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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

(Mark One)

 

x       ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the fiscal year ended March 31, 2015

 

or

 

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)

 

 

 

(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 x   No  o

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o   No x

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 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 x   No o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (Section 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x   No  o

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (Section 229.405 of this chapter) is not 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		Smaller reporting company o
(Do not check if a smaller reporting company)

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o   No x

 

The aggregate market value at September 30, 2014 of the Common Units held by non-affiliates of the registrant, based on the reported closing price of the Common Units on the New York Stock Exchange on such date ($39.37 per Common Unit) was $3,078,563,331. For purposes of this computation, 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 25, 2015, there were 106,328,594 common units issued and outstanding.

 

 

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TABLE OF CONTENTS

 

PART I
Item 1.	Business	3
Item 1A.	Risk Factors	32
Item 1B.	Unresolved Staff Comments	55
Item 2.	Properties	55
Item 3.	Legal Proceedings	56
Item 4.	Mine Safety Disclosures	56
PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	57
Item 6.	Selected Financial Data	58
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	60
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	98
Item 8.	Financial Statements and Supplementary Data	100
Item 9.	Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	100
Item 9A.	Controls and Procedures	100
Item 9B.	Other Information	101
PART III
Item 10.	Directors, Executive Officers and Corporate Governance	102
Item 11.	Executive Compensation	108
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	118
Item 13.	Certain Relationships and Related Transactions and Director Independence	121
Item 14.	Principal Accountant Fees and Services	125
PART IV
Item 15.	Exhibits and Financial Statement Schedules	126

 

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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. When used in this Annual Report, words such as “anticipate,” “believe,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “plan,” “project,” “will,” and similar expressions and statements regarding our plans and objectives for future operations, are intended to identify forward-looking statements. Although we and our general partner believe that the expectations on which such forward-looking statements are based are reasonable, neither we nor our general partner can give assurances that such expectations will prove to be correct. Forward-looking statements are subject to a variety of risks, uncertainties and assumptions. If one or more of these risks or uncertainties materialize, or if underlying assumptions prove incorrect, our actual results may vary materially from those anticipated, estimated, projected or expected. Among the key risk factors that may impact our consolidated financial position and results of operations are:

 

·                   the prices for crude oil, natural gas, natural gas liquids, refined products, ethanol, and biodiesel;

 

·                   energy prices generally;

 

·                   the price of propane and distillates relative to the price of alternative and competing fuels;

 

·                   the price of gasoline relative to the price of corn, which impacts the price of ethanol;

 

·                   the general level of crude oil, natural gas, and natural gas liquids production;

 

·                   the general level of demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel ;

 

·                   the availability of supply of crude oil, natural gas liquids, refined products, ethanol, and biodiesel ;

 

·                   the level of crude oil and natural gas drilling and production in producing areas in which we have water treatment and disposal facilities;

 

·                   the ability to obtain adequate supplies of propane and distillates for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane and distillates to market areas ;

 

·                   actions taken by foreign oil and gas producing nations;

 

·                   the political and economic stability of petroleum producing nations;

 

·                   the effect of weather conditions on supply and demand for crude oil, natural gas liquids, refined products, ethanol, and biodiesel ;

 

·                   the effect of natural disasters, lightning strikes, or other significant weather events;

 

·                   availability of local, intrastate and interstate transportation infrastructure, including with respect to our truck, railcar, and barge transportation services;

 

·                   availability, price, and marketing of competitive fuels;

 

·                   the impact of energy conservation efforts on product demand;

 

·                   energy efficiencies and technological trends;

 

·                   governmental regulation and taxation;

 

·                   the impact of legislative and regulatory actions on hydraulic fracturing and on the treatment of flowback and produced water;

 

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·                   hazards or operating risks incidental to the transporting and distributing of petroleum products that may not be fully covered by insurance;

 

·                   the maturity of the crude oil and natural gas liquids industries and competition from other marketers;

 

·                   loss of key personnel;

 

·                   the ability to hire drivers;

 

·                   the ability to renew contracts with key customers;

 

·                   the ability to maintain or increase the margins we realize for our terminal, barging, trucking and water disposal, and recycling, and discharge services;

 

·                   the ability to renew leases for our leased equipment and storage facilities;

 

·                   the nonpayment or nonperformance by our customers;

 

·                   the availability and cost of capital and our ability to access certain capital sources;

 

·                   a deterioration of the credit and capital markets;

 

·                   the ability to successfully identify and consummate strategic acquisitions and integrate acquired assets and businesses;

 

·                   changes in the volume of crude oil recovered during the wastewater treatment process;

 

·                   changes in the financial condition and results of operations of entities in which we own noncontrolling equity interests;

 

·                   changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations, or 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 Fuels Standard;

 

·                   the operational and financial success of our joint ventures; and

 

·                   changes in the jurisdictional characteristics of, or the applicable regulatory policies with respect to, our pipeline assets.

 

You should not put undue reliance on any forward-looking statements. All forward-looking statements speak only as of the date of this 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 39 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, 2015. Unless otherwise indicated, this data is as of March 31, 2015.

 

Item 1.                                  Business

 

Overview

 

We are a Delaware limited partnership formed in September 2010. Subsequent to our formation, we significantly expanded our operations through numerous business combinations. At March 31, 2015, our operations include:

 

·                   Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, owned and leased pipeline injection stations, a fleet of owned trucks and trailers, a fleet of owned and leased railcars, a fleet of owned and leased barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned 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 treatment and disposal facilities. Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recovered hydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids .

 

·                   Our 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 services through its 21 owned terminals throughout the United States and railcar transportation services through its fleet of leased railcars. Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the products to retailers, refiners, petrochemical plants, and other participants in the wholesale markets.

 

·                   Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain resellers in 25 states and the District of Columbia.

 

·                   Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.6% limited partner interest in TransMontaigne Partners L.P. (“TLP”), which conducts refined products terminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC (“BOSTCO”) and a 50% interest in Frontera Brownsville LLC (“Frontera”), which are entities that own refined products storage facilities.

 

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

 

Acquisitions

 

Subsequent to our initial public offering (“IPO”) in May 2011, we significantly expanded our operations through numerous acquisitions, including the following, among others:

 

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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.

 

·                   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 provides us the right to purchase water treatment and disposal facilities developed by the other party to the agreement, and we are also party to a solids facilities development agreement with this other party. During March 2014, we purchased one additional facility under this development agreement. During the year ended March 31, 2015, we purchased 16 water treatment and disposal facilities under this development agreement.

 

·                   In August 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively, “OWL”). The businesses of OWL include four water treatment and disposal facilities in the Eagle Ford shale play in Texas .

 

·                   In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), whereby we acquired 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

 

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(“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 2.0% 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.

 

·                   In November 2014, we completed the acquisition of two saltwater disposal facilities in the Bakken shale play in North Dakota.

 

·                   In February 2015, we acquired Sawtooth NGL Caverns, LLC (“Sawtooth”), which owns a natural gas liquids salt dome storage facility in Utah with rail and truck access to western U.S. markets and entered into a construction agreement to expand the storage capacity of the facility.

 

Primary Service Areas

 

The following maps show the primary service areas of our businesses at various points in time, to illustrate the growth of our businesses:

 

Primary Service Areas at March 31, 2012

 

 

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Primary Service Areas at March 31, 2013

 

 

 

Primary Service Areas at March 31, 2014

 

 

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Primary Service Areas at March 31, 2015

 

 

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Organizational Chart

 

The following chart provides a summarized view of our legal entity structure at March 31, 2015:

 

(1) Includes the operations of our crude oil logistics, refined products, and renewables businesses.

(2) Includes the operations of our water solutions business.

(3) Includes the operations of our liquids business.

(4) Includes the operations of our retail propane business.

 

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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 producers. 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 have acquired. We also believe that there are further organic growth opportunities within our existing businesses, particularly within our crude oil logistics, water solutions, and refined products businesses.

 

·                   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 crude oil logistics platform, and enhance our geographic diversity in our water solutions business. 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 . In our liquids, crude oil logistics, and refined products businesses, we intend to focus on long-term contracts associated with pipelines in addition to back-to-back contracts which minimize commodity price exposure. In our water solutions business, cash flows are supported by certain fee-based, multi-year contracts, some of which include acreage dedications from producers or volume commitments. We believe that expanding our retail propane business with an emphasis on a high level of residential customers and a high level of company-owned tanks will result in strong customer retention rates and consistent operating margins. Our refined products business is backed by term marketing agreements and long-term throughput agreements for terminaling operations.

 

·                   Maintain a disciplined capital structure characterized by low leverage . We target leverage levels that are consistent with those of investment grade companies. Through our disciplined approach to leverage, we maintain sufficient liquidity to manage existing and future capital requirements.

 

·                   Maintain a disciplined cash distribution policy that complements our 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. 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 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 vertically integrated and diversified operations, which help us generate more predictable and stable cash flows on a year-to-year basis. Our ability to provide multiple services to producers in numerous geographic areas enhances our competitive position. Our retail propane business sources propane through our liquids business which allows us to

 

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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.

 

·                   Our network of crude oil transportation assets, which allows us to serve customers over a wide geographic area and optimize sales. Our strategically deployed railcar fleet, towboats, barges, and trucks, and our owned and contracted pipeline capacity, provide access to a 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 Businesses

 

Crude Oil Logistics

 

Overview. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection stations, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs. 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 approximately 275,000 barrels per day of crude oil using the following assets:

 

·                   300 owned trucks and 300 owned trailers operating primarily in the Mid-Continent, Permian Basin, Eagle Ford shale play, and Rocky Mountain regions;

 

·                   400 owned railcars and 350 leased railcars operating primarily in Colorado, New Mexico, North Dakota, Oklahoma, Wyoming, and West Texas; and

 

·                   8 owned towboats, 19 owned barges, 2 leased towboats and 6 leased barges operating primarily in the intercoastal waterways of the Gulf 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 350 leased railcars, 100 are compliant with these standards.

 

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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 44 pipeline injection stations. The location of these facilities is summarized below.

 

		Number of Pipeline
State		Injection Stations
Oklahoma		17
Texas		15
New Mexico		5
Kansas		3
North Dakota		3
Montana		1
Total		44

 

We also lease 5 pipeline injection stations in Kansas, Montana, and North Dakota. We own and lease several rail transload facilities and have several throughput agreements at rail transload facilities in Colorado, New Mexico, North Dakota, and Oklahoma. 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 4,140,000 barrels, 1,000,000 barrels of which are owned by Glass Mountain. The combined storage capacity of the other six terminals is 462,500 barrels.

 

We lease 3,703,000 barrels of capacity at three storage terminal facilities. Of this leased storage capacity, 3,350,000 barrels are at Cushing, Oklahoma.

 

We have one Gulf Coast terminal facility that is under construction and is expected to be completed early in fiscal year 2017 with a total expected storage capacity of 300,000 barrels. We own a 50% interest in Glass Mountain, which owns a 210-mile crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline, which became operational in February 2014, has a capacity of 147,000 barrels per day. We also own Grand Mesa, which is constructing a 20-inch crude oil pipeline originating in Weld County, Colorado and terminating at our Cushing, Oklahoma terminal. We anticipate that the pipeline will commence service in the second half of calendar year 2016. Upon completion, Grand Mesa is expected to have a capacity in excess of 200,000 barrels per day. Rimrock Midstream LLC’s Platte River gathering system, which is currently under development, is expected to deliver volumes from multiple shippers to Grand Mesa’s northern origin near Lucerne, Colorado.

 

Customers. Our customers include crude oil refiners, producers, and marketers. During the year ended March 31, 2015, 65% of the revenues of the 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;

 

·                   reliability of service;

 

·                   logistics capabilities, including the availability of railcars, proprietary terminals, and owned pipelines, barges, railcars, trucks, and towboats;

 

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·                   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 600 producers at 6,200 leases.

 

Pricing Policy. Most of our contracts to purchase or sell crude oil are at floating prices that are indexed to published rates in active markets, such 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 the forward crude price is greater than the spot price) and can be backwardated (a condition in which the forward crude price is lower than the spot price). Our crude oil 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 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 generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, from the sale of recycled water and recovered hydrocarbons, and from the disposal of solids such as tank bottoms and drilling fluids. Our facilities are 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 three months ended March 31, 2015, we took delivery of 48.9 million barrels of wastewater, an average of 543,000 barrels per day.

 

Our water solutions segment is in the process of expanding its disposal business. With the addition of specialized equipment to select facilities in the Eagle Ford shale play, the Permian Basin, and the DJ Basin, we will be able to accept and dispose of solids such as tank bottoms and drilling 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.

 

Operations. We own 46 water treatment and disposal facilities, including 58 wells. The location of the facilities and the processing capacities at which the facilities currently operate are summarized below.

 

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		Processing		Located on
		Capacity		Land We Own
Location		(barrels per day)		or Lease
Pinedale Anticline:
Pinedale, Wyoming (A)		60,000		Lease
DJ Basin:
Briggsdale, Colorado (B)		34,000		Own
Grover, Colorado		25,000		Own
Greeley, Colorado		18,000		Lease
Grover, Colorado		17,500		Lease
Platteville, Colorado (B)		16,200		Own
Kersey, Colorado		14,000		Own
Orchard, Colorado		10,000		Own
LaSalle, Colorado		5,900		Own
Brighton, Colorado		5,100		Own
Total—DJ Basin		145,700
Permian Basin:
Mentone, Texas		35,000		Own
Orla, Texas (C)		35,000		Own
Big Lake, Texas		30,000		Own
Orla, Texas		30,000		Own
Big Spring, Texas		25,000		Own
Garden City, Texas		25,000		Own
Kermit, Texas		25,000		Own
Rankin, Texas		25,000		Own
Pecos, Texas		23,000		Own
Colorado City, Texas		20,000		Own
Crane, Texas		20,000		Own
Midland, Texas		20,000		Own
Midkiff, Texas		18,000		Own
Barnhart, Texas		16,000		Own
Andrews, Texas		12,000		Own
Total—Permian Basin		359,000
Eagle Ford Shale Play:
Carrizo Springs, Texas (D)		22,500		Lease
Catarina, Texas (D)		22,000		Lease
Charlotte, Texas		22,000		Own
Cheapside, Texas		22,000		Own
Gillett, Texas		22,000		Own
Karnes City, Texas		22,000		Own
Artesia Wells, Texas		20,000		Own
Los Angeles, Texas		20,000		Lease
Nixon, Texas		20,000		Own
Tilden, Texas		20,000		Lease
Westhoff, Texas (C)		20,000		Own
Fowlerton, Texas		18,000		Own
Pearsall, Texas		17,000		Lease
Cotulla, Texas		16,500		Own
Dilley Lea, Texas		15,000		Lease
Catarina, Texas (D)		12,000		Lease
Total—Eagle Ford Shale Play		311,000
Eaglebine Shale Play:
Madisonville, Texas		20,000		Own
Granite Wash Shale Play:
Wheeler, Texas		27,000		Own
Canadian, Texas		25,000		Own
Total—Granite Wash Shale Play		52,000
Bakken Shale Play:
Killdeer, North Dakota		20,000		Lease
Johnsons Corner, North Dakota		20,000		Own
Total—Bakken Shale Play		40,000
Total—All Facilities		987,700

 

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(A)        This facility has a design capacity of 60,000 barrels per day to process water to a recycle standard which also includes a design capacity of 15,000 barrels per day to process water to a discharge standard.

 

(B)        The processing capacity listed above for each of these facilities includes a design capacity of 10,000 barrels per day to process water to a recycle standard.

 

(C)        These facilities can dispose of both wastewater and solids such as tank bottoms and drilling fluids. We own a 50% interest in the disposal of solids.

 

(D)        Reflects the total processing capacity of each facility, of which we own a 75% interest in each of these facilities.

 

Our customers bring wastewater generated by crude oil and natural gas exploration and production operations to our facilities for treatment 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 with trucks.

 

Our facility in Wyoming has the assets and technology needed to treat the water more extensively. At this facility, the water is recycled, rather 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. We have recycled approximately 9 million barrels (378 million gallons) of recycle quality water since our merger with High Sierra in June 2012. We have returned approximately 5 million barrels (210 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.

 

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 customers of our facility in Wyoming have committed to deliver a specified minimum volume of water to our facility under long-term contracts. The primary customers of our facilities in Colorado have committed to deliver to our facilities all wastewater produced at all wells in a designated area. One customer in Texas has committed to deliver at least 50,000 barrels of wastewater per day to our facilities. Most of the customers at our other facilities are not under volume commitments. During the year ended March 31, 2015, 23% of the water treatment and disposal revenues of the water solutions segment were generated from our two largest customers of the segment, and 57% 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 significant crude oil and natural gas production.

 

Pricing Policy. We generally charge customers a processing fee per barrel of wastewater processed. Certain of our contracts require the customer 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,

 

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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 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, 2015, we sold 2.1 billion gallons of natural gas liquids, an average of 5.75 million gallons per day.

 

Operations . We procure natural gas liquids from refiners, gas processing plants, producers and other resellers for delivery to leased or owned 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 21 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 chart lists our natural gas liquids terminals and their throughput capacity:

 

		Throughput Capacity
Facility		(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. Catherines, Ontario, Canada		700,000
Janesville, Wisconsin		553,000
Light, Arkansas		524,400
Rixie, Arkansas		524,400
Winslow, Arizona		500,000
West Springfield, Massachusetts		441,000
Albuquerque, New Mexico		408,000
Kingsland, Arkansas		405,000
Portland, Maine		360,000
Vancouver, Washington		358,000
Green Bay, Wisconsin		310,000
Thackerville, Oklahoma		235,000
Ritzville, Washington		198,000
Sidney, Montana		180,000
Shelton, Washington		161,000
Total		12,110,800

 

We have operating agreements with third parties for certain of our terminals. The terminals in East St. Louis, Illinois and Jefferson City, Missouri 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 11 of the terminals are located and we either have easements or lease the land on which ten of the terminals are located. The terminals in East St. Louis, Illinois and Jefferson City, Missouri have perpetual easements, and the terminal in St. Catherines, Ontario, Canada has a long-term lease that expires in 2022.

 

In February 2015 we acquired an underground storage facility near Delta, Utah. This facility currently has capacity to store approximately 1.8 million barrels of natural gas liquids. We have begun construction of new caverns to expand the storage capacity, and we expect these new caverns to be operational during the year ending March 31, 2016. We lease storage to 11 customers, with lease terms ranging from one to four years. The facility is located on property for which we have a long-term lease.

 

We lease 4,591 railcars, of which 520 are subleased to a third party. These include high pressure and general-purpose railcars.

 

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

 

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

 

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The following chart shows our leased storage space at natural gas liquids storage facilities and interconnects to those facilities:

 

		Leased Storage Space
		(gallons)
		Beginning		At
		April 1,		March 31,
Storage Facility		2015		2015		Storage Interconnects
Conway, Kansas		64,940,000		73,290,000		Connected to Enterprise Mid-America and NuStar Pipelines; Rail Facility
Borger, Texas		42,000,000		42,000,000		Connected to ConocoPhillips Blue Line Pipeline
Bushton, Kansas		12,600,000		10,500,000		Connected to ONEOK North System Pipeline
Mont Belvieu, Texas		3,150,000		3,150,000		Connected to Enterprise Texas Eastern Products Pipeline
Carthage, Missouri		7,560,000		7,560,000		Connected to Mid-America Pipeline
Marysville, Michigan		2,100,000		4,200,000		Connected to Cochin Pipeline
Hattiesburg, Mississippi		11,340,000		6,930,000		Connected to Enterprise Dixie Pipeline; Rail Facility
Redwater, Alberta, Canada		9,072,000		7,938,000		Connected to Cochin Pipeline; Rail Facility
Regina, Saskatchewan, Canada		—		1,260,000		Connected to Cochin Pipeline; Rail Facility
St. Clair, Michigan		6,300,000		—		Rail Facility
Adamana, Arizona		1,680,000		1,398,600		Rail Facility
Corunna, Ontario, Canada		2,100,000		2,100,000		Rail Facility
Total		162,842,000		160,326,600

 

During the typical heating season from September 15 through March 15 each year, we have the right to utilize ConocoPhillips’ capacity as a 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 47 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 pipeline systems, rail terminals, refineries, and major United States propane storage hubs. During the year ended March 31, 2015, 33% of the revenues of the 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;

 

·                   logistics capabilities, including the availability of railcars, and proprietary terminals;

 

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·                   long-term customer relationships; and

 

·                   the acquisition of businesses.

 

Pricing Policy. In our natural gas liquids business, we offer our customers three categories of contracts for propane sourced from common 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 to as much as 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 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, 2015, we sold 204.1 million gallons of propane and distillates, an average of 559,000 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 107 customer service locations and 91 satellite distribution locations, with aggregate propane storage capacity of 11.5 million gallons and aggregate distillate storage capacity of 3.7 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 16,000 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 shows the number of our customer service locations and satellite distribution locations by state:

 

		Number of Customer		Number of Satellite
		Service		Distribution
State		Locations		Locations
Illinois		22		21
Maine		16		10
Georgia		14		3
Massachusetts		10		8
North Carolina		8		1
Pennsylvania		7		3
Kansas		6		26
Indiana		4		5
Connecticut		4		2
South Carolina		3		—
New Hampshire		2		1
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		—
New Jersey		—		1
Vermont		—		1
Total		107		91

 

We own 82 of our 107 customer service centers and 63 of our 91 satellite distribution locations, and we lease the remainder.

 

Tank ownership at customer locations is an important component to our operations and customer retention. At March 31, 2015, we owned 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, 2015, we owned a fleet of 430 bulk delivery trucks, 40 semi-tractors, 40 propane transport trailers and 490 other service trucks.

 

Retail deliveries of propane are usually made to customers by means of our fleet of bulk delivery trucks. Propane is pumped from the bulk delivery truck, which holds 2,400 to 5,000 gallons, into a storage tank at the customer’s premises. The capacity of these storage tanks ranges from 50 to 30,000 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 our customer service locations, and

 

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then returned to the retail customer, or refilled at the customer’s location. Customers can also bring the cylinders to our customer service centers to be refilled.

 

Approximately 69% of our residential customers receive their propane supply via our automatic route delivery program, which allows us 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, 2015, our retail propane and distillate customers were comprised of:

 

·                   71% residential customers;

 

·                   28% commercial and industrial customers; and

 

·                   1% agricultural customers.

 

No single customer accounted for more than 1% of our retail propane volumes during the year ended March 31, 2015.

 

Seasonality . The retail propane and distillate business is largely seasonal due to the primary use of propane and distillates as heating fuels. 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, fuel oil, 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

 

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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.

 

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. We own the 2.0% general partner interest and a 19.6% limited partner interest in TLP, which conducts refined products terminaling operations. TLP also owns a 42.5% interest in BOSTCO and a 50% interest in Frontera, which are entities that own refined products storage facilities. During the nine months ended March 31, 2015, we sold 60.1 million barrels of refined products, an average of 220,000 barrels per day.

 

Operations. We provide integrated terminal, transportation, storage, supply, distribution, and marketing services to refiners, wholesalers, distributors, marketers, and industrial and commercial end users of refined petroleum products. Although the assets and operations of TLP are included in our consolidated financial statements, this description of our business describes the activities of TLP separately.

 

The refined products we handle include gasoline, diesel fuel, heating oil, jet fuel, and kerosene. We purchase refined petroleum products primarily in the Gulf Coast, East Coast, 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.

 

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. We have the contractual right to the exclusive use of the majority of the terminals in TLP’s Southeast region.

 

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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 approximately 60,000 barrels of biodiesel storage in Deer Park, Texas and have a terminaling agreement at a biodiesel facility in Phoenix, Arizona with a minimum monthly throughput requirement. We lease 32 railcars for the transportation of renewables.

 

Customers . Our refined products and renewables segment serves customers in 43 states. During the year ended March 31, 2015, 22% of the revenues of this segment were generated from the ten largest customers. We sell to customers via rack spot sales, contract sales, bulk sales, and just-in-time sales.

 

Contract sales are made pursuant to negotiated contracts, generally ranging from one to twelve months in duration, that we enter into with 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 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.

 

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.

 

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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 contracted on a back-to-back basis where physical purchases are matched with physical sales.  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 2014 the federal government passed a law to reinstate the tax credit retroactively to January 1, 2014, with the credit expiring on December 31, 2014. Changes in future 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 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.

 

TLP

 

Overview. We own the 2.0% general partner interest and a 19.6% limited partner interest in TLP, which conducts refined products terminaling operations. TLP also provides storage of crude oil, fertilizer, chemicals, vegetable oils, naphtha, and wax.

 

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Operations . TLP is a terminaling and transportation company with operations in the United States. TLP uses its terminaling facilities to, among other things:

 

·                   receive refined products from the pipeline, ship, barge or railcar and transfer those refined products to the tanks located at its terminals;

 

·                   store the refined products in our tanks for its customers;

 

·                   monitor the volume of the refined products stored in its tanks;

 

·                   distribute the refined products out of our terminals in vessels, railcars or truckloads using truck racks and other distribution equipment located at its terminals, including pipelines; and

 

·                   heat residual fuel oils and asphalt stored in our tanks, and provide other ancillary services related to the throughput process.

 

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The locations and approximate aggregate active storage capacity at TLP’s terminal facilities at March 31, 2015 were as follows:

 

		Active Storage
		Capacity
Locations		(shell barrels)
Gulf Coast Facilities—
Florida
Cape Canaveral		724,000
Fisher Island		673,000
Jacksonville		271,000
Pensacola		270,000
Port Everglades Complex
Port Everglades—North		2,408,000
Port Everglades—South		376,000
Port Manatee		1,375,000
Tampa		760,000
Gulf Coast Total		6,857,000
Midwest Facilities—
Cushing, Oklahoma		1,005,000
Oklahoma City, Oklahoma		158,000
Rogers, Arkansas and Mount Vernon, Missouri (aggregate amounts)		406,000
Midwest Total		1,569,000
Brownsville Facilities—
Brownsville, Texas		919,000
Frontera (1)		1,498,000
Brownsville Total		2,417,000
River Facilities—
Arkansas City, Arkansas		446,000
Baton Rouge, Louisiana (Dock)		—
Cape Girardeau, Missouri		140,000
East Liverpool, Ohio		227,000
Evansville, Indiana		245,000
Greater Cincinnati, Kentucky		189,000
Greenville, Mississippi (Clay Street)		350,000
Greenville, Mississippi (Industrial Road)		56,000
Henderson, Kentucky		169,000
Louisville, Kentucky		183,000
New Albany, Indiana		201,000
Owensboro, Kentucky		157,000
Paducah, Kentucky		322,000
River Total		2,685,000
Southeast Facilities—
Albany, Georgia		203,000
Americus, Georgia		93,000
Athens, Georgia		203,000
Bainbridge, Georgia		367,000
Belton, South Carolina		—
Birmingham, Alabama		178,000
Charlotte, North Carolina		121,000
Collins, Mississippi		200,000
Collins/Purvis, Mississippi		3,419,000
Doraville, Georgia		438,000
Fairfax, Virginia		513,000
Greensboro, North Carolina		479,000
Griffin, Georgia		107,000
Lookout Mountain, Georgia		219,000
Macon, Georgia		174,000
Meridian, Mississippi		139,000
Montvale, Virginia		503,000
Norfolk, Virginia		1,336,000
Richmond, Virginia		478,000
Rome, Georgia		152,000
Selma, North Carolina		529,000
Spartanburg, South Carolina		166,000
Southeast Total		10,017,000
BOSTCO (2)		7,080,000
Total Capacity		30,625,000

(1)          Reflects the total active storage capacity of Frontera, of which TLP has a 50% ownership interest.

 

(2)          Reflects the completed construction total active storage capacity of BOSTCO, of which TLP has a 42.5%, general voting, Class A Member ownership interest.

 

TLP leases all or part of the land on which seven of the terminals are located. TLP owns the land on which its other terminals are located.

 

TLP owns and operates the Razorback pipeline. The Razorback pipeline is a 67-mile, 8 - inch diameter interstate common carrier pipeline that transports light refined product from its terminal at Mount Vernon, Missouri where it is interconnected with a pipeline system owned by Magellan Midstream Partners, L.P., to TLP’s terminal at Rogers, Arkansas. TLP also owns and operates the Diamondback pipeline. The Diamondback pipeline consists of an 8-inch pipeline that transports LPG approximately 16 miles from TLP’s Brownsville, Texas facilities to the U.S./Mexico border and a 6-inch pipeline, which runs parallel to the 8-inch pipeline, that can be used by TLP in the future to transport additional LPG or refined products to Matamoros, Mexico. The 8-inch pipeline has a capacity of approximately 20,000 barrels per day. The 6-inch pipeline has a capacity of approximately 12,000 barrels per day. TLP also operates and maintains the United States portion of a 174 -mile bidirectional refined products pipeline owned by P.M.I. Services North America Inc. This pipeline connects TLP’s Brownsville, Texas terminal complex to a pipeline in Mexico that delivers to Petróleos Mexicanos (“PEMEX”) terminal located in Reynosa, Mexico and terminates at PEMEX’s refinery, located in Cadereyta, Nuevo Leon, Mexico, a suburb of the large industrial city of Monterrey, Mexico.

 

Customers. TLP has several significant customer relationships from which it expects to derive a substantial majority of its revenue for the foreseeable future. During the period from July 1, 2014 through March 31, 2015, 33% of TLP’s revenues were generated from services to NGL (these revenues are eliminated in our consolidated statements of operations).

 

Competition. TLP faces competition from other terminals and pipelines that may be able to supply customers with integrated terminaling and transportation services on a more competitive basis. TLP competes with national, regional and local terminal and transportation companies, including the major integrated oil companies, of widely varying sizes, financial resources and experience. TLP’s ability to compete could be harmed by factors we cannot control, including:

 

·                   price competition from terminal and transportation companies, some of which are substantially larger than we are and have greater financial resources, and control substantially greater storage capacity, than TLP does;

 

·                   the perception that another company can provide better service; and

 

·                   the availability of alternative supply points, or supply points located closer to customers’ operations.

 

Supply . The volume of product that is handled, transported, throughput or stored in TLP’s terminals and pipeline is directly affected by the level of supply and demand in the wholesale markets served by our terminals and pipelines. Overall supply of refined products in the wholesale markets is influenced by the products’ absolute prices, the availability of capacity on delivering pipelines and vessels, fluctuating refinery margins and the markets’ perception of future project prices.

 

Pricing Policy. TLP derives revenue from its terminal and pipeline transportation operations by charging fees for providing integrated terminaling, transportation and related services. The fees and other sources of revenue are composed of:

 

·                   Terminaling Service Fees.  TLP generates terminaling service fees by receiving, storing and distributing products for customers. Terminaling service fees include throughput fees based on the volume of product distributed from the facility, injection fees based on the volume of product injected with additive compounds and storage fees based on a rate per barrel of storage capacity per month.

 

·                   Pipeline Transportation Fees.  TLP earns pipeline transportation fees on its Razorback pipeline and Diamondback pipeline and the Ella-Brownsville pipeline, which it leases from a third party, based on the volume of product transported and the distance from the origin point to the delivery point. The Federal Energy Regulatory Commission (“FERC”) regulates the tariff on the Razorback, Diamondback and Ella - Brownsville pipelines.

 

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·                   Management Fees and Reimbursed Costs.  TLP manages and operates certain tank capacity at its Port Everglades (South) terminal for a major oil company and receives a reimbursement of its proportionate share of operating and maintenance costs. TLP manages and operates for an affiliate of PEMEX, Mexico’s state - owned petroleum company, a bidirectional products pipeline connected to its Brownsville, Texas terminal facility and receives a management fee and reimbursement of costs. TLP manages and operates Frontera and receives a management fee based on costs incurred.

 

·                   Other Revenue.  TLP provides ancillary services including heating and mixing of stored products, product transfer services, railcar handling, wharfage fees and vapor recovery fees. Pursuant to certain terminaling services agreements with throughput customers, TLP is entitled to the volume of net product gained resulting from differences in the measurement of product volumes received and distributed at its terminaling facilities. Consistent with recognized industry practices, measurement differentials occur as the result of the inherent variances in measurement devices and methodology. TLP recognizes as revenue the net proceeds from the sale of the product gained.

 

Employees

 

At March 31, 2015, we had 3,100 full-time employees. Thirteen of our employees at two of our locations are members of a labor union. We 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 oil are subject to FERC regulation including reporting or other requirements. In addition, the intrastate transportation and storage of 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 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

 

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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 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

 

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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 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 operations or financial condition.

 

Oil Pollution Prevention.   Our operations involve the shipment of crude oil by barge through navigable waters of the United States. The Oil Pollution Prevention Act imposes liability for releases of 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 operations or financial condition. 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 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.

 

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

 

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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 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’ 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 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 Supreme Court of the United States invalidated the Tailoring Rule in Utility Air Regulatory Group v. EPA on

 

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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 doing 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 a set of rules and procedures governing the safe handling of propane, and Pamphlet Nos. 30, 30A, 31, 385, and 395 which establish rules and procedures governing the safe handling of distillates, such as fuel oil. We believe that the policies 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.

 

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

 

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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.

 

Item 1A.                         Risk Factors

 

We may not have sufficient cash to enable us to pay the minimum quarterly distribution to our unitholders following the establishment of cash reserves 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

 

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·                   prevailing economic conditions.

 

In addition, the actual amount of cash we will have available for distribution also depends on other factors, some of which are beyond our control, including:

 

·                   the level of capital expenditures we make;

 

·                   the cost of acquisitions, if any;

 

·                   restrictions contained in our credit agreement (the “Credit Agreement”), the purchase agreement governing our outstanding 6.65% senior 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.

 

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

 

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

 

·                   increased competition for attractive acquisitions;

 

·                   covenants in our Credit Agreement, Note Purchase Agreement and 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.

 

Our ability to expand our retail propane business is dependent on our ability to successfully complete accretive acquisitions. 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. While our business strategy includes expanding

 

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our existing retail propane operations through internal growth, our ability to grow within the retail propane business will depend principally on acquisitions, and there can be no assurances that we will be able to identify suitable acquisition candidates or successfully complete acquisitions in this line of business.

 

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

 

·                   the inability to successfully integrate the operations of recently acquired businesses;

 

·                   the assumption of known or unknown liabilities, including environmental liabilities;

 

·                   limitations on rights to indemnity from the seller;

 

·                   mistaken assumptions about the overall costs of equity or debt or synergies;

 

·                   unforeseen difficulties operating in new geographic areas or in new business segments;

 

·                   the diversion of management’s and employees’ attention from other business concerns;

 

·                   customer or key employee loss from the acquired businesses; and

 

·                   a potential significant increase in our indebtedness and related interest expense.

 

We undertake due diligence efforts in our assessment of acquisitions, but may be unable to identify or fully plan for all issues and risks attendant 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 financial condition, 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, financial condition 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 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 financial condition or results of operations.

 

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

 

At March 31, 2015, we had $2.7 billion of outstanding indebtedness. Our level of debt could have important consequences to us, including the following:

 

·                   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

 

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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 condition, 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;

 

·                   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 Part II, Item 7—“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity, Sources of Capital and Capital Resource Activities—Long-Term Debt.”

 

The provisions of our Credit Agreement, Note Purchase Agreement and 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, 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.

 

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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 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 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 oil and natural gas, the availability of liquids-rich natural gas needed to produce natural gas liquids, the supply of and demand for oil and natural gas, environmental restrictions on the exploration and production of oil and natural gas, such as existing and proposed regulation of hydraulic fracturing, domestic and worldwide economic conditions, political instability in 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 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 oil and natural gas prices, to the extent existing production is not replaced.

 

The oil and natural gas production industry tends to run in cycles and may, at any time, cycle into a downturn; if that occurs again, the rate at 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 oil and natural gas have caused many customers to reduce capital budgets for future periods and have caused decreased demand for oil and natural gas. Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause customers to 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 operating results.

 

Declining crude oil prices could adversely impact our water solutions and crude oil logistics businesses.

 

Crude oil spot and forward prices experienced a significant decline during the second half of calendar year 2014, and this has an unfavorable 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 significant portion of the revenues of our water solutions business are generated from the sale of crude oil that we recover in the process of treating the 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

 

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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.

 

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 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 cars are transported. Any disruptions in the operations of these railroads could adversely impact our ability to deliver product to our customers.

 

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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 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 “ — Certain of our operations are subject to the jurisdiction of the FERC, and some of our operations could become 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, results of operations and financial condition.

 

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

 

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

 

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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, results of operations, financial condition 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 oil and 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 wastewater treatment business carries with it environmental risks, including leakage from the treatment plants to surface or subsurface soils, surface water or groundwater, or accidental spills. Our crude oil logistics, liquids, and refined products and renewables businesses carry similar risks of leakage and sudden or accidental spills of crude oil, natural gas liquids, 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. In response to train derailments, United States regulators are implementing or considering new rules to address the safety risks of transporting crude oil by rail. 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 unfavorably 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 frac flowback water (or affect our hydraulic fracturing customers’ ability to operate) and cause delays, interruption or termination of our water treatment operations, all of which could have a material and adverse effect on our operations and financial performance.

 

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

 

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become more stringent over time. For example, in April 2012, the EPA issued final rules that established new air emission controls for oil and gas 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. In January 2015, the EPA announced its intention to propose regulations that would require further reductions in methane and VOC emissions from the oil and gas industry. The EPA’s schedule for proposing or finalizing these regulations is not presently known. 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 oil and 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 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 unfavorably impact the oil and gas drilling industry. For instance, the EPA has asserted federal regulatory 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. The EPA has also commenced a study of the potential environmental impact of hydraulic fracturing activities, the final results of which are expected in 2015. 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. The rule will become effective 90 days after publication in the Federal Register. 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 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 unfavorably 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.

 

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Seasonal weather conditions and natural or man-made disasters could severely disrupt normal operations and have an adverse effect on our business, financial condition and results of operations.

 

We operate in various locations across the United States and Canada which may be adversely affected by seasonal weather conditions and natural 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, financial condition, results of operations and cash flows.

 

Risk management procedures cannot eliminate all commodity risk, basis risk, or risk of adverse market conditions which can adversely affect our financial condition and results of operations. In addition, any non-compliance with our risk policy could result in significant financial losses.

 

Pursuant to the requirements of our market risk policy, we attempt to lock in a margin for a portion of the commodities we purchase by selling 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 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 financial condition and results of operations.

 

The counterparties to our commodity derivative and physical purchase and sale contracts may not be able to perform their obligations to us, which 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 oil and 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 results of operations and impair our ability to make payments on our debt obligations or distributions to our unitholders.

 

Certain of our operations are subject to the jurisdiction of the FERC, and some of our operations could be subject to the jurisdiction of the FERC in the future.

 

TLP’s Razorback and Diamondback pipelines are subject to the jurisdiction of the FERC. Any of our transportation services could in the future become subject to the jurisdiction of the FERC, which could adversely affect the terms 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 crude oil and refined products 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.

 

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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 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 results of operations and cash flows.

 

Additionally, our subsidiary Grand Mesa is in the process of constructing a pipeline originating in Weld County, Colorado and terminating at our Cushing, Oklahoma terminal. We expect that this pipeline will be subject to FERC regulation.

 

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

 

A significant portion of revenues in our water business is derived from sales of crude oil recovered during the wastewater treatment process. Our ability to recover sufficient volumes of crude oil is dependent upon the residual crude oil content in the wastewater we treat, which is, among other things, 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 condition 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.

 

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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 condition and results of operations.

 

A substantial portion of our retail propane sales are to residential customers located in the Northeast, Southeast, and Midwest who rely heavily 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 operating results and financial condition. 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 operating results and financial condition than if our retail propane business were less concentrated.

 

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

 

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

 

·                   a recession or other adverse economic condition that results in lower spending by consumers on gasoline, diesel, and travel;

 

·                   higher fuel taxes or other governmental or regulatory actions that increase, directly or indirectly, the cost of gasoline;

 

·                   an increase in automotive engine fuel economy, whether as a result of a shift by consumers to more fuel-efficient vehicles or technological advances by manufacturers;

 

·                   an increase in the market price of crude oil that leads to higher refined product prices, which may reduce demand for refined products and drive demand for alternative products; and

 

·                   the increased use of alternative fuel sources, such as battery-powered engines.

 

Recent attempts to reduce or eliminate the federal Renewable Fuels Standard (“RFS”), if successful, could unfavorably impact our results of operations.

 

The United States renewables industry is highly dependent on several federal and state incentives which promote the use of renewable fuels. Without these incentives, demand for and the price of renewable fuels could be negatively impacted which could have an adverse effect on our results 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 unfavorably impact our results of operations.

 

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

 

The demand for biodiesel is supported by certain federal tax credits. These tax credits have typically been granted for short durations, and on 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. Currently no such tax credit exists for transactions subsequent to December 31, 2014, 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.

 

Approximately 65% of the revenues of our crude oil logistics segment during the year ended March 31, 2015 were generated from our ten largest customers of the segment. Approximately 23% of the water treatment and disposal revenues of our water solutions segment during the year ended March 31, 2015 were generated from our two largest customers of the segment. Approximately 33% of the revenues of our liquids segment during the year ended March 31, 2015 were generated from our ten largest customers of the segment. Approximately 22% of the revenues of our refined products and renewables segment during the year ended

 

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March 31, 2015 were generated from our ten largest customers of the segment. We expect to continue to depend on key customers to support our revenues 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 results of operations.

 

Certain of our operations are conducted through joint ventures which have unique risks.

 

Certain of our operations are conducted through joint ventures. With respect to our joint ventures, we share ownership and 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 financial condition, operating results and cash flows.

 

Growing our business by constructing new transportation systems and facilities subjects us to construction risks and risks that supplies for such 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. In addition, Grand Mesa, one of our subsidiaries, is in the process of constructing a crude oil pipeline originating in Weld County, Colorado and terminating at our Cushing, Oklahoma terminal. We anticipate that the pipeline will commence service in the second half of calendar year 2016. 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. Moreover, 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 results of operations and financial condition.

 

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

 

Our operations are subject to all operating hazards and risks incident to handling, storing, transporting and providing customers with 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, results of operations, financial condition and cash flows.

 

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

 

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. If any of our financial, operational, or other data processing systems fail or have other significant shortcomings, our financial results could be adversely affected. Our 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

 

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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 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, results of operations and financial condition.

 

Additionally, certain facilities and equipment (or parts thereof) used by us are leased from third parties for specific periods, including many of 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 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. In addition, due in part to current economic conditions, including the cost of fuel, insurance, and tractors and the DOT regulatory requirements, the available pool of qualified truck drivers has been declining. 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 will create difficulties in increasing the number of our drivers for our anticipated expansion in our fleet of trucks. If we are unable to continue to attract and retain a sufficient 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 controls 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 controls. Any failure to maintain effective internal controls 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 controls over financial reporting, we can provide no assurance as to 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 trading price of our common units.

 

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

 

At March 31, 2015, we had reported goodwill and intangible assets of $2.7 billion. Such assets are subject to impairment reviews on an annual basis, or at an interim date if information indicates that such asset values have been impaired. Any impairment we would be required to record in our 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 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 TLP owns refined products terminals. These facilities depend on pipeline and storage systems that are owned and operated by third parties. Any interruption of service on the 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 affect the utilization and value of our terminals. We have historically been able to pass through the costs of pipeline transportation to our customers. However, if competing pipelines do not have similar annual tariff increases or service fee adjustments, such increases could affect our ability to compete, thereby adversely affecting our revenues.

 

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

 

Our product supply is transported and stored on facilities owned and operated by third parties. Any interruption of service on the pipeline or 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.

 

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.

 

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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 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;

 

·                   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;

 

·                   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;

 

·                   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 totality of the relationships between the parties involved, including other transactions that may be particularly favorable or advantageous to us; and

 

·                   provides that our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners for any 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

 

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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:

 

·                   our general partner is allowed to take into account the interests of parties other than us, such as members of the NGL Energy GP Investor Group, in resolving conflicts of interest;

 

·                   neither our partnership agreement nor any other agreement requires owners of our general partner to pursue a business strategy that favors us;

 

·                   except in limited circumstances, our general partner has the power and authority to conduct our business without unitholder approval;

 

·                   our general partner determines the amount and timing of asset purchases and sales, borrowings, issuance of additional partnership securities and the creation, reduction or increase of reserves, each of which can affect the amount of cash that is distributed to our unitholders;

 

·                   our general partner determines the amount and timing of any capital expenditures and whether a capital expenditure is classified as 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;

 

·                   our general partner determines which costs incurred by it are reimbursable by us;

 

·                   our general partner may cause us to borrow funds to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make incentive distributions;

 

·                   our partnership agreement permits us to classify up to $20.0 million as operating surplus, even if it is generated from asset sales, non-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”);

 

·                   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;

 

·                   our general partner intends to limit its liability regarding our contractual and other obligations;

 

·                   our general partner may exercise its right to call and purchase all of the common units not owned by it and its affiliates if they own more than 80% of the common units;

 

·                   our general partner controls the enforcement of the obligations that it and its affiliates owe to us;

 

·                   our general partner decides whether to retain separate counsel, accountants or others to perform services for us; and

 

·                   our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to 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.

 

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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.

 

Although we control TLP through our ownership of its general partner, TLP’s general partner owes fiduciary duties to TLP’s unitholders, which may conflict with our interests.

 

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and TLP and its limited partners, on the other hand. The directors and officers of TLP’s general partner have fiduciary duties to manage TLP in a manner beneficial to us. At the same time, TLP’s general partner has fiduciary duties to manage TLP in a manner beneficial to TLP and its limited partners. The board of directors of TLP’s general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.

 

For example, conflicts of interest with TLP may arise in the following situations:

 

·                   the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and TLP, on the other hand;

 

·                   the determination of the amount of cash to be distributed to TLP’s limited partners and the amount of cash to be reserved for the future conduct of TLP’s business; and

 

·                   the determination whether to make borrowings under TLP’s revolving credit facility to pay distributions to its limited partners.

 

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

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our 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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