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NGL Energy Partners LP - Annual Report: 2016 (Form 10-K)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K
(Mark One)
ý    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended March 31, 2016
OR
o    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from __________ to __________
Commission File Number: 001-35172
NGL Energy Partners LP
(Exact Name of Registrant as Specified in Its Charter)
Delaware
 
27-3427920
(State or Other Jurisdiction of Incorporation or Organization)
 
(I.R.S. Employer Identification No.)
6120 South Yale Avenue
Suite 805
Tulsa, 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 Registered
Common Units Representing Limited Partner Interests
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:  None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý  No o
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o  No ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý  No o
Indicate 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 and posted 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 and post such files). Yes ý  No o
Indicate 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. o
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Large accelerated filer x
 
Accelerated filer o
Non-accelerated filer o (Do not check if a smaller reporting company)
 
Smaller reporting company o
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o  No ý
The aggregate market value at September 30, 2015 of the Common Units held by non-affiliates of the registrant, based on the reported closing price of the Common Units on the New York Stock Exchange on such date ($19.97 per Common Unit) was $1.9 billion. For purposes of this computation, all executive officers, directors and 10% owners of the registrant are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers, directors and 10% beneficial owners are affiliates.
At May 23, 2016, there were 104,169,573 common units issued and outstanding.

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EXPLANATORY NOTE

This Annual Report on Form 10-K of NGL Energy Partners LP (referred to herein as the “Partnership,” “we,” “us” or “our”) includes restated unaudited quarterly consolidated financial information as of and for the periods ended June 30, 2015, September 30, 2015 and December 31, 2015. We will not file amended periodic reports for any prior filings, including Forms 10-Q for any of the affected quarterly periods.

Restatement Background

In connection with the recording of business combinations that occurred in the fourth quarter of fiscal year 2016, the Partnership identified certain contingent consideration liabilities in connection with those fourth quarter 2016 business combinations, and determined that the Partnership had not correctly accounted for contingent consideration related to royalty payments that were part of certain prior business combinations within its Water Solutions segment that had occurred prior to the fourth quarter of fiscal year 2016. The application of the correct accounting treatment results in an increase to goodwill, current liabilities and long-term liabilities and an increase to earnings for the first three quarters of the fiscal year ended March 31, 2016.

As a result of this error, on May 31, 2016, the Partnership’s management, Audit Committee and Board of Directors concluded, after consideration of the relevant facts and circumstances, that the Partnership’s unaudited interim consolidated financial statements set forth in the Partnership’s Quarterly Reports on Form 10-Q for the quarters ended June 30, 2015, September 30, 2015 and December 31, 2015 should be restated and that such financial statements previously filed with the Securities and Exchange Commission (the “SEC”) should no longer be relied upon and on that date filed a Form 8-K with the SEC to report such non-reliance. In addition, based on the relevant facts and circumstances, the Partnership’s management, Audit Committee and Board of Directors concluded that the correction was not material to any other periods prior to fiscal year 2016.

Within this Annual Report on Form 10-K for the year ended March 31, 2016, the Partnership has included restated unaudited quarterly data for each of the quarters ended June 30, 2015, September 30, 2015 and December 31, 2015 in the notes to the consolidated financial statements. For the financial data related to its fiscal year ended March 31, 2015 and all unaudited quarterly financial data for the quarters ended June 30, 2014, September 30, 2014, December 31, 2014 and March 31, 2015, the Partnership has included financial data that contains immaterial corrections for this issue.

Management has evaluated the effect of the restatements on its prior conclusions regarding the effectiveness of the Partnership’s internal control over financial reporting and disclosure controls and procedures and has concluded that a material weakness existed during each of the periods requiring correction. In connection therewith, the Partnership’s management concluded that during the periods requiring correction, the Partnership did not maintain effective controls over the identification of assets acquired and liabilities assumed in the Partnership’s business combinations. Accordingly, the Partnership’s internal control over financial reporting and disclosure controls and procedures were not effective during the periods being corrected.

The following parts of this Form 10-K include discussion of or disclosure related to the restatement:
•
Part I, Item 1A - Risk Factors
•
Part II, Item 7 - Management’s Discussion and Analysis of Financial Condition and Results of Operations
•
Part II, Item 8 - Financial Statements and Supplementary Data
•
Part II, Item 9A - Controls and Procedures
•
Part IV, Item 15 - Exhibits, Financial Statement Schedules


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Forward-Looking Statements

This Annual Report on Form 10-K (“Annual Report”) contains various forward-looking statements and information that are based on our beliefs and those of our general partner, as well as assumptions made by and information currently available to us. These forward-looking statements are identified as any statement 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 future operations, identify forward-looking statements. Although we and our general partner believe such forward-looking statements are reasonable, neither we nor our general partner can assure they will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those expected. Among the key risk factors that may impact our consolidated financial position and results of operations are:

•
the prices of crude oil, natural gas liquids, refined products, ethanol, and biodiesel;
•
energy prices generally;
•
the general level of crude oil, natural gas, and natural gas liquids production;
•
the general level of demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel;
•
the availability of supply of crude oil, natural gas liquids, refined products, ethanol, and biodiesel;
•
the level of crude oil and natural gas drilling and production in producing areas where we have water treatment and disposal facilities;
•
the prices of propane and distillates relative to the prices of alternative and competing fuels;
•
the price of gasoline relative to the price of corn, which impacts the price of ethanol;
•
the ability to obtain adequate supplies of products if an interruption in supply or transportation occurs and the availability of capacity to transport products to market areas;
•
actions taken by foreign oil and gas producing nations;
•
the political and economic stability of foreign oil and gas producing nations;
•
the effect of weather conditions on supply and demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel;
•
the effect of natural disasters, lightning strikes, or other significant weather events;
•
the availability of local, intrastate and interstate transportation infrastructure with respect to our truck, railcar, and barge transportation services;
•
the availability, price, and marketing of competing fuels;
•
the impact of energy conservation efforts on product demand;
•
energy efficiencies and technological trends;
•
governmental regulation and taxation;
•
the impact of legislative and regulatory actions on hydraulic fracturing, waste water disposal and on the treatment of flowback and 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, water disposal, recycling, and discharge services;
•
the ability to renew leases for our leased equipment and storage facilities;

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•
the nonpayment or nonperformance by our counterparties;
•
the availability and cost of capital and our ability to access certain capital sources;
•
a deterioration of the credit and capital markets;
•
the ability to successfully identify and consummate strategic acquisitions, and integrate acquired assets and businesses;
•
changes in the volume of hydrocarbons recovered during the wastewater treatment process;
•
changes in the financial condition and results of operations of entities in which we own noncontrolling equity interests;
•
changes in applicable laws and regulations, including tax, environmental, transportation and employment regulations, or new interpretations by regulatory agencies concerning such laws and regulations and the impact of such laws and regulations (now existing or in the future) on our business operations;
•
the costs and effects of legal and administrative proceedings;
•
any reduction or the elimination of the federal Renewable Fuel Standard; and
•
changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our pipeline assets.

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this Annual Report. Except as required by state and federal securities laws, we undertake no obligation to publicly update or revise any forward-looking statements as a result of new information, future events, or otherwise. When considering forward-looking statements, please review the risks described under Part I, Item 1A–“Risk Factors.”


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PART I
 
References in this Annual Report to (i) “NGL Energy Partners LP,” the “Partnership,” “we,” “our,” “us,” or similar terms refer to NGL Energy Partners 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 Partners LP, (iv) the “NGL Energy GP Investor Group” refers to, collectively, the 42 individuals and entities that own all of the outstanding membership interests in our general partner, and (v) the “NGL Energy LP Investor Group” refers to, collectively, the 15 individuals and entities that owned all of our outstanding common units before the closing date of our initial public offering.

We have presented operational data in Part I, Item 1–“Business” for the year ended March 31, 2016. Unless otherwise indicated, this data is as of March 31, 2016.
 
Item 1.    Business

Overview

We are a Delaware limited partnership formed in September 2010. Subsequent to our initial public offering (“IPO”) in May 2011, we significantly expanded our operations through numerous acquisitions. At March 31, 2016, our operations include:

•
Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals and pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests in two crude oil pipelines. Our crude oil logistics segment purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.
•
Our water solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities. Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck washouts. In addition, our water solutions segment sells the recycled water and recovered hydrocarbons that result from performing these services.
•
Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling and storage services through its 19 owned terminals throughout the United States, its salt dome storage facility in Utah, and its leased storage and railcar transportation services through its fleet of leased railcars.
•
Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia.
•
Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We purchase refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedule them for delivery at various locations. See “Dispositions ” below for a discussion of our interests in TransMontaigne Partners L.P. (“TLP”).

For more information regarding our reportable segments, please see Note 13 to our consolidated financial statements included in this Annual Report.

Acquisitions

Subsequent to our IPO in May 2011, we significantly expanded our operations through numerous acquisitions, including the following, among others:

Year Ended March 31, 2012

•
In October 2011, we completed a business combination with E. Osterman Propane, Inc., its affiliated companies, and members of the Osterman family (collectively, “Osterman”), whereby we acquired retail propane operations in the northeastern United States.

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•
In November 2011, we completed a business combination with SemStream, L.P. (“SemStream”), whereby we acquired SemStream’s wholesale natural gas liquids supply and marketing operations and its 12 natural gas liquids terminals.
•
In January 2012, we completed a business combination with seven companies associated with Pacer Propane Holding, L.P. (collectively, “Pacer”), whereby we acquired retail propane operations, primarily in the western United States.
•
In February 2012, we completed a business combination with North American Propane, Inc., whereby we acquired retail propane and distillate operations in the northeastern United States.

Year Ended March 31, 2013

•
In May 2012, we acquired the retail propane and distillate operations of Downeast Energy Corp. These operations are primarily in 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 include crude oil gathering, transportation and marketing; water treatment, disposal, and transportation; and natural gas liquids transportation and marketing.
•
In November 2012, we completed a business combination whereby we acquired Pecos Gathering & Marketing, L.L.C. and certain of its affiliated companies (collectively, “Pecos”). The business of Pecos consists primarily of crude oil purchasing and logistics operations in Texas and New Mexico.
•
In December 2012, we completed a business combination whereby we acquired all of the membership interests in Third Coast Towing, LLC (“Third Coast”). The business of Third Coast consists primarily of transporting crude oil via barge.

Year Ended March 31, 2014

•
In July 2013, we completed a business combination whereby we acquired the operating assets of Crescent Terminals, LLC, which operates a leased 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 of Texas.
•
In July 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd., whereby we acquired a water treatment and disposal facility in the Permian Basin in Texas. We also entered into a development agreement that requires us to purchase water solutions facilities developed by the other party to the agreement. During March 2014, we purchased one additional facility under this development agreement.
•
In August 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively, “OWL”). The businesses of OWL include four water treatment and disposal facilities in the Eagle Ford shale play in Texas.
•
In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), whereby we acquired the ownership interests in three water treatment and disposal facilities in the Eagle Ford shale play in Texas, and the option to acquire an additional facility, which we exercised in March 2014.
•
In December 2013, we acquired the ownership interests in Gavilon, LLC (“Gavilon Energy”). The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas and Louisiana, a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma and became operational in February 2014, and an interest in an ethanol production facility in the Midwest. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids, and also include crude oil storage in Cushing, Oklahoma.

Year Ended March 31, 2015

•
In July 2014, we acquired TransMontaigne Inc. (“TransMontaigne”). As part of this transaction, we also purchased inventory from the previous owner of TransMontaigne. The operations of TransMontaigne include the marketing of refined products. As part of this transaction, we acquired the 2% general partner interest, the incentive distribution rights, a 19.7% limited partner interest in TLP, and assumed certain terminaling service

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agreements with TLP from an affiliate of the previous owner of TransMontaigne. See “Dispositions” below for a discussion of the sale of the general partner interest.
•
In November 2014, we acquired two saltwater disposal facilities in the Bakken shale play in North Dakota.
•
In February 2015, we acquired Sawtooth NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility.
•
During the year ended March 31, 2015, we purchased 16 water treatment and disposal facilities under the development agreement discussed above.
•
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 Delaware Basin 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 of West Texas.
•
During the year ended March 31, 2016, we purchased 15 water treatment and disposal facilities under the development agreement discussed above.
•
During the year ended March 31, 2016, we acquired six retail propane businesses.

Dispositions

Sale of General Partner Interest in TLP

On February 1, 2016, we completed the sale of our general partner interest in TLP to an affiliate of ArcLight Capital Partners (“ArcLight”) for $350 million in cash. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the 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. In addition, we retained TransMontaigne’s marketing business, which is a significant part of our refined products and renewables segment, and TransMontaigne Product Services, LLC, its customer contracts and its line space on the Colonial and Plantation pipelines.

Sale of TLP Common Units

On April 1, 2016, we sold all of the TLP common units we owned to ArcLight for approximately $112.4 million in cash.



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Primary Service Areas

The following map shows the primary service areas of our businesses:





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Organizational Chart

The following chart summarizes our legal entity structure at April 1, 2016:

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Our Business Strategies

Our principal business objective is to increase the quarterly distributions that we pay to our unitholders over time while ensuring the ongoing stability 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 to enhance our ability to transport crude oil from the wellhead to refiners, refined products from refiners to customers, wastewater from the wellhead to treatment for disposal, recycle, or discharge, and natural gas liquids from processing plants to end users, including retail propane customers.
•
Achieve organic growth by investing in new assets that increase volumes, enhance our operations, and generate attractive rates of return. We believe that there are accretive organic growth opportunities that originate from assets we own and operate. We have and expect to continue to invest within our existing businesses, particularly within our crude oil logistics, water solutions, and refined products businesses as 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 to continue to pursue acquisitions that build upon our vertically integrated business model, add scale to our current operating platforms, and enhance our geographic diversity in our businesses. We have established a successful track record of acquiring companies and assets at attractive prices and we continue to evaluate acquisition opportunities in order to capitalize on this strategy in the future.
•
Focus on consistent annual cash flows by adding operations that minimize commodity price risk and generate fee-based, cost-plus, or margin-based revenues under multi-year contracts. We intend to focus on long-term fee-based contracts in addition to back-to-back contracts which minimize commodity price exposure. We continue to increase cash flows that are supported by certain fee-based, multi-year contracts, some of which include acreage dedications from producers or volume commitments. We also believe that expanding our retail propane business with an emphasis on a high level of residential customers with company-owned tanks will result in strong customer retention rates and consistent operating margins.
•
Maintain a disciplined capital structure characterized by low leverage. We target leverage levels that are consistent with those of investment grade companies. Through our disciplined approach to leverage, we expect to maintain sufficient liquidity to manage existing and future capital requirements and to take advantage of market opportunities.
•
Maintain a disciplined cash distribution policy that complements our leverage, acquisition and organic growth strategies. We intend to use cash flows from our operations to make distributions to our unitholders and to use excess cash flows to finance organic growth and opportunistically repay indebtedness, including amounts outstanding under our Revolving Credit Facility (as hereinafter defined). We believe this strategy positions us to pursue future acquisitions and to execute upon our organic growth initiatives.

Our Competitive Strengths

We believe that we are well positioned to successfully execute our business strategies and achieve our principal business objective because of the following competitive strengths:

•
Our vertically integrated and diversified operations, which help us generate more predictable and stable cash flows on a year-to-year basis. Our ability to provide multiple services to customers in numerous geographic areas enhances our competitive position. Our five businesses units are diversified by geography, customer-base and commodity sensitivities which we believe proves us with the ability to maintain cash flows throughout typical commodity cycles. By examples, our retail propane business sources propane through our liquids business which allows us to leverage the expertise of our liquids business to help improve our margins and profitability and enhance our cash flows. Furthermore, we believe that our liquids business provides us with valuable market intelligence that helps us identify potential acquisition opportunities. Our refined products and retail propane businesses benefit from lower energy prices driving increased customer demand, which can offset the downward pressure on our crude logistics and water businesses in a low price environment.
•
Our network of crude oil transportation assets, which allows us to serve customers over a wide geographic area and optimize sales. Our strategically deployed railcar fleet, towboats, barges, and trucks, and our owned and

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contracted pipeline capacity, provide access to a wide range 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 processing facilities are located among the most prolific crude oil and natural gas producing areas in the United States, including the Permian Basin, the DJ Basin, the Eagle Ford shale play, the Bakken shale play, and the Pinedale Anticline. In addition, we believe that the technological capabilities of our water solutions business can be quickly implemented at new facilities and locations.
•
Our network of natural gas liquids transportation, terminal, and storage assets, which allow us to provide multiple services over the continental United States. Our strategically located terminals, large railcar fleet, shipper status on common carrier pipelines, and substantial leased 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 generate higher margins than other customers. Our high percentage of propane tank ownership, payment billing systems, and automatic delivery program have resulted in a strong record of customer retention and help us better predict our cash flows in the retail propane business.
•
Our access to refined products pipeline and terminal infrastructure. Our capacity allocations on third-party pipelines and our access to TLP’s 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 and growing successful businesses. Our management team has significant experience managing companies in the energy industry, including master limited partnerships. In addition, through decades of experience, our management team has developed strong business relationships with key industry participants throughout the United States. We believe that our management’s knowledge of the industry, relationships within the industry, and experience in identifying, evaluating and completing acquisitions provides us with opportunities to grow through strategic and accretive acquisitions that complement or expand our existing operations.

Our Businesses
 
Crude Oil Logistics

Overview. Our crude oil logistics segment purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. We also lease space and capacity in our owned assets, such as 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 as the Bakken shale play in North Dakota, the DJ Basin in Colorado, the Mississippi Lime shale play in Oklahoma, the Permian Basin in Texas and New Mexico, the Eagle Ford shale play in Texas, the Anadarko Basin in Oklahoma and Texas, and southern Louisiana at the Gulf of Mexico.

Operations. We purchase crude oil from producers and transport it to refineries or for resale. Our strategically deployed railcar fleet, towboats, barges, and trucks, and our owned and contracted pipeline capacity, provide access to a wide range of customers and markets. We use this expansive network of transportation assets to deliver crude oil to the optimal markets.

We currently transport crude oil using the following assets:

•
200 owned trucks and 270 owned trailers operating primarily in the Mid-Continent, Permian Basin, Eagle Ford shale play, and Rocky Mountain regions;
•
400 owned railcars and 600 leased railcars operating primarily in Colorado, New Mexico, North Dakota, Oklahoma, Wyoming, and West Texas; and
•
11 owned towboats and 24 owned barges operating primarily in the intercoastal waterways of the Gulf Coast and along the Mississippi and Arkansas river systems.

Of our 400 owned railcars, all are compliant with the standards for railcars built subsequent to 2011. Of our 600 leased railcars, 100 are compliant with these standards (see Part I, Item 1A–“Risk Factors).

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We contract for truck, rail, and barge transportation services from third parties and ship on 17 common carrier pipelines. We own 35 pipeline injection stations, the locations of which are summarized below.
State
 
Number of Pipeline Injection Stations
Texas
 
14

Oklahoma
 
9

New Mexico
 
5

Kansas
 
3

North Dakota
 
3

Montana
 
1

Total
 
35


We also lease three pipeline injection stations in Montana and North Dakota. We also have commitments on several interstate pipelines for transportation of crude oil.

We own seven storage terminal facilities. The largest of these is a terminal in Cushing, Oklahoma with a storage capacity of 4,600,000 barrels, including 1,000,000 barrels which are owned by Glass Mountain. The combined storage capacity of the other six terminals is 462,500 barrels.

We lease 2,052,500 barrels of capacity at two storage terminal facilities. Of this leased storage capacity, 2,000,000 barrels are at Cushing, Oklahoma.

We have one Gulf Coast terminal facility that is under construction and is expected to be completed during the second quarter of fiscal year 2017 with a total expected storage capacity of 285,000 barrels. We own a 50% interest in Glass Mountain, which owns a 210-mile crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline, which became operational in February 2014, has a capacity of 147,000 barrels per day.

In September 2014, we entered into a joint venture with RimRock Midstream, LLC (“RimRock”) whereby each party owned a 50% interest in Grand Mesa Pipeline, LLC (“Grand Mesa”). In October 2014, we obtained ship-or-pay volume commitments from multiple shippers to begin construction of the Grand Mesa Pipeline, which will originate in Colorado and terminate in Cushing, Oklahoma. In November 2014, we acquired RimRock’s 50% ownership interest in Grand Mesa for $310.0 million in cash. In November 2015, Grand Mesa Pipeline entered into an agreement with Saddlehorn Pipeline Company, LLC (“Saddlehorn”), under which we acquired a 37.5% undivided interest in a crude oil pipeline currently under construction (the “Joint Pipeline”). The Joint Pipeline will take receipt from Grand Mesa Pipeline’s origin in Colorado and will deliver to Cushing, Oklahoma. We will have the right to utilize 150,000 barrels per day of capacity on the Joint Pipeline. Operating costs will be allocated to us based on our proportionate ownership interest and throughput. We expect the Joint Pipeline to be operational beginning in the third quarter of fiscal year 2017.

Through our undivided interest in the Joint Pipeline, we will have expanded capacity, sufficient to service our customer contracts at the same origin and termination points with the ability to accept additional volume commitments. We will retain ownership of our previously-acquired easements for the potential future development of transportation projects involving petroleum commodities other than crude oil and condensate. With the consent and participation of Saddlehorn, we and Saddlehorn may consider future opportunities using these easements for projects involving the transportation of crude oil and condensate.

Customers. Our customers include crude oil refiners, producers, and marketers. During the year ended March 31, 2016, 65% of the revenues of our crude oil logistics segment were generated from our ten largest customers of 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, some of which are larger and have greater financial resources than we do. The primary factors on which we compete are:

•
price;
•
availability of supply;

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•
reliability of service;
•
logistics capabilities, including the availability of railcars, proprietary terminals, and owned pipelines, barges, railcars, trucks, and towboats;
•
long-term customer relationships; and
•
the acquisition of businesses.

Supply. We obtain crude oil from a large base of suppliers, which consists primarily of crude oil producers. We currently purchase crude oil from approximately 350 producers at approximately 4,300 leases.

Pricing Policy. Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets such as Cushing, Oklahoma. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by hedging exposure 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 prices are greater than spot prices) or can be backwardated (a condition in which forward crude oil prices are lower than spot prices). Our crude oil logistics business benefits when the market is in contango, as increasing prices result in inventory holding gains during the time between when we purchase inventory and 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 typically invoice these customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our crude oil logistics customers. We believe the following procedures enhance our collection efforts with our crude oil logistics customers:

•
we require certain customers to prepay or place deposits for our services;
•
we require certain customers to post letters of credit or other forms of surety on a portion of our receivables; 
•
we review receivable aging analyses regularly to identify issues or trends that may develop; and
•
we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid invoices.

Trade Names. Our crude oil logistics segment operates primarily under the NGL Crude Logistics, NGL Crude Transportation and NGL Marine trade names.

Water Solutions

Overview. Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck washouts. In addition, our water solutions segment sells the recycled water and 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, including the Permian Basin in Texas, 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, 2016, we took delivery of 208.4 million barrels of wastewater, an average of 571,000 barrels per day.

Our water solutions segment is in the process of expanding its solids disposal business. With the addition of specialized equipment to select facilities 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 drilling fluids generated by crude oil and natural gas exploration and production activities. Our facilities will accept only exploration and production exempt waste allowed under our current permits.


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Operations. We own 70 water treatment and disposal facilities, including 87 wells. The location of the facilities and the processing capacities at which the facilities currently operate are summarized below.
Location
 
Processing Capacity
(barrels per day)
 
Located on Land
We Own or Lease
Pinedale Anticline (1)
 
60,000

 
Lease
 
 
 
 
 
DJ Basin (2)
 
189,500

 
Own
DJ Basin
 
72,500

 
Lease
Total-DJ Basin
 
262,000

 
 
 
 
 
 
 
Permian Basin (3)
 
653,000

 
Own
 
 
 
 
 
Eagle Ford Shale Play (3)
 
304,000

 
Own
Eagle Ford Shale Play (3)
 
169,000

 
Lease
Total-Eagle Ford Shale Play
 
473,000

 
 
 
 
 
 
 
Eaglebine Shale Play
 
20,000

 
Own
 
 
 
 
 
Granite Wash Shale Play (3)
 
52,000

 
Own
 
 
 
 
 
Bakken Shale Play
 
30,000

 
Own
Bakken Shale Play
 
16,000

 
Lease
Total-Bakken Shale Play
 
46,000

 
 
 
 
 
 
 
Total-All Facilities
 
1,566,000

 
 
 
(1)
This facility has a design capacity of 60,000 barrels per day to process water to a recycle standard which also includes a design capacity of 15,000 barrels per day to process water to a discharge standard.
(2)
Reflects the total processing capacity of facilities located on land we own at this location, which includes two facilities that have a combined design capacity of 20,000 barrels per day to process water to a recycle standard.
(3)
Certain facilities can dispose of both wastewater and solids such as tank bottoms and drilling fluids. We own a 50% interest in the disposal of solids.

In the table above, the processing capacity for the Permian Basin includes one facility with a processing capacity of 16,000 barrels per day in which we own a 50% interest. In the table above, the processing capacity for facilities located on land we lease in the Eagle Ford Shale Play includes three facilities with a combined processing capacity of 83,000 barrels per day in which we own a 75% interest.

Our customers bring wastewater generated by crude oil and natural gas exploration and production operations to our facilities for treatment through pipeline 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 the ultimate disposition of the water. Our solids customers bring solids generated by crude oil and natural gas exploration and production operations to our facilities by truck.

Our facility in Wyoming has the assets and technology needed to treat the water more extensively. At this facility, the water is recycled, rather than being disposed of in an injection well. We either process the water to the point where it can be returned to producers to be reused in future drilling operations (recycle quality water), or we treat the water to a greater extent, such that it exceeds the standards for drinking water, and can be returned to the ecosystem (discharge quality water). Recycling offers producers an alternative to the use of fresh water in hydraulic fracturing operations. This minimizes the impact on aquifers, particularly in arid regions of the United States. Since our merger with High Sierra in June 2012, we have recycled approximately 12 million barrels (504 million gallons) of recycle quality water and have returned approximately 8 million barrels (336 million gallons) of discharge quality water back to New Fork River, which is a tributary of the Colorado River. We also make discharge quality water available to producers and the surrounding community for purposes such as dust control.


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Our facilities in Colorado dispose of wastewater primarily into deep underground formations via injection wells. Two of our facilities in Colorado have the assets and technology needed to treat the water to the point that we can sell the water back to producers for use in future drilling operations.

Our facilities in Texas and North Dakota dispose of wastewater into deep underground formations via injection wells.

At our disposal facilities, we use proprietary well maintenance programs to enhance injection rates and extend the service lives of the wells.

Customers. The customers of our Wyoming and Colorado facilities consist primarily of large exploration and production companies that conduct drilling operations near our facilities. The customers of our Texas and North Dakota facilities consist of both wastewater transportation companies and producers. The primary customer of our Wyoming facility has committed to deliver a specified minimum volume of water to our facility under a long-term contract. 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 not under volume commitments, although certain of our facilities are connected to producer locations by pipeline. During the year ended March 31, 2016, 23% of the water treatment and disposal revenues of our water solutions segment were generated from our two largest customers of the segment, and 52% of the water 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 are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutions segment is the extent of exploration and production in the areas near our facilities, which is generally based upon producers’ expectations about the profitability of drilling new wells.

Pricing Policy. We generally charge customers a processing fee per barrel of wastewater processed. Certain of our contracts require the customer to deliver a specified minimum volume of wastewater over a specified period of time. We also generate revenue from the sale of hydrocarbons we recover in the process of treating the wastewater, which we take into consideration in negotiating the processing fees with our customers.

Billing and Collection Procedures. Our water solutions customers consist of large crude oil and natural gas producers, and also include smaller water transportation companies. We typically invoice customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our water solutions customers. We believe the following procedures enhance our collection efforts with our water solutions 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 paid invoices.

Trade Names. Our water solutions segment operates primarily under the NGL Water Solutions and Anticline Disposal trade names.

Technology. We hold multiple patents for processing technologies. We own a research and development center, which we use to optimize treatment processes and cost minimization. We believe that the technological capabilities of our water solutions business can be quickly implemented at new facilities and locations.

Liquids

Overview. Our liquids segment provides natural gas liquids procurement, storage, transportation, and supply services to customers through assets owned by us and third parties. Our liquids business also supplies the majority of the propane for our retail propane business. We also sell butanes and natural gasolines to refiners and producers for use as blending stocks and diluent and assist refineries by managing their seasonal butane supply needs. During the year ended March 31, 2016, we sold 2.1 billion gallons of natural gas liquids, an average of 5.72 million gallons per day.

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Operations. We procure natural gas liquids from refiners, gas processing plants, producers and other resellers for delivery to leased or owned storage space, common carrier pipelines, railcar terminals, and direct to certain customers. Our customers take delivery by loading natural gas liquids into transport vehicles 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 wholesale customers, protects our margins, and mitigates commodity price risk. Presales also reduce the impact of warm weather because the customer is required to take delivery of the propane regardless of the weather. We generally require cash deposits from these customers. In addition, on a daily basis we have the ability to balance our inventory by buying or selling propane, butanes, and natural gasoline to refiners, resellers, and propane producers through pipeline inventory transfers at major storage hubs.

In order to secure consistent supply during the heating season, we are often required to purchase volumes of propane during the entire fiscal year. In order 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 refiners during the winter blending season, when demand for butane is higher. We utilize a portion of our railcar fleet and a portion of our leased underground storage to store butane for this purpose.

We also transport customer-owned natural gas liquids on our leased railcars and charge the customers a transportation service fee. In addition, we sublease railcars to certain customers.

In addition, we purchase and sell asphalt. We utilize leased railcars to move the asphalt from our suppliers to our customers.

We own 19 natural gas liquids terminals and we lease a fleet of railcars. These assets give us the opportunity to access wholesale markets throughout the United States, and to move product to locations where demand is highest. We utilize these terminals and railcars primarily in the service of our wholesale operations, although we also provide transportation, storage, and throughput services to other parties to a lesser extent.


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The following table summarizes our natural gas liquids terminals and their throughput capacity:
Facility
 
Throughput Capacity
(gallons per day)
Rosemount, Minnesota
 
1,441,000

Lebanon, Indiana
 
1,058,000

West Memphis, Arkansas
 
1,058,000

Dexter, Missouri
 
930,000

East St. Louis, Illinois
 
883,000

Jefferson City, Missouri
 
883,000

St. Catharines, Ontario, Canada
 
700,000

Janesville, Wisconsin
 
553,000

Light, Arkansas
 
524,400

Rixie, Arkansas
 
524,400

West Springfield, Massachusetts
 
441,000

Albuquerque, New Mexico
 
408,000

Portland, Maine
 
360,000

Vancouver, Washington
 
358,000

Green Bay, Wisconsin
 
310,000

Ritzville, Washington
 
198,000

Thackerville, Oklahoma
 
180,000

Shelton, Washington
 
161,000

Superior, Montana (1)
 
120,000

Total
 
11,090,800

 
(1)
We own a terminal in Superior, Montana with throughput of 120,000 gallons per day that we are currently subleasing through October 2017 with an option to extend or to purchase.

We are currently building a rail terminal at the Port of Little Rock, Arkansas capable of receiving natural gas liquids by railcar, storing, and loading out via truck. The throughput capacity for this terminal is expected to be 120,000 gallons per day. We expect this terminal to be operational by June 30, 2016. Also, during the year ended March 31, 2016, we reached an agreement with the state of Maine’s Department of Transportation and, as of the end of April 2016, the Portland, Maine facility was shut down.

We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouri are operated for us by a third party for a monthly fee under an operating and maintenance agreement that expires in 2017. The terminal in St. Catherines, Ontario, Canada is operated by a third party under a year-to-year agreement.

We own the terminal assets. We own the land on which twelve of the terminals are located and we either have easements or lease the land on which seven of the terminals are located. The terminals in East St. Louis, Illinois and Jefferson City, Missouri have perpetual easements, and the terminal in St. Catharines, Ontario, Canada has a long-term lease that expires in 2022.

We own an underground storage facility near Delta, Utah. This facility currently has capacity to store approximately 4.2 million barrels of natural gas liquids. We have begun construction of a new cavern to expand the storage capacity, and we expect the new cavern to be operational in the second quarter of fiscal year ending March 31, 2017. We lease storage to 15 customers, with lease terms ranging from one to three years. The facility is located on property for which we have a long-term lease.

We lease 4,838 railcars, of which 765 are subleased to a third party. These include high pressure and general-purpose railcars.

We own 23 transloading units, which enable customers to transfer product from railcars to trucks. These transloading units can be moved to locations along a railroad where it is most convenient for customers to transfer their product.

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We lease natural gas liquids storage space to accommodate the supply requirements and contractual needs of our retail and wholesale customers. We lease storage space for natural gas liquids in various storage hubs in Arizona, Canada, Kansas, Mississippi, Missouri, and Texas.

The following table summarizes our significant leased storage space at natural gas liquids storage facilities and interconnects to those facilities:
 
 
Leased Storage Space
(gallons)
 
 
Storage Facility
 
Beginning
April 1,
2016
 
At
March 31,
2016
 
Storage Interconnects
Conway, Kansas
 
64,890,000

 
64,940,000

 
Connected to Enterprise Mid-America and NuStar Pipelines; Rail Facility
Borger, Texas
 
42,000,000

 
42,000,000

 
Connected to ConocoPhillips Blue Line Pipeline
Corunna, Ontario, Canada
 
15,800,000

 
2,100,000

 
Rail Facility
Bushton, Kansas
 
12,600,000

 
12,600,000

 
Connected to ONEOK North System Pipeline
Hattiesburg, Mississippi
 
9,660,000

 
6,300,000

 
Connected to Enterprise Dixie Pipeline; Rail Facility
Carthage, Missouri
 
7,560,000

 
7,560,000

 
Connected to Mid-America Pipeline
Redwater, Alberta, Canada
 
4,370,000

 
9,072,000

 
Connected to Cochin Pipeline; Rail Facility
Mont Belvieu, Texas
 
2,940,000

 
2,940,000

 
Connected to Enterprise Texas Eastern Products Pipeline
Napoleonville, LA
 
2,407,000

 
—

 
Connected to Enlink Pipeline; Rail Facility
Adamana, Arizona
 
1,680,000

 
1,680,000

 
Rail Facility
St. Clair, Michigan
 
—

 
6,300,000

 
Rail Facility
Marysville, Michigan
 
—

 
2,100,000

 
Connected to Cochin Pipeline
Total
 
163,907,000

 
157,592,000

 
 

During the typical heating season from September 15 through March 15 each year, we have the right to utilize ConocoPhillips’ capacity as a shipper on 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 independent retail, industrial, wholesale, petrochemical, refiner and natural gas liquids production customers. Our liquids business also supplies the majority of the propane for our retail propane business. We deliver the propane supply to our customers at terminals located on common carrier pipelines, rail terminals, refineries, and major United States propane storage hubs. During the year ended March 31, 2016, 34% of the revenues of our liquids segment were generated from our ten largest customers of the segment (exclusive of sales to our retail propane segment).

Seasonality. Our wholesale propane business is affected by the weather in a similar manner as our retail propane business as discussed below. However, we are able to partially mitigate the effects of seasonality by preselling a portion of our wholesale volumes to retailers and wholesalers and requiring the customer to take delivery regardless of the weather.

Competition. Our liquids business faces significant competition, as many entities, including other natural gas liquids wholesalers and companies involved in the natural gas liquids midstream industry (such as terminal and refinery operations), are engaged in the liquids 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;

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•
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 able to match our supply and sales commitments by offering our customers purchase contracts with flexible price, location, storage, and ratable delivery. However, certain common carrier pipelines require us to keep minimum in-line inventory balances year round to conduct our daily business, and these volumes may not be matched with a purchase commitment.

We generally require deposits from our customers for fixed priced future delivery of propane if the delivery date is more than 30 days after the time of contractual agreement.

Billing and Collection Procedures. Our liquids segment customers consist of commercial accounts varying in size from local independent distributors to large regional and national retailers. These sales tend to be large volume transactions that can range from 10,000 gallons up to 1,000,000 gallons, and deliveries can occur over time periods extending from days to as long as a year. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our liquids customers. We believe the following procedures enhance our collection efforts with our liquids 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 to take delivery of propane at their discretion;
•
we review receivable aging analyses regularly to identify issues or trends that may develop; and
•
we require our marketing personnel to manage their customers’ receivable position and suspend sales to customers that have not timely paid invoices.

Trade Names. Our liquids segment operates primarily under the NGL Supply Wholesale, NGL Supply Terminal Company, Sawtooth NGL Caverns, Centennial Energy, and Centennial Gas Liquids trade names.

Retail Propane

Overview. Our retail propane segment consists of the retail marketing, sale and distribution of propane and distillates, including the sale and lease of propane tanks, equipment and supplies, to more than 300,000 residential, agricultural, commercial and industrial customers. We also sell propane to certain resellers. We purchase the majority of the propane sold in our retail propane business from our liquids business, which provides our retail propane business with a stable and secure supply of propane. During the year ended March 31, 2016, we sold 182.9 million gallons of propane and distillates, an average of 501,000 gallons per day.

Operations. We market retail propane and distillates through our customer service locations. We sell propane primarily in rural areas, but we also have a number of customers in suburban areas where energy alternatives to propane such as natural gas are not generally available. We own or lease 113 customer service locations and 98 satellite distribution locations, with aggregate propane storage capacity of 11.9 million gallons and aggregate distillate storage capacity of 3.4 million gallons. Our customer service locations are staffed and operated to service a defined geographic market area and typically include a business office, product showroom, and secondary propane storage. Our satellite distribution locations, which are unmanned storage tanks, allow our customer service centers to serve an extended market area.


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Our customer service locations in Illinois and Indiana also rent over 17,000 water softeners and filters, primarily to residential customers in rural areas to treat well water or other problem water. We sell water conditioning equipment and treatment supplies as well. Although the water conditioning portion of our retail propane business is small, it generates steady year round revenues. The customer bases in Illinois and Indiana for retail propane and water conditioning have significant overlap, providing the opportunity to cross-sell both products between those customer bases.

The following table summarizes the number of our customer service locations and satellite distribution locations by state:
State
 
Number of Customer
Service Locations
 
Number of Satellite
Distribution Locations
Illinois
 
22

 
20

Maine
 
15

 
10

Georgia
 
14

 
5

Massachusetts
 
10

 
8

North Carolina
 
10

 
1

Pennsylvania
 
8

 
3

Kansas
 
8

 
28

Indiana
 
4

 
5

Connecticut
 
4

 
2

South Carolina
 
3

 
—

New Hampshire
 
3

 
4

Oregon
 
2

 
1

Washington
 
2

 
—

Mississippi
 
1

 
3

Maryland
 
1

 
1

Rhode Island
 
1

 
1

Tennessee
 
1

 
1

Utah
 
1

 
1

Wyoming
 
1

 
1

Colorado
 
1

 
—

Vermont
 
1

 
2

New Jersey
 
—

 
1

Total
 
113

 
98

 
We own 86 of our 113 customer service locations and 66 of our 98 satellite distribution locations, and we lease the remainder.

Tank ownership at customer locations is an important component to our operations and customer retention. At March 31, 2016, we owned the following propane storage tanks:

•
400 bulk storage tanks with capacities ranging from 2,000 to 90,000 gallons; and
•
over 300,000 stationary customer storage tanks with capacities ranging from 7 to 30,000 gallons.

We also lease an additional 20 bulk storage tanks.

At March 31, 2016, we owned a fleet of 440 bulk delivery trucks, 40 semi-tractors, 30 propane transport trailers and 520 other service trucks.

Retail deliveries of propane are usually made to customers by means of our fleet of bulk delivery trucks. Propane is pumped from the bulk delivery truck, which holds from 2,400 to 5,000 gallons, into a storage tank at the customer’s premises. The capacity of these storage tanks ranges from 50 to 30,000 gallons. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 25 gallons. These cylinders are either picked up on a delivery route, refilled at

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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 70% of our residential customers receive their propane supply via our automatic route delivery program, which allows us to maximize our delivery efficiency. For these customers, our delivery forecasting software system utilizes a customer’s historical consumption patterns combined with current weather conditions to more accurately predict the optimal time to refill the customer’s tank. The delivery information is then uploaded to routing software to calculate the most cost effective delivery route. Our automatic delivery program promotes customer retention by providing an uninterrupted supply of propane and enables us to efficiently conduct route deliveries on a regular basis. Some of our purchase plans, such as level payment billing, fixed price, and price cap programs, further promote our automatic delivery program.

Customers. Our retail propane and distillate customers fall into three broad categories: residential, commercial and industrial, and agricultural. At March 31, 2016, our retail propane and distillate customers were comprised of:

•
71% residential customers;
•
28% commercial and industrial customers; and
•
1% agricultural customers.

No single customer accounted for more than 1% of our retail propane volumes during the year ended March 31, 2016.

Seasonality. The retail propane and distillate business is largely seasonal due to the primary use of propane and distillates as heating fuels. In particular, residential and agricultural customers who use propane and distillates to heat homes and livestock buildings generally only need to purchase propane during the typical fall and winter heating season. Propane sales to agricultural customers who use propane for crop drying are also seasonal, although the impact on our retail propane volumes sold varies from year to year depending on the moisture content of the crop and the ambient temperature at the time of harvest. Propane and distillate sales to commercial and industrial customers, while affected by economic patterns, are not as seasonal as sales to residential and agricultural customers.

Competition. Our retail propane business faces significant competition, as many entities are engaged in the retail propane business, some of which have greater financial resources than we do. Also, we compete with alternative energy sources, including natural gas and electricity. The primary factors on which we compete are:

•
price;
•
availability of supply;
•
reliability of service;
•
long-term customer relationships; and
•
the acquisition of businesses.

Competition with other retail propane distributors in the propane industry is highly fragmented and generally occurs on a local basis with other large full-service, multi-state propane marketers, smaller local independent marketers, and farm cooperatives. Our customer service locations generally have one 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 competitive environment, since retailers are located in close proximity to their customers due to delivery economics. Our customer service locations generally have an effective 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, quality equipment, well-trained service staff, efficient delivery, 24-hours-a-day service for emergency repairs and deliveries, multiple payment and purchase options and the ability to maintain competitive prices. Additionally, we believe that our safety programs, policies and procedures are more comprehensive than many of our smaller, independent competitors, which offers a higher level of service to our customers. We also believe that our overall service capabilities and customer responsiveness differentiate us from many of our competitors.

Supply. Our retail propane segment purchases the majority of its propane from our liquids segment.


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Pricing Policy. Our pricing policy is an essential element in the successful marketing of retail propane and distillates. We protect our margin by adjusting our retail propane pricing based on, among other things, prevailing supply costs, local market conditions, and input from management at our customer service locations. We rely on our regional management to set prices based on these factors. Our regional managers are advised regularly of any changes in the delivered cost of propane and distillates, potential supply disruptions, changes in industry inventory levels, and possible trends in the future cost of propane and distillates. We believe the market intelligence provided by our liquids business, combined with our propane and distillate pricing methods allows us to respond to changes in supply costs in a manner that protects our customer base and our margins.

Billing and Collection Procedures. In our retail propane business, our customer service locations are typically responsible for customer billing and account collection. We believe that this decentralized and more personal approach is beneficial because our local staff has more detailed knowledge of our customers, their needs, and their history than would an employee at a remote billing center. Our local staff often develops relationships with our customers that 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 available to them at all times to answer customer inquiries.

Our retail propane customers must comply with our standards for extending credit, which typically includes submitting a credit application, supplying credit references, and undergoing a credit check with an appropriate credit agency.

Trade Names. We use a variety of trademarks and trade names that we own, including Hicksgas, Propane Central, Brantley Gas, Osterman, Pacer, Downeast Energy, Allied Propane, Lessig Oil and Propane, Proflame, Anthem Propane Exchange, Woodstock Gas, and Bernville Quality Fuels, among others. We typically retain and continue to use the names of the companies that we acquire and believe that this helps maintain the local identification of these companies and contributes to their continued success. We regard our trademarks, trade names, and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products.

Refined Products and Renewables

Overview. Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. During the year ended March 31, 2016, we sold 99.0 million barrels of refined products, an average of 271,000 barrels per day.

Operations. The refined products we handle include gasoline, diesel fuel, and heating oil. We purchase refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedule them for delivery primarily on the Colonial, Plantation, and Magellan pipelines. On certain interstate pipelines, demand for shipment exceeds the available capacity, and pipeline capacity is allocated to shippers based on their historical shipment volumes. We hold allocated capacity on the Colonial and Plantation pipelines.

A significant percentage of our business is priced on a back-to-back basis which minimizes our commodity price exposure. We sell our products to commercial and industrial end users, independent retailers, distributors, marketers, government entities, and other wholesalers of refined petroleum products. We sell our products at TLP’s terminals and at terminals owned by third parties. As discussed above, 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 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. In addition, we retained TransMontaigne’s marketing business, which is a significant part of our refined products and renewables segment, and TransMontaigne Product Services, LLC, its customer contracts and its line space on the Colonial and Plantation pipelines.


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The following table summarizes our leased storage space at refined products storage facilities:
Locations
 
Active Storage Capacity
(shell barrels)
Southeast Facilities
 
 
Albany, Georgia
 
203,000

Americus, Georgia
 
93,000

Athens, Georgia
 
193,000

Bainbridge, Georgia
 
372,000

Birmingham, Alabama
 
178,000

Charlotte, North Carolina
 
121,000

Collins, Mississippi
 
200,000

Collins/Purvis, Mississippi
 
94,000

Doraville, Georgia
 
438,000

Fairfax, Virginia
 
508,000

Greensboro, North Carolina
 
436,000

Griffin, Georgia
 
107,000

Linden, New Jersey
 
400,000

Lookout Mountain, Georgia
 
221,000

Macon, Georgia
 
174,000

Meridian, Mississippi
 
139,000

Montvale, Virginia
 
503,000

Nashville, Tennessee
 
11,000

Norfolk, Virginia
 
1,336,000

Port Everglades North, Florida
 
62,000

Richmond, Virginia
 
444,000

Rome, Georgia
 
152,000

Selma, North Carolina
 
218,000

Spartanburg, South Carolina
 
166,000

Total Southeast Facilities Storage Capacity
 
6,769,000

 
 
 
Mid-Continent Facilities
 
 
Magellan North system
 
202,000

NuStar East Products system
 
150,000

Total Mid-Continent Facilities Storage Capacity
 
352,000

Total Facilities Storage Capacity
 
7,121,000


We purchase ethanol primarily at production facilities in the Midwest and transport the ethanol via trucks and railcars for sale at various locations. We also blend ethanol into gasoline for sale to customers at TLP’s terminals. We market and handle logistics for third-party ethanol manufacturers for a service fee. We purchase biodiesel from production facilities in the Midwest and in Houston, Texas, and transport the biodiesel via railcar to sell to customers. We lease 67,000 barrels of biodiesel storage in Deer Park, Texas and have a biodiesel terminaling agreement at a 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 39 states. During the year ended March 31, 2016, 34% of the revenues of our refined products and renewables segment were generated from our ten largest customers of the segment. We sell to customers via rack spot sales, contract sales, bulk sales, and just-in-time sales.

Contract sales are made pursuant to negotiated contracts, generally ranging from one to twelve months in duration, that we enter into with local market wholesalers, independent gasoline station chains, heating oil suppliers, and other customers. Contract sales provide these customers with a specified volume of product during the term of the agreement. Delivery of product sold under these arrangements generally is at our truck racks. The pricing of the product delivered under a

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majority of our contract sales is based on published index prices, and varies based on changes in the applicable indices. In addition, at the customer’s option, the contract price may be fixed at a stipulated price per gallon.

Rack spot sales are sales that do not involve continuing contractual obligations to purchase or deliver product. Rack spot sales are priced and delivered 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 selling price for each product for each of our delivery locations. We announce or “post” to customers via website, e-mail, and telephone communications the rack spot sale price of various products for the following morning. Typical rack spot sale purchasers include commercial and industrial end users, independent retailers and small, independent marketers who resell product to retail gasoline stations or other end users. Our selling price of a particular product on a particular 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, and our desire to reduce inventory levels at that particular location that day.

Bulk sales generally involve the sale of products in large quantities in the major cash markets including the Houston Gulf Coast and New York Harbor. 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 these just-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 declines during the fall and winter months. However, the demand for diesel typically peaks during the fall and winter months due to colder temperatures in the Midwest and Northeast.

Competition. Our refined products and renewables business faces significant competition, as many entities are engaged in the refined products and renewables business, some of which have greater financial resources than we do. The primary factors on which we compete are:

•
price;
•
availability of supply;
•
reliability of service;
•
available space on common carrier pipelines;
•
storage availability;
•
logistics capabilities, including the availability of railcars, and proprietary terminals; and
•
long-term customer relationships.

Market Price Risk. Our philosophy is to maintain a minimum commodity price exposure through a combination of purchase contracts, sales contracts and financial derivatives. A significant percentage of our business is priced on a back-to-back basis which minimizes our commodity price exposure. For discretionary inventory, and for those instances where physical transactions cannot be appropriately matched, we utilize financial derivatives to mitigate commodity price exposure.  Specific exposure limits are mandated in our credit agreement and in our market risk policy.

The value of refined products in any local delivery market is the sum of the commodity price as reflected on the NYMEX and the basis differential for 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 quoted price in the futures markets for the prompt month. We typically utilize NYMEX futures contracts to mitigate commodity price exposure. We generally do not manage 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. Refiners and producers are required to blend a certain percentage of renewables into their refined products, although the percentage can vary from year to year based on the United States Environmental Protection Agency (“EPA”) mandates. In addition, the federal government has in recent years granted certain tax credits for the use of biodiesel, although on several occasions these tax credits have expired. In December 2015, the federal government passed a law to reinstate the tax credit retroactively to January 1, 2015, with the credit expiring on December 31, 2016. Changes in future

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mandates and incentives, or decisions by the federal government related to future reinstatement of the biodiesel tax credit, could result in changes in demand for ethanol and biodiesel.

Billing and Collection Procedures. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our refined products and renewables customers. We believe the following procedures enhance our collection efforts with our customers:

•
we require certain customers to prepay or place deposits for our services;
•
we require certain customers to post letters of credit or other forms of surety on a portion of our receivables;
•
we monitor individual customer receivables relative to previously-approved credit limits, and our automated rack delivery system gives us the option 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 paid invoices.

Trade Names. Our refined products and renewables segment operates primarily under the NGL Crude Logistics and TransMontaigne Product Services LLC trade names.

Employees

At March 31, 2016, we had 3,200 full-time employees. Thirteen of our employees at two of our locations are members of a labor union. We believe that our relations with our employees are satisfactory.

Government Regulation

Regulation of the Oil and Natural Gas Industries

Regulation of Oil and Natural Gas Exploration, Production and Sales. Sales of crude oil and natural gas liquids are not currently regulated and are transacted at market prices. In 1989, the United States Congress enacted the Natural Gas Wellhead Decontrol Act, which removed all remaining price and non-price controls affecting wellhead sales of natural gas. The FERC, which has the authority under the Natural Gas Act to regulate the prices and other terms and conditions of the sale of natural gas for resale in interstate commerce, has issued blanket authorizations for all natural gas resellers subject to its regulation, except interstate pipelines, to resell natural gas at market prices. Either Congress or the FERC (with respect to the 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 may affect 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 Interstate Commerce Act and natural gas pipeline and storage companies under the Natural Gas Act, and Natural Gas Policy Act of 1978 (the “NGPA”), as amended by the Energy Policy Act of 2005. While this regulation does not currently apply directly to our facilities, it may affect the price and availability of supply and thereby indirectly affect our business. Additionally, contracts we enter into for the transportation or storage of natural gas or crude oil are subject to FERC regulation including reporting or other requirements. The Joint Pipeline currently under construction by Grand Mesa and Saddlehorn will have several points of origin in Colorado and will terminate in Cushing, Oklahoma. The transportation services on this pipeline will be subject to FERC regulation once the pipeline commences service. In addition, the intrastate transportation and storage of crude oil and natural gas is subject to regulation by the state 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 on our business.

Anti-Market Manipulation Rules. We are subject to the anti-market manipulation provisions in the Natural Gas Act and the NGPA, as amended by the Energy Policy Act of 2005, which authorizes the FERC to impose fines of up to $1,000,000 per day per violation of the Natural Gas Act, the NGPA, or their implementing regulations. In addition, the Federal Trade Commission (“FTC”) holds statutory authority under the Energy Independence and Security Act of 2007 to prevent market

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manipulation in petroleum markets, including the authority to request that a court impose fines of up to $1,000,000 per violation. These agencies have promulgated broad rules and regulations prohibiting fraud and manipulation in oil and gas markets. The Commodity Futures Trading Commission (“CFTC”) is directed under the Commodity Exchange Act to prevent price manipulations in the commodity and futures markets, including the energy futures markets. Pursuant to statutory authority, the CFTC has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The CFTC also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per day per violation or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.

Maritime Transportation. The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels built and registered in the United States and owned and manned by United States citizens. Since we engage 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, we are responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to ensure that no violation of the Jones Act ownership restrictions occurs. The Jones Act also requires that all United States-flagged vessels be manned by United States citizens. Foreign-flagged seamen generally receive lower wages and benefits than those received by United States citizen seamen. This requirement significantly increases operating costs of United States-flagged vessel operations compared to foreign-flagged vessel operations. Certain foreign governments subsidize their nations’ shipyards. This results in lower shipyard costs both for new vessels and repairs than those paid by United States-flagged vessel owners. The United States Coast Guard and American Bureau of Shipping maintain the most stringent regimen of vessel inspection in the world, which tends to result in higher regulatory compliance costs for United States-flagged operators than for owners of vessels registered under foreign flags of convenience.

Environmental Regulation

General. Our operations are subject to stringent and complex federal, state and local laws and regulations relating to the protection of the environment. Accordingly, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact 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 our operations;
•
limiting or prohibiting construction activities in sensitive areas, such as wetlands, coastal regions or areas inhabited by endangered or threatened species;
•
delaying construction or system modification or upgrades during permit issuance or renewal;
•
requiring investigatory and remedial actions to mitigate pollution conditions caused by our operations or attributable to former operations; and
•
enjoining the operations of facilities deemed to be in non-compliance with permits or permit requirements issued pursuant to or imposed by such environmental laws and regulations.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where substances, hydrocarbons or wastes have been disposed or otherwise released. The trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment. Thus, there can be no assurance as to the amount or timing of future expenditures for environmental 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 governing environmental 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 solid and hazardous wastes; (ii) subject our operations to certain permitting and registration requirements; (iii) may result in the suspension or revocation of necessary permits, licenses and authorizations; (iv) impose substantial liabilities on us for pollution

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resulting from our operations; (v) require remedial measures to mitigate pollution from former or ongoing operations; and (vi) may result in the assessment of administrative, civil and criminal penalties for failure to comply with such laws. These laws include, among others, the Resource Conservation and Recovery Act (“RCRA”), the Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), the federal Clean Air Act, the Homeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean Water Act, the Safe Drinking Water Act, and comparable state statutes. For example, as a flammable substance, propane is subject to risk management plan requirements under section 112(r) of the federal Clean Air Act.

CERCLA, also known as the “Superfund” law, and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. While natural gas liquids are not a hazardous substance within the meaning of CERCLA, other chemicals used in or generated by our operations may be classified as hazardous. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict and joint and several liability for the costs of investigating and cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, most states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can seek to impose administrative, civil and criminal penalties for alleged non-compliance with RCRA and analogous state requirements. Certain wastes associated with the production of oil and natural gas, as well as certain 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 as non-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 could result 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 and financial position.

We currently own or lease properties where hydrocarbons are being or have been handled for many years. Although previous operators have utilized operating and disposal practices that were standard in the industry at the time, hydrocarbons or other wastes may have been disposed of or released on or under the properties owned or leased by us or on or under the other locations where these hydrocarbons and wastes have been transported for treatment or disposal. These properties and the wastes disposed thereon may be subject to CERCLA, RCRA and analogous state laws. Under these laws, we could be required to remove or remediate previously disposed wastes (including wastes disposed of or released by prior owners or operators), to clean up contaminated property (including contaminated groundwater) or to implement remedial measures to prevent or mitigate future contamination. We are not currently aware of any 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 Oil Pollution Prevention Act imposes liability for releases of crude oil from vessels or facilities into navigable waters. If a release of crude oil to navigable waters occurred 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 adopted oil pollution prevention regulations under the Clean Water Act. These oil pollution prevention regulations, as amended several times since their original adoption, require the preparation of a Spill Prevention Control and Countermeasure (“SPCC”) plan for facilities engaged in drilling, producing, gathering, storing, processing, refining, transferring, distributing, using, or consuming crude oil and oil products, and which due to their location, could reasonably be expected to discharge oil in harmful quantities into or upon the navigable waters of the United States. The owner or operator of an SPCC-regulated facility is required to prepare a written, site-specific spill prevention plan, which details how a facility’s operations comply with the requirements. 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, transfer operations (intrafacility piping), inspections and records, security, and training. Most importantly, the facility must fully implement the SPCC plan and train personnel in its execution. We maintain and implement such plans for our facilities.


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Air Emissions. Our operations are subject to the federal Clean Air Act and comparable state and local laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain permits prior to the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations and utilize specific emission 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 expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We are aware of planned EPA rulemakings concerning air emissions from the oil and gas industry, but the EPA’s schedule for proposing and finalizing these upcoming rulemakings is not presently known.

Water Discharges. The Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state 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 of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of 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 laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. We have discharge permits in place for a number of our facilities. These permits may require us to monitor and sample the storm water runoff from such facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

Underground Injection Control. Our underground injection operations are subject to the Safe Drinking Water Act, as well as analogous state laws and regulations, which establish requirements for permitting, testing, monitoring, record keeping, and reporting of injection well activities, as well as a prohibition against the migration of fluid containing any contaminant into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells could cause degradation of fresh groundwater resources, potentially resulting in suspension of our permits, issuance of fines and penalties from governmental agencies, incurrence of expenditures for remediation of the affected resource and imposition of liability by third parties for property damages and personal injuries.

Hydraulic Fracturing. The underground injection of crude oil and natural gas wastes are regulated by the Underground Injection Control program authorized by the Safe Drinking Water Act. The primary objective of injection well operating requirements is to ensure the mechanical integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of drinking water. We do not conduct any hydraulic fracturing activities. However, a portion of our customers’ crude oil and natural gas production is developed from unconventional sources that require hydraulic fracturing as part of the completion process and our water solutions business treats and disposes of wastewater generated from natural gas production, including production utilizing hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into the formation to stimulate oil and gas production. Legislation to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of underground injection and require federal permitting and regulatory control of hydraulic fracturing, as well as legislative proposals to require disclosure of the chemical constituents of the fluids used in the fracturing process, have been proposed in recent sessions of the United States Congress. Congress will likely continue to consider legislation to amend the Safe Drinking Water Act to subject hydraulic fracturing operations to regulation under the Act’s Underground Injection Control Program and/or to require disclosure of chemicals used in the hydraulic fracturing process. Federal agencies, including the EPA and the United States Department of the Interior, have asserted their regulatory authority to, for example, study the potential impacts of hydraulic fracturing on the environment, and initiate rulemakings to compel disclosure of the chemicals used in hydraulic fracturing operations, and establish pretreatment standards for wastewater from hydraulic fracturing operations. In addition, some states have also proposed or adopted legislative or regulatory restrictions on hydraulic fracturing, which include additional permit requirements, public disclosure of fracturing fluid contents, operational restrictions, and/or temporary or permanent bans on hydraulic fracturing. We expect that scrutiny of hydraulic fracturing activities will continue in the future.

Greenhouse Gas Regulation

There is a growing concern, both nationally and internationally, about climate change and the contribution of greenhouse gas emissions, most notably carbon dioxide, to global warming. In June 2009, the United States House of Representatives passed the ACES Act, also known as the Waxman-Markey Bill, but the ACES Act ultimately was not enacted

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by the 111th Congress. The ACES Act would have established an economy-wide cap on emissions of greenhouse gases in the United States and would have required most sources of greenhouse gas emissions to obtain and hold “allowances” corresponding to their annual emissions of greenhouse gases. A steady stream of legislation regarding climate change continues to be introduced into Congress, but none of the proposed bills have received bipartisan support. Recently, Rep. Chris Van Hollen (D-MD) introduced H.R. 1027, which would cap greenhouse gas emissions and require the purchase of carbon permits. The bill was referred to the Ways and Means Committee and the Energy and Commerce Committee on February 24, 2015 but has not yet advanced out of committee. The ultimate outcome of any possible future federal legislative initiatives is uncertain. In addition, several states have already adopted some legal measures to reduce emissions of greenhouse gases, primarily through the planned development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs.

On December 15, 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth’s atmosphere and other climatic changes. These findings allowed the EPA to adopt and implement regulations to restrict emissions of greenhouse gases under existing provisions of the federal Clean Air Act. Accordingly, the EPA has issued a number of regulations addressing greenhouse gas emissions under the federal Clean Air Act, including (i) the greenhouse gas reporting rule; (ii) greenhouse gas standards applicable to heavy-duty and light-duty vehicles; and (iii) a rule requiring stationary sources to address greenhouse gas emissions in Prevention of Significant Deterioration and Title V permits, known as the Tailoring Rule. The United States Supreme Court invalidated the Tailoring Rule in Utility Air Regulatory Group v. EPA on June 23, 2014. Under the Supreme Court’s decision, sources are no longer required to obtain Prevention of Significant Deterioration or Title V permits based solely on their greenhouse gas emissions; however, installation of the best available control technology for greenhouse gases may be required at sources that emit more than a de minimis amount of greenhouse gases and are otherwise required to obtain Prevention of Significant Deterioration permits. On January 14, 2015, the EPA announced its intention to propose regulations that would require reductions in methane and volatile organic compound emissions from the oil and gas industry. The schedule for when these regulations will be proposed or finalized is not presently known. The EPA’s greenhouse gas regulations could require us to incur costs to reduce emissions of greenhouse gases associated with our operations and also could adversely affect demand for the products that we transport, store, process, or otherwise handle in connection with our services.

Some scientists have suggested climate change from greenhouse gases could increase the severity of extreme weather, such as increased hurricanes and floods, which could damage our facilities. Another possible consequence of climate change is increased volatility in seasonal temperatures. The market for our natural gas liquids is generally improved by periods of colder weather and impaired by periods of warmer weather, so any changes in climate could affect the market for our products and services. If there is an overall trend of warmer temperatures, it would be expected to have an adverse effect on our business.

Because propane is considered a clean alternative fuel under the federal Clean Air Act Amendments of 1990, new climate change regulations may provide 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 action is taken that restricts certain aspects of our business or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business and prospects could be adversely affected.

Safety and Transportation

All states in which we operate have adopted fire safety codes that regulate the storage and distribution of propane and distillates. In some states, state agencies administer these laws. In others, municipalities administer them. We conduct training programs to help ensure that our operations comply with applicable 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 and procedures currently in effect at all of our facilities for the handling, storage and distribution of propane and distillates and related service and installation operations are consistent with industry standards and are in compliance in all material respects with applicable environmental, health and safety laws.


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With respect to the transportation of propane, distillates, crude oil, and water, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the United States Department of Transportation (“DOT”). Specifically, crude oil pipelines are subject to regulation by the DOT, through the Pipeline and Hazardous Materials Safety Administration (“PHMSA”), under the Hazardous Liquid Pipeline Safety Act of 1979 (“HLPSA”), which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the storage and transportation of hazardous liquids by and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. 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 for hazardous liquid pipelines, established safety standards for certain “regulated gathering lines,” and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in high consequence areas (“HCAs”), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, Congress required mandatory inspections for certain United States crude oil and natural gas transmission pipelines in HCAs and mandated that regulations be issued for low-stress hazardous liquid pipelines and pipeline control room management. In January 2012, the federal government passed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “2011 Pipeline Safety Act”). This act provides for additional regulatory oversight of the nation’s pipelines, increases the penalties for violations of pipeline safety rules, and complements the DOT’s other initiatives. The 2011 Pipeline Safety Act increases the maximum fine for the most serious pipeline safety violations involving deaths, injuries or major environmental harm from $1 million to $2 million. In addition, this law established additional safety requirements for newly constructed pipelines. The law also provides for (i) additional pipeline damage prevention measures, (ii) allowing the Secretary of Transportation to require automatic and remote-controlled shut-off valves on new pipelines, (iii) requiring the Secretary of Transportation to evaluate the effectiveness of expanding pipeline integrity management and leak detection requirements, (iv) improving the way the DOT and pipeline operators provide information to the public and emergency responders, and (v) reforming the process by which pipeline operators notify federal, state and local officials of pipeline accidents.

Railcar Regulation

We transport a significant portion of our natural gas liquids and crude oil via rail transportation, and we own and lease a fleet of railcars for this purpose. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies.

Occupational Health Regulations

The workplaces associated with our manufacturing, processing, terminal and storage facilities are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. We believe we have conducted our operations in substantial compliance with OSHA 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, we expect to increase our expenditures relating to compliance with likely higher industry and regulatory safety standards such as those described above. However, these expenditures cannot be accurately estimated at this time, but we do not expect them to have a material adverse effect on our business.

Available Information on our Website

Our website address is http://www.nglenergypartners.com. We make available on our website, free of charge, the periodic reports that we file with or furnish to the Securities and Exchange Commission (“SEC”), as well as all amendments to these reports, as soon as reasonably practicable after such reports are filed with or furnished to the SEC. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and 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 an internet site (http://www.sec.gov) that contains reports, proxy and information statements and other information related to issuers that file electronically with the SEC.

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Item 1A.    Risk Factors

Risks Related to Our Business

We may not have sufficient cash to enable us to pay the minimum quarterly distribution to our unitholders following the establishment of cash reserves by our general partner and the payment of costs and expenses, including reimbursement of expenses to our general partner.

We may not have sufficient cash each quarter to enable us to pay the minimum quarterly distribution. The amount of cash we can distribute on our common units principally 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, refined products, ethanol, and biodiesel that we buy for resale and whether we are able to pass along cost increases to our customers;
•
the volume of wastewater delivered to our processing facilities;
•
disruptions in the availability of crude oil and/or natural gas liquids supply;
•
our ability to renew leases for storage and 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:

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the level of capital expenditures we make;
•
the cost of acquisitions, if any;
•
restrictions contained in our credit agreement (the “Credit Agreement”), the purchase agreement governing our outstanding 6.65% senior secured notes due 2022 (the “Note Purchase Agreement”), the indentures governing our outstanding 6.875% senior notes due 2021 and 5.125% senior notes due 2019 (collectively, the “Indentures”) and other debt service requirements;
•
fluctuations in working capital needs;
•
our ability to borrow funds and access capital markets;
•
the amount, if any, of cash reserves established by our general partner; and
•
other business risks discussed in this Annual Report that may affect our cash levels.

The amount of cash we have available for distribution to our unitholders depends primarily on our cash flow rather than on our profitability, which may prevent us from making distributions, even during periods in which we realize net income.

The amount of cash we have available for distribution depends primarily on our cash flow and not solely on profitability, which will be affected by non-cash items. As a result, we might make cash distributions during periods when we record net losses for financial accounting purposes and we might not make cash distributions during periods when we record net income for financial accounting purposes.


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Our future financial performance and growth may be limited by our ability to successfully complete accretive acquisitions on economically acceptable terms.

Our ability to complete acquisitions on economically acceptable terms may be limited by various factors, including, but not limited to:

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increased competition for attractive acquisitions;
•
covenants in our Credit Agreement, Note Purchase Agreement and Indentures that limit the amount and types of indebtedness that we may 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 existing unitholders 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 on economically favorable terms, that any acquisitions will not be dilutive to earnings and distributions or that any additional debt that we incur to finance an acquisition will not affect our ability to make distributions to unitholders. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations may change significantly, and unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

While our business strategy includes expanding our existing retail propane operations through internal growth, our ability to expand our retail propane business will primarily be dependent on our ability to successfully complete accretive acquisitions. There can be no assurances that we will be able to identify suitable acquisition candidates or successfully complete acquisitions in this line of business. The propane industry is a mature industry, and we anticipate only limited growth in total national demand for propane in the near future. Increased competition from alternative energy sources has limited growth in the propane industry, and year-to-year industry volumes are primarily impacted by fluctuations in weather and economic conditions.

We may be subject to substantial risks in connection with the integration and operation of acquired businesses, in particular those businesses with operations 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:

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the inability to successfully integrate the operations of recently acquired businesses;
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the assumption of known or unknown liabilities, including environmental liabilities;
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limitations on rights to indemnity from the seller;
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mistaken assumptions about the overall costs of equity or debt or synergies;
•
unforeseen difficulties operating in new geographic areas or in new business segments;
•
the diversion of management’s and employees’ attention from other business concerns;
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customer or key employee loss from the acquired businesses; and
•
a potential significant increase in our indebtedness and related interest expense.

We undertake due diligence efforts in our assessment of acquisitions, but may be unable to identify or fully plan for all issues and risks attendant to a particular acquisition. Even when an issue or risk is identified, we may be unable to obtain adequate contractual protection from the seller. The realization of any of these risks could have a material adverse effect on the success of a particular acquisition or our consolidated financial position, results of operations 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 businesses is a complex, costly and time-consuming process and may involve assets with which we have limited operating experience. Failure to timely and successfully integrate acquired businesses into our existing operations may have a material adverse effect on our business, consolidated financial position or results of operations. In addition to the risks set forth above, new businesses will subject us to additional business and operating risks, such as the acquisitions not being accretive to our unitholders as a result of decreased profitability, increased interest expense related to debt we incur to make

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such acquisitions or an inability to successfully integrate those operations into our overall business operation. The realization of any of these risks could have a material adverse effect on our consolidated financial position or results of operations.

Our substantial indebtedness may limit our flexibility to obtain financing and to pursue other business opportunities.

At March 31, 2016, the face amount of our long-term debt was $2.9 billion. Our level of debt could have important consequences to us, including the following:

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our ability to obtain additional financing, if necessary, for working capital, capital expenditures, acquisitions or other purposes may be impaired or such financing may not be available on favorable terms;
•
our funds available for operations, future business opportunities and distributions to unitholders will be reduced by that portion of our cash flow required to make principal and interest payments on our debt;
•
we may be more vulnerable to competitive pressures or a downturn in our business or the economy generally; and
•
our flexibility in responding to changing business and economic conditions may be limited.

Our ability to service our debt will depend on, among other things, our future financial and operating performance, which will be affected by prevailing economic and weather conditions, and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service our future indebtedness, we would be forced to take actions such as reducing distributions, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets or seeking additional equity capital. We may be unable to effect any of these actions on satisfactory terms or at all. The agreements governing our indebtedness permit us to incur additional debt under certain circumstances, and we will likely need to incur additional debt in order to implement our growth strategy. We may experience adverse consequences from increased levels of debt.

Restrictions in our Credit Agreement, Note Purchase Agreement and 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, Note Purchase Agreement and Indentures limit our ability to, among other things:

•
incur additional debt or issue letters of credit;
•
redeem or repurchase units;
•
make certain loans, investments and acquisitions;
•
incur certain liens or permit them to exist;
•
engage in sale and leaseback transactions;
•
enter into certain types of transactions with affiliates;
•
enter into agreements limiting subsidiary distributions;
•
change the nature of our business or enter into a substantially different business;
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merge or consolidate with another company; and
•
transfer or otherwise dispose of assets.

We are permitted to make distributions to our unitholders under our Credit Agreement, Note Purchase Agreement and Indentures as long as no default or event of default exists both immediately before and after giving effect to the declaration and payment of the distribution and the distribution does not exceed available cash for the applicable quarterly period. Our Credit Agreement, Note Purchase Agreement and Indentures also contain covenants requiring us to maintain certain financial ratios. Please see Note 8 to our consolidated financial statements included in this Annual Report.

The provisions of our Credit Agreement, Note Purchase Agreement and Indentures may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our Credit Agreement could result in a covenant violation, default or an event of default that could enable our lenders, subject to the terms and conditions of our Credit Agreement, to declare the outstanding principal of that debt, together with accrued and unpaid interest, to be immediately due and payable. If we were unable to repay the accelerated amounts, our lenders could proceed against the collateral we granted them to secure our debts. If the payment of our debt is accelerated, defaults under our other debt instruments, if any then exist,

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may be triggered, and our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

Increases in interest rates could adversely impact our unit price, our ability to issue equity or incur debt for acquisitions or other purposes, and our 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 than current levels, causing our financing costs to increase accordingly. As with other yield-oriented securities, our unit price will be impacted by our level of cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank yield-oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make payments on our debt obligations and cash distributions at our intended levels.

Our business depends on the availability of supply of crude oil, natural gas liquids, and refined products in the United States and Canada, which is dependent on the ability and willingness of other parties to explore for and produce crude oil and natural gas. Spending on crude oil and natural gas exploration and production may be adversely affected by industry and financial market conditions that are beyond our control including, without limitation, (1) prices for crude oil, condensate, and natural gas liquids, (2) crude oil and natural gas producers having success in their operations, (3) continued commercially viable areas in which to explore and produce crude oil and natural gas, (4) the availability of liquids-rich natural gas needed to produce natural gas liquids, and (5) the availability of pipeline transportation and storage capacity.

Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business have been, and may continue to be, adversely affected by industry and financial market conditions and existing or new regulations, such as those related to environmental matters, that are beyond 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 oil and natural gas in the United States and Canada, and to extract natural gas liquids from natural gas as well as the availability of necessary pipeline transportation and storage capacity. Customers’ expectations of lower market prices for crude oil and natural gas, as well as the availability of capital for operating 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 to curtail spending, thereby reducing business opportunities and demand for our services.

Industry conditions are influenced by numerous factors over which we have no control, such as the availability of commercially viable geographic areas 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 supply of and demand for crude oil and natural gas, environmental restrictions on the exploration and production of crude oil and natural gas, such as existing and proposed regulation of hydraulic fracturing, domestic and worldwide economic conditions, political instability in crude oil and natural gas producing countries and merger and divestiture activity among our current or potential customers. The volatility of the oil and natural gas industry and the resulting impact on exploration and production activity could adversely impact the level of drilling activity. This reduction may cause a decline in business opportunities 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 in our 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 extent existing 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 which it returns to former levels, if ever, will be uncertain. Prior adverse changes in the global economic environment and capital markets and declines in prices for crude oil and natural gas have caused many customers to reduce capital budgets for future periods and have caused decreased demand for crude oil and natural gas. Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause customers to make additional reductions to capital budgets in the future even if commodity prices increase from current levels. These cuts in spending may curtail drilling programs and other discretionary spending, which could result in a reduction in business opportunities and demand for our services, the rates we can charge and our utilization. In addition, certain of our customers could become unable to pay their suppliers, including us. Any of these conditions or events could materially and adversely affect our consolidated results of operations.


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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. During calendar year 2015, crude oil prices remained low and trended down during the second half of the year and into the first quarter of calendar year 2016. This had an unfavorable impact on the revenues of our water solutions business. The volume of water we process is driven in part by the level of crude oil production, and the lower crude oil prices have given producers less incentive to expand production. In addition, a portion of the revenues of our water solutions business is generated from the sale of hydrocarbons that we recover when processing wastewater, and lower crude oil prices have an adverse impact on 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 solutions business.

In addition, the sharp decline in crude oil prices has reduced the incentive for producers to expand production. If crude oil prices remain low, resultant declines in crude oil production could adversely impact volumes in our crude oil logistics business.

Our profitability could be negatively impacted by price and inventory risk related to our business.

The crude oil logistics, liquids, retail propane, refined products, and renewables businesses are “margin-based” businesses in which our realized margins depend on the differential of sales prices over our total supply costs. Our profitability is therefore sensitive to changes in product prices caused by changes in supply, pipeline transportation and storage capacity or other market conditions.

Generally, we attempt to maintain an inventory position that is substantially balanced between our purchases and sales, including our future delivery 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, and we may be required to obtain supply at increased prices that cannot be passed through to our customers. In general, product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major storage points, creating the potential for sudden and drastic price fluctuations. Sudden and extended wholesale price increases could reduce our margins and could, if continued over an extended period of time, reduce demand by encouraging retail customers to conserve or convert to alternative energy sources. Conversely, a prolonged decline in product prices could potentially result in a reduction of the borrowing base under our working capital facility, and we could be required to liquidate inventory that we have already presold.

One of the strategies of our refined products and renewables segment is to purchase refined products in the Gulf Coast region and to transport the product on the Colonial pipeline for sale in the Southeast and East Coast. Spreads between product prices in the Gulf Coast compared to locations along the Colonial pipeline can vary significantly, which can create volatility in our product margins. In addition, we are subject to the risk of a price decline between the 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 futures contracts 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 larger and more firmly established and may have greater marketing and development budgets and capital resources than we do.

We experience competition in all of our segments. In our liquids segment, we compete for natural gas supplies and also for customers for our services. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport, store and market natural gas. Our natural gas liquids terminals compete with other terminaling and storage providers in the transportation and storage of natural gas liquids. Natural gas and natural gas liquids also compete with other forms of energy, including electricity, coal, fuel oil and renewable or alternative energy.

Our crude oil logistics segment faces significant competition for crude oil supplies and also for customers for our services. These operations also face competition from trucks for incremental and marginal volumes in the areas we serve. Further, our crude oil terminals compete with terminals owned by integrated petroleum companies, refining and marketing companies, independent terminal companies and distribution companies with marketing and trading operations.

Our water solutions segment is in direct and indirect competition with other businesses, including disposal and other wastewater treatment businesses.

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We face strong competition in the market for the sale of retail propane and distillates. Our competitors vary from retail propane companies who are larger and have substantially greater financial resources than we do to small retail propane distributors, rural electric cooperatives and fuel oil distributors who have entered the market due to a low barrier to entry. The actions of our retail-marketing competitors, including the impact of imports, could lead 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 for customers for our services.

We can make no assurances that we will be able to compete successfully in each of our lines of business. If a competitor attempts to increase market share by reducing prices, we may lose customers, which would reduce our revenues.

Our business would be adversely affected if service at our principal storage facilities or on the common carrier pipelines we use is interrupted.

We use third-party common carrier pipelines to transport and we use third-party facilities to store our products. Any significant interruption in the service at these storage facilities or on the common carrier pipelines we use would adversely affect our ability to obtain products.

Our business would be adversely affected if service on the railroads we use is interrupted.

We transport crude oil, natural gas liquids, ethanol, and biodiesel by railcar. We do not own or operate the railroads on which these railcars are transported. Any disruptions in the operations of these railroads could adversely impact our ability to deliver product to our customers.

If we are unable to purchase product from our principal suppliers, our results of operations would be adversely affected.

If we are unable to purchase product from significant suppliers, our failure to obtain alternate sources of supply at competitive prices and on a timely basis would adversely affect our ability to satisfy customer demand, reduce our revenues and adversely affect our consolidated results of operations.

The fees charged to customers under our agreements with them for the transportation and marketing of crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel may not escalate sufficiently to cover increases in costs and the agreements may be suspended in some circumstances, which would affect our profitability.

Our costs may increase at a rate greater than the rate that the fees that we charge to customers increase pursuant to our contracts with them. Additionally, some customers’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of crude oil, condensate, and/or natural gas liquids are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities of our customers. If the escalation of fees is insufficient to cover increased costs or if 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, refined products, ethanol, and biodiesel and related transportation and hedging activities, and our processing of wastewater, expose us to potential regulatory risks.

The FTC, the FERC, and the CFTC hold statutory authority to monitor certain segments of the physical and financial energy commodity markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of energy commodities, and any related transportation and/or hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Additionally, to the extent that we enter into transportation contracts with pipelines that are subject to the FERC regulation or we become subject to the FERC regulation ourselves (see “–Some of our operations could be subject to the jurisdiction of the FERC in the future,” below), we will be obligated to comply with the FERC’s regulations and policies. Any failure on our part to comply with the FERC’s regulations and policies at that time could result in the imposition of civil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material and adverse effect on our business, consolidated results of operations and financial position.

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The intrastate transportation or storage of crude oil and refined products is subject to regulation by the state in which the facilities and transactions occur and requires compliance with all such regulation. These state regulations can have a material and adverse effect on that portion of our business, consolidated results of operations and financial position.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) provides for statutory and regulatory requirements for derivative transactions, including crude oil and natural gas hedging transactions. Certain transactions will be required to be cleared on exchanges and cash collateral will have to be posted. The Dodd-Frank Act provides for a potential exemption from these clearing and cash collateral requirements for commercial end users and it includes a number of defined terms that will be used in determining how this exemption applies to particular derivative transactions and the parties to those transactions. Since the Dodd-Frank Act mandates the CFTC to promulgate rules to define these terms, the full impact of the Dodd-Frank Act on our hedging activities is uncertain at this time. However, new legislation and any new regulations could significantly increase the cost of derivative contracts (including through requirements to post 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 to monetize or restructure our existing derivative contracts, and increase our exposure to less creditworthy counterparties. The Dodd-Frank Act may also materially 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 Safety Accountability (“CSA”) program. The CSA program measures a carrier’s safety performance based on violations observed during roadside inspections as opposed to compliance audits performed by the FMCSA. The quantity and severity of any violations are compared to a peer group of companies of comparable 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 a progressive intervention strategy that begins with a company providing the FMCSA with an acceptable plan of corrective action that the company will implement. If the issues are not corrected, the intervention escalates to on-site compliance audits and ultimately an “unsatisfactory” rating and the revocation of the company’s operating authority by the FMCSA, which could result in a material 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 and the cost of compliance with, violation of or liabilities under, such laws and regulations could adversely affect our profitability.

Our operations, including those involving crude oil, condensate, natural gas liquids, refined products, renewables, and crude oil and natural gas produced wastewater, are subject to stringent federal, state, provincial and local laws and regulations relating to the protection of natural resources and the environment, health and safety, waste management, and transportation and disposal of such products and materials. We face inherent risks of incurring significant environmental costs and liabilities in the performance of our operations due to handling of wastewater and hydrocarbons, such as crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel. For instance, our water solutions business carries with it environmental risks, including leakage from the treatment plants to surface or subsurface soils, surface water or groundwater, or accidental spills. Our crude oil logistics, liquids, and refined products and renewables businesses carry similar risks of leakage and sudden or accidental spills of crude oil, natural gas liquids, 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 and water, including trucks, railcars and barges, each of which is subject to regulation. With respect to transportation by truck, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002, which cover the security and transportation of hazardous materials 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 the Federal Railroad Administration of the DOT, as well as other federal and state regulatory agencies. Recent railcar accidents within the industry in Quebec, Alabama, North Dakota, Pennsylvania and Virginia, in each case involving trains carrying crude oil from the Bakken region (none of which directly involved any of our business operations), have led to increased legislative and regulatory scrutiny over the safety of transporting crude oil by railcar. In 2015, the DOT, through the PHMSA, issued a rule implementing new railcar standards

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and railroad operating procedures. The introduction of these or other 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 which new railcars are retrofitted or constructed to meet new specifications. Our barge transportation operations are subject to the Jones Act, a federal law restricting marine transportation in the United States to vessels built and registered in the United States, and manned and owned by United States citizens, as well as rules and regulations of the United States Coast Guard. Non-compliance with any of these regulations could result in increased costs related to the transportation of our products and could have an adverse effect on our business.

In addition, under certain environmental laws, we could be subject to strict and/or joint and several liability for the investigation, removal or remediation of previously released materials. As a result, these laws could cause us to become liable for the conduct of others, such as prior owners or operators 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 actions were 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 have been 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 various federal, state, provincial and local governmental authorities relating to wastewater handling, discharge and disposal, air emissions, transportation and other environmental matters. These authorizations subject us to terms and conditions which may be onerous or costly to comply with, and that may require costly operational modifications to attain and maintain compliance. The renewal, amendment or modification of these permits, approvals and other authorizations may involve the imposition of even more stringent and burdensome terms and conditions with attendant higher costs and more significant effects upon our operations.

Changes in environmental laws and regulations occur frequently. New laws or regulations, changes to existing laws or regulations, such as more stringent 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 wells may 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 operations and financial position.

Furthermore, our customers in the oil and gas production industry are subject to certain environmental laws and regulations that may impose significant costs and liabilities on them, including as a result of changes in such laws and regulations causing them to become more stringent over time. For example, in April 2012, the EPA issued final rules that established new air emission controls for crude oil and natural gas production and gas processing operations. The final rule includes a 95% reduction in volatile organic compounds (“VOCs”) (which contribute to smog) emitted during the completion of new and modified hydraulically fractured wells. In August 2013, the EPA updated its 2012 air emission standards for crude oil and natural gas storage tanks to extend the compliance date and allow an alternate emissions limit of less than four tons per year without emission controls. On September 18, 2015, the EPA proposed new source performance standards for the oil and gas sector, which would require reductions in methane and VOC emissions across the oil and gas industry if finalized. The schedule for when these regulations will be proposed or finalized is not presently known, although the EPA has indicated its intention to finalize the regulations by the end of calendar year 2016. Any significant increased costs or restrictions placed on our customers to comply with environmental laws and regulations could affect their production output significantly. Such an effect could materially and adversely affect our utilization and profitability, thus reducing demand for our midstream services. Such an effect on our customers could materially and adversely affect our utilization and profitability. The adoption or implementation of any new regulations imposing additional reporting obligations on greenhouse gas emissions, or limiting greenhouse gas emissions from our equipment and operations, could require us to incur significant costs.

Federal and state legislation and regulatory initiatives relating to our hydraulic fracturing customers could result in increased costs and additional operating restrictions or delays and could harm our business.

Hydraulic fracturing is a frequent practice in the crude oil and natural gas fields in which our water solutions segment operates. Hydraulic fracturing is an important and common process used to facilitate production of natural gas and other hydrocarbon condensates in shale formations, as well as tight conventional formations. The hydraulic fracturing process is primarily regulated by state oil and gas authorities. This process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that chemicals used in the hydraulic fracturing process could adversely affect drinking water supplies. New laws or regulations, or changes to existing laws or regulations in response to this perceived threat may adversely impact the oil and gas drilling industry. For instance, the EPA has asserted federal regulatory

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authority over certain hydraulic fracturing practices involving the use of diesel fuel under the Safe Drinking Water Act and its Underground Injection Control program. In February 2014, the EPA issued technical guidance for the permitting of the underground injection of diesel fuel for hydraulic fracturing activities. At the request of the United States Congress, the EPA is undertaking a study of the impact of hydraulic fracturing on drinking water resources. In June 2015, the EPA released its draft assessment, which found that although hydraulic fracturing activities have the potential to impact drinking water resources, there is no evidence that hydraulic fracturing has led to widespread, systemic impacts on drinking water resources in the United States. In addition, the United States Department of the Interior issued a final rule on March 20, 2015 updating existing regulation of hydraulic fracturing activities on federal and tribal lands, including requirements for disclosure of chemicals used in hydraulic fracturing to the Bureau of Land Management, well bore integrity and handling of flowback water. Also, legislation has been introduced, but not adopted, in Congress to provide for federal regulation of hydraulic fracturing. In addition, some states have adopted and other states are considering adopting regulations that could restrict or regulate hydraulic fracturing in certain circumstances. For example, some states have adopted legislation requiring the disclosure of hydraulic fracturing chemicals, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the hydraulic fracturing process could adversely affect groundwater. Other states, such as New York, have banned hydraulic fracturing. We cannot predict whether any proposed federal, state or local laws or regulations will be enacted and, if so, what actions any such laws or regulations would require or prohibit. However, any restrictions on hydraulic fracturing could lead to operational delays or increased operating costs and regulatory burdens that could make it more difficult or costly to perform hydraulic fracturing which would negatively impact our customer base resulting in an adverse effect on our profitability.

Federal and state legislation and regulatory initiatives relating to saltwater disposal wells could result in increased costs and additional operating restrictions or delays and could harm our business.

The water disposal process is primarily regulated by state oil and gas authorities. This water disposal process has come under considerable scrutiny from sections of the public as well as environmental and other groups asserting that the operation of certain water disposal wells has caused increased seismic activity. New laws 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 its potential 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 geologic formation 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 would require or prohibit. However, any restrictions on water disposal could lead to operational delays or increased operating costs and regulatory burdens that could 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 or man-made disasters. During periods of heavy snow, ice, rain or extreme weather conditions such as high winds, tornados and hurricanes or after other natural disasters such as earthquakes or wildfires, we may be unable to move our trucks or railcars between locations and our facilities may be damaged, thereby reducing our ability to provide services and generate revenues. In addition, hurricanes or other severe weather in the Gulf Coast region could seriously disrupt the supply of products and cause serious shortages in various areas, including the areas in which we operate. These same conditions may cause serious damage or destruction to homes, business structures and the operations of customers. Such disruptions could potentially have a material adverse impact on our 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 financial position 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 such commodities for physical delivery to our customers, such as independent refiners or major oil companies, or by entering into future delivery obligations under contracts for forward sale. We also enter into financial derivative contracts, such as futures, to manage commodity price risk. Through these transactions, we seek to maintain a position that is substantially balanced between purchases on the one hand, and sales or future delivery obligations on the other

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hand. These policies and practices cannot, however, eliminate all risks. For example, any event that disrupts our anticipated physical supply of commodities could expose us to risk of loss resulting from the need to cover obligations required under contracts for forward sale. Additionally, we can provide no assurance that our processes and procedures will detect and/or prevent all violations of our risk management policies and procedures, particularly if deception or other intentional misconduct is involved.

Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of basis risk. In a backwardated market (when prices for future deliveries are lower than current prices), basis risk is created with respect to timing. In these instances, physical inventory generally loses value as price of such physical inventory declines over time. Basis risk cannot be entirely eliminated, and basis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our consolidated financial position and results of operations.

The counterparties to our commodity derivative and physical purchase and sale contracts may not be able to perform their obligations to us, which could materially 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 gas commodities sector overall for an extended or near term period of time could result in counterparty defaults on our derivative and physical purchase and sale contracts. This could impair our ability to obtain supply to fulfill our sales delivery commitments or obtain supply at reasonable prices, which could result in decreased 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 do so. We may, as a component of our overall business strategy, increase or decrease from time to time our use of such derivative financial instruments in the future. Our use of such derivative financial instruments could cause us to forego the economic benefits we would otherwise realize if commodity prices or interest rates were to change in our favor. In addition, although we monitor such activities in our risk management processes and procedures, such activities could result in losses, which could adversely affect our consolidated results of operations and impair our ability to make payments on our debt obligations or distributions to our unitholders.

Some of our operations could be subject to the jurisdiction of the FERC in the future.

The Joint Pipeline currently under construction by Grand Mesa and Saddlehorn will have several points of origin in Colorado and will terminate in Cushing, Oklahoma. The transportation services on this pipeline will be subject to FERC regulation once the pipeline commences service. Any of our transportation services could in the future become subject to the jurisdiction of the FERC, which could adversely affect the terms of service, rates and revenues of such services. At the date of this Annual Report, our facilities do not fall under the FERC’s jurisdiction. Currently, the FERC regulates the transportation of crude oil and refined products on interstate pipelines, among other things. Intrastate transportation and gathering pipelines that do not provide interstate services are not subject to regulation by the FERC. However, the distinction between the FERC-regulated interstate pipeline transportation on the one hand and intrastate pipeline transportation on the other hand, is a fact-based determination.

The classification and regulation of our crude oil pipelines are subject to change based on future determinations by the FERC, federal courts, Congress or regulatory commissions, courts or legislatures in the states in which we operate. Glass Mountain, one of our joint ventures, owns a pipeline in Oklahoma that carries crude oil owned by us and by third parties. We believe that the pipeline segments on which Glass Mountain would provide service to third parties and the services it would provide to third parties on this pipeline system meet the traditional tests that the FERC has used to determine that the pipeline services provided are not in interstate commerce. However, we cannot provide assurance that the FERC will not in the future, either at the request of other entities 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 its jurisdiction, or that such a determination would not adversely affect Glass Mountain’s or our consolidated results of operations. If the FERC’s regulatory reach 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 commit substantial capital to comply with such regulations and such expenditures could have a material and adverse effect on our consolidated results of operations and cash flows.


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Volumes of crude oil recovered during the wastewater treatment process can vary. Any significant reduction in residual crude oil content in wastewater we treat will affect our recovery of crude oil and, therefore, our profitability.

A portion of revenues in our water solutions business is generated from the sale of hydrocarbons that we recover when processing wastewater. Our ability to recover sufficient volumes of hydrocarbons is dependent upon the residual crude oil content in the wastewater we treat, which is, among other things, a function of water temperature. Generally, where water temperature is higher, residual crude oil content is lower. Thus, our crude oil recovery during the winter season is substantially higher than our recovery during the summer season. Additionally, residual crude oil content will decrease if, among other things, producers begin recovering higher levels of crude oil in produced wastewater prior to delivering such water to us for treatment. Any reduction in residual 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 against suppliers of electricity, natural gas and fuel oil. Competition from alternative energy sources, including electricity and natural gas, has increased as a result of reduced regulation of many utilities. Electricity is a major competitor of propane, but propane has historically enjoyed a competitive price advantage over electricity. Except for some industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because such pipelines generally make it possible for the delivered cost of natural gas to be less expensive than the bulk delivery of propane. The expansion of natural gas into traditional propane markets has historically been inhibited by the capital cost required to expand distribution and pipeline systems; however, the gradual expansion of the nation’s natural gas distribution systems has resulted in natural gas being available in areas that previously depended on propane, which could cause us to lose customers, thereby reducing our revenues. Although propane is similar to fuel oil in 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 and due to the fact that both fuel oil and propane have generally developed their own distinct geographic markets.

We cannot predict the effect that development of alternative energy sources may have on our operations, including whether subsidies of alternative energy 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 of more efficient furnaces and other heating devices, has adversely affected the demand for propane by retail customers. Future conservation measures or technological advances in heating, conservation, energy generation or other devices may reduce demand for propane. In addition, if the price of propane increases, some of our customers may increase their conservation efforts and thereby decrease their consumption of propane.

The majority of our retail propane operations are concentrated in the Northeast, Southeast, and Midwest, and localized warmer weather and/or economic downturns may adversely affect demand for propane in those regions, thereby affecting our financial position and results of operations.

A substantial portion of our retail propane sales are to residential customers located in the Northeast, Southeast, and Midwest who rely heavily on propane for heating purposes. A significant percentage of our retail propane volume is attributable to sales during the peak heating season of October through March. Warmer weather may result in reduced sales volumes that could adversely impact our consolidated results of operations and financial position. In addition, adverse economic conditions in areas where our retail propane operations are concentrated may cause our residential customers to reduce their use of propane regardless of weather conditions. Localized warmer weather and/or economic downturns may have a significantly greater impact on our consolidated results of operations and financial position than if our retail propane business were less concentrated.


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Reduced demand for refined products could have an adverse effect our results of operations.

Any sustained decrease in demand for refined products in the markets we serve could reduce our cash flow. Factors that could lead to a decrease in market demand include:

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a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel;
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higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;
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an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;
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an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products; and
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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 consolidated results of operations. The most significant of the federal and state incentives which benefit renewable products we market, such as ethanol and biodiesel, is the RFS. The RFS requires that an increasing amount of renewable fuels must be blended with petroleum-based fuels each year in the United States. However, the EPA has authority to waive the requirements of the RFS, in whole or in part, provided one of two conditions is met. The conditions are: (1) there is inadequate domestic renewable fuel supply; or (2) implementation of the requirement would severely harm the economy or environment of a state, region or the United States. Opponents of the RFS are seeking to force the EPA to reduce or eliminate the RFS. Further, several pieces of legislation have been introduced with the goal of significantly reducing or eliminating 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. If the EPA were to adjust the RFS requirements in any material way, it could negatively impact demand for the renewable fuel products we market, which could adversely impact our consolidated results of operations.

The expiration of tax credits could adversely impact the demand for biodiesel, which could adversely impact our results of operations

The demand for biodiesel is supported by certain federal tax credits. These tax credits have typically been granted for short durations, and on several occasions these tax credits have expired. In December 2014, the federal government passed a law reinstating the tax credit retroactively to January 1, 2014 to be 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 no assurance that the federal government will grant such tax credits in the future. If the federal government were to discontinue the practice of granting such tax credits, this would likely have an adverse effect on demand for biodiesel and on our biodiesel marketing operations.

A loss of one or more significant customers could materially or adversely affect our results of operations.

During the year ended March 31, 2016, 65% of the revenues of our crude oil logistics segment were generated from our ten largest customers of the segment. During the year ended March 31, 2016, 23% of the water treatment and disposal revenues of our water solutions segment were generated from our two largest customers of the segment. During the year ended March 31, 2016, 34% of the revenues of our liquids segment were generated from our ten largest customers of the segment (exclusive of sales to our retail propane segment). During the year ended March 31, 2016, 34% of the revenues of our refined products and renewables segment were generated from our ten largest customers of the segment. We expect to continue to depend on key customers to support our revenues for the foreseeable future. The loss of key customers, failure to renew contracts upon expiration, or a sustained decrease in demand by key customers could result in a substantial loss of revenues and could have a material and adverse effect on our consolidated results of operations.


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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 management responsibilities with partners that may not share our goals and objectives. Differences in views among the partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and 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 systems and facilities will not be available upon completion thereof.

One of the ways we intend to grow our business is through the construction of additions to our systems and/or the construction of new terminaling, transportation, and wastewater treatment facilities. The Joint Pipeline currently under construction by Grand Mesa and Saddlehorn will have several points of origin in Colorado and will terminate in Cushing, Oklahoma; and we expect that the transportation services on this pipeline to commence beginning in the third quarter of fiscal year 2017. These expansion projects require the expenditure of significant amounts of capital, which may exceed our resources, and involves numerous regulatory, environmental, political and legal uncertainties. There can be no assurances that we will be able to complete these projects on schedule or at all or at the budgeted cost. Our revenues may not increase upon the expenditure of funds on a particular project. Moreover, we may undertake expansion projects to capture anticipated future growth in production in a region in which anticipated production growth does not materialize or for which we are unable to acquire new customers. We may also rely on estimates of proved, probable or possible reserves in our decision to undertake expansion projects, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved, probable or possible reserves. As a result, our new facilities and infrastructure may not be able to attract enough product to achieve our expected investment return, which could materially and adversely affect our consolidated results of operations and financial position.

Product liability claims and litigation could adversely affect our business and results of operations.

Our operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with combustible liquids. As a result, we are subject to product liability claims and lawsuits, including potential class actions, in the ordinary course of business. Any product liability claim brought against us, with or without merit, could be costly to defend and could result in an increase of our insurance premiums. Some claims brought 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 full before 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 pay the amount of any settlement or judgment that is in excess of our policy limits. We may not be able to obtain insurance on terms acceptable to us or at all since insurance varies in cost and can be difficult to obtain. Our failure to maintain adequate insurance coverage or successfully defend against product liability claims could materially and adversely affect our business, consolidated results of operations, financial position and cash flows.

A failure in our operational systems or cyber security attacks on any of our facilities, or those of third parties, may affect adversely our financial results.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our financial results could also be adversely affected if an employee causes our operational systems to fail, either as a result of inadvertent error or by deliberately tampering with or manipulating our operational systems. In addition, dependence upon automated systems may further increase the risk related to operational system flaws, and employee tampering or manipulation of those systems will result in losses that are difficult to detect.

Due to increased technology advances, we have become more reliant on technology to help increase efficiency in our business. We use computer programs to help run our financial and operations sectors, and this may subject our business to increased risks. Any future cyber security attacks that affect our facilities, our customers and any financial data could have a material adverse effect on our business. In addition, cyber attacks on our customer and employee data may result in a financial

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loss, including potential fines for failure to safeguard data, and may negatively impact our reputation. Third-party systems on which we rely could also suffer operational system failure. Any of these occurrences could disrupt our business, result in potential liability or reputational damage or otherwise have an adverse effect on our financial results.

We do not own all of the land on which our facilities are located, and instead lease certain facilities and equipment, and we, therefore, are subject to the possibility of increased costs to retain necessary land and equipment use which could disrupt our operations.

We do not own all of the land on which our facilities are located, and we are therefore subject to the possibility of more onerous terms and/or increased 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 such rights-of-way. Additionally, our loss of rights, through our inability to renew right-of-way contracts or otherwise, could materially and adversely affect our business, 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 our railcars. Our inability to renew facility or equipment leases or otherwise maintain the right to utilize such facilities and equipment on acceptable terms, or the increased costs to maintain such rights, could have a material and adverse effect on our consolidated results of operations and cash flows.

We also must operate within the terms and conditions of permits and various rules and regulations from the United States Bureau of Land Management for the rights of way on which our pipelines are constructed and the Wyoming State Engineer’s Office for water well, disposal well and containment pits.

Difficulty in attracting and retaining qualified drivers could adversely affect our growth and profitability.

Maintaining a staff of qualified truck drivers is critical to the success of our crude oil logistics and retail propane operations. We have in the past experienced 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 qualified drivers and intense competition for drivers from other companies would create difficulties in increasing the number of our drivers in the event we choose to expand our fleet of trucks. If we are unable to continue to attract and retain a sufficient number of qualified drivers, we could have difficulty meeting customer demands, any of which could materially and adversely affect our growth and profitability.

If we fail to maintain an effective system of internal controls, including internal control over financial reporting, we may be unable to report our financial results accurately or prevent fraud, which would likely have a negative impact on the market price of our common units.

We are subject to the public reporting requirements of the Securities Exchange Act of 1934, as amended. We are also subject to the obligation under Section 404(a) of the Sarbanes Oxley Act of 2002 to annually review and report on our internal control over financial reporting, and to the obligation under Section 404(b) of the Sarbanes Oxley Act to engage our independent registered public accounting firm to attest to the effectiveness of our internal controls over financial reporting.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud, and operate successfully as a publicly traded partnership. Our efforts to maintain our internal controls may be unsuccessful, and we may be unable to maintain effective controls over financial reporting, including our disclosure control. Any failure to maintain effective internal control over financial reporting and disclosure controls could harm our operating results or cause us to fail to meet our reporting obligations. These risks may be heightened after a business combination, during the phase when we are implementing our internal control structure over the recently acquired business.

Given the difficulties inherent in the design and operation of internal control over financial reporting, we can provide no assurance as to either our or our independent registered public accounting firm’s conclusions about the effectiveness of internal controls in the future, and we may incur significant costs in our efforts to comply with Section 404. Ineffective internal controls could subject us to regulatory scrutiny and 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 on the market price of our common units.

In the fourth quarter of fiscal year 2016, we identified a material weakness in our internal control over financial reporting that existed through December 31, 2015. Our failure to establish and maintain effective internal control over financial reporting could result in material misstatements in our financial statements and cause investors to lose confidence in our reported financial information, which in turn could cause the trading price of our common units to decline.

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During the year ended March 31, 2016, we identified a material weakness in our internal control over financial reporting that existed through December 31, 2015, related to the appropriate policies and procedures in place to properly identify and account for liabilities related to contingent consideration payments in business combinations. We identified this material weakness in connection with the recording of business combinations in the fourth quarter of fiscal year 2016.  As a result of such weakness, our Audit Committee, upon recommendation of management, determined to restate our unaudited quarterly financial information for the quarters ended June 30, 2015, September 30, 2015 and December 31, 2015. For further information regarding this matter, please refer to Item 9A. Controls and Procedures.

Management’s ongoing assessment of internal control over financial reporting may in the future identify additional weaknesses and conditions that need to be addressed. Any failure to improve our internal control over financial reporting to address identified weaknesses in the future, if they were to occur, could prevent us from maintaining accurate accounting records and discovering material accounting errors, which in turn, could adversely affect our business and the value of our common units.

An impairment of goodwill and intangible assets could reduce our earnings.

At March 31, 2016, we had goodwill and intangible assets of $2.5 billion. Such assets are subject to impairment reviews on an annual basis, or at an interim date if information indicates that such asset values have been impaired. Any impairment we would be required to record in our financial statements would result in a charge to our income, which would reduce our earnings.

Our business requires extensive credit risk management that may not be adequate to protect against customer nonpayment.

Our credit management procedures may not fully eliminate the risk of nonpayment by our customers. We manage our credit risk exposure through credit analysis, credit approvals, establishing credit limits, requiring prepayments (partially or wholly), requiring product deliveries over defined time periods, 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 be significant and any such nonpayment problems could impact our consolidated results of operations and potentially limit our ability to make payments on our debt obligations or distributions to our unitholders.

Our terminaling operations depend on pipelines to transport crude oil, natural gas liquids and refined products.

We own natural gas liquids and crude oil terminals and lease refined products terminals. These facilities depend on pipeline and storage systems that are owned and operated by third parties. Any interruption of service on a pipeline or lateral connections 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, to transport product to and from our facilities and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation to and from our facilities impact the utilization and value of our terminals. We have historically been able to pass through the costs of pipeline transportation to our customers. However, if competing pipelines do not have similar annual tariff increases or service fee adjustments, such increases could affect our ability to compete, thereby adversely affecting our revenues.

Our marketing operations depend on the availability of transportation and storage capacity.

Our product supply is transported and stored on facilities owned and operated by third parties. Any interruption of service on the pipeline or storage companies 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, to transport products and have a corresponding material adverse effect on our revenues. In addition, the rates charged by the interconnected pipelines for transportation affects the profitability of our operations.

The financial results of our natural gas liquids businesses are seasonal and generally lower in the first and second quarters of our fiscal year, which may require us to borrow money to make distributions to our unitholders during these quarters.

The natural gas liquids inventory we have presold to customers is highest during summer months, and our cash receipts are lowest during summer months. 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 second fiscal quarters, we may be required to borrow money to pay distributions to our unitholders during these quarters. Any restrictions on our ability to borrow money could restrict our ability to pay the minimum quarterly distributions to our unitholders.

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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 will result in increased transportation costs to us. The price and supply of fuel is unpredictable and fluctuates based on events we cannot control, such as geopolitical developments, supply and demand for oil and gas, actions by oil and gas producers, war and unrest in oil producing countries and regions, regional production patterns and weather concerns. As a result, any increases in these prices may adversely affect our profitability and competitiveness.

Some of our operations cross the United States/Canada border and are subject to cross-border regulation.

Our cross-border activities subject us to regulatory matters, including import and export licenses, tariffs, Canadian and United States customs and tax issues and toxic substance certifications. Such regulations include the “Short Supply Controls” of the Export Administration Act, the North American Free Trade Agreement and the Toxic Substances Control Act. Violations of these licensing, tariff and tax reporting requirements could result in the imposition of significant 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 and natural gas, the major sources of propane, which could have a material impact on the availability and price of propane. Terrorist attacks in the areas of our operations could negatively impact our ability 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 and involvement of those key management personnel could potentially have a material adverse impact on our business and possibly on the market value of our units.

Risks Inherent in an Investment in Us

Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise be breaches of fiduciary duty.

Fiduciary duties owed to our unitholders by our general partner are prescribed by law and our partnership agreement. The Delaware Revised Uniform Limited Partnership Act (“Delaware LP Act”) provides that Delaware limited partnerships may, in their partnership agreements, restrict the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains provisions that reduce the standards to which our general 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 for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing common units, our unitholders consent to some actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law;
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permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner. This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include the exercise of its limited call right, its voting rights with respect to the units it owns and its determination whether or not to consent to any merger or consolidation of the partnership;
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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 long as it acted in good faith, meaning our general partner subjectively believed that the decision was in, or not opposed to, the best interests of the partnership;
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generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the conflicts committee and not involving a vote of our unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the

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totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us; and
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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 acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or engaged in fraud or willful misconduct.

By purchasing a common unit, a common unitholder will become bound by the provisions of our partnership agreement, including the provisions described 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 own interests to the detriment of us and our unitholders.

The NGL Energy GP Investor Group owns and controls our general partner and its 0.1% general partner interest in us. Although our general partner has 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 a fiduciary duty to manage our general partner in a manner beneficial to its owners. Furthermore, since certain executive officers and directors of our general partner are executive officers or directors of affiliates of our general partner, conflicts of interest may arise between the NGL Energy GP Investor Group and its affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over the interests of our unitholders (see “–Our partnership agreement limits the fiduciary duties of our general partner to our unitholders and restricts the remedies available to our unitholders for actions taken by our general partner that might otherwise be breaches of fiduciary duty,” above). The risk to our unitholders due to such conflicts may arise because of the following factors, among others:

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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;
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neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us;
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except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;
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our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders;
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our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as a maintenance capital expenditure, which reduces operating surplus, or an expansion capital expenditure, which does not reduce operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner;
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our general partner determines which costs incurred by it are reimbursable by us;
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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 to make incentive distributions;
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our partnership agreement permits us to classify up to $20.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions to our general partner in respect of the general partner interest or the incentive distribution rights (“IDRs”);
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our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;
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our general partner intends to limit its liability regarding our contractual and other obligations;
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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 than 80% of the common units;
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our general partner controls the enforcement of the obligations that it and its affiliates owe to us;

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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 our general partner’s IDRs without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

In addition, certain members of the NGL Energy GP Investor Group and their affiliates currently hold interests in other companies in the energy and natural resource sectors. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, members of the NGL Energy GP Investor Group are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, they could potentially compete 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 general partner 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 such person 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 entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to 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 us and our unitholders.

Even if our unitholders are dissatisfied, they have limited voting rights and are not entitled to elect our general partner or its directors.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner 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 publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. Furthermore, if our unitholders are dissatisfied with the performance of our general partner, they will have limited ability 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 the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence the manner or direction of management.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by a provision of our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their direct transferees and their indirect transferees approved by our 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 the consent of our unitholders. Furthermore, our partnership agreement does not restrict the ability of the members of the NGL Energy GP Investor Group to transfer 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 to replace the board of directors and officers of our general partner with its own designees and thereby exert significant control over the decisions made by the board of directors and officers.


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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 partner requires (except in certain limited circumstances) the consent of a majority of our outstanding common units (excluding common units held by our general partner and its affiliates). However, after the expiration of this period, our general partner may transfer its IDRs to a third party at any time without the consent of our unitholders. If our general partner transfers its IDRs to a third party but retains its general partner interest, our general partner may not have the same 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 may assign 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 price that 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 be required 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. Our unitholders 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 our behalf, which will be determined by our general partner in its sole discretion in accordance with the terms of our partnership agreement. In determining the costs and expenses allocable to us, our general partner is subject to its fiduciary duty, as modified by our partnership agreement, to the limited partners, which requires 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 are managed and operated by executive officers and directors of our general partner. The reimbursement of expenses and payment of fees, if any, to our general partner 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, including commercial bank borrowings and the issuance of debt and equity securities, as well as reserves we have established to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. There are no limitations in our partnership agreement or the agreements governing our indebtedness on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.

We may issue additional units without the approval of our unitholders, which would dilute the interests of existing unitholders.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. 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;

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•
the relative voting strength of each previously outstanding unit may be diminished; and
•
the market price of the common units may decline.

Our general partner, without the approval of our unitholders, may elect to cause us to issue common units while also maintaining its general partner interest 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 of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units 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 quarterly cash 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 anticipate that our general partner would exercise this reset right to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its IDRs based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued 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 of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly 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 partner if 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 partnership agreement 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 the Delaware LP Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became 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 non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware LP Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability.


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Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes. We could lose our status as a partnership for a number of reasons, including not having enough “qualifying income.” If the Internal Revenue Service (“IRS”) were to treat us as a corporation for federal income tax purposes, our cash available for distribution to our unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.

Despite the fact that we are a limited partnership under Delaware law, a publicly traded partnership such as us will be treated as a corporation for federal income tax purposes unless, for each taxable year, 90% or more of its gross income is “qualifying income” under Section 7704 of the Internal Revenue 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 of income such as certain interest and dividends and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. Although we do not believe based upon our current operations that we are treated as a corporation, we could be treated as a corporation for federal income tax purposes or otherwise subject to taxation as an entity if our gross income is not properly classified as qualifying income, there is a change in our business or there is a change in current law.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses or deductions would flow through to our unitholders. 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, likely causing 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 a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution 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 our unitholders.

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders. Our partnership agreement provides 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 quarterly distribution 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 administrative changes and differing interpretations, possibly on a retroactive basis.

The present income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of the United States Congress propose and consider substantive changes to the existing United States federal income tax laws that affect the tax treatment of publicly traded partnerships. Members of Congress have recently proposed substantive changes to the existing United States tax laws that would affect certain publicly traded partnerships, if such proposals are enacted into law. The Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. If successful, the Obama administration’s proposal, or other similar proposals, could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations, upon which we rely for our treatment as a partnership for United States federal income tax purposes.


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We are unable to predict whether any such change or other proposals will ultimately be enacted or will affect our tax treatment. Any modification to the 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 corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Moreover, such modifications and change in interpretations may affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. Although we are unable to predict whether any of these changes, or other proposals, will ultimately be 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 contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions 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 we take 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 may materially 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 be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

Our unitholders will be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Because we expect to be treated as a partnership for United States federal income tax purposes, our unitholders will be treated as partners to whom we 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 taxes and, in some cases, state and local income taxes on their share of our taxable income even if they receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common 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 the unitholder 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 potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sell units, they may incur a tax liability in excess of the amount of cash they 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 to them.

Investment in common units by tax exempt entities, such as employee benefit plans, individual retirement accounts (“IRAs”), Keogh plans and other retirement plans and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will 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 challenge this 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 amortization positions that may not conform to all aspects of existing Treasury Regulations. Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our

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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 a negative 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 conduct additional operations in corporate form in the future. Our corporate subsidiaries will be subject to corporate level tax, which will reduce the cash available for distribution 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 have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

We prorate our items of income, gain, loss and deduction for United States federal income tax purposes between transferors and transferees of our units each month based on the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may 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 our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations. The United States Treasury Department, however, has issued proposed Treasury Regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. Therefore, the use of this proration method may not be permitted under existing Treasury Regulations. If the IRS were to challenge our proration method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to affect a short sale of units may be considered as having disposed of those common units. If so, such unitholder would no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of the loaned units, 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 the unitholder 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 or deduction 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 be fully 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 are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

We have adopted certain valuation methodologies and monthly conventions for United States federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating 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 greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Internal Revenue Code Section 743(b) adjustment attributable to our tangible and intangible 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 our unitholders. 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 the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

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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 partnership for federal income tax purposes.

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable 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. A technical termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership 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 return if we are unable to determine that a technical termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-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 unrelated income. In cases where our unitholders are subject to the passive loss rules (generally, individuals and closely held corporations), any losses generated by us will 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. A unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years but not by losses from other passive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by a unitholder 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 or acquire properties.

In addition to federal income taxes, holders of our common units are subject to other taxes, including foreign, state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own or 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 local income 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 and conduct 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 on corporations and other entities. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional states that impose a personal income tax.

Item 1B.    Unresolved Staff Comments

None.

Item 2.    Properties

Overview. We believe that we have satisfactory title or valid rights to use all of our material properties. Although some of these properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-compete agreements entered into in connection with acquisitions and other encumbrances, easements and restrictions, we do not believe that any of these burdens will materially interfere with our continued use of these properties in our business, taken as a whole. Our obligations under our credit facilities are secured by liens and mortgages on substantially all of our real and personal property.


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Other than as described below, we believe that we have all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local governmental and regulatory authorities that relate to ownership of our properties or the operations of our business.

One of our facilities acquired in the High Sierra merger is operating with all but one of the required permits, as the State of Wyoming has not yet developed a process for issuing permits of this type. We believe that the permit will ultimately be granted, but we are unable to determine the timing of 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 Proceedings

We are involved from time to time in various legal proceedings and claims arising in the ordinary course of business. For information related to legal proceedings, please see the discussion under the captions “Legal Contingencies,” “Contractual Disputes,” and “Environmental Matters” in Note 10 to our consolidated financial statements included in this Annual Report, which information is incorporated by reference into this Item 3.

Item 4.    Mine Safety Disclosures

Not applicable.


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PART II

Item 5.
Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Market Information

Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “NGL.” Our common units began trading on the NYSE on May 12, 2011. Prior to May 12, 2011, our common units were not listed on any exchange or traded in any public market. At May 23, 2016, there were approximately 245 common unitholders of record which does not include unitholders for whom common units may be held in “street name.”

The following table summarizes the high and low sales prices per common unit for the periods indicated as reported on the New York Stock Exchange Composite Transactions tape, and the amount of cash distributions paid per common unit.
 
 
Price Range
 
Cash
 
 
High
 
Low
 
Distribution
2016 Fiscal Year
 
 
 
 
 
 
Fourth Quarter
 
$
15.16

 
$
5.57

 
$
0.6400

Third Quarter
 
23.33

 
8.04

 
0.6400

Second Quarter
 
31.31

 
19.55

 
0.6325

First Quarter
 
33.64

 
26.11

 
0.6250

2015 Fiscal Year
 
 
 
 
 
 
Fourth Quarter
 
$
31.70

 
$
24.88

 
$
0.6175

Third Quarter
 
40.58

 
22.57

 
0.6088

Second Quarter
 
44.86

 
39.13

 
0.5888

First Quarter
 
46.25

 
37.08

 
0.5513


Cash Distribution Policy

Available Cash

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership 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, less the 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 of our 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 next four quarters.

General Partner Interest

Our general partner is entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. Our general partner’s interest in our distributions 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) and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest.

Incentive Distribution Rights

The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as “incentive distributions” or “IDRs.” Our general partner currently holds the IDRs, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.


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The following table illustrates the percentage allocations of available cash from operating surplus between our unitholders and our general partner based on the specified target distribution levels. The amounts set forth under “Marginal Percentage Interest In Distributions” are the percentage interests of our general partner and our unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column “Total Quarterly Distribution Per Unit,” until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest, and assume that our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its IDRs.
 
 
 
 
Marginal Percentage Interest In
Distributions
 
 
Total Quarterly
Distribution Per Unit
 
Unitholders
 
General 
Partner
Minimum 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 Distributions

As described in Note 8 to our consolidated financial statements included in this Annual Report, our Credit Agreement contains covenants limiting our ability to pay distributions if we are in default under the Credit Agreement and to pay distributions that are in excess of available cash, as defined in the Credit Agreement.

Sales of Unregistered Securities

During the year ended March 31, 2016, we completed two acquisitions in which we issued unregistered common units as partial consideration. All of these units were issued in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act of 1933, as amended (“Securities Act”), as the units were issued to the owners of businesses acquired in privately negotiated transactions not involving any public offering or solicitation. During October 2015, we issued 52,199 common units to the sellers of a retail propane business. During the year ended March 31, 2016, we issued 781,255 common units to the sellers of two water treatment and disposal facilities.

Common Unit Repurchase Program

On September 10, 2015, the Board of Directors of our general partner authorized a common unit repurchase program pursuant to which we could repurchase 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 negotiated transactions. The following table summarizes the repurchase of common units during the three months ended March 31, 2016.
Period
 
Total Number of Common Units Purchased
 
Average Price Paid Per Common Unit
 
Total Number of Common Units Purchased as Part of a Publicly Announced Program
 
Approximate Dollar Value of Common Units that May Yet Be Purchased Under the Program
January 1-31, 2016
 
8,403

 
$
11.02

 
—

 
$
37,272,180

February 1-29, 2016
 
782,703

 
7.92

 
782,703

 
31,073,172

March 1-31, 2016
 
442,960

 
8.67

 
442,960

 
27,232,709

Total
 
1,234,066

 
$
8.19

 
1,225,663

 
$
—



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The common units not repurchased under the publicly announced program were surrendered by employees to pay tax withholding in connection with the vesting of restricted common units. As a result, we are including the common units surrendered in the “Total Number of Common Units Purchased” column.

Securities Authorized for Issuance Under Equity Compensation Plans

In connection with the completion of our IPO, our general partner adopted the NGL Energy Partners LP Long-Term Incentive Plan. Please see Part III, Item 12–“Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters–Securities Authorized for Issuance Under Equity Compensation Plan” which is incorporated by reference into this Item 5.

Item 6.    Selected Financial Data

The following table summarizes selected historical financial and operating data for the periods and as of the dates indicated. The following table should be read in conjunction with Part I, Item 7–“Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes included in this Annual Report.

The selected consolidated historical financial data (excluding volume information) at March 31, 2016 and 2015, and for each of the three years in the period ended March 31, 2016 is derived from our audited historical consolidated financial statements included in this Annual Report. The selected consolidated historical financial data (excluding volume information) at March 31, 2014, 2013 and 2012 and for each of the two years in the period ended March 31, 2013 is derived from our audited historical consolidated financial statements not included in this Annual Report.

Correction of Error

We have changed our previously issued consolidated balance sheet as of March 31, 2015 and consolidated statement of operations, consolidated statement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year ended March 31, 2015 for the correction of an immaterial error (see Note 17 to our consolidated financial statements included in this Annual Report).


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Year Ended March 31,
 
 
2016
 
2015
 
2014
 
2013
 
2012
 
 
(in thousands, except per unit data)
Income Statement Data (1)(2)
 
 
 
 
 
 
 
 
 
 
Total revenues
 
$
11,742,110

 
$
16,802,057

 
$
9,699,274

 
$
4,417,767

 
$
1,310,473

Total cost of sales
 
10,839,037

 
15,958,207

 
9,132,699

 
4,039,110

 
1,217,023

Operating (loss) income
 
(104,603
)
 
107,420

 
106,565

 
87,307

 
15,030

Interest expense
 
133,089

 
110,123

 
58,854

 
32,994

 
7,620

(Gain) loss on early extinguishment of debt
 
(28,532
)
 
—

 
—

 
5,769

 
—

Net (loss) income attributable to parent equity
 
(198,929
)
 
37,306

 
47,655

 
47,940

 
7,876

Basic and diluted (loss) income per common unit
 
(2.35
)
 
(0.05
)
 
0.51

 
0.96

 
0.32

Cash Flows Data (1)(2)
 
 
 
 

 
 

 
 

 
 

Net cash provided by operating activities
 
$
351,495

 
$
262,391

 
$
85,236

 
$
132,634

 
$
90,329

Net cash used in investing activities
 
(445,327
)
 
(1,366,221
)
 
(1,455,373
)
 
(546,621
)
 
(296,897
)
Net cash provided by financing activities
 
80,705

 
1,134,693

 
1,369,016

 
417,716

 
198,063

Cash distributions paid per common unit (subsequent to IPO)
 
2.54

 
2.37

 
2.01

 
1.69

 
0.85

Cash distributions paid per common unit (prior to IPO)
 
 
 
 
 
 
 
 
 
0.35

Balance Sheet Data - Period End (1)(2)(3)
 
 
 
 
 
 
 
 
 
 
Total assets (4)
 
$
5,560,155

 
$
6,655,792

 
$
4,134,910

 
$
2,290,901

 
$
749,519

Total long-term obligations, exclusive of debt issuance costs and current maturities (4)
 
3,160,073

 
2,842,493

 
1,628,173

 
741,924

 
199,389

Total equity
 
1,694,065

 
2,693,432

 
1,531,853

 
889,418

 
405,329

Volume Information (1)
 
 
 
 
 
 
 
 
 
 
Retail propane sold (gallons)
 
152,238

 
169,279

 
162,361

 
144,379

 
78,236

Distillates sold (gallons)
 
30,674

 
34,862

 
34,965

 
28,853

 
1,650

Wholesale propane sold (gallons) (5)
 
1,244,529

 
1,285,707

 
1,190,106

 
912,625

 
659,921

Wholesale other products sold (gallons)
 
843,922

 
825,514

 
786,671

 
505,529

 
134,999

Crude oil sold (barrels)
 
67,211

 
83,864

 
46,107

 
24,373

 
—

Water received (barrels)
 
208,440

 
161,664

 
75,451

 
25,009

 
—

Refined products sold (barrels)
 
98,988

 
68,043

 
9,833

 
—

 
—

Renewable products sold (barrels)
 
5,794

 
5,318

 
3,593

 
—

 
—

 
(1)
The acquisitions of businesses affect the comparability of this information.
(2)
On February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting.
(3)
Certain balance sheet data at March 31, 2015 was adjusted to reflect the final acquisition accounting for certain business combinations (see Note 2 to our consolidated financial statements included in this Annual Report).
(4)
Revised to reclassify debt issuance costs for our senior notes from intangible assets to long-term debt obligations for all balance sheet dates presented (see Note 2 to our consolidated financial statements included in this Annual Report).
(5)
Includes intercompany volumes sold to our retail propane segment.


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Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview

We are a Delaware limited partnership (the “Partnership”) formed in September 2010. NGL Energy Holdings LLC serves as our general partner. On May 17, 2011, we completed our initial public offering (“IPO”). Subsequent to our IPO, we significantly expanded our operations through numerous acquisitions, as described under Part I, Item 1–“Business–Acquisitions.” At March 31, 2016, our operations include:

•
Crude Oil Logistics
•
Water Solutions
•
Liquids
•
Retail Propane
•
Refined Products and Renewables

Correction of Error

We have changed our previously issued consolidated balance sheet as of March 31, 2015 and consolidated statement of operations, consolidated statement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year ended March 31, 2015 for the correction of an immaterial error (see Note 17 to our consolidated financial statements included in this Annual Report).

Crude Oil Logistics

Our crude oil logistics segment purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. The assets of our crude oil logistics segment include owned and leased crude oil storage terminals and pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests in two crude oil pipelines.

Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets such as Cushing, Oklahoma. We attempt to reduce our exposure to price fluctuations by using back-to-back physical contracts whenever possible. When back-to-back physical contracts are not optimal, we enter into financially settled derivative contracts as economic hedges of our physical inventory, physical sales and physical purchase contracts. We use our transportation assets to move crude oil from the wellhead to the highest value market. Spreads between crude oil prices in different markets can fluctuate, which may expand or limit our opportunity to generate margins by transporting crude oil to different markets.

The following table summarizes the range of low and high spot crude oil prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma for the periods indicated and the prices at period end:
 
 
Spot Price Per Barrel
Year Ended March 31,
 
Low
 
High
 
At Period End
2016
 
$
26.21

 
$
61.43

 
$
38.34

2015
 
43.46

 
107.26

 
47.60

2014
 
86.68

 
110.53

 
101.58


We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

Our crude oil logistics segment generated an operating loss of $40.7 million during the year ended March 31, 2016, compared to an operating loss of $35.8 million during the year ended March 31, 2015. The operating loss during the year ended March 31, 2016 included a write-down of $47.7 million related to pipe we no longer expect to use in the originally-planned Grand Mesa Pipeline.


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Water Solutions

Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck washouts. In addition, our water solutions segment sells the recycled water and recovered hydrocarbons that result from performing these services. The assets of our water solutions segment include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities.

Our water processing facilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutions segment is the extent of exploration and production in the areas near our facilities, which is generally based upon producers’ expectations about the profitability of drilling new wells. The primary customer of our Wyoming facility has committed to deliver a specified minimum volume of water to our facility under a long-term contract. 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 not under volume commitments, although certain of our facilities are connected to producer locations by pipeline.

Our water solutions segment generated an operating loss of $313.7 million during the year ended March 31, 2016, compared to operating income of $65.3 million during the year ended March 31, 2015. The operating loss during the year ended March 31, 2016 included a goodwill impairment of $380.2 million as the decline in crude oil prices and crude oil production have had an unfavorable impact on our water solutions business.

Liquids

Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the products to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada. Our liquids segment owns 19 terminals throughout the United States and a salt dome storage facility in Utah, operates a fleet of leased railcars, and leases underground storage capacity. We attempt to 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 a percentage of our winter volumes. We also enter into financially settled derivative contracts as economic hedges of our physical inventory, physical sales and physical purchase contracts.

Our wholesale liquids business is a “cost-plus” business that can be affected by both price fluctuations and volume variations. We establish our selling price based on a pass-through of our product supply, transportation, handling, storage, and capital costs plus an acceptable margin. The margin we realize 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 are typically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and 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 our main pricing hubs, for the periods indicated and the prices at period end:
 
 
Conway, Kansas
 
Mt. Belvieu, Texas
 
 
Spot Price Per Gallon
 
Spot Price Per Gallon
Year Ended March 31,
 
Low
 
High
 
At Period End
 
Low
 
High
 
At Period End
2016
 
$
0.27

 
$
0.51

 
$
0.39

 
$
0.30

 
$
0.57

 
$
0.44

2015
 
0.38

 
1.13

 
0.45

 
0.45

 
1.13

 
0.51

2014
 
0.77

 
4.33

 
1.03

 
0.81

 
1.73

 
1.06


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The range of low and high spot butane prices per gallon at Mt. Belvieu, Texas for the periods indicated and the prices at period end:
 
 
Spot Price Per Gallon
Year Ended March 31,
 
Low
 
High
 
At Period End
2016
 
$
0.42

 
$
0.68

 
$
0.53

2015
 
0.60

 
1.30

 
0.63

2014
 
1.08

 
1.64

 
1.26


We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

Our liquids segment generated operating income of $76.2 million and $45.1 million during the years ended March 31, 2016 and 2015, respectively. During the year ended March 31, 2016, we wrote off assets of $14.6 million acquired as part of the Gavilon Energy acquisition that we deemed no longer recoverable. Operating income during the year ended March 31, 2015 was reduced by a loss of $29.8 million on the sale of a natural gas liquids terminal. Additionally, Sawtooth NGL Caverns, LLC (“Sawtooth”), which we acquired in February 2015, generated $9.8 million of operating income during the year ended March 31, 2016.

Retail Propane

Our retail propane segment is a “cost-plus” business that sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia. Our retail propane segment purchases the majority of its propane from our liquids segment. Our retail propane segment generates margins based on the difference between the wholesale cost of product and the selling price of the product in the retail markets. These margins fluctuate over time due to supply and demand conditions. Weather conditions can have a significant impact on our sales volumes and prices, as a large portion of our sales are to residential customers who purchase propane and distillates for home heating purposes.

A significant factor affecting the profitability of our retail propane segment is our ability to maintain our product margin. Product margin is the difference between our sales prices and our total product costs, including transportation and storage. We monitor wholesale propane prices daily and adjust our retail prices accordingly. We believe volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

The retail propane business is both weather-sensitive and subject to seasonal volume variations due to propane’s primary use as a heating source in residential and commercial buildings and for agricultural purposes. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

Our retail propane segment generated operating income of $44.1 million and $64.1 million during the years ended March 31, 2016 and 2015, respectively.

Refined Products and Renewables

Our refined products and renewables segment conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We purchase refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedule them for delivery at various locations. As discussed in “Recent Developments” below, on February 1, 2016, we sold our general partner interest in TLP.

We purchase refined petroleum products primarily in the Gulf Coast, Southeast, and Midwest regions of the United States and schedule them for delivery primarily on the Colonial, Plantation, and Magellan pipelines. We sell our products to commercial and industrial end users, independent retailers, distributors, marketers, government entities, and other wholesalers of refined petroleum products. We sell our products at TLP’s terminals and at terminals owned by third parties.


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The following table summarizes the range of low and high spot gasoline prices per barrel using NYMEX gasoline prompt-month futures for the periods indicated and the prices at period end:

 
 
Spot Price Per Barrel
Year Ended March 31,
 
Low
 
High
 
At Period End
2016
 
$
37.75

 
$
90.15

 
$
59.91

2015
 
53.34

 
131.46

 
74.76

2014 (1)
 
109.20

 
126.84

 
122.22

 
(1)
Prices are for the four months ended March 31, 2014 as we acquired Gavilon, LLC (“Gavilon Energy”) on December 2, 2013.

The following table summarizes the range of low and high spot diesel prices per barrel using NYMEX ULSD prompt-month futures for the periods indicated and the prices at period end:

 
 
Spot Price Per Barrel
Year Ended March 31,
 
Low
 
High
 
At Period End
2016
 
$
36.36

 
$
84.68

 
$
49.76

2015
 
68.04

 
128.10

 
72.24

2014 (1)
 
121.80

 
137.76

 
123.06

 
(1)
Prices are for the four months ended March 31, 2014 as we acquired Gavilon Energy on December 2, 2013.

Our refined products and renewables segment generated operating income of $227.0 million and $54.6 million during the years ended March 31, 2016 and 2015, respectively. Our refined products and renewables segment was significantly expanded with our July 2014 acquisition of TransMontaigne. Operating income during the year ended March 31, 2016 was also increased by a gain of $130.4 million recorded on the sale of our general partner interest in TLP during the three months ended March 31, 2016, as discussed in “Recent Developments” below and Note 14 to our consolidated financial statements included in this Annual Report.

Trends    

Crude oil prices can fluctuate widely based on changes in supply and demand conditions. The opportunity to generate revenues in our crude oil logistics business is heavily influenced by the volume of crude oil being produced. Crude oil prices declined sharply during the period from July 2014 through March 2016 (the spot price for NYMEX West Texas Intermediate crude oil at Cushing, Oklahoma declined from $105.34 per barrel at July 1, 2014 to $38.34 per barrel at March 31, 2016). While crude oil production in the United States has been strong in recent years, the sharp decline in crude oil prices has reduced the incentive for producers to expand production. If crude oil prices remain low, resultant declines in crude oil production may adversely impact volumes in our crude oil logistics business.

Since January 2015, crude oil markets have been in contango (a condition in which forward crude oil prices are greater than spot prices). Our crude oil logistics business benefits when the market is in contango, as higher forward prices result in inventory holding gains between the time we financially hedge 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 in contango.

Our opportunity to generate revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. As described above, crude oil prices declined sharply since July 2014. At current market prices, drilling rigs and production have decreased and adversely impacted the volumes of our water solutions business. A portion of the revenues of our water solutions business is generated from the sale of hydrocarbons that we recover when processing the wastewater. Because of this, lower crude oil prices result in lower 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 Coast regions. We purchase product in the Gulf Coast, transport the product on third party pipelines, and sell the product primarily at TLP’s refined products terminals. Most of the contracts with these customers are one year in

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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 of this inventory will increase or decrease as market prices change. In order to mitigate this risk, we enter into futures contracts, which are only available based on New York Harbor pricing. Because our contracts are indexed to Gulf Coast prices and our futures contracts are based on New York Harbor prices, the futures contracts are not a perfect hedge against our inventory holding risk. During any given quarter, spreads between prices in the Gulf Coast and New York Harbor could narrow or widen, which could reduce the effectiveness of the futures contracts as a hedge of the inventory holding risk. The tenor of these futures contracts, which are typically six months to one year in duration at inception, can also contribute to volatility in earnings among individual quarters within a fiscal year.

During the year ended March 31, 2016, prices for refined products declined. Gulf Coast prices, on which our sales contracts are based, declined more than the New York Harbor prices, on which our futures contracts are based, which had an adverse impact on our cost of sales. Based on historical experience, we generally expect the spreads between Gulf Coast and New York Harbor prices to be more consistent over the course of a contract year than during 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 would expect during a full fiscal year.

The decline in crude oil prices has had an adverse impact on many participants in the energy markets, and the inherent risk of customer or counterparty nonperformance is higher when crude oil prices are low or in decline.

Seasonality

Seasonality impacts our liquids and retail propane segments. A large portion of our retail propane business is in the residential market where propane is used primarily for home heating purposes. Consequently, for these two segments, revenues, operating profits and operating cash flows are generated mostly in the third and fourth quarters of each fiscal year. See “–Liquidity, Sources of Capital and Capital Resource Activities–Cash Flows.”

Recent Developments

Grand Mesa Pipeline

In September 2014, we entered into a joint venture with RimRock Midstream, LLC (“RimRock”) whereby each party owned a 50% interest in Grand Mesa Pipeline, LLC (“Grand Mesa”). In October 2014, we obtained ship-or-pay volume commitments from multiple shippers to begin construction of the Grand Mesa Pipeline, which will originate in Colorado and terminate in Cushing, Oklahoma. In November 2014, we acquired RimRock’s 50% ownership interest in Grand Mesa for $310.0 million in cash. In November 2015, Grand Mesa Pipeline entered into an agreement with Saddlehorn Pipeline Company, LLC (“Saddlehorn”), under which we acquired a 37.5% undivided interest in a crude oil pipeline currently under construction (the “Joint Pipeline”). The Joint Pipeline will take receipt from Grand Mesa Pipeline’s origin in Colorado and will deliver to Cushing, Oklahoma. We will have the right to utilize 150,000 barrels per day of capacity on the Joint Pipeline. Operating costs will be allocated to us based on our proportionate ownership interest and throughput. We expect the Joint Pipeline to be operational beginning in the third quarter of fiscal year 2017.

Through our undivided interest in the Joint Pipeline, we will have expanded capacity, sufficient to service our customer contracts at the same origin and termination points with the ability to accept additional volume commitments. We will retain ownership of our previously-acquired easements for the potential future development of transportation projects involving petroleum commodities other than crude oil and condensate. With the consent and participation of Saddlehorn, we and Saddlehorn may consider future opportunities using these easements for projects involving the transportation of crude oil and condensate.

We estimate that our share of the cost to construct the Joint Pipeline will be $250 million. We paid $211 million towards the construction of the pipeline during the year ended March 31, 2016, and we expect to pay the remaining $39 million during the fiscal year ending March 31, 2017. Also, as part of the Joint Pipeline project, we are constructing certain assets that will be connected to the Joint Pipeline. The estimated costs for these assets are $117.0 million. We spent $36.4 million on the construction of these assets during the year ended March 31, 2016, and expect to pay the remaining $80.6 million during the fiscal year ending March 31, 2017.

During the fourth quarter of fiscal year 2016, we recorded a write-down of $47.7 million related to pipe we no longer expect to use in the originally-planned Grand Mesa Pipeline, which is reported within loss on disposal or impairment of assets, net. In addition, during the six months ended March 31, 2016, we reclassified $47.0 million of costs to acquire land, rights-of-

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way and easements on the originally-planned Grand Mesa Pipeline route to intangible assets. As discussed above, we acquired an undivided interest in a different crude oil pipeline with the same origin and destination points as those of our originally-planned Grand Mesa Pipeline route. We will retain the land, rights-of-way and easements along the originally-planned Grand Mesa Pipeline route for potential future development.

Sale of General Partner Interest in TLP

On February 1, 2016, we completed the sale of our general partner interest in TLP to an affiliate of ArcLight Capital Partners (“ArcLight”) for $350 million in cash and recorded a gain on disposal of $329.9 million during the three months ended March 31, 2016. As a result, on February 1, 2016, 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. As a result of entering into these leases, we deferred $204.6 million of the gain on the sale and will recognize this amount over our future lease payment obligations, which is approximately seven years. During the three months ended March 31, 2016, we recognized $5.0 million of the deferred gain in our consolidated statement of operations. In addition, we retained TransMontaigne’s marketing business, which is a significant part of our refined products and renewables segment, and TransMontaigne Product Services, LLC, its customer contracts and its line space on the Colonial and Plantation pipelines.

Subsequent Events

Sale of TLP Common Units

On April 1, 2016, we sold all of the TLP common units we owned to ArcLight for approximately $112.4 million in cash.

Class A Convertible Preferred Units

On April 21, 2016, we entered into an agreement to issue $200 million of 10.75% Class A Convertible Preferred Units (“Preferred Units”) to Oaktree Capital Management L.P. (“Oaktree”). Oaktree may acquire 16.6 million Preferred Units at a price of $12.03 per unit as well as 3.6 million warrants, which are subject to certain vesting and exercise terms. We expect to use the net proceeds from the issuance of the Preferred Units to repay borrowings outstanding on our Revolving Credit Facility (as hereinafter defined), which may be re-borrowed in the future to fund capital expenditures and for other general partnership purposes. The first closing of this transaction occurred on May 11, 2016 and we received gross proceeds of $100 million. We expect the second closing to occur prior to June 30, 2016.

Acquisitions

The acquisitions disclosed in Part I, Item 1–“Business–Acquisitions” impact the comparability of our results of operations between our current and prior fiscal years.


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Consolidated Results of Operations

The following table summarizes our consolidated statements of operations for the periods indicated:
 
 
Year Ended March 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Total revenues
 
$
11,742,110

 
$
16,802,057

 
$
9,699,274

Total cost of sales
 
10,839,037

 
15,958,207

 
9,132,699

Operating expenses
 
401,118

 
364,131

 
259,799

General and administrative expense
 
139,541

 
149,430

 
75,860

Depreciation and amortization
 
228,924

 
193,949

 
120,754

Loss on disposal or impairment of assets, net
 
320,766

 
41,184

 
3,597

Revaluation of liabilities
 
(82,673
)
 
(12,264
)
 
—

Operating (loss) income
 
(104,603
)
 
107,420

 
106,565

Equity in earnings of unconsolidated entities
 
16,121

 
12,103

 
1,898

Interest expense
 
(133,089
)
 
(110,123
)
 
(58,854
)
Gain on early extinguishment of debt
 
28,532

 
—

 
—

Other income, net
 
5,575

 
37,171

 
86

(Loss) income before income taxes
 
(187,464
)
 
46,571

 
49,695

Income tax benefit (expense)
 
367

 
3,622

 
(937
)
Net (loss) income
 
(187,097
)
 
50,193

 
48,758

Less: Net income allocated to general partner
 
(47,620
)
 
(45,700
)
 
(14,148
)
Less: Net income attributable to noncontrolling interests
 
(11,832
)
 
(12,887
)
 
(1,103
)
Net (loss) income allocated to limited partners
 
$
(246,549
)
 
$
(8,394
)
 
$
33,507


See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, and depreciation and amortization expense by segment below.

Non-GAAP Financial Measures

In addition to financial results reported in accordance with accounting principles generally accepted in the United States (“GAAP”), we have provided the non-GAAP financial measures of EBITDA and Adjusted EBITDA. These non-GAAP financial measures are not intended to be a substitute for those reported in accordance with GAAP. These measures may be different from non-GAAP financial measures used by other entities, even when similar terms are used to identify such measures.

We define EBITDA as net income (loss) attributable to parent equity, plus interest expense, gain on early extinguishment of debt, income tax expense (benefit), and depreciation and amortization expense. We define Adjusted EBITDA as EBITDA excluding net unrealized gains and losses on derivatives, lower of cost or market adjustments, gains and losses on disposal or impairment of assets, and equity-based compensation expense. We also include in Adjusted EBITDA certain inventory valuation adjustments related to our refined products and renewables segment, as described below. EBITDA and Adjusted EBITDA should not be considered alternatives to net income, income before income taxes, cash flows from operating activities, or any other measure of financial performance calculated in accordance with GAAP as those items are used to measure operating performance, liquidity or the ability to service debt obligations. We believe that EBITDA provides additional information to investors for evaluating our ability to make quarterly distributions to our unitholders and is presented solely as a supplemental measure. We believe that Adjusted EBITDA provides additional information to investors for evaluating our financial performance 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 between realized and unrealized gains and losses on derivatives. During the period when a derivative contract is open, we record changes in the fair value of the derivative as an unrealized gain or loss. When a derivative contract matures or is settled, we reverse the previously recorded unrealized gain or loss and record a realized gain or loss. We do not

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draw such a distinction between realized and unrealized gains and losses on derivatives of our refined products and renewables segment. The primary hedging strategy of our refined products and renewables segment is to hedge against the risk of declines in the value of inventory over the course of the contract cycle, and many of the hedges are six months to one year in duration at inception. The “inventory valuation adjustment” row in the table below 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. We include this in Adjusted EBITDA because the gains and losses associated with derivative contracts of this segment, which are intended primarily to hedge inventory holding risk, also impact Adjusted EBITDA.

A portion of the revenues of our water solutions business is generated from the sale of crude oil that we recover in the process of treating the wastewater. We have historically entered into derivative contracts to protect against the risk of declines in the value of the hydrocarbons we expect to recover in future months. During the year ended March 31, 2016, we settled certain derivative contracts that related to crude oil we expect to recover in the months 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 were attributable to derivatives with scheduled settlement dates during the quarters ending June 30, 2016, September 30, 2016, and December 31, 2016, respectively. During the year ended March 31, 2015, we settled certain derivative contracts that related to crude oil we recovered in the months from April 2015 through September 2015 and realized a gain of $17.9 million. Of this gain, $9.4 million and $8.5 million were attributable to derivatives that settled during the quarters ending June 30, 2015 and September 30, 2015, respectively.

The following table reconciles net (loss) income to our EBITDA and Adjusted EBITDA:
 
 
Year Ended March 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Net (loss) income
 
$
(187,097
)
 
$
50,193

 
$
48,758

Less: Net income attributable to noncontrolling interests
 
(11,832
)
 
(12,887
)
 
(1,103
)
Net (loss) income attributable to parent equity
 
(198,929
)
 
37,306

 
47,655

Interest expense
 
126,514

 
106,594

 
58,871

Gain on early extinguishment of debt
 
(28,532
)
 
—

 
—

Income tax (benefit) expense
 
(420
)
 
(3,676
)
 
937

Depreciation and amortization
 
217,893

 
191,998

 
127,821

EBITDA
 
116,526

 
332,222

 
235,284

Net unrealized losses (gains) on derivatives
 
1,255

 
7,559

 
(1,327
)
Inventory valuation adjustment
 
24,390

 
—

 
—

Lower of cost or market adjustments
 
(5,932
)
 
16,806

 
—

Loss on disposal or impairment of assets, net
 
320,783

 
41,274

 
3,597

Equity-based compensation expense (1)
 
58,816

 
42,890

 
17,804

Acquisition expense (2)
 
2,002

 
23,198

 
15,109

Revaluation of liabilities (3)
 
(93,725
)
 
(20,645
)
 
—

Adjusted EBITDA
 
$
424,115

 
$
443,304

 
$
270,467

 
(1)
Equity-based compensation expense in the table above may differ from equity-based compensation expense reported in Note 11 to our consolidated financial statements included 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 common units, whereas the amounts reported in Note 11 to our consolidated financial statements only include expenses associated with equity-based awards that have been formally granted.
(2)
During the years ended March 31, 2016, 2015 and 2014, we recorded $2.0 million, $7.4 million and $6.9 million, respectively, of expense related to legal and advisory costs associated with acquisitions. During the year ended March 31, 2015, we recorded $15.8 million of compensation expense associated with acquisitions (including certain bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon the successful completion of the sale of the business, and compensation expense related to termination benefits for certain TransMontaigne Inc. (“TransMontaigne”) employees). During the year ended March 31, 2014, we recorded $8.2 million of compensation expense associated with acquisitions (including certain bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon the successful completion of the sale of the business).

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(3)
Amount represents the non-cash valuation adjustment of contingent consideration liabilities, offset by the cash payments, related to royalty agreements acquired as part of acquisitions in our Water Solutions segment. Amount includes $3.0 million and $0.3 million for the years ended March 31, 2016 and 2015, respectively, related to the portion attributatble to noncontrolling interests.

The following tables reconcile depreciation and amortization amounts per the EBITDA table above to depreciation and amortization amounts reported in our consolidated statements of operations and consolidated statements of cash flows for the periods indicated:
 
 
Year Ended March 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Reconciliation to consolidated statements of operations:
 
 
 
 
 
 
Depreciation and amortization per EBITDA table
 
$
217,893

 
$
191,998

 
$
127,821

Intangible asset amortization recorded to cost of sales
 
(6,700
)
 
(7,767
)
 
(6,172
)
Depreciation and amortization of unconsolidated entities
 
(20,058
)
 
(18,979
)
 
(1,500
)
Depreciation and amortization attributable to noncontrolling interests
 
37,789

 
28,697

 
605

Depreciation and amortization per consolidated statements of operations
 
$
228,924

 
$
193,949

 
$
120,754

 
 
 
 
 
 
 
Reconciliation to consolidated statements of cash flows:
 
 
 
 
 
 
Depreciation and amortization per EBITDA table
 
$
217,893

 
$
191,998

 
$
127,821

Amortization of debt issuance costs recorded to interest expense
 
13,587

 
8,759

 
5,727

Depreciation and amortization of unconsolidated entities
 
(20,058
)
 
(18,979
)
 
(1,500
)
Depreciation and amortization attributable to noncontrolling interests
 
37,789

 
28,697

 
605

Depreciation and amortization per consolidated statements of cash flows
 
$
249,211

 
$
210,475

 
$
132,653

 

The following table reconciles interest expense per the EBITDA table above to interest expense reported in our consolidated statements of operations for the periods indicated:
 
 
Year Ended March 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Interest expense per EBITDA table
 
$
126,514

 
$
106,594

 
$
58,871

Interest expense attributable to noncontrolling interests (1)
 
5,493

 
3,443

 
—

Gain on extinguishment of debt of unconsolidated entities
 
693

 
—

 
—

Other (2)
 
389

 
86

 
(17
)
Interest expense per consolidated statements of operations
 
$
133,089

 
$
110,123

 
$
58,854

 
(1)
Includes ten months of consolidated TLP interest expense.
(2)
Includes two months of TLP interest expense as an equity method investment.


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The following tables reconcile operating income (loss) to Adjusted EBITDA by segment for the periods indicated:
 
Year Ended March 31, 2016
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
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

 
228,924

Amortization recorded to cost of sales
250

 
—

 
1,044

 
—

 
5,406

 
—

 
6,700

Net unrealized losses (gains) on derivatives
2,123

 
3,196

 
(4,008
)
 
(56
)
 
—

 
—

 
1,255

Inventory valuation adjustment
—

 
—

 
—

 
—

 
24,390

 
—

 
24,390

Lower of cost or market adjustments
(1,211
)
 
—

 
—

 
—

 
(4,721
)
 
—

 
(5,932
)
Loss (gain) on disposal or impairment of assets, net
54,952

 
381,682

 
11,600

 
(137
)
 
(127,314
)
 
—

 
320,783

Equity-based compensation expense
—

 
—

 
—

 
—

 
501

 
58,315

 
58,816

Acquisition expense
—

 
—

 
—

 
7

 
—

 
1,995

 
2,002

Equity in earnings (losses) of unconsolidated entities
3,547

 
(552
)
 
—

 
(528
)
 
13,654

 
—

 
16,121

Other (expense) income, net
(6,725
)
 
2,144

 
281

 
1,055

 
179

 
8,641

 
5,575

Depreciation and amortization of unconsolidated entities
9,927

 
1,135

 
—

 
98

 
8,898

 
—

 
20,058

Adjusted EBITDA attributable to noncontrolling interest
—

 
(518
)
 
—

 
(1,324
)
 
(54,407
)
 
—

 
(56,249
)
Revaluation of liabilities
—

 
(93,725
)
 
—

 
—

 
—

 
—

 
(93,725
)
Adjusted EBITDA
$
61,481

 
$
71,374

 
$
100,732

 
$
79,203

 
$
134,398

 
$
(23,073
)
 
$
424,115

 
Year Ended March 31, 2015
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
Consolidated
 
(in thousands)
Operating (loss) income
$
(35,832
)
 
$
65,340

 
$
45,072

 
$
64,075

 
$
54,567

 
$
(85,802
)
 
$
107,420

Depreciation and amortization
38,626

 
73,618

 
13,513

 
31,827

 
32,948

 
3,417

 
193,949

Amortization recorded to cost of sales
102

 
—

 
1,931

 
—

 
4,057

 
1,677

 
7,767

Net unrealized losses (gains) on derivatives
7,421

 
(2,786
)
 
2,921

 
3

 
—

 
—

 
7,559

Lower of cost or market adjustments
10,744

 
—

 
(51
)
 
—

 
6,113

 
—

 
16,806

Loss (gain) on disposal or impairment of assets, net
3,759

 
7,504

 
29,776

 
330

 
1

 
(96
)
 
41,274

Equity-based compensation expense
—

 
—

 
—

 
—

 
123

 
42,767

 
42,890

Acquisition expense
6,870

 
—

 
—

 
45

 
8,510

 
7,773

 
23,198

Equity in earnings (losses) of unconsolidated entities
3,731

 
(29
)
 
—

 
—

 
8,401

 
—

 
12,103

Other income (expense), net
27,305

 
3,360

 
31

 
1,644

 
(120
)
 
4,951

 
37,171

Depreciation and amortization of unconsolidated entities
10,213

 
1,123

 
—

 
—

 
7,643

 
—

 
18,979

Adjusted EBITDA attributable to noncontrolling interest
—

 
(1,220
)
 
—

 
(1,110
)
 
(42,837
)
 
—

 
(45,167
)
Revaluation of liabilities
—

 
(20,645
)
 
—

 
—

 
—

 
—

 
(20,645
)
Adjusted EBITDA
$
72,939

 
$
126,265

 
$
93,193

 
$
96,814

 
$
79,406

 
$
(25,313
)
 
$
443,304



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Table of Contents

 
Year Ended March 31, 2014
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products
and
Renewables
 
Corporate
and
Other
 
Consolidated
 
(in thousands)
Operating income (loss)
$
678

 
$
10,317

 
$
71,888

 
$
61,285

 
$
6,514

 
$
(44,117
)
 
$
106,565

Depreciation and amortization
22,111

 
55,105

 
11,018

 
28,878

 
625

 
3,017

 
120,754

Amortization recorded to cost of sales
990

 
—

 
2,882

 
—

 
1,600

 
700

 
6,172

Net unrealized losses (gains) on derivatives
2,229

 
647

 
(4,217
)
 
14

 
—

 
—

 
(1,327
)
(Gain) loss on disposal or impairment of assets, net
(169
)
 
2,994

 
5,305

 
1

 
—

 
(4,534
)
 
3,597

Equity-based compensation expense
—

 
—

 
—

 
—

 
—

 
17,804

 
17,804

Acquisition expense
3,500

 
—

 
—

 
23

 
—

 
11,586

 
15,109

Equity in (losses) earnings of unconsolidated entities
(26
)
 
—

 
—

 
—

 
—

 
1,924

 
1,898

Other (expense) income, net
(2,939
)
 
(266
)
 
(212
)
 
1,308

 
51

 
2,144

 
86

Depreciation and amortization of unconsolidated entities
1,500

 
—

 
—

 
—

 
—

 
—

 
1,500

Adjusted EBITDA attributable to noncontrolling interest
—

 
(631
)
 
—

 
(163
)
 
(897
)
 
—

 
(1,691
)
Adjusted EBITDA
$
27,874

 
$
68,166

 
$
86,664

 
$
91,346

 
$
7,893

 
$
(11,476
)
 
$
270,467

 

Segment Operating Results

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We have expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of Crescent Terminals, LLC and Cierra Marine, LP and its affiliated companies (collectively, “Crescent”) in July 2013, and Gavilon Energy in December 2013. We have expanded our water solutions business considerably through numerous acquisitions of water treatment and disposal facilities. We have expanded our liquids business through the February 2015 acquisition of Sawtooth. We have expanded our retail propane business through numerous acquisitions of retail propane businesses. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy and significantly expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane businesses are impacted by seasonality, due primarily to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues.


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Year Ended March 31, 2016 Compared to Year Ended March 31, 2015

Crude Oil Logistics 

The following table summarizes the operating results of our crude oil logistics segment for the periods indicated:
 
 
Year Ended March 31,
 
 
 
 
2016
 
2015 (1)
 
Change
 
 
(in thousands, expect per barrel amounts)
Revenues:
 
 
 
 
 
 
Crude oil sales
 
$
3,170,891

 
$
6,621,871

 
$
(3,450,980
)
Crude oil transportation and other
 
55,882

 
43,349

 
12,533

Total revenues (2)
 
3,226,773

 
6,665,220

 
(3,438,447
)
Expenses:
 
 

 
 

 
 

Cost of sales
 
3,121,411

 
6,590,313

 
(3,468,902
)
Operating expenses
 
43,458

 
52,790

 
(9,332
)
General and administrative expenses
 
8,334

 
15,564

 
(7,230
)
Depreciation and amortization expense
 
39,363

 
38,626

 
737

Loss on disposal or impairment of assets, net
 
54,952

 
3,759

 
51,193

Total expenses
 
3,267,518

 
6,701,052

 
(3,433,534
)
Segment operating loss (3)
 
$
(40,745
)
 
$
(35,832
)
 
$
(4,913
)
 
 
 
 
 
 
 
Crude oil sold (barrels)
 
67,211

 
83,864

 
(16,653
)
Crude oil sold ($/barrel)
 
$
47.178

 
$
78.960

 
$
(31.782
)
Cost per crude oil sold ($/barrel)
 
$
46.442

 
$
78.583

 
$
(32.141
)
Crude oil product margin ($/barrel)
 
$
0.736

 
$
0.377

 
$
0.359

 
(1)
During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to the categories shown in the table above. These changes did not impact total revenues. We have retrospectively adjusted previously reported amounts to conform to the current presentation.
(2)
Revenues include $9.7 million and $29.8 million of intersegment sales during the years ended March 31, 2016 and 2015, respectively, that are eliminated in our consolidated statements of operations.
(3)
In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to 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 and additional 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 in our consolidated statement of operations, net of certain project abandonment costs. Since this gain was reported in other income, it is not reflected in the table above.

Crude Oil Sales. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices since July 2014. The decrease in our sales volumes was due primarily to a slowdown in crude oil production and new drilling of crude oil in the current crude oil price environment.

Our cost of sales during the year ended March 31, 2016 was increased by $2.1 million of net unrealized losses on derivatives and reduced by $13.8 million of net realized gains on derivatives. Our cost of sales during the year ended March 31, 2015 was increased by $7.4 million of net unrealized losses on derivatives and reduced by $37.4 million of net realized gains on derivatives. Due to the sharper decline in crude oil prices during the year ended March 31, 2015 compared to the year ended March 31, 2016, realized gains on derivatives were higher during the year ended March 31, 2015. Our cost of sales 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.

Crude Oil Transportation and Other Revenues. The increase was due primarily to crude oil markets being in contango during the year ended March 31, 2016 (a condition in which forward crude oil prices are greater than spot prices), which allowed us to generate revenue from leasing our owned storage and subleasing our leased storage.

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Operating Expenses. The decrease was due primarily to lower compensation expense due primarily to a reduction in headcount from organizational changes and lower repair and maintenance expense due to the timing of repairs.

General and Administrative Expenses. The decrease was due primarily to $5.6 million of compensation expense during the year ended March 31, 2015 related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business, which were paid in December 2014, and $1.3 million of compensation expense during the year ended March 31, 2015 related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense. The increase was due primarily to capital additions during the year ended March 31, 2016.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2016, we recorded a write-down of $47.7 million related to pipe we no longer expect to use in the originally-planned Grand Mesa Pipeline. Also, during the year ended March 31, 2016, (i) two previously-planned projects were canceled and we recorded a loss of $3.1 million, (ii) we recorded an impairment of $2.4 million to the property, plant and equipment of two of our crude oil barges and (iii) we sold and/or abandoned certain trucks, trailers and barges and recorded a loss of $1.4 million. During the year ended March 31, 2015, we recorded a write-off of project costs of $3.5 million related to a crude oil terminal project that has been discontinued.

Water Solutions

The following table summarizes the operating results of our water solutions segment for the periods indicated:
 
 
Year Ended March 31,
 
 
 
 
2016
 
2015
 
Change
 
 
(in thousands, except per barrel amounts)
Revenues:
 
 
 
 
 
 
Service fees
 
$
136,710

 
$
105,682

 
$
31,028

Recovered hydrocarbons
 
41,090

 
81,762

 
(40,672
)
Water transportation
 
—

 
10,760

 
(10,760
)
Other revenues
 
7,201

 
1,838

 
5,363

Total revenues
 
185,001

 
200,042

 
(15,041
)
Expenses:
 
 
 
 
 
 
Cost of sales-derivative gain (1)
 
(7,095
)
 
(36,763
)
 
29,668

Cost of sales-other
 
(241
)
 
6,257

 
(6,498
)
Operating expenses
 
112,538

 
93,268

 
19,270

General and administrative expenses
 
2,778

 
3,082

 
(304
)
Depreciation and amortization expense
 
91,685

 
73,618

 
18,067

Loss on disposal or impairment of assets, net
 
381,682

 
7,504

 
374,178

Revaluation of liabilities
 
(82,673
)
 
(12,264
)
 
(70,409
)
Total expenses
 
498,674

 
134,702

 
363,972

Segment operating (loss) income
 
$
(313,673
)
 
$
65,340

 
$
(379,013
)
 
 
 
 
 
 
 
Water received (barrels)
 
208,440

 
161,664

 
46,776

Service fee for water processed ($/barrel)
 
$
0.66

 
$
0.65

 
$
0.01

Recovered hydrocarbons for water processed ($/barrel)
 
$
0.20

 
$
0.51

 
$
(0.31
)
 
(1)
Includes realized and unrealized (gains) losses.
The following tables summarize activity separated between the following categories:
•
facilities we owned before March 31, 2014, which we refer to below as “existing facilities” and
•
facilities we acquired or developed after March 31, 2014, which we refer to below as “recently acquired or developed facilities”.

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Service Fee Revenues. The following table summarizes our service fee revenues (in thousands, except per barrel amounts) for the periods indicated:
 
 
Year Ended March 31,
 
 
2016
 
2015
 
 
Service
Fees
 
Water Barrels Processed
 
Fees Per 
Water Barrel
Processed
 
Service
Fees
 
Water Barrels Processed
 
Fees Per 
Water Barrel
Processed
Existing facilities
 
$
74,195

 
90,377

 
$
0.82

 
$
81,273

 
122,454

 
$
0.66

Recently acquired or developed facilities
 
62,515

 
118,063

 
0.53

 
24,409

 
39,210

 
0.62

Total
 
$
136,710

 
208,440

 
0.66

 
$
105,682

 
161,664

 
0.65


The decrease in the volume processed at our existing facilities was due primarily to a slowdown in customer production as a result of the lower crude oil prices, as well as migration of volumes from existing facilities to recently developed or acquired facilities due to the location of the new facilities. The increase in fees per water barrel processed at our existing facilities is partially due to an increase in the service fees in a certain basin and a favorable deliver or pay agreement with a customer where the customer has not been delivering water to our facilities.

Recovered Hydrocarbon Revenues. The following table summarizes our recovered hydrocarbon revenues (in thousands, except per barrel amounts) for the periods indicated:
 
 
Year Ended March 31,
 
 
2016
 
2015
 
 
Recovered
Hydrocarbon
Revenue
 
Water Barrels Processed
 
Revenue Per 
Water Barrel
Processed
 
Recovered
Hydrocarbon
Revenue
 
Water Barrels Processed
 
Revenue Per 
Water Barrel
Processed
Existing facilities
 
$
22,791

 
90,377

 
$
0.25

 
$
71,301

 
122,454

 
$
0.58

Recently acquired or developed facilities
 
18,299

 
118,063

 
0.15

 
10,461

 
39,210

 
0.27

Total
 
$
41,090

 
208,440

 
0.20

 
$
81,762

 
161,664

 
0.51


The decrease in revenue per barrel associated with recovered hydrocarbons was due primarily to the sharp decline in crude oil prices since July 2014 and a decrease in the volume of hydrocarbons recovered per barrel of water processed.

Water Transportation Revenues. The decrease was due to revenues related to our water transportation business during the year ended March 31, 2015. We sold this business during September 2014.

Other Revenues. The increase was due primarily to revenues related to the disposal of solids.

Cost of Sales. We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expected to recover when processing the wastewater. Our cost of sales during the year ended March 31, 2016 included $10.3 million of net realized gains on derivatives, partially offset by $3.2 million of net unrealized losses on derivatives. Our cost of sales during the year ended March 31, 2015 included $2.8 million of net unrealized gains on derivatives and $34.0 million of net realized gains on derivatives. In December 2015, we settled derivative contracts that had scheduled settlement dates from January 2016 through December 2016, in order to lock in the gains on those derivatives. In December 2014, we settled derivative contracts that had scheduled settlement dates from April 2015 through September 2015, in order to lock in the gains on those derivatives.

The decrease in other cost of sales was due to costs related to our water transportation business during the year ended March 31, 2015. We sold this business during September 2014.


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Operating Expenses. The following table summarizes our operating expenses for the periods indicated: 
 
 
Year Ended March 31,
 
 
 
 
2016
 
2015
 
Change
 
 
(in thousands)
Existing facilities
 
$
65,739

 
$
73,533

 
$
(7,794
)
Recently acquired or developed facilities
 
46,799

 
19,735

 
27,064

Total
 
$
112,538

 
$
93,268

 
$
19,270


The decrease in operating expenses for existing facilities was due primarily to lower operating costs of water disposal wells at existing facilities due to lower volumes processed.

Depreciation and Amortization Expense. Of the increase, $15.7 million related to recently acquired or developed water treatment and disposal facilities and $3.4 million related to recently developed solids processing facilities.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2016, we recorded an estimated goodwill impairment charge of $380.2 million as the decline in crude oil prices and crude oil production have had an unfavorable impact on our water solutions business (see Note 14 to our consolidated financial statements included in this Annual Report). During the year ended March 31, 2015, we sold our water transportation business and recorded a loss of $4.0 million. Also, during the year ended March 31, 2015, we recorded a loss on abandonment of $3.1 million related to property, plant and equipment of water disposal facilities that we have retired.

Revaluation of Liabilities. The revaluation of liabilities represents the valuation adjustment of contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations. The increase was due to additional acquisitions during the year ended March 31, 2016 offset by changes in the fair value of the liability.


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Liquids

The following table summarizes the operating results of our liquids segment for the periods indicated: 
 
 
Year Ended March 31,
 
 
 
 
2016
 
2015 (1)
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues (2)
 
$
618,919

 
$
1,265,262

 
$
(646,343
)
Cost of sales
 
571,734

 
1,217,993

 
(646,259
)
Product margin
 
47,185

 
47,269

 
(84
)
 
 
 
 
 
 
 
Other product sales:
 
 
 
 
 
 
Revenues (2)
 
620,175

 
1,111,834

 
(491,659
)
Cost of sales
 
532,136

 
1,038,324

 
(506,188
)
Product margin
 
88,039

 
73,510

 
14,529

 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues (2)
 
35,943

 
28,745

 
7,198

Cost of sales
 
13,806

 
17,313

 
(3,507
)
Product margin
 
22,137

 
11,432

 
10,705

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
Operating expenses
 
45,140

 
35,580

 
9,560

General and administrative expenses
 
8,806

 
8,271

 
535

Depreciation and amortization expense
 
15,642

 
13,513

 
2,129

Loss on disposal or impairment of assets, net
 
11,600

 
29,775

 
(18,175
)
Total expenses
 
81,188

 
87,139

 
(5,951
)
Segment operating income
 
$
76,173

 
$
45,072

 
$
31,101

 
 
 
 
 
 
 
Propane sold
 
1,244,529

 
1,285,707

 
(41,178
)
Propane sold ($/gallon)
 
$
0.497

 
$
0.984

 
$
(0.487
)
Cost per propane sold ($/gallon)
 
$
0.459

 
$
0.947

 
$
(0.488
)
Propane product margin ($/gallon)
 
$
0.038

 
$
0.037

 
$
0.001

 
 
 
 
 
 
 
Other products sold (gallons)
 
843,922

 
825,514

 
18,408

Other products sold ($/gallon)
 
$
0.735

 
$
1.347

 
$
(0.612
)
Cost per other products sold ($/gallon)
 
$
0.631

 
$
1.258

 
$
(0.627
)
Other products product margin ($/gallon)
 
$
0.104

 
$
0.089

 
$
0.015

 
(1)
During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to railcar cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.
(2)
Revenues include $80.6 million and $162.0 million of intersegment sales during the years ended March 31, 2016 and 2015, respectively, that are eliminated in our consolidated statements of operations.

Propane Sales. The decrease in volumes was due to significantly warmer temperatures in the current year. The decrease in selling price was due to lower commodity prices from oversupply in the market and decreased demand due to the significantly warmer temperatures in the current year winter.


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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 net unrealized losses on derivatives for the years ended March 31, 2016 and 2015, respectively. Additionally, our cost of wholesale propane sales was increased by $1.6 million of net realized losses on derivatives and $8.2 million of net realized losses on derivatives for the years ended March 31, 2016 and 2015, respectively.

Product margins per gallon of propane sold were higher during the year ended March 31, 2016 than during the year ended March 31, 2015. Propane prices declined during the year ended March 31, 2016, but not as sharply as they declined during the year ended March 31, 2015. Declining propane prices typically 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 location of 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 to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these 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 all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of declining prices, this can result in lower margins on these sales. We would generally expect the impact of these two different strategies being in the same inventory costing pools to even out over the course of a full fiscal year.

Other Products Sales. The increase in the volume of other wholesale products sold was due to expanded operations.

Our cost of sales of other products during the year ended March 31, 2016 was reduced by $1.9 million of net unrealized gains on derivatives. Our cost of sales of other products during the year ended March 31, 2015 was reduced by $1.7 million of net unrealized gains on derivatives. Additionally, our cost of other products was reduced by $1.8 million of net realized gains on derivatives and increased by $5.4 million of net realized losses on derivatives for the years ended March 31, 2016 and 2015, respectively.

Product margins during the year ended March 31, 2016 benefited from a high level of butane supply in the market, which lowered our product cost.

Other Revenues. This revenue includes storage, terminaling and transportation services income. The increase was due primarily to $21.1 million of revenue related to Sawtooth, which we acquired in February 2015, partially offset 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 as a shift in the recording of incentive compensation expense related to bonuses from the liquids segment to “corporate and other” during the year ended March 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 in February 2015.

Depreciation and Amortization Expense. The increase was due to an additional $4.2 million of expense during the year ended March 31, 2016 related to Sawtooth, which we acquired in February 2015, partially offset by $1.0 million of expense recorded during the year ended March 31, 2015 related to a natural gas liquids terminal that we sold in December 2014.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2016, we wrote off assets of $14.6 million acquired as part of the Gavilon Energy acquisition that we deemed no longer recoverable. During the year ended March 31, 2016, we received a payment of $3.0 million from the state of Maine to relocate certain terminal assets. During the year ended March 31, 2015, we recorded a loss on disposal of assets of $29.8 million related to the sale of a natural gas liquids terminal.


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Retail Propane

The following table summarizes the operating results of our retail propane segment for the periods indicated: 
 
 
Year Ended March 31,
 
 
 
 
2016
 
2015
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues
 
$
248,673

 
$
347,575

 
$
(98,902
)
Cost of sales
 
95,191

 
181,655

 
(86,464
)
Product margin
 
153,482

 
165,920

 
(12,438
)
 
 
 
 
 
 
 
Distillate sales:
 
 
 
 
 
 
Revenues
 
64,868

 
106,037

 
(41,169
)
Cost of sales
 
48,191

 
85,329

 
(37,138
)
Product margin
 
16,677

 
20,708

 
(4,031
)
 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues
 
39,436

 
35,585

 
3,851

Cost of sales
 
13,375

 
11,554

 
1,821

Product margin
 
26,061

 
24,031

 
2,030

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
104,287

 
102,123

 
2,164

General 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

 
5,540

Segment operating income
$
44,096

 
$
64,075

 
$
(19,979
)
 
 
 
 
 
 
 
Propane sold (gallons)
 
152,238

 
169,279

 
(17,041
)
Propane sold ($/gallon)
 
$
1.633

 
$
2.053

 
$
(0.420
)
Cost per propane sold ($/gallon)
 
$
0.625

 
$
1.073

 
$
(0.448
)
Propane product margin ($/gallon)
 
$
1.008

 
$
0.980

 
$
0.028

 
 
 
 
 
 
 
Distillates sold (gallons)
 
30,674

 
34,862

 
(4,188
)
Distillates sold ($/gallon)
 
$
2.115

 
$
3.042

 
$
(0.927
)
Cost per distillates sold ($/gallon)
 
$
1.571

 
$
2.448

 
$
(0.877
)
Distillates product margin ($/gallon)
 
$
0.544

 
$
0.594

 
$
(0.050
)

Revenues. The decrease in both propane and distillate revenues was due to lower volumes as a result of significantly warmer winter temperatures in the current year, as compared to the prior year. The decrease in selling price was due to an oversupply in the propane market lowering commodity prices 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 were consistent 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.


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Refined Products and Renewables

The following table summarizes the operating results of our refined products and renewables segment for the periods indicated. Our refined products and renewables segment was significantly expanded with our July 2014 acquisition of TransMontaigne. 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 partner investment in TLP using the equity method of accounting.
 
 
Year Ended March 31,
 
 
 
 
2016
 
2015 (1)
 
Change
 
 
(in thousands, except per barrel and gallon amounts)
Refined products sales:
 
 
 
 
 
 
Revenues (2)
 
$
6,294,008

 
$
6,682,040

 
$
(388,032
)
Cost of sales
 
6,161,243

 
6,574,545

 
(413,302
)
Product margin
 
132,765

 
107,495

 
25,270

 
 
 
 
 
 
 
Renewables sales:
 
 
 
 
 
 
Revenues
 
390,753

 
473,885

 
(83,132
)
Cost of sales
 
380,212

 
461,996

 
(81,784
)
Product margin
 
10,541

 
11,889

 
(1,348
)
 
 
 
 
 
 
 
Service fee revenues
 
108,221

 
76,847

 
31,374

 
 
 
 
 
 
 
Expenses:
 
 
 


 
 
Operating expenses
 
95,371

 
82,583

 
12,788

General and administrative expenses
 
15,675

 
26,133

 
(10,458
)
Depreciation and amortization expense
 
40,861

 
32,948

 
7,913

Gain on disposal or impairment of assets, net
 
(127,331
)
 
—

 
(127,331
)
Total expenses
 
24,576

 
141,664

 
(117,088
)
Segment operating income
 
$
226,951

 
$
54,567

 
$
172,384

 
 
 
 
 
 
 
Refined products sold (barrels)
 
98,988

 
68,043

 
30,945

Refined products sold ($/barrel)
 
$
63.584

 
$
98.203

 
$
(34.619
)
Cost per refined products sold ($/barrel)
 
$
62.242

 
$
96.623

 
$
(34.381
)
Refined products product margin ($/barrel)
 
$
1.342

 
$
1.580

 
$
(0.238
)
Refined products product margin ($/gallon)
 
$
0.032

 
$
0.038

 
$
(0.006
)
 
 
 
 
 
 
 
Renewable products sold (barrels)
 
5,794

 
5,318

 
476

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
)
Renewable products product margin ($/gallon)
 
$
0.043

 
$
0.053

 
$
(0.010
)
 
(1)
During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues and cost of sales to the categories shown in the table above. These changes did not impact total revenues or total cost of sales. We have retrospectively adjusted previously reported amounts to conform to the current presentation.
(2)
Revenues include $0.9 million and $1.1 million of intersegment sales during the years ended March 31, 2016, and 2015, respectively, that are eliminated in our consolidated statement of operations.

Refined Products and Renewables Sales. Our refined products and renewables segment was significantly expanded with our July 2014 acquisition of TransMontaigne. The resultant increase in revenues and cost of sales was offset by a sharp decline in product prices. Also, the decrease in per-barrel renewable product margins was due primarily to lower renewables

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prices 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 for transactions during calendar year 2014 to $6.2 million for transactions in calendar year 2015.

Operating Expenses. The increase was due primarily to the inclusion of TLP for ten months of the current fiscal year, compared to nine months of the prior fiscal year as TLP was deconsolidated on February 1, 2016. Also contributing to the increase was the inclusion of TransMontaigne for the entire current fiscal year, compared to nine months of the prior fiscal year.

General and Administrative Expenses. The decrease was due primarily to $8.0 million of compensation expense during the year ended March 31, 2015 related to termination benefits for certain TransMontaigne employees. This decrease was partially offset by the inclusion of TransMontaigne for the entire current fiscal year, compared to nine months of the prior fiscal year.

Depreciation and Amortization Expense. The increase was due primarily to the inclusion of TLP for ten months of the current fiscal year, compared to nine months of the prior fiscal year as TLP was deconsolidated on February 1, 2016.

Gain on Disposal or Impairment of Assets, Net. During the year ended March 31, 2016, we sold our general partner interest in TLP and recorded a gain on disposal of $329.9 million during the three months ended March 31, 2016. As part of this transaction, we entered into lease agreements whereby we will remain the long-term exclusive tenant in the TLP Southeast terminal system. As a result of entering into these leases, we deferred $204.6 million of the gain on the sale and will recognize this amount over our future lease payment obligations, which is approximately seven years. During the three months ended March 31, 2016, we recognized $5.0 million of the deferred gain in our consolidated statement of operations. See “Recent Developments” above for a further discussion. During the year ended March 31, 2016, we recorded a loss of $1.8 million related to certain property, plant and equipment that we have retired and we also sold certain tank bottoms and recorded a loss of $1.3 million.

Corporate and Other

The operating loss within “corporate and other” includes the following components for the periods indicated: 
 
 
Year Ended March 31,
 
 
 
 
2016
 
2015
 
Change
 
 
(in thousands)
Incentive compensation expense
 
$
(61,252
)
 
$
(48,339
)
 
$
(12,913
)
Acquisition expense
 
(2,002
)
 
(7,382
)
 
5,380

Other corporate expenses
 
(34,151
)
 
(30,081
)
 
(4,070
)
Total
 
$
(97,405
)
 
$
(85,802
)
 
$
(11,603
)

The expenses shown in the table above for incentive compensation include cash-based and equity-based compensation. Such incentive compensation expenses were higher during the year ended March 31, 2016 than during the year ended March 31, 2015, due primarily to two factors described below.

As part of its review of our executive compensation program, the Compensation Committee of the Board of Directors approved a new type of equity-based compensation award, under which the number of common units that vest is contingent upon the performance of our common units relative to the performance of other entities in the Alerian MLP Index. During the year ended March 31, 2016, three tranches of these Performance Awards were granted, with vesting dates of July 1, 2015, July 1, 2016, and July 1, 2017, respectively. We recorded $16.4 million of expense related to the Performance 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 outstanding Service Awards was higher at March 31, 2016 than at March 31, 2015. This was due in part to the addition of new employees as our business has expanded, and was due in part to increases in the number of Service Awards granted to certain employees following the Compensation Committee’s review of our compensation program. The expense associated with these Service Awards (exclusive of accruals of annual 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 during the year ended March 31, 2015.

The expense associated with annual bonuses (a portion of which were paid or are expected to be paid in common units) was $2.9 million during the year ended March 31, 2016, compared to $5.0 million during the year ended March 31, 2015.

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We record compensation expense related to common units within “corporate and other”, while compensation expense paid in cash is recorded within the individual business segments.

The expenses shown in the table above for acquisitions relate primarily to legal and advisory costs. We incurred $4.2 million of such expenses during the year ended March 31, 2015 related to our acquisition of TransMontaigne.



Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $16.1 million and $12.1 million during the years ended March 31, 2016 and 2015, respectively. The increase was due primarily to an increase of $7.1 million of earnings from TLP (including Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and Frontera Brownsville LLC (“Frontera”)) that we acquired as part of our July 2014 acquisition of TransMontaigne, and which we deconsolidated when we sold our general partner interest in TLP as of February 1, 2016, partially offset by a decrease of $2.4 million in earnings from our investments in an ethanol production facility and a water supply company.

Interest Expense

Interest expense includes interest expense on our revolving credit facilities and senior notes, amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on noninterest bearing debt obligations. Interest expense was $133.1 million and $110.1 million during the years ended March 31, 2016 and 2015, respectively. The increase in interest expense was due primarily to (i) the increased level of debt outstanding on our Revolving Credit Facility (the average balance outstanding on our Revolving Credit Facility was $1.7 billion during the year ended March 31, 2016, compared to $1.2 billion during year ended March 31, 2015), primarily to finance acquisitions and capital expenditures; (ii) the issuance of $400.0 million of fixed-rate notes during July 2014; and (iii) increased interest expense related to TLP’s credit facility (our interest in TLP was acquired in July 2014, and we sold our general partner interest in TLP as of February 1, 2016).

Gain on Early Extinguishment of Debt

During the fourth quarter of fiscal year 2016, we repurchased $73.2 million of our 2019 Notes and 2021 Notes for an aggregate purchase price of $43.4 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2019 Notes and 2021 Notes of $28.5 million (net of the write off of debt issuance costs of $1.3 million).

Other Income, Net

The 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

 
$
4,575

Crude oil marketing arrangement (2)
(6,726
)
 
(5,642
)
Crude oil rail transloading facility (3)
—

 
31,600

Other (4)
297

 
6,638

Other 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 receivable from an equity method investee.
(2)
Represents another party’s share of the profits generated from a joint crude oil marketing arrangement.
(3)
In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to 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 and additional cash payments over the next five years. In addition, one of the producers committed to pay us a specified fee on each barrel

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of crude oil it produces in a specified basin over a period of seven years. Upon execution of these agreements in March 2015, we recorded a gain of $31.6 million to other income, net of certain project abandonment costs.
(4)
During the year ended March 31, 2015, we settled two separate contractual disputes and recorded $5.5 million of proceeds to other income. Also during the year ended March 31, 2015, we offered to settle another contractual dispute, and recorded $1.2 million to other expense as an estimate of the probable loss. During the year ended March 31, 2016, we finalized the settlement of this contractual dispute and paid approximately $0.5 million at the date of settlement and committed to pay approximately $1.1 million in equal annual installments over a period of 11 years beginning on October 15, 2016 and ending in October 2026.

Income Tax Expense (Benefit)

We qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner’s basis in the Partnership.

We have certain taxable corporate subsidiaries in the United States and in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. Our fiscal years 2012 to 2015 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.

Income tax benefit was $0.4 million and $3.6 million during the years ended March 31, 2016 and 2015, respectively. TransMontaigne was a taxable subsidiary from July 1, 2014 (the date we acquired TransMontaigne) to December 30, 2014 (the date we converted TransMontaigne to a non-taxable entity). Income tax benefit during the year ended March 31, 2016 includes a benefit of $3.6 million related to a change in estimate of the income tax obligation payable related to TransMontaigne. Income tax benefit during the year ended March 31, 2015 was attributable primarily to TransMontaigne.

Noncontrolling Interests

We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated financial statements represents the other owners’ interest in these entities.

Net income attributable to noncontrolling interests was $11.8 million and $12.9 million during the years ended March 31, 2016 and 2015, respectively. The noncontrolling interests were due primarily to the July 2014 acquisition of TransMontaigne, in which we acquired the 2% general partner interest and a 19.7% limited partner interest in TLP. On February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting.



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Year Ended March 31, 2015 Compared to Year Ended March 31, 2014

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the periods indicated:
 
 
Year Ended March 31,
 
 
 
 
2015
 
2014
 
Change
 
 
(in thousands, expect per barrel amounts)
Revenues:
 
 
 
 
 
 
Crude oil sales
 
$
6,621,871

 
$
4,559,923

 
$
2,061,948

Crude oil transportation and other
 
43,349

 
36,469

 
6,880

Total revenues (1)
 
6,665,220

 
4,596,392

 
2,068,828

Expenses:
 
 

 
 

 
 

Cost of sales
 
6,590,313

 
4,515,244

 
2,075,069

Operating expenses
 
52,790

 
54,043

 
(1,253
)
General and administrative expenses
 
15,564

 
4,487

 
11,077

Depreciation and amortization expense
 
38,626

 
22,111

 
16,515

Loss (gain) on disposal or impairment of assets, net
 
3,759

 
(171
)
 
3,930

Total expenses
 
6,701,052

 
4,595,714

 
2,105,338

Segment operating (loss) income (2)
 
$
(35,832
)
 
$
678

 
$
(36,510
)
 
 
 
 
 
 
 
Crude oil sold (barrels)
 
83,864

 
46,107

 
37,757

Crude oil sold ($/barrel)
 
$
78.960

 
$
98.899

 
$
(19.939
)
Cost per crude oil sold ($/barrel)
 
$
78.583

 
$
97.930

 
$
(19.347
)
Crude oil product margin ($/barrel)
 
$
0.377

 
$
0.969

 
$
(0.592
)
 
(1)
Revenues include $29.8 million and $37.8 million of intersegment sales during the years ended March 31, 2015 and 2014, respectively, that are eliminated in our consolidated statements of operations.
(2)
In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to 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 and additional 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 in our consolidated statement of operations, net of certain project abandonment costs. Since this gain was reported in other income, it is not reflected in the table above.

Crude Oil Sales. The decrease in revenue per barrel was due primarily to the sharp decline in crude oil prices since July 2014. The most significant driver of the increase in our sales volumes was the acquisition of Gavilon Energy in December 2013.

Our cost of sales during the year ended March 31, 2015 was increased by $7.4 million of net unrealized losses on derivatives and reduced by $37.4 million of net realized gains on derivatives. Our cost of sales during the year ended March 31, 2014 was increased by $2.2 million of net unrealized losses on derivatives and $5.1 million of net realized losses on derivatives.

The decrease in product margins was due primarily to the sharp decline in crude oil prices since July 2014, which had an adverse impact on margins due to the difference in timing of when we purchase product and when we deliver it to the point of sale. In addition, we were unable to utilize certain leased storage during most of the year ended March 31, 2015, as crude oil markets were backwardated for most of the year.

Crude Oil Transportation and Other Revenues. The increase was due primarily to the Crescent acquisition in July 2013 and the Gavilon Energy acquisition in December 2013.


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Operating Expenses. The decrease was due primarily to a shift in the recording of incentive compensation expense related to bonuses from the crude oil logistics segment to “corporate and other” during the year ended March 31, 2015. See further discussion within the “Corporate and Other” section below. The decrease was also due to lower railcar lease expense as we purchased railcars beginning in January 2014 to utilize in our operations and lower relocation expenses, partially offset by an increase due to the Gavilon Energy acquisition in December 2013.

General and Administrative Expenses. The increase was due to the acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. General and administrative expenses during the years ended March 31, 2015 and 2014 were increased by $5.6 million and $3.0 million, respectively, of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. General and administrative expenses during the year ended March 31, 2015 were also increased by $1.3 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense. The increase was due primarily to acquisitions and capital expansions.

Loss (Gain) on Disposal or Impairment of Assets, Net. During the year ended March 31, 2015, we recorded a write-off of project costs of $3.5 million related to a crude oil terminal project that has been discontinued.

Water Solutions

The following table summarizes the operating results of our water solutions segment for the periods indicated:
 
 
Year Ended March 31,
 
 
 
 
2015
 
2014
 
Change
 
 
(in thousands, except per barrel amounts)
Revenues:
 
 

 
 

 
 

Service fees
 
$
105,682

 
$
58,161

 
$
47,521

Recovered hydrocarbons
 
81,762

 
67,627

 
14,135

Water transportation
 
10,760

 
17,312

 
(6,552
)
Other revenues
 
1,838

 
—

 
1,838

Total revenues
 
200,042

 
143,100

 
56,942

Expenses:
 
 

 
 

 
 

 Cost of sales-derivative (gain) loss (1)
 
(36,763
)
 
1,969

 
(38,732
)
Cost of sales-other
 
6,257

 
9,769

 
(3,512
)
Operating expenses
 
93,268

 
59,184

 
34,084

General and administrative expenses
 
3,082

 
3,762

 
(680
)
Depreciation and amortization expense
 
73,618

 
55,105

 
18,513

Loss on disposal or impairment of assets, net
 
7,504

 
2,994

 
4,510

Revaluation of liabilities
 
(12,264
)
 
—

 
(12,264
)
Total expenses
 
134,702

 
132,783

 
1,919

Segment operating income
 
$
65,340

 
$
10,317

 
$
55,023

 
 
 
 
 
 
 
Water received (barrels)
 
161,664

 
75,451

 
86,213

Service fee for water processed ($/barrel)
 
$
0.65

 
$
0.77

 
$
(0.12
)
Recovered hydrocarbons for water processed ($/barrel)
 
$
0.51

 
$
0.90

 
$
(0.39
)
 
(1)
Includes realized and unrealized (gains) losses.

The following tables summarize activity separated between the following categories:

•
facilities we owned before March 31, 2013, which we refer to below as “existing facilities” and
•
facilities we acquired or developed after March 31, 2013, which we refer to below as “recently acquired or developed facilities”.


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Service Fee Revenues. The following table summarizes our service fee revenues (in thousands, except per barrel amounts) for the periods indicated:
 
 
Year Ended March 31,
 
 
2015
 
2014
 
 
Service
Fees
 
Water Barrels Processed
 
Fees Per 
Water Barrel
Processed
 
Service
Fees
 
Water Barrels Processed
 
Fees Per 
Water Barrel
Processed
Existing facilities
 
$
65,541

 
85,560

 
$
0.77

 
$
51,908

 
59,305

 
$
0.88

Recently acquired or developed facilities
 
40,141

 
76,104

 
0.53

 
6,253

 
16,146

 
0.39

Total
 
$
105,682

 
161,664

 
0.65

 
$
58,161

 
75,451

 
0.77


The increase in the volume processed at our existing facilities was due primarily to increased demand from customers. Also, the average revenue per barrel varies across the areas in which we operate due to market conditions in these areas. Per-barrel revenues are highest at our facility in Wyoming due to the nature of the services required. The majority of the recently acquired facilities are in Texas, where market rates for disposal are lower.

Recovered Hydrocarbon Revenues. The following table summarizes our recovered hydrocarbon revenues (in thousands, except per barrel amounts) for the periods indicated:
 
 
Year Ended March 31,
 
 
2015
 
2014
 
 
Recovered
Hydrocarbon
Revenue
 
Water Barrels Processed
 
Revenue Per 
Water Barrel
Processed
 
Recovered
Hydrocarbon
Revenue
 
Water Barrels Processed
 
Revenue Per 
Water Barrel
Processed
Existing facilities
 
$
36,361

 
85,560

 
$
0.42

 
$
40,393

 
59,305

 
$
0.68

Recently acquired or developed facilities
 
45,401

 
76,104

 
0.60

 
27,234

 
16,146

 
1.69

Total
 
$
81,762

 
161,664

 
0.51

 
$
67,627

 
75,451

 
0.90


The decrease in revenue per barrel associated with recovered hydrocarbons was due primarily to the sharp decline in crude oil prices since July 2014.

Water Transportation Revenues. The decrease resulted from the sale of our water transportation business during September 2014.

Cost of Sales. We enter into derivatives in our water solutions segment to protect against the risk of a decline in the market price of the hydrocarbons we expected to recover when processing the wastewater. Our cost of sales during the year ended March 31, 2015 included $2.8 million of net unrealized gains on derivatives and $34.0 million of net realized gains on derivatives. Our cost of sales during the year ended March 31, 2014 included $0.6 million of net unrealized losses on derivatives and $1.4 million of net realized losses on derivatives. In December 2014, we settled derivative contracts that had scheduled settlement dates from April 2015 through September 2015, in order to lock in the gains on those derivatives.

The decrease in other cost of sales resulted from the sale of our water transportation business during September 2014.

Operating Expenses. The following table summarizes our operating expenses for the periods indicated:
 
 
Year Ended March 31,
 
 
 
 
2015
 
2014
 
Change
 
 
(in thousands)
Existing facilities
 
$
41,167

 
$
36,381

 
$
4,786

Recently acquired or developed facilities
 
52,101

 
22,803

 
29,298

Total
 
$
93,268

 
$
59,184

 
$
34,084


The increase in operating expenses for existing facilities was due primarily to increased costs associated with the construction and operation of new water disposal wells at existing facilities.

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Depreciation and Amortization Expense. Of this increase, $15.0 million related to acquisitions, which included $1.3 million of amortization expense related to trade name intangible assets. The remaining increase was due primarily to $1.8 million of amortization expense related to trade name intangible assets. During the fourth quarter of the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2015, we sold our water transportation business and recorded a loss of $4.0 million. Also, during the year ended March 31, 2015, we recorded a loss on abandonment of $3.1 million related to property, plant and equipment of water disposal facilities that we have retired. During the year ended March 31, 2014, we recorded losses on disposal of property, plant and equipment of $2.0 million as a result of property damage from lightning strikes at two of our facilities.

Revaluation of Liabilities. The revaluation of liabilities represents the valuation adjustment of contingent consideration liabilities related to royalty agreements acquired as part of certain business combinations during the year ended March 31, 2015.

Liquids

The following table summarizes the operating results of our liquids segment for the periods indicated:
 
 
Year Ended March 31,
 
 
 
 
2015
 
2014
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues (1)
 
$
1,265,262

 
$
1,632,948

 
$
(367,686
)
Cost of sales
 
1,217,993

 
1,559,266

 
(341,273
)
Product margin
 
47,269

 
73,682

 
(26,413
)
 
 
 
 
 
 
 
Other product sales:
 
 
 
 
 
 
Revenues (1)
 
1,111,834

 
1,231,965

 
(120,131
)
Cost of sales
 
1,038,324

 
1,179,944

 
(141,620
)
Product margin
 
73,510

 
52,021

 
21,489

 
 
 
 
 
 
 
Other revenues:
 
 
 
 
 
 
Revenues (1)
 
28,745

 
31,062

 
(2,317
)
Cost of sales
 
17,313

 
24,439

 
(7,126
)
Product margin
 
11,432

 
6,623

 
4,809

 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
35,580

 
37,672

 
(2,092
)
General and administrative expenses
 
8,271

 
6,443

 
1,828

Depreciation and amortization expense
 
13,513

 
11,018

 
2,495

Loss on disposal or impairment of assets, net
 
29,775

 
5,305

 
24,470

Total expenses
 
87,139

 
60,438

 
26,701

Segment operating income
 
$
45,072

 
$
71,888

 
$
(26,816
)
 
 
 
 
 
 
 
Propane sold (gallon)
 
1,285,707

 
1,190,106

 
95,601

Propane sold ($/gallon)
 
$
0.984

 
$
1.372

 
$
(0.388
)
Cost per propane sold ($/gallon)
 
$
0.947

 
$
1.310

 
$
(0.363
)
Propane product margin ($/gallon)
 
$
0.037

 
$
0.062

 
$
(0.025
)
 
 
 
 
 
 
 
Other products sold (gallon)
 
825,514

 
786,671

 
38,843

Other products sold ($/gallon)
 
$
1.347

 
$
1.566

 
$
(0.219
)
Cost per other products sold ($/gallon)
 
$
1.258

 
$
1.500

 
$
(0.242
)
Other products product margin ($/gallon)
 
$
0.089

 
$
0.066

 
$
0.023


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(1)
Revenues include $162.0 million and $245.6 million of intersegment sales during the years ended March 31, 2015 and 2014, respectively, that are eliminated in our consolidated statements of operations.

Propane Sales. The increase in the volume sold from the year ended March 31, 2014 to the year ended March 31, 2015 was due primarily to the inclusion of the natural gas liquids operations acquired from Gavilon Energy for a full fiscal year (compared to only four months of the prior fiscal year) and to the expansion of an agreement under which we market the majority of the production from a fractionation facility.

Our cost of wholesale propane sales during the year ended March 31, 2015 was increased by $4.6 million of net unrealized losses on derivatives. Our cost of wholesale propane sales during the year ended March 31, 2014 was increased by $1.6 million of net unrealized losses on derivatives.

Product margins per gallon of propane sold were lower during the year ended March 31, 2015 than during the prior year. Although we sold a higher volume of propane during the year ended March 31, 2015 than during the prior year, product margins were narrower. During the winter season of the year ended March 31, 2014, the price of propane increased as a result of high demand due to cold weather conditions. During the winter season of the year ended March 31, 2015, propane prices decreased, due primarily to a decline in the price of crude oil. Our product margins are typically higher during periods of rising prices, due to the delay between when we purchase product and when we sell it. We utilize forward contracts and financial derivatives to hedge a portion, but not all, of the price risk associated with holding inventory. In addition, cost of sales during the year ended March 31, 2015 were increased by $4.6 million of net unrealized losses on derivatives, compared to $1.6 million of net unrealized losses on derivatives during the year ended March 31, 2014.

Other Products Sales. Our cost of sales of other products during the year ended March 31, 2015 was reduced by $1.7 million of net unrealized gains on derivatives. Our cost of sales of other products during the year ended March 31, 2014 was reduced by $5.8 million of net unrealized gains on derivatives.

Operating Expenses. This decrease was due primarily to lower compensation expense, $5.0 million of which resulted from a shift in the recording of incentive compensation expense related to bonuses from the liquids segment to “corporate and other” during the year ended March 31, 2015. See further discussion within the “Corporate and Other” section below.

General and Administrative Expenses. This increase was due primarily to expanded operations.

Loss on Disposal or Impairment of Assets, Net. During the year ended March 31, 2015, we recorded a loss on disposal of assets of $29.9 million related to the sale of a natural gas liquids terminal. During the year ended March 31, 2014, we recorded an impairment of $5.3 million to the value of the property, plant and equipment of another natural gas liquids terminal.


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Retail Propane

The following table summarizes the operating results of our retail propane segment for the periods indicated:
 
 
Year Ended March 31,
 
 
 
 
2015
 
2014
 
Change
 
 
(in thousands, except per gallon amounts)
Propane sales:
 
 
 
 
 
 
Revenues
 
$
347,575

 
$
388,225

 
$
(40,650
)
Cost of sales
 
181,655

 
233,110

 
(51,455
)
Product margin
 
165,920

 
155,115

 
10,805

 
 
 
 
 
 
 
Distillate sales:
 
 
 
 
 
 
Revenues
 
106,037

 
127,672

 
(21,635
)
Cost of sales
 
85,329

 
109,058

 
(23,729
)
Product margin
 
20,708

 
18,614

 
2,094

 
 
 
 
 
 
 
Other product sales:
 
 
 
 
 
 
Revenues
 
35,585

 
35,918

 
(333
)
Cost of sales
 
11,554

 
11,531

 
23

Product margin
 
24,031

 
24,387

 
(356
)
 
 
 
 
 
 
 
Expenses:
 
 
 
 
 
 
Operating expenses
 
102,123

 
96,936

 
5,187

General and administrative expenses
 
12,352

 
11,017

 
1,335

Depreciation and amortization expense
 
31,827

 
28,878

 
2,949

Loss on disposal or impairment of assets, net
 
282

 
—

 
282

Total expenses
 
146,584

 
136,831

 
9,753

Segment operating income
 
$
64,075

 
$
61,285

 
$
2,790

 
 
 
 
 
 
 
Propane sold (gallons)
 
169,279

 
162,361

 
6,918

Propane sold ($/gallon)
 
$
2.053

 
$
2.391

 
$
(0.338
)
Cost per propane sold ($/gallon)
 
$
1.073

 
$
1.436

 
$
(0.363
)
Propane product margin ($/gallon)
 
$
0.980

 
$
0.955

 
$
0.025

 
 
 
 
 
 
 
Distillates sold (gallons)
 
34,862

 
34,965

 
(103
)
Distillates sold ($/gallon)
 
$
3.042

 
$
3.651

 
$
(0.609
)
Cost per distillates sold ($/gallon)
 
$
2.448

 
$
3.119

 
$
(0.671
)
Distillates product margin ($/gallon)
 
$
0.594

 
$
0.532

 
$
0.062


Revenues. Our retail propane revenues decreased due to the lower demand as the weather conditions were warmer in some markets in the winter of the year ended March 31, 2015 compared to the winter of the prior year. This was partially offset by an increase in volume sold due in part of the growth of our business through acquisitions.

Cost of Sales. Our retail propane segment cost of sales decreased due to the decline in commodity prices.

Operating Expenses. The increase was due primarily to increased compensation expense resulting from the growth of the business.

General and Administrative Expenses. Our retail propane segment incurred $12.4 million of general and administrative expenses during the year ended March 31, 2015, compared to $11.0 million of general and administrative expenses during the year ended March 31, 2014.


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Refined Products and Renewables

The following table summarizes the operating results of our refined products and renewables segment for the periods indicated. Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and significantly expanded with our July 2014 acquisition of TransMontaigne.
 
Year Ended March 31,
 
 
 
2015
 
2014
 
Change
 
(in thousands, except per barrel and gallon amounts)
Refined products sales:
 
 
 
 
 
Revenues (1)
$
6,682,040

 
$
1,180,895

 
$
5,501,145

Cost of sales
6,574,545

 
1,172,754

 
5,401,791

Product margin
107,495

 
8,141

 
99,354

 
 
 
 
 
 
Renewables sales:
 
 
 
 
 
Revenues
473,885

 
176,781

 
297,104

Cost of sales
461,996

 
171,422

 
290,574

Product margin
11,889

 
5,359

 
6,530

 
 
 
 
 
 
Service fee revenues
76,847

 
—

 
76,847

 
 
 
 
 
 
Expenses:
 
 
 
 
 
Operating expenses
82,583

 
6,205

 
76,378

General and administrative expenses
26,133

 
156

 
25,977

Depreciation and amortization expense
32,948

 
625

 
32,323

Total expenses
141,664

 
6,986

 
134,678

Segment operating income
$
54,567

 
$
6,514

 
$
48,053

 
 
 
 
 
 
Refined products sold (barrels)
68,043

 
9,833

 
58,210

Refined products sold ($/barrel)
$
98.203

 
$
120.095

 
$
(21.892
)
Cost per refined products sold ($/barrel)
$
96.623

 
$
119.267

 
$
(22.644
)
Refined products product margin ($/barrel)
$
1.580

 
$
0.828

 
$
0.752

Refined products product margin ($/gallon)
$
0.038

 
$
0.020

 
$
0.018

 
 
 
 
 
 
Renewable products sold (barrels)
5,318

 
3,593

 
1,725

Renewable products sold ($/barrel)
$
89.110

 
$
49.202

 
$
39.908

Cost per renewable products sold ($/barrel)
$
86.874

 
$
47.710

 
$
39.164

Renewable products product margin ($/barrel)
$
2.236

 
$
1.492

 
$
0.744

Renewable products product margin ($/gallon)
$
0.053

 
$
0.036

 
$
0.017

 
(1)
Revenues include $1.1 million of intersegment sales during the year ended March 31, 2015 that are eliminated in our consolidated statement of operations.

Refined Products Revenues. Of the refined products revenues during the year ended March 31, 2015, $3.7 billion was attributable to TransMontaigne.

Refined Products Cost of Sales. Of the refined products cost of sales during the year ended March 31, 2015, $3.6 billion was attributable to TransMontaigne.

Renewables Sales. During December 2014, a federal law was passed that enabled us to claim certain biodiesel tax credits for transactions during calendar year 2014. During the year ended March 31, 2015, our cost of sales was reduced by $5.8 million related to these tax credits.

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Service Fee Revenues. Of the service fee revenues during the year ended March 31, 2015, $76.8 million was attributable to TLP.

Operating Expenses. Of the operating expenses during the year ended March 31, 2015, $77.1 million was attributable to TransMontaigne (including TLP).

General and Administrative Expenses. General and administrative expenses during the year ended March 31, 2015 were increased by $8.0 million of compensation expense related to termination benefits for certain TransMontaigne employees. Of the general and administrative expenses during the year ended March 31, 2015, $19.2 million was attributable to TransMontaigne (including TLP).

Depreciation and Amortization Expense. The increase was due primarily to depreciation on TLP’s terminal assets and amortization of customer relationship intangible assets acquired in the business combination with TransMontaigne. Of the depreciation and amortization expense during the year ended March 31, 2015, $30.3 million was attributable to TransMontaigne (including TLP).

Corporate and Other

The operating loss within “corporate and other” includes the following components for the periods indicated:
 
 
Year Ended March 31,
 
 
 
 
2015
 
2014
 
Change
 
 
(in thousands)
Compressor leasing business (1)
 
$
133

 
$
2,336

 
$
(2,203
)
Natural gas business (2)
 
(262
)
 
1,363

 
(1,625
)
Equity-based compensation expense
 
(32,767
)
 
(17,804
)
 
(14,963
)
Acquisition expense
 
(7,382
)
 
(6,908
)
 
(474
)
Other corporate expenses
 
(45,524
)
 
(23,104
)
 
(22,420
)
Total
 
$
(85,802
)
 
$
(44,117
)
 
$
(41,685
)
 
(1)
Operating income of our compressor leasing business during the year ended March 31, 2014 includes a $4.4 million gain from the sale of the business in February 2014.
(2)
We acquired the natural gas business in our December 2013 acquisition of Gavilon Energy. We subsequently wound down the natural gas business and, as of March 31, 2014, this business has no revenue-generating activity.

The increase in equity-based compensation expense during the year ended March 31, 2015 was due primarily to $10.6 million of expense associated with restricted units granted in July 2014 to certain employees as a bonus that vested in September 2014, $5.0 million of compensation expense otherwise payable in cash to employees of our liquids segment that was instead paid in common units, and an increase in the number of unvested restricted units outstanding resulting from the growth of the business. The impact of these factors was partially offset by the fact that the market value of our common units was lower at March 31, 2015 than at March 31, 2014.

The expenses shown in the table above for acquisitions relate primarily to legal and advisory costs. Acquisition expenses during the year ended March 31, 2015 related primarily to the acquisitions of TransMontaigne and Sawtooth. Acquisition expenses during the year ended March 31, 2014 related primarily to the acquisition of Gavilon Energy.

The increase in other corporate expenses during the year ended March 31, 2015 was due primarily to an increase in compensation expense, due to the addition of new corporate employees to provide general and administrative services in support of the growth of our business. In addition, during January 2015, we reached an agreement with certain employees whereby certain bonus commitments otherwise payable in cash subsequent to our fiscal year end would instead be paid using our common units. Other corporate expenses during the year ended March 31, 2015 include $10.0 million of this bonus expense, which, if paid in cash, would have been reflected in expenses of the crude oil logistics, liquids, and refined products and renewables segments.


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Operating loss during the years ended March 31, 2015 and 2014 was increased by $0.4 million and $2.0 million, respectively, of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses were paid in December 2014. This amount is reported within “other corporate expenses” in the table above.

 
Equity in Earnings of Unconsolidated Entities

Equity in earnings of unconsolidated entities was $12.1 million and $1.9 million during the years ended March 31, 2015 and 2014, respectively. The increase was due primarily to an increase of $5.5 million of earnings from BOSTCO and Frontera that we acquired as part of our July 2014 acquisition of TransMontaigne, and an increase of $4.7 million of earnings from Glass Mountain and an ethanol production facility that we acquired as part of our December 2013 acquisition of Gavilon Energy.

Interest Expense

Interest expense was $110.1 million and $58.9 million during the years ended March 31, 2015 and 2014, respectively. The increase in interest expense was due primarily to (i) the increased level of debt outstanding on our Revolving Credit Facility (the average balance outstanding on our Revolving Credit Facility was $1.2 billion during the year ended March 31, 2015, compared to $0.6 billion during year ended March 31, 2014), primarily to finance acquisitions and capital expenditures; (ii) the issuance of $450.0 million of fixed-rate notes during October 2013, which bear a higher interest rate than our Revolving Credit Facility; and (iii) increased interest expense related to TLP’s credit facility (our interest in TLP was acquired in July 2014).

Other Income, Net

The following table summarizes the components of other income, net for the periods indicated:
 
Year Ended March 31,
 
2015
 
2014
 
(in thousands)
Interest income (1)
$
4,575

 
$
1,365

Crude oil marketing arrangement (2)
(5,642
)
 
(1,064
)
Crude oil rail transloading facility (3)
31,600

 
—

Other (4)
6,638

 
(215
)
Other income, net
$
37,171

 
$
86

 
(1)
Relates primarily to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party and to a loan receivable from an equity method investee.
(2)
Represents another party’s share of the profits generated from a joint crude oil marketing arrangement.
(3)
In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent to 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 and additional cash payments over the next five years. In addition, one of the producers committed to pay us a specified fee on each barrel of crude oil it produces in a specified basin over a period of seven years. Upon execution of these agreements in March 2015, we recorded a gain of $31.6 million to other income, net of certain project abandonment costs.
(4)
During the year ended March 31, 2015, we settled two separate contractual disputes and recorded $5.5 million of proceeds to other income. Also during the year ended March 31, 2015, we offered to settle another contractual dispute, and recorded $1.2 million to other expense as an estimate of the probable loss.

Income Tax Expense (Benefit)

Income tax benefit was $3.6 million during the year ended March 31, 2015, compared to $0.9 million of income tax expense during the year ended March 31, 2014. The income tax benefit was due primarily to a benefit of $6.3 million related to the July 2014 acquisition of TransMontaigne, as TransMontaigne was subject to United States federal and state income taxes. On December 30, 2014, we converted TransMontaigne from a taxable entity to a non-taxable entity.

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Noncontrolling Interests

Net income attributable to noncontrolling interests was $12.9 million and $1.1 million during the years ended March 31, 2015 and 2014, respectively. The increase was due primarily to the July 2014 acquisition of TransMontaigne, in which we acquired the 2% general partner interest and a 19.7% limited partner interest in TLP.

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. See Note 8 to our consolidated financial statements included in this Annual Report for a detailed description of our long-term debt. Our cash flows from operations are discussed below.

Our borrowing needs vary during the year due in part to the seasonal nature of our liquids business. Our greatest working capital borrowing needs generally occur during the period of June through December, when we are building our natural gas liquids inventories in anticipation of the heating season. Our working capital borrowing needs generally decline during the period of January through March, when the cash flows from our retail propane and liquids segments are the greatest.

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership 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, less the 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 of our 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 next four quarters.

We believe that our anticipated cash flows from operations and the borrowing capacity under our Revolving Credit Facility are sufficient to meet our 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. Our ability to raise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances that we can raise additional capital to meet these needs (see Part I, Item 1A–“Risk Factors”). Commitments or expenditures, if any, we may make toward any acquisition projects are at our discretion.

We have historically pursued a strategy of growth through acquisitions. Under current market conditions, the cost of capital is much higher than it has been in recent years; prospective lenders seek much higher interest rates than they have sought in the past, and at our prior distribution level of $0.64 per common unit, the yield on our common units was much higher than it had been in the past. In April 2016, the board of directors of our general partner decided to reduce our distribution level from $0.64 per common unit to $0.39 per common unit, which it anticipates will continue for three additional quarters under current market conditions. We expect the reduction in the distribution to provide us with approximately $170 million of annual cash savings to enhance liquidity, repay indebtedness and/or invest in selected growth projects.

Under current market conditions, we are much less likely to pursue acquisitions than we have been in the past. We continue to undertake certain capital expansion projects, including the funding of our portion of the construction of the Joint Pipeline, our assets that will be connected to the Joint Pipeline and the continued development of Sawtooth natural gas liquids storage caverns, among others. We expect to be able to finance these projects through available capacity on our Revolving Credit Facility, asset sales or other forms of financing.

Other sources of liquidity during the three months ended March 31, 2016 and the month of April 2016 are discussed below.

Sale of General Partner Interest in TLP

On February 1, 2016, we completed the sale of our general partner interest in TLP to an affiliate of ArcLight for $350 million in cash.

Sale of TLP Common Units

On April 1, 2016, we sold all of the TLP common units we owned to ArcLight for approximately $112.4 million in cash.


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Class A Convertible Preferred Units

On April 21, 2016, we entered into an agreement to issue $200 million of Preferred Units to Oaktree. Oaktree may acquire 16.6 million Preferred Units at a price of $12.03 per unit as well as 3.6 million warrants, which are subject to certain vesting and exercise terms. We expect to use the net proceeds from the issuance of the Preferred Units to repay borrowings outstanding on our Revolving Credit Facility (as hereinafter defined), which may be re-borrowed in the future to fund capital expenditures and for other general partnership purposes. The first closing of this transaction occurred on May 11, 2016 and we received gross proceeds of $100 million. We expect the second closing to occur prior to June 30, 2016.

Long-Term Debt

Credit Agreement

We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit 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”). At March 31, 2016, our Revolving Credit Facility had a total capacity of $2.484 billion. Our Revolving Credit Facility has an “accordion” feature that allows us to increase the capacity by $150 million if new lenders wish to join the syndicate or if current lenders wish to increase their commitments.

The Expansion Capital Facility had a total capacity of $1.446 billion for cash borrowings at March 31, 2016. At that date, we had outstanding borrowings of $1.230 billion on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.038 billion for cash borrowings and letters of credit at March 31, 2016. At that date, we had outstanding borrowings of $618.5 million and outstanding letters of credit of $45.4 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our consolidated balance sheets, although they decrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base” (as defined in the Credit Agreement), which is calculated based on the value of certain working capital items at any point in time.

The commitments under the Credit Agreement expire on November 5, 2018. We have the right to prepay outstanding borrowings under the Credit Agreement without incurring any penalties, and prepayments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

The Credit Agreement is secured by substantially all of our assets. In December 2015, we entered into an agreement with the banks to increase our maximum leverage ratio to 4.75 to 1 at any quarter end. At March 31, 2016, our leverage ratio was approximately 3.9 to 1. The Credit Agreement also specifies that our interest coverage ratio (as defined in the Credit Agreement) cannot be less than 2.75 to 1 at any quarter end. At March 31, 2016, our interest coverage ratio was approximately 5.3 to 1.

At March 31, 2016, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”) in a private placement exempt from registration under the Securities Act of 1933, as amended (the “Securities Act”), pursuant to Rule 144A and Regulation S under the Securities Act. During the fourth quarter of fiscal year 2016, we repurchased $11.5 million of our 2019 Notes for an aggregate purchase price of $7.0 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2019 Notes of $4.5 million (net of the write off of debt issuance costs of $0.1 million)

The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes before the maturity date, although we would be required to pay a premium for early redemption.

At March 31, 2016, we were in compliance with the covenants under the indenture governing the 2019 Notes.

2021 Notes

On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”) in a private placement exempt from registration under the Securities Act pursuant to Rule 144A and Regulation S under the Securities Act. During the fourth quarter of fiscal year 2016, we repurchased $61.7 million of our 2021 Notes for an aggregate purchase price

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of $36.4 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2021 Notes of $24.0 million (net of the write off of debt issuance costs of $1.2 million)
 
The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes before the maturity date, although we would be required to pay a premium for early redemption.

At March 31, 2016, we were in compliance with the covenants under the indenture governing the 2021 Notes.

2022 Notes

On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the “Note Purchase Agreement”) whereby we issued $250.0 million of Senior Notes in a private placement (the “2022 Notes”). The 2022 Notes bear interest at a fixed rate of 6.65%, which is payable quarterly. In December 2015, we amended the Note Purchase Agreement to change the covenants to mirror the changes made to the covenants in our Credit Agreement. In addition, we agreed to pay an additional 0.5% per year in interest if our leverage ratio exceeds 4.50 to 1. The 2022 Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

At March 31, 2016, we were in compliance with the covenants under the Note Purchase Agreement.

For a further discussion of our Revolving Credit Facility and Senior Notes, see Note 8 to our consolidated financial statements included in this Annual Report.

Revolving Credit Balances

The following table summarizes our Revolving Credit Facility borrowings:
 
 
Average Balance
Outstanding
 
Lowest
Balance
 
Highest
Balance
 
 
(in thousands)
Year Ended March 31, 2016:
 
 
 
 
 
 
Expansion capital borrowings
 
$
1,067,549

 
$
739,500

 
$
1,380,000

Working capital borrowings
 
640,928

 
469,000

 
756,000

Year Ended March 31, 2015:
 
 
 
 
 
 
Expansion capital borrowings
 
$
435,752

 
$
114,000

 
$
830,000

Working capital borrowings
 
736,677

 
339,500

 
1,046,000

TLP credit facility borrowings
(from July 1, 2014 through March 31, 2015)
 
250,346

 
228,000

 
259,700


Capital Expenditures

The following table summarizes expansion and maintenance capital expenditures for the periods indicated. This information has been prepared on the accrual basis, and excludes property, plant and equipment acquired in acquisitions.
 
 
Capital Expenditures
Year Ended March 31,
 
Expansion (1)
 
Maintenance (2)
 
Total
 
 
(in thousands)
2016
 
$
613,598

 
42,001

 
$
655,599

2015
 
169,207

 
40,746

 
209,953

2014
 
132,948

 
32,200

 
165,148


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(1)
Includes expansion capital expenditures for TLP of $13.6 million and $3.7 million during the years ended March 31, 2016 and 2015, respectively.
(2)
Includes maintenance capital expenditures for TLP of $11.6 million and $9.8 million during the years ended March 31, 2016 and 2015, respectively.

We currently expect our growth capital expenditures for fiscal year 2017 to be between $200 million and $300 million.

Acquisitions

Subsequent to our IPO, we significantly expanded our operations through numerous acquisitions, as described under Part I, Item 1–“Business–Acquisitions.”

Cash Flows

The following table summarizes the sources (uses) of our cash flows for the periods indicated: 
 
 
Year Ended March 31,
Cash Flows Provided by (Used in):
 
2016
 
2015
 
2014
 
 
(in thousands)
Operating activities, before changes in operating assets and liabilities
 
$
226,881

 
$
107,599

 
$
243,576

Changes in operating assets and liabilities
 
124,614

 
154,792

 
(158,340
)
Operating activities
 
$
351,495

 
$
262,391

 
$
85,236

Investing activities
 
(445,327
)
 
(1,366,221
)
 
(1,455,373
)
Financing activities
 
80,705

 
1,134,693

 
1,369,016


Operating 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, and decreases in natural gas liquids prices typically increase our operating cash flows due to lower cash requirements to fund increases in inventories.

In general, our operating cash flows are at their lowest levels during our first and second fiscal quarters, or the six months ending September 30, when we experience operating losses or lower operating income as a result of lower volumes of natural gas liquids sales and when we are building our inventory levels for the upcoming heating season. Our operating cash flows are generally greatest during our third and fourth fiscal quarters, or the six months ending March 31, when our operating income levels are highest and customers pay for natural gas liquids consumed during the heating season months. We borrow under our Revolving Credit Facility to supplement our operating cash flows as necessary during our first and second fiscal quarters.

Investing Activities. Net cash used in investing activities was $445.3 million and $1.4 billion during the years ended March 31, 2016 and 2015, respectively. The decrease in net cash used in investing activities was due primarily to:

•
a $726.3 million decrease in cash paid for acquisitions during the year ended March 31, 2016 as cash paid for acquisitions during the year ended March 31, 2015 included $580.7 million for the acquisition of TransMontaigne;
•
a $343.1 million increase due to proceeds received from the sale of the general partner interest in TLP during the year ended March 31, 2016;
•
a $310.0 million decrease for the purchase of the remaining equity interest in Grand Mesa during the year ended March 31, 2015;
•
a $59.6 million decrease related to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party; and
•
a $24.2 million decrease for the purchase of certain refined product pipeline capacity allocations from other shippers during the year ended March 31, 2015.


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These decreases in net cash used in investing activities were partially offset by:

•
an increase in capital expenditures from $203.8 million during the year ended March 31, 2015, $163.0 million of which was expansion capital (of this expansion capital, $3.7 million related to TLP) and $40.8 million of which was maintenance capital (of this maintenance capital, $9.8 million related to TLP), to $536.9 million during the year ended March 31, 2016, $494.9 million of which was expansion capital (of this expansion capital, $13.6 million related to TLP) and $42.0 million of which was maintenance capital (of this maintenance capital, $11.6 million related to TLP);
•
a $125.0 million increase due to the purchase of a 37.5% undivided interest in a crude oil pipeline from Colorado to Oklahoma (see “Recent Developments” above) during the year ended March 31, 2016; and
•
a $93.5 million decrease in cash flows from derivatives.

Net cash used in investing activities was $1.4 billion and $1.5 billion during the years ended March 31, 2015 and 2014, respectively. The decrease in net cash used in investing activities was due primarily to:

•
a $307.9 million decrease in cash paid for acquisitions during the year ended March 31, 2015; and
•
a $235.1 million increase in cash flows from derivatives.

These decreases in net cash used in investing activities were partially offset by:

•
a $310.0 million increase for the purchase of the remaining equity interest in Grand Mesa during the year ended March 31, 2015;
•
a $61.9 million increase related to a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party;
•
an increase in capital expenditures from $165.1 million during the year ended March 31, 2014, $132.9 million of which was expansion capital and $32.2 million of which was maintenance capital, to $203.8 million during the year ended March 31, 2015, $163.0 million of which was expansion capital (of this expansion capital, $3.7 million related to TLP) and $40.8 million of which was maintenance capital (of this maintenance capital, $9.8 million related to TLP);
•
a $24.2 million increase for the purchase of certain refined product pipeline capacity allocations from other shippers during the year ended March 31, 2015; and
•
a $22.0 million increase in contributions to unconsolidated entities during the year ended March 31, 2015 due primarily to our investment in BOSTCO which we acquired as part of our July 2014 acquisition of TransMontaigne.

Financing Activities. Net cash provided by financing activities was $80.7 million and $1.1 billion during the years ended March 31, 2016 and 2015, respectively. The decrease in net cash provided by financing activities was due primarily to:

•
$541.1 million in proceeds received from the sale of our common units during the year ended March 31, 2015;
•
$400.0 million in proceeds received from the issuance of the 2019 Notes during the year ended March 31, 2015;
•
an $88.0 million increase in distributions paid to our partners and noncontrolling interest owners during the year ended March 31, 2016; and
•
$43.4 million in repurchases of a portion of our senior notes during the fourth quarter of fiscal year 2016.

These decreases in net cash provided by financing activities were partially offset by an increase of $53.2 million in proceeds from other long-term debt due primarily to equipment financing.

Net cash provided by financing activities was $1.1 billion and $1.4 billion during the years ended March 31, 2015 and 2014, respectively. The decrease in net cash provided by financing activities was due primarily to:

•
a $123.8 million increase in distributions paid to our partners and noncontrolling interest owners during the year ended March 31, 2015;

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•
a $109.0 million decrease in the proceeds received from the sale of our common units during the year ended March 31, 2015 as more of our common units were issued during the year ended March 31, 2014 to fund acquisitions; and
•
a $50.0 million decrease in the proceeds received from debt issuances during the years ended March 31, 2015 and 2014.

These decreases in net cash provided by financing activities were partially offset by a $40.0 million increase in borrowings on our revolving credit facilities (net of repayments) to fund our operating or investing requirements during the year ended March 31, 2015. To the extent our cash flows from operating activities are not sufficient to finance our required distributions to our partners and noncontrolling interest owners, we may be required to increase borrowings under our Working Capital Facility.

The following table summarizes distributions declared during the years ended March 31, 2016, 2015 and 2014:
Date Declared
 
Record Date
 
Date Paid
 
Amount
Per Unit
 
Amount Paid To
Limited Partners
 
Amount Paid To
General Partner
 
 
 
 
 
 
 
 
(in thousands)
 
(in thousands)
April 25, 2013
 
May 6, 2013
 
May 15, 2013
 
$
0.4775

 
$
25,605

 
$
1,189

July 25, 2013
 
August 5, 2013
 
August 14, 2013
 
0.4938

 
31,725

 
1,739

October 23, 2013
 
November 4, 2013
 
November 14, 2013
 
0.5113

 
35,908

 
2,491

January 24, 2014
 
February 4, 2014
 
February 14, 2014
 
0.5313

 
42,150

 
4,283

April 24, 2014
 
May 5, 2014
 
May 15, 2014
 
0.5513

 
43,737

 
5,754

July 24, 2014
 
August 4, 2014
 
August 14, 2014
 
0.5888

 
52,036

 
9,481

October 24, 2014
 
November 4, 2014
 
November 14, 2014
 
0.6088

 
53,902

 
11,141

January 26, 2015
 
February 6, 2015
 
February 13, 2015
 
0.6175

 
54,684

 
11,860

April 24, 2015
 
May 5, 2015
 
May 15, 2015
 
0.6250

 
59,651

 
13,446

July 23, 2015
 
August 3, 2015
 
August 14, 2015
 
0.6325

 
66,248

 
15,483

October 22, 2015
 
November 3, 2015
 
November 13, 2015
 
0.6400

 
67,313

 
16,277

January 21, 2016
 
February 3, 2016
 
February 15, 2016
 
0.6400

 
67,310

 
16,279

April 21, 2016
 
May 3, 2016
 
May 13, 2016
 
0.3900

 
40,626

 
70


The following table summarizes distributions declared by TLP after our acquisition of general and limited partner interests in TLP (exclusive of the distribution declared in July 2014, the proceeds of which we remitted to the former owners of TransMontaigne, pursuant to agreements entered into at the time of the business combination. On February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting.
Date Declared
 
Record Date
 
Date Paid
 
Amount
Per Unit
 
Amount Paid 
To NGL
 
Amount Paid To
Noncontrolling
Interest Owners
 
 
 
 
 
 
 
 
(in thousands)
 
(in thousands)
October 13, 2014
 
October 31, 2014
 
November 7, 2014
 
$
0.6650

 
$
4,010

 
$
8,614

January 8, 2015
 
January 30, 2015
 
February 6, 2015
 
0.6650

 
4,010

 
8,614

April 13, 2015
 
April 30, 2015
 
May 7, 2015
 
0.6650

 
4,007

 
8,617

July 13, 2015
 
July 31, 2015
 
August 7, 2015
 
0.6650

 
4,007

 
8,617

October 12, 2015
 
October 30, 2015
 
November 6, 2015
 
0.6650

 
4,007

 
8,617

January 19, 2016
 
January 29, 2016
 
February 8, 2016
 
0.6700

 
4,104

 
8,681


Common Unit Repurchase Program

On September 10, 2015, the Board of Directors of our general partner authorized a common unit repurchase program pursuant to which we could repurchase 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 negotiated transactions. During the year ended March 31, 2016, we repurchased 1,623,804 common units for an aggregate price of $17.7 million.


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Contractual Obligations

The following table summarizes our contractual obligations at March 31, 2016 for our fiscal years ending thereafter:
 
 
 
 
Years Ending March 31,
 
 
 
 
Total
 
2017
 
2018
 
2019
 
2020
 
2021
 
Thereafter
 
 
(in thousands)
Principal payments on long-term debt —
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Expansion capital borrowings
 
$
1,229,500

 
$
—

 
$
—

 
$
1,229,500

 
$
—

 
$
—

 
$
—

Working capital borrowings
 
618,500

 
—

 
—

 
618,500

 
—

 
—

 
—

2019 Notes
 
388,467

 
—

 
—

 
—

 
388,467

 
—

 
—

2021 Notes
 
388,289

 
—

 
—

 
—

 
—

 
—

 
388,289

2022 Notes
 
250,000

 
—

 
25,000

 
50,000

 
50,000

 
50,000

 
75,000

Other long-term debt
 
61,488

 
7,899

 
7,143

 
6,053

 
5,621

 
34,671

 
101

Interest payments on long-term debt —
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Revolving Credit Facility (1)
 
149,937

 
57,668

 
57,668

 
34,601

 
—

 
—

 
—

2019 Notes
 
70,639

 
20,226

 
20,165

 
20,165

 
10,083

 
—

 
—

2021 Notes
 
160,731

 
27,256

 
26,695

 
26,695

 
26,695

 
26,695

 
26,695

2022 Notes
 
66,500

 
16,625

 
16,209

 
13,300

 
9,975

 
6,650

 
3,741

Other long-term debt
 
14,257

 
3,739

 
3,323

 
2,908

 
2,521

 
1,762

 
4

Letters of credit
 
45,418

 
—

 
—

 
45,418

 
—

 
—

 
—

Future minimum lease payments under noncancelable operating leases
 
647,759

 
136,065

 
120,723

 
98,266

 
87,569

 
77,821

 
127,315

Future minimum throughput payments under noncancelable agreements (2)
 
200,734

 
53,024

 
53,042

 
52,250

 
42,418

 
—

 
—

Construction commitments (3)
 
126,800

 
126,800

 
—

 
—

 
—

 
—

 
—

Fixed-price commodity purchase commitments (4)
 
50,249

 
50,047

 
202

 
—

 
—

 
—

 
—

Index-price commodity purchase commitments (5)
 
883,908

 
685,092

 
92,891

 
73,928

 
31,997

 
—

 
—

Total contractual obligations
 
$
5,353,176

 
$
1,184,441

 
$
423,061

 
$
2,271,584

 
$
655,346

 
$
197,599

 
$
621,145

 
(1)
The estimated interest payments on our Revolving Credit Facility are based on principal and letters of credit outstanding at March 31, 2016. See Note 8 to our consolidated financial statements included in this Annual Report for additional information on our Credit Agreement.
(2)
We have executed noncancelable agreements with crude oil and refined products pipeline operators, which guarantee us minimum monthly 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.
(3)
At March 31, 2016, we had the following construction commitments:
•
As discussed above, in November 2015, we reached an agreement with Saddlehorn to jointly construct, own and operate the Joint Pipeline. At March 31, 2016, our share of the remaining total construction costs for the Joint Pipeline is approximately $39 million. We expect the Joint Pipeline to be operational beginning in the third quarter of fiscal year 2017.
•
As part of the Joint Pipeline project, we will have some assets connected to the Joint Pipeline. At March 31, 2016, the remaining costs for these assets are approximately $80.6 million. We expect these assets to be completed during the third quarter of fiscal year 2017.
•
In February 2015, we acquired Sawtooth, which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage

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capacity of the facility. At March 31, 2016, the remaining costs for this project are $7.2 million. We expect this project to be completed by the end of the second quarter of fiscal year 2017.
(4)    At March 31, 2016, we had the following fixed-price purchase commitments (in thousands):
 
Crude Oil
 
Natural Gas Liquids
 
Value
 
Volume
(in barrels)
 
Value
 
Volume
(in gallons)
2017
$
41,756

 
1,077

 
$
8,291

 
21,574

2018
—

 
—

 
202

 
504

Total
$
41,756

 
1,077

 
$
8,493

 
22,078

(5)    At March 31, 2016, we had the following index-price purchase commitments (in thousands):
 
Crude Oil
 
Natural Gas Liquids
 
Value
 
Volume
(in barrels)
 
Value
 
Volume
(in gallons)
2017
$
319,761

 
9,187

 
$
365,331

 
855,645

2018
92,745

 
2,640

 
146

 
300

2019
73,928

 
1,825

 
—

 
—

2020
31,997

 
1,070

 
—

 
—

Total
$
518,431

 
14,722

 
$
365,477

 
855,945

Index prices are based on a forward price curve at March 31, 2016. A theoretical change of $0.10 per gallon in the underlying commodity price at March 31, 2016 would result in a change of $85.6 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at March 31, 2016 would result in a change of $14.7 million in the value of our index-price crude oil purchase commitments.

Sales Contracts
We have entered into product sales contracts for which we expect the parties to physically settle the inventory in future periods. At March 31, 2016, we had the following sales contract volumes (in thousands):
Natural gas liquids fixed-price (gallons)
 
85,162

Natural gas liquids index-price (gallons)
 
312,198

Crude oil fixed-price (barrels)
 
2,107

Crude oil index-price (barrels)
 
18,754


Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases described in Note 10 to our consolidated financial statements included in this Annual Report.

Environmental Legislation

Please see Part I, Item 1–“Business–Government Regulation–Greenhouse Gas Regulation” for a discussion of proposed environmental legislation and regulations that, if enacted, could result in increased compliance and operating costs. However, at this time we cannot predict the structure or outcome of any future legislation or regulations or the eventual cost we could incur in compliance.

Recent Accounting Pronouncements

For a discussion of recent accounting pronouncements that are applicable to us, see Note 2 to our consolidated financial statements included in this Annual Report.


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Critical Accounting Policies

The preparation of financial statements and related disclosures in conformity with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Partnership’s operations and the use of estimates made by management. We have identified the following accounting policies that are most important to the portrayal of our consolidated financial position and results of operations. The application of these accounting policies, which requires subjective or complex judgments regarding estimates and projected outcomes of future events, and changes in these accounting policies, could have a material effect on our consolidated financial statements.

Revenue Recognition

We record product sales revenues when title to the product transfers to the purchaser, which typically occurs when the purchaser receives the product. We record terminaling, transportation, storage, and service revenues when the service is performed, and we record tank and other rental revenues over the lease term. Several of our terminaling service agreements with throughput customers, allow us to receive the product volume gained resulting from differences between the measurement of product volumes received and distributed at our terminaling facilities. Such differences are due to the inherent variances in measurement devices and methodology. We record revenues for the net proceeds from the sale of the product gained. Revenues for our water solutions segment are recognized when we obtain the wastewater at our treatment and disposal facilities.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our consolidated statements of operations.

We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into at the same time and in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our consolidated balance sheets except for certain contracts that qualify for 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.

We have not designated any financial instruments as hedges for accounting purposes. All changes in the fair value of our commodity derivative instruments that do not qualify as normal purchases and normal sales (whether cash transactions or non-cash mark-to-market adjustments) are reported within cost 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 into such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of 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 master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions.

Impairment of Long-Lived Assets

We evaluate the carrying value of our long-lived assets (property, plant and equipment and amortizable intangible assets) for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value. We compare the carrying value of the long-lived asset to the estimated undiscounted future cash flows

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expected to be generated from that asset. Estimates of future net cash flows include estimating future volumes, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans. If we determine that an asset’s unamortized cost may 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-down of the value and unfavorable change in the useful life of a long-lived assets would increase costs and expenses at that time.

We evaluate equity method investments for impairment when we believe the current fair value may be less than the carrying amount. We record impairments of equity method investments if we believe the decline in value is other than temporary.

Impairment of Goodwill

Goodwill is subject to at least an annual assessment for impairment. We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant. For purposes of goodwill impairment testing, assets are grouped into “reporting units”. A reporting unit is either an operating segment or a component of an operating segment, depending on how similar the components of the operating segment are to each other in terms of operational and economic characteristics. For each reporting unit, we perform a qualitative assessment of relevant events and circumstances about the likelihood of goodwill impairment. If it is deemed more likely than not the fair value of the reporting unit is less than its carrying amount, we calculate the fair value of the reporting unit. Otherwise, further testing is not required. The qualitative assessment is based on reviewing the totality of several factors, including macroeconomic conditions, industry and market considerations, cost factors, overall financial performance, other entity specific events (for example, changes in management) or other events such as selling or disposing of a reporting unit. The determination of a reporting unit’s fair value is predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include (i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins, (ii) long-term growth rates for cash flows beyond the discrete forecast period, (iii) appropriate discount rates and (iv) estimates of the cash flow multiples to apply in estimating the market 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 earnings may 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 exposed to 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 overall market, to determine if a triggering event occurs that would indicate that the fair value of a reporting unit is less than its carrying value.

Asset Retirement Obligations

We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. Our consolidated balance sheet at March 31, 2016 includes a liability of $5.6 million related to asset retirement obligations, which is reported within other noncurrent liabilities. We have contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when the assets are retired. Our liability for asset retirement obligations is discounted to present value. To calculate the liability, we make estimates and assumptions 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 and the occurrence of future events.

In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets. We do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

Depreciation Methods and Estimated Useful Lives of Property, Plant and Equipment

Depreciation expense is the systematic write-off of the cost of our property, plant and equipment, net of residual or salvage value (if any), to the results of operations for the quarterly and annual periods during which the assets are used. We depreciate the majority of our property, plant and equipment using the straight-line method, which results in our recording depreciation expense evenly over the estimated life of the individual asset. The estimate of depreciation expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. When we acquire and place our property, plant and equipment in service, we develop assumptions about the useful economic lives and residual values of such

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assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation expense prospectively. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset, changes in technology that render an asset obsolete, or changes in expected salvage values.

Amortization of Intangible Assets

Amortization expense is the systematic write-off of the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are used. We amortize the majority of these intangible assets using the straight-line method, which results in our recording amortization expense evenly over the estimated life of the individual asset. The estimate of amortization expense requires us to make assumptions regarding the useful economic lives of our assets. When we acquire intangible assets, we develop assumptions about the useful economic lives of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our amortization expense prospectively. Examples of such circumstances include changes in customer attrition rates and changes in laws and regulations that could limit the estimated economic life of an asset.

Tank Bottoms

Tank bottoms, which are product volumes required for the operation of storage tanks, are recorded at historical cost within either noncurrent assets or property, plant and equipment on our consolidated balance sheets. We recover tank bottoms when the storage tanks are removed from service. See Note 2 and Note 5 to our consolidated financial statements included in this Annual Report.

Linefill

We have entered into long-term shipment commitments for specified minimum volumes of crude oil on certain third-party owned pipelines. These agreements require that we maintain a certain minimum amount of crude oil in the pipeline to serve as linefill over the duration of the agreement. We report such linefill at historical cost within other noncurrent assets on our consolidated balance sheets. See Note 2 to our consolidated financial statements included in this Annual Report.

Business Combinations

We record business combinations using the “acquisition method,” in which the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets 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 commodity purchase and sale agreements, storage contracts, and transportation contracts. The excess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination.

Inventories

Our inventories consist primarily of crude oil, natural gas liquids, refined products, ethanol, and biodiesel. The market values of these commodities change 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 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 reporting period. At the end of each fiscal year, we also perform a “lower of cost or market” analysis; if the cost basis 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 recoverable amount. In performing this analysis, we consider fixed-price forward commitments and the opportunity to transfer propane inventory from our wholesale liquids business to our retail propane business to sell the inventory in retail markets. When performing this analysis during interim periods within a fiscal year, 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 future periods. In addition, write-downs at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

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Equity-Based Compensation

Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. 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 the performance of our common units relative to other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”). The awards may also vest in the event of a change in control, at the discretion of the board of directors.

We record the expense for the first tranche of each Service Award on a straight-line basis over the period beginning with the grant date of the awards and ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previous tranche and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distributions.

We record the expense for each of the tranches of the Performance Awards on a straight-line basis over the period beginning with the grant date and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using a Monte Carlo simulation.

We report unvested units as liabilities in our consolidated balance sheets. When units vest and are issued, we record an increase to equity.

Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

A significant portion of our long-term debt is variable-rate debt. Changes in interest rates impact the interest payments of our variable-rate debt but generally do not impact the fair value of the liability. Conversely, changes in interest rates impact the fair value of the fixed-rate debt but do not impact its cash flows.

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31, 2016, we had $1.8 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.94%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $2.3 million, based on borrowings outstanding at March 31, 2016.

Commodity Price and Credit Risk

Our operations are subject to certain business risks, including commodity price risk and credit risk. Commodity price risk is the risk that the market value of crude oil, natural gas liquids, and refined products will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract.

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 master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. At March 31, 2016, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers.

The crude oil, natural gas liquids, and refined products industries are “margin-based” and “cost-plus” businesses in which gross profits depend on the differential of sales prices over supply costs. We have no control over market conditions. As a result, our profitability may be impacted by sudden and significant changes in the price of crude oil, natural gas liquids, and refined products.


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We engage in various types of forward contracts and financial derivative transactions to reduce the effect of price volatility on our product costs, to protect the value of our inventory positions, and to help ensure the availability of product during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes when we have a matching purchase commitment from our wholesale and retail customers. We may experience net unbalanced positions from time to time. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio.

Although we use financial derivative instruments to reduce the market price risk associated with forecasted transactions, we do not account for financial derivative transactions as hedges. We record the changes in fair value of these financial derivative transactions within cost of sales. The following table summarizes the hypothetical impact on the March 31, 2016 fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):
 
Increase
(Decrease)
To Fair Value
Crude oil (crude oil logistics segment)
$
(6,163
)
Crude oil (water solutions segment)
(2,656
)
Propane (liquids segment)
963

Other products (liquids segment)
(296
)
Refined products (refined products and renewables segment)
(24,736
)
Renewables (refined products and renewables segment)
(4,508
)
Canadian dollars (liquids segment)
945


Fair Value

We use observable market values for determining the fair value of our derivative instruments. In cases where actively quoted prices are not available, other external sources are used which incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis.

Item 8.    Financial Statements and Supplementary Data

Our consolidated financial statements beginning on page F-1 of this Annual Report, together with the report of Grant Thornton LLP, our independent registered public accounting firm, are incorporated by reference into this Item 8.

Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A.    Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures, as defined in Rule 13(a)-15(e) 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 the Exchange Act is recorded, processed, summarized and reported within the periods specified in the rules and forms of the Securities and Exchange Commission (“SEC”) and that such information is accumulated and communicated to our management, including the principal executive officer and principal 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 and principal financial officer of our general partner, of the effectiveness of the design and operation of our disclosure controls and procedures as of March 31, 2016. Based on this evaluation, the principal executive officer and principal financial officer of our general partner have concluded that as of March 31, 2016, such disclosure controls and procedures were effective to provide the reasonable assurance described above.


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Management’s Report on Internal Control Over Financial Reporting

The management of our Delaware limited partnership (the “Partnership”) and subsidiaries is responsible for establishing and maintaining adequate internal 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 our management, including the Chief Executive Officer and Chief Financial Officer of our general partner, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in the 2013 Internal Control–Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, or the COSO framework.

Based on our evaluation under the COSO framework, our management concluded that our internal control over financial reporting was effective as of March 31, 2016.

Our internal control over financial reporting as of March 31, 2016 has been audited by Grant Thornton LLP, an independent registered public accounting 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 Reporting

The Partnership had a change in key personnel and controls in the fourth quarter of its 2016 fiscal year. More specifically, the Partnership’s general partner hired a new Chief Accounting Officer and a new Chief Financial Officer. These personnel additions (1) changed the design of the Chief Accounting Officer’s review control over business combination accounting, and (2) added a new and incremental control encompassing the Chief Financial Officer review of business combination accounting for accuracy and the fair value measurements for reasonableness. Both of these internal control modifications began in the fourth quarter of fiscal 2016. Through execution of these controls over the recording of business combinations that occurred in the fourth quarter of fiscal 2016, the Chief Accounting Officer and Chief Financial Officer identified certain contingent consideration liabilities in connection with the fourth quarter 2016 business combinations, and determined that the Partnership had failed to record similar liabilities for contingent consideration related to certain previous business combinations that had occurred prior to the fourth quarter of fiscal year 2016. Such liabilities should have been recorded at the acquisition date and subsequently revalued to estimated fair value at each reporting period with the offset to current earnings. Based on the determination that the Partnership had not properly accounted for these prior acquisitions, management determined that a material weakness in internal control existed through December 31, 2015, specifically related to the identification and review of accounting for assets acquired and liabilities assumed in business combinations. As described above in “Management’s Report on Internal Control Over Financial Reporting”, the Partnership concluded that its internal control over financial reporting was effective as of March 31, 2016 based, in part, on the effectiveness of the changed and new controls implemented in the fourth quarter of fiscal year 2016.

Other than changes that have been described above, there have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)-15(f) of the Exchange Act) during the three months ended March 31, 2016 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B.    Other Information

None.



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PART III

Item 10.    Directors, Executive Officers and Corporate Governance

Board of Directors of our General Partner

NGL Energy Holdings LLC, our general partner, manages our operations and activities on our behalf through its directors and executive officers. Unitholders are not entitled to elect the directors of our general partner or directly or indirectly participate in our management or operations. The NGL Energy GP Investor Group appoints all members to the board of directors of our general partner.

The board of directors of our general partner currently has ten members. The board of directors of our general partner has determined that Mr. Kneale, Mr. Cropper, and Mr. Collingsworth satisfy the New York Stock Exchange (“NYSE”) and SEC independence requirements. The NYSE does not require a listed publicly traded limited partnership like us to have a majority of independent directors on the board of directors of our general 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 and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. Our general partner has no minimum qualifications for director candidates. In general, however, the NGL Energy GP Investor Group reviews and evaluates both incumbent and potential new directors 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 or transportation, 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 partnership matters.

Although our general partner does not have a formal policy in regard to the consideration of diversity in identifying director nominees, qualified candidates for nomination to the board are considered without regard to race, color, religion, gender, ancestry or national origin.


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Directors and Executive Officers

Directors of our general partner are appointed by the NGL Energy GP Investor Group and hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion of, the board of directors of our general partner. The following table summarizes information regarding the current directors of our general partner and our executive officers. 
Name
 
Age
 
Position with NGL Energy Holdings LLC
H. Michael Krimbill
 
62
 
Chief Executive Officer and Director
Robert W. Karlovich III
 
39
 
Chief Financial Officer and Treasurer
James J. Burke
 
60
 
President and Director
Shawn W. Coady
 
54
 
President and Chief Operating Officer, Retail Division and Director
Vincent J. Osterman
 
59
 
President, Eastern Retail Propane Operations and Director
Christopher Beall
 
41
 
Director
James M. Collingsworth
 
61
 
Director
Stephen L. Cropper
 
66
 
Director
Bryan K. Guderian
 
56
 
Director
James C. Kneale
 
64
 
Director
John T. Raymond
 
45
 
Director
Patrick Wade
 
46
 
Director

H. Michael Krimbill. Mr. Krimbill has served as our Chief Executive Officer since October 2010 and as a member of the board of directors of our general 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. Krimbill joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as Vice President and Chief Financial Officer in 1990. Mr. Krimbill was 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 to 2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners, L.P., from 2000 to January 2007, 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 a publicly traded partnership, including substantial expertise in successfully acquiring and integrating propane and midstream businesses. Mr. Krimbill also brings financial expertise to the board, including his prior service as a chief financial officer. Mr. Krimbill’s experience serving on other public company boards is also a valuable asset to our board of directors.

Robert W. Karlovich III. Mr. Karlovich was appointed as our Chief Financial Officer in February 2016. Prior to joining NGL, Mr. Karlovich served as Chief Financial Officer of Targa Pipeline Partners, a subsidiary of Targa Resources Partners, LP, from February 2015 through February 2016, and as Senior Vice President of Commercial and Business Development for Targa Resources Partners LP from November 2015 to February 2016. Mr. Karlovich served in various roles at Atlas Pipeline Partners, L.P. and its subsidiaries (“APL”) from September 2006 to February 2015 when APL merged with Targa Resources Partners, LP. Mr. Karlovich served in various roles at Syntroleum Corporation from February 2004 to September 2006. Prior to that, Mr. Karlovich worked at Arthur Andersen LLP and Grant Thornton LLP. Mr. Karlovich is a certified public accountant.

James J. Burke. Mr. Burke serves as our President and joined the board of directors of our general partner in 2012. Mr. Burke was a co-founder of High Sierra Energy, LP and High Sierra Energy GP, LLC (“High Sierra”) and served as Chairman of the High Sierra board and President and Chief Executive Officer of the High Sierra general partner since September 2010 until NGL’s acquisition of High Sierra in June 2012. From July 2004 to September 2010, Mr. Burke was the Managing Director of High Sierra’s general partner. Mr. Burke, along with three other entrepreneurs, co-founded Petro Source Partners, LP, where he ran six business units throughout the United States and Canada for the company over a 17-year span. Prior to that, Mr. Burke served as Manager of Crude Oil Acquisitions at Asamera Oil (United States) Inc. from 1981 to 1984. Mr. Burke began his career as a Crude Oil Representative at Permian Corporation, where he worked from 1978 to 1981. Mr. Burke also serves as the Managing Director of Impact Energy Services, LLC.


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Mr. Burke brings valuable executive and operational experience in the crude oil marketing business and water solutions business to the board and provides expertise in both acquisitions and organic growth strategies.

Shawn W. Coady. Dr. Coady has served as our President and Chief Operating Officer, Retail Division, since April 2012 and previously served as our Co-President and Chief Operating Officer, Retail Division from October 2010 through April 2012. Dr. Coady has also served as a member of the board of directors of our general partner since its formation in September 2010. Dr. Coady served as an officer of Hicks Oils & Hicksgas, Incorporated (“HOH”), from March 1989 to September 2010 when HOH contributed its propane and propane related assets to Hicksgas LLC, and the membership interests in Hicksgas LLC were contributed to us as part of our formation transactions. Dr. Coady was also the President of Hicksgas Gifford, Inc. from March 1989 until the membership interests in the company were contributed to us as part of our formation transactions. Dr. Coady has served as a director for the National Propane Gas Association since 2004 and as a member of the executive committee of the Illinois Propane Gas Association from 2004 to March 2015.

Dr. Coady brings valuable management and operational experience to the board. Dr. Coady has over 25 years of experience in the retail propane industry, and provides expertise in both acquisition and organic growth strategies. Dr. Coady also provides insight into developments and trends in the propane 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 propane operations 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 of the 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 on the Board of Advisors of the Gaudette Insurance Agency.

With his long tenure as President of the Osterman Associated Companies, Mr. Osterman brings valuable executive and operational experience in the retail propane businesses to the board. Mr. Osterman also provides insight into developments and trends in the propane industry through his leadership roles in industry associations.

Christopher Beall. Mr. Beall has served on the board of directors of our general partner since May 2016. Mr. Beall is a Managing Director and Co-Portfolio Manager of Oaktree Capital Management L.P.’s (“Oaktree”) Infrastructure Investing Strategy. Mr. Beall has over 16 years of experience in direct investments, investment banking and finance. Mr. Beall served as a key investment professional for Highstar Capital for ten years prior to joining Oaktree in 2014 and continues to serve as a Partner of Highstar Capital for certain legal funds not managed by Oaktree. Prior to joining Highstar Capital in 2004, he worked in the Global Natural Resources Group at Lehman Brothers, Inc., and in operations and engineering at Koch Pipeline Company, a natural gas transmission pipeline owned by Koch Industries, Inc. Mr. Beall currently serves on the board of directors of Northstar Transloading, ADS Waste Holding, Inc., Ports America Companies, Wespac Midstream and Amtrak.

Mr. Beall brings considerable experience in the energy business and in financial markets. As a director for other public companies, Mr. Beall also provides cross board experience.

James M. Collingsworth. Mr. Collingsworth has served on the board of directors of our general partner since January 2015. Mr. Collingsworth previously served as a Senior Vice President of the general partner of Enterprise Products Partners L.P. from November 2001 through September 2012. Prior to that, Mr. Collingsworth served as a board member of Texaco Canada Petroleum Inc. from July 1998 to October 2001 and was employed by Texaco from 1991 to 2001 in various management positions, including Senior Vice President of NGL Assets and Business Services from July 1998 to October 2001. Prior to joining 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 Seminole pipelines. 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 midstream and petrochemical industry for more than 40 years.

Stephen L. Cropper. Mr. Cropper joined the board of directors of our general partner in June 2011. Mr. Cropper held various positions during his 25-year career at The Williams Companies, Inc., including serving as the President and Chief Executive Officer of Williams Energy Services, a Williams operating 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 also served as a director of Sunoco Logistics Partners, L.P., NRG Energy, Inc., Berry Petroleum Company, and Rental Car Finance

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Corp., a subsidiary of Dollar Thrifty Automotive Group. Mr. Cropper currently serves on the board of directors of QuikTrip Corporation and Wawa Inc.

Mr. Cropper brings substantial experience in the energy business and in the marketing of energy products to the board. With his significant management and governance experience, Mr. Cropper provides important skills in identifying, assessing and addressing various business issues. As a director for other public companies, Mr. Cropper also provides cross board experience.

Bryan K. Guderian. Mr. Guderian joined the board of directors of our general partner in May 2012. Mr. Guderian has served as Senior Vice President of Business Development of WPX Energy, Inc. (“WPX”) since October 2014. Mr. Guderian served as Senior Vice President of Operations of WPX from August 2011 to October 2014. Mr. Guderian previously served as Vice President of the Exploration & Production unit of The Williams Companies, Inc. from 1998 until August 2011, where he had responsibility for overseeing international operations. Mr. Guderian has served as a director of Apco Oil & Gas International Inc., since 2002 and as a director of Petrolera Entre Lomas S.A. since 2003.

Mr. Guderian brings considerable upstream experience to the board including executive, operational and financial expertise from 30 years of petroleum 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 Operating Officer 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 liquids gas industry in numerous positions, Mr. Kneale provides valuable insight into our business and industry.

John T. Raymond. Mr. Raymond joined the board of directors of our general partner in August 2013. Mr. Raymond is the Founder and Majority Owner of The Energy & Minerals Group (“EMG”) of which he has been a Managing Partner and the Chief Executive Officer since its September 2006 inception. Mr. Raymond has held executive leadership positions with various energy companies, including President and Chief Executive Officer of Plains Resources Inc. (the predecessor entity of Vulcan Energy Corporation), President and Chief Operating Officer of Plains Exploration and Production Company and was a Director of Plains All American Pipeline, LP.

Mr. Raymond also currently serves a director of American Energy Ohio Holdings, LLC, Ferus Inc., Ferus Natural Gas Fuels Inc., Iron Ore Holdings, Lighthouse Oil & Gas GP, LLC, MarkWest Utica EMG, LLC, Medallion Midstream, LLC, Plains All American GP LLC and Tallgrass MLP GP LLC. Mr. Raymond manages various private investments through personally held Lynx Holdings, LLC.

Patrick Wade. Mr. Wade served as a member of the High Sierra board beginning in November 2008 and as a member of the board of directors of our general partner since 2012. Mr. Wade has 20 years of experience in the energy sector. In 2002, Mr. Wade co-founded Tiger Midstream Investments, a natural gas midstream development and investment company that was involved primarily in the Rocky Mountains. From 2005 to 2007, Mr. Wade was a Managing Director at Bear Energy LP, responsible for investments in natural gas midstream infrastructure, as well as contracting for a diverse portfolio of natural 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 of specialized private equity funds. EMG focuses on investing across various facets of the global natural resource industry including the upstream and midstream segments of the energy complex. EMG is the managing partner of EMG NGL HC LLC. Mr. Wade’s primary focus is making direct investments across 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, L.L.C., Ferus Inc., and Lodestar Energy Group, LLC.

Mr. Wade brings extensive financial and industry experience to the board. With 20 years of experience in the energy sector, Mr. Wade provides valuable insight into our business.


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Director Appointment Rights

The Limited Liability Company Agreement of NGL Energy Holdings LLC grants certain parties the right to designate a specified number of persons to 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 who formed the Partnership (“IEP Parties”) (which consists of certain entities controlled by H. Michael Krimbill, and two other investors, one of whom is an employee of the Partnership) each have the right to designate one person to serve on the board of directors. The Coady Group has designated Shawn W. Coady and the IEP Parties have designated H. Michael Krimbill.

Board Leadership Structure and Role in Risk Oversight

The board of directors of our general partner believes that whether the offices of chairman of the board and chief executive officer are combined or separated should be decided by the board, from time to time, in its business judgment after considering relevant circumstances. The board of directors of our general partner currently does not have a chairman.

The board of directors and its committees regularly review material operational, financial, compensation and compliance risks with senior management. In particular, the audit committee is responsible for risk oversight with respect to financial and compliance risks and risks relating to our audit and independent registered public accounting firm. Our compensation committee considers risk in connection with its design and evaluation of compensation programs for our senior management. Each committee regularly reports to the board of directors.

Audit Committee

The board of directors of our general partner has established an audit committee. The audit committee assists the board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has 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 registered public accounting firm.

The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent 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 of directors of our general partner has determined that Mr. Kneale is an “audit committee financial expert” as defined under SEC rules and that each member of the audit committee is financially literate. In compliance with the requirements of the NYSE, all of the members of the audit committee are independent directors, as defined in the applicable NYSE and Exchange Act rules.


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Compensation Committee

The board of directors of our general partner has established a compensation committee. The compensation committee’s responsibilities include the following, among others:

•
establishing the general partner’s compensation philosophy and objectives;
•
approving the compensation of the Chief Executive Officer;
•
making recommendations to the board of directors with respect to the compensation of other officers and directors; and
•
reviewing and making recommendations to the board of directors with respect to incentive compensation and equity-based plans.

Mr. Cropper, Mr. Guderian, and Mr. Kneale currently serve on the compensation committee. Mr. Cropper serves as the chairman. The board of directors has determined that Mr. Cropper and Mr. Kneale are independent directors under applicable NYSE and Exchange Act rules. The NYSE does not require a listed publicly traded limited partnership to have a compensation committee consisting entirely of independent directors.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Exchange Act requires our general partner’s board of directors and officers, and persons who own more than 10% of a registered class of our equity securities, to file initial reports of beneficial ownership and reports of changes in beneficial ownership of our common units and other equity securities with the SEC. Directors, officers and greater than 10% unitholders are required by SEC regulations to furnish to us copies of all Section 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, we believe that all reporting obligations of our general partner’s directors and officers and our greater than 10% unitholders under Section 16(a) were satisfied during the year ended March 31, 2016, except for the purchase of stock by Shawn W. Coady on August 17, 2015 and by James Collingsworth on February 12, 2016 which were both late by one day. Also, a Form 3 for Robert W. Karlovich III, who became an executive officer on February 22, 2016, was not filed until March 9, 2016. Mr. Karlovich’s receipt of a grant of restricted common units on February 22, 2016 was not reported on a Form 4 until March 10, 2016.

Corporate Governance

The board of directors of our general partner has adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers, or Code of Ethics, that applies to the chief executive officer, chief financial officer, chief accounting officer, controller and all other senior financial and accounting officers 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 general partner has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct 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 to any unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics and the charters of the audit committee and the compensation committee of the board of directors of our general partner. Requests for print copies may be directed to Investor Relations at investorinfo@nglep.com or to Investor Relations, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136 or made by telephone at (918) 481-1119. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

Meeting of Non-Management Directors and Communications with Directors

At each quarterly meeting of the audit committee and/or the board of directors of our general partner, our independent directors meet in an executive session without participation by management or non-independent directors. Mr. Kneale presides over these executive sessions.


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Unitholders or interested parties may communicate directly with the board of directors of our general partner, any committee of the board, any independent directors, or any one director, by sending written correspondence by mail addressed to the board, committee or director to the attention of our Secretary at the following address: Name of the Director(s), c/o Secretary, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136. Communications are distributed to the board, committee, or director as appropriate, depending on the facts and circumstances outlined in the communication.

Item 11.    Executive Compensation

Compensation Discussion and Analysis

The year “2016” in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2016.

Introduction

The board of directors of our general partner has responsibility and authority for compensation-related decisions for our executive officers. The board of directors has formed a compensation committee to develop our compensation program, to determine the compensation of our Chief Executive Officer, and to make recommendations to the board of directors regarding the compensation of our other executive officers. Our executive officers are also officers of our operating companies and are compensated directly by our operating companies. While we reimburse our general partner and its affiliates for all expenses they incur on our behalf, our executive officers do not receive any additional compensation for the services they provide to our general partner.

Our “named executive officers” for fiscal year 2016 were:

•
H. Michael Krimbill–Chief Executive Officer
•
Robert W. Karlovich III–Chief Financial Officer (effective February 22, 2016)
•
James J. Burke–President
•
Shawn W. Coady–President and Chief Operating Officer, Retail Division
•
Vincent J. Osterman–President, Eastern Retail Propane Operations
•
Atanas H. Atanasov–Chief Financial Officer and Treasurer (resigned effective February 5, 2016)

Compensation Philosophy

Our compensation philosophy emphasizes pay-for-performance, focused primarily on the ability to increase sustainable quarterly distributions to our 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 same time 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.


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Recent Achievements

Our compensation structure is designed to reward our officers for achieving above-market returns for our unitholders. Our achievements during the year ended March 31, 2016 included the following:
•
Entered into an agreement with Saddlehorn Pipeline Company, LLC to combine pipeline projects to transport crude oil from Weld County, Colorado to Cushing Oklahoma, of which we will own a 37.5% undivided interest in the pipeline; and
•
We sold our general partner interest in TLP for $350 million.

Compensation Highlights

•
We paid no cash bonuses to our named executive officers during fiscal year 2016.
•
The salaries of most of our named executive officers remain below the median of our benchmark peer group. This enables us to grant more performance-based compensation to maintain competitive total compensation packages.
•
We introduced a new performance-based restricted unit program for which no payout will be made unless the return on our common units exceeds the median returns for a specified peer group over specified periods of time.
 
Factors Enhancing Alignment with Unitholder Interests

•
Majority of officer pay is at risk incentive compensation based on annual financial performance and growth in unitholder value;
•
Equity-based incentives are the largest single component of officer compensation;
•
Certain of the officers’ equity awards are subject to achievement of above-median total unitholder return relative to our performance peer group;
•
No excise tax gross-ups; and
•
Compensation committee engages an independent compensation adviser.
 
Compensation Setting Process
 
Our compensation program for our named executive officers supports our philosophy of pay-for-performance.
•
Role of Management: Our Chief Executive Officer also provides periodic recommendations to the compensation committee and the board of directors 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 the effectiveness of our executive compensation philosophy, plans and programs, our compensation committee has the authority to engage outside experts to assist in its deliberations. During fiscal year 2016, the compensation committee received compensation advice and data from Pearl Meyer & Partners (“PM&P”). PM&P conducted a competitive review of the principal components of compensation for our executives, including our 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 in providing executive compensation consulting services. In making this determination, the compensation committee noted that during fiscal year 2016:
◦
PM&P did not provide any services to the Partnership or management other than compensation consulting services requested by or with the approval of the compensation committee;
◦
PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or human resource outsourcing;
◦
PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and procedures designed to ensure independence;
◦
Fees paid to PM&P by the Partnership during fiscal year 2016 were less than 1% of PM&P’s total revenue;
◦
None of the PM&P consultants working on Partnership matters had any business or personal relationship with compensation committee members;

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◦
None of the PM&P consultants working on Partnership matters (or any consultants at PM&P) had any business or personal relationship with any executive officer of the Partnership; and
◦
None of the PM&P consultants working on Partnership matters own Partnership interests.

The compensation committee continues to monitor the independence of its compensation consultant on a periodic basis. The compensation committee considered the recommendations provided by PM&P in the process of designing the fiscal year 2016 compensation program.

Elements of Executive Compensation

As part of our pay-for-performance approach to executive compensation, the compensation of our executive officers includes a significant component of incentive compensation based on our performance. The following table summarizes the primary elements of compensation in our executive compensation program: 
 
 
 
 
 
 
Objective Supported
Element
 
Primary Purpose
 
How Amount Determined
 
Attract &
Retain
 
Motivate &
Pay for
Performance
 
Unitholder
Alignment
 
 
 
 
 
 
 
 
 
 
 
Base Salary
 
ž Fixed income to compensate executive officers for their level of responsibility, expertise and experience
 
ž Based on competition in the marketplace for executive talent and abilities
 
X
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Cash Bonus Awards
 
ž Rewards achievement of specific annual financial and operational performance goals
 
ž Based on the named executive officer’s relative contribution to achieving or exceeding annual goals
 
X
 
X
 
X
 
 
ž Recognizes individual contributions to our performance
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Long-Term Equity Incentive Awards
 
ž Motivates and rewards the achievement of long-term performance goals, including increasing the market price of our common units and the quarterly distributions to our unitholders
 
ž Based on the named executive officer’s expected contribution to long-term performance goals
 
X
 
X
 
X
 
 
ž Provides a forfeitable long-term incentive to encourage executive retention
 
 
 
 
 
 
 
 

Base Salary

The compensation committee periodically reviews the base salaries of our named executive officers and may recommend adjustments as necessary. We do not make automatic annual adjustments to base salary.
•
Mr. Krimbill’s initial base salary of $120,000 was originally determined as part of the negotiations for our formation transactions. In setting the base salaries, the parties considered various factors, including the compensation needed to attract or retain the officers, the historical compensation of the officers, and each officer’s expected individual contribution to our performance. At the request of Mr. Krimbill, the parties agreed that he should receive a lower base salary than our other executive officers at the time because, as our Chief Executive Officer, a significant portion of his compensation should be performance-based, to further align his interests with the interests of our unitholders. In February 2012, the base salary of Mr. Krimbill was reduced to $60,000, based on our operating and financial performance as a result of an unusually warm winter. The base salary of Mr. Krimbill was restored to $120,000 effective November 12, 2012. Effective July 1, 2014, the Board of

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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.
•
Mr. Burke’s base salary of $353,000 became effective on June 19, 2012 when Mr. Burke joined our management team upon completion of our merger with High Sierra. Mr. Burke’s base salary was increased to $375,000 in July 2013 and to $384,000 in June 2014. Mr. Burke was given a lower salary increase than the other named executive officers, based on the fact that his salary is higher relative to the benchmark peer group than the other named executive officers (his current salary is close to the 50th percentile of the peer group).
•
Dr. Coady’s base salary of $300,000 was determined as part of the negotiations for our formation transactions. In February 2012, the base salary of Dr. Coady was reduced to $200,000 based on our operating and financial performance as a result of an unusually warm winter. The base salary 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, in consideration 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 our acquisition of Osterman Propane. Mr. Osterman’s salary was increased to $200,000 in January 2013 and to $250,000 in July 2013, in consideration of the fact that his salary was low relative to the benchmark peer group.
•
Mr. Atanasov’s base salary of $195,000 was negotiated prior to his joining our management team in November 2011. The base salary of Mr. Atanasov was increased to $250,000 in July 2013 and to $300,000 in July 2014, in consideration of the fact that his salary was low relative to the benchmark peer group.

Cash Bonus Awards

None of the named executive officers is subject to a formal cash bonus plan, and any cash bonuses are at the discretion of the Compensation Committee or the Board of Directors, (in the case of Mr. Krimbill) or the Compensation Committee (in the case of the other named executive officers).

Long-Term Equity Incentive Awards

Certain restricted units granted to the named executive officers vest in tranches, contingent only on the continued service of the recipient through the vesting date (the “Service Awards”). The following table summarizes grants of Service Award units granted, vested and/or forfeited during fiscal year 2016 with respect to the named executive officers:
 
 
Unvested Units
at March 31, 2015
 
Units Granted
 
Units Vested
 
Units Forfeited
 
Unvested Units
at March 31, 2016
H. Michael Krimbill (1)
 
—

 
213,573

 
(71,191
)
 
—

 
142,382

Robert W. Karlovich III (2)
 
—

 
75,000

 
—

 
—

 
75,000

James J. Burke (3)
 
45,000

 
25,000

 
(25,000
)
 
—

 
45,000

Shawn W. Coady (3)
 
45,000

 
25,000

 
(25,000
)
 
—

 
45,000

Vincent J. Osterman (3)
 
45,000

 
25,000

 
(25,000
)
 
—

 
45,000

Atanas H. Atanasov (4)
 
36,000

 
8,333

 
(20,333
)
 
(24,000
)
 
—

 
(1)
Mr. Krimbill was granted 213,573 Service Awards on April 23, 2015.
(2)
Mr. Karlovich was granted 75,000 Service Awards on February 22, 2016.
(3)
Mr. Burke, Dr. Coady and Mr. Osterman were each granted 10,000 Service Awards on July 1, 2015 and 15,000 Service Awards on February 18, 2016.
(4)
Mr. Atanasov was granted 8,333 Service Awards on July 1, 2015 and forfeited all outstanding Service Awards upon his resignation from employment.

The number of Service Award units granted to Mr. Krimbill was calculated based on the median value of equity award units granted to chief executive officers in the benchmark peer group.


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The Service Award units granted in July 2015 were intended as discretionary bonuses for performance during fiscal year 2015.

The Service Award units granted to Mr. Karlovich were negotiated prior to his joining our management team in February 2016.

The Service Award units granted to in February 2016 were intended for retention.

The following table summarizes the vesting dates of the unvested Service Award units at March 31, 2016:
 
 
Service Award Units by Vesting Date
 
Total
Unvested Units
 
 
July 1, 2016
 
July 1, 2017
 
July 1, 2018
 
at March 31, 2016
H. Michael Krimbill
 
71,191

 
71,191

 
—

 
142,382

Robert W. Karlovich III
 
25,000

 
25,000

 
25,000

 
75,000

James J. Burke
 
30,000

 
15,000

 
—

 
45,000

Shawn W. Coady
 
30,000

 
15,000

 
—

 
45,000

Vincent J. Osterman
 
30,000

 
15,000

 
—

 
45,000


During April 2015, the Partnership granted awards that are contingent both on the continued service of the recipients through the vesting date and also on the performance of our common units relative to the performance of other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”).

The Performance Awards represent hypothetical units and are not actual common units. The Performance Awards settle in common units rather than cash. The right to receive common units with respect to the Performance Awards depends on (i) the level of total unitholder return attained by us over the applicable performance periods, as measured against our peer group and as described in the Performance Unit Agreement, provided that the number of 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 than the 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 the 90th percentile of the performance peer group over the same performance period (such number of earned Performance Awards are referred to, and defined in the Performance Unit Agreement, as, "Earned Performance Awards"), and (ii) the satisfaction of a continued service requirement.

The following table summarizes the maximum number of units that could vest on the Performance Awards granted to each named executive officer:
 
 
Maximum Performance Award Units
by Vesting Date
 
 
 
 
July 1, 2015
 
July 1, 2016
 
July 1, 2017
 
Total
H. Michael Krimbill
 
142,382

 
142,382

 
142,382

 
427,146

Atanas H. Atanasov
 
24,000

 
24,000

 
24,000

 
72,000

James J. Burke
 
30,000

 
30,000

 
30,000

 
90,000

Shawn W. Coady
 
30,000

 
30,000

 
30,000

 
90,000

Vincent J. Osterman
 
30,000

 
30,000

 
30,000

 
90,000


The number of Performance Award units that will vest is contingent on the performance of our common units relative to the performance of the other entities in the Index. Performance will be calculated based on the return on our common units (including changes in the market price of the common units and distributions paid during the performance period) relative to the returns on the common units of the other entities in the Index. Performance will be measured over the following periods:

Vesting Date of Tranche
 
Performance Period for Tranche
July 1, 2015
 
July 1, 2012 through June 30, 2015
July 1, 2016
 
July 1, 2013 through June 30, 2016
July 1, 2017
 
July 1, 2014 through June 30, 2017
 

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The following table summarizes the percentage of the maximum Performance Award units that will vest depending on the percentage of entities in the Index that NGL outperforms: 

Our Relative TUR Percentile Ranking
 
Payout (% of Target Units)
Less than 50th percentile
 
—%
Between the 50th and 75th percentile
 
50%–100%
Between the 75th and 90th percentile
 
100%–200%
Above the 90% percentile
 
200%

The Performance Award units were granted in consideration of the fact that the base salaries and the service-based equity awards for the named executive officers are in most cases below the median value for officers in their respective peer groups. The Compensation Committee believes that if the performance of NGL’s common units falls below the median performance of the Index, the named executive officers should receive lower compensation than their 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 be increased.

Severance and Change in Control Benefits

We do not provide any severance or change of control benefits to our named executive officers. The board of directors has the option to accelerate the 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 of directors 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 as reported in the “Outstanding Equity Awards at March 31, 2016” table below.

401(k) Plan

We have established a defined contribution 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred basis. The 401(k) plan permits all eligible employees, including our named executive officers, to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. We make a maximum employer matching contribution equal to 3.5% of the employee’s eligible compensation (as defined in the plan) that is not in excess of 6% of the employee’s eligible compensation (subject to annual Internal Revenue Service contribution limits). Our matching contributions prior to January 1, 2015 vest over 5 years and, effective January 1, 2015, our matching contributions vest over 2 years.

Other Benefits

We do not maintain a defined benefit or pension plan for our executive officers, because we believe such plans primarily reward longevity rather than performance. We provide a basic benefits package available to substantially all full-time employees, which includes a 401(k) plan and medical, dental, vision, disability and life insurance.

Other Officers

Certain officers who have leadership roles within our individual business units, but who are not executive officers, participate in formulaic bonus programs that are based on the performance of the individual business units with which they are involved. In most cases, similar programs were in place prior to our acquisition of the businesses, and we have left the programs substantially intact.

Competitive Review and Fiscal Year 2016 Compensation Program

During fiscal year 2016, PM&P conducted a competitive review of our executive compensation program and provided input to the compensation committee regarding competitive compensation levels and compensation program design. In order to provide guidance to the compensation committee regarding 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 general industry companies with revenues of between $1 billion and $6 billion; and

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•
Peer group data including pay data from 10-K and proxy filings for a group of 20 publicly traded midstream oil & gas partnerships of similar size and scope to us.

Compensation Peer Group Companies 
AmeriGas Partners LP
 
Enbridge Energy Partners, L.P.
 
Crosstex Energy LP
Ferrellgas Partners LP
 
NuStar Energy L.P.
 
DCP Midstream Partners LP
Star Gas Partners, L.P.
 
Targa Resources Partners LP
 
Martin Midstream Partners LP
Suburban Propane Partners, L.P.
 
Buckeye Partners, L.P.
 
Regency Energy Partners LP
ONEOK Partners, L.P.
 
Genesis Energy LP
 
Boardwalk Pipeline Partners, LP
Kinder Morgan Energy Partners, L.P.
 
Crestwood Midstream Partners LP
 
Western Gas Partners LP
Williams Partners L.P.
 
Magellan Midstream Partners LP
 
 

PM&P defines “market” as the combination of survey data and peer group data. As described above, the Compensation Committee considered this data in establishing salaries for fiscal year 2016 and in determining the number of Service Award and Performance Award units to grant to the named executive officers.

Employment Agreements

We do not have employment agreements with any of our named executive officers.

Deductibility of Compensation

We believe that the compensation paid to the named executive officers is generally fully deductible for federal income tax purposes. We are a limited partnership and we do not meet the definition of a “corporation” subject to deduction limitations under Section 162(m) of the Internal Revenue Code of 1986, as amended.

Compensation Committee Report

The Compensation Committee of the board of directors of our general partner has reviewed and discussed the Compensation Discussion and Analysis set forth above with management. Based on this review and discussion, the Compensation Committee recommended to the board of directors of our general partner that the Compensation Discussion and Analysis be included in this Annual Report. 
 
Members of the Compensation Committee:
 
 
 
Stephen L. Cropper (Chairman)
 
Bryan K. Guderian
 
James C. Kneale

Relation of Compensation Policies and Practices to Risk Management

Our compensation arrangements contain a number of design elements that serve to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. This includes using restricted unit grants as a significant element of the executive compensation, as the restricted units are designed to reward the executives based on the long-term performance of the Partnership. In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

Compensation Committee Interlocks and Insider Participation

During fiscal year 2016, Stephen L. Cropper, Bryan K. Guderian, and James C. Kneale served on the Compensation Committee. None of these individuals is an employee or an officer of our general partner. As described under Part I, Item 13–“Transactions With Related Persons,” Mr. Guderian is an executive officer of WPX, and we entered into certain transactions with WPX during fiscal year 2016. Shawn W. Coady is an executive officer and a member of 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 capacity Dr. Coady participates in the compensation setting process of the HOH board of directors.

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Summary Compensation Table for 2016

The following table summarizes the compensation earned by our named executive officers for fiscal years 2014 through 2016. 
Name and Position 
 
Fiscal
Year
 
Salary
($)
 
Bonus (1)
($)
 
Restricted
Unit
Awards (Service and Performance Awards) (2)
($)
 
All Other
Compensation (3)
($)
 
Total
($)
H. Michael Krimbill
 
2016
 
350,000

 
—

 
8,319,437

 
7,539

 
8,676,976

Chief Executive Officer
 
2015
 
292,500

 
—

 
—

 
9,319

 
301,819

 
 
2014
 
117,693

 
475,000

 
—

 
6,493

 
599,186

 
 
 
 
 
 
 
 
 
 
 
 
 
Robert W. Karlovich III
 
2016
 
30,769

 
—

 
419,250

 
—

 
450,019

Chief Financial Officer
 
 
 
 
 
 
 
 
 
 
 


 
 
 
 
 
 
 
 
 
 
 
 


James J. Burke (4)
 
2016
 
375,000

 
—

 
1,047,241

 
27,898

 
1,450,139

President
 
2015
 
381,750

 
—

 
602,270

 
26,467

 
1,010,487

 
 
2014
 
367,385

 
450,000

 
—

 
24,651

 
842,036

 
 
 
 
 
 
 
 
 
 
 
 
 
Shawn W. Coady
 
2016
 
315,000

 
—

 
1,047,241

 
9,329

 
1,371,570

President and Chief Operating
 
2015
 
311,250

 
—

 
1,331,501

 
19,153

 
1,661,904

Officer, Retail Division
 
2014
 
300,000

 
200,000

 
—

 
19,630

 
519,630

 
 
 
 
 
 
 
 
 
 
 
 
 
Vincent J. Osterman (5)
 
2016
 
250,000

 
—

 
1,047,241

 
30,906

 
1,328,147

President, Eastern Retail
 
2015
 
250,000

 
—

 
1,331,501

 
31,763

 
1,613,264

Propane Operations
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Atanas H. Atanasov (6)
 
2016
 
265,385

 
50,000

 
752,755

 
8,885

 
1,077,025

Former Chief Financial Officer
 
2015
 
287,500

 
—

 
864,664

 
9,346

 
1,161,510

 
 
2014
 
232,500

 
195,000

 
259,696

 
7,038

 
694,234

 
(1)
Amounts for fiscal year 2014 include discretionary bonuses paid in fiscal year 2014 based on contributions of the individuals since the time they joined the Partnership through the date of the bonus and based on expectations of future performance.
(2)
The fair values of the restricted units shown in the table above were calculated based on the closing market prices of our common units on the grant dates, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution prior to the grant date and assumptions that a market participant might make about future distribution growth. This calculation of fair value is consistent with the provisions of Accounting Standards Codification 718 Stock Compensation. The following table summarizes these amounts:

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Name
 
Service Award
Grant Date
Fair Value
 
Performance Award
Grant Date
Fair Value
 
Total
Grant Date
Fair Value
 
Performance Awards
at Maximum Value
H. Michael Krimbill
 
$
4,624,567

 
$
3,694,870

 
$
8,319,437

 
$
7,389,740

Robert W. Karlovich III
 
419,250

 
—

 
419,250

 
—

James J. Burke
 
413,050

 
650,591

 
1,063,641

 
1,301,181

Shawn W. Coady
 
413,050

 
650,591

 
1,063,641

 
1,301,181

Vincent J. Osterman
 
413,050

 
650,591

 
1,063,641

 
1,301,181

Atanas H. Atanasov
 
245,949

 
520,472

 
766,421

 
1,040,945


(3)
The amounts in this column include matching contributions to our 401(k) plan. Amounts for Mr. Burke include a club membership and a car allowance. Amounts for Dr. Coady include the incremental cost of the use of a company car, including depreciation, maintenance, insurance, and fuel. Amounts for Mr. Osterman include propane provided to him and to members of his family (valued for this purpose at the cost of the propane to NGL). The following table summarizes these amounts:
Name
 
Fiscal
Year
 
401(k)
Match
 
Car
Allowance
 
Club
Membership
 
Propane
 
Total Other
Compensation
James J. Burke
 
2016
 
$
10,774

 
$
9,000

 
$
8,124

 
$
—

 
$
27,898

 
 
2015
 
9,343

 
9,000

 
8,124

 
—

 
26,467

 
 
2014
 
7,527

 
9,000

 
8,124

 
—

 
24,651

 
 
 
 
 
 
 
 
 
 
 
 
 
Shawn W. Coady
 
2016
 
9,329

 
—

 
—

 
—

 
9,329

 
 
2015
 
9,796

 
9,357

 
—

 
—

 
19,153

 
 
2014
 
8,750

 
10,880

 
—

 
—

 
19,630

 
 
 
 
 
 
 
 
 
 
 
 
 
Vincent J. Osterman
 
2016
 
4,038

 
—

 
—

 
26,868

 
30,906

 
 
2015
 
18,468

 
—

 
—

 
13,295

 
31,763


(4)
Mr. Burke joined our management team upon completion of our merger with High Sierra on June 19, 2012.
(5)
Mr. Osterman was not a named executive officer prior to fiscal year 2015.
(6)
Mr. Atanasov resigned as Chief Financial Officer effective February 5, 2016.

Restricted Unit Awards

During fiscal year 2016, the Committee granted awards for which units vest at specified dates, contingent only on the continued service of the recipient through the service date (the “Service Awards”) and awards that vest at specific dates, contingent on both the performance of our common units relative to the performance of other entities and on the continued service of the recipient through the vesting (the “Performance Units”).


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2016 Grants of Plan Based Awards Table

The following table summarizes the number of restricted Service and Performance Award units granted to our named executive officers, and their grant date fair values:
 
 
 
 
 
 
Estimated Future Payouts Under Performance Awards (1)
 
 
Name
 
Grant Date
 
Total Number of Service Award Units
 
Threshold
(#) 50%
 
Target
(#) 100%
 
Maximum
(#) 200%
 
Grant Date
Fair Value of
Service Award Units
($)(2)(3)
H. Michael Krimbill
 
April 23, 2015
 
213,573

 
 
 
 
 
 
 
4,624,567

 
 
April 23, 2015
 
 
 
106,786

 
213,573

 
427,146

 
3,694,870

Robert W. Karlovich III
 
February 22, 2016
 
75,000

 
 
 
 
 
 
 
419,250

James J. Burke
 
April 17, 2015
 
 
 
22,500

 
45,000

 
90,000

 
650,591

 
 
July 1, 2015
 
10,000

 
 
 
 
 
 
 
295,150

 
 
February 18, 2016
 
15,000

 
 
 
 
 
 
 
117,900

Shawn W. Coady
 
April 17, 2015
 
 
 
22,500

 
45,000

 
90,000

 
650,591

 
 
July 1, 2015
 
10,000

 
 
 
 
 
 
 
295,150

 
 
February 18, 2016
 
15,000

 
 
 
 
 
 
 
117,900

Vincent J. Osterman
 
April 17, 2015
 
 
 
22,500

 
45,000

 
90,000

 
650,591

 
 
July 1, 2015
 
10,000

 
 
 
 
 
 
 
295,150

 
 
February 18, 2016
 
15,000

 
 
 
 
 
 
 
117,900

Atanas H. Atanasov
 
April 17, 2015
 
 
 
18,000

 
36,000

 
72,000

 
520,472

 
 
July 1, 2015
 
8,333

 
 
 
 
 
 
 
245,949

 
(1)
Amounts reported in the (a) “Threshold” column reflect the threshold number of Performance Awards (at 50% of target) that may be earned (assuming a relative TUR at the 50th 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 common units actually received by a named executive officer with respect to a Performance Award may vary based on the Partnership’s relative TUP as compared to the TUR of the performance 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 probably achievement of the performance conditions, which is consistent with the estimate of aggregate compensation to be recognized over the service period, excluding the effect of estimated forfeitures.
(3)
The fair value of the restricted Service Award units shown in the table above were calculated based on the closing market price of our common units on the grant dates, with adjustments made to reflect the fact that restricted units are not entitled to distributions during the vesting period.

We record in our consolidated financial statements the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through each reporting date using the estimated fair value of the awards at the reporting date.




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Outstanding Equity Awards at March 31, 2016

The following table summarizes the number of unvested Service Award and Performance Awards outstanding and their fair values at March 31, 2016:
 
 
Service Awards
 
Performance Awards
 
 
Number of Units
That Have Not Yet Vested
 
Market Value of Units that Have Not Vested
 
Number of Units
That Have Not Yet Vested
 
Market Value of Units that Have Not Vested
Name
 
#(1)
 
($)(2)
 
#(3)
 
($)(2)
H. Michael Krimbill
 
142,382

 
1,070,713

 
142,382

 
1,070,713

Robert W. Karlovich III
 
75,000

 
564,000

 
—

 
—

James J. Burke
 
45,000

 
338,400

 
30,000

 
225,600

Shawn W. Coady
 
45,000

 
338,400

 
30,000

 
225,600

Vincent J. Osterman
 
45,000

 
338,400

 
30,000

 
225,600

Atanas H. Atanasov (4)
 
N/A

 
N/A

 
N/A

 
N/A

 
(1)
Reflects Service Awards that have not vested and are held by each named executive officer.
(2)
Calculated based on the closing market price of our common units at March 31, 2016 of $7.52. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.
(3)
Reflects the target number of Performance Awards granted to each named executive officer that have not vested. Vesting of the Performance Awards are contingent upon our relative TUR as measured against the performance peer group and satisfaction of a continued service requirement.
(4)
Mr. Atanasov resigned effective February 5, 2016 resulting in the forfeiture of his Service Awards and Performance Awards. As a result, Mr. Atanasov did not have any outstanding equity awards as of March 31, 2016.

2016 Units Vested

During fiscal year 2016, certain of the restricted Service Award units and Performance Award units vested. The following table summarizes the value of the awards on the vesting date which was calculated based of the closing market price per common unit on the vesting dates.
 
 
Service Awards
 
Performance Awards
Name
 
Number of Units
Acquired on Vesting
 
Value Realized on Vesting
($)
 
Number of Units
Acquired on Vesting
 
Value Realized on Vesting
($)
H. Michael Krimbill
 
71,191

 
2,174,885

 
108,014

 
3,299,828

Robert W. Karlovich III
 
—

 
—

 
—

 
—

James J. Burke
 
25,000

 
717,100

 
22,759

 
695,287

Shawn W. Coady
 
25,000

 
717,100

 
22,759

 
695,287

Vincent J. Osterman
 
25,000

 
717,100

 
22,759

 
695,287

Atanas H. Atanasov
 
20,333

 
582,300

 
18,207

 
556,224



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Upon vesting, certain of the named executive officers elected for us to remit payments to taxing authorities in lieu of issuing common units. The following table summarizes the number of common units issued and the number of common units withheld for taxes:
Name
 
Number of Units
Issued
 
Number of Units
Withheld
 
Total
H. Michael Krimbill
 
128,226

 
50,979

 
179,205

James J. Burke
 
28,357

 
19,402

 
47,759

Shawn W. Coady
 
27,679

 
20,080

 
47,759

Vincent J. Osterman
 
26,805

 
20,954

 
47,759

Atanas H. Atanasov
 
24,468

 
14,072

 
38,540


Subsequent to vesting, regularly-scheduled distributions were paid on the common units. The following table summarizes the distributions paid during fiscal year 2015 on the common units that vested and were issued during fiscal year 2016:
Name
 
Distributions
H. Michael Krimbill
 
$
245,232

James J. Burke
 
50,854

Shawn W. Coady
 
49,502

Vincent J. Osterman
 
47,919

Atanas H. Atanasov
 
44,012


Director Compensation

Officers or employees of our general partner and its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner or its affiliates receives the following cash compensation for his board service:
•
an annual retainer of $60,000;
•
an annual retainer of $10,000 for the chairman of the audit committee; and
•
an annual retainer of $5,000 for each member of the audit committee other than the chairman.

In addition, each director who is not an officer or an employee of our general partner has been granted awards of restricted units. In April 2015, such directors were granted 15,000 restricted units that vest in tranches of 5,000 units each on July 1, 2015, July 1, 2016, and July 1, 2017.

All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Each director is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

Director Compensation for Fiscal Year 2016

The following table summarizes the compensation earned during fiscal year 2016 by each director who is not an officer or employee of our general partner or its affiliates:
Name
 
Fees Earned or
Paid in Cash
($)
 
Restricted Unit
Awards
($)
 
Total
($)
James M. Collingsworth
 
70,000

 
324,800

 
394,800

Stephen L. Cropper
 
75,000

 
324,800

 
399,800

Bryan K. Guderian
 
65,000

 
324,800

 
389,800

James C. Kneale
 
70,000

 
324,800

 
394,800


During fiscal year 2016, a tranche of 5,000 units vested for each of these directors. Subsequent to the vesting, these individuals received distributions of $1.91 on each of the vested units.

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As of March 31, 2016, each of the directors listed in the table above has 10,000 unvested restricted units.

Item 12.    Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

Security Ownership of Certain Beneficial Owners and Management

The following table summarizes the beneficial ownership, as of May 20, 2016 of our common units by:
•
each person or group of persons known by us to be a beneficial owner of more than 5% of our outstanding common units;
•
each director of our general partner;
•
each named executive officer of our general partner; and
•
all directors and executive officers of our general partner as a group.
Beneficial Owners
 
Common Units
Beneficially
Owned
 
Percentage of
Common Units
Beneficially
Owned (1)
5% or greater unitholders (other than officers and directors):
 
 

 
 

Oppenheimer Funds, Inc. (2)
 
10,745,300

 
10.32
%
Magnum NGL HoldCo LLC (3)
 
7,396,973

 
7.10
%
ALPS Advisors, Inc. (4)
 
7,202,476

 
6.91
%
Salient Capital Advisors, LLC (5)
 
6,286,363

 
6.03
%
 
 
 
 
 
Directors and named executive officers:
 
 

 
 

Atanas H. Atanasov
 
54,189

 
*

James J. Burke (6)
 
324,642

 
*

Shawn W. Coady (7)
 
2,531,910

 
2.43
%
James M. Collingsworth (8)
 
46,750

 
*

Stephen L. Cropper (9)
 
35,000

 
*

Bryan K. Guderian
 
32,500

 
*

Robert W. Karlovich III
 
25,000

 
*

James C. Kneale (10)
 
32,000

 
*

H. Michael Krimbill (11)
 
1,877,820

 
1.87
%
Vincent J. Osterman (12)
 
3,972,900

 
3.81
%
John T. Raymond (13)
 
176,634

 
*

Patrick Wade
 
—

 
—

All directors and executive officers as a group (11 persons) (14)
 
9,109,345

 
8.74
%
 
* Less than 1.0%
(1)
Based on 104,169,573 common units outstanding at May 23, 2016. 
(2)
The mailing address for OppenheimerFunds, Inc. is 225 Liberty Street, New York, NY 10281. OppenheimerFunds, Inc. reported shared voting and dispositive power with respect to all common units beneficially owned. This information related to OppenheimerFunds, Inc. is based upon its Schedule 13G/A filed with the SEC on April 8, 2016. 
(3)
The mailing address for Magnum NGL HoldCo LLC is 2603 Augusta, Suite 900, Houston, TX 77057. Magnum NGL HoldCo LLC reported shared voting and dispositive power with respect to all common units beneficially owned. This information related to Magnum NGL HoldCo LLC is based upon its Schedule 13G filed with the SEC on February 27, 2015. 
(4)
The mailing address for ALPS Advisors, Inc. is 1290 Broadway, Suite 1100, Denver, CO 80203. ALPS Advisors, Inc. reported shared voting and dispositive power with respect to all common units beneficially owned. This information related to ALPS Advisors, Inc. is based upon its Schedule 13G filed with the SEC on February 3, 2016. 

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(5)
The mailing address for Salient Capital Advisors, LLC is 4265 San Felipe, 8th Floor, Houston, TX 77027. Salient Capital Advisors, LLC reported shared voting and dispositive power with respect to all common units beneficially owned. This information related to Salient Capital Advisors, LLC is based upon its Schedule 13G filed with the SEC on January 12, 2016. 
(6)
Mr. Burke owns 290,770 of these common units which includes 30,000 units that will vest on July 1, 2016, which were reported on Mr. Burke’s most recent Form 4, but does not include 15,000 unvested units which were reported on Mr. Burke’s most recent Form 4. Impact Development, LLC owns 33,872 of these common units. Impact Development, LLC is solely owned by James J. Burke, who may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. Impact Development, LLC also owns a 2.87% interest in our general partner.
(7)
Dr. Shawn W. Coady owns 52,019 of these common units which includes 30,000 units that will vest on July 1, 2016, which were reported on Dr. Coady’s most recent Form 4. SWC Family Partnership LP owns 2,320,391 of these common units. SWC Family Partnership LP is solely owned by SWC General Partner, LLC, of which Dr. Coady is the sole partner. Dr. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady Irrevocable Insurance Trust, which was established for the benefit of Shawn W. Coady’s children, owns 135,000 of these common units. Dr. Coady may be deemed to have sole voting and 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, of which 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 common units. 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. 
(8)
Mr. Collingsworth owns 44,500 of these common units which includes 5,000 units that will vest on July 1, 2016, which were reported on Mr. Collingsworth’s most recent Form 4, but does not include 5,000 unvested units which were reported on Mr. Collingworth’s most recent Form 4. Mr. Collingsworth holds 2,000 of these common units jointly with his spouse, Cindy Collingsworth. Cindy Collingsworth and her sister jointly own 2,250 of these common units.
(9)
Mr. Cropper owns 10,000 of these common units which includes 5,000 units that will vest on July 1, 2016, which were reported on Mr. Cropper’s most recent Form 4, but does not include 5,000 unvested units which were reported on Mr. Cropper’s most recent Form 4. The Donna L. Cropper Living Trust, of which Stephen L. Cropper and his spouse, Donna L. Cropper, are the trustees, owns 25,000 of these common units.
(10)
Mr. Kneale owns 5,000 of these common units which includes 5,000 units that will vest on July 1, 2016, which were reported on Mr. Kneale’s most recent Form 4, but does not include 5,000 unvested units which were reported on Mr. Kneale’s most recent Form 4. The Suzanne and Jim Kneale Living Trust, of whom Mr. Kneale and his wife are trustees, owns 27,000 of these common units.
(11)
Mr. H. Michael Krimbill owns 489,417 of these common units which includes 71,191 units that will vest on July 1, 2016, which were reported on Mr. Krimbill’s most recent Form 4, but does not include 71,191 unvested units which were reported on Mr. Krimbill’s most recent Form 4. Krim2010, LLC owns 904,484 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 owns 120,000 of these common units. Krimbill Enterprises LP is controlled by H. Michael Krimbill via his ownership of its general partner, Krimbill Holding Company. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. KrimGP2010 LLC owns 363,555 of these common units. KrimGP2010 LLC is solely owned by H. Michael Krimbill. H. Michael Krimbill may be deemed to have sole voting and investment power over these units. H. Michael Krimbill also owns a 14.81% interest in our general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests and Krimbill Capital Group, LLC, which is owned 100% by the H. Michael Krimbill Revocable Trust.
(12)
Mr. Osterman owns 118,263 of these common units which includes 30,000 units that will vest on July 1, 2016, which were reported on Mr. Osterman’s most recent Form 4. The remaining common units are owned by AO Energy, Inc. (110,587 common units), E. Osterman, Inc. (394,350 common units), E. Osterman Gas Services, Inc. (301,700 common units), E. Osterman Propane, Inc. (669,300 common units), Milford Propane, Inc. (559,784 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 of these 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 each of these entities and may be deemed to have sole voting and investment power over 787,563 common units and shared voting and investment power

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(with his father, Ernest Osterman) 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.
(13)
EMG NGL HC, LLC owns all of the 176,634 common units. John T. Raymond is the Chief Executive Officer and Managing Partner of NGP MR GP LLC, the general partner 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 be deemed 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 NGL GP 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.
(14)
The directors and executive officers of our general partner also collectively own a 48.11% interest in our general partner.

Unless otherwise noted, each of the individuals listed above is believed to have sole voting and investment power with respect to the units beneficially 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 Plan

The following table summarizes information regarding the securities that may be issued under the LTIP at March 31, 2016.
 
 
Number of Securities to be
Issued upon Exercise of
Outstanding Options,
Warrants and Rights
 
Weighted-average
Exercise Price of
Outstanding Options,
Warrants and Rights
 
Number of Securities
Remaining Available for
Future Issuances Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column (a))
Plan Category 
 
(a)
 
(b)
 
(c)(1)
Equity Compensation Plans Approved by Security Holders
 
—

 
—

 
—

Equity Compensation Plans Not Approved by Security Holders (2)
 
2,297,132

 
—

 
4,640,927

Total
 
2,297,132

 
—

 
4,640,927

 
(1)
The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of our issued and outstanding common units. The maximum number of common units deliverable under the LTIP automatically increases to 10% of the issued and outstanding common 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 the approval of our unitholders.

Item 13.    Certain Relationships and Related Transactions, and Director Independence

Our directors, executive officers, and greater than 5% unitholders collectively own an aggregate of 40,740,457 common units, representing an aggregate 38.70% limited partner interest in us. In addition, our general partner owns a 0.1% general partner interest in us and all of our incentive distribution rights (“IDRs”).

Distributions and Payments to Our General Partner and Its Affiliates

Our general partner and its affiliates do not receive any management fee or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. Our general partner determines the amount of 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 receive incentive distributions if the amount we distribute with respect to any quarter exceeds levels specified in our partnership agreement.

The following table summarizes the distributions and payments to be made by us to our directors, officers, and greater than 5% owners and our general partner in connection with our ongoing operation and any liquidation. These distributions and

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payments were determined by and among affiliated entities before our IPO and, consequently, are not the result of arm’s length negotiations.

Operation Stage
 
 
 
 
 
Distributions of available cash to our directors, officers, and greater than 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 of an aggregate 40,740,457 common units, and 0.1% to our general partner. In addition, when distributions exceed the minimum quarterly distribution and other higher target distribution levels, our general partner is entitled to increasing percentages of the distributions, up to 48.1% of the distributions above the highest target distribution level.
 
 
 
 
 
Assuming we have sufficient available cash to pay the same quarterly distribution on all of our outstanding units for four quarters that we paid in May 2016 ($0.39 per unit), our general partner would receive an annual distribution of $0.3 million on its general partner interest and incentive distribution rights, and our directors, officers, and greater than 5% owners would receive an aggregate annual distribution of $72.2 million on their common units.
 
 
 
 
 
If our general partner elects to reset the target distribution levels, it will be entitled 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 or other compensation for the management of our business and affairs, but they are reimbursed for all expenses that they incur on our behalf, including general and administrative expenses. As the sole purpose of the general partner is to act as our general partner, substantially all of the expenses of our general partner are incurred on our behalf and reimbursed by us or our subsidiaries. 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 and its IDRs will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.
 
 
 
Liquidation Stage
 
 
 
 
 
Liquidation
 
Upon our liquidation, our partners, including our general partner, will be entitled to receive liquidating distributions according to their respective capital account balances.

Transactions With Related Persons

SemGroup

SemGroup holds an 11.78% ownership interest in our general partner. We sell product to and purchase product from SemGroup, and these transactions are included within revenues and cost of sales, respectively, in our consolidated statements of operations (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 consolidated statement of operations). We also lease crude oil storage from SemGroup. The following table summarizes transactions with SemGroup for the year ended March 31, 2016 (in thousands):
Sales to SemGroup
$
109,557

Purchases from SemGroup
117,538



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WPX

Bryan 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 consolidated statement of operations). The following table summarizes transactions with WPX for the year ended March 31, 2016 (in thousands):
Sales to WPX
$
101,052

Purchases from WPX
169,648


Other Transactions

We purchase goods and services from certain entities that are partially owned by our executive officers. The following table summarizes these transactions for the year ended March 31, 2016:
Entity
 
Nature of Purchases
 
Amount
Purchased
 
Ownership Interest
in Entity
 
 
 
 
(in thousands)
 
 
Shawn W. Coady
 
 
 
 
 
 
Hicks Motor Sales
 
Vehicle purchases
 
$
640

 
50
%
Vincent J. Osterman
 
 
 
 
 
 
VE Properties III, LLC
 
Office space rental
 
153

 
100
%
H. Michael Krimbill
 
 
 
 
 
 
Pinnacle Aviation 2007, LLC
 
Aircraft rental
 
81

 
50
%
H. Michael Krimbill
 
 
 
 
 
 
KAIR2014 LLC
 
Aircraft rental
 
47

 
50
%

We provide goods and services to certain entities that are partially owned by our executive officers. The following table summarizes these transactions for the year ended March 31, 2016:
Entity
 
Nature of Services
 
Revenues
Generated
 
Ownership Interest
in Entity
 
 
 
 
(in thousands)
 
 
James J. Burke
 
 
 
 
 
 
Impact Energy Services, LLC
 
Truck transportation services
 
$
314

 
50
%

Todd M. Coady, an officer and employee of the Partnership, is the brother of Shawn W. Coady, who is an officer of the Partnership and a member of the board of directors. Todd M. Coady’s annual base compensation is $250,000. Todd M. Coady reduced his hours in January 2016, and his annual base of compensation is $125,000. Todd M. Coady was also eligible to participate in the Partnership’s 401(k) plan, and he received $5,889 of employer matching contributions during the year ended March 31, 2016. In April 2015, Todd M. Coady was granted 24,000 Performance Units that vested on July 1, 2015. The aggregate grant date fair value of these awards was $346,982. In July 2015, Todd M. Coady was granted a bonus of 6,666 restricted units that vested during August 2015. The grant date fair value of this bonus was $185,815. Todd M. Coady was also granted 8,000 Service Award units that are scheduled to vest on July 1, 2016. The aggregate grant date fair value of this award was $62,880.

Timothy Osterman, an employee of the Partnership, is the son of Vincent J. Osterman, who is an executive officer of the Partnership and a member of the board of directors. Timothy Osterman’s base compensation during the year ended March 31, 2016 was $110,000. In July 2015, Timothy Osterman was granted a bonus of 6,069 restricted units that vested during August 2015. The grant date fair value of this bonus was $169,174. Timothy Osterman was also eligible to participate in the Partnership’s 401(k) plan, and he received $3,850 of employer matching contributions during the year ended March 31, 2016. In March 2015, Timothy Osterman was granted 2,000 units of which 1,000 units vested on July 1, 2015 and the other 1,000 units will vest on July 1, 2016. The aggregate grant date fair value of this award was $45,220. Timothy Osterman was also granted 5,000 Service Award units in February 2016, that are scheduled to vest on July 1, 2016. The aggregate grant date fair value of this award was $39,300.


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Registration Rights Agreement

We have entered into a registration rights agreement (as amended, the “Registration Rights Agreement”) with certain third parties (the “registration rights parties”) pursuant to which we agreed to register for resale under the Securities Act of 1933, as amended (“Securities Act”) common units, including any common units issued upon the conversion of subordinated units, owned by the parties to the Registration Rights Agreement. In connection with our IPO, we granted registration rights to the NGL Energy LP Investor Group, and subsequently, we have granted registration rights in connection with several acquisitions. We will not be required to register such common units if an exemption from the registration requirements of the Securities Act is available with respect to the number of common units desired to be sold. Subject to limitations 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 they continue 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 a specified number of common units, subject to limitations on the number of requests for registration that can be made in any twelve-month period as well as customary cutbacks at the discretion of the underwriters relating to a potential offering. All other registration rights parties are entitled 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 rights and 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, the registration rights parties are entitled to notice of such registration and have the right to include their common units in the registration, subject to limitations that the underwriters relating to a potential offering may impose on the number of common units included in the registration. These counterparties also have the right to include their units in our future registrations, including secondary offerings of our common units.
•
Expenses of Registration. With specified exceptions, we are required to pay all expenses incidental to any registration of common units, excluding underwriting discounts and commissions.

Review, Approval or Ratification of Transactions with Related Parties

The board of directors of our general partner has adopted a Code of Business Conduct and Ethics that, among other things, sets forth our policies for the review, approval and ratification of transactions with related persons. The Code of Business Conduct and Ethics provides that the board of directors of our general partner or its authorized committee will periodically review all related person transactions that are required to be disclosed under SEC rules and, when appropriate, initially authorize or ratify all such transactions. In the event that the board of directors of our general partner or its authorized committee considers ratification of a related person transaction and determines not to so ratify, the Code of Business Conduct and Ethics provides that our officers will make 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 related party transaction, the board of directors of our general partner or its authorized committee should consider all of the relevant facts and circumstances available, 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 director or 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.

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Director Independence

The NYSE does not require a listed publicly traded partnership like us to have a majority of independent directors on the board of directors of our general partner. For a discussion of the independence of the board of directors of our general partner, please see Part III, Item 10–“Directors, Executive Officers and Corporate Governance–Board of Directors of our General Partner.”
 
Item 14.    Principal Accounting Fees and Services

We have engaged Grant Thornton LLP as our independent registered public accounting firm. The following table summarizes fees we have paid Grant Thornton LLP to audit our annual consolidated financial statements and for other services for the periods indicated:
 
 
March 31,
 
 
2016
 
2015
Audit fees (1)
 
$
2,676,038

 
$
2,762,764

Audit-related fees
 
—

 
—

Tax fees (2)
 
—

 
30,000

All other fees
 
—

 
—

Total
 
$
2,676,038

 
$
2,792,764

 
(1)
Includes fees for audits of the Partnership’s financial statements, reviews of the related quarterly financial statements, and services that are normally provided by the independent accountants in connection with statutory and regulatory filings or engagements, including reviews of documents filed with the SEC and the preparation of letters to underwriters and other requesting parties.
(2)
Includes fees for tax services in connection with tax compliance and consultation on tax matters.

Audit Committee Approval of Audit and Non-Audit Services

The audit committee of the board of directors of our general partner has adopted a pre-approval policy with respect to services which may be performed by Grant Thornton LLP. This policy lists specific audit-related services as well as any other services that Grant Thornton LLP is authorized to perform and sets out specific dollar limits for each specific service, which may not be exceeded without additional audit committee authorization. The audit committee receives quarterly reports on the status of expenditures pursuant to the pre-approval policy. The audit committee reviews the policy at least annually 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.


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PART IV

Item 15.    Exhibits, Financial Statement Schedules

(a)
The following documents are filed as part of this Annual Report:
1.
Financial Statements. Please see the accompanying Index to Financial Statements.
2.
Financial Statement Schedules. All schedules have been omitted because they are either not applicable, not required or the information required in such schedules appears in the financial statements or the related notes.
3.
Exhibits.
Exhibit Number
Description
2.1
 
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 Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
 
 
 
2.2
 
LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Karnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC 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 trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
 
 
 
2.4
 
LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
 
 
 
2.5
 
LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWL Operating, LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High 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 and Gavilon Energy Intermediate, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013)
 
 
 
3.1
 
Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
 
 
 
3.2
 
Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
 
 
 
3.3
 
Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011)
 
 
 
3.4
 
First Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 26, 2011)
 
 
 
3.5
 
Second Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
 
 
 
3.6
 
Third Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 26, 2012)
 
 
 

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Exhibit Number
Description
3.7
 
Fourth Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 2012)
 
 
 
3.8
 
Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
 
 
 
3.9
 
Certificate of Amendment to Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
 
 
 
3.10
 
Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on February 28, 2013)
 
 
 
3.11
 
Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC, dated as 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)
 
 
 
3.12
 
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)
 
 
 
4.1
 
First Amended and Restated Registration Rights Agreement, dated October 3, 2011, by and among the Partnership, Hicks Oils & Hicksgas, Incorporated, NGL Holdings, Inc., Krim2010, LLC, Infrastructure Capital Management, LLC, Atkinson Investors, LLC, E. Osterman Propane, Inc. and the other holders party thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 7, 2011)
 
 
 
4.2
 
Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 by and among the Partnership and SemStream (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on November 4, 2011)
 
 
 
4.3
 
Amendment No. 2 and Joinder to First Amended and Restated Registration Rights Agreement, dated January 3, 2012, by and among NGL Energy Holdings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-Portland Propane, L.L.C., Pacer Propane (Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
 
 
 
4.4
 
Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGL Energy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 4, 2012)
 
 
 
4.5
 
Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and between NGL Energy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
 
 
 
4.6
 
Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and between NGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2012)
 
 
 
4.7
 
Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by and between NGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust and Nitor Trust (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (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 Energy Holdings 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 Energy Holdings 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 the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 

129
Table of Contents

Exhibit Number
Description
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 Energy Holdings LLC and Magnum NGL Holdco LLC
 
 
 
4.11
 
Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
 
 
 
4.12
 
Amendment No. 1 to Note Purchase Agreement, dated as of January 15, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18, 2013)
 
 
 
4.13
 
Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 9, 2013)
 
 
 
4.14
 
Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s 6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)
 
 
 
4.15
 
Amendment No. 4 to Note Purchase Agreement, dated as of November 5, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
 
 
 
4.16
 
Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30, 2013)
 
 
 
4.17
 
Amendment No. 6 to Note Purchase Agreement, dated as of June 30, 2014, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 3, 2014)
 
 
 
4.18
 
Amendment No. 7 to Note Purchase Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 2, 2015)
 
 
 
4.19
 
Amendment No. 8 to Note Purchase Agreement, dated as of May 1, 2015, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.18 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
4.20
 
Amendment No. 9 to Note Purchase Agreement, dated as of December 23, 2015, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended December 31, 2015 filed with the SEC on February 9, 2016)
 
 
 
4.21*
 
Amendment No. 10 to Note Purchase Agreement, dated as of February 9, 2016, among the Partnership and the purchasers named therein
 
 
 
4.22
 
Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party 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 the SEC on October 16, 2013)
 
 
 
4.23
 
Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
 
 
 
4.24
 
First Supplemental Indenture, dated as of December 2, 2013, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.19 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with the SEC on May 30, 2014)
 
 
 
4.25
 
Second Supplemental Indenture, dated as of April 22, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiary party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.20 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with the SEC on May 30, 2014)
 
 
 
4.26
 
Third Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiary party thereto 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)
 
 
 

130
Table of Contents

Exhibit Number
Description
4.27
 
Fourth Supplemental Indenture, dated as of December 1, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.25 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
4.28
 
Fifth Supplemental Indenture, dated as of February 17, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.26 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
4.29
 
Sixth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed with the SEC on November 9, 2015)
 
 
 
4.30
 
Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
 
 
 
4.31
 
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)
 
 
 
4.32
 
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. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014)
 
 
 
4.33
 
Forms of 5.125% Senior Notes due 2019 (incorporated by reference and included as Exhibits A1 and A2 to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014)
 
 
 
4.34
 
Registration Rights Agreement, dated July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listed therein on Exhibit A and RBS Securities Inc. as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014)
 
 
 
4.35
 
First Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto 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)
 
 
 
4.36
 
Second Supplemental Indenture, dated as of December 1, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.32 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
4.37
 
Third Supplemental Indenture, dated as of February 17, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.33 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
4.38
 
Fourth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed with the SEC on November 9, 2015)
 
 
 
10.1
 
Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders party thereto and Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
 
 
 
10.2
 
Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012)
 
 
 

131
Table of Contents

Exhibit Number
Description
10.3
 
Amendment No. 1 to Credit Agreement, dated as of January 15, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18, 2013)
 
 
 
10.4
 
Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No 001-35172) filed on May 9, 2013)
 
 
 
10.5
 
Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, each subsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank Trust Company Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)
 
 
 
10.6
 
Amendment No. 4 to Credit Agreement, dated as of November 5, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
 
 
 
10.7
 
Amendment No. 5 to Credit Agreement, dated as of December 23, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank and Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30, 2013)
 
 
 
10.8
 
Facility Increase Agreement, dated as of December 30, 2013, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 3, 2014)
 
 
 
10.9
 
Amendment No. 6 to Credit Agreement, dated as of June 12, 2014, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 16, 2014)
 
 
 
10.10
 
Amendment No. 7 to Credit Agreement, dated as of June 27, 2014, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 3, 2014)
 
 
 
10.11
 
Facility Increase Agreement, dated December 1, 2014, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 1, 2014)
 
 
 
10.12
 
Amendment No. 8 to Credit Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 2, 2015)
 
 
 
10.13
 
Amendment No. 9 to Credit Agreement, dated as of May 1, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
10.14
 
Amendment No. 10 to Credit Agreement, dated as of July 31, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 4, 2015)
 
 
 
10.15
 
Facility Increase Agreement, dated October 7, 2015, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended December 31, 2015 filed with the SEC on February 9, 2016)
 
 
 

132
Table of Contents

Exhibit Number
Description
10.16
 
Amendment No. 11 to Credit Agreement, dated as of December 23, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended December 31, 2015 filed with the SEC on February 9, 2016)
 
 
 
10.17*
 
Amendment No. 12 to Credit Agreement, dated as of February 9, 2016, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto
 
 
 
10.18
 
Common Unit Purchase Agreement, dated November 5, 2013, by and among NGL Energy Partners LP and the purchasers listed 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)
 
 
 
10.19+
 
Letter Agreement among Silverthorne Energy Holdings LLC, Shawn W. Coady and Todd M. Coady dated October 14, 2010 (incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
 
 
 
10.20+
 
NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011)
 
 
 
10.21+
 
Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended June 30, 2012 filed with the SEC on August 14, 2012 )
 
 
 
10.22
 
NGL Performance Unit Program (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
12.1*

Computation of ratios of earnings to fixed charges
 
 
 
21.1*

List of Subsidiaries of NGL Energy Partners LP
 
 
 
23.1*

Consent of Grant Thornton LLP
 
 
 
31.1*

Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
31.2*

Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
32.1*

Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
32.2*

Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
101.INS**

XBRL Instance Document
 
 
 
101.SCH**

XBRL Schema Document
 
 
 
101.CAL**

XBRL Calculation Linkbase Document
 
 
 
101.DEF**

XBRL Definition Linkbase Document
 
 
 
101.LAB**

XBRL Label Linkbase Document
 
 
 
101.PRE**

XBRL Presentation Linkbase Document
 
*
Exhibits filed with this report.
**
The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at March 31, 2016 and 2015, (ii) Consolidated Statements of Operations for the years ended March 31, 2016, 2015, and 2014, (iii) Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2016, 2015, and 2014, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2016, 2015, and 2014, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2016, 2015, and 2014, and (vi) Notes to Consolidated Financial Statements.
+
Management contracts or compensatory plans or arrangements.


133
Table of Contents

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) Securities Exchange Act of 1934, as amended, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized on May 31, 2016.
 
NGL ENERGY PARTNERS LP
 
 
 
By:
NGL Energy Holdings LLC, its general partner
 
 
 
 
 
By:
/s/ H. Michael Krimbill
 
 
H. Michael Krimbill
 
 
Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, as amended, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.
Signature
 
Title
 
Date
 
 
 
 
 
/s/ H. Michael Krimbill
 
Chief Executive Officer and Director
 
May 31, 2016
H. Michael Krimbill
 
(Principal Executive Officer)
 
 
 
 
 
 
 
/s/ Robert W. Karlovich III
 
Chief Financial Officer
 
May 31, 2016
Robert W. Karlovich III
 
(Principal Financial Officer)
 
 
 
 
 
 
 
/s/ Lawrence W. Thuillier
 
Chief Accounting Officer
 
May 31, 2016
Lawrence W. Thuillier
 
(Principal Accounting Officer)
 
 
 
 
 
 
 
/s/ Christopher Beall
 
Director
 
May 31, 2016
Christopher Beall
 
 
 
 
 
 
 
 
 
/s/ James J. Burke
 
Director
 
May 31, 2016
James J. Burke
 
 
 
 
 
 
 
 
 
/s/ Shawn W. Coady
 
Director
 
May 31, 2016
Shawn W. Coady
 
 
 
 
 
 
 
 
 
/s/ James M. Collingsworth
 
Director
 
May 31, 2016
James M. Collingsworth
 
 
 
 
 
 
 
 
 
/s/ Stephen L. Cropper
 
Director
 
May 31, 2016
Stephen L. Cropper
 
 
 
 
 
 
 
 
 
/s/ Bryan K. Guderian
 
Director
 
May 31, 2016
Bryan K. Guderian
 
 
 
 
 
 
 
 
 
/s/ James C. Kneale
 
Director
 
May 31, 2016
James C. Kneale
 
 
 
 
 
 
 
 
 
/s/ Vincent J. Osterman
 
Director
 
May 31, 2016
Vincent J. Osterman
 
 
 
 
 
 
 
 
 
 
 
Director
 
May 31, 2016
John T. Raymond
 
 
 
 
 
 
 
 
 
 
 
Director
 
May 31, 2016
Patrick Wade
 
 
 
 

134
Table of Contents

INDEX TO FINANCIAL STATEMENTS
 
NGL ENERGY PARTNERS LP
 
 
 
Report of Independent Registered Public Accounting Firm
F-2
 
 
Consolidated Balance Sheets at March 31, 2016 and 2015
F-4
 
 
Consolidated Statements of Operations for the years ended March 31, 2016, 2015, and 2014
F-5
 
 
Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2016, 2015, and 2014
F-6
 
 
Consolidated Statements of Changes in Equity for the years ended March 31, 2016, 2015, and 2014
F-7
 
 
Consolidated Statements of Cash Flows for the years ended March 31, 2016, 2015, and 2014
F-8
 
 
Notes to Consolidated Financial Statements
F-10


F-1
Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners
NGL Energy Partners LP

We have audited the accompanying consolidated balance sheets of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of March 31, 2016 and 2015, and the related consolidated statements of operations, comprehensive income (loss), changes in equity, and cash flows for each of the three years in the period ended March 31, 2016. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our 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 Energy Partners LP and subsidiaries as of March 31, 2016 and 2015, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2016 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, the Partnership adopted new accounting guidance in 2016 and 2015 related to the presentation of debt issuance costs.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership’s internal control over financial reporting as of March 31, 2016, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 31, 2016 expressed an unqualified opinion.

/s/ GRANT THORNTON LLP
 
 
 
Tulsa, Oklahoma
 
May 31, 2016
 


F-2
Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners
NGL Energy Partners LP

We have audited the internal control over financial reporting of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the “Partnership”) as of March 31, 2016, based on criteria established in the 2013 Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting (“Management’s Report”). Our responsibility is to express an opinion on the Partnership’s internal control 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 standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we 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 financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal 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 as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of March 31, 2016, based on criteria 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 consolidated financial statements of the Partnership as of and for the year ended March 31, 2016, and our report dated May 31, 2016 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP
 
 
 
Tulsa, Oklahoma
 
May 31, 2016
 


F-3
Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Balance Sheets
(U.S. Dollars in Thousands, except unit amounts)
 
March 31,
 
2016
 
2015
ASSETS
 
 
 
CURRENT ASSETS:
 
 
 
Cash and cash equivalents
$
28,176

 
$
41,303

Accounts receivable-trade, net of allowance for doubtful accounts of $6,928 and $4,367, respectively
521,014

 
1,025,763

Accounts receivable-affiliates
15,625

 
17,198

Inventories
367,806

 
442,025

Prepaid expenses and other current assets
95,859

 
121,207

Total current assets
1,028,480

 
1,647,496

 
 
 
 
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $266,491 and $202,959, respectively
1,649,572

 
1,624,016

GOODWILL
1,315,362

 
1,558,233

INTANGIBLE ASSETS, net of accumulated amortization of $316,878 and $216,493, respectively
1,148,890

 
1,232,308

INVESTMENTS IN UNCONSOLIDATED ENTITIES
219,550

 
472,673

LOAN RECEIVABLE-AFFILIATE
22,262

 
8,154

OTHER NONCURRENT ASSETS
176,039

 
112,912

Total assets
$
5,560,155

 
$
6,655,792

 
 
 
 
LIABILITIES AND EQUITY
 
 
 
CURRENT LIABILITIES:
 
 
 
Accounts payable-trade
$
420,306

 
$
833,018

Accounts payable-affiliates
7,193

 
25,794

Accrued expenses and other payables
214,426

 
202,349

Advance payments received from customers
56,185

 
54,234

Current maturities of long-term debt
7,907

 
4,472

Total current liabilities
706,017

 
1,119,867

 
 
 
 
LONG-TERM DEBT, net of debt issuance costs of $15,500 and $17,835, respectively, and current maturities
2,912,837

 
2,727,464

OTHER NONCURRENT LIABILITIES
247,236

 
115,029

 
 
 
 
COMMITMENTS AND CONTINGENCIES (NOTE 10)
0

 
0

 
 
 
 
EQUITY:
 
 
 
General partner, representing a 0.1% interest, 104,274 and 103,899 notional units, respectively
(50,811
)
 
(37,000
)
Limited partners, representing a 99.9% interest, 104,169,573 and 103,794,870 common units issued and outstanding, respectively
1,707,326

 
2,183,551

Accumulated other comprehensive loss
(157
)
 
(109
)
Noncontrolling interests
37,707

 
546,990

Total equity
1,694,065

 
2,693,432

Total liabilities and equity
$
5,560,155

 
$
6,655,792


The accompanying notes are an integral part of these consolidated financial statements.

F-4
Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Operations
(U.S. Dollars in Thousands, except unit and per unit amounts)
 
Year Ended March 31,
 
2016
 
2015
 
2014
REVENUES:
 
 
 
 
 
Crude oil logistics
$
3,217,079

 
$
6,635,384

 
$
4,558,545

Water solutions
185,001

 
200,042

 
143,100

Liquids
1,194,479

 
2,243,825

 
2,650,425

Retail propane
352,977

 
489,197

 
551,815

Refined products and renewables
6,792,112

 
7,231,693

 
1,357,676

Other
462

 
1,916

 
437,713

Total Revenues
11,742,110

 
16,802,057

 
9,699,274

 
 
 
 
 
 
COST OF SALES:
 
 
 
 
 
Crude oil logistics
3,111,717

 
6,560,506

 
4,477,397

Water solutions
(7,336
)
 
(30,506
)
 
11,738

Liquids
1,037,118

 
2,111,614

 
2,518,099

Retail propane
156,757

 
278,538

 
354,676

Refined products and renewables
6,540,599

 
7,035,472

 
1,344,176

Other
182

 
2,583

 
426,613

Total Cost of Sales
10,839,037

 
15,958,207

 
9,132,699

 
 
 
 
 
 
OPERATING COSTS AND EXPENSES:
 
 
 
 
 
Operating
401,118

 
364,131

 
259,799

General and administrative
139,541

 
149,430

 
75,860

Depreciation and amortization
228,924

 
193,949

 
120,754

Loss on disposal or impairment of assets, net
320,766

 
41,184

 
3,597

Revaluation of liabilities
(82,673
)
 
(12,264
)
 
—

Operating (Loss) Income
(104,603
)
 
107,420

 
106,565

 
 
 
 
 
 
OTHER INCOME (EXPENSE):
 
 
 
 
 
Equity in earnings of unconsolidated entities
16,121

 
12,103

 
1,898

Interest expense
(133,089
)
 
(110,123
)
 
(58,854
)
Gain on early extinguishment of debt
28,532

 
—

 
—

Other income, net
5,575

 
37,171

 
86

(Loss) Income Before Income Taxes
(187,464
)
 
46,571

 
49,695

 
 
 
 
 
 
INCOME TAX BENEFIT (EXPENSE)
367

 
3,622

 
(937
)
 
 
 
 
 
 
Net (Loss) Income
(187,097
)
 
50,193

 
48,758

 
 
 
 
 
 
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER
(47,620
)
 
(45,700
)
 
(14,148
)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
(11,832
)
 
(12,887
)
 
(1,103
)
NET (LOSS) INCOME ALLOCATED TO LIMITED PARTNERS
$
(246,549
)
 
$
(8,394
)
 
$
33,507

 
 
 
 
 
 
BASIC AND DILUTED (LOSS) INCOME PER COMMON UNIT
$
(2.35
)
 
$
(0.05
)
 
$
0.51

BASIC AND DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
104,838,886

 
86,359,300

 
61,970,471

 
The accompanying notes are an integral part of these consolidated financial statements.

F-5
Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Comprehensive Income (Loss)
(U.S. Dollars in Thousands)

 
Year Ended March 31,
 
2016
 
2015
 
2014
Net (loss) income
$
(187,097
)
 
$
50,193

 
$
48,758

Other comprehensive (loss) income
(48
)
 
127

 
(260
)
Comprehensive (loss) income
$
(187,145
)
 
$
50,320

 
$
48,498


The accompanying notes are an integral part of these consolidated financial statements.


F-6
Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Changes in Equity
For the Years Ended March 31, 2016, 2015, and 2014
(U.S. Dollars in Thousands, except unit amounts)

 
 
 
Limited Partners
 
 
 
 
 
 
 
General
Partner
 
Common
Units
 
Amount
 
Subordinated
Units
 
Amount
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interests
 
Total
Equity
BALANCES AT MARCH 31, 2013
$
(50,497
)
 
47,703,313

 
$
920,998

 
5,919,346

 
$
13,153

 
$
24

 
$
5,740

 
$
889,418

Distributions
(9,703
)
 
—

 
(123,467
)
 
—

 
(11,920
)
 
—

 
(840
)
 
(145,930
)
Contributions
765

 
—

 
—

 
—

 
—

 
—

 
2,060

 
2,825

Business combinations
—

 
2,860,879

 
80,591

 
—

 
—

 
—

 
—

 
80,591

Sales of units, net of offering costs
—

 
22,560,848

 
650,155

 
—

 
—

 
—

 
—

 
650,155

Equity issued pursuant to incentive compensation plan
—

 
296,269

 
9,085

 
—

 
—

 
—

 
—

 
9,085

Disposal of noncontrolling interest
—

 
—

 
—

 
—

 
—

 
—

 
(2,789
)
 
(2,789
)
Net income
14,148

 
—

 
32,712

 
—

 
795

 
—

 
1,103

 
48,758

Other comprehensive loss
—

 
—

 
—

 
—

 
—

 
(260
)
 
—

 
(260
)
BALANCES AT MARCH 31, 2014
(45,287
)
 
73,421,309

 
1,570,074

 
5,919,346

 
2,028

 
(236
)
 
5,274

 
1,531,853

Distributions
(38,236
)
 
—

 
(197,611
)
 
—

 
(6,748
)
 
—

 
(27,147
)
 
(269,742
)
Contributions
823

 
—

 
—

 
—

 
—

 
—

 
9,433

 
10,256

Business combinations
—

 
8,851,105

 
259,937

 
—

 
—

 
—

 
546,740

 
806,677

Sales of units, net of offering costs
—

 
15,017,100

 
541,128

 
—

 
—

 
—

 
—

 
541,128

Equity issued pursuant to incentive compensation plan
—

 
586,010

 
23,134

 
—

 
—

 
—

 
—

 
23,134

Net income (loss)
45,700

 
—

 
(4,479
)
 
—

 
(3,915
)
 
—

 
12,887

 
50,193

Other comprehensive income
—

 
—

 
—

 
—

 
—

 
127

 
—

 
127

Conversion of subordinated units to common units
—

 
5,919,346

 
(8,635
)
 
(5,919,346
)
 
8,635

 
—

 
—

 
—

Other
—

 
—

 
3

 
—

 
—

 
—

 
(197
)
 
(194
)
BALANCES AT MARCH 31, 2015
(37,000
)
 
103,794,870

 
2,183,551

 
—

 
—

 
(109
)
 
546,990

 
2,693,432

Distributions
(61,485
)
 
—

 
(260,522
)
 
—

 
—

 
—

 
(35,720
)
 
(357,727
)
Contributions
54

 
—

 
(3,829
)
 
—

 
—

 
—

 
15,376

 
11,601

Business combinations
—

 
833,454

 
19,108

 
—

 
—

 
—

 
9,248

 
28,356

Equity issued pursuant to incentive compensation plan
—

 
1,165,053

 
33,290

 
—

 
—

 
—

 
—

 
33,290

Common 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

 
1,301

Other
—

 
—

 
(43
)
 
—

 
—

 
—

 
(29
)
 
(72
)
BALANCES AT MARCH 31, 2016
$
(50,811
)
 
104,169,573

 
$
1,707,326

 
—

 
$
—

 
$
(157
)
 
$
37,707

 
$
1,694,065


The accompanying notes are an integral part of these consolidated financial statements.


F-7
Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Consolidated Statements of Cash Flows
(U.S. Dollars in Thousands)
 
Year Ended March 31,
 
2016
 
2015
 
2014
OPERATING ACTIVITIES:
 
 
 
 
 
Net (loss) income
$
(187,097
)
 
$
50,193

 
$
48,758

Adjustments to reconcile net (loss) income to net cash provided by operating activities:
 
 
 
 
 
Depreciation and amortization, including amortization of debt issuance costs
249,211

 
210,475

 
132,653

Gain on early extinguishment of debt
(28,532
)
 
—

 
—

Non-cash equity-based compensation expense
51,565

 
32,767

 
14,054

Loss on disposal or impairment of assets, net
320,766

 
41,184

 
3,597

Revaluation of liabilities
(82,673
)
 
(12,264
)
 
—

Provision for doubtful accounts
5,628

 
4,105

 
2,445

Net commodity derivative (gain) loss
(103,223
)
 
(219,421
)
 
43,655

Equity in earnings of unconsolidated entities
(16,121
)
 
(12,103
)
 
(1,898
)
Distributions of earnings from unconsolidated entities
17,404

 
12,539

 
—

Other
(47
)
 
124

 
312

Changes in operating assets and liabilities, exclusive of acquisitions:
 
 
 
 
 
Accounts receivable-trade
497,560

 
50,620

 
21,115

Accounts receivable-affiliates
7,980

 
(9,225
)
 
18,002

Inventories
74,686

 
243,292

 
(73,321
)
Prepaid expenses and other assets
10,572

 
(34,505
)
 
20,308

Accounts payable-trade
(421,210
)
 
(1,965
)
 
(167,060
)
Accounts payable-affiliates
(18,499
)
 
(51,121
)
 
67,361

Accrued expenses and other liabilities
(26,665
)
 
(61,889
)
 
(41,671
)
Advance payments received from customers
190

 
19,585

 
(3,074
)
Net cash provided by operating activities
351,495

 
262,391

 
85,236

 
 
 
 
 
 
INVESTING ACTIVITIES:
 
 
 
 
 
Purchases of long-lived assets
(661,885
)
 
(203,760
)
 
(165,148
)
Purchases of pipeline capacity allocations
—

 
(24,218
)
 
—

Purchase of equity interest in Grand Mesa Pipeline
—

 
(310,000
)
 
—

Acquisitions of businesses, including acquired working capital, net of cash acquired
(234,652
)
 
(960,922
)
 
(1,268,810
)
Cash flows from commodity derivatives
105,662

 
199,165

 
(35,956
)
Proceeds from sales of assets
8,455

 
26,262

 
24,660

Proceeds from sale of general partner interest in TLP, net
343,135

 
—

 
—

Investments in unconsolidated entities
(11,431
)
 
(33,528
)
 
(11,515
)
Distributions of capital from unconsolidated entities
15,792

 
10,823

 
1,591

Loan for natural gas liquids facility
(3,913
)
 
(63,518
)
 
—

Payments on loan for natural gas liquids facility
7,618

 
1,625

 
—

Loan to affiliate
(15,621
)
 
(8,154
)
 
—

Payments on loan to affiliate
1,513

 
—

 
—

Other
—

 
4

 
(195
)
Net cash used in investing activities
(445,327
)
 
(1,366,221
)
 
(1,455,373
)
 
 
 
 
 
 
FINANCING ACTIVITIES:
 
 
 
 
 
Proceeds from borrowings under revolving credit facilities
2,602,500

 
3,764,500

 
2,545,500

Payments on revolving credit facilities
(2,133,000
)
 
(3,280,000
)
 
(2,101,000
)
Issuances of notes
—

 
400,000

 
450,000

Repurchases of senior notes
(43,421
)
 
—

 
—

Proceeds from borrowings under other long-term debt
53,223

 
—

 
880

Payments on other long-term debt
(5,087
)
 
(6,688
)
 
(8,819
)
Debt issuance costs
(10,237
)
 
(11,076
)
 
(24,595
)

F-8
Table of Contents

Contributions from general partner
54

 
823

 
765

Contributions from limited partner
(3,829
)
 
—

 
—

Contributions from noncontrolling interest owners
15,376

 
9,433

 
2,060

Distributions to partners
(322,007
)
 
(242,595
)
 
(145,090
)
Distributions to noncontrolling interest owners
(35,720
)
 
(27,147
)
 
(840
)
Taxes paid on behalf of equity incentive plan participants
(19,395
)
 
(13,491
)
 
—

Common unit repurchases
(17,680
)
 
—

 
—

Proceeds from sale of common units, net of offering costs
—

 
541,128

 
650,155

Other
(72
)
 
(194
)
 
—

Net cash provided by financing activities
80,705

 
1,134,693

 
1,369,016

Net (decrease) increase in cash and cash equivalents
(13,127
)
 
30,863

 
(1,121
)
Cash and cash equivalents, beginning of period
41,303

 
10,440

 
11,561

Cash and cash equivalents, end of period
$
28,176

 
$
41,303

 
$
10,440


The accompanying notes are an integral part of these consolidated financial statements.


F-9
Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES
Notes to Consolidated Financial Statements
At March 31, 2016 and 2015, and for the Years Ended March 31, 2016, 2015, and 2014

Note 1—Nature of Operations and Organization

NGL Energy Partners LP (“we,” “us,” “our,” or the “Partnership”) is a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. On May 17, 2011, we completed our initial public offering (“IPO”). Subsequent to our IPO, we significantly expanded our operations through numerous acquisitions as discussed in Note 4. At March 31, 2016, our operations include:

•
Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals and pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned barges and towboats, and interests in two crude oil pipelines. Our crude oil logistics segment purchases crude oil from producers and transports it to refineries or for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.
•
Our water solutions segment, the assets of which include water pipelines, water treatment and disposal facilities, washout facilities, and solid waste disposal facilities. Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production and for the disposal of solids such as tank bottoms and drilling fluids and performs truck washouts. In addition, our water solutions segment sells the recycled water and recovered hydrocarbons that result from performing these services.
•
Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling and storage services through its 19 owned terminals throughout the United States, its salt dome storage facility in Utah, and its leased storage and railcar transportation services through its fleet of leased railcars.
•
Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia.
•
Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We purchase refined petroleum and renewable products primarily in the Gulf Coast, Southeast and Midwest regions of the United States and schedule them for delivery at various locations. See Note 14 for a discussion of our interests in TransMontaigne Partners L.P. (“TLP”).

Recent Developments

On February 1, 2016, we completed the sale of our general partner interest in TLP to an affiliate of ArcLight Capital Partners (“ArcLight”). As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. See Note 14 for a discussion of the sale. Our investment in TLP is included in investments in unconsolidated entities in our consolidated balance sheet. As TLP was previously a consolidated entity, our consolidated statement of operations includes ten months of TLP’s operations and income attributable to the noncontrolling interests of TLP, and two months of our equity in earnings of TLP, the period after the deconsolidation.
 
Note 2—Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States (“GAAP”). The accompanying consolidated financial statements include our accounts and those of our controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation. Investments we cannot control, but can exercise significant influence over, are accounted for using the equity method of accounting. We also own an undivided interest in a crude oil pipeline (see Note 16). We will include our proportionate share of assets, liabilities, and expenses related to this pipeline in our consolidated financial statements.

We have reclassified certain prior period financial statement information to be consistent with the classification methods used in the current fiscal year. These reclassifications did not impact previously reported amounts of equity, net income, or cash flows. In addition, certain balances at March 31, 2015 were adjusted to reflect the final acquisition accounting for certain business combinations.

F-10
Table of Contents


In the fourth quarter of fiscal year 2016, we identified an immaterial error in our previously issued financial statements for the year ended March 31, 2015. We have changed our previously issued consolidated balance sheet as of March 31, 2015 and consolidated statements of operations, consolidated statement of comprehensive income, consolidated statement of changes in equity, and consolidated statement of cash flows for the year ended March 31, 2015 for the correction of this immaterial error. The impact of this error correction is more specifically described  in Note 17.

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the amount of assets and liabilities reported at the date of the consolidated financial statements and the amount of revenues and expenses reported during the periods presented.

Critical estimates we make in the preparation of our consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations, the collectability of accounts receivable, the recoverability of inventories, useful lives and recoverability of property, plant and equipment and amortizable intangible assets, the impairment of assets, the fair value of asset retirement obligations, the value of equity-based compensation, and accruals for various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual results could differ from those estimates.

Fair Value Measurements

We record our commodity derivative instruments and assets and liabilities acquired in business combinations at fair value. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability. We use the following fair value hierarchy, which prioritizes valuation technique inputs used to measure fair value into three broad levels:

•
Level 1—Quoted prices in active markets for identical assets and liabilities that we have the ability to access at the measurement date.
•
Level 2—Inputs (other than quoted prices included within Level 1) that are either directly or indirectly observable for the asset or liability, including (i) quoted prices for similar assets or liabilities in active markets, (ii) quoted prices for identical or similar assets or liabilities in inactive markets, (iii) inputs other than quoted prices that are observable for the asset or liability, and (iv) inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts. We determine the fair value of all of our derivative financial instruments utilizing pricing models for similar instruments. Inputs to the pricing models include publicly available prices and forward curves generated from a compilation of data gathered from third parties.
•
Level 3—Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to a fair value measurement requires judgment, considering factors specific to the asset or liability.

Derivative Financial Instruments

We record all derivative financial instrument contracts at fair value in our consolidated balance sheets except for certain contracts that qualify for 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.

We have not designated any financial instruments as hedges for accounting purposes. All changes in the fair value of our commodity derivative instruments that do not qualify as normal purchases and normal sales (whether cash transactions or non-cash mark-to-market adjustments) are reported within cost of sales in our consolidated statements of operations, regardless of whether the contract is physically or financially settled.

F-11
Table of Contents


We utilize various commodity derivative financial instrument contracts to attempt to reduce our exposure to price fluctuations. We do not enter into such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of 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 master netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions.

Revenue Recognition

We record product sales revenues when title to the product transfers to the purchaser, which typically occurs when the purchaser receives the product. We record terminaling, transportation, storage, and service revenues when the service is performed, and we record tank and other rental revenues over the lease term. Several of our terminaling service agreements with throughput customers, allow us to receive the product volume gained resulting from differences between the measurement of product volumes received and distributed at our terminaling facilities. Such differences are due to the inherent variances in measurement devices and methodology. We record revenues for the net proceeds from the sale of the product gained. Revenues for our water solutions segment are recognized when we obtain the wastewater at our treatment and disposal facilities.

We report taxes collected from customers and remitted to taxing authorities, such as sales and use taxes, on a net basis. We include amounts billed to customers for shipping and handling costs in revenues in our consolidated statements of operations. We enter into certain contracts whereby we agree to purchase product from a counterparty and sell the same volume of product to the same counterparty at a different location or time. When such agreements are entered into at the same time and in contemplation of each other, we record the revenues for these transactions net of cost of sales.

Revenues include $5.8 million and $0.7 million during the years ended March 31, 2016 and 2015, respectively, associated with the amortization of a liability recorded in the acquisition accounting for an acquired business related to certain out-of-market revenue contracts.

Cost of Sales

We include all costs we incur to acquire products, including the costs of purchasing, terminaling, and transporting inventory, prior to delivery to our customers, in cost of sales. Cost of sales excludes depreciation of our property, plant and equipment. Cost of sales includes amortization of certain contract-based intangible assets of $6.7 million, $7.8 million, and $6.2 million during the years ended March 31, 2016, 2015, and 2014, respectively.

Depreciation and Amortization

Depreciation and amortization in our consolidated statements of operations includes all depreciation of our property, plant and equipment and amortization of intangible assets other than debt issuance costs, for which the amortization is recorded to interest expense, and certain contract-based intangible assets, for which the amortization is recorded to cost of sales.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase. At times, certain account balances may exceed federally insured limits.


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Supplemental Cash Flow Information

Supplemental cash flow information is as follows for the periods indicated:
 
 
Year Ended March 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees
 
$
117,185

 
$
90,556

 
$
31,827

Income taxes paid (net of income tax refunds)
 
$
2,300

 
$
22,816

 
$
1,639


Cash flows from settlements of commodity derivative instruments are classified as cash flows from investing activities in our consolidated statements of cash flows, and adjustments to the fair value of commodity derivative instruments are included in operating activities.

Accounts Receivable and Concentration of Credit Risk

We operate in the United States and Canada. We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each customer’s creditworthiness as well as general economic conditions. The allowance for doubtful accounts is based on our assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. Accounts receivable are considered past due or delinquent based on contractual terms. We write off accounts receivable against 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 the extent a netting agreement is in place and we intend to settle on a net basis.

Our accounts receivable consist of the following at the dates indicated:
 
 
March 31, 2016
 
March 31, 2015
Segment
 
Gross
Receivable
 
Allowance for
Doubtful Accounts
 
Gross
Receivable
 
Allowance for
Doubtful Accounts
 
 
(in thousands)
Crude oil logistics
 
$
175,341

 
$
8

 
$
600,896

 
$
382

Water solutions
 
34,952

 
4,514

 
38,689

 
709

Liquids
 
73,478

 
505

 
99,699

 
1,133

Retail propane
 
31,583

 
965

 
55,147

 
1,619

Refined products and renewables
 
211,259

 
936

 
234,802

 
524

Other
 
1,329

 
—

 
897

 
—

Total
 
$
527,942

 
$
6,928

 
$
1,030,130

 
$
4,367


Changes in the allowance for doubtful accounts are as follows for the periods indicated:
 
 
Year Ended March 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Allowance for doubtful accounts, beginning of period
 
$
4,367

 
$
2,822

 
$
1,760

Provision for doubtful accounts
 
5,628

 
4,105

 
2,445

Write off of uncollectible accounts
 
(3,067
)
 
(2,560
)
 
(1,383
)
Allowance for doubtful accounts, end of period
 
$
6,928

 
$
4,367

 
$
2,822


We did not have any customers that represented over 10% of consolidated revenues for fiscal years 2016, 2015 and 2014.


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Inventories

We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. Market is determined based on estimated replacement cost using prices at the end of the reporting period. In performing this analysis, we consider fixed-price forward commitments and the opportunity to transfer propane inventory from our wholesale liquids business to our retail propane business to sell the inventory in retail markets. At March 31, 2016 and 2015, our inventory values were reduced by $13.3 million and $16.8 million, respectively, of lower of cost or market adjustments.

Inventories consist of the following at the dates indicated:
 
 
March 31,
 
 
2016
 
2015
 
 
(in thousands)
Crude oil
 
$
84,030

 
$
145,412

Natural gas liquids—
 
 
 
 
Propane
 
28,639

 
44,798

Butane
 
8,461

 
8,668

Other
 
6,011

 
3,874

Refined products—
 
 
 
 
Gasoline
 
80,569

 
128,092

Diesel
 
99,398

 
59,097

Renewables
 
52,458

 
44,668

Other
 
8,240

 
7,416

Total
 
$
367,806

 
$
442,025


Investments in Unconsolidated Entities

We own noncontrolling interests in certain entities. We account for these investments using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our consolidated 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 capital contributions and decreased by our proportionate share of any losses, distributions paid, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the historical net book value of the net assets of the investee.

As discussed below, on February 1, 2016, we sold our general partner interest in TLP. As a result, on February 1, 2016, we deconsolidated TLP and began to account for our limited partner investment in TLP using the equity method of accounting. Also, as part of the deconsolidation of TLP, our previous investments in Battleground 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.


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Our investments in unconsolidated entities consist of the following at the dates indicated:
 
 
 
 
Ownership
 
Date Acquired
 
March 31,
Entity
 
Segment
 
Interest
 
or Formed
 
2016
 
2015
 
 
 
 
 
 
 
 
(in thousands)
Glass Mountain (1)
 
Crude oil logistics
 
50.0%
 
December 2013
 
$
179,594

 
$
187,590

TLP (2)
 
Refined products and renewables
 
19.6%
 
July 2014
 
8,301

 
—

BOSTCO (3)
 
Refined products and renewables
 
42.5%
 
July 2014
 
—

 
238,146

Frontera (3)
 
Refined products and renewables
 
50.0%
 
July 2014
 
—

 
16,927

Water supply company
 
Water solutions
 
35.0%
 
June 2014
 
15,875

 
16,471

Water treatment and disposal facility
 
Water solutions
 
50.0%
 
August 2015
 
2,238

 
—

Ethanol production facility
 
Refined products and renewables
 
19.0%
 
December 2013
 
12,570

 
13,539

Retail propane company
 
Retail propane
 
50.0%
 
April 2015
 
972

 
—

Total
 
 
 
 
 
 
 
$
219,550

 
$
472,673

 
 
(1)
When we acquired Gavilon Energy, we recorded the investment in Glass Mountain, which owns a crude oil pipeline in Oklahoma, at fair value. Our investment in Glass Mountain exceeds our proportionate share of the historical net book value of Glass Mountain’s net assets by $74.6 million at March 31, 2016. This difference relates primarily to goodwill and customer relationships.
(2)
On February 1, 2016, we deconsolidated TLP (see Note 1 and Note 14), and as a result, we recorded our equity method investment in TLP. On April 1, 2016, we sold all of the TLP common units that we held (see Note 19).
(3)
As part of the deconsolidation of TLP on February 1, 2016, our previous investments in BOSTCO and Frontera are no longer disclosed as investments in unconsolidated entities.

The following table summarizes the cumulative earnings (loss) from our unconsolidated entities and cumulative distributions received from our unconsolidated entities at March 31, 2016:
Entity
 
Cumulative Earnings (Loss) From Unconsolidated Entities
 
Cumulative Distributions Received From Unconsolidated Entities
 
 
(in thousands)
Glass Mountain
 
$
7,251

 
$
23,260

TLP
 
807

 
—

BOSTCO
 
13,432

 
23,491

Frontera
 
3,779

 
4,274

Water supply company
 
(625
)
 
—

Water treatment and disposal facility
 
44

 
96

Ethanol production facility
 
5,961

 
7,028

Retail propane company
 
(528
)
 
—



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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,
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
(in thousands)
Glass Mountain
$
7,248

 
$
8,456

 
$
204,020

 
$
214,494

 
$
1,268

 
$
1,080

 
$
24

 
$
37

TLP
10,419

 
—

 
652,309

 
—

 
18,812

 
—

 
267,373

 
—

BOSTCO
—

 
13,710

 
—

 
507,655

 
—

 
11,189

 
—

 
—

Frontera
—

 
4,608

 
—

 
43,805

 
—

 
1,370

 
—

 
—

Water supply company
2,589

 
3,160

 
28,150

 
32,447

 
2,923

 
644

 
20,746

 
26,251

Water treatment and disposal facility
91

 
—

 
4,476

 
—

 
124

 
—

 
—

 
—

Ethanol production facility
34,477

 
38,607

 
90,310

 
85,277

 
14,616

 
15,755

 
30,730

 
21,403

Retail propane company
700

 
—

 
2,248

 
—

 
555

 
—

 
449

 
—


Statements of operations -
 
Revenues
 
Cost of Sales
 
Net Income (Loss)
 
March 31,
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
 
2016
 
2015
 
2014
 
(in thousands)
Glass Mountain
$
35,978

 
$
37,539

 
$
3,979

 
$
1,943

 
2,771

 
$
—

 
$
11,227

 
$
12,345

 
$
445

TLP
28,258

 
—

 
—

 
—

 
—

 
—

 
6,083

 
—

 
—

BOSTCO
60,420

 
45,067

 
—

 
—

 
—

 
—

 
21,987

 
11,074

 
—

Frontera
14,114

 
10,643

 
—

 
—

 
—

 
—

 
4,091

 
1,352

 
—

Water supply company
4,062

 
8,326

 
—

 
—

 
—

 
—

 
(1,618
)
 
(104
)
 
—

Water treatment and disposal facility
777

 
—

 
—

 
—

 
—

 
—

 
85

 
—

 
—

Ethanol production facility
129,533

 
159,148

 
61,929

 
105,161

 
117,222

 
39,449

 
5,796

 
24,607

 
17,599

Retail propane company
715

 
—

 
—

 
321

 
—

 
—

 
(1,056
)
 
—

 
—


Other Noncurrent Assets

Other noncurrent assets consist of the following at the dates indicated:
 
 
March 31,
 
 
2016
 
2015
 
 
(in thousands)
Loan receivable (1)
 
$
49,827

 
$
58,050

Linefill (2)
 
35,060

 
35,060

Tank bottoms (3)
 
42,044

 
—

Other
 
49,108

 
19,802

Total
 
$
176,039

 
$
112,912

 
(1)
Represents a loan receivable associated with our financing of the construction of a natural gas liquids facility to be utilized by a third party.
(2)
Represents minimum volumes of crude oil we are required to leave on certain third-party owned pipelines under long-term shipment commitments. At March 31, 2016, linefill consisted of 487,104 barrels of crude oil.

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(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 are removed from service. At March 31, 2016, tank bottoms held in third party terminals consisted of 366,212 barrels of refined products. Tank bottoms held in terminals we own are included within property, plant and equipment (see Note 5).

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following at the dates indicated:
 
 
March 31,
 
 
2016
 
2015
 
 
(in thousands)
Accrued compensation and benefits
 
$
40,517

 
$
52,078

Excise and other tax liabilities
 
59,455

 
43,847

Derivative liabilities
 
28,612

 
27,950

Accrued interest
 
20,543

 
23,065

Product exchange liabilities
 
5,843

 
15,480

Deferred gain on sale of general partner interest in TLP
 
30,113

 
—

Other
 
29,343

 
39,929

Total
 
$
214,426

 
$
202,349


Property, Plant and Equipment

We record property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. As we dispose of assets, we remove the cost and related accumulated depreciation from the accounts, and any resulting gain or loss is included in loss on disposal or impairment of assets, net. We compute depreciation expense on a majority of our property, plant and equipment using the straight-line method over the estimated useful lives of the assets (see Note 5).

We evaluate the carrying value of our property, plant and equipment for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is less than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group (see Note 14).

Intangible Assets

Our intangible assets include contracts and arrangements acquired in business combinations, including customer relationships, pipeline capacity rights, a water facility development agreement, executory contracts and other agreements, covenants not to compete, trade names, and customer commitments. In addition, we capitalize certain debt issuance costs associated with our revolving credit facilities. We amortize the majority of our intangible assets on a straight-line basis over the assets estimated useful lives (see Note 7). We amortize debt issuance costs over the terms of the related debt on a method that approximates the effective interest method.

We evaluate the carrying value of our amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from 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 the carrying value exceeds the fair value of the asset group. When we cease to use an acquired trade name, we test the trade name for impairment using the “relief from royalty” method and we begin amortizing the trade name over its estimated useful life as a defensive asset.


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Table of Contents

Debt Issuance Costs

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015-03, “Simplifying the Presentation of Debt Issuance Costs.” On March 31, 2016, we adopted this ASU, which requires certain debt issuance costs to be reported as a reduction to the carrying amount of the long-term debt. This ASU does not apply to debt issuance costs related to revolving credit facilities, and we continue to report such debt issuance costs as intangible assets. We have applied this ASU retrospectively to our March 31, 2015 consolidated balance sheet. The following table compares the intangible asset and long-term debt balances as currently reported to the amounts that would have been reported under the old accounting standard:
 
 
At March 31,
 
 
2016
 
2015
 
 
Current Standard
 
Previous Standard
 
Current Standard
 
Previous Standard
 
 
(in thousands)
Intangible assets
 
$
1,148,890

 
$
1,164,390

 
$
1,232,308

 
$
1,250,143

Long-term debt
 
2,912,837

 
2,928,337

 
2,727,464

 
2,745,299


Goodwill

Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Business combinations are accounted for using the “acquisition method” (see Note 4). We expect that substantially all of our goodwill at March 31, 2016 is deductible for income tax purposes.

Goodwill and indefinite-lived intangible assets are not amortized, but instead are evaluated for impairment periodically. We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant.

To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. If we conclude that it is more likely than not that the fair value of a reporting unit exceeds its carrying amount, we perform the following two-step goodwill impairment test:

•
In the first step of the goodwill impairment test, we compare the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amount of a reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of impairment loss, if any.
•
In the second step of the goodwill impairment test, we compare the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess.

Estimates and assumptions used to perform the impairment evaluation are inherently uncertain and can significantly affect the outcome of the analysis. The estimates and assumptions we used in the annual assessment for impairment of goodwill included market participant considerations and future forecasted operating results. Changes in operating results and other assumptions could materially affect these estimates. See Note 14 further a further discussion and analysis of our goodwill impairment assessment.

Product Exchanges

Quantities of products receivable or returnable under exchange agreements are reported within prepaid expenses and other current assets or within accrued expenses and other payables in our consolidated balance sheets. We estimate the value of product exchange assets and liabilities based on the weighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus or minus location differentials.


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Advance Payments Received from Customers

We record customer advances on product purchases as a liability in our consolidated balance sheets.

Noncontrolling Interests

We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated financial statements represents the other owners’ interest in these entities.

As previously reported, as part of our acquisition of TransMontaigne on July 1, 2014, we acquired the 2% general partner interest and a 19.7% limited partner interest in TLP. We attributed net earnings allocable to TLP’s limited partners to the controlling and noncontrolling interests based on the relative ownership interests in TLP. Earnings allocable to TLP’s limited partners were net of the earnings allocable to TLP’s general partner interest. Earnings allocable to TLP’s general partner interest include the distributions of cash attributable to the period to TLP’s general partner interest and incentive distribution rights, net of adjustments for TLP’s general partner’s proportionate share of undistributed earnings. Undistributed earnings were allocated to TLP’s limited partners and TLP’s general partner interest based on their ownership percentages of 98% and 2%, respectively. 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 partner investment in TLP using the equity method of accounting. See Note 14 for a further discussion of the sale of the TLP general partner.

Business Combination Measurement Period

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination. As described 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 described in Note 4, we made certain adjustments during the year ended March 31, 2016 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2015. We retrospectively adjusted the March 31, 2015 consolidated balance sheet for these adjustments. Due to the immateriality of these adjustments, we did not retrospectively adjust our consolidated statement of operations for the year ended March 31, 2015 for these measurement period adjustments.

Recent Accounting Pronouncements

In February 2016, the FASB issued ASU No. 2016-02, “Leases.” The ASU will replace previous lease accounting guidance in GAAP. The ASU requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. The ASU retains a distinction between finance leases and operating leases. The ASU is effective for the Partnership beginning April 1, 2019, and requires a modified retrospective method of adoption. We are in the process of assessing the impact of this ASU on our consolidated financial statements.

In July 2015, the FASB issued ASU No. 2015-11, “Simplifying the Measurement of Inventory.” The ASU requires that inventory within the scope of the guidance be measured at the lower of cost or net realizable value. The ASU is effective for the Partnership beginning April 1, 2017, and requires a prospective method of adoption, although early adoption is permitted. We do not expect the adoption of this ASU to have a material impact on our consolidated financial position or results of operations.

In May 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers.” The ASU will replace most existing revenue recognition 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 the amount 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 for both full retrospective and modified retrospective (with cumulative effect) methods of adoption. We are in the process of determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.


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Table of Contents

Note 3—Income (Loss) Per Common Unit

Our income (loss) per common unit is as follows for the periods indicated:
 
 
Year Ended March 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands, except unit and per unit amounts)
Net (loss) income
 
$
(187,097
)
 
$
50,193

 
$
48,758

Less: Net income attributable to noncontrolling interests
 
(11,832
)
 
(12,887
)
 
(1,103
)
Net (loss) income attributable to parent equity
 
(198,929
)
 
37,306

 
47,655

Less: Net income allocated to general partner (1)
 
(47,620
)
 
(45,700
)
 
(14,148
)
Less: Net loss (income) allocated to subordinated unitholders (2)
 
—

 
3,915

 
(1,893
)
Net (loss) income allocated to common unitholders
 
$
(246,549
)
 
$
(4,479
)
 
$
31,614

 
 
 
 
 
 
 
Basic and diluted (loss) income per common unit
 
$
(2.35
)
 
$
(0.05
)
 
$
0.51

Basic and diluted weighted average common units outstanding
 
104,838,886

 
86,359,300

 
61,970,471

 
(1)
Net income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are 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. During the three months ended June 30, 2014, 5,919,346 subordinated units were outstanding and the loss per subordinated unit was $(0.68). During the year ended March 31, 2014, 5,919,346 subordinated units were outstanding and income per subordinated unit was $0.32.

The restricted units (as described in Note 11) were considered antidilutive for the years ended March 31, 2016, 2015, and 2014.

Note 4—Acquisitions

Year Ended March 31, 2016

Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination. The business combinations for which this measurement period was still open as of March 31, 2016 are summarized below.


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Table of Contents

Water Pipeline Company

On January 7, 2016, we acquired a 57.125% interest in an existing produced water pipeline company operating in the Delaware Basin portion of West Texas for $12.3 million of cash. In addition, we have recorded contingent consideration liabilities, recorded within accrued expenses and other payables and noncurrent liabilities, related to future royalty payments to the sellers of this company for the life of the pipelines. We estimated the contingent consideration based on the contracted royalty rate, which is a flat rate per barrel, multiplied by the expected disposal volumes to flow through the pipelines during the life of the pipelines. This amount was then discounted back to present value using a weighted average cost of capital. As of the acquisition date we recorded a contingent liability of $2.6 million. We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in this business combination, and as a result, the estimates of fair value at March 31, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending December 31, 2016. The following table summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed (in thousands):
Accounts receivable-affiliates
$
1,000

Prepaid expenses and other current assets
50

Property, plant and equipment:
 
Water treatment facilities and equipment (3-30 years)
12,154

Vehicles (5 years)
54

Goodwill
5,561

Intangible assets:
 
Customer relationships (9 years)
6,000

Non-compete agreements (32 years)
350

Accrued expenses and other payables
(1,000
)
Noncurrent liabilities
(2,600
)
Noncontrolling interest
(9,248
)
Fair value of net assets acquired
$
12,321


Delaware Basin Water Solutions Facilities

On August 24, 2015, we acquired four saltwater disposal facilities and a 50% interest in an additional saltwater disposal facility in the Delaware Basin of the Permian Basin in Texas for $50.0 million of cash. In addition, we have recorded contingent consideration liabilities, recorded within accrued expenses and other payables and noncurrent liabilities, related to future royalty payments due to the sellers of these facilities. We estimated the contingent consideration based on the contracted royalty rate, which is a flat rate per disposal barrel and a percentage of the oil revenues, multiplied by the expected disposal volumes and oil revenue for the life of the facility and disposal well. This amount was then discounted back to present value using a weighted average cost of capital. As of the acquisition date we recorded a contingent liability of $11.0 million. We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed in this business combination, and as a result, the estimates of fair value at March 31, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending June 30, 2016. The following table summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed (in thousands):
Property, plant and equipment:
 
Water treatment facilities and equipment (3-30 years)
$
18,902

Vehicles (5 years)
148

Goodwill
23,776

Intangible asset:
 
Customer relationships (6 years)
16,000

Investments in unconsolidated entities
2,290

Accrued expenses and other payables
(861
)
Noncurrent liabilities
(10,255
)
Fair value of net assets acquired
$
50,000





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Table of Contents

Water Solutions Facilities

We are party to a development agreement that requires us to purchase water solutions facilities developed by the other party to the agreement. During the year ended March 31, 2016, we purchased 15 water treatment and disposal facilities under this development agreement. We also purchased one additional water treatment and disposal facility in December 2015 from a different seller. On a combined basis, we paid $146.5 million of cash and issued 781,255 common units, valued at $18.1 million, in exchange for these facilities. In addition, we have recorded contingent consideration liabilities, recorded within accrued expenses and other payables and noncurrent liabilities, related to future royalty payments due to the sellers of these facilities. We estimated the contingent consideration based on the contracted royalty rate, which is a flat rate per disposal barrel and percentage of oil revenues, multiplied by the expected disposal volumes and oil revenue for the life of the facility and disposal well. This amount was then discounted back to present value using a weighted average cost of capital. As of the acquisition date we recorded a contingent liability of $47.6 million.

During the year ended March 31, 2016, we completed the acquisition accounting for six of these water treatment and disposal facilities. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed (in thousands):
Property, plant and equipment:
 
Water treatment facilities and equipment (3-30 years)
$
27,065

Buildings and leasehold improvements (7-30 years)
6,879

Land
1,070

Other (5 years)
32

Goodwill
62,105

Accrued expenses and other payables
(2,512
)
Noncurrent liabilities
(21,462
)
Fair value of net assets acquired
$
73,177


We are in the process of identifying and determining the fair values of the assets acquired and liabilities assumed for the other ten water treatment and disposal facilities, and as a result, the estimates of fair value at March 31, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending December 31, 2016. The following table summarizes the preliminary estimates of the fair values of the assets acquired (and useful lives) and liabilities assumed (in thousands):
Property, plant and equipment:
 
Water treatment facilities and equipment (3-30 years)
$
48,465

Buildings and leasehold improvements (7-30 years)
8,214

Land
3,907

Other (5 years)
21

Goodwill
55,880

Accrued expenses and other payables
(2,861
)
Noncurrent liabilities
(22,198
)
Fair value of net assets acquired
$
91,428


For all water solutions acquisitions during the year ended March 31, 2016, goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to expand our operations into oilfield production basins not previously serviced by us, to expand the number of our disposal sites in oilfield production basins currently serviced by us, thereby enhancing our competitive position as a provider of disposal services in these oilfield production basins, and to expand and strengthen our pre-existing customer relationships with key oilfield producers. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Retail Propane Businesses

During the year ended March 31, 2016, we acquired six retail propane businesses. On a combined basis, we paid $25.9 million of cash and issued 52,199 common units, valued at $1.0 million, in exchange for these assets and operations. The agreements for these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of

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identifying and determining the fair values of the assets acquired and liabilities assumed in these business combinations, and as a result, the estimates of fair value at March 31, 2016 are subject to change. We expect to complete this process before we issue our financial statements for the three months ending December 31, 2016.

Year Ended March 31, 2015

Natural Gas Liquids Storage Facility

In February 2015, we acquired Sawtooth, NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western United States markets and entered into a construction agreement to expand the storage capacity of the facility. We paid $97.6 million of cash, net of cash acquired, and issued 7,396,973 common units, valued at $218.5 million, in exchange for these assets and operations. During the three months ended December 31, 2015, we completed the acquisition accounting for this business combination. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed:
 
Final
 
Estimated At
March 31,
2015
 
Change
 
(in thousands)
Accounts receivable-trade
$
42

 
$
42

 
$
—

Inventories
263

 
—

 
263

Prepaid expenses and other current assets
843

 
600

 
243

Property, plant and equipment:
 
 
 
 


Natural gas liquids terminal and storage assets (2-30 years)
61,130

 
62,205

 
(1,075
)
Vehicles and railcars (3-25 years)
78

 
75

 
3

Land
69

 
68

 
1

Other
17

 
32

 
(15
)
Construction in progress
19,525

 
19,525

 
—

Goodwill
183,096

 
151,853

 
31,243

Intangible assets:
 
 
 
 


Customer relationships (20 years)
61,500

 
85,000

 
(23,500
)
Non-compete agreements (24 years)
5,100

 
12,000

 
(6,900
)
Accounts payable-trade
(931
)
 
(931
)
 
—

Accrued expenses and other payables
(6,774
)
 
(6,511
)
 
(263
)
Advance payments received from customers
(1,015
)
 
(1,015
)
 
—

Other noncurrent liabilities
(6,817
)
 
(6,817
)
 
—

Fair value of net assets acquired
$
316,126

 
$
316,126

 
$
—


Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to gain entry to a new fee-based liquids storage business by acquiring underground storage assets in a new and competitively advantaged location, which also provides us with an additional strategically located facility from which to expand the current marketing efforts of our liquids business in that area. Goodwill also represents the premium paid for the potential expansion of the facilities. At the time of acquisition, the facility had two salt domes in operation and two salt domes under construction with the long-term possibility of adding four additional salt domes. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.


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Table of Contents

The acquisition method of accounting requires that executory contracts with unfavorable terms relative to market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain storage leases were at unfavorable terms relative to acquisition date market conditions, we recorded a liability of $12.8 million related to these leases in the acquisition accounting, a portion of which we recorded to accrued expenses and other payables and a portion of which we recorded to other noncurrent liabilities. We amortized $5.8 million of this balance as an increase to revenues during the year ended March 31, 2016. We will amortize the remainder of this liability over the term of the leases. The following table summarizes the future amortization of this liability (in thousands):

Year Ending March 31,
 
2017
$
4,805

2018
1,306

2019
88


Bakken Water Solutions Facilities

On November 21, 2014, we acquired two saltwater disposal facilities in the Bakken shale play in North Dakota for $34.6 million of cash. In addition, we have recorded contingent consideration liabilities, recorded within accrued expenses and other payables and noncurrent liabilities, related to future royalty payments due to the sellers of these facilities. We estimated the contingent consideration based on the contracted royalty rate, which is a flat rate per barrel, multiplied by the expected disposal volumes over the life of the facility and disposal well. This amount was then discounted back to present value using a weighted average cost of capital. As of the acquisition date we recorded a contingent liability of $3.5 million. During the three months ended September 30, 2015, we completed the acquisition accounting for these water treatment and disposal facilities. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed:
 
Final
 
Estimated At
March 31,
2015
 
Change
Property, plant and equipment:
(in thousands)
Vehicles (10 years)
$
63

 
$
63

 
$
—

Water treatment facilities and equipment (3-30 years)
5,815

 
5,815

 
—

Buildings and leasehold improvements (7-30 years)
130

 
130

 
—

Land
100

 
100

 
—

Goodwill
7,946

 
10,085

 
(2,139
)
Intangible asset:
 
 
 
 


Customer relationships (7 years)
24,300

 
22,000

 
2,300

Other noncurrent assets
75

 
—

 
75

Accrued expenses and other payables
(395
)
 
(395
)
 
—

Other noncurrent liabilities
(3,434
)
 
(3,198
)
 
(236
)
Fair value of net assets acquired
$
34,600

 
$
34,600

 
$
—


Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to expand our operations into oilfield production basins not previously serviced by us and strengthen our pre-existing customer relationships with key oilfield producers. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

TransMontaigne Inc.

As previously reported, on July 1, 2014, we acquired TransMontaigne for $200.3 million of cash, net of cash acquired (including $174.1 million paid at closing and $26.2 million paid upon completion of the working capital settlement). As part of this transaction, we also purchased $380.4 million of inventory from the previous owner of TransMontaigne (including $346.9

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Table of Contents

million paid at closing and $33.5 million subsequently paid as the working capital settlement process progressed). The operations of TransMontaigne include the marketing of refined products. As part of this transaction, we acquired the 2% general partner interest, the incentive distribution rights, a 19.7% limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne.

During the three months ended June 30, 2015, we completed the acquisition accounting for this business combination. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed:
 
Final
 
Estimated At
March 31,
2015
 
Change
 
(in thousands)
Cash and cash equivalents
$
1,469

 
$
1,469

 
$
—

Accounts receivable-trade
199,366

 
197,829

 
1,537

Accounts receivable-affiliates
528

 
528

 
—

Inventories
373,870

 
373,870

 
—

Prepaid expenses and other current assets
15,110

 
15,001

 
109

Property, plant and equipment:
 

 
 

 


Refined products terminal assets and equipment (20 years)
415,317

 
399,323

 
15,994

Vehicles
1,696

 
1,698

 
(2
)
Crude oil tanks and related equipment (20 years)
1,085

 
1,058

 
27

Information technology equipment
7,253

 
7,253

 
—

Buildings and leasehold improvements (20 years)
15,323

 
14,770

 
553

Land
61,329

 
70,529

 
(9,200
)
Tank bottoms (indefinite life)
46,900

 
46,900

 
—

Other
15,536

 
15,534

 
2

Construction in progress
4,487

 
4,487

 
—

Goodwill
30,169

 
28,074

 
2,095

Intangible assets:
 
 
 

 


Customer relationships (15 years)
66,000

 
76,100

 
(10,100
)
Pipeline capacity rights (30 years)
87,618

 
87,618

 
—

Investments in unconsolidated entities
240,583

 
240,583

 
—

Other noncurrent assets
3,911

 
3,911

 
—

Accounts payable-trade
(113,103
)
 
(113,066
)
 
(37
)
Accounts payable-affiliates
(69
)
 
(69
)
 
—

Accrued expenses and other payables
(79,405
)
 
(78,427
)
 
(978
)
Advance payments received from customers
(1,919
)
 
(1,919
)
 
—

Long-term debt
(234,000
)
 
(234,000
)
 
—

Other noncurrent liabilities
(33,227
)
 
(33,227
)
 
—

Noncontrolling interests
(545,120
)
 
(545,120
)
 
—

Fair value of net assets acquired
$
580,707

 
$
580,707

 
$
—


Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to acquire the skilled workforce, expand the scale of our existing refined and renewables product lines and expand the scale of our existing refined and renewables businesses by gaining control and access to TransMontaigne’s network of terminals and pipeline capacity. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.


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Table of Contents

The intangible asset for pipeline capacity rights relates to capacity allocations on a third-party refined products pipeline. Demand for use of this pipeline exceeds the pipeline’s capacity, and the limited capacity is allocated based on a shipper’s historical shipment volumes.

The fair value of the noncontrolling interests was calculated by multiplying the closing price of TLP’s common units on the acquisition date by the number of TLP common units held by parties other than us, adjusted for a lack-of-control discount.

As discussed in Note 2, on February 1, 2016, we sold our general partner interest in TLP and on April 1, 2016, we sold all of the TLP units we owned to ArcLight. See Note 1, Note 14 and Note 19 for a further discussion.

Water Solutions Facilities

We are party to a development agreement that requires us to purchase water solutions facilities developed by the other party to the agreement. During the year ended March 31, 2015, we purchased 16 water treatment and disposal facilities under this development agreement. We also purchased a 75% interest in one additional water treatment and disposal facility in July 2014 from a different seller. On a combined basis, we paid $190.0 million of cash and issued 1,322,032 common units, valued at $37.8 million, in exchange for these 17 facilities. In addition, we have recorded contingent consideration liabilities, recorded within accrued expenses and other payables and noncurrent liabilities, related to future royalty payments due to the sellers of these facilities. We estimated the contingent consideration based on the contracted royalty rate, which is a flat rate per disposal barrel and a percentage of oil revenue, multiplied by the expected disposal volumes and oil revenue over the life of the facility and disposal well. This amount was then discounted back to present value using a weighted average cost of capital. As of the acquisition date we recorded a contingent liability of $121.5 million.

During the three months ended December 31, 2015, we completed the acquisition accounting for all of these water treatment and disposal facilities. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed:
 
Final
 
Estimated At
March 31,
2015
 
Change
 
(in thousands)
Accounts receivable-trade
$
939

 
$
939

 
$
—

Inventories
253

 
253

 
—

Prepaid expenses and other current assets
62

 
62

 
—

Property, plant and equipment:
 
 
 
 


Water treatment facilities and equipment (3-30 years)
79,982

 
79,706

 
276

Buildings and leasehold improvements (7-30 years)
10,690

 
10,250

 
440

Land
3,127

 
3,109

 
18

Other (5 years)
132

 
129

 
3

Goodwill
253,517

 
254,255

 
(738
)
Intangible asset:
 
 
 
 


Customer relationships (4 years)
10,000

 
10,000

 
—

Other noncurrent assets
50

 
50

 
—

Accounts payable-trade
(58
)
 
(58
)
 
—

Accrued expenses and other payables
(15,785
)
 
(15,786
)
 
1

Other noncurrent liabilities
(109,373
)
 
(109,373
)
 
—

Noncontrolling interest
(5,775
)
 
(5,775
)
 
—

Fair value of net assets acquired
$
227,761

 
$
227,761

 
$
—


For these water solutions acquisitions, goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to expand the number of our disposal sites in oilfield production basins currently serviced by us, thereby enhancing our competitive position as a provider of disposal services in these oilfield production basins, and to expand and strengthen our pre-existing customer relationships with key oilfield producers. We estimate that all of the goodwill will be deductible for federal income tax purposes.

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Table of Contents


Retail Propane Businesses

During the year ended March 31, 2015, we acquired eight retail propane businesses. On a combined basis, we paid $39.1 million of cash and issued 132,100 common units, valued at $3.7 million, in exchange for these assets and operations.

During the three months ended September 30, 2015, we completed the acquisition accounting for all of these business combinations. The following table summarizes the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed:
 
Final
 
Estimated At
March 31,
2015
 
Change
 
(in thousands)
Accounts receivable-trade
$
2,237

 
$
2,237

 
$
—

Inventories
771

 
771

 
—

Prepaid expenses and other current assets
110

 
110

 
—

Property, plant and equipment:
 
 
 

 


Retail propane equipment (15-20 years)
13,177

 
13,177

 
—

Vehicles and railcars (5-7 years)
2,332

 
2,332

 
—

Buildings and leasehold improvements (30 years)
534

 
784

 
(250
)
Land
505

 
655

 
(150
)
Other (5-7 years)
118

 
116

 
2

Goodwill
8,097

 
8,097

 
—

Intangible assets:
 
 
 

 


Customer relationships (10-15 years)
17,563

 
17,563

 
—

Non-compete agreements (5-7 years)
500

 
500

 
—

Trade names (3-12 years)
950

 
950

 
—

Accounts payable-trade
(1,523
)
 
(1,921
)
 
398

Advance payments received from customers
(1,750
)
 
(1,750
)
 
—

Current maturities of long-term debt
(78
)
 
(78
)
 
—

Long-term debt, net of current maturities
(760
)
 
(760
)
 
—

Fair value of net assets acquired
$
42,783

 
$
42,783

 
$
—


Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill represents a premium paid to acquire the skilled workforce of each of the businesses acquired. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.


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Note 5—Property, Plant and Equipment

Our property, plant and equipment consists of the following at the dates indicated:
 
 
Estimated
 
March 31,
Description
 
Useful Lives
 
2016
 
2015
 
 
 
 
(in thousands)
Natural gas liquids terminal and storage assets
 
2-30 years
 
$
169,758

 
$
131,776

Refined products terminal assets and equipment
 
20 years
 
6,844

 
419,603

Retail propane equipment
 
2-30 years
 
201,312

 
181,140

Vehicles and railcars
 
3-25 years
 
185,547

 
180,680

Water treatment facilities and equipment
 
3-30 years
 
508,239

 
317,593

Crude oil tanks and related equipment
 
2-40 years
 
137,894

 
109,936

Barges and towboats
 
5-40 years
 
86,731

 
59,848

Information technology equipment
 
3-7 years
 
38,653

 
34,915

Buildings and leasehold improvements
 
3-40 years
 
118,885

 
99,732

Land
 
 
 
47,114

 
97,767

Tank bottoms (1)
 
 
 
20,355

 
62,656

Other
 
3-30 years
 
11,699

 
34,407

Construction in progress
 
 
 
383,032

 
96,922

 
 
 
 
1,916,063

 
1,826,975

Accumulated depreciation
 
 
 
(266,491
)
 
(202,959
)
Net property, plant and equipment
 
 
 
$
1,649,572

 
$
1,624,016

 
(1)
Due to the deconsolidation of TLP in February 2016 (see Note 1), the tank bottoms for the TLP terminals were reclassified to noncurrent assets.

The following table summarizes depreciation expense and capitalized interest expense for the periods indicated:
 
Year Ended March 31,
 
2016
 
2015
 
2014
 
(in thousands)
Depreciation expense
$
136,938

 
$
105,687

 
$
59,899

Capitalized interest expense
4,012

 
113

 
774


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 are removed from service. The following table summarizes the tank bottoms included in the table above at the dates indicated:
 
 
March 31, 2016
 
March 31, 2015
Product
 
Volume
(in barrels)
(in thousands)
 
Value
(in thousands)
 
Volume
(in barrels)
(in thousands)
 
Value
(in thousands)
Gasoline
 
—

 
$
—

 
219

 
$
25,710

Crude oil
 
231

 
19,348

 
184

 
16,835

Diesel
 
—

 
—

 
124

 
15,153

Renewables
 
—

 
—

 
41

 
4,220

Other
 
24

 
1,007

 
12

 
738

Total
 
 

 
$
20,355

 
 
 
$
62,656



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Table of Contents

Note 6—Goodwill

The following table summarizes changes in goodwill by segment for the periods indicated (in thousands):
 
Crude Oil
Logistics
 
Water
Solutions
 
Liquids
 
Retail
Propane
 
Refined
Products and
Renewables
 
Total
Balances at March 31, 2014, as retrospectively adjusted
$
579,846

 
$
264,127

 
$
91,135

 
$
114,285

 
$
36,000

 
$
1,085,393

Disposals (Note 14)
—

 
(1,797
)
 
(8,185
)
 
—

 
—

 
(9,982
)
Acquisitions (Note 4)
—

 
261,460

 
183,096

 
8,097

 
30,169

 
482,822

Balances at March 31, 2015, as retrospectively adjusted
579,846

 
523,790

 
266,046

 
122,382

 
66,169

 
1,558,233

Acquisitions (Note 4)
—

 
147,322

 
—

 
5,046

 
—

 
152,368

Disposals (Note 14)
—

 
—

 
—

 
—

 
(15,042
)
 
(15,042
)
Impairment (Note 14)
—

 
(380,197
)
 
—

 
—

 
—

 
(380,197
)
Balances at March 31, 2016
$
579,846

 
$
290,915

 
$
266,046

 
$
127,428

 
$
51,127

 
$
1,315,362

 
Note 7—Intangible Assets

Our intangible assets consist of the following at the dates indicated:
 
 
 
 
March 31, 2016
 
March 31, 2015
 
 
Amortizable
Lives
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
Gross Carrying
Amount
 
Accumulated
Amortization
 
 
 
 
(in thousands)
Amortizable-
 
 
 
 
 
 
 
 
 
 
Customer relationships
 
3-20 years
 
$
852,118

 
$
233,838

 
$
890,118

 
$
159,215

Pipeline capacity rights
 
30 years
 
119,636

 
6,559

 
119,636

 
2,571

Water facility development agreement
 
5 years
 
14,000

 
7,700

 
14,000

 
4,900

Executory contracts and other agreements
 
2-10 years
 
23,920

 
21,075

 
23,920

 
18,387

Non-compete agreements
 
2-32 years
 
20,903

 
13,564

 
19,762

 
10,408

Trade names
 
1-10 years
 
15,439

 
12,034

 
15,439

 
7,569

Debt issuance costs (1)
 
3 years
 
39,942

 
22,108

 
33,306

 
13,443

Total amortizable
 
 
 
1,085,958

 
316,878

 
1,116,181

 
216,493

Non-amortizable-
 
 
 
 
 
 
 
 
 
 
Customer commitments
 
 
 
310,000

 
—

 
310,000

 
—

Rights-of-way and easements (2)
 
 
 
47,190

 
—

 
—

 
—

Trade names
 
 
 
22,620

 
—

 
22,620

 
—

Total non-amortizable
 
 
 
379,810

 
—

 
332,620

 
—

Total
 
 
 
$
1,465,768

 
$
316,878

 
$
1,448,801

 
$
216,493

 
(1)
Includes debt issuance costs related to revolving credit facilities. Debt issuance costs related to fixed-rate notes are reported as a reduction of the carrying amount of long-term debt.
(2)
See Note 16 for a discussion of acquired rights-of-way and easements along a planned pipeline route.

The weighted-average remaining amortization period for intangible assets is approximately 13 years.

As described in Note 1, on February 1, 2016 due to the sale of our interest in TLP general partner to ArcLight, we deconsolidated TLP and began to account for our investment in TLP using the equity method of accounting. See Note 14 for a discussion of the sale.


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Table of Contents

Amortization expense is as follows for the periods indicated:
 
 
Year Ended March 31,
Recorded In
 
2016
 
2015
 
2014
 
 
(in thousands)
Depreciation and amortization
 
$
91,986

 
$
88,262

 
$
60,855

Cost of sales
 
6,700

 
7,767

 
6,172

Interest expense
 
8,942

 
5,722

 
4,800

Total
 
$
107,628

 
$
101,751

 
$
71,827


Expected amortization of our intangible assets, exclusive of assets that are not yet amortizable, is as follows (in thousands):
Year Ending March 31,
 

2017
$
96,155

2018
93,734

2019
83,981

2020
77,558

2021
65,717

Thereafter
351,935

Total
$
769,080

 
Note 8—Long-Term Debt

Our long-term debt consists of the following at the dates indicated:
 
 
March 31, 2016
 
March 31, 2015
 
 
Face
Amount
 
Unamortized
Debt Issuance
Costs (1)
 
Book
Value
 
Face
Amount
 
Unamortized
Debt Issuance
Costs (1)
 
Book
Value
 
 
(in thousands)
Revolving credit facility —
 


 
 
 
 
 
 
 
 
 
 
Expansion capital borrowings
 
$
1,229,500

 
$
—

 
$
1,229,500

 
$
702,500

 
$
—

 
$
702,500

Working capital borrowings
 
618,500

 
—

 
618,500

 
688,000

 
—

 
688,000

5.125% Notes due 2019
 
388,467

 
(4,681
)
 
383,786

 
400,000

 
(6,242
)
 
393,758

6.875% Notes due 2021
 
388,289

 
(7,545
)
 
380,744

 
450,000

 
(10,280
)
 
439,720

6.650% Notes due 2022
 
250,000

 
(3,166
)
 
246,834

 
250,000

 
(1,313
)
 
248,687

TLP credit facility (2)
 
—

 
—

 
—

 
250,000

 
—

 
250,000

Other long-term debt
 
61,488

 
(108
)
 
61,380

 
9,271

 
—

 
9,271

 
 
2,936,244

 
(15,500
)
 
2,920,744

 
2,749,771

 
(17,835
)
 
2,731,936

Less: Current maturities
 
7,907

 
—

 
7,907

 
4,472

 
—

 
4,472

Long-term debt
 
$
2,928,337

 
$
(15,500
)
 
$
2,912,837

 
$
2,745,299

 
$
(17,835
)
 
$
2,727,464

 
(1)
Debt issuance costs related to revolving credit facilities are reported within intangible assets, rather than as a reduction of the carrying amount of long-term debt.
(2)
Due to the sale of the general partner interest in TLP, TLP was deconsolidated as of February 1, 2016 (see Note 1 and Note 14).


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Amortization expense for debt issuance costs related to the Senior Notes is as follows for the periods indicated:
Year Ended March 31,
2016
 
2015
 
2014
(in thousands)
$4,645
 
$3,037
 
$927

Expected amortization of debt issuance costs is as follows (in thousands):
Year Ending March 31,
 
 
2017
 
$
3,410

2018
 
3,300

2019
 
3,296

2020
 
2,283

2021
 
1,865

Thereafter
 
1,346

Total
 
$
15,500


Credit Agreement

We have entered into a credit agreement (as amended, the “Credit Agreement”) with a syndicate of banks. The Credit Agreement includes a revolving credit 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”). At March 31, 2016, our Revolving Credit Facility had a total capacity of $2.484 billion. Our Revolving Credit Facility has an “accordion” feature that allows us to increase the capacity by $150 million if new lenders wish to join the syndicate or if current lenders wish to increase their commitments.

The Expansion Capital Facility had a total capacity of $1.446 billion for cash borrowings at March 31, 2016. At that date, we had outstanding borrowings of $1.230 billion on the Expansion Capital Facility. The Working Capital Facility had a total capacity of $1.038 billion for cash borrowings and letters of credit at March 31, 2016. At that date, we had outstanding borrowings of $618.5 million and outstanding letters of credit of $45.4 million on the Working Capital Facility. Amounts outstanding for letters of credit are not recorded as long-term debt on our consolidated balance sheets, although they decrease our borrowing capacity under the Working Capital Facility. The capacity available under the Working Capital Facility may be limited by a “borrowing base” (as defined in the Credit Agreement), which is calculated based on the value of certain working capital items at any point in time.

The commitments under the Credit Agreement expire on November 5, 2018. We have the right to prepay outstanding borrowings under the Credit Agreement without incurring any penalties, and prepayments of principal may be required if we enter into certain transactions to sell assets or obtain new borrowings.

All borrowings under the Credit Agreement bear interest, at our option, at either (i) an alternate base rate plus a margin of 0.50% to 1.50% per year or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per year. The applicable margin is determined based on our consolidated leverage ratio (as defined in the Credit Agreement). At March 31, 2016, the borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at March 31, 2016 of 2.94%, calculated as the LIBOR rate of 0.94% plus a margin of 2.0%. At March 31, 2016, the interest rate in effect on letters of credit was 2.25%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused capacity.

The Credit Agreement is secured by substantially all of our assets. In December 2015, we entered into an agreement with the banks to increase our maximum leverage ratio to 4.75 to 1 at any quarter end. At March 31, 2016, our leverage ratio was approximately 3.9 to 1. The Credit Agreement also specifies that our interest coverage ratio (as defined in the Credit Agreement) cannot be less than 2.75 to 1 at any quarter end. At March 31, 2016, our interest coverage ratio was approximately 5.3 to 1.

The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement 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) a breach by the Partnership or its subsidiaries of any

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material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

At March 31, 2016, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the “2019 Notes”). During the fourth quarter of fiscal year 2016, we repurchased $11.5 million of our 2019 Notes for an aggregate purchase price of $7.0 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2019 Notes of $4.5 million (net of the write off of debt issuance costs of $0.1 million).

The 2019 Notes mature on July 15, 2019. Interest is payable on January 15 and July 15 of each year. We have the right to redeem the 2019 Notes before the maturity date, although we would be required to pay a premium for early redemption.

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2019 Notes contains various customary covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the indenture 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) certain events of bankruptcy or insolvency.

At March 31, 2016, we were in compliance with the covenants under the indenture governing the 2019 Notes.
 
2021 Notes

On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the “2021 Notes”). During the fourth quarter of fiscal year 2016, we repurchased $61.7 million of our 2021 Notes for an aggregate purchase price of $36.4 million (excluding payments of accrued interest). As a result, we recorded a gain on the early extinguishment of our 2021 Notes of $24.0 million (net of the write off of debt issuance costs of $1.2 million).

The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes before the maturity date, although we would be required to pay a premium for early redemption.

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The indenture governing the 2021 Notes contains various customary covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the indenture 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) certain events of bankruptcy or insolvency.

At March 31, 2016, we were in compliance with the covenants under the indenture governing the 2021 Notes.

2022 Notes

On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the “Note Purchase Agreement”) whereby we issued $250.0 million of Senior Notes in a private placement (the “2022 Notes”). The 2022 Notes bear interest at a fixed rate of 6.65%, which is payable quarterly. The 2022 Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the

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Note Purchase Agreement contains similar leverage ratio and interest coverage ratio requirements to those of our Credit Agreement, which is described above. In December 2015, we amended the Note Purchase Agreement to change the covenants to mirror the changes made to the covenants in our Credit Agreement. In addition, we agreed to pay an additional 0.5% per year in interest if our leverage ratio exceeds 4.25 to 1.

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) nonpayment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the 2022 Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness 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) the failure of the Note Purchase Agreement, the 2022 Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding 2022 Notes of any series may declare all of the 2022 Notes of such series to be due and payable immediately.

At March 31, 2016, we were in compliance with the covenants under the Note Purchase Agreement.

Other Long-Term Debt

We have executed various noninterest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing. These instruments have a combined principal balance of $61.5 million at March 31, 2016, and the interest rates on these instruments range from 1.17% to 7.08% per year.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at March 31, 2016:
Year Ending March 31,
 
Revolving
Credit
Facility
 
2019
Notes
 
2021
Notes
 
2022
Notes
 
Other
Long-Term
Debt
 
Total
 
 
(in thousands)
2017
 
$
—

 
$
—

 
$
—

 
$
—

 
$
7,899

 
$
7,899

2018
 
—

 
—

 
—

 
25,000

 
7,143

 
32,143

2019
 
1,848,000

 
—

 
—

 
50,000

 
6,053

 
1,904,053

2020
 
—

 
388,467

 
—

 
50,000

 
5,621

 
444,088

2021
 
—

 
—

 
—

 
50,000

 
34,671

 
84,671

Thereafter
 
—

 
—

 
388,289

 
75,000

 
101

 
463,390

Total
 
$
1,848,000

 
$
388,467

 
$
388,289

 
$
250,000

 
$
61,488

 
$
2,936,244


Note 9—Income Taxes

We qualify as a partnership for income tax purposes. As such, we generally do not pay United States federal income tax. Rather, each owner reports his or her share of our income or loss on his or her individual tax return. The aggregate difference in the basis of our net assets for financial and tax reporting purposes cannot be readily determined, as we do not have access to information regarding each partner’s basis in the Partnership.

We have certain taxable corporate subsidiaries in the United States and in Canada, and our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales. Our fiscal years 2012 to 2015 generally remain subject to examination by federal, state, and Canadian tax authorities. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date.


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A publicly traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income for each of 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, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in our consolidated financial statements at March 31, 2016 or 2015.

Note 10—Commitments and Contingencies

Legal Contingencies

We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, is not expected to have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our liabilities may change materially as circumstances develop.

Contractual Disputes

During the year ended March 31, 2015, we settled two separate contractual disputes and recorded $5.5 million of proceeds to other income in our consolidated statement of operations. Also during the year ended March 31, 2015, we offered to settle another contractual dispute, and recorded $1.2 million to other expense as an estimate of the probable loss. During the year ended March 31, 2016, we finalized the settlement of this contractual dispute and paid approximately $0.5 million at the date of settlement and committed to pay approximately $1.1 million in equal annual installments over a period of 11 years beginning on October 15, 2016 and ending in October 2026.

Environmental Matters

Our consolidated balance sheet at March 31, 2016 includes a liability, measured on an undiscounted basis, of $2.3 million related to environmental matters, which is reported within accrued expenses and other payables. 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 laws and 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, and claims 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 materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

The U.S. Environmental Protection Agency (“EPA”) has informed NGL Crude Logistics, LLC (“NGL Crude” formerly known as Gavilon Energy prior to its acquisition by us in December 2013) of alleged violations in 2011 by Gavilon Energy of the Clean Air Act’s renewable fuel standards regulations. The EPA’s allegations relate to transactions between Gavilon Energy and one of its suppliers and the generation of biodiesel renewable identification numbers sold by such supplier to Gavilon Energy in 2011. We have vigorously denied the allegations. In an effort to resolve this matter, the parties have recently commenced settlement negotiations, which are ongoing.

At this time, we are unable to ascertain whether the settlement discussions will produce a resolution satisfactory to us or whether the EPA will seek resolution of the matter through an enforcement action. As a result, we are also unable to determine the likely terms of any resolution or their significance to us. Although we believe we have legal defenses, it is reasonably possible that we may agree to pay the EPA some amount to settle the matter.


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Asset Retirement Obligations

We have contractual and regulatory obligations at certain facilities for which we have to perform remediation, dismantlement, or removal activities when the assets are retired. Our liability for asset retirement obligations is discounted to present value. To calculate the liability, we make estimates and assumptions 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 and the occurrence of future events. The following table is a rollforward of our asset retirement obligation, which is reported within other noncurrent liabilities in our consolidated balance sheets (in thousands):
Balance at March 31, 2014
 
$
2,261

Liabilities incurred
 
1,695

Liabilities settled
 
(390
)
Accretion expense
 
333

Balance at March 31, 2015
 
3,899

Liabilities incurred
 
1,486

Liabilities settled
 
(191
)
Accretion expense
 
380

Balance at March 31, 2016
 
$
5,574


In addition to the obligations described above, we may be obligated to remove facilities or perform other remediation upon retirement of certain other assets. We do not believe the present value of these asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of our facilities, is material to our consolidated financial position or results of operations.

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. The following table summarizes future minimum lease payments under these agreements at March 31, 2016 (in thousands):
Year Ending March 31,
 
2017
$
136,065

2018
120,723

2019
98,266

2020
87,569

2021
77,821

Thereafter
127,315

Total
$
647,759


Rental expense relating to operating leases was $125.5 million, $125.5 million, and $98.3 million during the years ended March 31, 2016, 2015, and 2014, respectively.

Pipeline Capacity Agreements

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. The following table summarizes future minimum throughput payments under these agreements at March 31, 2016 (in thousands):
Year Ending March 31,
 

2017
$
53,024

2018
53,042

2019
52,250

2020
42,418

Total
$
200,734


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Sales and Purchase Contracts

We have entered into product sales and purchase contracts for which we expect the parties to physically settle and deliver the inventory in future periods. The following table summarizes such commitments at March 31, 2016:
 
 
Volume
 
Value
 
 
(in thousands)
Purchase commitments:
 
 

 
 

Natural gas liquids fixed-price (gallons)
 
22,078

 
$
8,493

Natural gas liquids index-price (gallons)
 
855,945

 
365,477

Crude oil fixed-price (barrels)
 
1,077

 
41,756

Crude oil index-price (barrels)
 
14,722

 
518,431

Sale commitments:
 
 

 
 

Natural gas liquids fixed-price (gallons)
 
85,162

 
52,633

Natural gas liquids index-price (gallons)
 
312,198

 
197,861

Crude oil fixed-price (barrels)
 
2,107

 
92,469

Crude oil index-price (barrels)
 
18,754

 
730,583


We account for the contracts shown in the table above as normal purchases and normal sales. 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 table above may have offsetting derivative contracts (described in Note 12) or inventory positions (described in Note 2).

Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value in our consolidated balance sheet and are not included in the table above. These contracts are included in the derivative disclosures in Note 12, and represent $31.5 million of our prepaid expenses and other current assets and $25.2 million of our accrued expenses and other payables at March 31, 2016.

Note 11—Equity

Partnership Equity

The Partnership’s equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Our general partner is not required to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

Equity Issuances

The following table summarizes our equity issuances for fiscal years 2015 and 2014 (in millions, except unit amounts). There were no equity issuances during fiscal year 2016.
Issuance Date
 
Type of
Offering
 
Number of
Common Units
Issued
 
Gross
Proceeds
 
Underwriting
Discounts and
Commissions
 
Offering
Costs
 
Net
Proceeds
March 11, 2015
 
Public Offering
 
6,250,000

 
$
172.3

 
$
1.4

 
$
0.2

 
$
170.7

June 23, 2014
 
Public Offering
 
8,767,100

 
383.2

 
12.3

 
0.5

 
370.4

December 2, 2013
 
Private Placement
 
8,110,848

 
240.0

 
—

 
4.9

 
235.1

September 25, 2013
 
Public Offering
 
4,100,000

 
132.8

 
5.0

 
0.2

 
127.6

July 5, 2013
 
Public Offering
 
10,350,000

 
300.2

 
12.0

 
0.7

 
287.5


Common Unit Repurchase Program

On September 10, 2015, the Board of Directors of our general partner authorized a common unit repurchase program pursuant to which we could repurchase up to $45 million of our outstanding common units through March 31, 2016 from time

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to time in the open market or in other privately negotiated transactions. During the year ended March 31, 2016, we repurchased 1,623,804 common units for an aggregate price of $17.7 million.

Distributions

The following table summarizes distributions declared for the last three fiscal years:
Date Declared
 
Record Date
 
Date Paid
 
Amount
Per Unit
 
Amount Paid to
Limited Partners
 
Amount Paid To
General Partner
 
 
 
 
 
 
 
 
(in thousands)
April 25, 2013
 
May 6, 2013
 
May 15, 2013
 
$
0.4775

 
$
25,605

 
$
1,189

July 25, 2013
 
August 5, 2013
 
August 14, 2013
 
0.4938

 
31,725

 
1,739

October 23, 2013
 
November 4, 2013
 
November 14, 2013
 
0.5113

 
35,908

 
2,491

January 24, 2014
 
February 4, 2014
 
February 14, 2014
 
0.5313

 
42,150

 
4,283

April 24, 2014
 
May 5, 2014
 
May 15, 2014
 
0.5513

 
43,737

 
5,754

July 24, 2014
 
August 4, 2014
 
August 14, 2014
 
0.5888

 
52,036

 
9,481

October 24, 2014
 
November 4, 2014
 
November 14, 2014
 
0.6088

 
53,902

 
11,141

January 26, 2015
 
February 6, 2015
 
February 13, 2015
 
0.6175

 
54,684

 
11,860

April 24, 2015
 
May 5, 2015
 
May 15, 2015
 
0.6250

 
59,651

 
13,446

July 23, 2015
 
August 3, 2015
 
August 14, 2015
 
0.6325

 
66,248

 
15,483

October 22, 2015
 
November 3, 2015
 
November 13, 2015
 
0.6400

 
67,313

 
16,277

January 21, 2016
 
February 3, 2016
 
February 15, 2016
 
0.6400

 
67,310

 
16,279

April 21, 2016
 
May 3, 2016
 
May 13, 2016
 
0.3900

 
40,626

 
70


Several of our business combination agreements contained provisions that temporarily limited the distributions to which the newly issued units were entitled. 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 Units
Not Eligible
November 4, 2013
 
979,886

February 6, 2015
 
132,100

May 5, 2015
 
8,352,902

February 3, 2016
 
223,077


TLP’s Distributions

The following table summarizes distributions declared by TLP after our acquisition of general and limited partner interests in TLP (exclusive of the distribution declared in July 2014, the proceeds of which we remitted to the former owners of TransMontaigne, pursuant to agreements entered into at the time of the business combination) through February 1, 2016, the date TLP was deconsolidated:
Date Declared
 
Record Date
 
Date Paid
 
Amount
Per Unit
 
Amount Paid
To NGL
 
Amount Paid To
Other Partners
 
 
 
 
 
 
 
 
(in thousands)
October 13, 2014
 
October 31, 2014
 
November 7, 2014
 
$
0.6650

 
$
4,010

 
$
8,614

January 8, 2015
 
January 30, 2015
 
February 6, 2015
 
0.6650

 
4,010

 
8,614

April 13, 2015
 
April 30, 2015
 
May 7, 2015
 
0.6650

 
4,007

 
8,617

July 13, 2015
 
July 31, 2015
 
August 7, 2015
 
0.6650

 
4,007

 
8,617

October 12, 2015
 
October 30, 2015
 
November 6, 2015
 
0.6650

 
4,007

 
8,617

January 19, 2016
 
January 29, 2016
 
February 8, 2016
 
0.6700

 
4,104

 
8,681



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Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plan (“LTIP”), which allows for the issuance of equity-based compensation. Our general partner has granted certain restricted units to employees and directors, which vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions accrue to or are paid on the restricted 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 the performance of our common units relative to other entities in the Alerian MLP Index (the “Index”) over specified periods of time (the “Performance Awards”).

The following table summarizes the Service Award activity during the years ended March 31, 2016, 2015 and 2014:
Unvested Service Award units at March 31, 2013
 
1,444,900

Units granted
 
494,000

Units vested and issued
 
(296,269
)
Units withheld for employee taxes
 
(122,531
)
Units forfeited
 
(209,000
)
Unvested Service Award units at March 31, 2014
 
1,311,100

Units granted
 
2,093,139

Units vested and issued
 
(586,010
)
Units withheld for employee taxes
 
(354,829
)
Units forfeited
 
(203,000
)
Unvested Service Award units at March 31, 2015
 
2,260,400

Units granted
 
1,484,412

Units vested and issued
 
(844,626
)
Units withheld for employee taxes
 
(464,054
)
Units forfeited
 
(139,000
)
Unvested Service Award units at March 31, 2016
 
2,297,132


The following table summarizes the scheduled vesting of our unvested Service Award units:
Year Ending March 31,
 
Number of Units
2017
 
1,369,491

2018
 
763,141

2019
 
142,500

2020
 
21,000

2021
 
1,000

Unvested Service Award units at March 31, 2016
 
2,297,132


We record the expense for the first tranche of each Service Award on a straight-line basis over the period beginning with the grant date of the awards and ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previous tranche and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distributions.


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The following table summarizes the estimated future expense we expect to record on the unvested Service Award units at March 31, 2016 (in thousands), after taking into consideration estimated forfeitures of approximately 210,808 units. For purposes of this calculation, we used the closing price of our common units on March 31, 2016, which was $7.52.
Year Ending March 31,
 
 
2017
 
$
8,426

2018
 
2,029

2019
 
462

2020
 
45

2021
 
2

Total
 
$
10,964


The following table is a rollforward of the liability related to the Service Award units, which is reported within accrued expenses and other payables in our consolidated balance sheets (in thousands):
March 31, 2013
 
$
5,043

Expense recorded
 
17,804

Value of units vested and issued
 
(9,085
)
Taxes paid on behalf of participants
 
(3,750
)
March 31, 2014
 
10,012

Expense recorded
 
32,767

Value of units vested and issued
 
(23,134
)
Taxes paid on behalf of participants
 
(13,491
)
March 31, 2015
 
6,154

Expense recorded
 
35,177

Value of units vested and issued
 
(23,631
)
Taxes paid on behalf of participants
 
(12,975
)
March 31, 2016
 
$
4,725


The weighted-average fair value of the Service Award units at March 31, 2016 was $5.61 per common unit, which was calculated as the closing price of the common units on March 31, 2016, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution.

During April 2015, our general partner granted 1,041,073 Performance Award units to certain employees. The number of Performance Award units that will vest is contingent on the performance of our common units relative to the performance of the other entities in the Alerian Index. Performance will be calculated based on the total unitholder return (“TUR”) on our common units (including changes in the market price of the common units and distributions paid during the performance period) relative to the TUR on the common units of the other entities in the Alerian Index. The following table presents the number of units granted per tranche, vesting dates and the period over which performance will be measured:
Performance Units Granted Per Tranche
 
Vesting Date of Tranche
 
Performance Period for Tranche
349,691
 
July 1, 2015
 
July 1, 2012 through June 30, 2015
347,691
 
July 1, 2016
 
July 1, 2013 through June 30, 2016
343,691
 
July 1, 2017
 
July 1, 2014 through June 30, 2017

The following table summarizes the percentage of the maximum Performance Award units that will vest will depend on the percentage of entities in the Index that NGL outperforms:
Our Relative TUR Percentile Ranking
 
Payout (% of Target Units)
Less than 50th percentile
 
0%
Between the 50th and 75th percentile
 
50%–100%
Between the 75th and 90th percentile
 
100%–200%
Above the 90% percentile
 
200%

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The April 2015 Performance Award grants included a tranche that vested on July 1, 2015. During the July 1, 2012 through June 30, 2015 performance period, the return on our common units exceeded the return on 83% of our peer companies in the Index. As a result, the July 1, 2015 tranche of the Performance Awards vested at 151% of the maximum number of awards, and 530,564 common units vested on July 1, 2015. Of these units, recipients elected for us to withhold 210,137 common units for employee taxes, valued at $6.4 million. We issued the remaining 320,427 common units, valued at $9.7 million, on July 1, 2015.

The following table summarizes the maximum number of units that could vest on these Performance Awards for each vesting tranche, taking into consideration any Performance Awards that have been forfeited since the grant date:
Vesting Date of Tranche
 
Maximum Performance
Award Units
July 1, 2016
 
641,382

July 1, 2017
 
633,382

Total
 
1,274,764


The following table summarizes the estimated fair value for each unvested tranche at March 31, 2016, without consideration of estimated forfeitures:
Vesting Date of Tranche
 
Fair Value of
Unvested Awards
 
 
(in thousands)
July 1, 2016
 
$
263

July 1, 2017
 
285

Total
 
$
548


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 and ending with the vesting date of the tranche. At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using a Monte Carlo simulation. The following table summarizes the expense recorded during the year ended March 31, 2016 (in thousands):
Vesting Date of Tranche
 
 
July 1, 2015
 
$
16,077

July 1, 2016
 
197

July 1, 2017
 
114

Total
 
$
16,388


The following table is a rollforward of the liability related to the Performance Awards units, which is reported within accrued expenses and other payables in our consolidated balance sheet (in thousands):
Balance at March 31, 2015
 
$
—

Expense recorded
 
16,388

Value of units vested and issued
 
(9,659
)
Taxes paid on behalf of participants
 
(6,420
)
Balance at March 31, 2016
 
$
309


The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common units. The maximum number of units deliverable under the plan 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. 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 awards under the LTIP. At March 31, 2016, approximately 4.6 million common units remain available for issuance under the LTIP.

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Note 12—Fair Value of Financial Instruments

Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current assets and liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature.

Commodity Derivatives

The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported in our consolidated balance sheet at the dates indicated:
 
 
March 31, 2016
 
March 31, 2015
 
 
Derivative
Assets
 
Derivative
Liabilities
 
Derivative
Assets
 
Derivative
Liabilities
 
 
(in thousands)
Level 1 measurements
 
$
47,361

 
$
(3,983
)
 
$
83,779

 
$
(3,969
)
Level 2 measurements
 
32,700

 
(28,612
)
 
34,963

 
(28,764
)
 
 
80,061

 
(32,595
)
 
118,742

 
(32,733
)
 
 
 
 
 
 
 
 
 
Netting of counterparty contracts (1)
 
(3,384
)
 
3,384

 
(1,804
)
 
1,804

Net cash collateral provided (held)
 
(18,176
)
 
599

 
(56,660
)
 
2,979

Commodity derivatives in consolidated balance sheet
 
$
58,501

 
$
(28,612
)
 
$
60,278

 
$
(27,950
)
 
(1)
Relates to commodity derivative assets and liabilities that are expected to be net settled on an exchange or through a netting arrangement with the counterparty.

The following table summarizes the accounts that include our commodity derivative assets and liabilities in our consolidated balance sheets:
 
 
March 31,
 
 
2016
 
2015
 
 
(in thousands)
Prepaid expenses and other current assets
 
$
58,501

 
$
60,278

Accrued expenses and other payables
 
(28,612
)
 
(27,950
)
Net commodity derivative asset
 
$
29,889

 
$
32,328



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The following table summarizes our open commodity derivative contract positions at the dates indicated. We do not account for these derivatives as hedges.
Contracts
 
Settlement Period
 
Net Long
(Short)
Notional
(Barrels)
 
Fair Value
of
Net Assets
(Liabilities)
 
 
 
 
(in thousands)
At March 31, 2016-
 
 
 
 
 
 
Cross-commodity (1)
 
April 2016–March 2017
 
251

 
$
1,663

Crude oil fixed-price (2)
 
April 2016–December 2016
 
(1,583
)
 
(3,655
)
Propane fixed-price (2)
 
April 2016–December 2017
 
540

 
(592
)
Refined products fixed-price (2)
 
April 2016–June 2017
 
(5,355
)
 
48,557

Other
 
April 2016–March 2017
 
 
 
1,493

 
 
 
 
 
 
47,466

Net cash collateral held
 
 
 
 
 
(17,577
)
Net commodity derivatives in consolidated balance sheet
 
 
 
 
 
$
29,889

 
 
 
 
 
 
 
At March 31, 2015-
 
 
 
 
 
 
Cross-commodity (1)
 
April 2015–March 2016
 
98

 
$
(105
)
Crude oil fixed-price (2)
 
April 2015–June 2015
 
(1,113
)
 
(171
)
Crude oil index-price (3)
 
April 2015–July 2015
 
751

 
1,835

Propane fixed-price (2)
 
April 2015–December 2016
 
193

 
(2,842
)
Refined products fixed-price (2)
 
April 2015–December 2015
 
(3,005
)
 
84,996

Other
 
April 2015–December 2015
 
 
 
2,296

 
 
 
 
 
 
86,009

Net cash collateral held
 
 
 
 
 
(53,681
)
Net commodity derivatives in consolidated balance sheet
 
 
 
 
 
$
32,328

 
(1)
Cross-commodity - We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. These contracts are derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.
(2)
Commodity fixed-price - We may have fixed price physical purchases, including inventory, offset by floating price physical sales or floating price physical purchases offset by fixed price physical sales. These contracts are derivatives we have entered into as an economic hedge against the risk of mismatches between fixed and floating price physical obligations.
(3)
Commodity fixed-price - We may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different indices. These indices may vary in the commodity grade or location, or in the timing of delivery within a given month. These contracts are derivatives we have entered into as an economic hedge against the risk of one index moving relative to another index.

The following table summarizes the net gains (losses) recorded from our commodity derivatives to cost of sales for the periods indicated (in thousands):

Year Ending March 31,
 
 
2016
 
$
103,223

2015
 
219,421

2014
 
(43,655
)


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Credit Risk

We 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 for offsetting counterparty receivable and payable balances for certain transactions. At March 31, 2016, our primary counterparties were retailers, resellers, energy marketers, producers, refiners, and dealers. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, as the counterparties may be similarly affected by changes in economic, regulatory or other conditions. If a counterparty does not perform on a contract, we may not realize amounts that have been recorded in our consolidated balance sheets and recognized in our net income.

Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31, 2016, we had $1.8 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 2.94%.

Fair Value of Fixed-Rate Notes

The following table summarizes fair values estimates of our fixed-rate notes at March 31, 2016 (in thousands):
5.125% Notes due 2019
 
$
235,023

6.875% Notes due 2021
 
233,621

6.650% Notes due 2022
 
156,638


For the 2019 Notes and the 2021 Notes, the fair value estimates were developed based on publicly traded quotes and would be classified as Level 1 in the fair value hierarchy. For the 2022 Notes, the fair value estimate was developed using observed yields on publicly traded notes issued by us, adjusted for differences in the key terms of those notes and the key terms of our notes (examples include differences in the tenor of the debt, credit standing of 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 value hierarchy.

Note 13—Segments

The following table summarizes certain financial data related to our segments. Transactions between segments are recorded based on prices negotiated between the segments.

Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and significantly expanded with our July 2014 acquisition of TransMontaigne. 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 partner investment in TLP using the equity method of accounting.

Items labeled “corporate and other” in the table below include the operations of a compressor leasing business that we sold in February 2014 and certain natural gas marketing operations that we acquired in our December 2013 acquisition of Gavilon Energy and wound down during fiscal year 2014. The “corporate and other” category also includes certain corporate expenses that are not allocated to the reportable segments.


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Year Ended March 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Revenues (1):
 
 
 
 
 
 
Crude oil logistics-
 
 
 
 
 
 
Crude oil sales
 
$
3,170,891

 
$
6,621,871

 
$
4,559,923

Crude oil transportation and other
 
55,882

 
43,349

 
36,469

Elimination of intersegment sales
 
(9,694
)
 
(29,836
)
 
(37,847
)
Total crude oil logistics revenues
 
3,217,079

 
6,635,384

 
4,558,545

Water solutions-
 
 
 
 
 
 
Service fees
 
136,710

 
105,682

 
58,161

Recovered hydrocarbons
 
41,090

 
81,762

 
67,627

Water transportation
 
—

 
10,760

 
17,312

Other revenues
 
7,201

 
1,838

 
—

Total water solutions revenues
 
185,001

 
200,042

 
143,100

Liquids-
 
 
 
 
 
 
Propane sales
 
618,919

 
1,265,262

 
1,632,948

Other product sales
 
620,175

 
1,111,834

 
1,231,965

Other revenues
 
35,943

 
28,745

 
31,062

Elimination of intersegment sales
 
(80,558
)
 
(162,016
)
 
(245,550
)
Total liquids revenues
 
1,194,479

 
2,243,825

 
2,650,425

Retail propane-
 
 
 
 
 
 
Propane sales
 
248,673

 
347,575

 
388,225

Distillate sales
 
64,868

 
106,037

 
127,672

Other revenues
 
39,436

 
35,585

 
35,918

Total retail propane revenues
 
352,977

 
489,197

 
551,815

Refined products and renewables-
 
 
 
 
 
 
Refined products sales
 
6,294,008

 
6,682,040

 
1,180,895

Renewables sales
 
390,753

 
473,885

 
176,781

Service fees
 
108,221

 
76,847

 
—

Elimination of intersegment sales
 
(870
)
 
(1,079
)
 
—

Total refined products and renewables revenues
 
6,792,112

 
7,231,693

 
1,357,676

Corporate and other
 
462

 
1,916

 
437,713

Total revenues
 
$
11,742,110

 
$
16,802,057

 
$
9,699,274

Depreciation and Amortization:
 
 
 
 
 
 
Crude oil logistics
 
$
39,363

 
$
38,626

 
$
22,111

Water solutions
 
91,685

 
73,618

 
55,105

Liquids
 
15,642

 
13,513

 
11,018

Retail propane
 
35,992

 
31,827

 
28,878

Refined products and renewables
 
40,861

 
32,948

 
625

Corporate and other
 
5,381

 
3,417

 
3,017

Total depreciation and amortization
 
$
228,924

 
$
193,949

 
$
120,754

Operating Income (Loss):
 
 
 
 
 
 
Crude oil logistics
 
$
(40,745
)
 
$
(35,832
)
 
$
678

Water solutions
 
(313,673
)
 
65,340

 
10,317

Liquids
 
76,173

 
45,072

 
71,888

Retail propane
 
44,096

 
64,075

 
61,285

Refined products and renewables
 
226,951

 
54,567

 
6,514

Corporate and other
 
(97,405
)
 
(85,802
)
 
(44,117
)
Total operating (loss) income
 
$
(104,603
)
 
$
107,420

 
$
106,565

 
(1)
During the six months ended September 30, 2015, we made certain changes in the way we attribute revenues to the categories shown in the table above. These changes did not impact total revenues. We have retrospectively adjusted previously reported amounts to conform to the current presentation.

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The following table summarizes additions to property, plant and equipment by segment. This information has been prepared on the accrual basis, and includes property, plant and equipment acquired in acquisitions.
 
 
Year Ended March 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Additions to property, plant and equipment:
 
 
 
 
 
 
Crude oil logistics
 
$
447,952

 
$
58,747

 
$
204,642

Water solutions
 
211,080

 
186,007

 
100,877

Liquids
 
50,533

 
114,180

 
52,560

Retail propane
 
41,235

 
35,602

 
24,430

Refined products and renewables
 
25,147

 
573,954

 
1,238

Corporate and other
 
15,172

 
1,286

 
7,242

Total
 
$
791,119

 
$
969,776

 
$
390,989


The following tables summarize long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets by segment:
 
 
March 31,
 
 
2016
 
2015
 
 
(in thousands)
Long-lived assets, net:
 
 
 
 
Crude oil logistics
 
$
1,679,027

 
$
1,327,538

Water solutions
 
1,162,405

 
1,244,965

Liquids
 
572,081

 
534,317

Retail propane
 
483,330

 
467,254

Refined products and renewables
 
180,783

 
808,126

Corporate and other
 
36,198

 
32,357

Total
 
$
4,113,824

 
$
4,414,557

 
 
 
 
 
Total assets:
 
 
 
 
Crude oil logistics
 
$
2,197,113

 
$
2,337,188

Water solutions
 
1,236,875

 
1,311,175

Liquids
 
693,872

 
713,810

Retail propane
 
538,267

 
542,078

Refined products and renewables
 
765,806

 
1,669,851

Corporate and other
 
128,222

 
81,690

Total
 
$
5,560,155

 
$
6,655,792

 

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Note 14—Disposals and Impairments

Sale of General Partner Interest in TLP

On February 1, 2016, we completed the sale of our general partner interest in TLP to ArcLight for $350 million in cash and recorded a gain on disposal of $329.9 million during the three months ended March 31, 2016. As part of this transaction, we entered into lease agreements whereby we will remain the long-term exclusive tenant in the TLP Southeast terminal system. As a result of entering into these leases, we deferred $204.6 million of the gain on the sale and will recognize this amount over our future lease payment obligations, which is approximately seven years. During the three months ended March 31, 2016, we recognized $5.0 million of the deferred gain in our consolidated statement of operations. Expected amortization of the deferred gain is as follows (in thousands):

Year Ending March 31,
 

2017
$
30,113

2018
30,113

2019
30,113

2020
30,113

2021
29,593

Thereafter
49,487

Total
$
199,532


Within our consolidated balance sheet, the current portion of the deferred gain, $30.1 million, is recorded in accrued expenses and other payables and the long-term portion, $169.4 million, is recorded in other noncurrent liabilities. In addition, we retained TransMontaigne’s marketing business, which is a significant part of our refined products and renewables segment, and TransMontaigne Product Services, LLC, its customer contracts and its line space on the Colonial and Plantation pipelines. See Note 19 for a discussion of the sale of all common units we held in TLP to an affiliate of ArcLight.

Other Disposals

During the year ended March 31, 2016 in our crude oil logistics segment, (i) two previously-planned projects were canceled and we recorded a loss of $3.1 million and (ii) we sold and/or abandoned certain trucks, trailers and barges and recorded a loss of $1.4 million. These losses are reported within loss on disposal or impairment of assets, net in our consolidated statement of operations.

During the year ended March 31, 2016 in our refined products and renewables segment, we recorded a loss of $1.8 million related to certain property, plant and equipment that we have retired and we also sold certain tank bottoms and recorded a loss of $1.3 million. These losses are reported within loss on disposal or impairment of assets, net in our consolidated statement of operations.

During the year ended March 31, 2016, we received a payment of $3.0 million from the state of Maine to relocate certain terminal assets in our liquids segment. This payment is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations.

During the year ended March 31, 2015, we sold a natural gas liquids terminal and recorded a loss in our consolidated statement of operations of $29.8 million, which included a loss on property, plant and equipment of $21.7 million and a loss of $8.1 million on goodwill allocated to the assets sold. This loss is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations.

During the year ended March 31, 2015, we sold the water transportation business in our water solutions segment and recorded a loss in our consolidated statement of operations of $4.0 million, which included a loss on property, plant and equipment of $2.2 million and a loss of $1.8 million on goodwill allocated to the assets sold. This loss is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations.


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During the year ended March 31, 2015, we recorded a loss on abandonment of $3.1 million related to the property, plant and equipment of water disposal facilities that we have retired in our water solutions segment. This loss is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations.

We acquired Gavilon Energy in December 2013, which operated a natural gas marketing business. During March 2014, we assigned all of the storage and transportation contracts of the natural gas marketing business to a third party. Since these contracts were at unfavorable terms relative to current market conditions, we paid $44.8 million to assign these contracts. We recorded a liability of $50.8 million related to these storage and transportation contracts in the acquisition accounting, and we amortized $6.0 million of this balance as a reduction to cost of sales during the period from the acquisition date through the date we assigned the contracts. We also assigned all forward purchase and sale contracts and all financial derivative contracts, and thereby wound down the natural gas business. Our consolidated statement of operations for the year ended March 31, 2014 includes $1.4 million of operating income related to the natural gas business, which is reported within “corporate and other” in the segment disclosures in Note 13.

We acquired High Sierra in June 2012, which operated a compressor leasing business. We sold the compressor leasing business in February 2014 for $10.8 million (net of the amount due to the owner of the noncontrolling interest in the business). We recorded a gain on the sale of the business of $4.4 million, $1.6 million of which was attributable to the disposal of the noncontrolling interest. We reported the gain as a reduction to loss on disposal or impairment of assets, net in our consolidated statement of operations. Our consolidated statement of operations for the year ended March 31, 2014 includes $2.3 million of operating income related to the compressor leasing business, which is reported within “corporate and other” in the segment disclosures in Note 13.

Long-lived Asset Impairments

During the fourth quarter of fiscal year 2016, we recorded a write-down of $47.7 million related to pipe we no longer expect to use in the originally-planned Grand Mesa Pipeline, which is reported within loss on disposal or impairment of assets, net.

During the year ended March 31, 2016, we recorded an impairment of $2.4 million to the property, plant and equipment of two of our crude oil barges in our crude oil logistics segment, which is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations.

During the year ended March 31, 2016, we wrote off assets of $14.6 million acquired as part of the Gavilon Energy acquisition that we deemed no longer recoverable in our liquids segment, which is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations.

During the year ended March 31, 2014, we recorded an impairment of $5.3 million to the property, plant and equipment of one of our natural gas liquids terminals in our liquids segment, which is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations.

During the year ended March 31, 2014, two of our water solutions facilities in our water solutions segment experienced damage to their property, plant and equipment as a result of lightning strikes. We recorded a write-down to property, plant and equipment of $1.5 million related to these incidents, which is reported within loss on disposal or impairment of assets, net in our consolidated statement of operations.

Goodwill Impairment

Due to the continued decline in crude oil prices and crude oil production, we tested the goodwill within our water solutions reporting unit for impairment at December 31, 2015. At December 31, 2015, our water solutions reporting unit had a goodwill balance of $660.8 million. We estimated the fair value of our water solutions reporting unit based on the income approach, also known as the discounted cash flow method, which utilizes the present value of cash flows to estimate the fair value. The future cash flows of our water solutions reporting unit were projected based upon estimates as of the test date of future revenues, operating expenses and cash outflows necessary to support these cash flows, including working capital and maintenance capital expenditures. We also considered expectations regarding: (i) expected disposal volumes, which have continued in spite of the lower crude oil price environment as oilfield producers have focused on their most productive properties and have continued to deliver disposal volumes to our facilities, and (ii) the crude oil price environment as reflected in crude oil forward prices as of the test date. In performing the discounted cash flow analysis, we utilized reports issued by independent third parties projecting crude oil prices through 2018. We assumed an approximate $1/barrel increase each quarter for the periods beyond those represented in the reports, with crude oil reaching $65/barrel by the fourth quarter of 2021. We

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used a price of $32/barrel for the fourth quarter of 2016, the starting point of our cash flow projections. We kept prices constant at $65/barrel for periods in our model beyond 2021. Consistent with observed disposal volume trends, the disposal volumes were based on an expectation of a certain amount of production returning at certain crude oil price levels. For expenses, we assumed an increase consistent with the increase in disposal volumes. The discount rate used in our discounted cash flow method was calculated by using the average of the range of discount rates from a recent water solutions transaction similar in size to our water solutions reporting unit. The discounted cash flow results indicated that the estimated fair value of our water solutions reporting unit was greater than its carrying value by approximately 9% at December 31, 2015.

As a result of the continued decline in crude oil production, its continued adverse impact on our water solutions reporting unit and the completion of 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 more likely than not that the fair value of our water solutions reporting unit was less than the carry amount. Similar to the testing performed as of December 31, 2015, fair value of the water solutions reporting unit was based on the income approach, which utilizes the present value of cash flows to estimate the fair value. We utilized the same pricing, expense and discount rate assumptions in our current model as described above but adjusted our expected water volumes and percentage recovered hydrocarbons to match what we have budgeted for our fiscal year 2017. Volumes budgeted for fiscal year 2017 were heavily influenced by the reporting unit’s fourth quarter 2017 operating results. We utilized the same assumptions related to anticipated volume growth as above. The discounted cash flow results indicated that the estimated fair value of our water business was less than its carrying value by approximately 11% at March 31, 2016.

During the year ended March 31, 2016, we recorded an estimated goodwill impairment charge of $380.2 million, which is recorded within loss on disposal or impairment of assets in our consolidated statements of operations. We plan to finalize our goodwill impairment analysis prior to issuing our financial statements for the quarter ending June 30, 2016, and will adjust our estimated impairment as needed. At March 31, 2016 our water solutions reporting units had a goodwill balance of $290.9 million.

Our estimated fair value is predicated upon crude oil prices increasing over the next six years based on the third party forecasts utilized and management’s assumption of a price recovery to $65/barrel by 2021. We used this increase in crude oil prices to estimate the volume of wastewater to be processed at our facilities, based on the expected increased production by our customers, and the revenue generated by selling the hydrocarbons extracted from the wastewater. The projected prices we used were from reports generated by independent third parties and were based on their assessment of the market and their expectation of the market going forward. Due to the current volatility in the crude oil market, we believe that it is reasonably possible that crude oil prices could decline. Further declines in crude oil prices would negatively affect the timing of the recovery of crude oil prices and the estimated water disposal volumes we used in our estimates, such that our estimate of fair value could change and result in further impairment of the goodwill in our water solutions reporting unit.

For our other reporting units, we performed a qualitative assessment as of January 1, 2016 to determine whether it is more likely than not that the fair value of each reporting unit is greater than the book value of the reporting unit. Based on these qualitative assessments we determined that the fair value of each of these reporting units was more likely than not greater than the carrying value of the reporting units.

We did not record any goodwill impairments during the years ended March 31, 2015 and March 31, 2014.

Note 15—Transactions with Affiliates

SemGroup Corporation (“SemGroup”) holds ownership interests in our general partner. We sell product to and purchase product from SemGroup, and these transactions are included within revenues and cost of sales, respectively, in our consolidated statements of operations. We also lease crude oil storage from SemGroup.

We purchase ethanol from an equity method investee. These transactions are reported within cost of sales in our consolidated statements of operations.

Certain members of our management and members of their families own interests in entities from which we have purchased products and services and to which we have sold products and services. During the year ended March 31, 2016, $32.7 million of these transactions were capital expenditures and were recorded as increases to property, plant and equipment.


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The following table summarizes these related party transactions:
 
 
Year Ended March 31,
 
 
2016
 
2015
 
2014
 
 
(in thousands)
Sales to SemGroup
 
$
43,825

 
$
88,276

 
$
160,993

Purchases from SemGroup
 
53,209

 
130,134

 
300,164

Sales to equity method investees
 
14,836

 
14,493

 
—

Purchases from equity method investees
 
113,780

 
149,828

 
47,731

Sales to entities affiliated with management
 
318

 
2,151

 
110,824

Purchases from entities affiliated with management
 
45,197

 
29,419

 
120,038


Accounts receivable from affiliates consist of the following at the dates indicated:
 
 
March 31,
 
 
2016
 
2015
 
 
(in thousands)
Receivables from SemGroup
 
$
1,166

 
$
13,443

Receivables from equity method investees
 
14,446

 
652

Receivables from entities affiliated with management
 
13

 
3,103

Total
 
$
15,625

 
$
17,198


Accounts payable to affiliates consist of the following at the dates indicated:
 
 
March 31,
 
 
2016
 
2015
 
 
(in thousands)
Payables to SemGroup
 
$
1,823

 
$
11,546

Payables to equity method investees
 
3,947

 
6,788

Payables to entities affiliated with management
 
1,423

 
7,460

Total
 
$
7,193

 
$
25,794


We also have a loan receivable of $22.3 million at March 31, 2016 from an equity method investee. During the year ended March 31, 2016, we received loan payments of $1.5 million from our investee in accordance with the loan agreement. The investee makes loan payments from time to time in accordance with the loan agreement and is required to make monthly principal payments beginning on June 1, 2018 with the remaining principal balance due on May 31, 2020.

During the year ended March 31, 2014, we completed the acquisition of a crude oil logistics business owned by an employee. We paid $11.0 million of cash for this acquisition.

Note 16—Other Matters

Grand Mesa Pipeline

In September 2014, we entered into a joint venture with RimRock Midstream, LLC (“RimRock”) whereby each party owned a 50% interest in Grand Mesa Pipeline, LLC (“Grand Mesa”). In October 2014, we obtained ship-or-pay volume commitments from multiple shippers to begin construction of the Grand Mesa Pipeline, which will originate in Colorado and terminate in Cushing, Oklahoma. In November 2014, we acquired RimRock’s 50% ownership interest in Grand Mesa for $310.0 million in cash. In November 2015, Grand Mesa Pipeline entered into an agreement with Saddlehorn Pipeline Company, LLC (“Saddlehorn”), under which we acquired a 37.5% undivided interest in a crude oil pipeline currently under construction (the “Joint Pipeline”). The Joint Pipeline will take receipt from Grand Mesa Pipeline’s origin in Colorado and will deliver to Cushing, Oklahoma. We will have the right to utilize 150,000 barrels per day of capacity on the Joint Pipeline. Operating costs will be allocated to us based on our proportionate ownership interest and throughput. We expect the Joint Pipeline to be operational beginning in the third quarter of fiscal year 2017.


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Through our undivided interest in the Joint Pipeline, we will have expanded capacity, sufficient to service our customer contracts at the same origin and termination points with the ability to accept additional volume commitments. We will retain ownership of our previously-acquired easements for the potential future development of transportation projects involving petroleum commodities other than crude oil and condensate. With the consent and participation of Saddlehorn, we and Saddlehorn may consider future opportunities using these easements for projects involving the transportation of crude oil and condensate.

During the six months ended March 31, 2016, we reclassified $47.0 million of costs to acquire land, rights-of-way and easements on the originally-planned Grand Mesa Pipeline route to intangible assets. As discussed above, we acquired an undivided interest in a different crude oil pipeline with the same origin and destination points as those of our originally-planned Grand Mesa Pipeline route. We will retain the land, rights-of-way and easements along the originally-planned Grand Mesa Pipeline route for potential future development.

Purchase of Pipeline Capacity Allocations

On certain interstate refined product pipelines, shipment demand exceeds available capacity, and capacity is allocated to shippers based on their historical shipment volumes. During the year ended March 31, 2015, we paid $24.2 million to acquire certain refined product pipeline capacity allocations from other shippers.

Crude Oil Rail Transloading Facility

In October 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments. Subsequent 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 and additional cash payments over the next five years. In addition, one of the producers committed to pay us a specified fee on each barrel of crude oil it produces in a specified basin over a period of seven years. Upon execution of these agreements in March 2015, we recorded a gain of $31.6 million to other income in our consolidated statement of operations, net of certain project abandonment costs.

Note 17—Error Correction

Subsequent to the issuance of certain previously issued financial statements, we determined that there were errors in those financial statements from not recording certain contingent consideration liabilities related to royalty agreements assumed as part of acquisitions in our water solutions segment. The effect of the error was material to the financial statements for each of the first three fiscal quarters of 2016 so those quarters have been restated for the effects of the error correction. The effect of the error was not material to the financial statements for the fiscal year 2015 or for the quarters within fiscal year 2015. As a result, fiscal year 2015 and the quarters within fiscal year 2015 have been changed for the correction of an immaterial error in accordance with the methodology described in SAB Topic 1N, Considering the Effects of Prior Year Misstatements When Quantifying Misstatements in the Current Year Financial Statements.

We have changed our previously issued (i) consolidated balance sheet at March 31, 2015, (ii) consolidated statement of operations, consolidated statement of comprehensive income, consolidated statement of changes in equity and consolidated statement of cash flows for the year ended March 31, 2015, and (iii) unaudited financial information for the quarters within fiscal year 2015. We are restating our previously issued unaudited financial information for the first three fiscal quarters of 2016. The following tables summarize the impact of the error correction on our consolidated financial statements, each as compared with the amounts presented in previously issued financial statements. Certain of the as previously reported balances include purchase accounting adjustments and the adoption of ASU 2015-03 related to debt issuance costs (see Note 2).

The following tables summarize the as previously reported balances, adjustments, and corrected and restated balances on our consolidated balance sheets by financial statement line item (in thousands):


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December 31, 2015
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Restated
Goodwill
$
1,522,644

 
$
177,509

 
$
1,700,153

Total assets
6,547,043

 
177,509

 
6,724,552

Accrued expenses and other payables
193,295

 
4,563

 
197,858

Total current liabilities
796,908

 
4,563

 
801,471

Other noncurrent liabilities
13,232

 
99,692

 
112,924

Equity - general partner interest
(34,431
)
 
77

 
(34,354
)
Equity - limited partners interest
1,920,528

 
71,734

 
1,992,262

Equity - noncontrolling interests
544,890

 
1,443

 
546,333

Total equity
2,430,839

 
73,254

 
2,504,093

Total liabilities and equity
6,547,043

 
177,509

 
6,724,552

 
September 30, 2015
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Restated
Goodwill
$
1,490,928

 
$
167,309

 
$
1,658,237

Total assets
6,433,747

 
167,309

 
6,601,056

Accrued expenses and other payables
164,433

 
5,469

 
169,902

Total current liabilities
852,170

 
5,469

 
857,639

Other noncurrent liabilities
17,679

 
109,960

 
127,639

Equity - general partner interest
(34,380
)
 
55

 
(34,325
)
Equity - limited partners interest
1,976,663

 
51,080

 
2,027,743

Equity - noncontrolling interests
544,147

 
745

 
544,892

Total equity
2,486,294

 
51,880

 
2,538,174

Total liabilities and equity
6,433,747

 
167,309

 
6,601,056

 
June 30, 2015
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Restated
Goodwill
$
1,451,654

 
$
148,809

 
$
1,600,463

Total assets
6,625,715

 
148,809

 
6,774,524

Accrued expenses and other payables
237,407

 
5,898

 
243,305

Total current liabilities
1,088,700

 
5,898

 
1,094,598

Other noncurrent liabilities
17,082

 
109,083

 
126,165

Equity - general partner interest
(35,097
)
 
36

 
(35,061
)
Equity - limited partners interest
2,056,852

 
33,653

 
2,090,505

Equity - noncontrolling interests
547,162

 
139

 
547,301

Total equity
2,568,800

 
33,828

 
2,602,628

Total liabilities and equity
6,625,715

 
148,809

 
6,774,524


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Table of Contents

 
March 31, 2015
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Goodwill
$
1,433,224

 
$
125,009

 
$
1,558,233

Total assets
6,530,783

 
125,009

 
6,655,792

Accrued expenses and other payables
196,357

 
5,992

 
202,349

Total current liabilities
1,113,875

 
5,992

 
1,119,867

Other noncurrent liabilities
16,321

 
98,708

 
115,029

Equity - general partner interest
(37,021
)
 
21

 
(37,000
)
Equity - limited partners interest
2,162,924

 
20,624

 
2,183,551

Equity - noncontrolling interests
547,326

 
(336
)
 
546,990

Total equity
2,673,120

 
20,309

 
2,693,432

Total liabilities and equity
6,530,783

 
125,009

 
6,655,792

 
December 31, 2014
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Goodwill
$
1,250,239

 
$
111,308

 
$
1,361,547

Total assets
6,905,902

 
111,308

 
7,017,210

Accrued expenses and other payables
277,304

 
5,661

 
282,965

Total current liabilities
1,901,168

 
5,661

 
1,906,829

Other noncurrent liabilities
11,811

 
99,805

 
111,616

Equity - general partner interest
(39,035
)
 
6

 
(39,029
)
Equity - limited partners interest
1,709,150

 
5,638

 
1,714,788

Equity - noncontrolling interests
569,575

 
198

 
569,773

Total equity
2,239,601

 
5,842

 
2,245,443

Total liabilities and equity
6,905,902

 
111,308

 
7,017,210

 
September 30, 2014
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Goodwill
$
1,170,490

 
$
83,783

 
$
1,254,273

Total assets
6,551,679

 
83,783

 
6,635,462

Accrued expenses and other payables
218,482

 
4,922

 
223,404

Total current liabilities
1,759,980

 
4,922

 
1,764,902

Other noncurrent liabilities
39,518

 
75,211

 
114,729

Equity - general partner interest
(39,690
)
 
4

 
(39,686
)
Equity - limited partners interest
1,785,823

 
3,550

 
1,789,373

Equity - noncontrolling interests
568,770

 
96

 
568,866

Total equity
2,314,830

 
3,650

 
2,318,480

Total liabilities and equity
6,551,679

 
83,783

 
6,635,462


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Table of Contents

 
June 30, 2014
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Goodwill
$
1,101,471

 
$
56,830

 
$
1,158,301

Total assets
4,265,502

 
56,830

 
4,322,332

Accrued expenses and other payables
123,939

 
4,621

 
128,560

Total current liabilities
1,034,335

 
4,621

 
1,038,956

Other noncurrent liabilities
8,000

 
50,862

 
58,862

Equity - general partner interest
(41,308
)
 
1

 
(41,307
)
Equity - limited partners interest
1,822,572

 
1,223

 
1,823,795

Equity - subordinated interest
(5,248
)
 
98

 
(5,150
)
Equity - noncontrolling interests
5,327

 
25

 
5,352

Total equity
1,781,292

 
1,347

 
1,782,639

Total liabilities and equity
4,265,502

 
56,830

 
4,322,332


The following tables summarize the as previously reported balances, adjustments and corrected and restated balances on our consolidated statements of operations by financial statement line item for the periods ended (in thousands, except per unit amounts):
 
Three Months Ended
 
December 31, 2015
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Restated
Operating expenses
$
106,783

 
$
(2,062
)
 
$
104,721

Revaluation of liabilities
—

 
(19,312
)
 
(19,312
)
Income before income taxes
30,023

 
21,374

 
51,397

Net income
29,621

 
21,374

 
50,995

Net income allocated to general partner
16,217

 
22

 
16,239

Net income attributable to noncontrolling interests
6,140

 
698

 
6,838

Net income allocated to limited partners
7,264

 
20,654

 
27,918

Basic income per common unit
0.07

 
0.20

 
0.27

Diluted income per common unit
0.03

 
0.19

 
0.22

 
Three Months Ended
 
September 30, 2015
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Restated
Operating expenses
$
99,773

 
$
(2,143
)
 
$
97,630

Revaluation of liabilities
—

 
(15,909
)
 
(15,909
)
Loss before income taxes
(26,938
)
 
18,052

 
(8,886
)
Net loss
(24,152
)
 
18,052

 
(6,100
)
Net income allocated to general partner
16,166

 
19

 
16,185

Net income attributable to noncontrolling interests
2,891

 
606

 
3,497

Net loss allocated to limited partners
(43,209
)
 
17,427

 
(25,782
)
Basic and diluted loss per common unit
(0.41
)
 
0.16

 
(0.25
)

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Three Months Ended
 
June 30, 2015
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Restated
Operating expenses
$
107,914

 
$
(2,324
)
 
$
105,590

Revaluation of liabilities
—

 
(11,195
)
 
(11,195
)
Loss before income taxes
(37,988
)
 
13,519

 
(24,469
)
Net loss
(38,526
)
 
13,519

 
(25,007
)
Net income allocated to general partner
15,359

 
15

 
15,374

Net income attributable to noncontrolling interests
3,875

 
475

 
4,350

Net loss allocated to limited partners
(57,760
)
 
13,029

 
(44,731
)
Basic and diluted loss per common unit
(0.56
)
 
0.13

 
(0.43
)
 
Three Months Ended
 
March 31, 2015
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Operating expenses
$
109,560

 
$
(2,203
)
 
$
107,357

Revaluation of liabilities
—

 
(12,264
)
 
(12,264
)
Income before income taxes
90,297

 
14,467

 
104,764

Net income
90,942

 
14,467

 
105,409

Net income allocated to general partner
13,459

 
15

 
13,474

Net income attributable to noncontrolling interests
4,164

 
(534
)
 
3,630

Net income allocated to limited partners
73,319

 
14,986

 
88,305

Basic and diluted income per common unit
0.78

 
0.15

 
0.93

 
Three Months Ended
 
December 31, 2014
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Operating expenses
$
97,761

 
$
(2,192
)
 
$
95,569

Loss before income taxes
(7,359
)
 
2,192

 
(5,167
)
Net loss
(5,269
)
 
2,192

 
(3,077
)
Net income allocated to general partner
11,783

 
2

 
11,785

Net income attributable to noncontrolling interests
5,649

 
102

 
5,751

Net loss allocated to limited partners
(22,701
)
 
2,088

 
(20,613
)
Basic and diluted loss per common unit
(0.26
)
 
0.03

 
(0.23
)

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Three Months Ended
 
September 30, 2014
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Operating expenses
$
97,419

 
$
(2,303
)
 
$
95,116

Loss before income taxes
(17,801
)
 
2,303

 
(15,498
)
Net loss
(15,879
)
 
2,303

 
(13,576
)
Net income allocated to general partner
11,056

 
3

 
11,059

Net income attributable to noncontrolling interests
3,345

 
71

 
3,416

Net loss allocated to limited partners
(30,280
)
 
2,229

 
(28,051
)
Basic and diluted loss per common unit
(0.34
)
 
0.02

 
(0.32
)
 
Three Months Ended
 
June 30, 2014
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Operating expenses
$
67,436

 
$
(1,347
)
 
$
66,089

Loss before income taxes
(38,875
)
 
1,347

 
(37,528
)
Net loss
(39,910
)
 
1,347

 
(38,563
)
Net income allocated to general partner
9,381

 
1

 
9,382

Net income attributable to noncontrolling interests
65

 
25

 
90

Net loss allocated to limited partners
(49,356
)
 
1,321

 
(48,035
)
Basic and diluted loss per common unit
(0.61
)
 
0.01

 
(0.60
)
 
Six Months Ended
 
September 30, 2015
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Restated
Operating expenses
$
207,687

 
$
(4,467
)
 
$
203,220

Revaluation of liabilities
—

 
(27,104
)
 
(27,104
)
Loss before income taxes
(64,926
)
 
31,571

 
(33,355
)
Net loss
(62,678
)
 
31,571

 
(31,107
)
Net income allocated to general partner
31,525

 
34

 
31,559

Net income attributable to noncontrolling interests
6,766

 
1,081

 
7,847

Net loss allocated to limited partners
(100,969
)
 
30,456

 
(70,513
)
Basic and diluted loss per common unit
(0.97
)
 
0.30

 
(0.67
)

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Table of Contents

 
Six Months Ended
 
September 30, 2014
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Operating expenses
$
164,855

 
$
(3,650
)
 
$
161,205

Loss before income taxes
(56,676
)
 
3,650

 
(53,026
)
Net loss
(55,789
)
 
3,650

 
(52,139
)
Net income allocated to general partner
20,437

 
4

 
20,441

Net income attributable to noncontrolling interests
3,410

 
96

 
3,506

Net loss allocated to limited partners
(79,636
)
 
3,550

 
(76,086
)
Basic and diluted loss per common unit
(0.93
)
 
0.04

 
(0.89
)
 
Nine Months Ended
 
December 31, 2015
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Restated
Operating expenses
$
314,470

 
$
(6,529
)
 
$
307,941

Revaluation of liabilities
—

 
(46,416
)
 
(46,416
)
(Loss) income before income taxes
(34,903
)
 
52,945

 
18,042

Net (loss) income
(33,057
)
 
52,945

 
19,888

Net income allocated to general partner
47,742

 
56

 
47,798

Net income attributable to noncontrolling interests
12,906

 
1,779

 
14,685

Net loss allocated to limited partners
(93,705
)
 
51,110

 
(42,595
)
Basic and diluted loss per common unit
(0.90
)
 
0.49

 
(0.41
)
 
Nine Months Ended
 
December 31, 2014
 
(Unaudited)
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Operating expenses
$
262,616

 
$
(5,842
)
 
$
256,774

Loss before income taxes
(64,035
)
 
5,842

 
(58,193
)
Net loss
(61,058
)
 
5,842

 
(55,216
)
Net income allocated to general partner
32,220

 
6

 
32,226

Net income attributable to noncontrolling interests
9,059

 
198

 
9,257

Net loss allocated to limited partners
(102,337
)
 
5,638

 
(96,699
)
Basic and diluted loss per common unit
(1.17
)
 
0.06

 
(1.11
)

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Table of Contents

 
Year Ended
 
March 31, 2015
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Operating expenses
$
372,176

 
$
(8,045
)
 
$
364,131

Revaluation of liabilities
—

 
(12,264
)
 
(12,264
)
Income before income taxes
26,262

 
20,309

 
46,571

Net income
29,884

 
20,309

 
50,193

Net income allocated to general partner
45,679

 
21

 
45,700

Net income attributable to noncontrolling interests
13,223

 
(336
)
 
12,887

Net loss allocated to limited partners
(29,018
)
 
20,624

 
(8,394
)
Basic and diluted loss per common unit
(0.29
)
 
0.24

 
(0.05
)

The following table summarizes the as previously reported balances, adjustments and corrected balances on the consolidated statement of comprehensive income by financial statement line item for the year ended March 31, 2015 (in thousands):
 
Year Ended
 
March 31, 2015
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Net income
$
29,884

 
$
20,309

 
$
50,193

Comprehensive income
30,011

 
20,309

 
50,320


The only changes to the consolidated statements of comprehensive income for all periods, including the interim periods for fiscal 2015 and 2016, are the changes to net income (loss) shown in the tables above.

The following table summarizes the as previously reported balances, adjustments and corrected balances on our consolidated statement of changes in equity by financial statement line item for the year ended March 31, 2015 (in thousands):
 
Year Ended
 
March 31, 2015
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Net income allocated to general partner
$
45,679

 
$
21

 
$
45,700

Net income attributable to noncontrolling interests
13,223

 
(336
)
 
12,887

Net loss allocated to limited partners
(29,018
)
 
20,624

 
(8,394
)
Net income
29,884

 
20,309

 
50,193

Equity - general partner interest
(37,021
)
 
21

 
(37,000
)
Equity - limited partners interest
2,162,924

 
20,624

 
2,183,551

Equity - noncontrolling interests
547,326

 
(336
)
 
546,990

Total equity
2,673,120

 
20,309

 
2,693,432


The following table summarizes the as previously reported balances, adjustments and corrected balances on our consolidated statement of cash flows by financial statement line item for the year ended March 31, 2015 (in thousands):

F-57
Table of Contents

 
Year Ended
 
March 31, 2015
 
 
 
 
 
 
 
As Reported
 
Adjustment
 
As Corrected
Net income
$
29,884

 
$
20,309

 
$
50,193

Revaluation of liabilities
—

 
(12,264
)
 
(12,264
)
Accrued expenses and other liabilities
(53,844
)
 
(8,045
)
 
(61,889
)

The only changes to the consolidated statements of cash flows for all periods, including the interim periods for fiscal 2015 and 2016, are the changes to net income (loss) and the reconciling items from net income (loss) to cash flows from operations: revaluation of liabilities and changes in accrued expenses and other liabilities. Total cash flows from operating, investing and financing activities are unchanged for all periods.

Note 18—Quarterly Information (Unaudited) (As Corrected and Restated)

The following tables summarize our corrected and restated historical consolidated balance sheets and consolidated statements of operations for the interim quarters impacted by the changes discussed in Note 17. Certain of the as corrected and restated balances include purchase accounting adjustments and the adoption of ASU 2015-03 related to debt issuance costs (see Note 2). The computation of net income (loss) per common unit is done separately by quarter 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, due primarily to the income allocation between the general partner and limited partners and variations in the weighted average units outstanding used in computing such amounts.

Our retail propane segment’s business is seasonal due to weather conditions in our service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Our liquids segment is also subject to seasonal fluctuations, as demand for propane and butane is typically higher during the winter months. Our operating revenues from our other segments 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. The numbers in the tables below, with the exception of the units outstanding and the per unit numbers are represented in thousands.


F-58
Table of Contents

 
 
 
As Restated
 
March 31,
 
December 31,
 
September 30,
 
June 30,
 
2016
 
2015
 
2015
 
2015
ASSETS
 
 
 
 
 
 
 
CURRENT ASSETS:
 
 
 
 
 
 
 
Cash and cash equivalents
$
28,176

 
$
25,179

 
$
30,053

 
$
43,506

Accounts receivable-trade, net of allowance for doubtful accounts
521,014

 
581,621

 
712,025

 
905,196

Accounts receivable-affiliates
15,625

 
3,812

 
6,345

 
18,740

Inventories
367,806

 
414,088

 
408,374

 
489,064

Prepaid expenses and other current assets
95,859

 
117,476

 
120,122

 
130,889

Assets held for sale
—

 
87,383

 
—

 
—

Total current assets
1,028,480

 
1,229,559

 
1,276,919

 
1,587,395

 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation
1,649,572

 
1,972,925

 
1,845,112

 
1,743,584

GOODWILL
1,315,362

 
1,700,153

 
1,658,237

 
1,600,463

INTANGIBLE ASSETS, net of accumulated amortization
1,148,890

 
1,225,012

 
1,215,102

 
1,234,542

INVESTMENTS IN UNCONSOLIDATED ENTITIES
219,550

 
467,559

 
473,239

 
474,221

LOAN RECEIVABLE-AFFILIATE
22,262

 
23,258

 
23,775

 
23,775

OTHER NONCURRENT ASSETS
176,039

 
106,086

 
108,672

 
110,544

Total assets
$
5,560,155

 
$
6,724,552

 
$
6,601,056

 
$
6,774,524

 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
 
 
 
Accounts payable-trade
$
420,306

 
$
511,309

 
$
568,523

 
$
755,062

Accounts payable-affiliates
7,193

 
11,042

 
18,794

 
25,592

Accrued expenses and other payables
214,426

 
197,858

 
169,902

 
243,305

Advance payments received from customers
56,185

 
73,662

 
96,380

 
66,706

Current maturities of long-term debt
7,907

 
7,600

 
4,040

 
3,933

Total current liabilities
706,017

 
801,471

 
857,639

 
1,094,598

 
 
 
 
 
 
 
 
LONG-TERM DEBT, net of debt issuance costs and current maturities
2,912,837

 
3,306,064

 
3,077,604

 
2,951,133

OTHER NONCURRENT LIABILITIES
247,236

 
112,924

 
127,639

 
126,165

 
 
 
 
 
 
 
 
COMMITMENTS AND CONTINGENCIES
—

 
—

 
—

 
—

 
 
 
 
 
 
 
 
EQUITY:
 
 
 
 
 
 
 
General partner, representing a 0.1% interest
(50,811
)
 
(34,354
)
 
(34,325
)
 
(35,061
)
Limited partners, representing a 99.9% interest
1,707,326

 
1,992,262

 
2,027,743

 
2,090,505

Accumulated other comprehensive loss
(157
)
 
(148
)
 
(136
)
 
(117
)
Noncontrolling interests
37,707

 
546,333

 
544,892

 
547,301

Total equity
1,694,065

 
2,504,093

 
2,538,174

 
2,602,628

Total liabilities and equity
$
5,560,155

 
$
6,724,552

 
$
6,601,056

 
$
6,774,524





F-59
Table of Contents

 
As Corrected
 
March 31,
 
December 31,
 
September 30,
 
June 30,
 
2015
 
2014
 
2014
 
2014
ASSETS
 
 
 
 
 
 
 
CURRENT ASSETS:
 
 
 
 
 
 
 
Cash and cash equivalents
$
41,303

 
$
30,556

 
$
11,823

 
$
39,679

Accounts receivable-trade, net of allowance for doubtful accounts
1,025,763

 
1,664,039

 
1,433,117

 
903,011

Accounts receivable-affiliates
17,198

 
42,549

 
41,706

 
1,110

Inventories
442,025

 
535,928

 
941,589

 
373,633

Prepaid expenses and other current assets
121,207

 
184,675

 
156,818

 
58,613

Total current assets
1,647,496

 
2,457,747

 
2,585,053

 
1,376,046

 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation
1,624,016

 
1,472,295

 
1,433,313

 
863,457

GOODWILL
1,558,233

 
1,361,547

 
1,254,273

 
1,158,301

INTANGIBLE ASSETS, net of accumulated amortization
1,232,308

 
1,153,028

 
838,088

 
699,315

INVESTMENTS IN UNCONSOLIDATED ENTITIES
472,673

 
478,444

 
482,644

 
211,480

LOAN RECEIVABLE-AFFILIATE
8,154

 
—

 
—

 
—

OTHER NONCURRENT ASSETS
112,912

 
94,149

 
42,091

 
13,733

Total assets
$
6,655,792

 
$
7,017,210

 
$
6,635,462

 
$
4,322,332

 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
 
 
 
Accounts payable-trade
$
833,018

 
$
1,534,568

 
$
1,345,024

 
$
810,149

Accounts payable-affiliates
25,794

 
12,766

 
85,307

 
37,706

Accrued expenses and other payables
202,349

 
282,965

 
223,404

 
128,560

Advance payments received from customers
54,234

 
72,075

 
106,105

 
56,373

Current maturities of long-term debt
4,472

 
4,455

 
5,062

 
6,168

Total current liabilities
1,119,867

 
1,906,829

 
1,764,902

 
1,038,956

 
 
 
 
 
 
 
 
LONG-TERM DEBT, net of debt issuance costs and current maturities
2,727,464

 
2,753,322

 
2,437,351

 
1,441,875

OTHER NONCURRENT LIABILITIES
115,029

 
111,616

 
114,729

 
58,862

 
 
 
 
 
 
 
 
COMMITMENTS AND CONTINGENCIES
0

 
0

 
0

 
0

 
 
 
 
 
 
 
 
EQUITY:
 
 
 
 
 
 
 
General partner, representing a 0.1% interest
(37,000
)
 
(39,029
)
 
(39,686
)
 
(41,307
)
Limited partners, representing a 99.9% interest
2,183,551

 
1,714,788

 
1,789,373

 
1,823,795

Subordinated units
—

 
—

 
—

 
(5,150
)
Accumulated other comprehensive loss
(109
)
 
(89
)
 
(73
)
 
(51
)
Noncontrolling interests
546,990

 
569,773

 
568,866

 
5,352

Total equity
2,693,432

 
2,245,443

 
2,318,480

 
1,782,639

Total liabilities and equity
$
6,655,792

 
$
7,017,210

 
$
6,635,462

 
$
4,322,332




F-60
Table of Contents

 
 
 
As Restated
 
Three Months Ended
 
March 31,
 
December 31,
 
September 30,
 
June 30,
 
2016
 
2015
 
2015
 
2015
REVENUES:
 
 
 
 
 
 
 
Crude oil logistics
$
362,292

 
$
519,425

 
$
1,007,578

 
$
1,327,784

Water solutions
37,776

 
45,438

 
47,494

 
54,293

Liquids
332,975

 
353,527

 
258,992

 
248,985

Retail propane
135,179

 
100,145

 
53,206

 
64,447

Refined products and renewables
1,456,756

 
1,666,471

 
1,825,925

 
1,842,960

Other
462

 
—

 
—

 
—

Total Revenues
2,325,440

 
2,685,006

 
3,193,195

 
3,538,469

 
 
 
 
 
 
 
 
COST OF SALES:
 
 
 
 
 
 
 
Crude oil logistics
341,477

 
495,529

 
982,719

 
1,291,992

Water solutions
752

 
(3,128
)
 
(8,567
)
 
3,607

Liquids
282,961

 
300,766

 
221,115

 
232,276

Retail propane
60,340

 
45,974

 
20,879

 
29,564

Refined products and renewables
1,391,448

 
1,594,359

 
1,789,680

 
1,765,112

Other
182

 
—

 
—

 
—

Total Cost of Sales
2,077,160

 
2,433,500

 
3,005,826

 
3,322,551

 
 
 
 
 
 
 
 
OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
Operating
93,177

 
104,721

 
97,630

 
105,590

General and administrative
24,727

 
23,035

 
29,298

 
62,481

Depreciation and amortization
53,152

 
59,180

 
56,761

 
59,831

Loss on disposal or impairment of assets, net
317,726

 
1,328

 
1,291

 
421

Revaluation of liabilities
(36,257
)
 
(19,312
)
 
(15,909
)
 
(11,195
)
Operating (Loss) Income
(204,245
)
 
82,554

 
18,298

 
(1,210
)
 
 
 
 
 
 
 
 
OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Equity in earnings of unconsolidated entities
2,113

 
2,858

 
2,432

 
8,718

Interest expense
(34,540
)
 
(36,176
)
 
(31,571
)
 
(30,802
)
Gain on early extinguishment of debt
28,532

 
—

 
—

 
—

Other income (expense), net
2,634

 
2,161

 
1,955

 
(1,175
)
(Loss) Income Before Income Taxes
(205,506
)
 
51,397

 
(8,886
)
 
(24,469
)
 
 
 
 
 
 
 
 
INCOME TAX (EXPENSE) BENEFIT
(1,479
)
 
(402
)
 
2,786

 
(538
)
 
 
 
 
 
 
 
 
Net (Loss) Income
(206,985
)
 
50,995

 
(6,100
)
 
(25,007
)
 
 
 
 
 
 
 
 
LESS: NET LOSS (INCOME) ALLOCATED TO GENERAL PARTNER
178

 
(16,239
)
 
(16,185
)
 
(15,374
)
LESS: NET LOSS (INCOME) ATTRIBUTABLE TO NONCONTROLLING INTERESTS
2,853

 
(6,838
)
 
(3,497
)
 
(4,350
)
NET (LOSS) INCOME ALLOCATED TO LIMITED PARTNERS
$
(203,954
)
 
$
27,918

 
$
(25,782
)
 
$
(44,731
)
BASIC (LOSS) INCOME PER COMMON UNIT
$
(1.94
)
 
$
0.27

 
$
(0.25
)
 
$
(0.43
)
DILUTED (LOSS) INCOME PER COMMON UNIT
$
(1.94
)
 
$
0.22

 
$
(0.25
)
 
$
(0.43
)
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
104,930,260

 
105,338,200

 
105,189,463

 
103,888,281

DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
104,930,260

 
106,194,547

 
105,189,463

 
103,888,281


F-61
Table of Contents

 
As Corrected
 
Three Months Ended
 
March 31,
 
December 31,
 
September 30,
 
June 30,
 
2015
 
2014
 
2014
 
2014
REVENUES:
 
 
 
 
 
 
 
Crude oil logistics
$
900,077

 
$
1,694,881

 
$
2,111,143

 
$
1,929,283

Water solutions
49,768

 
50,241

 
52,719

 
47,314

Liquids
543,819

 
685,096

 
539,753

 
475,157

Retail propane
203,172

 
139,765

 
68,358

 
77,902

Refined products and renewables
1,523,532

 
1,983,444

 
2,607,220

 
1,117,497

Other
403

 
(1,281
)
 
1,333

 
1,461

Total Revenues
3,220,771

 
4,552,146

 
5,380,526

 
3,648,614

 
 
 
 
 
 
 
 
COST OF SALES:
 
 
 
 
 
 
 
Crude oil logistics
881,781

 
1,697,374

 
2,083,712

 
1,897,639

Water solutions
(2,555
)
 
(29,085
)
 
(9,439
)
 
10,573

Liquids
478,524

 
657,010

 
514,064

 
462,016

Retail propane
109,948

 
81,172

 
39,894

 
47,524

Refined products and renewables
1,465,287

 
1,905,021

 
2,550,851

 
1,114,313

Other
36

 
176

 
383

 
1,988

Total Cost of Sales
2,933,021

 
4,311,668

 
5,179,465

 
3,534,053

 
 
 
 
 
 
 
 
OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
Operating
107,357

 
95,569

 
95,116

 
66,089

General and administrative
35,688

 
44,230

 
41,639

 
27,873

Depreciation and amortization
54,140

 
50,335

 
50,099

 
39,375

Loss on disposal or impairment of assets, net
6,545

 
30,073

 
4,134

 
432

Revaluation of liabilities
(12,264
)
 
—

 
—

 
—

Operating Income (Loss)
96,284

 
20,271

 
10,073

 
(19,208
)
 
 
 
 
 
 
 
 
OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
Equity in earnings of unconsolidated entities
4,599

 
1,242

 
3,697

 
2,565

Interest expense
(30,927
)
 
(30,051
)
 
(28,651
)
 
(20,494
)
Other income (expense), net
34,808

 
3,371

 
(617
)
 
(391
)
Income (Loss) Before Income Taxes
104,764

 
(5,167
)
 
(15,498
)
 
(37,528
)
 
 
 
 
 
 
 
 
INCOME TAX BENEFIT (EXPENSE)
645

 
2,090

 
1,922

 
(1,035
)
 
 
 
 
 
 
 
 
Net Income (Loss)
105,409

 
(3,077
)
 
(13,576
)
 
(38,563
)
 
 
 
 
 
 
 
 
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER
(13,474
)
 
(11,785
)
 
(11,059
)
 
(9,382
)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
(3,630
)
 
(5,751
)
 
(3,416
)
 
(90
)
NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS
$
88,305

 
$
(20,613
)
 
$
(28,051
)
 
$
(48,035
)
BASIC INCOME (LOSS) PER COMMON UNIT
$
0.93

 
$
(0.23
)
 
$
(0.32
)
 
$
(0.60
)
DILUTED INCOME (LOSS) PER COMMON UNIT
$
0.93

 
$
(0.23
)
 
$
(0.32
)
 
$
(0.60
)
BASIC WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
94,447,339

 
88,545,764

 
88,331,653

 
74,126,205

DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING
94,447,339

 
88,545,764

 
88,331,653

 
74,126,205



F-62
Table of Contents


On February 1, 2016, we completed the sale of our general partner interest in TLP to ArcLight and recognized a gain of $130.4 million in our consolidated statement of operations (see Note 14 for a further discussion).

During the fourth quarter of fiscal year 2016, we recorded an estimated goodwill impairment charge of $380.2 million as the decline in crude oil prices and crude oil production have had an unfavorable impact on our water solutions business. Also, during the fourth quarter of fiscal year 2016, we recorded write-downs and impairments of certain property, plant and equipment of $64.7 million (see Note 14 for a further discussion).

During the fourth quarter of fiscal year 2016, we repurchased a portion of our 2019 Notes and 2021 Notes and recorded a gain on the early extinguishment of debt of $28.5 million (see Note 8 for a further discussion).

As described in Note 16, in March 2015, we agreed to release certain producers from certain commitments in return for a cash payment in March 2015 and additional cash payments over the next five years. Upon execution of these agreements in March 2015, we recorded a gain of $31.6 million to other income in our consolidated statement of operations, net of certain project abandonment costs.

Note 19—Subsequent Events

Sale of TLP Common Units

On April 1, 2016, we sold all of the TLP common units we owned to ArcLight for approximately $112.4 million in cash.
 
Repurchases of Senior Notes

During April 2016, we repurchased $5.0 million of our 2019 Notes and $19.2 million of our 2021 Notes for an aggregate purchase price of $15.1 million (excluding payments of accrued interest).  As a result, we expect to record a gain on the early extinguishment of these notes of $8.6 million (net of the write off of debt issuance costs of $0.5 million) during the three months ended June 30, 2016.

Class A Convertible Preferred Units

On April 21, 2016, we entered into an agreement to issue $200 million of 10.75% Class A Convertible Preferred Units (“Preferred Units”) to Oaktree Capital Management L.P. (“Oaktree”). Oaktree may acquire 16.6 million Preferred Units at a price of $12.03 per unit as well as 3.6 million warrants, which are subject to certain vesting and exercise terms. We expect to use the net proceeds from the issuance of the Preferred Units to repay borrowings outstanding on our Revolving Credit Facility, which may be re-borrowed in the future to fund capital expenditures and for other general partnership purposes.

Note 20—Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and the 2021 Notes (see Note 8). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the consolidating financial information for NGL Energy Partners LP, NGL Energy Finance Corp. (which, along with NGL Energy Partners LP, is a co-issuer of the 2019 Notes and 2021 Notes), the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below.

During the periods presented in the tables below, the status of certain subsidiaries changed, in that they either became guarantors of or ceased to be guarantors of the 2019 Notes and 2021 Notes. Such changes have been given retrospective application in the tables below.

There are no significant restrictions that prevent the parent or any of the guarantor subsidiaries from obtaining funds from their respective subsidiaries by dividend or loan. None of the assets of the guarantor subsidiaries (other than the investments in non-guarantor subsidiaries) are restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act of 1933, as amended.


F-63
Table of Contents

For purposes of the tables below, (i) the consolidating financial information is presented on a legal entity basis, (ii) investments in consolidated subsidiaries are accounted for as equity method investments, and (iii) contributions, distributions, and advances to (from) consolidated entities are reported on a net basis within net changes in advances with consolidated entities in the consolidating statement of cash flow tables below.

F-64
Table of Contents

NGL ENERGY PARTNERS LP
Consolidating Balance Sheet
(U.S. Dollars in Thousands)
 
 
March 31, 2016
 
 
NGL Energy
Partners LP
(Parent)(1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
CURRENT ASSETS:
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
25,749

 
$
—

 
$
784

 
$
1,643

 
$
—

 
$
28,176

Accounts receivable-trade, net of allowance for doubtful accounts
 
—

 
—

 
516,362

 
4,652

 
—

 
521,014

Accounts receivable-affiliates
 
—

 
—

 
15,625

 
—

 
—

 
15,625

Inventories
 
—

 
—

 
367,250

 
556

 
—

 
367,806

Prepaid expenses and other current assets
 
—

 
—

 
94,426

 
1,433

 
—

 
95,859

Total current assets
 
25,749

 
—

 
994,447

 
8,284

 
—

 
1,028,480

 
 
 
 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation
 
—

 
—

 
1,568,488

 
81,084

 
—

 
1,649,572

GOODWILL
 
—

 
—

 
1,313,364

 
1,998

 
—

 
1,315,362

INTANGIBLE ASSETS, net of accumulated amortization
 
—

 
—

 
1,146,355

 
2,535

 
—

 
1,148,890

INVESTMENTS IN UNCONSOLIDATED ENTITIES
 
—

 
—

 
219,550

 
—

 
—

 
219,550

NET INTERCOMPANY RECEIVABLES (PAYABLES)
 
1,404,479

 
—

 
(1,402,360
)
 
(2,119
)
 
—

 
—

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES
 
1,254,383

 
—

 
42,227

 
—

 
(1,296,610
)
 
—

LOAN RECEIVABLE-AFFILIATE
 
—

 
—

 
22,262

 
—

 
—

 
22,262

OTHER NONCURRENT ASSETS
 
—

 
—

 
175,512

 
527

 
—

 
176,039

Total assets
 
$
2,684,611

 
$
—

 
$
4,079,845

 
$
92,309

 
$
(1,296,610
)
 
$
5,560,155

 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts payable-trade
 
$
—

 
$
—

 
$
417,707

 
$
2,599

 
$
—

 
$
420,306

Accounts payable-affiliates
 
1

 
—

 
7,190

 
2

 
—

 
7,193

Accrued expenses and other payables
 
16,887

 
—

 
196,596

 
943

 
—

 
214,426

Advance payments received from customers
 
—

 
—

 
55,737

 
448

 
—

 
56,185

Current maturities of long-term debt
 
—

 
—

 
7,109

 
798

 
—

 
7,907

Total current liabilities
 
16,888

 
—

 
684,339

 
4,790

 
—

 
706,017

 
 
 
 
 
 
 
 
 
 
 
 
 
LONG-TERM DEBT, net of debt issuance costs and current maturities
 
1,011,365

 
—

 
1,894,428

 
7,044

 
—

 
2,912,837

OTHER NONCURRENT LIABILITIES
 
—

 
—

 
246,695

 
541

 
—

 
247,236

 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
Partners’ equity
 
1,656,358

 
—

 
1,254,384

 
80,090

 
(1,334,317
)
 
1,656,515

Accumulated other comprehensive loss
 
—

 
—

 
(1
)
 
(156
)
 
—

 
(157
)
Noncontrolling interests
 
—

 
—

 
—

 
—

 
37,707

 
37,707

Total equity
 
1,656,358

 
—

 
1,254,383

 
79,934

 
(1,296,610
)
 
1,694,065

Total liabilities and equity
 
$
2,684,611

 
$
—

 
$
4,079,845

 
$
92,309

 
$
(1,296,610
)
 
$
5,560,155

 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Since the parent received the proceeds from the issuance of the 2019 Notes and 2021 Notes, all activity has been reflected in the parent column.


F-65
Table of Contents

NGL ENERGY PARTNERS LP
Consolidating Balance Sheet
(U.S. Dollars in Thousands)
 
 
March 31, 2015
 
 
NGL Energy
Partners LP
(Parent)(1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
ASSETS
 
 
 
 
 
 
 
 
 
 
 
 
CURRENT ASSETS:
 
 
 
 
 
 
 
 
 
 
 
 
Cash and cash equivalents
 
$
29,115

 
$
—

 
$
9,757

 
$
2,431

 
$
—

 
$
41,303

Accounts receivable-trade, net of allowance for doubtful accounts
 
—

 
—

 
1,007,001

 
18,762

 
—

 
1,025,763

Accounts receivable-affiliates
 
5

 
—

 
16,610

 
583

 
—

 
17,198

Inventories
 
—

 
—

 
440,289

 
1,736

 
—

 
442,025

Prepaid expenses and other current assets
 
—

 
—

 
104,771

 
16,436

 
—

 
121,207

Total current assets
 
29,120

 
—

 
1,578,428

 
39,948

 
—

 
1,647,496

 
 
 
 
 
 
 
 
 
 
 
 
 
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation
 
—

 
—

 
1,092,271

 
531,745

 
—

 
1,624,016

GOODWILL
 
—

 
—

 
1,526,067

 
32,166

 
—

 
1,558,233

INTANGIBLE ASSETS, net of accumulated amortization
 
—

 
—

 
1,167,795

 
64,513

 
—

 
1,232,308

INVESTMENTS IN UNCONSOLIDATED ENTITIES
 
—

 
—

 
217,600

 
255,073

 
—

 
472,673

NET INTERCOMPANY RECEIVABLES (PAYABLES)
 
1,363,792

 
—

 
(1,319,388
)
 
(44,404
)
 
—

 
—

INVESTMENTS IN CONSOLIDATED SUBSIDIARIES
 
1,855,386

 
—

 
56,690

 
—

 
(1,912,076
)
 
—

LOAN RECEIVABLE-AFFILIATE
 
—

 
—

 
8,154

 
—

 
—

 
8,154

OTHER NONCURRENT ASSETS
 
—

 
—

 
110,195

 
2,717

 
—

 
112,912

Total assets
 
$
3,248,298

 
$
—

 
$
4,437,812

 
$
881,758

 
$
(1,912,076
)
 
$
6,655,792

 
 
 
 
 
 
 
 
 
 
 
 
 
LIABILITIES AND EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
CURRENT LIABILITIES:
 
 
 
 
 
 
 
 
 
 
 
 
Accounts payable-trade
 
$
—

 
$
—

 
$
820,042

 
$
12,976

 
$
—

 
$
833,018

Accounts payable-affiliates
 
—

 
—

 
25,690

 
104

 
—

 
25,794

Accrued expenses and other payables
 
19,690

 
—

 
172,074

 
10,585

 
—

 
202,349

Advance payments received from customers
 
—

 
—

 
53,903

 
331

 
—

 
54,234

Current maturities of long-term debt
 
—

 
—

 
4,413

 
59

 
—

 
4,472

Total current liabilities
 
19,690

 
—

 
1,076,122

 
24,055

 
—

 
1,119,867

 
 
 
 
 
 
 
 
 
 
 
 
 
LONG-TERM DEBT, net of debt issuance costs and current maturities (2)
 
1,082,166

 
—

 
1,395,099

 
250,199

 
—

 
2,727,464

OTHER NONCURRENT LIABILITIES
 
—

 
—

 
111,205

 
3,824

 
—

 
115,029

 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY
 
 
 
 
 
 
 
 
 
 
 
 
Partners’ equity
 
2,146,442

 
—

 
1,855,386

 
603,789

 
(2,459,066
)
 
2,146,551

Accumulated other comprehensive loss
 
—

 
—

 
—

 
(109
)
 
—

 
(109
)
Noncontrolling interests
 
—

 
—

 
—

 
—

 
546,990

 
546,990

Total equity
 
2,146,442

 
—

 
1,855,386

 
603,680

 
(1,912,076
)
 
2,693,432

Total liabilities and equity
 
$
3,248,298

 
$
—

 
$
4,437,812

 
$
881,758

 
$
(1,912,076
)
 
$
6,655,792

 
 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes. Since the parent received the proceeds from the issuance of the 2019 Notes and 2021 Notes, all activity has been reflected in the parent column.
(2)
The carrying value of long-term debt in the NGL Energy Partners LP (Parent) column has been reduced by $17.8 million of debt issuance costs.

F-66
Table of Contents

NGL ENERGY PARTNERS LP
Consolidating Statement of Operations
(U.S. Dollars in Thousands)
 
 
Year Ended March 31, 2016
 
 
NGL Energy
Partners LP
(Parent) (1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$
—

 
$
—

 
$
11,593,272

 
$
182,175

 
$
(33,337
)
 
$
11,742,110

 
 
 
 
 
 
 
 
 
 
 
 
 
COST OF SALES
 
—

 
—

 
10,843,937

 
28,237

 
(33,137
)
 
10,839,037

 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
 
 
 
 
 
Operating
 
—

 
—

 
327,377

 
73,941

 
(200
)
 
401,118

General and administrative
 
—

 
—

 
122,196

 
17,345

 
—

 
139,541

Depreciation and amortization
 
—

 
—

 
184,091

 
44,833

 
—

 
228,924

Loss on disposal or impairment of assets, net
 
—

 
—

 
303,422

 
17,344

 
—

 
320,766

Revaluation 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

 
—

 
16,121

Interest expense
 
(43,493
)
 
—

 
(82,360
)
 
(7,546
)
 
310

 
(133,089
)
Gain on early extinguishment of debt
 
—

 
—

 
28,532

 
—

 
—

 
28,532

Other income, net
 
—

 
—

 
5,533

 
352

 
(310
)
 
5,575

 
 
 
 
 
 
 
 
 
 
 
 
 
(Loss) Income Before Income Taxes
 
(43,493
)
 
—

 
(148,999
)
 
5,028

 
—

 
(187,464
)
 
 
 
 
 
 
 
 
 
 
 
 
 
INCOME TAX BENEFIT (EXPENSE)
 
—

 
—

 
574

 
(207
)
 
—

 
367

 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY IN NET LOSS OF CONSOLIDATED SUBSIDIARIES
 
(155,436
)
 
—

 
(7,011
)
 
—

 
162,447

 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
Net (Loss) Income
 
(198,929
)
 
—

 
(155,436
)
 
4,821

 
162,447

 
(187,097
)
 
 
 
 
 
 
 
 
 
 
 
 
 
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER
 
 
 
 
 
 
 
 
 
(47,620
)
 
(47,620
)
 
 
 
 
 
 
 
 
 
 
 
 
 
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
(11,832
)
 
(11,832
)
 
 
 
 
 
 
 
 
 
 
 
 
 
NET (LOSS) INCOME ALLOCATED TO LIMITED PARTNERS
 
$
(198,929
)
 
$
—

 
$
(155,436
)
 
$
4,821

 
$
102,995

 
$
(246,549
)
 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.


F-67
Table of Contents

NGL ENERGY PARTNERS LP
Consolidating Statement of Operations
(U.S. Dollars in Thousands)
 
 
Year Ended March 31, 2015
 
 
NGL Energy
Partners LP
(Parent) (1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$
—

 
$
—

 
$
16,648,382

 
$
189,979

 
$
(36,304
)
 
$
16,802,057

 
 
 
 
 
 
 
 
 
 
 
 
 
COST OF SALES
 
—

 
—

 
15,934,529

 
59,825

 
(36,147
)
 
15,958,207

 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
 
 
 
 
 
Operating
 
—

 
—

 
306,576

 
57,555

 
—

 
364,131

General and administrative
 
—

 
—

 
131,898

 
17,532

 
—

 
149,430

Depreciation and amortization
 
—

 
—

 
161,906

 
32,043

 
—

 
193,949

Loss on disposal or impairment of assets, net
 
—

 
—

 
11,619

 
29,565

 
—

 
41,184

Revaluation of liabilities
 
—

 
—

 
(12,264
)
 
—

 
—

 
(12,264
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Income (Loss)
 
—

 
—

 
114,118

 
(6,541
)
 
(157
)
 
107,420

 
 
 
 
 
 
 
 
 
 
 
 
 
OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of unconsolidated entities
 
—

 
—

 
6,640

 
5,463

 
—

 
12,103

Interest expense
 
(65,723
)
 
—

 
(39,023
)
 
(5,423
)
 
46

 
(110,123
)
Other income, net
 
—

 
—

 
36,953

 
264

 
(46
)
 
37,171

 
 
 
 
 
 
 
 
 
 
 
 
 
(Loss) Income Before Income Taxes
 
(65,723
)
 
—

 
118,688

 
(6,237
)
 
(157
)
 
46,571

 
 
 
 
 
 
 
 
 
 
 
 
 
INCOME TAX BENEFIT (EXPENSE)
 
—

 
—

 
3,795

 
(173
)
 
—

 
3,622

 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES
 
103,029

 
—

 
(19,297
)
 
—

 
(83,732
)
 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income (Loss)
 
37,306

 
—

 
103,186

 
(6,410
)
 
(83,889
)
 
50,193

 
 
 
 
 
 
 
 
 
 
 
 
 
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER
 
 
 
 
 
 
 
 
 
(45,700
)
 
(45,700
)
 
 
 
 
 
 
 
 
 
 
 
 
 
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
(12,887
)
 
(12,887
)
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS
 
$
37,306

 
$
—

 
$
103,186

 
$
(6,410
)
 
$
(142,476
)
 
$
(8,394
)
 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.


F-68
Table of Contents

NGL ENERGY PARTNERS LP
Consolidating Statement of Operations
(U.S. Dollars in Thousands)
 
 
Year Ended March 31, 2014
 
 
NGL Energy
Partners LP
(Parent) (1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
REVENUES
 
$
—

 
$
—

 
$
9,560,124

 
$
139,519

 
$
(369
)
 
$
9,699,274

 
 
 
 
 
 
 
 
 
 
 
 
 
COST OF SALES
 
—

 
—

 
9,011,011

 
122,057

 
(369
)
 
9,132,699

 
 
 
 
 
 
 
 
 
 
 
 
 
OPERATING COSTS AND EXPENSES:
 
 
 
 
 
 
 
 
 
 
 
 
Operating
 
—

 
—

 
250,841

 
8,958

 
—

 
259,799

General and administrative
 
—

 
—

 
73,756

 
2,104

 
—

 
75,860

Depreciation and amortization
 
—

 
—

 
117,573

 
3,181

 
—

 
120,754

Loss (gain) on disposal or impairment of assets, net
 
—

 
—

 
6,373

 
(2,776
)
 
—

 
3,597

 
 
 
 
 
 
 
 
 
 
 
 
 
Operating Income
 
—

 
—

 
100,570

 
5,995

 
—

 
106,565

 
 
 
 
 
 
 
 
 
 
 
 
 
OTHER INCOME (EXPENSE):
 
 
 
 
 
 
 
 
 
 
 
 
Equity in earnings of unconsolidated entities
 
—

 
—

 
1,898

 
—

 
—

 
1,898

Interest expense
 
(31,818
)
 
—

 
(27,031
)
 
(51
)
 
46

 
(58,854
)
Other income (expense), net
 
—

 
—

 
202

 
(70
)
 
(46
)
 
86

 
 
 
 
 
 
 
 
 
 
 
 
 
(Loss) Income Before Income Taxes
 
(31,818
)
 
—

 
75,639

 
5,874

 
—

 
49,695

 
 
 
 
 
 
 
 
 
 
 
 
 
INCOME TAX EXPENSE
 
—

 
—

 
(937
)
 
—

 
—

 
(937
)
 
 
 
 
 
 
 
 
 
 
 
 
 
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES
 
79,473

 
—

 
4,771

 
—

 
(84,244
)
 
—

 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
47,655

 
—

 
79,473

 
5,874

 
(84,244
)
 
48,758

 
 
 
 
 
 
 
 
 
 
 
 
 
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER
 
 
 
 
 
 
 
 
 
(14,148
)
 
(14,148
)
 
 
 
 
 
 
 
 
 
 
 
 
 
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS
 
 
 
 
 
 
 
 
 
(1,103
)
 
(1,103
)
 
 
 
 
 
 
 
 
 
 
 
 
 
NET INCOME ALLOCATED TO LIMITED PARTNERS
 
$
47,655

 
$
—

 
$
79,473

 
$
5,874

 
$
(99,495
)
 
$
33,507

 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.


F-69
Table of Contents

NGL ENERGY PARTNERS LP
Consolidating Statements of Comprehensive Income (Loss)
(U.S. Dollars in Thousands)
 
 
Year Ended March 31, 2016
 
 
NGL Energy
Partners LP
(Parent) (1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
Net (loss) income
 
$
(198,929
)
 
$
—

 
$
(155,436
)
 
$
4,821

 
$
162,447

 
$
(187,097
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Other comprehensive loss
 
—

 
—

 
—

 
(48
)
 
—

 
(48
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive (loss) income
 
$
(198,929
)
 
$
—

 
$
(155,436
)
 
$
4,773

 
$
162,447

 
$
(187,145
)
 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.


 
 
Year Ended March 31, 2015
 
 
NGL Energy
Partners LP
(Parent) (1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income (loss)
 
$
37,306

 
$
—

 
$
103,186

 
$
(6,410
)
 
$
(83,889
)
 
$
50,193

 
 
 
 
 
 
 
 
 
 
 
 
 
Other comprehensive income (loss)
 
—

 
—

 
189

 
(62
)
 
—

 
127

 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive income (loss)
 
$
37,306

 
$
—

 
$
103,375

 
$
(6,472
)
 
$
(83,889
)
 
$
50,320

 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.


 
 
Year Ended March 31, 2014
 
 
NGL Energy
Partners LP
(Parent) (1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidating
Adjustments
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
 
 
Net income
 
$
47,655

 
$
—

 
$
79,473

 
$
5,874

 
$
(84,244
)
 
$
48,758

 
 
 
 
 
 
 
 
 
 
 
 
 
Other comprehensive loss
 
—

 
—

 
(189
)
 
(71
)
 
—

 
(260
)
 
 
 
 
 
 
 
 
 
 
 
 
 
Comprehensive income
 
$
47,655

 
$
—

 
$
79,284

 
$
5,803

 
$
(84,244
)
 
$
48,498

 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.


F-70
Table of Contents

NGL ENERGY PARTNERS LP
Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)
 
 
Year Ended March 31, 2016
 
 
NGL Energy
Partners LP
(Parent) (1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Net cash (used in) provided by operating activities
 
$
(74,822
)
 
$
—

 
$
360,851

 
$
65,466

 
$
351,495

 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Purchases of long-lived assets
 
—

 
—

 
(604,214
)
 
(57,671
)
 
(661,885
)
Acquisitions of businesses, including acquired working capital, net of cash acquired
 
(624
)
 
—

 
(232,148
)
 
(1,880
)
 
(234,652
)
Cash flows from commodity derivatives
 
—

 
—

 
105,662

 
—

 
105,662

Proceeds from sales of assets
 
—

 
—

 
8,453

 
2

 
8,455

Proceeds from sale of general partner interest in TLP, net
 
—

 
—

 
343,135

 
—

 
343,135

Investments in unconsolidated entities
 
—

 
—

 
(4,480
)
 
(6,951
)
 
(11,431
)
Distributions of capital from unconsolidated entities
 
—

 
—

 
11,031

 
4,761

 
15,792

Loan for natural gas liquids facility
 
—

 
—

 
(3,913
)
 
—

 
(3,913
)
Payments on loan for natural gas liquids facility
 
—

 
—

 
7,618

 
—

 
7,618

Loan to affiliate
 
—

 
—

 
(15,621
)
 
—

 
(15,621
)
Payments on loan to affiliate
 
—

 
—

 
1,513

 
—

 
1,513

Net 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

 
2,602,500

Payments 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

 
53,223

Payments on other long-term debt
 
—

 
—

 
(4,762
)
 
(325
)
 
(5,087
)
Debt issuance costs
 
(3,493
)
 
—

 
(6,744
)
 
—

 
(10,237
)
Contributions from general partner
 
54

 
—

 
—

 
—

 
54

Contributions from limited partner
 
(3,829
)
 
—

 
—

 
—

 
(3,829
)
Contributions from noncontrolling interest owners
 
—

 
—

 
—

 
15,376

 
15,376

Distributions to partners
 
(322,007
)
 
—

 
—

 
—

 
(322,007
)
Distributions to noncontrolling interest owners
 
—

 
—

 
—

 
(35,720
)
 
(35,720
)
Taxes paid on behalf of equity incentive plan participants
 
—

 
—

 
(19,395
)
 
—

 
(19,395
)
Common unit repurchases
 
(17,680
)
 
—

 
—

 
—

 
(17,680
)
Net changes in advances with consolidated entities
 
462,456

 
—

 
(459,289
)
 
(3,167
)
 
—

Other
 
—

 
—

 
(43
)
 
(29
)
 
(72
)
Net cash provided by (used in) financing activities
 
72,080

 
—

 
13,140

 
(4,515
)
 
80,705

 
 
 
 
 
 
 
 
 
 
 
Net decrease in cash and cash equivalents
 
(3,366
)
 
—

 
(8,973
)
 
(788
)
 
(13,127
)
Cash and cash equivalents, beginning of period
 
29,115

 
—

 
9,757

 
2,431

 
41,303

Cash and cash equivalents, end of period
 
$
25,749

 
$
—

 
$
784

 
$
1,643

 
$
28,176

 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.


F-71
Table of Contents

NGL ENERGY PARTNERS LP
Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)
 
 
Year Ended March 31, 2015
 
 
NGL Energy
Partners LP
(Parent) (1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Net cash (used in) provided by operating activities
 
$
(59,448
)
 
$
—

 
$
287,953

 
$
33,886

 
$
262,391

 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Purchases of long-lived assets
 
—

 
—

 
(198,847
)
 
(4,913
)
 
(203,760
)
Purchases of pipeline capacity allocations
 
—

 
—

 
(24,218
)
 
—

 
(24,218
)
Purchase of equity interest in Grand Mesa Pipeline
 
—

 
—

 
(310,000
)
 
—

 
(310,000
)
Acquisitions of businesses, including acquired working capital, net of cash acquired
 
(124,281
)
 
—

 
(831,505
)
 
(5,136
)
 
(960,922
)
Cash flows from commodity derivatives
 
—

 
—

 
199,165

 
—

 
199,165

Proceeds from sales of assets
 
—

 
—

 
11,806

 
14,456

 
26,262

Investments in unconsolidated entities
 
—

 
—

 
(13,244
)
 
(20,284
)
 
(33,528
)
Distributions of capital from unconsolidated entities
 
—

 
—

 
5,030

 
5,793

 
10,823

Loan for natural gas liquids facility
 
—

 
—

 
(63,518
)
 
—

 
(63,518
)
Payments on loan for natural gas liquids facility
 
—

 
—

 
1,625

 
—

 
1,625

Loan to affiliate
 
—

 
—

 
(8,154
)
 
—

 
(8,154
)
Other
 
—

 
—

 
4

 
—

 
4

Net 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

 
3,764,500

Payments on revolving credit facilities
 
—

 
—

 
(3,194,500
)
 
(85,500
)
 
(3,280,000
)
Issuances of notes
 
400,000

 
—

 
—

 
—

 
400,000

Payments on other long-term debt
 
—

 
—

 
(6,666
)
 
(22
)
 
(6,688
)
Debt issuance costs
 
(8,150
)
 
—

 
(2,926
)
 
—

 
(11,076
)
Contributions from general partner
 
823

 
—

 
—

 
—

 
823

Contributions from noncontrolling interest owners
 
—

 
—

 
—

 
9,433

 
9,433

Distributions 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

 
—

 
—

 
—

 
541,128

Taxes paid on behalf of equity incentive plan participants
 
—

 
—

 
(13,491
)
 
—

 
(13,491
)
Net changes in advances with consolidated entities
 
(479,543
)
 
—

 
499,709

 
(20,166
)
 
—

Other
 
—

 
—

 
(194
)
 
—

 
(194
)
Net cash provided by (used in) financing activities
 
211,663

 
—

 
944,932

 
(21,902
)
 
1,134,693

 
 
 
 
 
 
 
 
 
 
 
Net increase in cash and cash equivalents
 
27,934

 
—

 
1,029

 
1,900

 
30,863

Cash and cash equivalents, beginning of period
 
1,181

 
—

 
8,728

 
531

 
10,440

Cash and cash equivalents, end of period
 
$
29,115

 
$
—

 
$
9,757

 
$
2,431

 
$
41,303

 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.


F-72
Table of Contents

NGL ENERGY PARTNERS LP
Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)
 
 
Year Ended March 31, 2014
 
 
NGL Energy
Partners LP
(Parent) (1)
 
NGL Energy
Finance Corp. (1)
 
Guarantor
Subsidiaries
 
Non-Guarantor
Subsidiaries
 
Consolidated
 
 
 
 
 
 
 
 
 
 
 
OPERATING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Net cash (used in) provided by operating activities
 
$
(16,625
)
 
$
—

 
$
99,754

 
$
2,107

 
$
85,236

 
 
 
 
 
 
 
 
 
 
 
INVESTING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Purchases of long-lived assets
 
—

 
—

 
(118,455
)
 
(46,693
)
 
(165,148
)
Acquisitions of businesses, including acquired working capital, net of cash acquired
 
(334,154
)
 
—

 
(932,373
)
 
(2,283
)
 
(1,268,810
)
Cash flows from commodity derivatives
 
—

 
—

 
(35,956
)
 
—

 
(35,956
)
Proceeds from sales of assets
 
—

 
—

 
12,884

 
11,776

 
24,660

Investments in unconsolidated entities
 
—

 
—

 
(11,515
)
 
—

 
(11,515
)
Distributions of capital from unconsolidated entities
 
—

 
—

 
1,591

 
—

 
1,591

Other
 
—

 
—

 
540

 
(735
)
 
(195
)
Net cash used in investing activities
 
(334,154
)
 
—

 
(1,083,284
)
 
(37,935
)
 
(1,455,373
)
 
 
 
 
 
 
 
 
 
 
 
FINANCING ACTIVITIES:
 
 
 
 
 
 
 
 
 
 
Proceeds from borrowings under revolving credit facilities
 
—

 
—

 
2,545,500

 
—

 
2,545,500

Payments on revolving credit facilities
 
—

 
—

 
(2,101,000
)
 
—

 
(2,101,000
)
Issuances of notes
 
450,000

 
—

 
—

 
—

 
450,000

Proceeds from borrowings under other long-term debt
 
—

 
—

 
780

 
100

 
880

Payments on other long-term debt
 
—

 
—

 
(8,802
)
 
(17
)
 
(8,819
)
Debt issuance costs
 
(12,931
)
 
—

 
(11,664
)
 
—

 
(24,595
)
Contributions from general partner
 
765

 
—

 
—

 
—

 
765

Contributions from noncontrolling interest owners
 
—

 
—

 
—

 
2,060

 
2,060

Distributions to partners
 
(145,090
)
 
—

 
—

 
—

 
(145,090
)
Distributions to noncontrolling interest owners
 
—

 
—

 
—

 
(840
)
 
(840
)
Proceeds from sale of common units, net of offering costs
 
650,155

 
—

 
—

 
—

 
650,155

Net changes in advances with consolidated entities
 
(590,939
)
 
—

 
556,238

 
34,701

 
—

Net cash provided by financing activities
 
351,960

 
—

 
981,052

 
36,004

 
1,369,016

 
 
 
 
 
 
 
 
 
 
 
Net increase (decrease) in cash and cash equivalents
 
1,181

 
—

 
(2,478
)
 
176

 
(1,121
)
Cash and cash equivalents, beginning of period
 
—

 
—

 
11,206

 
355

 
11,561

Cash and cash equivalents, end of period
 
$
1,181

 
$
—

 
$
8,728

 
$
531

 
$
10,440

 
(1)
The parent and NGL Energy Finance Corp. are co-issuers of the 2019 Notes and 2021 Notes.


F-73
Table of Contents

INDEX TO EXHIBITS
Exhibit Number
Description
2.1
 
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 Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
 
 
 
2.2
 
LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, as the Representative, OWL Karnes SWD, LLC, OWL Karnes Holdings, LLC, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC 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 trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
 
 
 
2.4
 
LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, OWL Nixon SWD, LLC, Terry Bailey, as trustee of the PJB Irrevocable Trust, NGL Energy Partners, LP and High Sierra Water-Eagle Ford, LLC (incorporated by reference to Exhibit 2.4 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 7, 2013)
 
 
 
2.5
 
LLC Interest Transfer Agreement, dated as of August 1, 2013, by and among Oilfield Water Lines, LP, HR OWL, LLC, OWL Operating, LLC, Lotus Oilfield Services, L.L.C., OWL Lotus, LLC, NGL Energy Partners, LP, High Sierra Water-Eagle Ford, LLC and High 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 and Gavilon Energy Intermediate, LLC (incorporated by reference to Exhibit 2.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 5, 2013)
 
 
 
3.1
 
Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
 
 
 
3.2
 
Certificate of Amendment to Certificate of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.2 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
 
 
 
3.3
 
Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011)
 
 
 
3.4
 
First Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 26, 2011)
 
 
 
3.5
 
Second Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
 
 
 
3.6
 
Third Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 26, 2012)
 
 
 
3.7
 
Fourth Amendment to Second Amended and Restated Agreement of Limited Partnership of NGL Energy Partners LP (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 17, 2012)
 
 
 
3.8
 
Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.4 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
 
 
 
3.9
 
Certificate of Amendment to Certificate of Formation of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.5 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
 
 
 
3.10
 
Third Amended and Restated Limited Liability Company Agreement of NGL Energy Holdings LLC (incorporated by reference to Exhibit 3.1 to the Current Report on Form 8-K (File No. 001-35172) filed on February 28, 2013)

F-74
Table of Contents

Exhibit Number
Description
3.11
 
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)
 
 
 
3.12
 
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)
 
 
 
4.1
 
First Amended and Restated Registration Rights Agreement, dated October 3, 2011, by and among the Partnership, Hicks Oils & Hicksgas, Incorporated, NGL Holdings, Inc., Krim2010, LLC, Infrastructure Capital Management, LLC, Atkinson Investors, LLC, E. Osterman Propane, Inc. and the other holders party thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on October 7, 2011)
 
 
 
4.2
 
Amendment No. 1 and Joinder to First Amended and Restated Registration Rights Agreement dated as of November 1, 2011 by and among the Partnership and SemStream (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on November 4, 2011)
 
 
 
4.3
 
Amendment No. 2 and Joinder to First Amended and Restated Registration Rights Agreement, dated January 3, 2012, by and among NGL Energy Holdings LLC, Liberty Propane, L.L.C., Pacer-Enviro Propane, L.L.C., Pacer-Pittman Propane, L.L.C., Pacer-Portland Propane, L.L.C., Pacer Propane (Washington), L.L.C., Pacer-Salida Propane, L.L.C. and Pacer-Utah Propane, L.L.C. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 9, 2012)
 
 
 
4.4
 
Amendment No. 3 and Joinder to First Amended and Restated Registration Rights Agreement, dated May 1, 2012, by and between NGL Energy Holdings LLC and Downeast Energy Corp. (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on May 4, 2012)
 
 
 
4.5
 
Amendment No. 4 and Joinder to First Amended and Restated Registration Rights Agreement, dated June 19, 2012, by and between NGL Energy Holdings LLC and NGP M&R HS LP LLC (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
 
 
 
4.6
 
Amendment No. 5 and Joinder to First Amended and Restated Registration Rights Agreement, dated October 1, 2012, by and between NGL Energy Holdings LLC and Enstone, LLC (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2012)
 
 
 
4.7
 
Amendment No. 6 and Joinder to First Amended and Restated Registration Rights Agreement, dated November 13, 2012, by and between NGL Energy Holdings LLC and Gerald L. Jensen, Thrift Opportunity Holdings, LP, Jenco Petroleum Corporation, Caritas Trust, Animosus Trust and Nitor Trust (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (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 Energy Holdings 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 Energy Holdings 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 the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
4.10*
 
Amendment No. 9 and Joinder to First Amended and Restated Registration Rights Agreement, dated as of February 25, 2016, by and among NGL Energy Holdings LLC and Magnum NGL Holdco LLC
 
 
 
4.11
 
Note Purchase Agreement, dated June 19, 2012, by and among NGL and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
 
 
 
4.12
 
Amendment No. 1 to Note Purchase Agreement, dated as of January 15, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18, 2013)
 
 
 

F-75
Table of Contents

Exhibit Number
Description
4.13
 
Amendment No. 2 to Note Purchase Agreement, dated as of May 8, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 9, 2013)
 
 
 
4.14
 
Amendment No. 3 to Note Purchase Agreement, dated September 30, 2013, among NGL Energy Partners LP and the holders of NGL’s 6.65% senior secured notes due 2022 signatory thereto (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)
 
 
 
4.15
 
Amendment No. 4 to Note Purchase Agreement, dated as of November 5, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
 
 
 
4.16
 
Amendment No. 5 to Note Purchase Agreement, dated as of December 23, 2013, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30, 2013)
 
 
 
4.17
 
Amendment No. 6 to Note Purchase Agreement, dated as of June 30, 2014, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 3, 2014)
 
 
 
4.18
 
Amendment No. 7 to Note Purchase Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 2, 2015)
 
 
 
4.19
 
Amendment No. 8 to Note Purchase Agreement, dated as of May 1, 2015, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.18 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
4.20
 
Amendment No. 9 to Note Purchase Agreement, dated as of December 23, 2015, among the Partnership and the purchasers named therein (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended December 31, 2015 filed with the SEC on February 9, 2016)
 
 
 
4.21*
 
Amendment No. 10 to Note Purchase Agreement, dated as of February 9, 2016, among the Partnership and the purchasers named therein
 
 
 
4.22
 
Indenture, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors party 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 the SEC on October 16, 2013)
 
 
 
4.23
 
Forms of 6.875% Senior Notes due 2021 (incorporated by reference to Exhibit 4.2 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
 
 
 
4.24
 
First Supplemental Indenture, dated as of December 2, 2013, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.19 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with the SEC on May 30, 2014)
 
 
 
4.25
 
Second Supplemental Indenture, dated as of April 22, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiary party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.20 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2014 filed with the SEC on May 30, 2014)
 
 
 
4.26
 
Third Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiary party thereto 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)
 
 
 
4.27
 
Fourth Supplemental Indenture, dated as of December 1, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.25 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
4.28
 
Fifth Supplemental Indenture, dated as of February 17, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.26 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)

F-76
Table of Contents

Exhibit Number
Description
4.29
 
Sixth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed with the SEC on November 9, 2015)
 
 
 
4.30
 
Registration Rights Agreement, dated as of October 16, 2013, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listed therein on Exhibit A and RBC Capital Markets, LLC as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 16, 2013)
 
 
 
4.31
 
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)
 
 
 
4.32
 
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. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014)
 
 
 
4.33
 
Forms of 5.125% Senior Notes due 2019 (incorporated by reference and included as Exhibits A1 and A2 to Exhibit 4.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014)
 
 
 
4.34
 
Registration Rights Agreement, dated July 9, 2014, by and among NGL Energy Partners LP, NGL Energy Finance Corp., the Guarantors listed therein on Exhibit A and RBS Securities Inc. as representative of the several initial purchasers (incorporated by reference to Exhibit 4.3 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 9, 2014)
 
 
 
4.35
 
First Supplemental Indenture, dated as of July 31, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto 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)
 
 
 
4.36
 
Second Supplemental Indenture, dated as of December 1, 2014, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.32 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
4.37
 
Third Supplemental Indenture, dated as of February 17, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.33 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
4.38
 
Fourth Supplemental Indenture, dated as of August 21, 2015, among NGL Energy Partners LP, NGL Energy Finance Corp., the Guaranteeing Subsidiaries party thereto, the Guarantors party thereto and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended September 30, 2015 filed with the SEC on November 9, 2015)
 
 
 
10.1
 
Credit Agreement, dated as of June 19, 2012, among NGL Energy Partners LP, the NGL subsidiary borrowers, the lenders party thereto and Deutsche Bank Trust Company Americas, as administrative agent (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 25, 2012)
 
 
 
10.2
 
Facility Increase Agreement, dated as of November 1, 2012, among NGL Energy Operating LLC, NGL Energy Partners LP, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 7, 2012)
 
 
 
10.3
 
Amendment No. 1 to Credit Agreement, dated as of January 15, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 18, 2013)
 
 
 
10.4
 
Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No 001-35172) filed on May 9, 2013)
 
 
 

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Exhibit Number
Description
10.5
 
Amendment No. 3 to Credit Agreement, dated September 30, 2013, among NGL Energy Partners LP, NGL Energy Operating LLC, each subsidiary of NGL identified as a “Borrower” therein, Deutsche Bank AG, New York Branch, as technical agent, Deutsche Bank Trust Company Americas, as administrative agent and collateral agent and each financial institution identified as a “Lender” or “Issuing Bank” therein (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on October 3, 2013)
 
 
 
10.6
 
Amendment No. 4 to Credit Agreement, dated as of November 5, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on November 8, 2013)
 
 
 
10.7
 
Amendment No. 5 to Credit Agreement, dated as of December 23, 2013, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank and Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 30, 2013)
 
 
 
10.8
 
Facility Increase Agreement, dated as of December 30, 2013, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on January 3, 2014)
 
 
 
10.9
 
Amendment No. 6 to Credit Agreement, dated as of June 12, 2014, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on June 16, 2014)
 
 
 
10.10
 
Amendment No. 7 to Credit Agreement, dated as of June 27, 2014, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on July 3, 2014)
 
 
 
10.11
 
Facility Increase Agreement, dated December 1, 2014, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on December 1, 2014)
 
 
 
10.12
 
Amendment No. 8 to Credit Agreement, dated as of December 19, 2014 and effective as of December 26, 2014, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed on January 2, 2015)
 
 
 
10.13
 
Amendment No. 9 to Credit Agreement, dated as of May 1, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.13 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
10.14
 
Amendment No. 10 to Credit Agreement, dated as of July 31, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed with the SEC on August 4, 2015)
 
 
 
10.15
 
Facility Increase Agreement, dated October 7, 2015, among NGL Energy Operating LLC, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.1 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended December 31, 2015 filed with the SEC on February 9, 2016)
 
 
 
10.16
 
Amendment No. 11 to Credit Agreement, dated as of December 23, 2015, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended December 31, 2015 filed with the SEC on February 9, 2016)
 
 
 
10.17*
 
Amendment No. 12 to Credit Agreement, dated as of February 9, 2016, among NGL Energy Operating LLC, the Partnership, the subsidiary borrowers party thereto, Deutsche Bank Trust Company Americas and the other financial institutions party thereto
 
 
 

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Table of Contents

Exhibit Number
Description
10.18
 
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)
 
 
 
10.19+
 
Letter Agreement among Silverthorne Energy Holdings LLC, Shawn W. Coady and Todd M. Coady dated October 14, 2010 (incorporated by reference to Exhibit 10.11 to the Registration Statement on Form S-1 (File No. 333-172186) filed on April 15, 2011)
 
 
 
10.20+
 
NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K (File No. 001-35172) filed on May 17, 2011)
 
 
 
10.21+
 
Form of Restricted Unit Award Agreement under the NGL Energy Partners LP 2011 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Quarterly Report on Form 10-Q (File No. 001-35172) for the quarter ended June 30, 2012 filed with the SEC on August 14, 2012 )
 
 
 
10.22
 
NGL Performance Unit Program (incorporated by reference to Exhibit 10.18 to the Annual Report on Form 10-K (File No. 001-35172) for the year ended March 31, 2015 filed with the SEC on June 1, 2015)
 
 
 
12.1*
 
Computation of ratios of earnings to fixed charges
 
 
 
21.1*
 
List of Subsidiaries of NGL Energy Partners LP
 
 
 
23.1*
 
Consent of Grant Thornton LLP
 
 
 
31.1*
 
Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
31.2*
 
Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
32.1*
 
Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
32.2*
 
Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
101.INS**
 
XBRL Instance Document
 
 
 
101.SCH**
 
XBRL Schema Document
 
 
 
101.CAL**
 
XBRL Calculation Linkbase Document
 
 
 
101.DEF**
 
XBRL Definition Linkbase Document
 
 
 
101.LAB**
 
XBRL Label Linkbase Document
 
 
 
101.PRE**
 
XBRL Presentation Linkbase Document
 
*
Exhibits filed with this report.
**
The following documents are formatted in XBRL (Extensible Business Reporting Language): (i) Consolidated Balance Sheets at March 31, 2016 and 2015, (ii) Consolidated Statements of Operations for the years ended March 31, 2016, 2015, and 2014, (iii) Consolidated Statements of Comprehensive Income (Loss) for the years ended March 31, 2016, 2015, and 2014, (iv) Consolidated Statements of Changes in Equity for the years ended March 31, 2016, 2015, and 2014, (v) Consolidated Statements of Cash Flows for the years ended March 31, 2016, 2015, and 2014, and (vi) Notes to Consolidated Financial Statements.
+
Management contracts or compensatory plans or arrangements.


F-79