30, 2016, we received loanpayments of $0.7 million from Grassland in accordance with the loan agreement. On June 3, 2016, we acquired the remaining 65% ownership interest inGrassland (see Note 4) and this loan receivable was eliminated upon consolidation. As a result of the acquisition, we incurred an impairment charge of $1.7million to write down the loan receivable to its fair value.Note 15—Employee Benefit 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 to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. For every dollar thatemployees contribute up to 1% of their eligible compensation (as defined in the plan), we contribute one dollar, plus 50 cents for every dollar employeescontribute between 1% and 6% of their eligible compensation (as defined in the plan).Our matching contributions prior to January 1, 2015 vest over fiveyears and, effective January 1, 2015, our matching contributions vest over two years. Expenses under the plan for the years ended March 31, 2017, 2016 and2015 were $3.4 million, $4.2 million and $3.3 million, respectively.F-49Table of ContentsNote 16—Other MattersTermination of a Storage Sublease AgreementDuring the year ended March 31, 2017, we agreed to terminate a storage sublease agreement that was scheduled to commence in January 2017 andhad a term of five years. For terminating this agreement, the counterparty agreed to pay us a specific amount in five equal payments which began in February2017 and in January of the next four years and removed any future obligations of the Partnership. As a result, we discounted the future payments and recordeda gain of $16.2 million to other income, net in our consolidated statement of operations during the year ended March 31, 2017.Termination of Development AgreementOn June 3, 2016, we entered into a purchase and sale agreement with the counterparty to the development agreement in our Water Solutions segment(see Note 4). Total cash consideration paid under the agreement was $49.6 million and in return we received the following:•Termination of the development agreement (see Note 7);•Additional interest in the water pipeline company we acquired in January 2016 (see Note 4);•Release of contingent consideration liabilities attributed to certain of our water treatment and disposal facilities;•Certain parcels of land and permits to develop saltwater disposal wells and other parcels of land containing water wells and equipment; and•A two-year non-compete agreement with the counterparty.We accounted for the transaction as an acquisition of assets. Acquiring assets in groups requires not only ascertaining the cost of the asset (or netasset) group but also allocating that cost to the individual assets (or individual assets and liabilities) that make up the group. The cost of a group of assetsacquired in an asset acquisition shall be allocated to the individual assets acquired or liabilities assumed/released based on their relative fair values and shallnot give rise to goodwill or bargain purchase gains. We allocated $1.2 million of the total consideration to property, plant and equipment, $3.3 million tointangible assets, $2.8 million to noncontrolling interest, $25.5 million to the release of contingent consideration liabilities and $16.9 million to thetermination of the development agreement. We recorded a $21.3 million gain on the release of $46.8 million of contingent consideration liabilities, whichwas recorded within gain on early extinguishment of liabilities, net in our consolidated statement of operations during the year ended March 31, 2017. Forthe termination of the development agreement, we recorded a loss of $22.7 million, which included the carrying value of the development agreement assetthat was written off (see Note 7). This loss was recorded within (gain) loss on disposal or impairment of assets, net in our consolidated statement of operationsduring the year ended March 31, 2017.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, net in our consolidated statement of operations, net of certain project abandonment costs.Note 17—Quarterly Financial Data (Unaudited)The following tables summarize our unaudited quarterly financial data. 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 isF-50Table of Contentsalso subject to seasonal fluctuations, as demand for propane and butane is typically higher during the winter months. Our operating revenues from our othersegments are less weather sensitive. Additionally, the acquisitions described in Note 4 impact the comparability of the quarterly information within the year,and year to year. Quarter Ended Year Ended June 30, 2016 September 30, 2016 December 31, 2016 March 31, 2017 March 31, 2017 (in thousands, except unit and per unit amounts)Total revenues$2,721,970 $3,045,538 $3,406,641 $3,848,079 $13,022,228Total cost of sales$2,566,440 $2,928,730 $3,228,022 $3,598,717 $12,321,909Net income (loss)$182,753 $(66,658) $1,293 $26,486 $143,874Net income (loss) attributable to NGL Energy Partners LP$176,920 $(66,599) $976 $25,745 $137,042Basic income (loss) per common unit$1.66 $(0.71) $(0.07) $0.14 $0.99Diluted income (loss) per common unit$1.38 $(0.71) $(0.07) $0.14 $0.95Basic weighted average common units outstanding104,169,573 106,186,389 107,966,901 114,131,764 108,091,486Diluted weighted average common units outstanding128,453,733 106,186,389 107,966,901 120,198,802 111,850,621 Quarter Ended Year Ended June 30, 2015 September 30, 2015 December 31, 2015 March 31, 2016 March 31, 2016 (in thousands, except unit and per unit amounts)Total revenues$3,538,469 $3,193,195 $2,685,006 $2,325,440 $11,742,110Total cost of sales$3,322,551 $3,005,826 $2,433,500 $2,077,160 $10,839,037Net (loss) income$(25,007) $(6,100) $50,995 $(206,985) $(187,097)Net (loss) income attributable to NGL Energy Partners LP$(29,357) $(9,597) $44,157 $(204,132) $(198,929)Basic (loss) income per common unit$(0.43) $(0.25) $0.27 $(1.94) $(2.35)Diluted (loss) income per common unit$(0.43) $(0.25) $0.22 $(1.94) $(2.35)Basic weighted average common units outstanding103,888,281 105,189,463 105,338,200 104,930,260 104,838,886Diluted weighted average common units outstanding103,888,281 105,189,463 106,194,547 104,930,260 104,838,886The following summarizes significant items recognized during the years ended March 31, 2017 and 2016:Year Ended March 31, 2017•On April 1, 2016, we sold all of the TLP common units we owned and recorded a gain (see Note 2);•On June 3, 2016, we recorded a gain on the release of contingent consideration liabilities and a loss for the termination of the developmentagreement (see Note 16);•On June 3, 2016, we acquired the remaining ownership interest in Grassland and revalued our previously held ownership interest to fair valueand recorded a loss (see Note 2);•During the first quarter of fiscal year 2017, we recorded an adjustment of the previously recorded goodwill impairment charge estimaterecognized during the three months ended March 31, 2016 (see Note 6);•During the third quarter of fiscal year 2017, we agreed to terminate a storage sublease agreement that was scheduled to commence in January2017 and recorded a gain (see Note 16);•On October 24, 2016 and February 22, 2017, we issued the 2023 Notes and 2025 Notes, respectively (see Note 8); and•During the first and fourth quarters of fiscal year 2017, we repurchased a portion of our 2019 Notes and 2021 Notes and recorded a net gain onthe early extinguishment of these notes (see Note 8).Year Ended March 31, 2016•On February 1, 2016, we sold our general partner interest in TLP and recorded a gain (see Note 2);•During the fourth quarter of fiscal year 2016, we recorded a preliminary goodwill impairment charge (see Note 6);F-51Table of Contents•During the fourth quarter of fiscal year 2016, we recorded write-downs and impairments of certain property, plant and equipment and otherassets of $64.7 million; and•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 these notes (see Note 8).Note 18—Consolidating Guarantor and Non-Guarantor Financial InformationCertain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the Senior Notes (see Note 8). Pursuantto Rule 3-10 of Regulation S-X, we have presented in columnar format the consolidating financial information for NGL Energy Partners LP (Parent), NGLEnergy Finance Corp., the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below. NGLEnergy Partners LP and NGL Energy Finance Corp. are co-issuers of the Senior Notes. Since NGL Energy Partners LP received the proceeds from the issuanceof the Senior Notes, all activity has been reflected in the NGL Energy Partners LP (Parent) column 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 Senior Notes.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.For purposes of the tables below, (i) the consolidating financial information is presented on a legal entity basis, (ii) investments in consolidatedsubsidiaries are accounted for as equity method investments, and (iii) contributions, distributions, and advances to (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-52Table of ContentsConsolidating Balance Sheet(in Thousands) March 31, 2017 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments ConsolidatedASSETS CURRENT ASSETS: Cash and cash equivalents $6,257 $— $2,903 $3,104 $— $12,264Accounts receivable-trade, net of allowance fordoubtful accounts — — 795,479 5,128 — 800,607Accounts receivable-affiliates — — 6,711 — — 6,711Inventories — — 560,769 663 — 561,432Prepaid expenses and other current assets — — 102,703 490 — 103,193Total current assets 6,257 — 1,468,565 9,385 — 1,484,207PROPERTY, PLANT AND EQUIPMENT, net ofaccumulated depreciation — — 1,725,383 64,890 — 1,790,273GOODWILL — — 1,437,759 13,957 — 1,451,716INTANGIBLE ASSETS, net of accumulatedamortization — — 1,149,524 14,432 — 1,163,956INVESTMENTS IN UNCONSOLIDATEDENTITIES — — 187,423 — — 187,423NET INTERCOMPANY RECEIVABLES(PAYABLES) 2,424,730 — (2,408,189) (16,541) — —INVESTMENTS IN CONSOLIDATEDSUBSIDIARIES 1,978,158 — 47,598 — (2,025,756) —LOAN RECEIVABLE-AFFILIATE — — 3,200 — — 3,200OTHER NONCURRENT ASSETS — — 239,436 168 — 239,604Total assets $4,409,145 $— $3,850,699 $86,291 $(2,025,756) $6,320,379LIABILITIES AND EQUITY CURRENT LIABILITIES: Accounts payable-trade $— $— $657,077 $944 $— $658,021Accounts payable-affiliates 1 — 7,907 10 — 7,918Accrued expenses and other payables 42,150 — 164,012 963 — 207,125Advance payments received from customers — — 35,107 837 — 35,944Current maturities of long-term debt 25,000 — 4,211 379 — 29,590Total current liabilities 67,151 — 868,314 3,133 — 938,598LONG-TERM DEBT, net of debt issuance costsand current maturities 2,138,048 — 824,370 1,065 — 2,963,483OTHER NONCURRENT LIABILITIES — — 179,857 4,677 — 184,534CLASS A 10.75% CONVERTIBLE PREFERREDUNITS 63,890 — — — — 63,890REDEEMABLE NONCONTROLLINGINTEREST — — — 3,072 — 3,072EQUITY: Partners’ equity 2,140,056 — 1,979,785 74,545 (2,052,502) 2,141,884Accumulated other comprehensive loss — — (1,627) (201) — (1,828)Noncontrolling interests — — — — 26,746 26,746Total equity 2,140,056 — 1,978,158 74,344 (2,025,756) 2,166,802Total liabilities and equity $4,409,145 $— $3,850,699 $86,291 $(2,025,756) $6,320,379F-53Table of ContentsConsolidating Balance Sheet(in Thousands) March 31, 2016 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments ConsolidatedASSETS CURRENT ASSETS: Cash and cash equivalents $25,749 $— $784 $1,643 $— $28,176Accounts receivable-trade, net of allowance fordoubtful accounts — — 516,362 4,652 — 521,014Accounts receivable-affiliates — — 15,625 — — 15,625Inventories — — 367,250 556 — 367,806Prepaid expenses and other current assets — — 94,426 1,433 — 95,859Total current assets 25,749 — 994,447 8,284 — 1,028,480PROPERTY, PLANT AND EQUIPMENT, net ofaccumulated depreciation — — 1,568,488 81,084 — 1,649,572GOODWILL — — 1,313,364 1,998 — 1,315,362INTANGIBLE ASSETS, net of accumulatedamortization — — 1,146,355 2,535 — 1,148,890INVESTMENTS IN UNCONSOLIDATEDENTITIES — — 219,550 — — 219,550NET INTERCOMPANY RECEIVABLES(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) $5,560,155LIABILITIES 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 from customers — — 55,737 448 — 56,185Current maturities of long-term debt — — 7,109 798 — 7,907Total current liabilities 16,888 — 684,339 4,790 — 706,017LONG-TERM DEBT, net of debt issuance costsand current maturities 1,011,365 — 1,894,428 7,044 — 2,912,837OTHER NONCURRENT LIABILITIES — — 246,695 541 — 247,236EQUITY: Partners’ equity 1,656,358 — 1,254,384 80,090 (1,334,317) 1,656,515Accumulated other comprehensive loss — — (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) $5,560,155F-54Table of ContentsConsolidating Statement of Operations(in Thousands) Year Ended March 31, 2017 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated REVENUES $— $— $12,988,467 $37,155 $(3,394) $13,022,228COST OF SALES — — 12,316,563 8,740 (3,394) 12,321,909OPERATING COSTS AND EXPENSES: Operating — — 296,002 11,923 — 307,925General and administrative — — 115,753 813 — 116,566Depreciation and amortization — — 214,082 9,123 — 223,205Gain on disposal or impairment of assets, net — — (209,101) (76) — (209,177)Revaluation of liabilities — — 6,305 412 — 6,717Operating Income — — 248,863 6,220 — 255,083OTHER INCOME (EXPENSE): Equity in earnings of unconsolidated entities — — 3,084 — — 3,084Revaluation of investments — — (14,365) — — (14,365)Interest expense (91,259) — (59,025) (787) 593 (150,478)Gain on early extinguishment of liabilities, net 8,507 — 16,220 — — 24,727Other income, net — — 28,292 63 (593) 27,762(Loss) Income Before Income Taxes (82,752) — 223,069 5,496 — 145,813INCOME TAX EXPENSE — — (1,939) — — (1,939)EQUITY IN NET INCOME (LOSS) OFCONSOLIDATED SUBSIDIARIES 219,794 — (1,336) — (218,458) —Net Income 137,042 — 219,794 5,496 (218,458) 143,874LESS: NET INCOME ATTRIBUTABLE TONONCONTROLLING INTERESTS (6,832) (6,832)LESS: DISTRIBUTIONS TO PREFERREDUNITHOLDERS (30,142) (30,142)LESS: NET INCOME ALLOCATED TOGENERAL PARTNER (232) (232)NET INCOME ALLOCATED TO LIMITEDPARTNERS $137,042 $— $219,794 $5,496 $(255,664) $106,668F-55Table of ContentsConsolidating Statement of Operations(in Thousands) Year Ended March 31, 2016 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated REVENUES $— $— $11,593,272 $182,175 $(33,337) $11,742,110COST OF SALES — — 10,843,937 28,237 (33,137) 10,839,037OPERATING 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 unconsolidated entities — — 4,374 11,747 — 16,121Interest expense (43,493) — (82,360) (7,546) 310 (133,089)Gain on early extinguishment of liabilities, net — — 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) — 367EQUITY IN NET LOSS OF CONSOLIDATEDSUBSIDIARIES (155,436) — (7,011) — 162,447 —Net (Loss) Income (198,929) — (155,436) 4,821 162,447 (187,097)LESS: NET INCOME ATTRIBUTABLE TONONCONTROLLING INTERESTS (11,832) (11,832)LESS: NET INCOME ALLOCATED TOGENERAL PARTNER (47,620) (47,620)NET (LOSS) INCOME ALLOCATED TOLIMITED PARTNERS $(198,929) $— $(155,436) $4,821 $102,995 $(246,549)F-56Table of ContentsConsolidating Statement of Operations(in Thousands) Year Ended March 31, 2015 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated REVENUES $— $— $16,648,382 $189,979 $(36,304) $16,802,057COST OF SALES — — 15,934,529 59,825 (36,147) 15,958,207OPERATING 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) 107,420OTHER INCOME (EXPENSE): Equity in earnings of unconsolidated entities — — 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) 46,571INCOME TAX BENEFIT (EXPENSE) — — 3,795 (173) — 3,622EQUITY IN NET INCOME (LOSS) OFCONSOLIDATED SUBSIDIARIES 103,029 — (19,297) — (83,732) —Net Income (Loss) 37,306 — 103,186 (6,410) (83,889) 50,193LESS: NET INCOME ATTRIBUTABLE TONONCONTROLLING INTERESTS (12,887) (12,887)LESS: NET INCOME ALLOCATED TOGENERAL PARTNER (45,700) (45,700)NET INCOME (LOSS) ALLOCATED TOLIMITED PARTNERS $37,306 $— $103,186 $(6,410) $(142,476) $(8,394)F-57Table of ContentsConsolidating Statements of Comprehensive Income (Loss)(in Thousands) Year Ended March 31, 2017 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated Net income $137,042 $— $219,794 $5,496 $(218,458) $143,874Other comprehensive loss — — (1,626) (45) — (1,671)Comprehensive income $137,042 $— $218,168 $5,451 $(218,458) $142,203 Year Ended March 31, 2016 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. 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) Year Ended March 31, 2015 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatingAdjustments Consolidated Net income (loss) $37,306 $— $103,186 $(6,410) $(83,889) $50,193Other comprehensive income (loss) — — 189 (62) — 127Comprehensive income (loss) $37,306 $— $103,375 $(6,472) $(83,889) $50,320F-58Table of ContentsConsolidating Statement of Cash Flows(in Thousands) Year Ended March 31, 2017 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatedOPERATING ACTIVITIES: Net cash (used in) provided by operating activities $(749,250) $— $700,269 $22,157 $(26,824)INVESTING ACTIVITIES: Capital expenditures — — (356,473) (7,398) (363,871)Acquisitions, net of cash acquired — — (111,426) (11,406) (122,832)Cash flows from settlements of commodity derivatives — — (37,442) — (37,442)Proceeds from sales of assets — — 29,527 39 29,566Proceeds from sale of TLP common units — — 112,370 — 112,370Proceeds from sale of Grassland — — — 22,000 22,000Investments in unconsolidated entities — — (2,105) — (2,105)Distributions of capital from unconsolidated entities — — 9,692 — 9,692Payments on loan for natural gas liquids facility — — 8,916 — 8,916Loan to affiliate — — (3,200) — (3,200)Payments on loan to affiliate — — 655 — 655Payment to terminate development agreement — — (16,875) — (16,875)Net cash (used in) provided by investing activities — — (366,361) 3,235 (363,126)FINANCING ACTIVITIES: Proceeds from borrowings under revolving credit facilities — — 1,700,000 — 1,700,000Payments on revolving credit facilities — — (2,733,500) — (2,733,500)Issuance of senior notes 1,200,000 — — — 1,200,000Repurchases of senior notes (21,193) — — — (21,193)Payments on other long-term debt — — (49,596) (190) (49,786)Debt issuance costs (21,868) — (11,690) — (33,558)Contributions from general partner 49 — — — 49Contributions from noncontrolling interest owners, net — — — 672 672Distributions to partners (181,581) — — — (181,581)Distributions to noncontrolling interest owners — — — (3,292) (3,292)Proceeds from sale of convertible preferred units and warrants, net ofoffering costs 234,975 — — — 234,975Proceeds from sale of common units, net of offering costs 287,136 — — — 287,136Payments for the early extinguishment of liabilities — — (25,884) — (25,884)Net changes in advances with consolidated entities (767,760) — 788,881 (21,121) —Net cash provided by (used in) financing activities 729,758 — (331,789) (23,931) 374,038Net (decrease) increase in cash and cash equivalents (19,492) — 2,119 1,461 (15,912)Cash and cash equivalents, beginning of period 25,749 — 784 1,643 28,176Cash and cash equivalents, end of period $6,257 $— $2,903 $3,104 $12,264F-59Table of ContentsConsolidating Statement of Cash Flows(in Thousands) Year Ended March 31, 2016 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatedOPERATING ACTIVITIES: Net cash (used in) provided by operating activities $(74,822) $— $360,851 $65,466 $351,495INVESTING ACTIVITIES: Capital expenditures — — (604,214) (57,671) (661,885)Acquisitions, net of cash acquired (624) — (232,148) (1,880) (234,652)Cash flows from settlements of 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 noncontrolling interest owners, net (3,829) — — 15,376 11,547Distributions 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) 80,705Net 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 $28,176F-60Table of ContentsConsolidating Statement of Cash Flows(in Thousands) Year Ended March 31, 2015 NGL EnergyPartners LP(Parent) NGL EnergyFinance Corp. GuarantorSubsidiaries Non-GuarantorSubsidiaries ConsolidatedOPERATING ACTIVITIES: Net cash (used in) provided by operating activities $(59,448) $— $287,953 $33,886 $262,391INVESTING ACTIVITIES: Capital expenditures — — (223,065) (4,913) (227,978)Purchase of equity interest in Grand Mesa Pipeline — — (310,000) — (310,000)Acquisitions, net of cash acquired (124,281) — (831,505) (5,136) (960,922)Cash flows from settlements of 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)Issuance of senior 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, net — — — 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) 1,134,693Net 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 $41,303F-61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, OWL Pearsall SWD, LLC,OWL Pearsall Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.1 to the CurrentReport 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 Karnes SWD, LLC,OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.2 to the CurrentReport 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, Terry Bailey, as trusteeof the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.3 to the CurrentReport 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, Terry Bailey, as trusteeof the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.4 to the CurrentReport 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, LotusOilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High Sierra Transportation, LLC(incorporated by reference to Exhibit 2.5 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)2.6 Equity Interest Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP, High Sierra Energy, LP, Gavilon, LLC andGavilon 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 SECon 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 on Form S-1 (FileNo. 333-172186) filed with the SEC on April 15, 2011)3.2 Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.2 to the RegistrationStatement on Form S-1 (File No. 333-172186) filed with the SEC on April 15, 2011)3.3 Third Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the CurrentReport on Form 8-K (File No. 001-35172) filed with the SEC on June 28, 2016)3.4 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 with the SEC on April 15, 2011)3.5 Certificate of Amendment to Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.5 to the Registration Statementon Form S-1 (File No. 333-172186) filed with the SEC on April 15, 2011)3.6 Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on February 28, 2013)3.7 Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of August 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 on August 7, 2013)3.8 Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of June 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 on July 3, 2014)3.9 Amendment No. 3 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as of June 24, 2016(incorporated by reference to Exhibit 3.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 28, 2016)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 otherholders party 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 7,2011)4.2 Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 by and among thePartnership and SemStream (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC onNovember 4, 2011)4.3 Amendment No. 2 and Joinder to First Amended and Restated Registration Rights Agreement, dated January 3, 2012, by and among NGL EnergyHoldings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-Portland Propane, L.L.C., Pacer Propane(Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C. (incorporated by reference to Exhibit 4.1 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on January 9, 2012)4.4 Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGL Energy HoldingsLLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SECon May 4, 2012)4.5 Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and between NGL EnergyHoldings 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 withthe SEC on June 25, 2012)F-62Table of ContentsExhibit NumberDescription4.6 Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and between NGL EnergyHoldings 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 onOctober 3, 2012)4.7 Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by and between NGL EnergyHoldings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust and Nitor Trust(incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 19, 2012)4.8 Amendment No. 7 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of August 1, 2013, by and among NGL EnergyHoldings LLC, Oilfield Water Lines, LP and Terry G. Bailey (incorporated by reference to Exhibit 4.1 to the Current 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 and among NGL EnergyHoldings LLC and Magnum NGL Holdco LLC (incorporated by reference to Exhibit 4.9 to the Annual Report on Form 10-K (File No. 001-35172) for theyear 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 and among NGL EnergyHoldings LLC and Magnum NGL Holdco LLC (incorporated by reference to Exhibit 4.10 to the Annual Report on Form 10-K (File No. 001-35172) forthe year ended March 31, 2016 filed with the SEC on May 31, 2016)4.11 Amended and Restated Note Purchase Agreement, dated March 31, 2017 and effective as of December 31, 2016, by and among NGL Energy Partners LPand 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 onApril 4, 2017)4.12 Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party thereto and U.S. BankNational 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 onOctober 16, 2013)4.13 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 theSEC on October 16, 2013)4.14 Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listedtherein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)4.15 First Supplemental Indenture, dated as of December 2, 2013, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiariesparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.19 to the Annual Reporton Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with the SEC on May 30, 2014)4.16 Second Supplemental Indenture, dated as of April 22, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaryparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.20 to the Annual Reporton Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with the SEC on May 30, 2014)4.17 Third Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiary partythereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.6 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with the SEC on November 10, 2014)4.18 Fourth Supplemental Indenture, dated as of December 1, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the GuaranteeingSubsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.25 to theAnnual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)4.19 Fifth Supplemental Indenture, dated as of February 17, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiariesparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.26 to the Annual Reporton Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)4.20 Sixth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiariesparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Quarterly Reporton Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed with the SEC on November 9, 2015)4.21 Registration Rights Agreement, dated December 2, 2013, by and among NGL Energy Partners LP and the purchasers set forth on Schedule A 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 December 5, 2013)4.22 Indenture, dated as of July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party thereto and U.S. BankNational 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 onJuly 9, 2014)4.23 Forms of 5.125% Senior Notes due 2019 (incorporated by reference and included as Exhibits A1 and A2 to Exhibit 4.1 to the Current Report on Form 8-K(File No. 001-35172) filed with the SEC on July 9, 2014) F-63Table of ContentsExhibit NumberDescription4.24 Registration Rights Agreement, dated July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listed therein onExhibit A and RBS Securities Inc. as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report onForm 8-K (File No. 001-35172) filed with the SEC on July 9, 2014)4.25 First Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries partythereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.5 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2014 filed with the SEC on November 10, 2014)4.26 Second Supplemental Indenture, dated as of December 1, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the GuaranteeingSubsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.32 to theAnnual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)4.27 Third Supplemental Indenture, dated as of February 17, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiariesparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.33 to the Annual Reporton Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)4.28 Fourth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiariesparty thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Reporton Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed with the SEC on November 9, 2015)4.29 Registration Rights Agreement, dated May 11, 2016, by and among NGL Energy Partners LP and Highstar NGL Prism/IV-A Interco LLC and HighstarNGL Main Interco 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 June 28,2016)4.30 Amendment to Registration Rights Agreement, dated June 24, 2016, by and among NGL Energy Partners LP and Highstar NGL Prism/IV-A Interco LLC,Highstar NGL Main Interco LLC and NGL CIV A, 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 28, 2016)4.31 Indenture, dated as of October 24, 2016, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors party thereto and U.S. BankNational 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 onOctober 24, 2016)4.32 Forms of 7.5% Senior Notes due 2023 (incorporated by reference to Exhibit 4.2 and included as Exhibits A1 and A2 to Exhibit 4.1 to the Current Reporton Form 8-K (File No. 001-35172) filed with the SEC on October 24, 2016)4.33 Registration Rights Agreement, dated as of October 24, 2016, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors listedtherein on Exhibit A and Barclays Capital Inc. as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the CurrentReport on Form 8-K (File No. 001-35172) filed with the SEC on October 24, 2016)4.34 Indenture, dated as of February 22, 2017, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors party thereto and U.S. BankNational 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 onFebruary 22, 2017)4.35 Forms of 6.125% Senior Notes due 2025 (included as Exhibits A1 and A2 to Exhibit 4.1 of this Current Report on Form 8-K) (incorporated by referenceto Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on February 22, 2017)4.36 Registration Rights Agreement, dated as of February 22, 2017, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the guarantors listedtherein on Exhibit A and RBC Capital Markets, LLC and Deutsche Bank Securities Inc., as representatives 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 February 22, 2017)10.1 Amended and Restated Credit Agreement, dated as of February 14, 2017, by and among NGL Energy Partners LP, NGL Energy Operating LLC, thesubsidiary guarantors party thereto, Deutsche Bank Trust Company Americas, Deutsche Bank AG, New York Branch, and the other financial institutionsparty 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 February 15, 2017)10.2 Amendment No. 1 to Amended and Restated Credit Agreement, dated as of March 31, 2017, among the NGL Energy Partners LP, NGL Energy OperatingLLC, the other subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas, and the other financial institutions party thereto (incorporatedby reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on April 5, 2017)10.3 Class A Convertible Preferred Unit and Warrant Purchase Agreement, dated as of April 21, 2016, by and among NGL Energy Partners LP, Highstar NGLPrism/IV-A Interco LLC and Highstar NGL Main Interco LLC (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No.001-35172) filed with the SEC on April 27, 2016)10.4 Amendment to Class A Convertible Preferred Unit and Warrant Purchase Agreement, dated as of June 23, 2016, by and among NGL Energy Partners LPand Highstar NGL Prism/IV-A Interco LLC, Highstar NGL Main Interco LLC and NGL CIV A, LLC (incorporated by reference to Exhibit 10.1 to theCurrent Report on Form 8-K (File No. 001-35172) filed with the SEC on June 28, 2016)10.5 Form of Warrant (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K (File No. 001-35172) filed on June 28, 2016)10.6 Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed on Schedule A 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 5, 2013)F-64Table of ContentsExhibit NumberDescription10.7+ Letter Agreement among Silverthorne Energy Holdings LLC, Shawn W. Coady and Todd M. Coady dated October 14, 2010 (incorporated by reference toExhibit 10.11 to the Registration Statement on Form S-1 (File No. 333-172186) filed with the SEC on April 15, 2011)10.8+ 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 with the SEC on May 17, 2011)10.9+ Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 tothe Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended June 30, 2012 filed with the SEC on August 14, 2012 )10.10 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 endedMarch 31, 2015 filed with the SEC on June 1, 2015)12.1* Computation of ratios of earnings to fixed charges and combined fixed charges and preferred unit distributions21.1* List of Subsidiaries of NGL Energy Partners LP23.1* Consent of Grant Thornton LLP31.1* Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 200231.2* Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 200232.1* Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 200232.2* Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002101.INS** XBRL Instance Document101.SCH** XBRL Schema Document101.CAL** XBRL Calculation Linkbase Document101.DEF** XBRL Definition Linkbase Document101.LAB** XBRL Label Linkbase Document101.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, 2017 and 2016, (ii) ConsolidatedStatements of Operations for the years ended March 31, 2017, 2016, and 2015, (iii) Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31,2017, 2016, and 2015, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2017, 2016, and 2015, (v) Consolidated Statements of Cash Flowsfor the years ended March 31, 2017, 2016, and 2015, and (vi) Notes to Consolidated Financial Statements.+Management contracts or compensatory plans or arrangements.F-65Exhibit 12.1NGL ENERGY PARTNERS LP AND SUBSIDIARIESCOMPUTATION OF RATIOS OF EARNINGS (LOSS) TO FIXED CHARGESAND COMBINED FIXED CHARGES AND PREFERRED UNIT DISTRIBUTIONS(In thousands, except ratio amounts) Year Ended March 31, 2017 2016 2015 2014 2013 EARNINGS (LOSS): Income (loss) before income taxes $145,813 $(187,464) $46,571 $49,695 $50,065Income before income taxes attributable to noncontrolling interests (6,832) (11,832) (12,887) (1,103) (250)Fixed charges 189,465 146,401 151,956 91,622 66,824Total earnings (loss) $328,446 $(52,895) $185,640 $140,214 $116,639 FIXED CHARGES: Interest expense $150,478 $133,089 $110,123 $58,854 $32,994(Gain) loss on early extinguishment of debt (2,449) (28,532) — — 5,769Portion of rental expense estimated to relate to interest (1) 41,436 41,844 41,833 32,768 28,061Fixed charges $189,465 $146,401 $151,956 $91,622 $66,824 PREFERRED UNIT DISTRIBUTIONS 14,693 — — — —Combined fixed charges and preferred unit distributions $204,158 $146,401 $151,956 $91,622 $66,824 Ratio of earnings to fixed charges (2) 1.73 — 1.22 1.53 1.75Ratio of earnings to combined fixed charges and preferred unit distributions 1.61 (1)Represents one-third of the total operating lease rental expense, which is that portion estimated to represent interest.(2)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 of earnings to achieve aratio of 1:1.Exhibit 21.1 LIST OF SUBSIDIARIES OF NGL ENERGY PARTNERS LPSubsidiary Jurisdiction of OrganizationNGL Energy Operating LLC DelawareNGL Energy Finance Corp. DelawareTransMontaigne LLC DelawareNGL Energy Equipment LLC ColoradoAtlantic Propane, LLC (1) OklahomaNGL Crude Logistics, LLC DelawareNGL Crude Transportation, LLC ColoradoNGL Crude Terminals, LLC DelawareNGL Marine, LLC TexasNGL Milan Investments, LLC ColoradoGrand Mesa Pipeline, LLC DelawareNGL Crude Cushing, LLC OklahomaE Energy Adams, LLC (2) NebraskaHigh Sierra Crude Oil & Marketing, LLC ColoradoNGL Crude Canada Holdings, LLC ColoradoNGL Crude Canada ULC AlbertaNGL Crude Pipelines, LLC OklahomaNGL Energy Logistics, LLC DelawareNGL Energy Holdings II, LLC DelawareGlass Mountain Pipeline, LLC (3) DelawareNGL Shipping and Trading, LLC DelawareNGL Propane, LLC DelawareOsterman Propane, LLC DelawareVictory Propane, LLC (4) OklahomaHicksgas, LLC DelawareNGL-NE Real Estate, LLC DelawareNGL-MA Real Estate, LLC DelawareNGL-MA, LLC DelawareNGL Liquids, LLC DelawareCentennial Energy, LLC ColoradoCentennial Gas Liquids, ULC AlbertaNGL Gateway Terminals, Inc. OntarioNGL Supply Terminal Company, LLC DelawareNGL Hutch, LLC DelawareSawtooth NGL Caverns, LLC DelawareNGL Supply Terminal Solution Mining, LLC UtahNGL Supply Wholesale, LLC DelawareNGL Water Solutions, LLC ColoradoNGL Water Solutions Bakken, LLC ColoradoNGL Water Solutions Mid-Continent, LLC ColoradoNGL Water Pipelines, LLC (5) TexasNGL Solids Solutions, LLC (6) ColoradoAntiCline Disposal, LLC WyomingNGL Water Solutions DJ, LLC ColoradoNGL Water Solutions Eagle Ford, LLC DelawareSubsidiary Jurisdiction of OrganizationIndigo Injection #3-1, LLC (7) DelawareChoya Operating, LLC TexasNGL Water Solutions Permian, LLC ColoradoTransMontaigne Product Services LLC DelawareTransMontaigne Services LLC DelawareHigh Sierra Energy GP, LLC ColoradoHigh Sierra Energy, LP Delaware (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 an 81.625% member interest in NGL Water Pipelines, LLC.(6) NGL Energy Partners LP owns a 50% member interest in NGL Solids Solutions, LLC.(7) NGL Energy Partners LP owns a 75% member interest in Indigo Injection #3-1, LLC.Exhibit 23.1CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMWe have issued our reports dated May 26, 2017, with respect to the consolidated financial statements and internal control over financial reportingincluded in the Annual Report of NGL Energy Partners LP on Form 10-K for the year ended March 31, 2017. We hereby consent to the incorporation byreference of said reports in the Registration Statements of NGL Energy Partners LP on Form S-8 (File No. 333-185068) and on Forms S-3 (File No. 333-194035, File No. 333-212316, File No. 333-214479, and File No. 333-216079)/s/ GRANT THORNTON LLP Tulsa, Oklahoma May 26, 2017 Exhibit 31.1CERTIFICATIONI, 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; andd.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; and5.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; andb.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 26, 2017/s/ H. Michael Krimbill H. Michael Krimbill Chief Executive Officer of NGL Energy Holdings LLC, the general partner ofNGL Energy Partners LPExhibit 31.2CERTIFICATIONI, 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; andd.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; and5.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; andb.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 26, 2017/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 32.1CERTIFICATIONPURSUANT TO 18 U.S.C. SECTION 1350In connection with the Annual Report of NGL Energy Partners LP (the “Partnership”) on Form 10-K for the fiscal year ended March 31, 2017 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; and2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of thePartnership.Date : May 26, 2017/s/ H. Michael Krimbill H. Michael Krimbill Chief Executive Officer of NGL Energy Holdings LLC, the general partner ofNGL Energy Partners LPThis 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 32.2CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350In connection with the Annual Report of NGL Energy Partners LP (the “Partnership”) on Form 10-K for the fiscal year ended March 31, 2017 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; and2.The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of thePartnership.Date : May 26, 2017/s/ Robert W. Karlovich III Robert W. Karlovich III Chief Financial Officer of NGL Energy Holdings LLC, the general partner ofNGL Energy Partners LPThis 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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