NGL Energy Partners LP - Annual Report: 2014 (Form 10-K)

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-K

 

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

 

For the fiscal year ended March 31, 2014

 

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:

 

 

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 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.

 

 

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, 2013 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 ($30.84 per Common Unit) was $1,443,663,823. For purposes of this computation, all executive officers, directors and 10% owners of the registrant are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers, directors and 10% beneficial owners are affiliates.

 

At May 23, 2014, there were 74,706,160 common units and 5,919,346 subordinated units issued and outstanding.

 

 

Table of Contents

 

TABLE OF CONTENTS

 

	PART I
Item 1.	Business	3
Item 1A.	Risk Factors	27
Item 1B.	Unresolved Staff Comments	49
Item 2.	Properties	49
Item 3.	Legal Proceedings	49
Item 4.	Mine Safety Disclosures	49
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	50
Item 6.	Selected Financial Data	51
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	54
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	85
Item 8.	Financial Statements and Supplementary Data	86
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	86
Item 9A.	Controls and Procedures	87
Item 9B.	Other Information	87
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	88
Item 11.	Executive Compensation	94
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	103
Item 13.	Certain Relationships and Related Transactions and Director Independence	105
Item 14.	Principal Accountant Fees and Services	109
	PART IV
Item 15.	Exhibits and Financial Statement Schedules	110

 

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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 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 basins in which we have water treatment 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;

 

·                  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;

 

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·                  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, recycling, and discharge services;

 

·                  the ability to renew leases for general purpose and high pressure railcars;

 

·                  the ability to renew leases for underground natural gas liquids storage;

 

·                  the non-payment 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 at purchase prices that are accretive to our financial results;

 

·                  the ability to successfully 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, including our sales of crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel, our processing of wastewater, and transportation and risk management activities;

 

·                  the costs and effects of legal and administrative proceedings;

 

·                  the demand for refined products;

 

·                  any reduction or elimination of the 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 joint venture’s 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 “Item 1A — Risk Factors.”

 

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PART I

 

References in this Annual Report to (i) “NGL Energy Partners LP,” “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) “NGL Supply” refers to NGL Supply, Inc. for periods prior to our formation and refers to NGL Supply, LLC, a wholly-owned subsidiary of NGL Energy Operating LLC, for periods after our formation, (v) “Hicksgas” refers to the combined assets and operations of Hicksgas Gifford, Inc., which we refer to as Gifford, and Hicksgas, LLC, a wholly-owned subsidiary of NGL Energy Operating LLC, which we refer to as Hicks LLC, (vi) the “NGL Energy GP Investor Group” refers to, collectively, the 36 individuals and entities that own all of the outstanding membership interests in our general partner, (vii) 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, and (viii) the “NGL Energy Investor Group” refers to, collectively, the NGL Energy GP Investor Group and the NGL Energy LP Investor Group.

 

We have presented various operational data in “Item 1 — Business” for the year ended March 31, 2014. Unless otherwise indicated, this data is as of March 31, 2014.

 

Item 1.         Business

 

Overview

 

We are a Delaware limited partnership formed in September 2010 by several investors (“IEP Parties”). As part of our formation, we acquired and combined the assets and operations of NGL Supply, Inc., primarily a wholesale propane and terminaling business founded in 1967, and Hicksgas, LLC and Hicksgas Gifford, Inc., primarily a retail propane business founded in 1940. Subsequent to our formation, we significantly expanded our operations through numerous business combinations. At March 31, 2014, our primary businesses include:

 

·                  A crude oil logistics business, the assets of which include crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics business purchases crude oil from producers and transports it for resale at pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.

 

·                  A water solutions business, the assets of which include water treatment and disposal facilities, a fleet of water trucks, and frac tanks. Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons.

 

·                  Our liquids business, 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 22 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids business purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, and other participants in the wholesale markets.

 

·                  Our retail propane business, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.

 

We also operate a refined products marketing business, which purchases gasoline and diesel fuel from suppliers and typically sells these products in back-to-back contracts to customers at a nationwide network of third-party owned terminaling and storage facilities. We also operate a renewables business, which purchases ethanol primarily at production facilities and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using leased railcars for sale to refiners and blenders. These businesses were acquired in our December 2013 acquisition of Gavilon, LLC (“Gavilon Energy”).

 

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

 

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Initial Public Offering

 

On May 17, 2011, we completed our initial public offering (“IPO”) and listed our common units on the New York Stock Exchange under the symbol “NGL.” Upon the completion of our IPO, we had outstanding common units, subordinated units, a 0.1% general partner interest, and incentive distribution rights (“IDRs”). IDRs entitle the holder to specified increasing percentages of cash distributions as our per-unit cash distributions increase above specified levels.

 

Acquisitions Subsequent to Initial Public Offering

 

Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, including the following, among others:

 

·                  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. (“North American”), whereby we acquired retail propane and distillate operations in the northeastern United States.

 

·                  In May 2012, we acquired the retail propane and distillate operations of Downeast Energy Corp (“Downeast”). 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 transaction 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.

 

·                  In July 2013, we completed a business combination whereby we acquired the assets of Crescent Terminals, LLC and the ownership interests in Cierra Marine, LP and its affiliated companies (collectively, “Crescent”), whereby we acquired four towboats, seven crude oil barges, and a crude oil terminal in South Texas.

 

·                  In July 2013, we completed a business combination with High Roller Wells Big Lake SWD No. 1, Ltd. (“Big Lake”), whereby we acquired a water disposal facility in West Texas. We also entered into a development agreement that provides us the option to purchase disposal facilities that may be developed in the future. During March 2014, we purchased one additional facility under this development agreement.

 

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·                  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 water disposal operations and a water transportation business in Texas.

 

·                  In September 2013, we completed a business combination with Coastal Plains Disposal #1, LLC (“Coastal”), in which we acquired the ownership interests in water disposal facilities in Texas and the right to purchase one additional facility, which we exercised in March 2014.

 

·                  In December 2013, we acquired the ownership interests in Gavilon Energy. The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana and a 50% interest in Glass Mountain Pipeline, LLC (“Glass Mountain”), which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma. This pipeline became operational in February 2014. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids.

 

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 May 11, 2011

 

 

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Primary Service Areas at March 31, 2012

 

 

Primary Service Areas at March 31, 2013

 

 

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Primary Service Areas at March 31, 2014

 

 

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Organizational Chart

 

The following chart provides a summarized view of our legal entity structure at March 31, 2014:

 

 

(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, wastewater from the wellhead to treatment for disposal, recycle, or discharge, and transport 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 and water solutions 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 segment. 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. 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. In our liquids and crude oil logistics segments, we intend to focus on back-to-back contracts which minimize commodity price exposure. In our water solutions segment, cash flows are typically supported by fee-based contracts, some of which include acreage dedications from producers or volume commitments.

 

·                  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 objectives 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 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.

 

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·                  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, together with our proprietary linear programming model, to deliver crude oil to the optimal markets.

 

·                  Our water processing facilities, which are strategically located near areas of growing crude oil and natural gas production. Our water processing facilities are located among the most prolific oil and gas producing basins in the United States, including the Permian, Niobrara, and Eagle Ford shale plays. In addition, we believe that the technological capabilities of our water processing 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 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 segment.

 

Our Businesses

 

Crude Oil Logistics

 

Overview. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at pipeline injection points, 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 Basin in North Dakota, the Niobrara Shale Basin in Colorado, the Mississippi Lime Basin in Oklahoma, the Permian Basin in Texas and New Mexico, the Eagle Ford Basin in Texas, and the Anadarko Basin in Oklahoma and Texas.

 

Operations. We transport crude oil using the following assets:

 

·                  300 owned trucks, 300 owned trailers, and 100 leased trucks operating primarily in the Mid-Continent, Permian Basin, Eagle Ford Basin, and Rocky Mountain regions;

 

·                  200 owned railcars and 700 leased railcars operating primarily in North Dakota, Oklahoma, Colorado, Wyoming, and Texas; and

 

·                  8 owned towboats, 19 owned barges, 5 leased towboats and 12 leased barges (including 1 leased storage barge) operating primarily in the inter-coastal waterways of the Gulf Coast and along the Mississippi and Arkansas river systems.

 

We contract for truck, rail, and barge transportation services from third parties and ship on common carrier pipelines. We own 60 pipeline injection facilities in Kansas, Oklahoma, North Dakota, New Mexico, Texas, and Montana. We lease six rail transload facilities and have throughput agreements at seven rail transload facilities in Colorado, Kansas, Louisiana, New Mexico, North Dakota, Oklahoma, and Texas.

 

We own seven storage terminal facilities, as summarized below:

 

		Storage Capacity
Location		(barrels)
Cushing, Oklahoma		4,140,000
Catoosa, Oklahoma		138,000
Port Aransas, Texas		120,000
Rio Hondo, Texas		80,000
Wheatland, Wyoming		80,000
Seadrift, Texas		25,000
Sunray, Texas		9,500

 

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We lease 3.85 million barrels of storage capacity in Cushing, Oklahoma.

 

We have two Gulf Coast terminal facilities that are under construction and are expected to be completed during the latter part of fiscal 2015 with a total expected storage capacity of 625,000 barrels. We also 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.

 

Customers. Our customers include crude oil refiners and marketers. Approximately 60% of the revenues from our crude oil logistics segment during the year ended March 31, 2014 related to our ten largest customers of the segment. In addition to utilizing our assets to transport product we own, we also provide truck transportation, barge transportation, storage, and terminal throughput services to our customers.

 

Competition. We face 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;

 

·                  level and quality of service;

 

·                  available space on common carrier pipelines;

 

·                  the availability of railcars;

 

·                  proprietary terminals;

 

·                  owned barges and towboats;

 

·                  obtaining and retaining customers; and

 

·                  the acquisition of businesses.

 

Supply. We obtain crude oil from a large base of suppliers, which consist primarily of crude oil producers. We currently purchase from 800 producers at 7,600 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 entering into financial derivatives. We also seek to maximize margins on crude oil sales by combining crude oil of varying qualities (such as gravity, sulphur content, or mineral content).

 

Billing and Collection Procedures. As is customary in the crude oil industry, we generally receive payment from customers on a monthly basis. As a result, receivables from individual customers in our crude oil business are typically higher than the receivables from customers of our other segments. 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

 

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·                  we require our sales personnel to manage their customers’ receivable position and tie a portion of our sales personnel’s compensation to their ability to manage their accounts and minimize and collect past due balances.

 

Trade Names. Our crude oil logistics business operates primarily under the NGL — Crude Logistics trade name.

 

Water Solutions

 

Overview. Our water solutions segment generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. Our facilities are located near fields with high levels of crude oil and natural gas production, such as the Pinedale Anticline Basin in Wyoming, the DJ Basin in Colorado, and the Permian and Eagle Ford Basins in Texas.

 

Operations. We own 23 wastewater processing facilities. The location of the facilities and the processing capacities at which the facilities currently operate are summarized below.

 

		Processing
		Capacity
Location		(barrels per day)
Pinedale, Wyoming (A)(B)		60,000
Briggsdale, Colorado (C)(D)		34,000
Grover, Colorado (C)		25,000
Greeley, Colorado (B)		18,000
Platteville, Colorado (C)(E)		16,200
Kersey, Colorado (C)		14,000
LaSalle, Colorado (C)		5,900
Brighton, Colorado (C)		5,100
Big Lake, Texas (C)		30,000
Pecos, Texas (C)(F)		23,000
Carrizo Springs, Texas (B)		22,500
Charlotte, Texas (C)(F)		22,000
Cheapside, Texas (C)		22,000
Gillett, Texas (C)		22,000
Karnes City, Texas (C)		22,000
Artesia Wells, Texas (C)		20,000
Nixon, Texas (C)		20,000
Los Angeles, Texas (B)		20,000
Fowlerton, Texas (C)		18,000
Pearsall, Texas (B)		17,000
Cotulla, Texas (C)		16,500
Dilley Lea, Texas (B)		15,000
Andrews, Texas (C)		12,000

 

(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 20,000 barrels per day to process water to a discharge standard.

(B)       These facilities are located on land we lease.

(C)       These facilities are located on land we own.

(D)       The processing capacity listed above for this facility includes a design capacity of 12,000 barrels per day to process water to a recycle standard.

(E)        The processing capacity listed above for this facility includes a design capacity of 10,000 barrels per day to process water to a recycle standard.

(F)         We purchased these facilities effective March 1, 2014.

 

Our customers bring wastewater generated by crude oil and natural gas exploration and production operations to our facilities for treatment. Once we take delivery of the water, the level of processing is determined by the ultimate disposition of the water.

 

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

 

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producers to be re-used in future drilling operations, 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.

 

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 dispose of wastewater into deep underground formations via injection wells. We also operate a wastewater transportation business in Texas, whereby we transport wastewater via truck to processing facilities owned by us and other parties. We operate this business with 70 owned trucks, 20 owned trailers, and 80 frac tanks.

 

Customers. The customers of our Wyoming and Colorado facilities consist primarily of large exploration and production companies who conduct drilling operations near our facilities. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume to our facility under multi-year contracts. Certain other customers, primarily those of our facilities in Colorado, have committed to deliver to our facilities all wastewater produced at all wells in a designated area under multi-year contracts. The customers of our facilities in Texas consist primarily of wastewater transportation companies, although one customer has committed to deliver 50,000 barrels per day to our facilities in Texas. During the year ended March 31, 2014, 37% of the revenues of the water solutions segment were generated from our two largest customers of the segment, and 73% of the 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 oil and natural gas producers, and also include smaller water transportation companies. We typically invoice customers on a monthly basis. We perform credit analysis, require credit approvals, establish credit limits, and follow monitoring procedures on our water solutions customers. We believe the following procedures enhance our collection efforts with our water solutions customers:

 

·                  we require certain customers to prepay or place deposits for our services;

 

·                  we review receivable aging analyses regularly to identify issues or trends that may develop; and

 

·                  we require our sales personnel to manage their customers’ receivable position and tie a portion of our sales personnel’s compensation to their ability to manage their accounts and to minimize and collect past due balances.

 

Trade Names. Our water solutions business operates primarily under the NGL — Water Solutions trade name.

 

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.

 

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.

 

Operations. We procure natural gas liquids from refiners, gas processing plants, producers and other resellers for delivery to leased 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.

 

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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. Pre-sales 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 sub-lease railcars to certain customers.

 

We also purchase and sell asphalt. We utilize leased railcars to move the asphalt from our suppliers to our customers.

 

We own 22 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.

 

The following chart lists our natural gas liquids terminals and their throughput capacity:

 

		Throughput Capacity
Facility		(in 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
Hutchinson, Kansas		840,000
St. Catherines, Ontario, Canada		700,000
Janesville, Wisconsin		553,000
Light, Arkansas		524,400
Rixie, Arkansas		524,400
Winslow, Arizona		500,000
Albuquerque, New Mexico		408,000
Kingsland, Arkansas		405,000
Portland, Maine		360,000
West Springfield, Massachusetts		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

 

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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 has a term 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 12 of the terminals are located and we either have easements or lease the land on which 10 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.

 

We own 4 railcars and lease 3,700 additional railcars, of which 600 railcars are subleased to a third party. These include high pressure and general purpose railcars.

 

We own 16 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, New York and Texas.

 

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

 

			Leased Storage Space
			(in gallons)
			Beginning			At
			April 1,			March 31,
Storage Facility			2014			2014		Storage Interconnects
Conway, Kansas				73,290,000		85,890,000		Connected to Enterprise Mid-America and NuStar Pipelines; Rail Facility
Borger, Texas				42,000,000		31,500,000		Connected to ConocoPhillips Blue Line Pipeline
Bushton, Kansas				10,500,000		12,600,000		Connected to ONEOK North System Pipeline
Mont Belvieu, Texas				3,150,000		2,940,000		Connected to Enterprise Texas Eastern Products Pipeline
Carthage, Missouri				7,560,000		7,560,000		Connected to Magellan Pipeline
Marysville, Michigan				4,200,000		15,750,000		Connected to Cochin Pipeline
Hattiesburg, Mississippi				6,930,000		7,350,000		Connected to Enterprise Dixie Pipeline; Rail Facility
Redwater, Alberta, Canada				7,938,000		9,055,200		Connected to Cochin Pipeline; Rail Facility
Regina, Saskatchewan, Canada				1,260,000		—		Connected to Cochin Pipeline; Rail Facility
Bath, New York				—		10,122,000		Rail Facility
Adamana, Arizona				1,398,600		1,680,000		Rail Facility
Corunna, Ontario, Canada				2,100,000		2,100,000		Rail Facility
Total				160,326,600		186,547,200

 

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 900 customers in 45 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. For the year ended March 31, 2014, our ten largest liquids customers represented 35% of the total sales of our liquids business (exclusive of sales to our retail propane segment).

 

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Seasonality. Our liquids business is affected by the weather in a similar manner as our retail propane business. However, we are able to partially mitigate the effects of seasonality by pre-selling 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. The primary factors on which we compete are:

 

·                  price;

 

·                  availability of supply;

 

·                  level and quality of service;

 

·                  available space on common carrier pipelines;

 

·                  storage availability;

 

·                  the availability of railcars;

 

·                  proprietary terminals;

 

·                  obtaining and retaining customers; and

 

·                  the acquisition of businesses.

 

Our competitors generally include other natural gas liquids wholesalers and companies involved in the natural gas liquids midstream industry (such as terminal and refinery operations), some of which have greater financial resources than we do.

 

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;

 

·                  rack barrel, which is a posted 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 wholesale customers. We believe the following procedures enhance our collection efforts with our wholesale customers:

 

·                  we require certain customers to prepay or place deposits for their purchases;

 

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·                  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 sales personnel to manage their wholesale customers’ receivable position and suspend sales to customers that have not paid previous invoices timely.

 

Trade Names. Our liquids business operates primarily under the NGL - Liquids, Centennial Energy, and Centennial Gas Liquids trade names.

 

Retail Propane

 

Overview. Our retail propane business 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 290,000 residential, agricultural, commercial and industrial customers. We also sell propane to certain re-sellers. 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.

 

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 92 customer service locations and 91 satellite distribution locations, with aggregate propane storage capacity of 10.7 million gallons and aggregate distillate storage capacity of 3.4 million gallons. Our customer service locations are staffed and operated to service a defined geographic market area and typically include a business office, product showroom, and secondary propane storage. Our satellite distribution locations, which are unmanned storage tanks, allow our customer service centers to serve an extended market area.

 

Our customer service locations in Illinois and Indiana also rent 15,000 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.

 

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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		23		19
Maine		17		10
Georgia		11		3
Massachusetts		10		8
Kansas		5		27
Indiana		4		5
Pennsylvania		4		3
Connecticut		3		2
North Carolina		3		1
Oregon		2		1
Washington		2		—
Mississippi		1		3
New Hampshire		1		1
Maryland		1		1
Rhode Island		1		1
Utah		1		1
Wyoming		1		1
Colorado		1		—
South Carolina		1		—
Delaware		—		1
New Jersey		—		1
Tennessee		—		1
Vermont		—		1
Total		92		91

 

We own 74 of our 92 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, 2014, we owned the following propane storage tanks:

 

·                  400 bulk storage tanks with capacities ranging from 2,000 to 90,000 gallons; and

 

·                  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, 2014, we owned a fleet of 370 bulk delivery trucks, 40 semi-tractors, 40 propane transport trailers and 480 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 30 to 1,000 gallons. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 25 gallons. These cylinders are typically picked up on a delivery route, refilled at our customer service locations, and then returned to the retail customer. Customers can also bring the cylinders to our customer service centers to be refilled.

 

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Approximately 73% 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, agricultural, and commercial and industrial. At March 31, 2014, 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, 2014.

 

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 are sales to residential and agricultural customers.

 

Competition. Our retail propane business faces significant competition. The primary factors on which we compete are:

 

·                  price;

 

·                  availability of supply;

 

·                  level and quality of service;

 

·                  obtaining and retaining customers; and

 

·                  the acquisition of businesses.

 

Our competitors generally include other propane retailers and companies involved in the sale of natural gas, fuel oil and electricity, some of which have greater financial resources than we do. We compete with alternative energy sources and with other companies engaged in the retail propane distribution business. 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 65 miles, although in certain areas the marketing radius may be extended by satellite distribution locations.

 

The ability to compete effectively depends on the ability to provide superior customer service, which includes reliability of supply, quality equipment, well-trained service staff, efficient delivery, 24-hours-a-day service for emergency repairs and deliveries, multiple payment and purchase options and the ability to maintain competitive prices. Additionally, we believe that our safety programs, policies and procedures are more comprehensive than many of our smaller, independent competitors, which offers a higher level of service to our customers. We also believe that our overall service capabilities and customer responsiveness differentiate us from many of our competitors.

 

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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, and Proflame, 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

 

Overview. Our refined products marketing business purchases gasoline and diesel fuel primarily from eight suppliers and typically sells these products in back-to-back contracts to over 300 customers at a nationwide network of third-party owned terminaling and storage facilities. We lease 175,000 barrels of refined products storage on a third-party pipeline.

 

Customers. Our customers include convenience stores, petroleum-related transportation companies and railroad companies, among others. Approximately 41% of the revenues from our refined products segment during the year ended March 31, 2014 related to our ten largest customers of the segment.

 

Competition. We face significant competition, as many entities are engaged in the refined products 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;

 

·                  level and quality of service;

 

·                  available space on common carrier pipelines;

 

·                  the availability of railcars;

 

·                  proprietary terminals; and

 

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·                  obtaining and retaining customers.

 

Supply. We obtain refined products primarily from eight suppliers, which consist primarily of large energy and petrochemicals companies.

 

Pricing Policy. Most of our contracts to purchase or sell refined products are at floating prices that are indexed to published rates in active markets. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives.

 

Billing and Collection Procedures. Our refined products customers consist primarily of large energy and petrochemicals companies. 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 refined products customers. We believe the following procedures enhance our collection efforts with our refined products 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 sales personnel to manage their customers’ receivable position and tie a portion of our sales personnel’s compensation to their ability to manage their accounts and minimize and collect past due balances.

 

Renewables

 

Overview. Our renewables business, including ethanol marketing and biodiesel marketing businesses, purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations to refiners and blenders, and purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product using 40 leased railcars operating primarily in Iowa, Oklahoma, Minnesota, Missouri, and Texas for sale to refiners and blenders. We also transport and market third-party owned ethanol for a service fee. In our ethanol business, we lease and sublease railcars. We lease 2.5 million gallons of biodiesel storage at a facility in Deer Park, Texas and have a terminaling agreement at a facility in Phoenix, Arizona, with a minimum monthly throughput requirement of one million gallons.

 

Customers. Our customers include crude oil refiners and blenders. Approximately 70% of the revenues from our renewables segment during the year ended March 31, 2014 related to our ten largest customers of the segment.

 

Competition. We face significant competition, as many entities are engaged in the renewables 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;

 

·                  level and quality of service;

 

·                  available space on common carrier pipelines;

 

·                  the availability of railcars;

 

·                  proprietary terminals; and

 

·                  obtaining and retaining customers.

 

Supply. We obtain renewables from production facilities in the Midwest and in Houston, Texas.

 

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Pricing Policy. Most of our contracts to purchase or sell renewables are at floating prices that are indexed to published rates in active markets. We seek to manage price risk by entering into purchase and sale contracts of similar volumes based on similar indexes and by entering into financial derivatives.

 

Billing and Collection Procedures. Our renewables customers consist primarily of crude oil refiners and blenders. 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 refined products customers. We believe the following procedures enhance our collection efforts with our renewables 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 sales personnel to manage their customers’ receivable position and tie a portion of our sales personnel’s compensation to their ability to manage their accounts and minimize and collect past due balances.

 

Employees

 

At March 31, 2014, we had 2,500 full-time employees, of which 2,300 were operational and 200 were general and administrative. Fourteen 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 Federal Energy Regulatory Commission (“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 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. 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 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 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 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 Commodity Futures Trading Commission has adopted anti-market manipulation regulations that prohibit fraud and price manipulation in the commodity and futures markets. The Commodity Futures

 

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Trading Commission also has statutory authority to seek civil penalties of up to the greater of $1,000,000 per day per violation or triple the monetary gain to the violator for violations of the anti-market manipulation sections of the Commodity Exchange Act. We are also subject to various reporting requirements that are designed to facilitate transparency and prevent market manipulation.

 

Maritime Transportation. The Jones Act is a federal law that restricts maritime transportation between locations in the United States to vessels built and registered in the United States and owned and manned by United States citizens. Since we engage in maritime transportation through our barge fleet between locations in the United States, we are subject to the provisions of the law. As a result, we are responsible for monitoring the ownership of our subsidiaries that engage in maritime transportation and for taking any remedial action necessary to insure 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 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, health and safety 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 or occupational health and safety. 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; (vi) and 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 Clean Air Act, the Occupational Safety and Health Act, the Homeland Security Act of 2002, the Emergency Planning and Community Right to Know Act, the Clean 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 Clean Air Act.

 

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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 propane is not a hazardous substance within the meaning of CERCLA, other chemicals used in or generated by our operations may be classified as hazardous. Persons who are or were responsible for releases of hazardous substances under CERCLA may be subject to strict and joint and several liability for the costs of investigating and cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies, and it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.

 

RCRA, and comparable state statutes and their implementing regulations, regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the United States Environmental Protection Agency (“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 petroleum-contaminated media, are exempt 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 pre-approval for 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.

 

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Water Discharges. The Clean Water Act and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters as well as waters of the United States and impose requirements affecting our ability to conduct construction activities in waters and wetlands. Certain state regulations and the general permits issued under the Federal National Pollutant Discharge Elimination System program prohibit the discharge of pollutants and chemicals. Spill prevention, control and countermeasure requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of regulated waters in the event of a hydrocarbon or other constituent tank spill, rupture or leak. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. We have discharge permits in place for a number of our facilities. These permits may require us to monitor and sample the storm water runoff from such facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations.

 

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

 

Hydraulic Fracturing. The underground injection of 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 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, several states, including Texas, Colorado and California, 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. The ACES Act did not pass the United States Senate, however, and so 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. More recently, the Climate Protection Act of 2013 was introduced in the United States Senate in February 2013. The Climate Protection Act of 2013 would introduce a carbon tax on all fossil fuels extracted, manufactured, produced in, or imported into the United States. The bill has not been advanced out of a United States Senate committee. The ultimate outcome of any possible future 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, although in recent years some states have scaled back their commitment to greenhouse gas initiatives.

 

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 Clean Air Act, including: the greenhouse gas reporting rule; greenhouse gas standards applicable to heavy-duty and light-duty vehicles; a rule requiring stationary sources to address greenhouse gas emissions in Prevention of Significant Deterioration and Title V permits; and new source performance standards for greenhouse gas emissions from new power plants. The EPA’s greenhouse gas permitting rule is currently being reviewed by the United States Supreme Court with a decision expected by June 2014. The outcome of the litigation is unknown. 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.

 

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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 (the “NFPA”), Pamphlet Nos. 54 and No. 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 U.S. 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.

 

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.

 

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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 and subordinated units principally depends on the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

·                  weather conditions in our operating areas;

 

·                  the cost of crude oil, natural gas liquids, refined products, ethanol, and biodiesel that we buy for resale and whether we are able to pass along cost increases to our customers;

 

·                  the volume of wastewater delivered to our processing facilities;

 

·                  disruptions in the availability of crude oil and/or natural gas liquids supply;

 

·                  our ability to renew leases for storage and railcars;

 

·                  the effectiveness of our commodity price hedging strategy;

 

·                  the level of competition from other energy providers; and

 

·                  prevailing economic conditions.

 

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

 

·                  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 indenture governing our outstanding 6.875% senior notes due 2021 (the “Indenture”) 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.

 

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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 Indenture 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 acceptable 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.

 

The propane industry is a mature industry. 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. In addition, our retail propane business concentrates on sales to residential customers, but because of longstanding customer relationships that are typical in the retail residential propane industry, the inconvenience of switching tanks and suppliers, we may have difficulty in increasing our retail customer base other than through acquisitions. Therefore, while our business strategy includes expanding our existing retail propane operations through internal growth, our ability to grow within the retail propane business will depend principally on acquisitions.

 

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;

 

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·                  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.

 

Debt we have incurred or will incur in the future may limit our flexibility to obtain financing and to pursue other business opportunities.

 

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 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 Indenture 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 Indenture 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;

 

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·                  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 Indenture 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 Indenture also contain covenants requiring us to maintain certain financial ratios. Please read “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 Indenture 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 and natural gas liquids in the United States and Canada, which is dependent on the ability and willingness of other parties to explore for and produce crude oil and natural gas. Spending on crude oil and natural gas exploration and production may be adversely affected by industry and financial market conditions that are beyond our control including, without limitation, (1) prices for crude oil, condensate, and natural gas liquids, (2) crude oil and natural gas producers having success in their operations, (3) continued commercially viable areas in which to explore and produce crude oil and natural gas,  (4) the availability of liquids-rich natural gas needed to produce natural gas liquids, and (5) the availability of pipeline transportation and storage capacity.

 

Our business depends on domestic spending by the oil and natural gas industry, and this spending and our business have been, and may continue to be, adversely affected by industry and financial market conditions and existing or new regulations, such as those related to environmental matters, that are beyond our control.

 

We depend on the ability and willingness of other entities to make operating and capital expenditures to explore for, develop, and produce 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.

 

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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.

 

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

 

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

 

Generally, we attempt to maintain an inventory position that is substantially balanced between our purchases and sales, including our future delivery obligations. We attempt to obtain a certain margin for our purchases by selling our product to our customers, which include third-party consumers, other wholesalers and retailers, and others. However, market, weather or other conditions beyond our control may disrupt our expected supply of product, and we may be required to obtain supply at increased prices that cannot be passed through to our customers. In general, product supply contracts permit suppliers to charge posted prices at the time of delivery or the current prices established at major storage points, creating the potential for sudden and drastic price fluctuations. Sudden and extended wholesale price increases could reduce our margins and could, if continued over an extended period of time, reduce demand by encouraging retail customers to conserve or convert to alternative energy sources. Conversely, a prolonged decline in product prices could potentially result in a reduction of the borrowing base under our working capital facility, and we could be required to liquidate inventory that we have already pre-sold.

 

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. 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

 

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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 segments also face 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 crude oil and natural gas liquids and we use third-party facilities to store natural gas liquids and ethanol. 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 propane.

 

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.

 

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 Federal Trade Commission (“FTC”), the Federal Energy Regulatory Commission (“FERC”), and the Commodity Futures Trading Commission (“CFTC”) hold statutory authority to monitor certain segments of the physical and futures energy commodities markets. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to our physical sales of energy commodities, and any related transportation and/or hedging activities that we undertake, we are required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Our sales may also be subject to certain reporting and other requirements. Additionally, to the extent that we enter into transportation contracts with pipelines that are subject to the FERC regulation or we become subject to the FERC regulation ourselves (see —“Some of our operations could become subject to the jurisdiction of the FERC,” 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 natural gas or crude oil 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.

 

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The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) provides for statutory and regulatory requirements for derivative transactions, including oil and 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, we do not know the definitions the CFTC will actually adopt or how these definitions will apply to us. Although the CFTC established position limits on certain core futures and equivalent swaps contracts, with exceptions for certain bona fide hedging transactions, those limits were vacated by a federal district court on September 28, 2012, and will not go into effect until the CFTC prevails on appeal of this ruling, or issues and finalizes revised rules. Additionally, in December 2012, the CFTC published final rules regarding mandatory clearing of four classes of interest rate swaps and two classes of credit swaps and setting compliance dates of March 11, 2013, June 10, 2013, and, for end users of swaps, September 9, 2013. 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 the trucking safety regulations, which are likely to be amended, and made stricter, as part of the initiative known as Comprehensive, Safety, Analysis (“CSA”). If our current United States Department of Transportation (“DOT”) safety ratings are downgraded to “Unsatisfactory” or the equivalent in connection with this initiative, our business and results of our operations may be adversely affected.

 

As part of the CSA initiative, the Federal Motor Carrier Safety Administration (“FMCSA”) is expected to open a rulemaking docket for purposes of changing its safety rating methodology. Any new methodology adopted in the rulemaking is likely to link safety ratings more closely to roadside inspection and driver violation data gathered and analyzed from month to month under the agency’s new Safety Measurement System (“SMS”). This linkage could result in greater variability in safety ratings than the current system, in which a safety rating is based on relatively infrequent on-site compliance audits at a carrier’s place(s) of business. Preliminary studies by transportation consulting firms indicate that “Satisfactory” ratings (or any equivalent under a new SMS-based system) may become more difficult to achieve and maintain under such a system. If we ever receive an “Unsatisfactory” or equivalent rating, we may lose some of our customer contracts that require such a rating, which may materially and adversely affect our business prospects and results of operations.

 

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, 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 and transportation business carries with it environmental risks, including leakage from the treatment plants to surface or subsurface soils, surface water or groundwater, or accidental spills or releases during the transport of wastewater. Our crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel businesses carry similar risks of leakage and sudden or accidental spills of crude oil, condensate, 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 recent train derailments occurring in the United States and Canada in 2013, United States regulators are implementing or considering new rules to address the safety risks of transporting crude oil by rail. On January 23, 2014, the National Transportation Safety Board issued a series of recommendations to address safety risks, and on February 25, 2014 the DOT issued an emergency order requiring all persons, prior to offering petroleum crude oil into transportation, to ensure such product

 

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is properly tested and classed. 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, which we acquired in 2012, 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 flow-back 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 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 4 tons per year without emission controls. 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 typically 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. In addition, some have asserted that the fracturing process and/or the wastewater disposal process could result in increased seismic activity. 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 2014. In addition, the United States

 

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Department of the Interior published a revised proposed rule on May 16, 2013 that would update existing regulation of hydraulic fracturing activities on federal lands, including requirements for disclosure, well bore integrity and handling of flowback water. Also, legislation has been introduced, but not adopted, in Congress to provide for federal regulation of hydraulic fracturing. In addition, some states have adopted and other states are considering adopting regulations that could restrict or regulate hydraulic fracturing in certain circumstances. For example, some states have adopted legislation requiring the disclosure of hydraulic fracturing chemicals, which could make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. 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.

 

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. 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 non-performance 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

 

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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.

 

Some of our operations could become 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 natural gas pipelines, among other things. Intrastate transportation and gathering pipelines that do not provide interstate services are not subject to regulation by the FERC. However, the distinction between the FERC-regulated interstate pipeline transportation on the one hand and intrastate pipeline transportation on the other hand, is a fact-based determination. The classification and regulation of our crude oil pipelines are subject to change based on future determinations by the FERC, federal courts, Congress or regulatory commissions, courts or legislatures in the states in which we operate. Glass Mountain Pipeline, LLC (“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. Further, 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.

 

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

 

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reduce demand for propane. In addition, if the price of propane increases, some of our customers may increase their conservation efforts and thereby decrease their consumption of propane.

 

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

 

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

 

Approximately 37% of the revenues of our water solutions segment during the year ended March 31, 2014 were generated from our two largest customers of the segment. Approximately 60% of the revenues of our crude oil logistics segment during the year ended March 31, 2014 were generated from our ten largest customers of the segment. Approximately 35% of the revenues of our liquids segment were generated from our ten largest customers of the segment. Approximately 41% of the revenues of our refined products segment were generated from our ten largest customers of the segment. Approximately 70% of the revenues of our renewables segment were generated from our ten largest customers of the segment. For the year ended March 31, 2014, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. 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

 

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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. The construction of such facilities requires the expenditure of significant amounts of capital, which may exceed our resources, and involves numerous regulatory, environmental, political and legal uncertainties. If we undertake these projects, we may not be able to complete them 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. For instance, if we build a new wastewater treatment facility, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until at least after completion of the project, if at all. Moreover, we may construct facilities 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 build new transportation systems and facilities, which may prove to be inaccurate because there are numerous uncertainties inherent in estimating quantities of proved, probable or possible reserves. As a result, new facilities 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 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

 

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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 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 (the “Exchange Act”). 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.

 

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

 

At March 31, 2014, we had reported goodwill and intangible assets of $1.8 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.

 

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

 

Our credit management procedures may not fully eliminate the risk of non-payment 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 non-payment 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 and natural gas liquids.

 

We own 22 natural gas liquids terminals and seven crude oil 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 natural gas 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 pre-sold 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.

 

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.

 

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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 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

 

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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 and the ability of the subordinated units to convert to common units;

 

·                  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 on our subordinated units or to our general partner in respect of the general partner interest or the incentive distribution rights;

 

·                  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 incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

 

In addition, certain members of the NGL Energy GP Investor Group and their affiliates currently hold interests in other companies in the energy and natural resource sectors. Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership interest in us. However, members of the NGL Energy GP Investor Group are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. As a result, they could potentially compete with us for acquisition opportunities and for new business or extensions of the existing services provided by us.

 

Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have

 

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any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders.

 

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

 

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner is chosen entirely by its members and not by our unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. Furthermore, if the 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 the 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 the 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.

 

The incentive distribution rights 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 incentive distribution rights (“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 a negative return on their investment. Our unitholders may also incur a tax liability upon a sale of their units.

 

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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 our Credit Agreement 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;

 

·                  because a lower percentage of total outstanding units will be subordinated units, the risk that a shortfall in the payment of the minimum quarterly distribution borne by our common unitholders will increase;

 

·                  the ratio of taxable income to distributions may increase;

 

·                  the relative voting strength of each previously outstanding unit may be diminished; and

 

·                  the market price of the common units may decline.

 

Our general partner, without the approval of our unitholders, may elect to cause us to issue common units while also maintaining its general partner interest in connection with a resetting of the target distribution levels related to its incentive distribution rights. This could result in lower distributions to our unitholders.

 

Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its IDRs at the highest level to which it is entitled (48.1%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

 

If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled

 

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their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the IDRs in the prior two quarters. We anticipate that our general partner would exercise this reset right to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common units rather than retain the right to receive distributions on its IDRs based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units and general partner interests to our general partner in connection with resetting the target distribution levels.

 

Our unitholders’ liability may not be limited if a court finds that unitholder action constitutes control of our business.

 

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if a court or government agency were to determine that:

 

·                  we were conducting business in a state but had not complied with that particular state’s partnership statute; or

 

·                  a unitholder’s right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute “control” of our business.

 

Our unitholders may have liability to repay distributions that were wrongfully distributed to them.

 

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware LP Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of an impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interests nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware LP Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability.

 

Tax Risks to Common Unitholders

 

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

 

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

 

Despite the fact that we are a limited partnership under Delaware law, a publicly traded partnership such as us will be treated as a corporation for federal income tax purposes unless, for each taxable year, 90% or more of its gross income is “qualifying income” under Section 7704 of the Internal Revenue Code of 1986, as amended (the “Code”). “Qualifying income” includes income and gains derived from the exploration, development, production, processing, transportation, storage and marketing of natural gas, natural gas products, and crude oil or other passive types of income such as certain interest and dividends and gains from the sale or other disposition of capital assets held for the production of income that otherwise constitutes qualifying income. Although we do not believe based upon our current operations that we are treated as a corporation, we could be treated as a corporation for federal income tax purposes or otherwise subject to taxation as an entity if our gross income is not properly classified as qualifying income, there is a change in our business or there is a change in current law.

 

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If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would pay state income tax at varying rates. Distributions to our unitholders would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses or deductions would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

 

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

 

If we were subjected to a material amount of additional entity-level taxation by individual states, it would reduce our cash available for distribution to our unitholders.

 

Changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. Imposition of any such taxes may substantially reduce the cash available for distribution to our unitholders. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that subjects us to entity-level taxation, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us.

 

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

 

The present income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of the United States Congress propose and consider substantive changes to the existing United States federal income tax laws that affect the tax treatment of publicly traded partnerships. Members of Congress have recently proposed substantive changes to the existing U.S. tax laws that would affect certain publicly traded partnerships, if such proposals are enacted into law. We are unable to predict whether any such change or other proposals will ultimately be enacted or will affect our tax treatment. Any modification to the income tax laws and interpretations thereof may or may not be applied retroactively and could, among other things, cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Moreover, such modifications and change in interpretations may affect or cause us to change our business activities, affect the tax considerations of an investment in us, change the character or treatment of portions of our income and adversely affect an investment in our common units. Although we are unable to predict whether any of these changes, or other proposals, will ultimately be enacted, any such changes could negatively impact the value of an investment in our common units.

 

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

 

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

 

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

 

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

 

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

 

If unitholders sell their common units, they will recognize a gain or loss equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of the unitholder’s allocable share of our net taxable income decrease the unitholder’s tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the

 

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units the unitholder sells will, in effect, become taxable income to the unitholder if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if a unitholder sell units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

 

Tax-exempt entities and non-United States persons face unique tax issues from owning our common units that may result in adverse tax consequences to them.

 

Investment in common units by tax-exempt entities, such as employee benefit plans, individual retirement accounts (known as IRAs), Keogh plans and other retirement plans and non-United States persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-United States persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non-United States persons will be required to file United States federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-United States person, you should consult your tax advisor before investing in our common units.

 

We treat each purchaser of common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

 

Because we cannot match transferors and transferees of common units and because of other reasons, we have adopted depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our unitholders. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to tax returns of unitholders.

 

We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate level income taxes.

 

We conduct a portion of our operations through subsidiaries that are corporations for federal income tax purposes. We may elect to conduct additional operations in corporate form in the future. Our corporate subsidiaries will be subject to corporate level tax, which will reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS or other state or local jurisdictions were to successfully assert that our corporate subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

 

We prorate our items of income, gain, loss and deduction for United States federal income tax purposes between transferors and transferees of our units each month based on the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

 

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

 

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

 

Because a unitholder whose units are loaned to a “short seller” to effect a short sale of units may be considered as having disposed of the loaned units, the unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those units may not be reportable by

 

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the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

 

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

 

When we issue additional units or engage in certain other transactions, we will determine the fair market value of our assets and allocate any unrealized gain or loss attributable to our assets to the capital accounts of our unitholders and our general partner. Our methodology may be viewed as understating the value of our assets. In that case, there may be a shift of income, gain, loss and deduction between certain unitholders and the general partner, which may be unfavorable to such unitholders. Moreover, under our current valuation methods, subsequent purchasers of common units may have a greater portion of their Code Section 743(b) adjustment allocated to our tangible assets and a lesser portion allocated to our intangible assets. The IRS may challenge our valuation methods, or our allocation of the Code Section 743(b) adjustment attributable to our tangible and intangible assets, and allocations of taxable income, gain, loss and deduction between the general partner and certain of our unitholders.

 

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our unitholders. It also could affect the amount of taxable gain from our unitholders’ sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions.

 

The sale or exchange of 50% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

 

We will be considered to have technically terminated for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50% threshold has been met, multiple sales of the same unit will be counted only once. While we would continue our existence as a Delaware limited partnership, our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a significant deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. A technical termination currently would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties for failure to file a timely return if we are unable to determine that a technical termination occurred. The IRS has announced a relief procedure whereby if a publicly traded partnership that has technically terminated requests and the IRS grants special relief, among other things, the partnership will be required to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

 

There are limits on the deductibility of our losses that may adversely affect our unitholders.

 

There are a number of limitations that may prevent unitholders from using their allocable share of our losses as a deduction against unrelated income. In cases where our unitholders are subject to the passive loss rules (generally, individuals and closely-held corporations), any losses generated by us will only be available to offset our future income and cannot be used to offset income from other activities, including other passive activities or investments. Unused losses may be deducted when the unitholder disposes of its entire investment in us in a fully taxable transaction with an unrelated party. A unitholder’s share of our net passive income may be offset by unused losses from us carried over from prior years but not by losses from other passive activities, including losses from other publicly traded partnerships. Other limitations that may further restrict the deductibility of our losses by a unitholder include the at-risk rules and the prohibition against loss allocations in excess of the unitholder’s tax basis in its units.

 

Purchasers of our common units may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

 

In addition to federal income taxes, holders of our common units are subject to other taxes, including foreign, state and local income taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or own or control property now or in the future. Holders of our common units are required to file foreign, state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions and may be subject to penalties for failure to comply with those requirements. We own assets and conduct business in a number of states, most of which impose a personal income tax on individuals. Most of these states also impose an income tax on corporations and other entities. As we make acquisitions or expand our business, we may own or control assets or conduct business in additional states that impose a personal income tax.

 

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Item 1B.          Unresolved Staff Comments

 

None.

 

Item 2.                   Properties

 

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

 

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

 

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

 

Our corporate headquarters are in Tulsa, Oklahoma and are leased. We also lease corporate offices in Denver, Colorado and Houston, Texas.

 

For additional information regarding our properties and the reportable segments in which they are used, see “Item 1 — Business.”

 

Item 3.                   Legal Proceedings

 

We are involved from time to time in various legal proceedings and claims arising in the ordinary course of business. For information related to legal proceedings, please see the discussion under the caption “Legal Contingencies” in Note 10 to our audited consolidated financial statements in Part IV, Item 15 of this Annual Report, which information is incorporated by reference into this Item 3.

 

Item 4.                   Mine Safety Disclosures

 

Not Applicable.

 

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PART II

 

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

 

Market Information

 

Our common units are listed on the New York Stock Exchange (“NYSE”) under the symbol “NGL.”  Our common units began trading on the NYSE on May 12, 2011. Prior to May 12, 2011, our common units were not listed on any exchange or traded in any public market.

 

At May 23, 2014, there were 239 common unitholders of record. This number does not include unitholders for whom common units may be held in “street name.”  We have also issued 5,919,346 subordinated units, for which there is no established public trading market. All of the subordinated units are held by the members of the NGL Energy LP Investor Group.

 

The following table sets forth, for the periods indicated, the high and low closing prices per common unit, as reported on the New York Stock Exchange Composite Transactions tape, and the amount of cash distributions paid per common unit.

 

		Price Range						Cash
2014 Fiscal Year		High			Low			Distribution
Fourth Quarter		$	37.72		$	33.45		$	0.5313
Third Quarter		34.50			30.43			0.5113
Second Quarter		33.73			28.21			0.4938
First Quarter		30.37			26.65			0.4775

 

		Price Range						Cash
2013 Fiscal Year		High			Low			Distribution
Fourth Quarter		$	26.90		$	22.64		$	0.4625
Third Quarter		25.16			21.26			0.4500
Second Quarter		26.67			22.11			0.4125
First Quarter		23.50			20.15			0.3625

 

Cash Distribution Policy

 

Available Cash

 

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. Available cash, for any quarter, generally consists of all cash on hand at the end of that quarter less the amount of cash reserves established by our general partner to (i) provide for the proper conduct of our business, (ii) comply with applicable law, any of our debt instruments or other agreements, and (iii) provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters.

 

Minimum Quarterly Distribution

 

Our partnership agreement provides that, during the subordination period, the common units are entitled to distributions of available cash each quarter in an amount equal to the minimum quarterly distribution, which is $0.3375 per common unit, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash are permitted on the subordinated units. Arrearages do not apply to and therefore will not be paid on the subordinated units. The effect of the subordinated units is to increase the likelihood that, during the subordination period, available cash is sufficient to fully fund cash distributions on the common units in an amount equal to the minimum quarterly distribution.

 

The subordination period will end on the first business day after we have earned and paid the minimum quarterly distribution on each outstanding common unit and subordinated unit and the corresponding distribution on the general partner interest for each of three consecutive, non-overlapping four-quarter periods ending on or after June 30, 2014 which we expect to occur in August 2014. The subordination period will also terminate automatically if the general partner is removed without cause and the units held by the general partner and its affiliates are not voted in favor of removal. When the subordination period lapses or otherwise terminates, all

 

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remaining subordinated units will convert into common units on a one-for-one basis and the common units will no longer be entitled to arrearages.

 

General Partner Interest

 

Our general partner is entitled to 0.1% of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest. Our general partner’s interest in our distributions may be reduced if we issue additional limited partner units in the future (other than the issuance of common units upon conversion of outstanding subordinated units or the issuance of common units upon a reset of the IDRs) and our general partner does not contribute a proportionate amount of capital to us to maintain its 0.1% general partner interest.

 

Incentive Distribution Rights

 

Our general partner also currently holds incentive distribution rights (“IDRs”) which represent a variable interest in our distributions. IDRs entitle our general partner to receive increasing percentages, up to a maximum of 48.1%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of $0.388125 per unit per quarter. The maximum distribution of 48.1% includes distributions paid to our general partner on its 0.1% general partner interest and assumes that our general partner maintains its general partner interest at 0.1%. The maximum distribution of 48.1% does not include any distributions that our general partner may receive on common units or subordinated units that it owns.

 

Restrictions on the Payment of Distributions

 

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

 

Sales of Unregistered Securities

 

During the fiscal year ended March 31, 2014, we completed three acquisitions in which we issued unregistered common units as part of the consideration for the acquisitions. All of these units were issued in reliance upon the exemption from registration provided by Section 4(a)(2) of the Securities Act, as the units were issued to the owners of businesses acquired in privately negotiated transactions not involving any public offering or solicitation. On July 1, 2013, we issued 175,211 common units to the sellers of Crescent Terminals, LLC and Cierra Marine, LP. On August 1, 2013, we issued 2,463,287 common units to the sellers of entities affiliated with Oilfield Water Lines, LP. On September 3, 2013, we issued 222,381 common units to the sellers of Coastal Plains Disposal #1, LLC.

 

On October 16, 2013, we completed the sale to a group of financial institutions, for which RBC Capital Markets, LLC acted as representative (collectively, the “Initial Purchasers”), of $450.0 million aggregate principal amount of 6.875% Senior Notes due 2021 (the “Unsecured Notes”) of the Partnership and its subsidiary NGL Energy Finance Corp. (collectively, the “Issuers”). The Initial Purchasers resold the Unsecured Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act, and to persons outside of the United States pursuant to Regulation S under the Securities Act. The Unsecured Notes were sold at par, and the Issuers received approximately $439.4 million of net proceeds from the sale of the Unsecured Notes.

 

On December 2, 2013, we issued and sold 8,110,848 common units in a private placement at a price of $29.59 per common unit for aggregate consideration of $240.0 million. This sale of common units was made in reliance upon an exemption from the registration requirements of the Securities Act of 1933, as amended, pursuant to Section 4(a)(2) thereof, as a transaction by an issuer not involving any public offering.

 

Securities Authorized for Issuance Under Equity Compensation Plans

 

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

 

Item 6.                   Selected Financial Data

 

We were formed on September 8, 2010, but had no operations through September 30, 2010. In October 2010, we acquired the assets and operations of NGL Supply and Hicksgas. We do not have our own historical financial statements for periods prior to our

 

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formation. The following table shows selected historical financial and operating data for NGL Energy Partners LP and NGL Supply (the deemed acquirer for accounting purposes in our formation) for the periods and as of the dates indicated. The financial statements of NGL Supply became our historical financial statements for all periods prior to October 1, 2010. The following table should be read in conjunction with “Item 7 — Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the financial statements and related notes included in this Annual Report.

 

The selected consolidated historical financial data (excluding volume information) at March 31, 2014 and 2013 and for each of the three years in the period ended March 31, 2014 are derived from our audited historical consolidated financial statements included in this Annual Report. The selected consolidated historical financial data (excluding volume information) at March 31, 2012 and 2011 and for the six months ended March 31, 2011 are derived from our financial records. The selected consolidated historical financial data (excluding volume information) at September 30, 2010 and for the six months then ended and at March 31, 2010 and for the year then ended are derived from the financial records of NGL Supply.

 

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		NGL Energy Partners LP												NGL Supply, Inc.
											Six Months Ended			Six Months Ended			Year Ended
		Year Ended March 31,									March 31,			September 30,			March 31,
		2014			2013			2012			2011			2010			2010
		(in thousands, except per unit data)
Income Statement Data (1)
Total revenues		$	9,699,274		$	4,417,767		$	1,310,473		$	622,232		$	316,943		$	735,506
Total cost of sales		9,132,699			4,039,110			1,217,023			583,032			310,908			708,215
Operating income (loss)		106,565			87,307			15,030			14,837			(3,795		)	6,661
Interest expense		58,854			32,994			7,620			2,482			372			668
Loss on early extinguishment of debt		—			5,769			—			—			—			—
Net income (loss) attributable to parent equity		47,655			47,940			7,876			12,679			(2,515		)	3,636
Basic and diluted earnings per common unit		0.51			0.96			0.32			1.16
Basic earnings (loss) per common share														(128.46		)	178.75
Diluted earnings (loss) per common share														(128.46		)	176.61
Cash Flows Data (1)
Cash flows from operating activities		$	85,236		$	132,634		$	90,329		$	34,009		$	(30,749	)	$	7,480
Cash distributions paid per common unit (subsequent to IPO)		2.01			1.69			0.85
Cash distributions per common unit (prior to IPO)								0.35			—
Cash distributions paid per common share														357.09			—
Capital expenditures:
Purchases of long-lived assets		165,148			72,475			7,544			1,440			280			582
Acquisitions of businesses, including additional consideration paid on prior period acquisitions		1,268,810			490,805			297,401			17,400			123			3,113
Balance Sheet Data - Period End (1)
Total assets		$	4,167,223		$	2,291,618		$	749,519		$	163,833		$	148,596		$	111,580
Total long-term obligations, exclusive of current maturities		1,639,578			742,641			199,389			65,936			18,940			8,851
Redeemable preferred stock		—			—			—			—			—			3,000
Total equity		1,531,853			889,418			405,329			47,353			36,811			46,403
Volume Information (1)
Retail propane and distillates sold (gallons)		197,326			173,232			79,886			34,932			3,747			15,514
Wholesale propane sold (gallons) (2)		1,190,106			912,625			659,921			372,504			226,330			623,510
Wholesale other products sold (gallons)		786,671			505,529			134,999			49,465			46,092			53,878
Crude oil sold (barrels)		46,107			24,373			—			—			—			—
Water delivered (barrels)		62,774			25,009			—			—			—			—
Refined products sold (gallons)		412,974			—			—			—			—			—
Renewables sold (gallons)		150,925			—			—			—			—			—

 

(1)             The acquisitions of businesses affect the comparability of this information.

 

(2)             Includes intercompany volumes sold to our retail propane segment.

 

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