NGL Energy Partners S4/A Registration of securities issued in business combination transactions (amended)

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TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS1
TABLE OF CONTENTS
INDEX TO FINANCIAL STATEMENTS2

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As filed with the Securities and Exchange Commission on December 24, 2014

Registration No. 333-197341

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Amendment No. 2
to

Form S-4
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933

NGL ENERGY PARTNERS LP*
NGL ENERGY FINANCE CORP.*
(Exact name of registrant as specified in its charter)


Delaware Delaware (State or other jurisdiction of incorporation or organization)		5900 5900 (Primary Standard Industrial Classification Code Number)		27-3427920 80-0956287 (I.R.S. Employer Identification Number)

6120 South Yale Avenue
Suite 805
Tulsa, Oklahoma
(918) 481-1119
(Address, including zip code, and telephone number, including area code, of registrant's principal executive offices)

H. Michael Krimbill
Chief Executive Officer
NGL Energy Partners LP
6120 South Yale Avenue
Suite 805
Tulsa, Oklahoma
(918) 481-1119
(Name, address, including zip code, and telephone number, including area code, of agent for service)

Copies to:
Henry Havre
Andrews Kurth LLP
600 Travis, Suite 4200
Houston, Texas 77002
(713) 220-4200

Approximate date of commencement of proposed sale of the securities to the public:
As soon as practicable after the effective date of this Registration Statement.

If the securities being registered on this Form are to be offered in connection with the formation of a holding company and there is compliance with General Instruction G, check the following box. o

If this Form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.


Large Accelerated filer ý		Accelerated filer o		Non-accelerated filer o (Do not check if a smaller reporting company)		Smaller reporting company o

If applicable, place an X in the box to designate the appropriate rule provision relied upon in conducting this transaction:

Exchange Act Rule 13e-4(i) (Cross-Border Issuer Tender Offer) o

Exchange Act Rule 144-1(d) (Cross-Border Third-Party Tender Offer) o

Each Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until this Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.

TABLE OF ADDITIONAL REGISTRANT GUARANTORS

* The following are co-registrants that guarantee the debt securities:

Exact name of registrant guarantor(1)	State or other jurisdiction of incorporation or organization

NGL Energy Operating LLC	Delaware	27-3428096
NGL Crude Logistics, LLC	Delaware	47-0794813
NGL Propane, LLC	Delaware	26-0648745
NGL Liquids, LLC	Delaware	27-3756258
NGL Crude Transportation, LLC	Delaware	46-5216792
NGL Crude Cushing, LLC	Oklahoma	27-4216425
High Sierra Crude Oil & Marketing, LLC	Colorado	03-0611248
High Sierra Energy, LP	Delaware	32-0133367
High Sierra Energy Operating, LLC	Colorado	32-0133362
High Sierra Compression LLC	Colorado	65-1259662
NGL Crude Pipelines, LLC	Oklahoma	27-2635247
NGL Energy Logistics, LLC	Delaware	90-0999490
NGL Energy Holdings II, LLC	Delaware	27-2639996
NGL Crude Terminals, LLC	Delaware	27-4016063
Lotus Oilfield Services, LLC	Texas	27-2394590
Andrews Oil Buyers, Inc.	Texas	75-2331321
NGL Crude Canada Holdings, LLC	Colorado	30-0762281
NGL Marine, LLC	Delaware	87-0758428
High Sierra Transportation, LLC	Colorado	73-1732045
Osterman Propane, LLC	Delaware	45-3263311
Hicksgas, LLC	Delaware	27-3573860
NGL-NE Real Estate, LLC	Delaware	37-1663246
NGL-MA Real Estate, LLC	Delaware	80-0781281
NGL-MA, LLC	Delaware	90-0790881
Centennial Energy, LLC	Colorado	84-1227036
Centennial Gas Liquids, ULC	Alberta	85-6127923
NGL Shipping and Trading, LLC	Delaware	68-0486837
NGL Supply Terminal Company, LLC	Delaware	01-0749898
NGL Supply Wholesale, LLC	Delaware	20-0317348
NGL Water Solutions, LLC	Colorado	20-8661032
AntiCline Disposal, LLC	Wyoming	41-2031951
NGL Water Solutions DJ, LLC	Colorado	37-1632639
NGL Water Solutions Eagle Ford, LLC	Delaware	80-0858222
NGL Water Solutions Permian, LLC	Colorado	32-0412772
TransMontaigne Inc.	Delaware	06-1052062
TransMontaigne Product Services Inc.	Delaware	84-1477374
TransMontaigne Services Inc.	Delaware	26-1409042
TransMontaigne GP L.L.C.	Delaware	51-0536032
NGL Milan Investments LLC	Colorado	37-1766148
NGL Water Solutions Mid-Continent, LLC	Colorado	61-1748866

(1): The address for each the registrant guarantors is 6120 S. Yale, Suite 805, Tulsa, OK 74136, and the telephone number for each of the registrant guarantors is (918) 481-1119. The Primary Standard Industrial Classification Code for the registrant guarantors is 5900.

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The information in this prospectus is not complete and may be changed. We may not sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any jurisdiction where the offer or sale is not permitted.

SUBJECT TO COMPLETION, DATED DECEMBER 24, 2014

PROSPECTUS

NGL Energy Partners LP
NGL Energy Finance Corp.

Offer to Issue
Up to $450,000,000 of
6.875% Senior Notes due 2021

That Have Been Registered Under
the Securities Act of 1933
("new notes")
In Exchange For

Up to $450,000,000 of
6.875% Senior Notes due 2021

That Have Not Been Registered Under
the Securities Act of 1933
("old notes")

Terms of the New Notes:

•: The terms of the new notes are identical to the terms of the old notes that were issued in October 2013, except that the new notes will be registered under the Securities Act of 1933, as amended, (the "Securities Act") and therefore freely tradable, and will not contain restrictions on transfer, registration rights or provisions for additional interest.

Terms of the Exchange Offer:

•: We are offering to issue new notes in exchange for the same principal amount of old notes.
•: Interest on the new notes will accrue from the last interest payment date on the notes at the rate of 6.875% per annum, and will be payable on April 15 and October 15 of each year.
•: The exchange offer expires at 5:00 p.m., New York City time, on , 2015, unless extended.
•: Tenders of old notes may be withdrawn at any time prior to the expiration of the exchange offer.
•: Your exchange of old notes for new notes will not be a taxable event for U.S. federal income tax purposes. Please read "Certain U.S. Federal Income Tax Consequences."

You should carefully consider the risks set forth under "Risk Factors" beginning on page 11 of this prospectus for a discussion of factors you should consider before participating in the exchange offer.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined if this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is , 2014.

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This prospectus is part of a registration statement we filed with the Securities and Exchange Commission. In making your investment decision, you should rely only on the information contained in this prospectus and in the accompanying letter of transmittal. We have not authorized anyone to provide you with any other information. If you receive any unauthorized information, you must not rely on it. We are not making an offer to sell these securities or soliciting an offer to buy these securities in any jurisdiction where an offer or solicitation is not authorized or in which the person making that offer or solicitation is not qualified to do so or to anyone whom it is unlawful to make an offer or solicitation. You should not assume that the information contained in this prospectus is accurate as of any date other than the date on the front cover of this prospectus.

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		Page

WHERE YOU CAN FIND MORE INFORMATION			ii
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			iii
PROSPECTUS SUMMARY			1
RISK FACTORS			11
EXCHANGE OFFER			33
RATIO OF EARNINGS TO FIXED CHARGES			41
USE OF PROCEEDS			42
SELECTED CONSOLIDATED HISTORICAL FINANCIAL AND OPERATING DATA			43
BUSINESS			44
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			71
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			137
MANAGEMENT			139
EXECUTIVE COMPENSATION			145
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS			156
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
DESCRIPTION OF NOTES			159
PLAN OF DISTRIBUTION			218
CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES			219
LEGAL MATTERS			220
EXPERTS			220
INDEX TO FINANCIAL STATEMENTS			F-1

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WHERE YOU CAN FIND MORE INFORMATION

Our SEC filings will be available to the public over the Internet at the SEC's web site at http://www.sec.gov. You may also read and copy any document we file at the SEC's public reference room located at 100 F Street, N.E., Washington D.C. 20549. Please call the SEC at 1-800-SEC-0330 for further information on the public reference room and copy charges. We will provide you upon request, without charge, a copy of the notes and the indenture governing the notes. You may request copies of these documents by contacting us at:

NGL Energy Partners LP
6120 South Yale Avenue
Suite 805
Tulsa, Oklahoma 74136
(918) 481-1119

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CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

This prospectus 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 prospectus, 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. The following are key risk factors that may impact our consolidated financial position and results of operations:

•: 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;

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•: hazards or operating risks incidental to the transporting and distributing of petroleum products that may not be fully covered by insurance;
•: the maturity of the crude oil and natural gas liquids industries and competition from other marketers;
•: the loss of key personnel;
•: the ability to hire drivers;
•: the ability to renew contracts with key customers;
•: the ability to maintain or increase the margins we realize for our terminal, barging, trucking, and water disposal and recycling and discharge services;
•: the ability to renew leases for general purpose and high pressure railcars;
•: the ability to renew leases for underground natural gas liquids storage;
•: the nonpayment or nonperformance by our customers;
•: the availability and cost of capital and our ability to access certain capital sources;
•: a deterioration of the credit and capital markets;
•: the ability to successfully identify and consummate strategic acquisitions 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;
•: any reduction or the 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.; and
•: other risks and uncertainties, including those described under "Risk Factors."

All readers are cautioned that the forward-looking statements contained in this prospectus are not guarantees of future performance, and our expectations may not be realized or the forward-looking events and circumstances may not occur. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to factors described elsewhere in this prospectus, including under the heading "Risk Factors" in this prospectus. You should not put undue reliance on any forward-looking statements. All forward-looking statements included in this prospectus are made only as of the date hereof. Except as required by state and federal securities laws, we undertake no obligation to update or revise any forward-looking statements as a result of information, future events or otherwise.

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PROSPECTUS SUMMARY

This summary highlights information included in this prospectus. It does not contain all of the information that may be important to you. You should read carefully this entire prospectus for a more complete understanding of our business and the terms of this offering, as well as the tax and other considerations that are important to you in making your investment decision.

Unless the context otherwise requires, references to "NGL Energy Partners," "NGL," "we," "us," "our" and similar terms, as well as references to the "Partnership," are to NGL Energy Partners LP and all of its subsidiaries. Our "general partner" refers to NGL Energy Holdings LLC.

NGL Energy Partners LP

Overview

We are a Delaware limited partnership formed in September 2010 by several investors. As part of our formation, we acquired and combined the assets and operations of NGL Supply, Inc., primarily a wholesale propane and terminalling 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, including with High Sierra Energy, LP in 2012, as a result of which we entered the crude oil logistics and water services businesses, and Gavilon, LLC in December 2013, as a result of which we entered the refined products marketing and renewables businesses.

At September 30, 2014, our operations include:

•: Ourcrude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased and owned railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.
•: Ourwater solutions segment, the assets of which include water treatment and disposal facilities. Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, and from the sale of recycled water and recovered hydrocarbons.
•: Ourliquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 22 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, petrochemical plants, and other participants in the wholesale markets.
•: Ourretail propane segment, 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.
•: Ourrefined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.7% limited partner interest in TransMontaigne Partners L.P. ("TLP"), which conducts refined products terminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC ("BOSTCO") and a 50% interest in Frontera Brownsville LLC, which are entities that own refined products storage facilities.

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Our Ownership and Organizational Structure

The following chart provides a simplified overview of our organizational structure as of September 30, 2014:

(1): The notes are currently guaranteed by all of our restricted subsidiaries (other than NGL Energy Finance Corp.) that are obligors under certain of our indebtedness, including our Credit Agreement. See "Description of Notes—Note Guarantees" and "—Additional Note Guarantees."
(2): Includes (i) NGL Crude Logistics, LLC which includes the operations of our crude oil logistics, refined products and renewables business, (ii) NGL Water Solutions, LLC, which includes the operations of our water solutions business, (iii) NGL Liquids, LLC, which includes the operations of our liquids business and (iv) NGL Propane, LLC, which includes the operations of our retail propane business.

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Recent Developments

Grand Mesa Acquisition

On November 26, 2014, NGL Crude Terminals, LLC ("NGL Crude"), a subsidiary of NGL Energy Partners LP (the "Partnership"), entered into a Membership Interest Purchase Agreement (the "Purchase Agreement") with Rimrock Midstream, LLC ("Rimrock"), its 50% joint venture partner in the ownership of Grand Mesa Pipeline, LLC ("Grand Mesa"). Pursuant to the Purchase Agreement, NGL Crude agreed to acquire from Rimrock the remaining 50% membership interest in Grand Mesa in exchange for $310.0 million in cash. The Purchase Agreement contains provisions regarding contingencies as well as customary representations and warranties, covenants and agreements. NGL Crude completed the purchase on December 1, 2014.

Facility Increase Agreement

On December 1, 2014, NGL Energy Operating, LLC, in its capacity as borrowers' agent and a wholly-owned subsidiary of the Partnership, entered into a Facility Increase Agreement (the "Agreement") with Deutsche Bank Trust Company Americas, as administrative agent and the other financial institutions party thereto. The Agreement increases the working capital revolving commitments under the Partnership's revolving credit facility by an additional $103.0 million.

Principal Executive Offices

We are a limited partnership formed under the laws of the State of Delaware. Our executive offices are located at 6120 South Yale Avenue, Suite 805, Tulsa, Oklahoma 74136. Our telephone number is (918) 481-1119. We maintain a website at http://www.nglenergypartners.com. Information contained on this website, however, is not incorporated into or otherwise a part of this prospectus.

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The Exchange Offer

On October 16, 2013 we completed a private offering of the old notes. We entered into a registration rights agreement with the initial purchasers in the private offering pursuant to which we agreed to deliver to you this prospectus and to use commercially reasonable efforts to cause the registration statement of which his prospectus forms a part to be declared effective by the SEC on or before October 16, 2014.


Old Notes		$450 million aggregate principal amount of 6.875% Senior Notes due 2021, issued pursuant to Rule 144A and Regulation S promulgated under the Securities Act. Transfer restrictions apply to the old notes.
New Notes		Up to $450 million aggregate principal amount of 6.875% Senior Notes due 2021. The terms of the new notes are identical to the terms of the old notes, except that the new notes will be registered under the Securities Act, and will not have restrictions on transfer, registration rights or provisions for additional interest.
		Except as provided below, we believe that the new notes may be offered for resale, resold and otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Actprovided that:
		• the new notes are being acquired in the ordinary course of business,
		• you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the new notes issued to you in the exchange offer,
		• you are not our affiliate, and
		• you are not a broker-dealer tendering old notes acquired directly from us for your account.
		Our belief is based on interpretations by the staff of the SEC, as set forth in no-action letters issued to third parties that are not related to us. The SEC has not considered this exchange offer in the context of a no-action letter, and we cannot assure you that the SEC would make similar determinations with respect to this exchange offer. If any of these conditions are not satisfied, or if our belief is not accurate, and you transfer any new notes issued to you in the exchange offer without delivering a resale prospectus meeting the requirements of the Securities Act or without an exemption from registration of your new notes from those requirements, you may incur liability under the Securities Act. We will not assume, nor will we indemnify you against, any such liability. Each broker-dealer that receives new notes for its own account in exchange for old notes, where the old notes were acquired by such broker-dealer as a result of market-making or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. See "Plan of Distribution."

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Exchange Offer		We are offering to issue freely tradable new notes in exchange for the same principal amount of old notes. The old notes may be tendered only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. We will issue new notes in exchange for all old notes that are validly tendered and not withdrawn prior to the expiration of the exchange offer. We will cause the exchange to be effected promptly after the expiration date of the exchange offer.
		The new notes will evidence the same debt as the old notes and will be issued under and entitled to the benefits of the same indenture that governs the old notes. Because we have registered the offers and sales of the new notes, the new notes will not be subject to transfer restrictions, and holders of old notes that have tendered and had their outstanding notes accepted in the exchange offer will have no further registration rights.
Expiration Date		The exchange offer will expire at 5:00 p.m., New York City time, on , 20 , unless we decide to extend it.
Conditions to the Exchange Offer		The registration rights agreement does not require us to accept old notes for exchange if the exchange offer, or the making of any exchange by a holder of the old notes, would violate any applicable law or interpretation of the staff of the Securities and Exchange Commission. The exchange offer is not conditioned on a minimum aggregate principal amount of old notes being tendered. Please read "Exchange Offer—Conditions to the Exchange Offer" for more information about the conditions to the exchange offer.
Procedures for Tendering Old Notes		To participate in the exchange offer, you must follow the procedures established by The Depository Trust Company, or DTC, for tendering notes held in book-entry form. These procedures for using DTC's Automated Tender Offer Program, or ATOP, require that (i) the exchange agent receive, prior to the expiration date of the exchange offer, a computer generated message known as an "agent's message" that is transmitted through ATOP, and (ii) DTC confirms that:
		• DTC has received your instructions to exchange your notes; and
		• you agree to be bound by the terms of the letter of transmittal.
		By transmitting an agent's message, you will represent to us that, among other things:
		• the new notes you receive will be acquired in the ordinary course of your business;
		• you are not participating, and you have no arrangement with any person or entity to participate, in the distribution of the new notes;

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		• you are not our "affiliate," as defined in Rule 405 under the Securities Act, or a broker-dealer tendering old notes acquired directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act; and
		• if you are not a broker-dealer, that you are not engaged in and do not intend to engage in the distribution of the new notes.
		For more information on tendering your old notes, please refer to the section in this prospectus entitled "Exchange Offer—Terms of the Exchange Offer," "—Procedures for Tendering," and "Description of Notes—Book-Entry, Delivery and Form."
Guaranteed Delivery Procedures		None.
Withdrawal of Tenders		You may withdraw your tender of old notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 5:00 p.m., New York City time, on the expiration date of the exchange offer. Please refer to the section in this prospectus entitled "Exchange Offer—Withdrawal of Tenders."
Acceptance of Old Notes and Delivery of New Notes		If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in the exchange offer on or before 5:00 p.m., New York City time, on the expiration date. We will return any old notes that we do not accept for exchange to you without expense promptly after the expiration date and acceptance of the old notes for exchange. Please refer to the section in this prospectus entitled "Exchange Offer—Terms of the Exchange Offer."
Fees and Expenses		We will bear expenses related to the exchange offer. Please refer to the section in this prospectus entitled "Exchange Offer—Fees and Expenses."
Use of Proceeds		The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement entered into in connection with the initial issuance of the old notes.

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Consequences of Failure to Exchange Old Notes		If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register the old notes under the Securities Act, except in limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.
U.S. Federal Income Tax Considerations		The exchange of old notes for new notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read "Certain U.S. Federal Income Tax Consequences."
Exchange Agent		We have appointed U.S. Bank National Association as exchange agent for the exchange offer. You should direct questions and requests for assistance, as well as requests for additional copies of this prospectus or the letter of transmittal, to the exchange agent addressed as follows: U.S. Bank National Association, Corporate Trust Services, Attention: Specialized Finance Department, 111 Fillmore Ave. E., St. Paul, MN 55107. Eligible institutions may make requests by facsimile at (651) 466-7372, and may confirm facsimile delivery by calling (800) 934-6802.

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Terms of the New Notes

The new notes will be identical to the old notes, except that the new notes are registered under the Securities Act and will not have restrictions on transfer, registration rights or provisions for additional interest. The new notes will evidence the same debt as the old notes, and the same indenture will govern the new notes and the old notes.

The following summary contains basic information about the new notes and is not intended to be complete. It does not contain all the information that is important to you. For a more complete understanding of the new notes, please refer to the section of this prospectus entitled "Description of Notes."


Issuers		NGL Energy Partners LP and NGL Energy Finance Corp.
		NGL Energy Finance Corp., a Delaware corporation, is a 100% owned subsidiary of NGL Energy Partners LP that was organized for the sole purpose of being a co-issuer of certain of our indebtedness, including the new notes. NGL Energy Finance Corp. has no operations and no revenue other than as may be incidental to its activities as co-issuer of our indebtedness.
Notes Offered		$450 million aggregate principal amount of 6.875% Senior Notes due 2021.
Maturity Date		October 15, 2021.
Interest		Interest on the new notes will accrue from April 15, 2014 at a rate of 6.875% per annum (calculated using a 360-day year).
		Interest on the new notes is payable on April 15 and October 15 of each year.
Ranking		Like the old notes, the new notes will be the unsecured senior obligations of each of the Issuers. Accordingly, they will rank:
		• pari passu in right of payment with all existing and future unsecured senior indebtedness of each of the Issuers;
		• senior in right of payment to any future subordinated indebtedness of each of the Issuers;
		• structurally subordinated to all obligations of any of our subsidiaries; and
		• effectively junior in right of payment to all existing and future secured indebtedness of each of the Issuers, including indebtedness under the our revolving credit agreement (the "Credit Agreement") and our 6.65% Senior Secured Notes due 2022 (the "Existing Senior Secured Notes"), which are secured by substantially all of the assets of NGL Energy, to the extent of the value of the assets of the Issuers constituting collateral securing such indebtedness.
		See "Risk Factors—Risks Related to the Notes—The notes and the guarantees are unsecured and effectively subordinated to our and our subsidiary guarantors' existing and future secured indebtedness.."

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		As of September 30, 2014, we had $2,442.4 million of total long-term indebtedness, $1,329.5 million of which was secured indebtedness, and we had $904.3 million of remaining borrowing capacity under our Credit Agreement (net of $209.2 million of outstanding letters of credit).
		The guarantees will rank:
		• pari passu in right of payment with all existing and future unsecured senior indebtedness of each guarantor;
		• senior in right of payment to any future subordinated indebtedness of each guarantor; and
		• effectively junior in right of payment to all existing and future secured indebtedness of each guarantor, including indebtedness under the Credit Agreement and the Existing Senior Secured Notes, to the extent of the value of the assets of each guarantor constituting collateral securing such indebtedness.
Optional Redemption		Beginning on October 15, 2016, we may redeem some or all of the new notes at the redemption prices listed under "Description of Notes—Optional Redemption" plus accrued and unpaid interest, if any, on the notes to the date of redemption.
		At any time prior to October 15, 2016, we may, at our option, redeem up to 35% of the new notes with a cash amount equal to the net proceeds of certain equity offerings at a redemption price equal to 106.875% of the aggregate principal amount, plus accrued and unpaid interest, if any, to the redemption date. We may make that redemption only if, after the redemption, at least 65% of the aggregate principal amount of the new notes issued on the initial issue date remains outstanding and the redemption occurs within 180 days of the closing of the equity offering. Please see "Description of Notes—Optional Redemption."
		We may, from time to time prior to October 15, 2016, redeem all or a part of the new notes, at a redemption price equal to 100% of the aggregate principal amount of the new notes redeemed, plus a "make-whole" premium and accrued and unpaid interest, if any, to the redemption date.
Change of Control		If we experience certain kinds of changes of control, we must give holders of the new notes the opportunity to sell us their new notes at 101% of their principal amount, plus accrued and unpaid interest, if any.
Certain Covenants		The indenture governing the new notes contains certain covenants limiting our ability and the ability of our restricted subsidiaries to, under certain circumstances:
		• pay distributions on, purchase or redeem our common equity or purchase or redeem our subordinated debt;

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		• incur or guarantee additional indebtedness or issue preferred units;
		• create or incur certain liens;
		• enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
		• consolidate, merge or transfer all or substantially all of our assets; and
		• engage in transactions with affiliates.
		These covenants are subject to important exceptions and qualifications as described in this prospectus under the caption "Description of Notes—Covenants." In addition, certain of the covenants listed above will terminate before the new notes mature if any two of the three specified rating agencies assign the new notes an investment grade rating in the future and no events of default exist under the indenture. Any covenants that cease to apply to us as a result of achieving investment grade ratings will not be restored, even if the credit ratings assigned to the new notes later fall below investment grade.
Absence of Established Market for the New Notes		The new notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development or liquidity of any market for the new notes.
		We do not intend to apply for a listing of the new notes on any securities exchange or for the inclusion of the new notes on any automated dealer quotation system.

Ratio of Earnings to Fixed Charges

The following table presents the ratios of earnings to fixed charges of the Partnership for the periods indicated. For purposes of computing the ratios of earnings to fixed charges, earnings consist of income (loss) from continuing operations before income taxes plus fixed charges and loss (income) from continuing operations before income taxes attributable to noncontrolling interests. Fixed charges consists of interest expense plus loss on early extinguishment of debt and the portion of rental expense estimated to relate to interest. The portion of rental expense estimated to relate to interest represents one-third of total operating lease rental expense, which is the portion estimated to represent interest.

	NGL Energy Partners LP										NGL Supply, Inc.

	Six Months Ended September 30, 2014		Year Ended March 31, 2014		Year Ended March 31, 2013		Year Ended March 31, 2012		Six Months Ended March 31, 2011		Six Months Ended September 30, 2010		Year Ended March 31, 2010
Ratio of earnings to fixed charges		(a)		1.53x		1.75x		1.91x		5.59x		(b)		6.32x

(a): Due to NGL Energy Partners LP's loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2014. NGL Energy Partners LP would have needed to generate an additional $60.1 million of earnings to achieve a ratio of 1:1.
(b): Due to NGL Supply, Inc.'s loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2010. NGL Supply, Inc. would have needed to generate an additional $3.9 million of earnings to achieve a ratio of 1:1.

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RISK FACTORS

An investment in the notes is subject to numerous risks, including those listed below. You should carefully consider the following risks as well as the information provided elsewhere in this prospectus. While these are the risks and uncertainties we believe are most important for you to consider, you should know that they are not the only risks or uncertainties facing us or which may adversely affect our business. These risks could materially affect our ability to meet our obligations under the notes. You could lose all or part of your investment in and fail to achieve the expected return on the notes

Risks Related to Investing in the New Notes

Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects and our ability to make payments on the notes.

As of September 30, 2014, we had $2,442.4 million of total long-term indebtedness, including $1,079.5 million of debt outstanding under our Credit Agreement and approximately $250 million aggregate principal amount of our senior secured notes, and we had additional borrowing capacity of $904.3 million under our Credit Agreement (net of $209.2 million of outstanding letters of credit). Our level of indebtedness could affect our operations in several ways, including the following:

•: requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and limiting our flexibility in planning for or reacting to changes in our business and the industry in which we operate;
•: increasing our vulnerability to economic downturns and adverse developments in our business;
•: limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
•: placing restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
•: placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and
•: making it more difficult for us to satisfy our obligations under the notes or other debt and increasing the risk that we may default on our debt obligations.

Our leverage could have important consequences to investors in the notes. We will require substantial cash flow to meet our principal and interest obligations with respect to the notes and our other indebtedness. Our ability to make scheduled payments, to refinance our obligations with respect to our indebtedness or our ability to obtain additional financing in the future will depend on our financial and operating performance, which, in turn, is subject to prevailing economic conditions and to financial, business and other factors. We believe that we will have sufficient cash flow from operations and available borrowings under our Credit Agreement to service our indebtedness. However, a significant downturn in our business or other development adversely affecting our cash flow could materiallyimpair our ability to service our indebtedness. If our cash flow and capital resources are insufficient to fund our debt service obligations, we may be forced to refinance all or a portion of our debt or sell assets. We cannot assure you that we would be able to refinance our existing indebtedness or sell assets on terms that are commercially reasonable.

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We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

We are a holding company, and our operating subsidiaries conduct all of our operations and own all of our operating assets. We have no significant assets other than our interest in our operating subsidiaries. As a result, our ability to make required payments on the notes depends on the performance of our operating subsidiaries and their ability to distribute funds to us. The ability of our subsidiaries to make distributions to us may be restricted by, among other things, our Credit Agreement and the purchase agreement governing our Existing Senior Secured Notes and applicable state partnership laws and other laws and regulations. If we are unable to obtain the funds necessary to pay the principal amount at maturity of the notes, or to repurchase the notes upon the occurrence of a change of control, we may be required to adopt one or more alternatives, such as a refinancing of the notes or a sale of assets. We may not be able to refinance the notes or sell assets on acceptable terms, or at all.

Despite our current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.

We may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our Credit Agreement and under the indenture for the notes. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations, including those relating to the notes.

The notes and the guarantees are unsecured and effectively subordinated to our and our subsidiary guarantors' existing and future secured indebtedness.

The notes and the guarantees are general unsecured senior obligations ranking effectively junior in right of payment to all existing and future secured debt of ours and that of any subsidiary guarantors, including obligations under our Credit Agreement and our Existing Senior Secured Notes, to the extent of the value of the collateral securing the debt. If we or any subsidiary guarantor is declared bankrupt, becomes insolvent or is liquidated or reorganized, any secured debt of ours or of such subsidiary guarantor will be entitled to be paid in full from our assets or the assets of such subsidiary guarantor, as applicable, securing that debt before any payment may be made with respect to the notes or the affected guarantees. Holders of the notes will participate ratably with all holders of our other unsecured indebtedness that does not rank junior to the notes, including all of our other general creditors, based upon the respective amounts owed to each holder or creditor, in our remaining assets. In any of the foregoing events, we cannot assure you that there will be sufficient assets to pay amounts due on the notes. As a result, holders of the notes would likely receive less, ratably, than holders of secured indebtedness.

The notes and the guarantees are structurally subordinated to all liabilities of our non-guarantor subsidiaries.

The notes are structurally subordinated to the indebtedness and other liabilities of our subsidiaries that are not guaranteeing the notes. These non-guarantor subsidiaries are separate and distinct legal entities and have no obligation, contingent or otherwise, to pay any amounts due pursuant to the notes, or to make any funds available therefor, whether by loans, distributions or other payments. Any right that we or the subsidiary guarantors have to receive any assets of any of the non-guarantor subsidiaries upon the liquidation or reorganization of those non-guarantor subsidiaries, and the consequent rights of

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holders of notes to realize proceeds from the sale of any of those non-guarantor subsidiaries' assets, will be effectively subordinated to the claims of those non-guarantor subsidiaries' creditors, including trade creditors and holders of preferred equity interests of those non-guarantor subsidiaries. Accordingly, in the event of a bankruptcy, liquidation or reorganization of any of our non-guarantor subsidiaries, these non-guarantor subsidiaries will pay the holders of their debts, holders of preferred equity interests and their trade creditors before they will be able to distribute any of their assets to us. As of September 30, 2014, our non-guarantor subsidiaries (as the term "Subsidiary" is defined pursuant to the indenture governing the notes) had no material indebtedness outstanding.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our Credit Agreement bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our cash available for servicing our indebtedness would decrease. A 1.0% increase in interest rates on the debt outstanding under our facility as of September 30, 2014 would have cost us approximately $10.8 million in additional annual interest expense.

We may not have the funds necessary to finance the repurchase of the notes in connection with a change of control offer required by the indenture.

Upon the occurrence of specific kinds of change of control events, the indenture governing the notes requires us to make an offer to repurchase all such notes at 101% of the principal amount thereof, plus accrued and unpaid interest (and liquidated damages, if any) to the date of repurchase. However, it is possible that we will not have sufficient funds, or the ability to raise sufficient funds, at the time of the change of control to make the required repurchase of the notes. In addition, restrictions under our Credit Agreement and the Existing Senior Secured Notes may not allow us to make such a repurchase upon a change of control. If we could not refinance our Credit Agreement or Existing Senior Secured Notes or otherwise obtain a waiver from the holders of such debt, we would be prohibited from repurchasing the notes, which would constitute an event of default under the indenture. In addition, certain important corporate events, such as leveraged recapitalizations that would increase the level of our indebtedness, would not constitute a "Change of Control" under the indenture. Because the definition of change of control under our Credit Agreement differs from that under the indenture, there may be a change of control and resulting default under our Credit Agreement at a time when no change of control has occurred under the indenture. Please read "Description of Notes—Repurchase at the Option of Holders—Change of Control."

Holders of the notes may not be able to determine when a change of control giving rise to their right to have the notes repurchased has occurred following a sale of "substantially all" of our assets.

The definition of change of control in the indenture governing the notes includes a phrase relating to the direct or indirect sale, lease, transfer, conveyance or other disposition of "all or substantially all" of the properties or assets of the Partnership and its subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require us to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of the Partnership and its subsidiaries taken as a whole to another person or group may be uncertain.

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Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from subsidiary guarantors.

Under the federal bankruptcy law and comparable provisions of state fraudulent transfer laws, a guarantee of the notes could be voided, or claims in respect of a guarantee could be subordinated to all other debts of that subsidiary guarantor, if, among other things, the subsidiary guarantor, at the time it incurred the debt evidenced by its guarantee:

•: received less than reasonably equivalent value or fair consideration for the incurrence of such guarantee;
•: was insolvent or rendered insolvent by reason of such incurrence; was engaged in a business or transaction for which the subsidiary guarantor's remaining assets constituted unreasonably small capital; or
•: intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature.

In addition, any payment by that subsidiary guarantor pursuant to its guarantee could be voided and required to be returned to the subsidiary guarantor, or to a fund for the benefit of our creditors or the creditors of the guarantor.

The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a subsidiary guarantor would be considered insolvent if:

•: the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;
•: if the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as
•: they become absolute and mature; or
•: it could not pay its debts as they become due.

On the basis of historical financial information, recent operating history and other factors, we believe that each subsidiary guarantor, after giving effect to its guarantee of the notes, will not be insolvent, will not have unreasonably small capital for the business in which it is engaged and will not have incurred debts beyond its ability to pay such debts as they mature. We cannot assure you, however, as to what standard a court would apply in making these determinations or that a court would agree with our conclusions in this regard.

If an active trading market does not develop for the new notes you may not be able to resell them.

Prior to this offering, there was no trading market for the new notes, and we cannot assure you that an active trading market will develop. If no active trading market develops, you may not be able to resell your notes at their fair market value or at all. Future trading prices of the notes will depend on many factors, including, among other things, our ability to consummate this exchange offer, prevailing interest rates, our operating results and the market for similar securities. We do not intend to apply to list the notes on any securities exchange.

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Many of the covenants contained in the indenture will terminate if the notes are rated investment grade by any two of Standard & Poor's Ratings Services, Moody's Investor Service, Inc. and Fitch Ratings, Inc. and no default has occurred and is continuing.

Many of the covenants in the indenture governing the notes will terminate if the notes are rated investment grade by any two of Standard & Poor's, Moody's, and Fitch provided that at such time no default has occurred and is continuing. The covenants restrict, among other things, our ability to pay distributions, incur debt and to enter into certain other transactions. There can be no assurance that the notes will ever be rated investment grade. However, termination of these covenants would allow us to engage in certain transactions that would not have been permitted while these covenants were in force, and the effects of any such transactions will be permitted to remain in place even if the notes are subsequently downgraded below investment grade. See "Description of Notes—Certain Covenants—Covenant Termination."

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of the U.S. Congress propose and consider substantive changes to the existing federal income tax laws that affect certain publicly traded partnerships. We are unable to predict whether any such proposals will ultimately be enacted. However, it is possible that a change in law could affect us and may be applied retroactively. Any such changes could cause a material reduction in our anticipated cash flow, which could materially and adversely affect our ability to make payments on the notes and our other debt obligations and could cause a reduction in the value of the notes.

Risks Related to our Business

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, the purchase agreement governing our outstanding 6.65% senior secured notes due 2022 (the "Note Purchase Agreement") and indentures governing our outstanding 6.875% senior notes due 2021 and our outstanding 5.125% Senior Notes due 2019 (the "Indentures") that limit the amount and types of indebtedness that we may incur to finance acquisitions and which may adversely affect our ability to service our debt obligations, including the notes;
•: 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 service our debt obligations, including the notes. Furthermore, if we consummate any future acquisitions, our capitalization and results of operations may change

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significantly, and investors 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;
•: 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, 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.

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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 to service our debt obligations, including the notes, 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.

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.

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We depend on the ability and willingness of other entities to make operating and capital expenditures to explore for, develop, and produce oil and natural gas in the United States and Canada, and to extract natural gas liquids from natural gas as well as the availability of necessary pipeline transportation and storage capacity. Customers' expectations of lower market prices for oil and natural gas, as well as the availability of capital for operating and capital expenditures, may cause them to curtail spending, thereby reducing business opportunities and demand for our services and equipment. Actual market conditions and producers' expectations of market conditions for crude oil, condensate and natural gas liquids may also cause producers to curtail spending, thereby reducing business opportunities and demand for our services.

Industry conditions are influenced by numerous factors over which we have no control, such as the availability of commercially viable geographic areas in which to explore and produce oil and natural gas, the availability of liquids-rich natural gas needed to produce natural gas liquids, the supply of and demand for oil and natural gas, environmental restrictions on the exploration and production of oil and natural gas, such as existing and proposed regulation of hydraulic fracturing, domestic and worldwide economic conditions, political instability in oil and natural gas producing countries and merger and divestiture activity among our current or potential customers. The volatility of the oil and natural gas industry and the resulting impact on exploration and production activity could adversely impact the level of drilling activity. This reduction may cause a decline in business opportunities or the demand for our services, or adversely affect the price of our services. Reduced discovery rates of new oil and natural gas reserves in our market areas also may have a negative long-term impact on our business, even in an environment of stronger oil and natural gas prices, to the extent existing production is not replaced.

The oil and natural gas production industry tends to run in cycles and may, at any time, cycle into a downturn; if that occurs again, the rate at which it returns to former levels, if ever, will be uncertain. Prior adverse changes in the global economic environment and capital markets and declines in prices for oil and natural gas have caused many customers to reduce capital budgets for future periods and have caused decreased demand for oil and natural gas. Limitations on the availability of capital, or higher costs of capital, for financing expenditures have caused and may continue to cause customers to make additional reductions to capital budgets in the future even if commodity prices increase from current levels. These cuts in spending may curtail drilling programs and other discretionary spending, which could result in a reduction in business opportunities and demand for our services, the rates we can charge and our utilization. In addition, certain of our customers could become unable to pay their suppliers, including us. Any of these conditions or events could materially and adversely affect our operating results.

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

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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 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.

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

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

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

Our costs may increase at a rate greater than the rate that the fees that we charge to customers increase pursuant to our contracts with them. Additionally, some customers' obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of crude oil, condensate, and/or natural gas liquids are curtailed or cut off. Force majeure events include (but are not limited to) revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities of our customers. If the escalation of fees is insufficient to cover increased costs or if any customer suspends or terminates its contracts with us, our profitability could be materially and adversely affected.

Our sales of crude oil, condensate, natural gas liquids, refined products, ethanol, and biodiesel and related transportation and hedging activities, and our processing of wastewater, expose us to potential regulatory risks.

The 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.

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

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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,

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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 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.

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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 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.

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

We operate in various locations across the United States and Canada which may be adversely affected by seasonal weather conditions and natural or man-made disasters. During periods of heavy snow, ice, rain or extreme weather conditions such as high winds, tornados and hurricanes or after other natural disasters such as earthquakes or wildfires, we may be unable to move our trucks or railcars between locations and our facilities may be damaged, thereby reducing our ability to provide services and generate revenues. In addition, hurricanes or other severe weather in the Gulf Coast region could seriously disrupt the supply of products and cause serious shortages in various areas, including the areas in which we operate. These same conditions may cause serious damage or destruction to homes, business structures and the operations of customers. Such disruptions could potentially have a material adverse impact on our business, financial condition, results of operations and cash flows.

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

Pursuant to the requirements of our market risk policy, we attempt to lock in a margin for a portion of the commodities we purchase by selling such commodities for physical delivery to our customers, such as independent refiners or major oil companies, or by entering into future delivery obligations under contracts for forward sale. 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 service our debt obligations, including the notes.

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Our use of derivative financial instruments could have an adverse effect on our results of operations.

We have used derivative financial instruments as a means to protect against commodity price risk or interest rate risk and expect to continue to do so. We may, as a component of our overall business strategy, increase or decrease from time to time our use of such derivative financial instruments in the future. Our use of such derivative financial instruments could cause us to forego the economic benefits we would otherwise realize if commodity prices or interest rates were to change in our favor. In addition, although we monitor such activities in our risk management processes and procedures, such activities could result in losses, which could adversely affect our results of operations and impair our ability to make payments on our debt obligations.

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. As of March 31, 2014, 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.

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Competition from alternative energy sources may cause us to lose customers, thereby negatively impacting our financial condition and results of operations.

Propane competes with other sources of energy, some of which are less costly for equivalent energy value. We compete for customers against suppliers of electricity, natural gas and fuel oil. Competition from alternative energy sources, including electricity and natural gas, has increased as a result of reduced regulation of many utilities. Electricity is a major competitor of propane, but propane has historically enjoyed a competitive price advantage over electricity. Except for some industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because such pipelines generally make it possible for the delivered cost of natural gas to be less expensive than the bulk delivery of propane. The expansion of natural gas into traditional propane markets has historically been inhibited by the capital cost required to expand distribution and pipeline systems; however, the gradual expansion of the nation's natural gas distribution systems has resulted in natural gas being available in areas that previously depended on propane, which could cause us to lose customers, thereby reducing our revenues. Although propane is similar to fuel oil in some applications and market demand, propane and fuel oil compete to a lesser extent primarily because of the cost of converting from one to the other and due to the fact that both fuel oil and propane have generally developed their own distinct geographic markets.

We cannot predict the effect that development of alternative energy sources may have on our operations, including whether subsidies of alternative energy sources by local, state, and federal governments might be expanded, or what impact this might have on the supply of or the demand for crude oil, natural gas, and natural gas liquids.

Energy efficiency and new technology may reduce the demand for propane and adversely affect our operating results.

The national trend toward increased conservation and technological advances, such as installation of improved insulation and the development of more efficient furnaces and other heating devices, has adversely affected the demand for propane by retail customers. Future conservation measures or technological advances in heating, conservation, energy generation or other devices may reduce demand for propane. In addition, if the price of propane increases, some of our customers may increase their conservation efforts and thereby decrease their consumption of propane.

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.

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

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

•: 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 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.

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

Certain of our operations are conducted through joint ventures. With respect to our joint ventures, we share ownership and management responsibilities with partners that may not share our goals and objectives. Differences in views among the partners may result in delayed decisions or failures to agree on major matters, such as large expenditures or contractual commitments, the construction or acquisition of assets or borrowing money, among others. Delay or failure to agree may prevent action with respect to such matters, even though such action may serve our best interest or that of the joint venture. Accordingly, delayed decisions and disagreements could adversely affect the business and operations of the joint ventures and, in turn, our business and operations. From time to time, our joint ventures may be involved in disputes or legal proceedings which may negatively affect our investments. Accordingly, any such occurrences could adversely affect our 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.

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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 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.

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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 and September 30, 2014, we had reported goodwill and intangible assets of approximately $1.8 billion and $2.0 billion, respectively. Such assets are subject to impairment reviews on an annual basis, or at an interim date if information indicates that such asset values have been impaired. Any impairment we would be required to record in our financial statements would result in a charge to our income, which would reduce our earnings.

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

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

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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

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operations could negatively impact our ability to transport propane to our locations. These risks could potentially negatively impact our results of operations.

We depend on the leadership and involvement of key personnel for the success of our businesses.

We have certain key individuals in our senior management who we believe are critical to the success of our business. The loss of leadership and involvement of those key management personnel could potentially have a material adverse impact on our business and possibly on the market value of our units.

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 service our debt obligations, including the notes.

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EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

We sold the old notes on October 16, 2013 pursuant to the purchase agreement, dated as of October 10, 2013, by and among us, our subsidiary guarantors and the initial purchasers named therein. The old notes were subsequently offered by the initial purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to non-U.S. persons pursuant to Regulation S under the Securities Act.

We sold the old notes in transactions that were exempt from or not subject to the registration requirements under the Securities Act. Accordingly, the old notes are subject to transfer restrictions. In general, you may not offer or sell the old notes unless either they are registered under the Securities Act or the offer or sale is exempt from, or not subject to, registration under the Securities Act and applicable state securities laws.

In connection with the sale of the old notes, we entered into a registration rights agreement with the initial purchasers of the old notes. In that agreement, we agreed to use our commercially reasonable efforts to file an exchange offer registration statement after the closing date following the offering of the old notes. Now, to satisfy our obligations under the registration rights agreement, we are offering holders of the old notes who are able to make certain representations described below the opportunity to exchange their old notes for the new notes in the exchange offer. The exchange offer will be open for a period of at least 20 business days. During the exchange offer period, we will exchange the new notes for all old notes properly surrendered and not withdrawn before the expiration date. The new notes will be registered under the Securities Act, and the transfer restrictions, registration rights and provisions for additional interest relating to the old notes will not apply to the new notes.

For each old note surrendered to us pursuant to the exchange offer, the holder of such old note will receive a new note having a principal amount equal to that of the surrendered old note. Interest on each new note will accrue from the last interest payment date on which interest was paid on the surrendered old note. The registration rights agreement also provides an agreement to include in the prospectus for the exchange offer certain information necessary to allow a broker-dealer who holds old notes that were acquired for its own account as a result of market-making activities or other ordinary course trading activities (other than old notes acquired directly from us or one of our affiliates) to exchange such old notes pursuant to the exchange offer and to satisfy the prospectus delivery requirements in connection with resales of new notes received by such broker-dealer in the exchange offer. We agreed to use commercially reasonable efforts to maintain the effectiveness of the exchange offer registration statement for these purposes for a period ending on the earlier of 180 days from the date on which the exchange offer registration statement is declared effective and the date on which the broker-dealer is no longer required to deliver a prospectus in connection with market-making or other trading activities.

The preceding agreement is needed because any broker-dealer who acquires old notes for its own account as a result of market-making activities or other trading activities is required to deliver a prospectus meeting the requirements of the Securities Act. This prospectus covers the offer and sale of the new notes pursuant to the exchange offer and the resale of new notes received in the exchange offer by any broker-dealer who held old notes acquired for its own account as a result of market-making activities or other trading activities, other than old notes acquired directly from us or one of our affiliates.

Based on interpretations by the staff of the SEC set forth in no-action letters issued to third parties, we believe that the new notes issued pursuant to the exchange offer would in general be freely tradable after the exchange offer without further registration under the Securities Act. However, any

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purchaser of old notes who is an "affiliate" of ours or who intends to participate in the exchange offer for the purpose of distributing the related new notes:

•: will not be able to rely on the interpretation of the staff of the SEC,
•: will not be able to tender its old notes in the exchange offer, and
•: must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the old notes unless such sale or transfer is made pursuant to an exemption from such requirements.

Each holder of the old notes (other than certain specified holders) who desires to exchange old notes for the new notes in the exchange offer will be required to make the representations described below under "—Procedures for Tendering—Your Representations to Us."

We further agreed to file with the SEC a shelf registration statement to register for public resale old notes held by any holder who provides us with certain information for inclusion in the shelf registration statement if:

•

the exchange offer is not permitted by applicable law or SEC policy;

•

for any reason the exchange offer is not consummated within 30 business days after October 16, 2014; or

•

prior to the 20th business day following the consummation of this offering, any holder notifies us that:

•: the holder is prohibited by applicable law or SEC policy from participating in the exchange offer;
•: the holder may not resell the new notes acquired in the exchange offer to the public without delivering a prospectus, and the prospectus contained in the exchange offer is not appropriate or available for such resales by such purchaser; or
•: the holder is a broker-dealer and holds old notes acquired directly from us or one of our affiliates that are not freely tradeable, and such holder cannot participate in the exchange offer.

We have agreed to use commercially reasonable efforts to file the shelf registration with the SEC on or before the 30 days after the occurrence of the events described in the first three bullets above, which date we refer to as the "shelf filing deadline," and to use commercially reasonable efforts to cause the shelf registration statement to be declared effective on or before 90 days after the shelf filing deadline. We have also agreed to use commercially reasonable efforts to keep the shelf registration statement continuously effective from the date on which the shelf registration statement is declared effective by the SEC until the earlier of the first anniversary of the effective date of such shelf registration statement and such time as all notes covered by the shelf registration statement have been sold or are freely tradeable. We refer to this period as the "shelf effectiveness period."

If:

(1): the Issuers and the subsidiary guarantors become obligated under the registration rights agreement to file a shelf registration statement and fail to do so on or before the shelf filing deadline;
(2): any registration statement required by the registration rights agreement is not declared effective by the SEC on or prior to the date specified for such effectiveness (the "Effectiveness Target Date");

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(3): the Issuers and the subsidiary guarantors fail to consummate the exchange offer within 30 business days of the Effectiveness Target Date with respect to the exchange offer registration statement; or
(4): the shelf registration statement or the exchange offer registration statement is declared effective by the SEC but thereafter ceases to be effective or usable for its intended purpose (with such event referred to in clauses (1) through (4) above, a "Registration Default");

then the Issuers and the subsidiary guarantors will pay liquidated damages to each holder of notes, with respect to the first 90-day period immediately following the occurrence of the first Registration Default in an amount equal to one quarter of one percent (0.25%) per annum on the principal amount of notes held by such holder. The amount of the liquidated damages will increase by an additional one-quarter of one percent (0.25%) per annum on the principal amount of notes with respect to each subsequent 90-day period until all Registration Defaults have been cured, up to a maximum amount of liquidated damages for all Registration Defaults of one-half of one percent (0.50%) per annum. All accrued liquidated damages will be paid by the Issuers (or the subsidiary guarantors, if applicable) in the manner provided for with respect to the payment of interest in the Indenture as more fully set forth in the Indenture and the notes. Following the cure of all Registration Defaults, the accrual of liquidated damages will cease.

Holders of the old notes will be required to make certain representations to us (as described below under "—Procedures for Tendering") in order to participate in the exchange offer and will be required to deliver information to be used in connection with the shelf registration statement and to provide comments on the shelf registration statement within the time periods set forth in the registration rights agreement in order to have their old notes included in the shelf registration statement.

If we effect the registered exchange offer, we will be entitled to close the registered exchange offer 20 business days after its commencement as long as we have accepted all old notes validly tendered in accordance with the terms of the exchange offer and no brokers or dealers continue to hold any old notes.

This summary of the material provisions of the registration rights agreement does not purport to be complete and is subject to, and is qualified in its entirety by reference to, all the provisions of the registration rights agreement, a copy of which is filed as an exhibit to the registration statement that includes this prospectus.

Except as set forth above, after consummation of the exchange offer, holders of old notes that are the subject of the exchange offer will have no registration or exchange rights under the registration rights agreement. See "—Consequences of Failure to Exchange."

Terms of the Exchange Offer

Subject to the terms and conditions described in this prospectus and in the letter of transmittal, we will accept for exchange any old notes properly tendered and not withdrawn prior to 5:00 p.m., New York City time, on the expiration date. We will issue new notes in a principal amount equal to the principal amount of old notes surrendered in the exchange offer. Old notes may be tendered only for new notes and only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof.

The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

As of the date of this prospectus, $450.0 million in aggregate principal amount of the old notes is outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of old

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notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

We intend to conduct the exchange offer in accordance with the provisions of the registration rights agreement, the applicable requirements of the Securities Act and the Securities Exchange Act of 1934, as amended (the "Exchange Act") and the rules and regulations of the Securities and Exchange Commission. Old notes that the holders thereof do not tender for exchange in the exchange offer will remain outstanding and continue to accrue interest. These old notes will continue to be entitled to the rights and benefits such holders have under the indenture relating to the notes and the registration rights agreement.

We will be deemed to have accepted for exchange properly tendered old notes when we have given oral or written notice of the acceptance to the exchange agent and complied with the applicable provisions of the registration rights agreement. The exchange agent will act as agent for the tendering holders for the purposes of receiving the new notes from us.

Expiration Date

The exchange offer will expire at 5:00 p.m., New York City time, on , 2015, unless, in our sole discretion, we extend it.

Extensions, Delays in Acceptance, Termination or Amendment

We expressly reserve the right, at any time or various times, to extend the period of time during which the exchange offer is open. We may delay acceptance of any old notes by giving oral or written notice of such extension to their holders at any time until the exchange offer expires or terminates. During any such extensions, all old notes previously tendered will remain subject to the exchange offer, and we may accept them for exchange.

In order to extend the exchange offer, we will notify the exchange agent orally or in writing of any extension. We will notify the registered holders of old notes of the extension by a press release issued no later than 9:00 a.m., New York City time, on the business day after the previously scheduled expiration date.

Any such notice relating to the extension of the exchange offer will disclose the number of securities tendered as of the date of the notice, as required by Rule 14e-1(d) under the Exchange Act.

We expressly reserve the right at our sole discretion:

•: to delay accepting the old notes, provided that any such delay is done in a manner consistent with Rule 14e-1(c) of the Exchange Act;
•: to extend the exchange offer;
•: to terminate the exchange offer and not accept old notes not previously accepted if any of the conditions listed under "—Conditions to the Exchange Offer" are not satisfied or waived by us, by giving oral or written notice of such delay, extension or termination to the exchange agent; or
•: to amend the terms of the exchange offer in any manner.

Following the commencement of the exchange offer, we currently anticipate that we would only delay accepting old notes tendered in the exchange offer due to an extension of the expiration date.

We will follow any delay in acceptance, extension or termination as promptly as practicable by oral or written notice to the exchange agent.

Any such delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice thereof to the registered holders of old notes. If we amend the

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exchange offer in a manner that we determine to constitute a material change, we will promptly disclose such amendment by means of a prospectus supplement. The prospectus supplement will be distributed to the registered holders of the old notes. Depending upon the significance of the amendment and the manner of disclosure to the registered holders, we may extend the exchange offer. In the event of a material change in the exchange offer, including the waiver by us of a material condition, we will extend the exchange offer period, if necessary, so that at least five business days remain in the exchange offer period following notice of the material change.

If we delay accepting any old notes or terminate the exchange offer, we will promptly return any old notes deposited pursuant to the exchange offer as required by Rule 14e-1(c).

Conditions to the Exchange Offer

We will not be required to accept for exchange, or exchange any new notes for, any old notes if the exchange offer, or the making of any exchange by a holder of old notes, would violate applicable law or any applicable interpretation of the staff of the SEC. Similarly, we may terminate the exchange offer as provided in this prospectus before accepting old notes for exchange in the event of such a potential violation.

In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under "—Purpose and Effect of the Exchange Offer," "—Procedures for Tendering" and "Plan of Distribution" and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the issuance of the new notes under the Securities Act.

We expressly reserve the right to amend or terminate the exchange offer, and to reject for exchange any old notes not previously accepted for exchange, upon the occurrence of any of the conditions to the exchange offer specified above. We will give prompt oral or written notice of any extension, amendment, non-acceptance or termination to the holders of the old notes as promptly as practicable.

These conditions are for our sole benefit, and we may assert them or waive them in whole or in part at any time or at various times in our sole discretion prior to the expiration of the exchange offer. If we fail at any time to exercise any of these rights, this failure will not mean that we have waived our rights. Each such right will be deemed an ongoing right that we may assert at any time or at various times prior to the expiration of the exchange offer.

In addition, we will not accept for exchange any old notes tendered, and will not issue new notes in exchange for any such old notes, if at such time any stop order has been threatened or is in effect with respect to the registration statement of which this prospectus constitutes a part or the qualification of the indenture relating to the notes under the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act").

Procedures for Tendering

In order to participate in the exchange offer, you must properly tender your old notes to the exchange agent as described below. We will only issue new notes in exchange for old notes that you timely and properly tender. Therefore, you should allow sufficient time to ensure timely delivery of the old notes, and you should follow carefully the instructions on how to tender your old notes. It is your responsibility to properly tender your notes. We have the right to waive any defects. However, we are not required to waive defects and are not required to notify you of defects in your tender.

If you have any questions or need help in exchanging your notes, please call the exchange agent, whose address and phone number are set forth in "Prospectus Summary—The Exchange Offer—Exchange Agent."

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All of the old notes were issued in book-entry form, and all of the old notes are currently represented by global certificates held for the account of DTC. We have confirmed with DTC that the old notes may be tendered using the Automated Tender Offer Program, or ATOP, instituted by DTC. The exchange agent will establish an account with DTC for purposes of the exchange offer promptly after the commencement of the exchange offer, and DTC participants may electronically transmit their acceptance of the exchange offer by causing DTC to transfer their old notes to the exchange agent using the ATOP procedures. In connection with the transfer, DTC will send an "agent's message" to the exchange agent. The agent's message will state that DTC has received instructions from the participant to tender old notes and that the participant agrees to be bound by the terms of the letter of transmittal.

By using the ATOP procedures to exchange old notes, you will not be required to deliver a letter of transmittal to the exchange agent. However, you will be bound by its terms just as if you had signed it.

There is no procedure for guaranteed late delivery of the notes.

Determinations Under the Exchange Offer

We will determine, in our sole discretion, all questions as to the validity, form, eligibility, time of receipt, acceptance of tendered old notes and withdrawal of tendered old notes. Our determination will be final and binding. We reserve the absolute right to reject any old notes not properly tendered or any old notes our acceptance of which would, in the opinion of our counsel, be unlawful. We also reserve the right to waive any defects, irregularities or conditions of tender as to particular old notes. Our interpretation of the terms and conditions of the exchange offer, including the instructions in the letter of transmittal, will be final and binding on all parties. Unless waived, all defects or irregularities in connection with tenders of old notes must be cured within such time as we shall determine. Although we intend to notify holders of defects or irregularities with respect to tenders of old notes, neither we, the exchange agent nor any other person will incur any liability for failure to give such notification. Tenders of old notes will not be deemed made until such defects or irregularities have been cured or waived. Any old notes received by the exchange agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned to the tendering holder, unless otherwise provided in the letter of transmittal, promptly following the expiration date of the exchange.

When We Will Issue New Notes

In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

•: a book-entry confirmation of such old notes into the exchange agent's account at DTC; and
•: a properly transmitted agent's message.

Return of Old Notes Not Accepted or Exchanged

If we do not accept any tendered old notes for exchange or if old notes are submitted for a greater principal amount than the holder desires to exchange, the unaccepted or non-exchanged old notes will be returned without expense to their tendering holder. Such non-exchanged old notes will be credited to an account maintained with DTC. These actions will occur promptly after the expiration or termination of the exchange offer.

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Your Representations to Us

By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

•: any new notes that you receive will be acquired in the ordinary course of your business;
•: you have no arrangement or understanding with any person or entity to participate in the distribution of the new notes;
•: you are not our "affiliate," as defined in Rule 405 of the Securities Act;
•: if you are a broker-dealer that will receive new notes for your own account in exchange for old notes, you acquired those notes as a result of market-making activities or other trading activities and you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes; and
•: if you are a broker-dealer that participates in the exchange offer with respect to old notes acquired for your own account as a result of market-making activities or other trading activities, you have not entered into any arrangement or understanding with us or any of our "affiliates" to distribute the new notes.

Withdrawal of Tenders

Except as otherwise provided in this prospectus, you may withdraw your tender at any time prior to 5:00 p.m., New York City time, on the expiration date. For a withdrawal to be effective, you must comply with the appropriate procedures of DTC's ATOP system. Any notice of withdrawal must specify the name and number of the account at DTC to be credited with withdrawn old notes and otherwise comply with the procedures of DTC.

We will determine all questions as to the validity, form, eligibility and time of receipt of notice of withdrawal. Our determination shall be final and binding on all parties. We will deem any old notes so withdrawn not to have been validly tendered for exchange for purposes of the exchange offer.

Any old notes that have been tendered for exchange but are not exchanged for any reason will be credited to an account maintained with DTC for the old notes. This crediting will take place promptly after withdrawal, rejection of tender or termination of the exchange offer. You may retender properly withdrawn old notes by following the procedures described under "—Procedures for Tendering" above at any time prior to 5:00 p.m., New York City time, on the expiration date of the exchange offer.

Fees and Expenses

We will bear the expenses of soliciting tenders. The principal solicitation is being made by electronic mail; however, we may make additional solicitation by facsimile, telephone, mail or in person by our officers and regular employees and those of our affiliates.

We have not retained any dealer-manager in connection with the exchange offer and will not make any payments to broker-dealers or others soliciting acceptances of the exchange offer. We will, however, pay the exchange agent reasonable and customary fees for its services and reimburse it for its related reasonable out-of-pocket expenses.

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

•: all registration and filing fees and expenses;
•: all fees and expenses of compliance with federal securities and state "blue sky" or securities laws;

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•: accounting and legal fees, disbursements and printing, messenger and delivery services, and telephone costs; and
•: related fees and expenses.

Transfer Taxes

We will pay all transfer taxes, if any, applicable to the exchange of old notes under the exchange offer. The tendering holder, however, will be required to pay any transfer taxes, whether imposed on the registered holder or any other person, if a transfer tax is imposed for any reason other than the exchange of old notes under the exchange offer.

Consequences of Failure to Exchange

If you do not exchange new notes for your old notes under the exchange offer you will remain subject to the existing restrictions on transfer of the old notes. In general, you may not offer or sell the old notes unless the offer or sale is either registered under the Securities Act or exempt from registration under the Securities Act and applicable state securities laws. Except as required by the registration rights agreement, we do not intend to register resales of the old notes under the Securities Act.

Accounting Treatment

We will record the new notes in our accounting records at the same carrying value as the old notes. This carrying value is the aggregate principal amount of the old notes less any bond discount, as reflected in our accounting records on the date of exchange. Accordingly, we will not recognize any gain or loss for accounting purposes in connection with the exchange offer.

Other

Participation in the exchange offer is voluntary and you should carefully consider whether to accept. You are urged to consult your financial and tax advisors in making your own decision on what action to take.

We may in the future seek to acquire untendered old notes in open market or privately-negotiated transactions, through subsequent exchange offers or otherwise. We have no present plans to acquire any old notes that are not tendered in the exchange offer or to file a registration statement to permit resales of any untendered old notes.

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RATIO OF EARNINGS TO FIXED CHARGES

	NGL Energy Partners LP										NGL Supply, Inc.

	Six Months Ended September 30, 2014		Year Ended March 31, 2014		Year Ended March 31, 2013		Year Ended March 31, 2012		Six Months Ended March 31, 2011		Six Months Ended September 30, 2010		Year Ended March 31, 2010
Ratio of earnings to fixed charges		(a)		1.53x		1.75x		1.91x		5.59x		(b)		6.32x

(a): Due to NGL Energy Partners LP's loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2014. NGL Energy Partners LP would have needed to generate an additional $60.1 million of earnings to achieve a ratio of 1:1.
(b): Due to NGL Supply, Inc.'s loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2010. NGL Supply, Inc. would have needed to generate an additional $3.9 million of earnings to achieve a ratio of 1:1.

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USE OF PROCEEDS

The exchange offer is intended to satisfy our obligations under the registration rights agreement. We will not receive any proceeds from the issuance of the new notes in the exchange offer. In consideration for issuing the new notes as contemplated by this prospectus, we will receive old notes in a like principal amount. The form and terms of the new notes are identical in all respects to the form and terms of the old notes, except the new notes will be registered under the Securities Act and will not contain restrictions on transfer, registration rights or provisions for additional interest. Old notes surrendered in exchange for the new notes will be retired and cancelled and will not be reissued. Accordingly, the issuance of the new notes will not result in any change in outstanding indebtedness.

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SELECTED CONSOLIDATED HISTORICAL FINANCIAL AND OPERATING 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 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 "Management's Discussion and Analysis of Financial Condition and Results of Operations" and the financial statements and related notes of NGL Energy Partners LP included elsewhere in this prospectus.

The selected consolidated historical financial data (excluding volume information) at September 30, 2014 and for the six months ended September 30, 2014 are derived from our unaudited historical consolidated financial statements included elsewhere in this prospectus. 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 elsewhere in this prospectus. 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.

				NGL Energy Partners LP								NGL Supply, Inc.

	Six Months Ended September 30, 2014			Year Ended March 31,						Six Months Ended March 31, 2011		Six Months Ended September 30, 2010
				Year Ended March 31,											Year Ended March 31, 2010
				2014		2013		2012							Year Ended March 31, 2010
				(in thousands, except per unit data)
Income Statement Data(1)
Total revenues	$	9,029,140		$	9,699,274	$	4,417,767	$	1,310,473	$	622,232	$	316,943		$	735,506
Total cost of sales		8,713,518			9,132,699		4,039,110		1,217,023		583,032		310,908			708,215
Operating income (loss)		(12,785	)		106,565		87,307		15,030		14,837		(3,795	)		6,661
Interest expense		(49,145	)		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		(59,199	)		47,655		47,940		7,876		12,679		(2,515	)		3,636
Basic and diluted earnings (loss) per common unit		(0.93	)		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	$	(61,635	)	$	85,236	$	132,634	$	90,329	$	34,009	$	(30,749	)	$	7,480
Cash distributions paid per common unit (subsequent to IPO)		1.14			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		82,851			165,148		72,475		7,544		1,440		280			582
Acquisitions of businesses, including additional consideration paid on prior period acquisitions		658,764			1,268,810		490,805		297,401		17,400		123			3,113
Balance Sheet Data—Period End(1)
Total assets	$	6,551,679		$	4,167,223	$	2,291,618	$	749,519	$	163,833	$	148,596		$	111,580
Total long-term obligations, exclusive of current maturities		2,437,351			1,639,578		742,641		199,389		65,936		18,940			8,851
Redeemable preferred stock		—			—		—		—		—		—			3,000
Total equity		2,314,830			1,531,853		889,418		405,329		47,353		36,811			46,403
Volume Information(1)
Retail propane and distillates sold (gallons)		55,854			197,326		173,232		79,886		34,932		3,747			15,514
Wholesale propane sold (gallons)(2)		423,992			1,190,106		912,625		659,921		372,504		226,330			623,510
Wholesale other products sold (gallons)		384,235			786,671		505,529		134,999		49,465		46,092			53,878
Crude oil sold (barrels)		40,806			46,107		24,373		—		—		—			—
Water delivered (barrels)		51,804			62,774		25,009		—		—		—			—
Refined products sold (gallons)		1,221,949			412,974		—		—		—		—			—

(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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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 audited consolidated financial statements included elsewhere in this prospectus.

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.

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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.
•: 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.

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•: 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

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

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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.
•: 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.

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•: 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:

Location		Storage Capacity (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

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

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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
•: 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

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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.

Location		Processing Capacity (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 producers to be re-used in future drilling

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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.

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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.

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.

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

Facility		Throughput Capacity (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

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.

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

	Leased Storage Space (in gallons)

Storage Facility	Beginning April 1, 2014		At March 31, 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).

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;

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•: 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;
•: 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.

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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.

The following table shows the number of our customer service locations and satellite distribution locations by state:

State

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

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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.

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.

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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.

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;

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•: 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
•: 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.

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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.

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

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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 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.

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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 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

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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.

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.

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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.

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

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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

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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.

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

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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.

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 included elsewhere in this prospectus, which information is incorporated herein.

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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 prospectus.

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

Overview

We are a Delaware limited partnership formed in September 2010. NGL Energy Holdings LLC serves as our general partner. As part of our formation, we acquired and combined the assets and operations of NGL Supply, which was primarily a wholesale propane and terminaling business that was founded in 1967, and Hicksgas, which was primarily a retail propane business that was founded in 1940. We completed an IPO in May 2011. At the time of our IPO, we owned and operated retail propane and wholesale natural gas liquids businesses. Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, as described under "Business—Acquisitions Subsequent to Initial Public Offering."

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.

At September 30, 2014, our operations include:

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

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•: Our water solutions segment, the assets of which include water treatment and disposal facilities. Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, and from the sale of recycled water and recovered hydrocarbons.
•: Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 22 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, petrochemical plants, and other participants in the wholesale markets.
•: Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.
•: Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.7% limited partner interest in TransMontaigne Partners L.P. ("TLP"), which conducts refined products terminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC ("BOSTCO") and a 50% interest in Frontera Brownsville LLC, which are entities that own refined products storage facilities.

Crude Oil Logistics

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. We attempt to reduce our exposure to price fluctuations by using back-to-back contracts whenever possible. In addition, we enter into forward contracts, financial swaps, and commodity spread trades as economic hedges of our physical forward sales and purchase contracts with our customers and suppliers.

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 utilize our transportation assets to move crude oil from the wellhead to the highest value market. The spread between crude oil prices in different markets can fluctuate widely, which may expand or limit our opportunity to generate margins by transporting crude oil to different markets. We also seek to maximize margins by blending crude oil of varying properties.

The range of low and high spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma and the prices at March 31, 2014 were as follows:

	Spot Price Per Barrel

Year Ended:	Low		High		At Period End
March 31, 2014	$	86.68	$	110.53	$	101.58
March 31, 2013		77.69		106.16		97.23

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The range of low and high spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma and the prices at September 30, 2014 were as follows:

	Spot Price Per Barrel

	Low		High		At Period End
Three Months Ended September 30,
2014	$	91.16	$	105.34	$	91.16
2013		97.99		110.53		102.33
Six Months Ended September 30,
2014	$	91.16	$	107.26	$	91.16
2013		86.68		110.53		102.33

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

Water Solutions

Our water solutions business generates revenues from the gathering, transportation, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recycled water and recovered hydrocarbons. Our water processing facilities are strategically located near areas of high crude oil and natural gas production. A significant factor affecting the profitability of our water solutions segment is the extent of exploration and production in the areas near our facilities, which is based upon producers' expectations about the profitability of drilling new wells. The primary customers of our facility in Wyoming have committed to deliver a specified minimum volume of water to our facility under long-term contracts. The primary customers of our facilities in Colorado have committed to deliver to our facilities all wastewater produced at wells in a designated area. Most of the customers at our other facilities in Texas are not under volume commitments, other than one customer that has committed to deliver 50,000 barrels per day to our facilities.

Liquids

Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, petrochemical plants, and other participants in the wholesale markets. Our liquids segment owns 22 terminals and operates a fleet of owned and leased railcars and leases underground storage capacity. We attempt to reduce our exposure to the impact of price fluctuations by using back-to-back contracts and pre-sale agreements that allow us to lock in a margin on a percentage of our winter volumes. We also attempt to reduce our exposure to the impact of price fluctuations by entering into swap agreements whereby we agree to pay a floating rate and receive a fixed rate on a specified notional amount of product. We enter into these agreements as economic hedges against the potential decline in the value of a portion of our inventory.

Our wholesale business is a "cost-plus" business that is affected both by price fluctuations and volume variations. We establish our selling price based on a pass-through of our product supply, transportation, handling, storage and capital costs plus an acceptable margin. The margins we realize in our wholesale business are substantially less on a per gallon basis than our retail propane business.

Weather conditions and gasoline blending have a significant impact on the demand for propane and butane, and sales volumes and prices are typically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

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The range of low and high spot propane prices per gallon at Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, and the prices at March 31, 2014 were as follows:

	Conway, Kansas						Mt. Belvieu, Texas

	Spot Price Per Gallon						Spot Price Per Gallon
	Spot Price Per Gallon				Spot Price Per Gallon At Period End		Spot Price Per Gallon				Spot Price Per Gallon At Period End
Year Ended:	Low		High		Spot Price Per Gallon At Period End		Low		High		Spot Price Per Gallon At Period End
March 31, 2014	$	0.77	$	4.33	$	1.03	$	0.81	$	1.73	$	1.06
March 31, 2013		0.50		0.96		0.90		0.71		1.22		0.96
March 31, 2012		0.90		1.49		0.98		1.17		1.63		1.24

The range of low and high spot butane prices per gallon at Mt. Belvieu, Texas and the prices at March 31, 2014 were as follows:

	Spot Price Per Gallon

Year Ended:	Low		High		At Period End
March 31, 2014	$	1.08	$	1.64	$	1.26
March 31, 2013		1.14		1.93		1.45

The range of low and high spot propane prices per gallon at Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, and the prices at period end were as follows:

	Conway, Kansas						Mt. Belvieu, Texas

	Spot Price Per Gallon						Spot Price Per Gallon
	Low		High		At Period End		Low		High		At Period End
Three Months Ended September 30,
2014	$	1.00	$	1.10	$	1.03	$	0.99	$	1.11	$	1.04
2013		0.81		1.16		1.01		0.86		1.19		1.05
Six Months Ended September 30,
2014	$	0.96	$	1.13	$	1.03	$	0.99	$	1.13	$	1.04
2013		0.77		1.16		1.01		0.81		1.19		1.05

The range of low and high spot butane prices per gallon at Mt. Belvieu, Texas and the prices at period end were as follows:

	Spot Price Per Gallon

	Low		High		At Period End
Three Months Ended September 30,
2014	$	1.21	$	1.30	$	1.22
2013		1.19		1.44		1.38
Six Months Ended September 30,
2014	$	1.20	$	1.30	$	1.22
2013		1.08		1.44		1.38

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

Retail Propane

Our retail propane segment sells propane, distillates, and equipment and supplies to residential, agricultural, commercial, and industrial end users. Our retail propane segment purchases the majority of its propane from our liquids segment. Our retail propane segment generates margins based on the difference between the wholesale cost of product and the selling price of the product in the retail markets. These margins fluctuate over time due to supply and demand conditions. Weather conditions

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have a significant impact on our sales volumes and prices, as a significant portion of our sales are to residential customers who purchase propane and distillates for home heating purposes.

A significant factor affecting the profitability of our retail propane segment is our ability to maintain our realized product margin on a cents per gallon basis. Product margin is the differential between our sales prices and our total product costs, including transportation and storage. Historically, we have been successful in passing on price increases to our customers. We monitor propane prices daily and adjust our retail prices to maintain expected margins by passing on the wholesale costs to our customers. We believe that volatility in commodity prices will continue, and our ability to adjust to and manage this volatility may impact our financial results.

In periods of significant propane price increases we have experienced, and expect to continue to experience, conservation of propane used by our customers that could result in a decline in our sales volumes, revenues and gross margins. In periods of decreasing propane costs, we have experienced an increase in our product margin. The retail propane business is weather-sensitive and subject to seasonal volume variations due to propane's primary use as a heating source in residential and commercial buildings and for agricultural purposes. Typically, over 70% of our retail volume is sold during the peak heating season from October through March. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

Refined Products

Our refined products marketing business purchases gasoline and diesel fuel primarily from eight suppliers, and sells to over 300 customers. We purchase and sell these products at a nationwide network of third-party owned terminaling and storage facilities. We typically sell the product at the same time it is purchased in back-to-back transactions.

Renewables

Our ethanol marketing business purchases ethanol primarily at production facilities, and transports the ethanol for sale at various locations to refiners and blenders. We also transport and market third-party owned ethanol for a service fee.

Our biodiesel marketing business purchases biodiesel from production facilities in the Midwest and in Houston, Texas, and transports the product on leased railcars for sale to refiners and blenders. We lease biodiesel storage at facilities in Phoenix, Arizona and Deer Park, Texas.

Recent Developments

Acquisitions of businesses have had a significant impact on the comparability of our results of operations from fiscal 2012 through 2014. These transactions are described under "Business—Acquisitions Subsequent to Initial Public Offering."

Development of Crude Oil Rail Transloading Facility

On October 2, 2014, we announced plans to build a crude oil rail transloading facility, backed by executed producer commitments, capable of handling unit trains west of Albuquerque, New Mexico in the San Juan Basin. We expect the terminal to be completed in the third quarter of calendar year 2015 and, we expect the terminal to have multiple inbound truck unloading bays, an initial outbound capacity of at least two unit trains per week, and over 240,000 barrels of storage.

Grand Mesa Pipeline, LLC

On September 5, 2014, we formed the Grand Mesa Pipeline, LLC ("Grand Mesa") joint venture in which we have a 50% ownership interest. Grand Mesa expects to build a crude oil pipeline with

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initial capacity exceeding 130,000 barrels per day, originating in Weld County, Colorado, and terminating at our crude oil storage terminal in Cushing, Oklahoma.

TransMontaigne Inc.

On July 1, 2014, we acquired TransMontaigne Inc. ("TransMontaigne") for $174.2 million of cash, net of cash acquired. As part of this transaction, we also purchased $380.4 million of inventory from the previous owner of TransMontaigne (including $346.9 million paid at closing and $33.5 million subsequently paid as the working capital settlement process progressed). The operations of TransMontaigne include the marketing of refined products and crude oil. As part of this transaction, we acquired the 2.0% general partner interest, the incentive distribution rights, and a 19.7% limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne. The acquisition agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. We estimate that we will pay an additional $27.5 million once the working capital settlement process has been completed.

On July 10, 2014, we submitted a nonbinding proposal to the conflicts committee of the board of directors of TLP's general partner. Under this proposal, each outstanding unit of TLP would be exchanged for one of our common units. On August 15, 2014, we and TLP's general partner terminated discussions regarding our previously submitted nonbinding proposal to acquire the outstanding common units of TLP.

Water Solutions Facilities

As described below, we are party to a development agreement that provides us a right to purchase water disposal facilities developed by the other party to the agreement. During the six months ended September 30, 2014, we purchased four water disposal facilities under this development agreement. We also purchased a 75% interest in one additional water disposal facility in July 2014 from a different seller. On a combined basis, we paid $82.9 million of cash for these five water disposal facilities.

During October and November 2014, we purchased five facilities under this development agreement and paid $52.2 million of cash for these facilities.

Water Supply Company

In June 2014, we acquired an interest in a water supply company that expands our water solutions business in the DJ Basin.

Summary Discussion of Operating Results for the Three Months Ended September 30, 2014

During the three months ended September 30, 2014, we generated operating income of $7.8 million, compared to operating income of $9.9 million during the three months endedSeptember 30, 2013.

Our crude oil logistics segment generated operating income of less than $0.1 million during the three months ended September 30, 2014, compared to operating income of $5.9 million during the three months ended September 30, 2013. Spreads between the price of crude oil in different markets narrowed during the three months ended September 30, 2013 and remained narrow, which reduced our opportunity to generate increased margins by transporting crude oil from lower-price markets to higher-price markets. In addition, prices declined steadily during the three months ended September 30, 2014, which adversely impacted our margins.

Our water solutions segment generated operating income of $14.8 million during the three months ended September 30, 2014, compared to operating income of $2.9 million during the three months ended September 30, 2013. This increase was due in part to an increase in the volume of wastewater

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processed, which was due to increased demand for existing facilities and to the development and acquisition of new facilities.

Our liquids segment generated operating income of $10.9 million during the three months ended September 30, 2014, compared to operating income of $14.6 million during the three months ended September 30, 2013. Although sales volumes were higher during the three months ended September 30, 2014 than during the three months ended September 30, 2013, product margins were similar. This was due in part to the impact of unrealized gains on derivatives, which reduced cost of sales by $0.3 million during the three months ended September 30, 2014 and by $3.3 million during the three months ended September 30, 2013. Operating and general and administrative expenses were higher during the three months ended September 30, 2014 than during the three months ended September 30, 2013, due to expanded operations. Due to the seasonal nature of demand for natural gas liquids, sales volumes of our liquids segment are typically lower during the first and second quarters of the fiscal year than during the third and fourth quarters of the fiscal year.

Our retail propane segment generated an operating loss of $3.1 million during the three months ended September 30, 2014, compared to an operating loss of $4.5 million during the three months ended September 30, 2013. Sales volumes increased due to high demand as a result of cold weather conditions during the previous winter. Due to the seasonal nature of demand for propane, sales volumes of our retail propane business typically are lower during the first and second quarters of the fiscal year than during the third and fourth quarters of the fiscal year.

Our refined products and renewables segment generated operating income of $8.8 million during the three months ended September 30, 2014. Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.

We recorded $3.7 million of earnings from our equity method investments during the three months ended September 30, 2014. Most of our equity method investments were acquired in our December 2013 acquisition of Gavilon Energy and our July 2014 acquisition of TransMontaigne.

We incurred interest expense of $28.7 million during the three months ended September 30, 2014, compared to interest expense of $11.1 million during the three months ended September 30, 2013. The increase was due primarily to borrowings to finance acquisitions.

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Consolidated Results of Operations

The following table summarizes our historical unaudited condensed consolidated statements of operations for the periods indicated:

	Three Months Ended September 30,						Six Months Ended September 30,

	2014			2013			2014			2013
	(in thousands)
Total revenues	$	5,380,526		$	1,593,937		$	9,029,140		$	2,979,894
Total cost of sales		5,179,465			1,488,850			8,713,518			2,791,926
Operating and general and administrative expenses		143,192			70,081			238,933			137,580
Depreciation and amortization		50,099			25,061			89,474			47,785


Operating income (loss)		7,770			9,945			(12,785	)		2,603
Earnings of unconsolidated entities		3,697			—			6,262			—
Interest expense		(28,651	)		(11,060	)		(49,145	)		(21,682	)
Other, net		(617	)		419			(1,008	)		469


Loss before income taxes		(17,801	)		(696	)		(56,676	)		(18,610	)
Income tax (provision) benefit		1,922			(236	)		887			170


Net loss		(15,879	)		(932	)		(55,789	)		(18,440	)
Less: Net income allocated to general partner		(11,056	)		(2,451	)		(20,437	)		(4,139	)
Less: Net income attributable to noncontrolling interests		(3,345	)		(9	)		(3,410	)		(134	)


Net loss attributable to parent equity	$	(30,280	)	$	(3,392	)	$	(79,636	)	$	(22,713	)

See the detailed discussion of revenues, cost of sales, operating expenses, general and administrative expenses, depreciation and amortization expense and operating income by segment below. The acquisitions described above had a significant impact on the comparability of our results of operations during the three months and six months ended September 30, 2014 and 2013.

Segment Operating Results for the Three Months Ended September 30, 2014 and 2013

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. We expanded our water solutions business through several acquisitions of water disposal and transportation businesses, including OWL in August 2013, Coastal in September 2013, and other water disposal facilities subsequent to September 30, 2013. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane segments are impacted by seasonality, primarily due to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the three months ended September 30, 2014 are not necessarily indicative of the results to be expected for the full fiscal year.

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Volumes

The following table summarizes the volume of product sold and water delivered during the three months ended September 30, 2014 and 2013. Volumes shown in the following table include intersegment sales.

	Three Months Ended September 30,

Segment	2014		2013		Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)		21,549		9,280		12,269
Water solutions
Water delivered (barrels)		30,869		16,459		14,410
Liquids
Propane sold (gallons)		240,234		183,415		56,819
Other products sold (gallons)		197,510		195,292		2,218
Retail propane
Propane sold (gallons)		23,551		20,599		2,952
Distillates sold (gallons)		3,434		3,072		362
Refined products and renewables
Refined products sold (gallons)		890,141		—		890,141
Renewable products sold (gallons)		51,557		—		51,557

Operating Income (Loss) by Segment

Our operating income (loss) by segment is as follows:

	Three Months Ended September 30,

Segment	2014			2013			Change
	(in thousands)
Crude oil logistics	$	38		$	5,884		$	(5,846	)
Water solutions		14,792			2,913			11,879
Liquids		10,929			14,605			(3,676	)
Retail propane		(3,062	)		(4,520	)		1,458
Refined products and renewables		8,822			—			8,822
Corporate and other		(23,749	)		(8,937	)		(14,812	)


Operating income	$	7,770		$	9,945		$	(2,175	)

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Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the periods indicated:

	Three Months Ended September 30,

	2014		2013		Change
	(in thousands)
Revenues:
Crude oil sales	$	2,108,117	$	1,013,061	$	1,095,056
Crude oil transportation and other		13,082		9,794		3,288


Total revenues(1)		2,121,199		1,022,855		1,098,344
Expenses:
Cost of sales		2,093,744		1,000,982		1,092,762
Operating expenses		12,432		11,760		672
General and administrative expenses		5,745		899		4,846
Depreciation and amortization expense		9,240		3,330		5,910


Total expenses		2,121,161		1,016,971		1,104,190


Segment operating income	$	38	$	5,884	$	(5,846	)

(1): Revenues include $10.1 million and $8.8 million of intersegment sales during the three months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues. Our crude oil logistics segment generated $2.1 billion of revenue from crude oil sales during the three months ended September 30, 2014, selling 21.5 million barrels at an average price of $97.83 per barrel. During the three months ended September 30, 2013, our crude oil logistics segment generated $1.0 billion of revenue from crude oil sales, selling 9.3 million barrels at an average price of $109.17 per barrel.

Crude oil transportation and other revenues of our crude oil logistics segment were $13.1 million during the three months ended September 30, 2014, compared to $9.8 million of crude oil transportation and other revenues during the three months ended September 30, 2013. This increase was due primarily to the Gavilon acquisition in December 2013.

Cost of Sales. Our cost of crude oil sold was $2.1 billion during the three months ended September 30, 2014, as we sold 21.5 million barrels at an average cost of $97.16 per barrel. Our cost of sales during the three months ended September 30, 2014 was reduced by $0.7 million of net unrealized gains on derivatives. During the three months ended September 30, 2013, our cost of crude oil sold was $1.0 billion, as we sold 9.3 million barrels at an average cost of $107.86 per barrel. Our cost of sales during the three months ended September 30, 2013 was increased by $3.1 million of net unrealized losses on derivatives.

The most significant drivers of the increase in our volumes, revenues, and cost of sales were the acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. Spreads between the price of crude oil in different markets narrowed during the three months ended September 30, 2013 and remained narrow, which reduced our opportunity to generate increased margins by transporting crude oil from lower-price markets to higher-price markets.

Operating Expenses. Our crude oil logistics segment incurred $12.4 million of operating expenses during the three months ended September 30, 2014, compared to $11.8 million of operating expenses during the three months ended September 30, 2013.

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General and Administrative Expenses. Our crude oil logistics segment incurred $5.7 million of general and administrative expenses during the three months ended September 30, 2014, compared to $0.9 million of general and administrative expenses during the three months ended September 30, 2013. This increase was due to the acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. General and administrative expenses during the three months ended September 30, 2014 were increased by $2.2 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. General and administrative expenses during the three months ended September 30, 2014 were also increased by $1.2 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense. Our crude oil logistics segment incurred $9.2 million of depreciation and amortization expense during the three months ended September 30, 2014, compared to $3.3 million of depreciation and amortization expense during the three months ended September 30, 2013. This increase was primarily due to acquisitions and capital expansions.

Operating Income. Our crude oil logistics segment generated operating income of less than $0.1 million during the three months ended September 30, 2014, compared to operating income of $5.9 million during the three months ended September 30, 2013. Operating income during the three months ended September 30, 2014 was increased by $0.7 million of net unrealized gains on derivatives. Operating income during the three months ended September 30, 2013 was reduced by $3.1 million of net unrealized losses on derivatives. Spreads between the price of crude oil in different markets narrowed during the three months ended September 30, 2013 and remained narrow, which reduced our opportunity to generate increased margins by transporting crude oil from lower-price markets to higher-price markets.

Water Solutions

The following table summarizes the operating results of our water solutions segment for the periods indicated:

	Three Months Ended September 30,					Change

	2014			2013		Acquisitions(1)			Other
	(in thousands)
Revenues:
Water treatment and disposal	$	47,572		$	28,823	$	14,861		$	3,888
Water transportation		5,147			5,367		1,354			(1,574	)


Total revenues		52,719			34,190		16,215			2,314
Expenses:
Cost of sales		(9,439	)		3,782		1,152			(14,373	)
Operating expenses		29,019			15,003		13,947			69
General and administrative expenses		774			1,054		126			(406	)
Depreciation and amortization expense		17,573			11,438		5,708			427


Total expenses		37,927			31,277		20,933			(14,283	)


Segment operating income	$	14,792		$	2,913	$	(4,718	)	$	16,597

(1): Represents the change in revenues and expenses attributable to acquisitions subsequent to June 30, 2013. The cost of sales amount shown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities.

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Revenues. The acquisitions subsequent to June 30, 2013 generated $19.4 million of treatment and disposal revenue during the three months ended September 30, 2014, taking delivery of 14.0 million barrels of wastewater at an average revenue of $1.39 per barrel. Exclusive of the acquisitions subsequent to June 30, 2013, our water solutions segment generated $28.2 million of treatment and disposal revenue during the three months ended September 30, 2014, taking delivery of 16.9 million barrels of wastewater at an average revenue of $1.67 per barrel. The acquisitions subsequent toJune 30, 2013 generated $4.5 million of treatment and disposal revenue during the three months ended September 30, 2013, taking delivery of 2.7 million barrels of wastewater at an average revenue of $1.68 per barrel. Exclusive of the acquisitions subsequent to June 30, 2013, our water solutions segment generated $24.3 million of treatment and disposal revenue during the three months ended September 30, 2014, taking delivery of 13.8 million barrels of wastewater at an average revenue of $1.76 per barrel. The primary reasons for the increase in revenues and water delivered were acquisitions made subsequent to June 30, 2013, including our acquisitions of OWL and Coastal, and to an increase in water volumes processed due to higher demand from customers.

Water transportation revenues decreased by $0.2 million during the three months ended September 30, 2014 compared to the three months ended September 30, 2013. During September 2014, we sold our water transportation business in order to focus our efforts on water processing. As part of this transaction, the buyer of the transportation business committed to deliver to our facilities substantially all of the water it transports for a period of two years.

Cost of Sales. We enter into derivatives in our water solutions business to protect against the risk of a decline in the market price of the hydrocarbons we expect to recover when processing the wastewater. Our cost of sales for the three months ended September 30, 2014 was reduced by $12.7 million of net unrealized gains on derivatives and increased by $0.3 million of net realized losses on derivatives. Our cost of sales for the three months ended September 30, 2013 was increased by $0.2 million of net unrealized losses on derivatives and $0.9 million of net realized losses on derivatives. In the table above, the full impact of the change in derivative gains and losses during the three months ended September 30, 2014 as compared to the three months ended September 30, 2013 is reported in the "other" column, as it is not possible to attribute these gains and losses to individual water facilities.

Operating Expenses. Our water solutions segment incurred $29.0 million of operating expenses during the three months ended September 30, 2014, compared to $15.0 million of operating expenses during the three months ended September 30, 2013. Of this increase, $13.9 million related to the acquisitions subsequent to June 30, 2013, which includes a loss of $4.0 million related to the sale of our water transportation business. This increase was partially offset by losses on disposal of property, plant and equipment of $2.0 million during the three months ended September 30, 2013 as a result of property damage from lightning strikes at two of our facilities.

General and Administrative Expenses. Our water solutions segment incurred $0.8 million of general and administrative expenses during the three months ended September 30, 2014, compared to $1.1 million of general and administrative expenses during the three months ended September 30, 2013.

Depreciation and Amortization Expense. Our water solutions segment incurred $17.6 million of depreciation and amortization expense during the three months ended September 30, 2014, compared to $11.4 million of depreciation and amortization expense during the three months ended September 30, 2013. Of this increase, $5.7 million related to the acquisitions subsequent toJune 30, 2013, which included $0.5 million of amortization expense related to trade name intangible assets. Exclusive of the acquisitions subsequent to June 30, 2013, the increase is due in part to $0.6 million of amortization expense related to trade name intangible assets. During the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets.

Operating Income. Our water solutions segment generated operating income of $14.8 million during the three months ended September 30, 2014, compared to operating income of $2.9 million

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during the three months ended September 30, 2013. This increase was due in part to an increase in the volume of wastewater processed, which was due to increased demand for existing facilities and to the development and acquisition of new facilities.

Liquids

The following table summarizes the operating results of our liquids segment for the periods indicated:

	Three Months Ended September 30,

	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	240,433	$	191,437	$	48,996
Other product sales		306,625		308,606		(1,981	)
Other revenues		6,814		9,250		(2,436	)


Total revenues(1)		553,872		509,293		44,579
Expenses:
Cost of sales—propane		230,729		184,565		46,164
Cost of sales—other products		293,262		292,142		1,120
Cost of sales—other		4,222		7,106		(2,884	)
Operating expenses		9,183		6,800		2,383
General and administrative expenses		2,163		1,403		760
Depreciation and amortization expense		3,384		2,672		712


Total expenses		542,943		494,688		48,255


Segment operating income	$	10,929	$	14,605	$	(3,676	)

(1): Revenues include $14.1 million and $24.4 million of intersegment sales during the three months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues. Our liquids segment generated $240.4 million of wholesale propane sales revenue during the three months ended September 30, 2014, selling 240.2 million gallons at an average price of $1.00 per gallon. During the three months ended September 30, 2013, our liquids segment generated $191.4 million of wholesale propane sales revenue, selling 183.4 million gallons at an average price of $1.04 per gallon. The increase in volume was due to higher market demand, due in part to cold weather conditions during the previous winter.

Our liquids segment generated $306.6 million of other wholesale products sales revenue during the three months ended September 30, 2014, selling 197.5 million gallons at an average price of $1.55 per gallon. During the three months ended September 30, 2013, our liquids segment generated $308.6 million of other wholesale products sales revenue, selling 195.3 million gallons at an average price of $1.58 per gallon.

Cost of Sales. Our cost of wholesale propane sales was $230.7 million during the three months ended September 30, 2014, as we sold 240.2 million gallons at an average cost of $0.96 per gallon. Our cost of wholesale propane sales during the three months ended September 30, 2014 was increased by $1.9 million of net unrealized losses on derivatives. During the three months ended September 30, 2013, our cost of wholesale propane sales was $184.6 million, as we sold 183.4 million gallons at an average cost of $1.01 per gallon. Our cost of wholesale propane sales during the three months ended September 30, 2013 was increased by $3.6 million of net unrealized losses on derivatives.

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Our cost of sales of other products was $293.3 million during the three months ended September 30, 2014, as we sold 197.5 million gallons at an average cost of $1.48 per gallon. Our cost of sales of other products during the three months ended September 30, 2014 was reduced by $2.2 million of net unrealized gains on derivatives. During the three months ended September 30, 2013, our cost of sales of other products was $292.1 million, as we sold 195.3 million gallons at an average cost of $1.50 per gallon. Our cost of sales of other products during the three months ended September 30, 2013 was reduced by $6.9 million of net unrealized gains on derivatives.

Operating Expenses. Our liquids segment incurred $9.2 million of operating expenses during the three months ended September 30, 2014, compared to $6.8 million of operating expenses during the three months ended September 30, 2013. This increase was due primarily to expanded operations.

General and Administrative Expenses. Our liquids segment incurred $2.2 million of general and administrative expenses during the three months ended September 30, 2014, compared to $1.4 million of general and administrative expenses during the three months ended September 30, 2013. This increase was due primarily to expanded operations.

Depreciation and Amortization Expense. Our liquids segment incurred $3.4 million of depreciation and amortization expense during the three months ended September 30, 2014, compared to $2.7 million of depreciation and amortization expense during the three months ended September 30, 2013.

Operating Income. Our liquids segment generated operating income of $10.9 million during the three months ended September 30, 2014, compared to operating income of $14.6 million during the three months ended September 30, 2013. Although sales volumes were higher during the three months ended September 30, 2014 than during the three months ended September 30, 2013, product margins were similar. This was due in part to the impact of unrealized gains on derivatives, which reduced cost of sales by $0.3 million during the three months ended September 30, 2014 and by $3.3 million during the three months ended September 30, 2013. Operating and general and administrative expenses were higher during the three months ended September 30, 2014 than during the three months ended September 30, 2013, due to expanded operations. The wholesale natural gas liquids business is weather-sensitive and subject to seasonal volume variations due to propane's primary use as a heating source and butane's use in gasoline blending, and sales prices and volumes are typically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the periods indicated:

	Three Months Ended September 30,

	2014			2013			Change
	(in thousands)
Revenues:
Propane sales	$	48,552		$	40,651		$	7,901
Distillate sales		11,530			10,562			968
Other revenues		8,276			8,198			78


Total revenues		68,358			59,411			8,947
Expenses:
Cost of sales—propane		27,434			21,848			5,586
Cost of sales—distillates		9,840			9,265			575
Cost of sales—other		2,620			2,457			163
Operating expenses		21,205			20,997			208
General and administrative expenses		2,637			2,493			144
Depreciation and amortization expense		7,684			6,871			813


Total expenses		71,420			63,931			7,489


Segment operating loss	$	(3,062	)	$	(4,520	)	$	1,458

Revenues. Our retail propane segment generated revenue of $48.6 million from propane sales during the three months ended September 30, 2014, selling 23.6 million gallons at an average price of $2.06 per gallon. During the three months ended September 30, 2013, our retail propane segment generated $40.7 million of revenue from propane sales, selling 20.6 million gallons at an average price of $1.97 per gallon. The increase in average sales prices during the three months ended September 30, 2014 compared to the three months ended September 30, 2013 was due primarily to higher market demand as a result of cold weather conditions during the recent winter.

Our retail propane segment generated revenue of $11.5 million from distillate sales during the three months ended September 30, 2014, selling 3.4 million gallons at an average price of $3.36 per gallon. During the three months ended September 30, 2013, our retail propane segment generated $10.6 million of revenue from distillate sales, selling 3.1 million gallons at an average price of $3.44 per gallon.

Cost of Sales. Our cost of retail propane sales was $27.4 million during the three months ended September 30, 2014, as we sold 23.6 million gallons at an average cost of $1.16 per gallon. During the three months ended September 30, 2013, our cost of retail propane sales was $21.8 million, as we sold 20.6 million gallons at an average cost of $1.06 per gallon.

Our cost of distillate sales was $9.8 million during the three months ended September 30, 2014, as we sold 3.4 million gallons at an average cost of $2.87 per gallon. During the three months ended September 30, 2013, our cost of distillate sales was $9.3 million, as we sold 3.1 million gallons at an average cost of $3.02 per gallon.

Operating Expenses. Our retail propane segment incurred $21.2 million of operating expenses during the three months ended September 30, 2014, compared to $21.0 million of operating expenses during the three months ended September 30, 2013.

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General and Administrative Expenses. Our retail propane segment incurred $2.6 million of general and administrative expenses during the three months ended September 30, 2014, compared to $2.5 million of general and administrative expenses during the three months ended September 30, 2013.

Depreciation and Amortization Expense. Our retail propane segment incurred $7.7 million of depreciation and amortization expense during the three months ended September 30, 2014, compared to $6.9 million of depreciation and amortization expense during the three months ended September 30, 2013.

Operating Loss. Our retail propane segment generated an operating loss of $3.1 million during the three months ended September 30, 2014, compared to an operating loss of $4.5 million during the three months ended September 30, 2013. The decrease in operating loss was due primarily due to an increase in propane sales volumes. Demand was high during the three months ended September 30, 2014, as customers sought to replenish their supplies of natural gas liquids that had been depleted during the winter. The retail propane business is weather-sensitive and subject to seasonal volume variations due to propane's primary use as a heating source in residential and commercial buildings and for agricultural purposes. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

Refined Products and Renewables

The following table summarizes the operating results of our refined products and renewables segment during the three months ended September 30, 2014 (in thousands). Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.


Revenues:
Refined products sales	$	2,489,795
Renewables sales(1)		117,425


Total revenues		2,607,220
Expenses:
Cost of sales—refined products		2,435,868
Cost of sales—renewables(1)		114,983
Operating expenses		29,838
General and administrative expenses		5,792
Depreciation and amortization expense		11,917


Total expenses		2,598,398


Segment operating income	$	8,822

(1): Revenues and cost of sales include $4.9 million and $2.0 million, respectively, associated with freely tradable Renewable Identification Numbers ("RINs") with no corresponding sales volume during the three months ended September 30, 2014.

Revenues. Our refined products and renewables segment generated $2.5 billion of refined products sales revenue during the three months ended September 30, 2014, selling 890.1 million gallons at an average price of $2.80 per gallon.

Our refined products and renewables segment generated $112.5 million of renewables sales revenue (excluding freely tradable RINS) during the three months ended September 30, 2014, selling 51.6 million gallons at an average price of $2.18 per gallon.

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Cost of Sales. Our cost of refined products sales was $2.4 billion during the three months ended September 30, 2014, as we sold 890.1 million gallons at an average cost of $2.74 per gallon.

Our cost of renewables sales was $113.0 million (excluding freely tradable RINS) during the three months ended September 30, 2014, as we sold 51.6 million gallons at an average cost of $2.19 per gallon. We use a weighted-average inventory costing method for our ethanol inventory. During periods of declining prices, our margins are reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

Operating Expenses. Our refined products and renewables segment incurred $29.8 million of operating expenses during the three months ended September 30, 2014.

General and Administrative Expenses. Our refined products and renewables segment incurred $5.8 million of general and administrative expenses during the three months ended September 30, 2014. General and administrative expenses during the three months ended September 30, 2014 were increased by $0.1 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. General and administrative expenses during the three months ended September 30, 2014 were also increased by $1.5 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense. Our refined products and renewables segment incurred $11.9 million of depreciation and amortization expense during the three months ended September 30, 2014.

Operating Income. Our refined products and renewables segment generated operating income of $8.8 million during the three months ended September 30, 2014. The adverse impact resulting from declining refined products prices during the quarter was mitigated by gains on hedges entered into to protect against the risk of declines in inventory prices.

Corporate and Other

The operating loss within "corporate and other" includes the following components:

	Three Months Ended September 30,

	2014			2013			Change
	(in thousands)
Equity-based compensation expense	$	(13,745	)	$	(3,217	)	$	(10,528	)
Acquisition expenses		(3,230	)		(785	)		(2,445	)
Other corporate expenses		(6,774	)		(4,935	)		(1,839	)


	$	(23,749	)	$	(8,937	)	$	(14,812	)

The increase in equity-based compensation expense is due primarily to $10.5 million of expense associated with restricted units granted in July 2014 to certain employees as a discretionary bonus that vested in September 2014.

Acquisition expenses during the three months ended September 30, 2014 related primarily to the acquisition of TransMontaigne.

The increase in other corporate expenses is due primarily to increases in compensation expense, due to the addition of new corporate employees to provide general and administrative services in support of the growth of our business.

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Segment Operating Results for the Six Months Ended September 30, 2014 and 2013

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of Crescent and Cierra Marine in July 2013, Gavilon Energy in December 2013 and TransMontaigne in July 2014. We expanded our water solutions business through several acquisitions of water disposal and transportation businesses, including Big Lake in July 2013, OWL in August 2013, Coastal in September 2013, and other water disposal facilities subsequent to September 30, 2013. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane segments are impacted by seasonality, primarily due to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the six months ended September 30, 2014 are not necessarily indicative of the results to be expected for the full fiscal year.

Volumes

The following table summarizes the volume of product sold and water delivered during the six months ended September 30, 2014 and 2013. Volumes shown in the following table include intersegment sales.

	Six Months Ended September 30,

Segment	2014		2013		Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)		40,806		18,535		22,271
Water solutions
Water delivered (barrels)		51,804		26,498		25,306
Liquids
Propane sold (gallons)		423,992		310,834		113,158
Other products sold (gallons)		384,235		373,722		10,513
Retail propane
Propane sold (gallons)		47,142		43,992		3,150
Distillates sold (gallons)		8,712		8,176		536
Refined products and renewables
Refined products sold (gallons)		1,221,949		—		1,221,949
Renewable products sold (gallons)		104,591		—		104,591

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Operating Income (Loss) by Segment

Our operating income (loss) by segment is as follows:

	Six Months Ended September 30,

Segment	2014			2013			Change
	(in thousands)
Crude oil logistics	$	1,501		$	12,493		$	(10,992	)
Water solutions		13,885			5,956			7,929
Liquids		10,016			12,490			(2,474	)
Retail propane		(4,648	)		(6,024	)		1,376
Refined products and renewables		7,567			—			7,567
Corporate and other		(41,106	)		(22,312	)		(18,794	)


Operating income (loss)	$	(12,785	)	$	2,603		$	(15,388	)

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the periods indicated:

	Six Months Ended September 30,

	2014		2013		Change
	(in thousands)
Revenues:
Crude oil sales	$	4,035,061	$	1,941,595	$	2,093,466
Crude oil transportation and other		25,196		19,729		5,467


Total revenues(1)		4,060,257		1,961,324		2,098,933
Expenses:
Cost of sales		4,001,158		1,917,876		2,083,282
Operating expenses		28,417		21,175		7,242
General and administrative expenses		10,210		1,766		8,444
Depreciation and amortization expense		18,971		8,014		10,957


Total expenses		4,058,756		1,948,831		2,109,925


Segment operating income	$	1,501	$	12,493	$	(10,992	)

(1): Revenues include $19.8 million and $16.5 million of intersegment sales during the six months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues. Our crude oil logistics segment generated $4.0 billion of revenue from crude oil sales during the six months ended September 30, 2014, selling 40.8 million barrels at an average price of $98.88 per barrel. During the six months ended September 30, 2013, our crude oil logistics segment generated $1.9 billion of revenue from crude oil sales, selling 18.5 million barrels at an average price of $104.75 per barrel.

Crude oil transportation and other revenues of our crude oil logistics segment were $25.2 million during the six months ended September 30, 2014, compared to $19.7 million of crude oil transportation and other revenues during the six months ended September 30, 2013. This increase was due primarily to the Crescent and Cierra Marine acquisition in July 2013 and the Gavilon acquisition in December 2013.

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Cost of Sales. Our cost of crude oil sold was $4.0 billion during the six months ended September 30, 2014, as we sold 40.8 million barrels at an average cost of $98.05 per barrel. Our cost of sales during the six months ended September 30, 2014 was reduced by $3.1 million of net unrealized gains on derivatives. During the six months ended September 30, 2013, our cost of crude oil sold was $1.9 billion, as we sold 18.5 million barrels at an average cost of $103.47 per barrel. Our cost of sales during the six months ended September 30, 2013 was reduced by $1.5 million of net unrealized gains on derivatives.

The most significant drivers of the increase in our volumes, revenues, and cost of sales were the acquisition of Gavilon Energy in December 2013 and TransMontaigne in July 2014. Spreads between the price of crude oil in different markets narrowed during the six months ended September 30, 2013 and remained narrow, which reduced our opportunity to generate increased margins by transporting crude oil from lower-price markets to higher-price markets.

Operating Expenses. Our crude oil logistics segment incurred $28.4 million of operating expenses during the six months ended September 30, 2014, compared to $21.2 million of operating expenses during the six months ended September 30, 2013. This increase was primarily due to the Gavilon acquisition in December 2013.

General and Administrative Expenses. Our crude oil logistics segment incurred $10.2 million of general and administrative expenses during the six months ended September 30, 2014, compared to $1.8 million of general and administrative expenses during the six months ended September 30, 2013. This increase was due to the acquisitions of Gavilon Energy in December 2013 and TransMontaigne in July 2014. General and administrative expenses during the six months ended September 30, 2014 were increased by $4.3 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. General and administrative expenses during the six months ended September 30, 2014 were also increased by $1.2 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense. Our crude oil logistics segment incurred $19.0 million of depreciation and amortization expense during the six months ended September 30, 2014, compared to $8.0 million of depreciation and amortization expense during the six months ended September 30, 2013. This increase was primarily due to acquisitions and capital expansions.

Operating Income. Our crude oil logistics segment generated operating income of $1.5 million during the six months ended September 30, 2014, compared to operating income of $12.5 million during the six months ended September 30, 2013. Operating income during the three months ended September 30, 2014 was increased by $3.1 million of net unrealized gains on derivatives. Operating income during the three months ended September 30, 2013 was increased by $1.5 million of net unrealized gains on derivatives. Spreads between the price of crude oil in different markets narrowed during the six months ended September 30, 2013 and remained narrow, which reduced our opportunity to generate increased margins by transporting crude oil from lower-price markets to higher-price markets.

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Water Solutions

The following table summarizes the operating results of our water solutions segment for the periods indicated:

	Six Months Ended September 30,				Change

	2014		2013		Acquisitions(1)			Other
	(in thousands)
Revenues:
Water treatment and disposal	$	89,288	$	47,511	$	28,627		$	13,150
Water transportation		10,745		7,192		6,954			(3,401	)


Total revenues		100,033		54,703		35,581			9,749
Expenses:
Cost of sales		1,134		4,365		4,984			(8,215	)
Operating expenses		48,748		24,010		23,141			1,597
General and administrative expenses		1,601		1,578		199			(176	)
Depreciation and amortization expense		34,665		18,794		15,348			523


Total expenses		86,148		48,747		43,672			(6,271	)


Segment operating income	$	13,885	$	5,956	$	(8,091	)	$	16,020

(1): Represents the change in revenues and expenses attributable to acquisitions subsequent to March 31, 2013. The cost of sales amount shown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities.

Revenues. The acquisitions subsequent to March 31, 2013 generated $35.6 million of treatment and disposal revenue during the six months ended September 30, 2014, taking delivery of 22.9 million barrels of wastewater at an average revenue of $1.56 per barrel. Exclusive of the acquisitions subsequent to March 31, 2013, our water solutions segment generated $53.7 million of treatment and disposal revenue during the six months ended September 30, 2014, taking delivery of 28.9 million barrels of wastewater at an average revenue of $1.85 per barrel. The acquisitions subsequent to March 31, 2013 generated $7.0 million of treatment and disposal revenue during the six months ended September 30, 2013, taking delivery of 5.1 million barrels of wastewater at an average revenue of $1.37per barrel. Exclusive of the acquisitions subsequent to March 31, 2013, our water solutions segment generated $40.5 million of treatment and disposal revenue during the six months ended September 30, 2014, taking delivery of 21.4 million barrels of wastewater at an average revenue of $1.89 per barrel. The primary reasons for the increase in revenues and water delivered were acquisitions made subsequent to March 31, 2013, including our acquisitions of Big Lake, OWL and Coastal, and to an increase in water volumes processed due to higher demand from customers.

Water transportation revenues increased by $3.6 million during the six months ended September 30, 2014 compared to the six months ended September 30, 2013, due primarily to the acquisition of OWL. During September 2014, we sold our water transportation business in order to focus our efforts on water processing. As part of this transaction, the buyer of the transportation business committed to deliver to our facilities substantially all of the water it transports for a period of two years.

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unrealized gains on derivatives and increased by $1.1 million of net realized losses on derivatives. In the table above, the full impact of the change in derivative gains and losses during the six months ended September 30, 2014 as compared to the six months ended September 30, 2013 is reported in the "other" column, as it is not possible to attribute these gains and losses to individual water facilities.

Operating Expenses. Our water solutions segment incurred $48.7 million of operating expenses during the six months ended September 30, 2014, compared to $24.0 million of operating expenses during the six months ended September 30, 2013. Of this increase, $23.1 million related to the acquisitions subsequent to March 31, 2013, which includes a loss of $4.0 million related to the sale of our water transportation business. This increase was partially offset by losses on disposal of property, plant and equipment of $2.0 million during the six months ended September 30, 2013 as a result of property damage from lightning strikes at two of our facilities.

General and Administrative Expenses. Our water solutions segment incurred $1.6 million of general and administrative expenses during the six months ended September 30, 2014 and the six months ended September 30, 2013.

Depreciation and Amortization Expense. Our water solutions segment incurred $34.7 million of depreciation and amortization expense during the six months ended September 30, 2014, compared to $18.8 million of depreciation and amortization expense during the six months ended September 30, 2013. Of this increase, $15.3 million related to the acquisitions subsequent to March 31, 2013, which included $1.0 million of amortization expense related to trade name intangible assets. Exclusive of the acquisitions subsequent to March 31, 2013, the increase is due in part to $1.2 million of amortization expense related to trade name intangible assets. During the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets.

Operating Income. Our water solutions segment generated operating income of $13.9 million during the six months ended September 30, 2014, compared to operating income of $6.0 million during the six months ended September 30, 2013. This increase was due in part to an increase in the volume of wastewater processed, which was due to increased demand for existing facilities and to the development and acquisition of new facilities.

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Liquids

The following table summarizes the operating results of our liquids segment for the periods indicated:

	Six Months Ended September 30,

	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	462,879	$	315,274	$	147,605
Other product sales		594,984		558,459		36,525
Other revenues		12,530		18,114		(5,584	)


Total revenues(1)		1,070,393		891,847		178,546
Expenses:
Cost of sales—propane		449,636		302,108		147,528
Cost of sales—other products		574,524		541,077		33,447
Cost of sales—other		7,403		12,474		(5,071	)
Operating expenses		18,248		15,532		2,716
General and administrative expenses		3,981		2,790		1,191
Depreciation and amortization expense		6,585		5,376		1,209


Total expenses		1,060,377		879,357		181,020


Segment operating income	$	10,016	$	12,490	$	(2,474	)

(1): Revenues include $55.5 million and $46.0 million of intersegment sales during the six months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

Revenues. Our liquids segment generated $462.9 million of wholesale propane sales revenue during the six months ended September 30, 2014, selling 424.0 million gallons at an average price of $1.09 per gallon. During the six months ended September 30, 2013, our liquids segment generated $315.3 million of wholesale propane sales revenue, selling 310.8 million gallons at an average price of $1.01 per gallon. The increase in volume was due to higher market demand, due in part to cold weather conditions during the previous winter.

Our liquids segment generated $595.0 million of other wholesale products sales revenue during the six months ended September 30, 2014, selling 384.2 million gallons at an average price of $1.55 per gallon. During the six months ended September 30, 2013, our liquids segment generated $558.5 million of other wholesale products sales revenue, selling 373.7 million gallons at an average price of $1.49 per gallon.

Cost of Sales. Our cost of wholesale propane sales was $449.6 million during the six months ended September 30, 2014, as we sold 424.0 million gallons at an average cost of $1.06 per gallon. Our cost of wholesale propane sales during the six months ended September 30, 2014 was increased by $1.7 million of net unrealized losses on derivatives. During the six months ended September 30, 2013, our cost of wholesale propane sales was $302.1 million, as we sold 310.8 million gallons at an average cost of $0.97 per gallon. Our cost of wholesale propane sales during the six months ended September 30, 2013 was increased by $5.2 million of net unrealized losses on derivatives.

Product margins per gallon of propane sold were lower during the six months ended September 30, 2014 than during the six months ended September 30, 2013. Propane prices were high during the recent winter due to cold weather conditions, and prices declined during February and March 2014. We use a

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weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the location of the inventory. During periods of declining prices, our margins are reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of falling prices, this can result in negative margins on these sales.

Our cost of sales of other products was $574.5 million during the six months ended September 30, 2014, as we sold 384.2 million gallons at an average cost of $1.50 per gallon. Our cost of sales of other products during the six months ended September 30, 2014 was reduced by $0.8 million of net unrealized gains on derivatives. During the six months ended September 30, 2013, our cost of sales of other products was $541.1 million, as we sold 373.7 million gallons at an average cost of $1.45 per gallon. Our cost of sales of other products during the six months ended September 30, 2013 was increased by $0.3 million of net unrealized losses on derivatives.

Operating Expenses. Our liquids segment incurred $18.2 million of operating expenses during the six months ended September 30, 2014, compared to $15.5 million of operating expenses during the six months ended September 30, 2013. This increase was due primarily to expanded operations.

General and Administrative Expenses. Our liquids segment incurred $4.0 million of general and administrative expenses during the six months ended September 30, 2014, compared to $2.8 million of general and administrative expenses during the six months ended September 30, 2013. This increase was due primarily to expanded operations.

Depreciation and Amortization Expense. Our liquids segment incurred $6.6 million of depreciation and amortization expense during the six months ended September 30, 2014, compared to $5.4 million of depreciation and amortization expense during the six months ended September 30, 2013.

Operating Income. Our liquids segment generated operating income of $10.0 million during the six months ended September 30, 2014, compared to operating income of $12.5 million during the six months ended September 30, 2013. The wholesale natural gas liquids business is weather-sensitive and subject to seasonal volume variations due to propane's primary use as a heating source and butane's use in gasoline blending, and sales prices and volumes are typically higher during the colder months of the year. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the periods indicated:

	Six Months Ended September 30,

	2014			2013			Change
	(in thousands)
Revenues:
Propane sales	$	100,578		$	87,342		$	13,236
Distillate sales		30,225			28,431			1,794
Other revenues		15,457			15,898			(441	)


Total revenues		146,260			131,671			14,589
Expenses:
Cost of sales—propane		56,721			47,027			9,694
Cost of sales—distillates		25,876			24,509			1,367
Cost of sales—other		4,821			5,100			(279	)
Operating expenses		42,687			41,839			848
General and administrative expenses		5,548			5,109			439
Depreciation and amortization expense		15,255			14,111			1,144


Total expenses		150,908			137,695			13,213


Segment operating loss	$	(4,648	)	$	(6,024	)	$	1,376

Revenues. Our retail propane segment generated revenue of $100.6 million from propane sales during the six months ended September 30, 2014, selling 47.1 million gallons at an average price of $2.13 per gallon. During the six months ended September 30, 2013, our retail propane segment generated $87.3 million of revenue from propane sales, selling 44.0 million gallons at an average price of $1.99 per gallon. The increase in volumes and average sales prices during the six months ended September 30, 2014 compared to the six months ended September 30, 2013 was due primarily to higher market demand as a result of cold weather conditions during the recent winter.

Our retail propane segment generated revenue of $30.2 million from distillate sales during the six months ended September 30, 2014, selling 8.7 million gallons at an average price of $3.47 per gallon. During the six months ended September 30, 2013, our retail propane segment generated $28.4 million of revenue from distillate sales, selling 8.2 million gallons at an average price of $3.48 per gallon.

Cost of Sales. Our cost of retail propane sales was $56.7 million during the six months ended September 30, 2014, as we sold 47.1 million gallons at an average cost of $1.20 per gallon. During the six months ended September 30, 2013, our cost of retail propane sales was $47.0 million, as we sold 44.0 million gallons at an average cost of $1.07 per gallon.

Our cost of distillate sales was $25.9 million during the six months ended September 30, 2014, as we sold 8.7 million gallons at an average cost of $2.97 per gallon. During the six months ended September 30, 2013, our cost of distillate sales was $24.5 million, as we sold 8.2 million gallons at an average cost of $3.00 per gallon.

Operating Expenses. Our retail propane segment incurred $42.7 million of operating expenses during the six months ended September 30, 2014, compared to $41.8 million of operating expenses during the six months ended September 30, 2013.

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General and Administrative Expenses. Our retail propane segment incurred $5.5 million of general and administrative expenses during the six months ended September 30, 2014, compared to $5.1 million of general and administrative expenses during the six months ended September 30, 2013.

Depreciation and Amortization Expense. Our retail propane segment incurred $15.3 million of depreciation and amortization expense during the six months ended September 30, 2014, compared to $14.1 million of depreciation and amortization expense during the six months ended September 30, 2013.

Operating Loss. Our retail propane segment generated an operating loss of $4.6 million during the six months ended September 30, 2014, compared to an operating loss of $6.0 million during the six months ended September 30, 2013. The decrease in operating loss was due primarily to an increase in propane sales volumes. Demand was high during the six months ended September 30, 2014, as customers sought to replenish their supplies of natural gas liquids that had been depleted during the winter. The retail propane business is weather-sensitive and subject to seasonal volume variations due to propane's primary use as a heating source in residential and commercial buildings and for agricultural purposes. Consequently, our revenues, operating profits, and operating cash flows are typically lower in the first and second quarters of each fiscal year.

Refined Products and Renewables

The following table summarizes the operating results of our refined products and renewables segment during the six months ended September 30, 2014 (in thousands). Our refined products and renewables segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.


Revenues:
Refined products sales	$	3,476,018
Renewables sales(1)		248,699


Total revenues		3,724,717
Expenses:
Cost of sales—refined products		3,418,880
Cost of sales—renewables(1)		246,284
Operating expenses		31,462
General and administrative expenses		7,763
Depreciation and amortization expense		12,761


Total expenses		3,717,150


Segment operating income	$	7,567

(1): Revenues and cost of sales include $6.7 million and $4.4 million, respectively, associated with freely tradable RINs with no corresponding sales volume during the six months ended September 30, 2014.

Revenues. Our refined products and renewables segment generated $3.5 billion of refined products sales revenue during the six months ended September 30, 2014, selling 1.2 billion gallons at an average price of $2.84 per gallon.

Our refined products and renewables segment generated $242.0 (excluding freely tradable RINs) million of renewables sales revenue during the six months ended September 30, 2014, selling 104.6 million gallons at an average price of $2.31 per gallon.

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Cost of Sales. Our cost of refined products sales was $3.4 billion during the six months ended September 30, 2014, as we sold 1.2 billion gallons at an average cost of $2.80 per gallon.

Our cost of renewables sales was $241.9 (excluding freely tradable RINs) million during the six months ended September 30, 2014, as we sold 104.6 million gallons at an average cost of $2.31 per gallon. We use a weighted-average inventory costing method for our ethanol inventory. During periods of declining prices, our margins are reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

Operating Expenses. Our refined products and renewables segment incurred $31.5 million of operating expenses during the six months ended September 30, 2014.

General and Administrative Expenses. Our refined products and renewables segment incurred $7.8 million of general and administrative expenses during thesix months ended September 30, 2014. General and administrative expenses during the six months ended September 30, 2014 were increased by $0.4 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. General and administrative expenses during the six months ended September 30, 2014 were also increased by $1.5 million of compensation expense related to termination benefits for certain TransMontaigne employees.

Depreciation and Amortization Expense. Our refined products and renewables segment incurred $12.8 million of depreciation and amortization expense during the six months ended September 30, 2014.

Operating Income. Our refined products and renewables segment generated operating income of $7.6 million during the six months ended September 30, 2014. The adverse impact resulting from declining refined products prices during the quarter was mitigated by gains on hedges entered into to protect against the risk of declines in inventory prices.

Corporate and Other

The operating loss within "corporate and other" includes the following components:

	Six Months Ended September 30,

	2014			2013			Change
	(in thousands)
Equity-based compensation expense	$	(21,659	)	$	(10,292	)	$	(11,367	)
Acquisition expenses		(4,328	)		(1,368	)		(2,960	)
Other corporate expenses		(15,119	)		(10,652	)		(4,467	)


	$	(41,106	)	$	(22,312	)	$	(18,794	)

Acquisition expenses during the six months ended September 30, 2014 related primarily to the acquisition of TransMontaigne.

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Operating loss during the six months ended September 30, 2014 was increased by $0.4 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. This amount is reported within "other corporate expenses" in the table above.

Interest Expense

The largest component of interest expense during the three months and six months ended September 30, 2014 and 2013 has been interest on our Revolving Credit Facility, the 2019 Notes, the 2021 Notes, the 2022 Notes, and the TLP Credit Facility (each as hereinafter defined). See Note 7 to our unaudited condensed consolidated financial statements included elsewhere in this prospectus for additional information on our long-term debt. The change in interest expense during the periods presented is due primarily to fluctuations in the average outstanding debt balance and the applicable interest rates, as summarized below:

	Revolving Credit Facility					2019 Notes					2021 Notes					2022 Notes					TLP Credit Facility

	Average Balance Outstanding (in thousands)		Average Interest Rate			Average Balance Outstanding (in thousands)		Interest Rate			Average Balance Outstanding (in thousands)		Interest Rate			Average Balance Outstanding (in thousands)		Interest Rate			Average Balance Outstanding (in thousands)		Average Interest Rate
Three Months Ended September 30,
2014	$	1,026,011		2.48	%	$	360,870		5.13	%	$	450,000		6.88	%	$	250,000		6.65	%	$	246,750		2.70	%
2013		572,353		3.63	%		—		—			—		—			250,000		6.65	%		—		—
Six Months Ended September 30,
2014	$	987,224		2.38	%	$	181,424		5.13	%	$	450,000		6.88	%	$	250,000		6.65	%	$	246,750		2.70	%
2013		521,202		3.65	%		—		—			—		—			250,000		6.65	%		—		—

Interest expense also includes amortization of debt issuance costs, letter of credit fees, interest on equipment financing notes, and accretion of interest on noninterest bearing debt obligations assumed in business combinations.

The increased level of debt outstanding during the three months and six months ended September 30, 2014 is due primarily to borrowings to finance acquisitions.

Income Tax Provision

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

Income tax benefit was $1.9 million during the three months ended September 30, 2014, compared to $0.2 million of income tax expense during the three months ended September 30, 2013. The increase in the income tax benefit was primarily due to the July 2014 acquisition of TransMontaigne, as TransMontaigne is subject to United States federal and state income taxes.

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Income tax benefit was $0.9 million during the six months ended September 30, 2014, compared to $0.2 million of an income tax benefit during the six months ended September 30, 2013. The increase in the income tax benefit was primarily due to the July 2014 acquisition of TransMontaigne, as TransMontaigne is subject to United States federal and state income taxes.

Noncontrolling Interests

We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our condensed consolidated statements of operations represents the other owners' share of the net income of these entities.

Net income attributable to noncontrolling interests was $3.3 million during the three months ended September 30, 2014, compared to less than $0.1 million of net income attributable to noncontrolling interests during the three months ended September 30, 2013. The increase was primarily due to the July 2014 acquisition of TransMontaigne, in which we acquired the general partner interest and a 19.7% limited partner interest in TLP.

Net income attributable to noncontrolling interests was $3.4 million during the six months ended September 30, 2014, compared to $0.1 million of net income attributable to noncontrolling interests during the six months ended September 30, 2013. The increase was primarily due to the July 2014 acquisition of TransMontaigne, in which we acquired the general partner interest and a 19.7% limited partner interest in TLP.

Seasonality

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

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Consolidated Results of Operations—Year ended March 31, 2014

The following table summarizes our historical consolidated statements of operations for the years ended March 31, 2014, 2013, and 2012:

	Year Ended March 31,

	2014			2013			2012
	(in thousands)
Total revenues	$	9,699,274		$	4,417,767		$	1,310,473
Total cost of sales		9,132,699			4,039,110			1,217,023
Operating and general and administrative expenses		339,256			222,497			63,309
Depreciation and amortization		120,754			68,853			15,111


Operating income		106,565			87,307			15,030
Earnings of unconsolidated entities		1,898			—			—
Interest expense		(58,854	)		(32,994	)		(7,620	)
Loss on early extinguishment of debt		—			(5,769	)		—
Other, net		86			1,521			1,055


Income before income taxes		49,695			50,065			8,465
Income tax provision		(937	)		(1,875	)		(601	)


Net income		48,758			48,190			7,864
Net (income) loss attributable to noncontrolling interests		(1,103	)		(250	)		12


Net income attributable to parent equity	$	47,655		$	47,940		$	7,876

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

Interest Expense

See Note 8 to our audited consolidated financial statements included elsewhere in this prospectus for additional information on our long-term debt. The change in interest expense during the periods presented is due primarily to fluctuations in the average outstanding debt balance, and in the applicable interest rates, as summarized below:

	Revolving Credit Facilities					Senior Notes					Unsecured Notes

Year Ended:	Average Balance Outstanding (in thousands)		Average Interest Rate			Average Balance Outstanding (in thousands)		Interest Rate			Average Balance Outstanding (in thousands)		Interest Rate
March 31, 2014	$	588,375		3.04	%	$	250,000		6.65	%	$	205,890		6.88	%
March 31, 2013		405,114		3.56	%		195,890		6.65	%		—		—
March 31, 2012		125,859		4.48	%		—		—			—		—

Interest expense also includes amortization of debt issuance costs, which represented $5.7 million of expense during the year ended March 31, 2014, $3.4 million of expense during the year ended March 31, 2013, and $1.3 million of expense during the year ended March 31, 2012. Interest expense also includes letter of credit fees, interest on equipment financing notes, and accretion of interest on non-interest bearing debt obligations assumed in business combinations.

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that had not yet been amortized. This expense is reported as "Loss on early extinguishment of debt" in our consolidated statement of operations for the year ended March 31, 2013.

The increased levels of debt outstanding during the periods from fiscal 2012 through fiscal 2014 are due primarily to borrowings to finance acquisitions.

Income Tax Provision

We have certain taxable corporate subsidiaries in the United States and Canada. In addition, our operations in Texas are subject to a state franchise tax that is calculated based on revenues net of cost of sales.

Noncontrolling Interests

We have certain consolidated subsidiaries in which outside parties own interests. The noncontrolling interest shown in our consolidated statements of operations represents the other owners' share of the net income of these entities.

Segment Operating Results

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of High Sierra in June 2012, Pecos in November 2012, Third Coast in December 2012, Crescent in July 2013, and Gavilon Energy in December 2013. We expanded our water solutions business through several acquisitions of water disposal and transportation businesses, including High Sierra in June 2012, Big Lake in July 2013, OWL in August 2013, and Coastal in September 2013. We expanded our liquids business through the acquisitions of SemStream in October 2011 and High Sierra in June 2012. We expanded our retail propane operations through the acquisitions of Osterman in October 2011, Pacer in January 2012, North American in February 2012, and Downeast in May 2012. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy.

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Volumes

The following table summarizes the volume of product sold and water delivered for the years ended March 31, 2014 and 2013. Volumes shown in the table below for our liquids segment include sales to our retail propane segment.

	Year Ended March 31,

Segment	2014		2013		Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)		46,107		24,373		21,734
Water solutions
Water delivered (barrels)		62,774		25,009		37,765
Liquids
Propane sold (gallons)		1,190,106		912,625		277,481
Other products sold (gallons)		786,671		505,529		281,142
Retail propane
Propane sold (gallons)		162,361		144,379		17,982
Distillates sold (gallons)		34,965		28,853		6,112
Refined products
Refined products sold (gallons)		412,974		—		412,974
Renewables
Renewables sold (gallons)		150,925		—		150,925

Volumes sold by our crude oil logistics and water solutions segments were higher during the year ended March 31, 2014 than during the year ended March 31, 2013, due primarily to the expansion of our business through acquisitions.

Volumes sold by our liquids segment were higher during the year ended March 31, 2014 than during the year ended March 31, 2013, due to several factors. Market demand for propane was higher, due in part to colder weather conditions. Market demand for butane to be used in gasoline blending operations was also higher. Volumes also increased due to the expansion of our customer base. In addition, during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

Volumes sold by our retail propane segment during the year ended March 31, 2014 increased compared to the volumes sold during the year ended March 31, 2013, due primarily to colder weather conditions.

Our refined products and renewables segments began with the December 2013 acquisition of Gavilon Energy.

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Operating Income (Loss) by Segment

Our operating income (loss) by segment for the years ended March 31, 2014 and 2013 was as follows:

	Year Ended March 31,

Segment	2014			2013			Change
	(in thousands)
Crude oil logistics	$	678		$	34,236		$	(33,558	)
Water solutions		10,317			8,576			1,741
Liquids		71,888			30,336			41,552
Retail propane		61,285			46,869			14,416
Refined products		4,080			—			4,080
Renewables		2,434			—			2,434
Corporate and other		(44,117	)		(32,710	)		(11,407	)


Operating income	$	106,565		$	87,307		$	19,258

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,

	2014		2013		Change
	(in thousands)
Revenues:
Crude oil sales	$	4,559,923	$	2,322,706	$	2,237,217
Crude oil transportation and other		36,469		16,442		20,027


Total revenues(1)		4,596,392		2,339,148		2,257,244
Expenses:
Cost of sales		4,515,244		2,267,507		2,247,737
Operating expenses		53,872		25,484		28,388
General and administrative expenses		4,487		2,745		1,742
Depreciation and amortization expense		22,111		9,176		12,935


Total expenses		4,595,714		2,304,912		2,290,802


Segment operating income	$	678	$	34,236	$	(33,558	)

(1): Revenues include $37.8 million of intersegment sales during the year ended March 31, 2014 and $22.9 million of intersegment sales during the year ended March 31, 2013 that are eliminated in our consolidated statements of operations.

Revenues. Our crude oil logistics segment generated $4.6 billion of revenue from crude oil sales during the year ended March 31, 2014, selling 46.1 million barrels at an average price of $98.90 per barrel. During the year ended March 31, 2013, our crude oil logistics segment generated $2.3 billion of revenue from crude oil sales, selling 24.4 million barrels at an average price of $95.30 per barrel. The increase in volume during the year ended March 31, 2014 compared to the year ended March 31, 2013 was due in part to the fact that we did not own a crude oil logistics business for the full 12 months ended March 31, 2013, as we acquired this business in our June 19, 2012 merger with High Sierra. The increase in volume was also due to acquisitions of crude oil logistics businesses, including Gavilon

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Energy, Pecos, and Third Coast, among others. Of this increase, $1.0 billion was attributable to Gavilon Energy.

Crude oil transportation and other revenues of our crude oil logistics segment were $36.5 million during the year ended March 31, 2014, compared to $16.4 million of crude oil transportation and other revenues during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to acquisitions of crude oil logistics businesses, including Gavilon Energy, Pecos, and Third Coast.

Cost of Sales. Our cost of crude oil sold was $4.5 billion during the year ended March 31, 2014, as we sold 46.1 million barrels at an average cost of $97.93 per barrel. Our cost of sales during the year ended March 31, 2014 was increased by $2.2 million of unrealized losses on derivatives. During the year ended March 31, 2013, our cost of crude oil was $2.3 billion, as we sold 24.4 million barrels at an average cost of $93.03 per barrel.

Operating Expenses. Our crude oil logistics segment incurred $53.9 million of operating expenses during the year ended March 31, 2014, compared to $25.5 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions, including Gavilon Energy, Pecos, and Third Coast. Of this increase, $10.1 million was attributable to Gavilon Energy.

General and Administrative Expenses. Our crude oil logistics segment incurred $4.5 million of general and administrative expenses during the year ended March 31, 2014, compared to $2.7 million of general and administrative expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions. Of this increase, $1.0 million was attributable to our acquisition of Gavilon Energy.

Depreciation and Amortization Expense. Our crude oil logistics segment incurred $22.1 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $9.2 million of depreciation and amortization expense during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a crude oil logistics business until our June 19, 2012 merger with High Sierra, and was also due in part to the expansion of operations resulting from acquisitions. Of this increase, $2.8 million was attributable to our acquisition of Gavilon Energy.

Operating Income. Our crude oil logistics segment generated $0.7 million of operating income during the year ended March 31, 2014, compared to $34.2 million of operating income during the year ended March 31, 2013. Acquisitions of businesses contributed to operating income during the year ended March 31, 2014, although this benefit was offset by several factors. These factors included a narrowing of price differences between markets, which reduced our opportunities to generate increased margins by transporting product from lower-price to higher-price markets, and increased competition in the South Texas region from newly-constructed pipelines. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved. Operating income during the year ended March 31, 2014 was reduced by $3.0 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. We also recorded $0.5 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the Gavilon Energy acquisition.

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Water Solutions

The following table summarizes the operating results of our water solutions segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,				Change

	2014		2013		Acquisitions(1)		Other
	(in thousands)
Revenues:
Water treatment and disposal	$	125,788	$	54,334	$	64,119	$	7,335
Water transportation		17,312		7,893		14,231		(4,812	)


Total revenues		143,100		62,227		78,350		2,523
Expenses:
Cost of sales		11,738		5,611		9,325		(3,198	)
Operating expenses		58,178		25,452		35,377		(2,651	)
General and administrative expenses		7,762		1,665		1,239		4,858
Depreciation and amortization expense		55,105		20,923		26,955		7,227


Total expenses		132,783		53,651		72,896		6,236


Segment operating income	$	10,317	$	8,576	$	5,454	$	(3,713	)

(1): Represents the change in revenues and expenses attributable to acquisitions subsequent to the merger with High Sierra. The cost of sales amount shown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities.

Revenues. Our water solutions segment generated $125.8 million of treatment and disposal revenue during the year ended March 31, 2014, taking delivery of 62.8 million barrels of wastewater at an average revenue of $2.00 per barrel. During the year ended March 31, 2013, our water solutions segment generated $54.3 million of treatment and disposal revenue, taking delivery of 25.0 million barrels of wastewater at an average revenue of $2.17 per barrel. The increase in revenues was due primarily to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra and was due also to acquisitions during the year ended March 31, 2013, including Indigo, and acquisitions during the year ended March 31, 2014, including OWL, Big Lake and Coastal. The decrease in revenue per barrel was due primarily to the fact that the expansion of our water solutions business subsequent to our merger with High Sierra has been primarily in Texas, where the market rates for water disposal services are typically lower than in Wyoming or Colorado.

In our June 2012 merger with High Sierra, we acquired a water transportation business in Oklahoma. In our August 2013 acquisition of OWL, we acquired a water transportation business in Texas. Our water solutions segment generated $17.3 million of transportation revenues during the year ended March 31, 2014, compared to $7.9 million of transportation revenues during the year ended March 31, 2013. This increase was due primarily to the acquisition of OWL. This increase was partially offset by a decrease in water transportation revenues generated by the water solutions business acquired in the merger with High Sierra, which resulted primarily from a slowdown in production activities by a customer. During the three months ended December 31, 2013, we wound down our water transportation operations in Oklahoma, transferring certain of the assets to our business in Texas and selling the remaining assets.

Cost of Sales. The cost of sales for our water solutions segment was $11.7 million during the year ended March 31, 2014. Our cost of sales during the year ended March 31, 2014 was increased by $0.6 million of unrealized losses on derivatives. Because a portion of our processing revenue is generated from the sale of recovered hydrocarbons, we enter into derivatives to protect against the risk

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of a decline in the market price of a portion of the hydrocarbons we expect to recover. During the year ended March 31, 2013, the cost of sales for our water solutions segment was $5.6 million. Our cost of sales during the year ended March 31, 2013 was increased by $1.0 million of unrealized losses on derivatives. The increase in our cost of sales was due primarily to the expansion of our operations through acquisitions of water solutions businesses.

Operating Expenses. Our water solutions segment incurred $58.2 million of operating expenses during the year ended March 31, 2014, compared to $25.5 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due primarily to subsequent acquisitions of businesses. We incurred losses on disposal of property, plant and equipment of $2.0 million during the year ended March 31, 2014 as a result of property damage from lightning strikes at two of our facilities.

General and Administrative Expenses. Our water solutions segment incurred $7.8 million of general and administrative expenses during the year ended March 31, 2014, compared to $1.7 million of general and administrative expenses during the year ended March 31, 2013. This increase was due in part to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due to subsequent acquisitions of businesses.

Depreciation and Amortization Expense. Our water solutions segment incurred $55.1 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $20.9 million of depreciation and amortization expense during the year ended March 31, 2013. This increase was due in part to the fact that we did not own a water solutions business until our June 19, 2012 merger with High Sierra, and was also due to subsequent acquisitions of businesses. The increase is also due in part to $2.1 million of amortization expense related to trade name intangible assets. During the year ended March 31, 2014, we ceased using certain trade names and began amortizing them as finite-lived defensive assets.

Operating Income. Our water solutions segment generated $10.3 million of operating income during the year ended March 31, 2014, compared to operating income of $8.6 million during the year ended March 31, 2013. Exclusive of acquisitions during the year ended March 31, 2014, our operating income decreased by $3.7 million. Increases in revenues were offset by increases in operating expenses, including a $7.2 million increase in depreciation and amortization expense. The businesses acquired during the year ended March 31, 2014 generated operating income of $5.5 million, which included $27.0 million of depreciation and amortization expense, which consisted primarily of amortization expense on acquired customer relationship intangible assets.

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Liquids

The following table summarizes the operating results of our liquids segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,

	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	1,632,948	$	841,448	$	791,500
Other product sales		1,231,965		858,276		373,689
Other revenues		31,062		33,954		(2,892	)


Total revenues(1)		2,895,975		1,733,678		1,162,297
Expenses:
Cost of sales—propane		1,559,266		801,694		757,572
Cost of sales—other products		1,179,944		836,747		343,197
Cost of sales—other		24,439		20,950		3,489
Operating expenses		42,977		27,605		15,372
General and administrative expenses		6,443		5,261		1,182
Depreciation and amortization expense		11,018		11,085		(67	)


Total expenses		2,824,087		1,703,342		1,120,745


Segment operating income	$	71,888	$	30,336	$	41,552

(1): Revenues include $245.6 million of intersegment sales during the year ended March 31, 2014 and $128.9 million of intersegment sales during the year ended March 31, 2013 that are eliminated in our consolidated statements of operations.

Revenues. Our liquids segment generated $1.6 billion of wholesale propane sales revenue during the year ended March 31, 2014, selling 1.1 billion gallons at an average price of $1.37 per gallon. During the year ended March 31, 2013, our liquids segment generated $841.4 million of wholesale propane sales revenue, selling 912.6 million gallons at an average price of $0.92 per gallon. Approximately 221.2 million gallons of the increase in volumes was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the year ended March 31, 2013. The remaining increase in volume was due to several factors, including higher market demand, due in part to colder weather conditions, and the expansion of our customer base. In addition, during the year ended March 31, 2013, we upgraded two terminals that we acquired in February 2012, which enabled us to expand our wholesale operations from these terminals.

Our liquids segment generated $1.2 billion of other wholesale products sales revenue during the year ended March 31, 2014, selling 786.7 million gallons at an average price of $1.57 per gallon. During the year ended March 31, 2013, our liquids segment generated $858.3 million of other wholesale products sales revenue, selling 505.5 million gallons at an average price of $1.70 per gallon. Approximately 454.1 million gallons of the increase in volumes was due to the fact that we only owned the natural gas liquids business of High Sierra for a part of the year ended March 31, 2013. The remaining increase in volume was due to several factors, including higher market demand for butane to be used in gasoline blending operations, the expansion of our customer base, and an increased focus on the opportunity to more fully utilize our terminals to market butane.

Cost of Sales. Our cost of wholesale propane sales was $1.6 billion during the year ended March 31, 2014, as we sold 1.1 billion gallons at an average cost of $1.31 per gallon. Our cost of wholesale propane sales during the year ended March 31, 2014 was increased by $1.6 million of unrealized losses on derivatives. During the year ended March 31, 2013, our cost of wholesale propane

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sales was $801.7 million, as we sold 912.6 million gallons at an average cost of $0.88 per gallon. Our cost of wholesale propane sales during the year ended March 31, 2013 was reduced by $3.2 million of unrealized gains on derivatives.

Declining wholesale propane prices during the first quarter of the prior fiscal year had an adverse effect on cost of sales during the year ended March 31, 2013. Our wholesale segment utilizes a weighted-average inventory costing method to calculate cost of sales. Propane prices decreased steadily during April and May 2012, as a result of which the replacement cost of propane was at times lower than the weighted-average cost, which had an adverse effect on margins. One of our business strategies is to purchase and store inventory during the warmer months for sale during the winter months. We seek to lock in a margin on inventory held in storage through back-to-back purchases and sales, fixed-price forward sale commitments, and financial derivatives. We also have contracts whereby we have committed to purchase ratable volumes each month at index prices. We seek to manage the price risk associated with these contracts primarily by selling the inventory immediately after it is received. When we sell product, we record the cost of the sale at the average cost of all inventory at that location, which may include inventory stored for sale in the future. During periods of rising prices, this can result in greater margins on these sales. During periods of falling prices, such as we experienced during the three months ended June 30, 2012, this can result in negative margins on these sales, which we recovered when delivering future volumes.

Our cost of sales of other products was $1.2 billion during the year ended March 31, 2014, as we sold 786.7 million gallons at an average cost of $1.50 per gallon. Our cost of sales of other products during the year ended March 31, 2014 was reduced by $5.8 million of unrealized gains on derivatives. During the year ended March 31, 2013, our cost of sales of other products was $836.7 million, as we sold 505.5 million gallons at an average cost of $1.66 per gallon. Our cost of sales of other products during the year ended March 31, 2013 was increased by $7.5 million of unrealized losses on derivatives.

Operating Expenses. Our liquids segment incurred $43.0 million of operating expenses during the year ended March 31, 2014, compared to $27.6 million of operating expenses during the year ended March 31, 2013. This increase was due primarily to expanded operations. In addition, during the year ended March 31, 2014, we recorded an impairment of $5.3 million related to the property, plant and equipment of one of our terminals.

General and Administrative Expenses. Our liquids segment incurred $6.4 million of general and administrative expenses during the year ended March 31, 2014, compared to $5.3 million of general and administrative expenses during the year ended March 31, 2013. This increase was due primarily to expanded operations.

Depreciation and Amortization Expense. Our liquids segment incurred $11.0 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $11.1 million of depreciation and amortization expense during the year ended March 31, 2013.

Operating Income. Our liquids segment generated $71.9 million of operating income during the year ended March 31, 2014, compared to $30.3 million of operating income during the year ended March 31, 2013. The increase in operating income was due primarily to the expansion of our operations and to colder weather conditions. As a result of the cold weather conditions, the demand for natural gas liquids increased considerably during the recent winter, which had a favorable impact on our sales volumes. The demand also resulted in increases to the market prices for natural gas liquids, which had a favorable impact on product margins, as we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory. These increases were partially offset by increased operating expenses as a result of expanding our operations. During the year ended March 31, 2014, operating income was increased by $4.2 million of unrealized gains on derivatives. During the year ended March 31, 2013, operating income was reduced by $4.3 million of unrealized losses on derivatives.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,

	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	388,225	$	288,410	$	99,815
Distillate sales		127,672		106,192		21,480
Other revenues		35,918		35,856		62


Total revenues		551,815		430,458		121,357
Expenses:
Cost of sales—propane		233,110		155,118		77,992
Cost of sales—distillates		109,058		90,772		18,286
Cost of sales—other		11,531		12,688		(1,157	)
Operating expenses		96,936		88,651		8,285
General and administrative expenses		11,017		10,864		153
Depreciation and amortization expense		28,878		25,496		3,382


Total expenses		490,530		383,589		106,941


Segment operating income	$	61,285	$	46,869	$	14,416

Revenues. Our retail propane segment generated revenue of $388.2 million from propane sales during the year ended March 31, 2014, selling 162.4 million gallons at an average price of $2.39 per gallon. During the year ended March 31, 2013, our retail propane segment generated $288.4 million of revenue from propane sales, selling 144.4 million gallons at an average price of $2.00 per gallon. The increase in volumes and average sales prices during the year ended March 31, 2014 compared to the year ended March 31, 2013 was due primarily to market demand being higher as a result of colder weather conditions. Revenues also benefitted from the continued integration of previously-acquired businesses.

Our retail propane segment generated revenue of $127.7 million from distillate sales during the year ended March 31, 2014, selling 35.0 million gallons at an average price of $3.65 per gallon. During the year ended March 31, 2013, our retail propane segment generated $106.2 million of revenue from distillate sales, selling 28.9 million gallons at an average price of $3.68 per gallon. The increase in volumes was due primarily to colder weather conditions and to the acquisitions of smaller retailers.

Cost of Sales. Our cost of retail propane sales was $233.1 million during the year ended March 31, 2014, as we sold 162.4 million gallons at an average cost of $1.44 per gallon. During the year ended March 31, 2013, our cost of retail propane sales was $155.1 million, as we sold 144.4 million gallons at an average cost of $1.07 per gallon.

Our cost of distillate sales was $109.1 million during the year ended March 31, 2014, as we sold 35.0 million gallons at an average cost of $3.12 per gallon. During the year ended March 31, 2013, our cost of distillate sales was $90.8 million, as we sold 28.9 million gallons at an average cost of $3.15 per gallon.

Operating Expenses. Our retail propane segment incurred $96.9 million of operating expenses during the year ended March 31, 2014, compared to $88.7 million of operating expenses during the year ended March 31, 2013. This increase was due in part to the inclusion of Downeast in our results of operations for the full 12 months ended March 31, 2014, as compared to only 11 of the months in the 12-month period ended March 31, 2013.

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General and Administrative Expenses. Our retail propane segment incurred $11.0 million of general and administrative expenses during the year ended March 31, 2014, compared to $10.9 million of general and administrative expenses during the year ended March 31, 2013. This increase was due primarily to acquisitions of smaller retailers.

Depreciation and Amortization Expense. Our retail propane segment incurred $28.9 million of depreciation and amortization expense during the year ended March 31, 2014, compared to $25.5 million of depreciation and amortization expense during the year ended March 31, 2013. This increase was due primarily to capital expenditures and acquisitions.

Operating Income. Our retail propane segment generated $61.3 million of operating income during the year ended March 31, 2014, compared to $46.9 million of operating income during the year ended March 31, 2013. The increase in operating income was due primarily to increased market demand due to colder weather conditions, partially offset by increased operating expenses.

Refined Products

The following table summarizes the operating results of our refined products segment for the year ended March 31, 2014 (in thousands). Our refined products segment began with our December 2013 acquisition of Gavilon Energy.


Revenues	$	1,180,895
Expenses:
Cost of sales		1,172,754
Operating expenses		3,887
General and administrative expenses		65
Depreciation and amortization expense		109


Total expenses		1,176,815


Segment operating income	$	4,080

Revenues. Our refined products segment generated $1.2 billion of revenue during the year ended March 31, 2014, selling 413.0 million gallons at an average price of $2.86 per gallon.

Cost of Sales. Our cost of sales was $1.2 billion during the year ended March 31, 2014, as we sold 413.0 million gallons at an average cost of $2.84 per gallon.

Operating Expenses. Our refined products segment incurred $3.9 million of operating expenses during the year ended March 31, 2014.

General and Administrative Expenses. Our refined products segment incurred $0.1 million of general and administrative expenses during the year ended March 31, 2014.

Depreciation and Amortization Expense. Our refined products segment incurred $0.1 million of depreciation and amortization expense during the year ended March 31, 2014.

Operating Income. Our refined products segment generated $4.1 million of operating income during the year ended March 31, 2014.

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Renewables

The following table summarizes the operating results of our renewables segment for the year ended March 31, 2014 (in thousands). Our renewables segment began with our December 2013 acquisition of Gavilon Energy.


Revenues	$	176,781
Expenses:
Cost of sales		171,422
Operating expenses		2,318
General and administrative expenses		91
Depreciation and amortization expense		516


Total expenses		174,347


Segment operating income	$	2,434

Revenues. Our renewables segment generated $176.8 million of revenue during the year ended March 31, 2014, selling 150.9 million gallons at an average price of $1.17 per gallon.

Cost of Sales. Our cost of sales was $171.4 million during the year ended March 31, 2014, as we sold 150.9 million gallons at an average cost of $1.14 pergallon.

Operating Expenses. Our renewables segment incurred $2.3 million of operating expenses during the year ended March 31, 2014.

General and Administrative Expenses. Our renewables segment incurred $0.1 million of general and administrative expenses during the year ended March 31, 2014.

Depreciation and Amortization Expense. Our renewables segment incurred $0.5 million of depreciation and amortization expense during the year ended March 31, 2014.

Operating Income. Our renewables segment generated $2.4 million of operating income during the year ended March 31, 2014.

Corporate and Other

The operating loss within "corporate and other" includes the following components:

	Year Ended March 31,

	2014			2013			Change
	(in thousands)
Compressor leasing business	$	2,336		$	(1	)	$	2,337
Natural gas business		1,363			—			1,363
Equity-based compensation expense		(17,804	)		(10,138	)		(7,666	)
Acquisition expenses		(6,908	)		(5,602	)		(1,306	)
Other corporate expenses		(23,104	)		(16,969	)		(6,135	)


	$	(44,117	)	$	(32,710	)	$	(11,407	)

Operating income of our compressor leasing business for the year ended March 31, 2014 includes a $4.4 million gain from the sale of the business in February 2014.

We acquired the natural gas business in our December 2013 acquisition of Gavilon Energy. We subsequently wound down the natural gas business and, as of March 31, 2014, this business has no revenue-generating activity.

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The increase in equity-based compensation is due in part to the timing of award grants and is also due in part to an increase in the market value of our common units. The first restricted units were granted during fiscal 2013, and therefore were not in existence for the full fiscal year. The life-to-date expense for unvested units is adjusted based on the market value of the common units on the reporting date, and the value of the common units was higher at March 31, 2014 than at March 31, 2013.

Operating income during the year ended March 31, 2014 was reduced by $2.0 million of compensation expense related to bonuses that the previous owners of Gavilon Energy granted to employees, contingent upon successful completion of the sale of the business. These bonuses will be payable in December 2014, contingent upon the continued service of the employees. We also recorded $2.2 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the Gavilon Energy acquisition, $1.3 million of which is reported under "natural gas business" in the table above and the remainder of which is reported under "other corporate expenses" in the table above.

Year Ended March 31, 2013
Compared to Year Ended March 31, 2012

Volumes Sold or Delivered

The following table summarizes the volume of product sold and water delivered for the years ended March 31, 2013 and 2012. Volumes shown in the table below for our liquids segment include sales to our retail propane segment.

	Year Ended March 31,				Change Resulting From

	Year Ended March 31,				Retail Combinations(1)		SemStream Combination			High Sierra Combinations(2)
Segment	2013		2012		Retail Combinations(1)		SemStream Combination			High Sierra Combinations(2)		Other
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)		24,373		—		—		—			24,373		—
Water solutions
Water delivered (barrels)		25,009		—		—		—			25,009		—
Liquids
Propane sold (gallons)		912,625		659,921		—			(3)		140,632		112,072
Other products sold (gallons)		505,529		134,999		—			(3)		320,283		50,247
Retail propane
Propane sold (gallons)		144,379		78,236		54,949		—			—		11,194
Distillates sold (gallons)		28,853		1,650		27,027		—			—		176

(1): This data includes the operations of Osterman (acquired in October 2011) from April 1, 2012 through September 30, 2012, Pacer (acquired in January 2012) from April 1, 2012 through December 31, 2012, North American (acquired in February 2012) from April 1, 2012 through January 31, 2013, Downeast (acquired in May 2012), and certain other smaller retail propane business acquired during fiscal 2013.
(2): This data includes the operations of High Sierra (acquired in June 2012), Pecos (acquired in November 2012), and other subsequent acquisitions of smaller crude oil and water solutions businesses.

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(3): Although the SemStream combination enabled us to significantly expand our wholesale operations, it is not possible to determine which of the volumes sold subsequent to the combination were specifically attributable to the SemStream combination and which were attributable to our historical wholesale business.

As shown in the table above, the increases in volumes were driven primarily by acquisitions of businesses during fiscal 2012 and fiscal 2013. The remaining increase in volume of our retail propane business was due primarily to colder weather during the 2013-2014 winter season, which increased the demand for propane.

Operating Income by Segment

Our operating income by segment is as follows:

	Year Ended March 31,

Segment	2013			2012			Change
	(in thousands)
Crude oil logistics	$	34,236		$	—		$	34,236
Water solutions		8,576			—			8,576
Liquids		30,336			9,735			20,601
Retail propane		46,869			9,616			37,253
Corporate and other		(32,710	)		(4,321	)		(28,389	)


Operating income	$	87,307		$	15,030		$	72,277

The operating loss within "corporate and other" increased $28.4 million during the year ended March 31, 2013 as compared to $4.3 million during the year ended March 31, 2012. This increase is due in part to $8.4 million of incremental expenses associated with the corporate activities of High Sierra. In addition, corporate general and administrative expense for the year ended March 31, 2013 includes $10.1 million of compensation expense related to certain restricted units granted pursuant to employee and director compensation programs. Corporate general and administrative expense for the year ended March 31, 2013 also includes costs related to acquisitions, including $3.7 million of expense related to the acquisition of High Sierra. The operations of our compressor leasing business are also included within "corporate and other."

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Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the year ended March 31, 2013 (amounts in thousands). The operations of our crude oil logistics segment began with our June 19, 2012 combination with High Sierra.


Revenues:
Crude oil sales	$	2,322,706
Crude oil transportation and other		16,442


Total revenues(1)		2,339,148
Expenses:
Cost of sales		2,267,507
Operating expenses		25,484
General and administrative expenses		2,745
Depreciation and amortization expense	��	9,176


Total expenses		2,304,912


Segment operating income	$	34,236

(1): Revenues include $22.9 million of intersegment sales that are eliminated in our consolidated statement of operations.

Revenues. We generated revenue of $2.3 billion from crude oil sales during the year ended March 31, 2013, selling 24.4 million barrels at an average price of $95.30 per barrel. We also generated $16.4 million of revenue from the transportation of crude oil owned by other parties.

Cost of Sales. Our cost of crude oil sold was $2.3 billion during the year ended March 31, 2013. We sold 24.4 million barrels at an average cost of $93.03 per barrel. Our cost of sales during the year ended March 31, 2013 was increased by $9.8 million of realized losses on derivatives.

Other Operating Expenses. Our crude oil operations incurred $28.2 million of operating and general and administrative expenses during the year ended March 31, 2013. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $9.2 million during the year ended March 31, 2013.

Water Solutions

The following table summarizes the operating results of our water solutions segment for the year ended March 31, 2013 (amounts in thousands). The operations of our water solutions segment began with our June 19, 2012 combination with High Sierra.


Revenues:
Water treatment and disposal	$	54,334
Water transportation		7,893


Total revenues		62,227
Expenses:
Cost of sales		5,611
Operating expenses		25,452
General and administrative expenses		1,665
Depreciation and amortization expense		20,923


Total expenses		53,651


Segment operating income	$	8,576

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Revenues. Our water solutions segment generated $54.3 million of treatment and disposal revenue during the year ended March 31, 2013, taking delivery of 25.0 million barrels of wastewater at an average revenue of $2.17 per barrel. Our water transportation business generated $7.9 million of revenues.

Cost of Sales. The cost of sales for our water solutions segment was $5.6 million for the year ended March 31, 2013, an average cost of $0.22 per barrel delivered. Cost of sales was increased by unrealized losses of $1.0 million and realized losses of $0.8 million on derivatives. A portion of our processing revenue is generated from the sale of recovered hydrocarbons; we enter into these derivatives to protect against the risk of a decline in the market price of a portion of the hydrocarbons we expect to recover.

Other Operating Expenses. Our water solutions segment incurred $27.1 million of operating and general and administrative expenses during the year ended March 31, 2013. Depreciation and amortization expense, which consists of depreciation on fixed assets and amortization of customer relationship intangible assets, was $20.9 million during the year ended March 31, 2013.

Liquids

The following table compares the operating results of our liquids segment for the years ended March 31, 2013 and 2012:

					Change Resulting From

	Year Ended March 31,
	Year Ended March 31,				High Sierra Combination
	2013		2012		High Sierra Combination		Other
	(in thousands)
Revenues:
Propane sales	$	841,448	$	923,022	$	115,606	$	(197,180	)
Other product sales		858,276		251,627		563,211		43,438
Other revenues		33,954		2,462		19,053		12,439


Total revenues(1)		1,733,678		1,177,111		697,870		(141,303	)
Expenses:
Cost of sales—propane		801,694		904,082		109,851		(212,239	)
Cost of sales—other products		836,747		246,995		546,588		43,164
Costs of sales—other		20,950		1,776		8,637		10,537
Operating expenses		27,605		8,124		15,097		4,384
General and administrative expenses		5,261		2,738		1,693		830
Depreciation and amortization expense		11,085		3,661		3,101		4,323


Total expenses		1,703,342		1,167,376		684,967		(149,001	)


Segment operating income	$	30,336	$	9,735	$	12,903	$	7,698

(1): Revenues include $128.9 million of intersegment sales during the year ended March 31, 2013 and $66.0 million of intersegment sales during the year ended March 31, 2012 that are eliminated in our consolidated statements of operations.

Revenues. Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale propane sales decreased $197.2 million during the year ended March 31, 2013, as compared to $923.0 million during the year ended March 31, 2012. This resulted from a decrease in the average selling price of $0.46 per gallon, as compared to an average selling price per gallon of $1.40 in the prior year. This decrease in revenue was partially offset by an increase in volume sold of 112.1 million gallons, as compared to 659.9 million gallons sold in the prior year.

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During the year ended March 31, 2013, the operations of High Sierra contributed revenues of $115.6 million from propane sales. These operations sold 140.6 million gallons of propane at an average price of $0.82 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, revenues from wholesale sales of other products increased $43.4 million during the year ended March 31, 2013, as compared to $251.6 million during the year ended March 31, 2012. This resulted from an increase in volume sold of 50.2 million gallons as compared to 135.0 million gallons in the prior year, partially offset by a decrease in the average selling price of $0.27 per gallon, as compared to $1.86 per gallon in the prior year.

During the year ended March 31, 2013, the operations of High Sierra contributed revenues of $563.2 million from sales of other products (primarily butane). These operations sold 320.3 million gallons of other products at an average price of $1.76 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, the increase in volume sold is due primarily to the November 2011 SemStream acquisition, which expanded the markets we are able to serve. We believe the decline in average selling prices is due primarily to a greater than normal supply in the marketplace, due in part to low demand as a result of mild weather.

Transportation and other revenues for the year ended March 31, 2013 relate primarily to fees charged for transporting customer-owned product by railcar.

Cost of Sales. Exclusive of the operations acquired in our June 2012 merger with High Sierra, costs of wholesale propane sales decreased $212.2 million during the year ended March 31, 2013, as compared to $904.1 million during the year ended March 31, 2012. This resulted from a decrease in the average cost of $0.47 per gallon, as compared to an average cost per gallon of $1.37 in the prior year. This decrease in cost was partially offset by an increase in volume sold of 112.1 million gallons, as compared to 659.9 million gallons sold in the prior year. Cost of propane sales were reduced by $14.8 million during the year ended March 31, 2013 due to $11.6 million of realized gains and $3.2 million of unrealized gains on derivatives. These derivatives consisted primarily of propane swaps that we entered into as economic hedges against the potential decline in the market value of our propane inventories. Excluding gains on derivatives, our average cost of propane sold during the year ended March 31, 2013 was $0.92 cents per gallon.

During the year ended March 31, 2013, the cost of propane sales of the High Sierra operations were $109.9 million. These operations sold 140.6 million gallons of propane at an average price of $0.78 per gallon.

Exclusive of the operations acquired in our June 2012 merger with High Sierra, cost of wholesale sales of other products increased $43.2 million during the year ended March 31, 2013, as compared to $247.0 million during the year ended March 31, 2012. This resulted from an increase in volume sold of 50.2 million gallons as compared to 135.0 million gallons in the prior year, partially offset by a decrease in the average cost of $0.26 per gallon, as compared to $1.83 per gallon in the prior year. Cost of other products sales during the year ended March 31, 2013 was reduced by $0.2 million due to realized gains on derivatives.

During the year ended March 31, 2013, the cost of other products sales of the High Sierra operations was $546.6 million. These operations sold 320.3 million gallons of other products (primarily butane) at an average price of $1.71 per gallon. Costs of sales of other products during the year ended March 31, 2013 were increased by $7.5 million of unrealized losses and $0.3 million of realized losses on derivatives.

Other cost of sales for the year ended March 31, 2013 relate primarily to the cost of leasing railcars used in the transportation of customer-owned product.

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Operating Expenses. Exclusive of the operations acquired in our June 2012 merger with High Sierra, operating expenses of our liquids segment increased $4.4 million during the year ended March 31, 2013 as compared to operating expenses of $8.1 million during the year ended March 31, 2012. The increase in operating expenses is due primarily to increased compensation and terminal operating expenses resulting from our SemStream combination. During the year ended March 31, 2013, our liquids segment incurred $15.1 million of operating expenses related to the operations of High Sierra.

General and Administrative Expenses. Exclusive of the operations acquired in our June 2012 merger with High Sierra, general and administrative expenses of our liquids segment increased $0.8 million during the year ended March 31, 2013 as compared to general and administrative expenses of $2.7 million during the year ended March 31, 2012. This increase is due primarily to increased compensation and related expenses resulting from our SemStream combination. During the year ended March 31, 2013, our liquids segment incurred $1.7 million of general and administrative expenses related to the operations of High Sierra.

Depreciation and Amortization Expense. Exclusive of the operations acquired in our June 2012 merger with High Sierra, depreciation and amortization expense of our liquids segment increased $4.3 million during the year ended March 31, 2013, as compared to depreciation and amortization expense of $3.7 million during the year ended March 31, 2012. This increase is due primarily to depreciation and amortization expense related to assets acquired in the SemStream combination, including depreciation of terminal assets and amortization of customer relationship intangible assets. During the year ended March 31, 2013, our liquids segment recorded $3.1 million of depreciation and amortization expense related to assets acquired in our merger with High Sierra.

Operating Income. Our liquids segment had operating income of $30.3 million during the year ended March 31, 2013 as compared to operating income of $9.7 million during the year ended March 31, 2012. The increased operating income is due in part to $12.9 million of operating income contributed by the operations acquired in the merger with High Sierra. Exclusive of these operations, operating income improved by $7.7 million, which was due to increased product margins, partially offset by increased expenses.

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Retail Propane

The following table compares the operating results of our retail propane segment for the years ended March 31, 2013 and 2012:

					Change Resulting From

	Year Ended March 31,				Change Resulting From
	Year Ended March 31,				Retail Combinations(1)
	2013		2012		Retail Combinations(1)		Other
	(in thousands)
Revenues:
Propane sales	$	288,410	$	175,417	$	117,686	$	(4,693	)
Distillate sales		106,192		6,547		99,410		235
Other sales		35,856		17,370		20,752		(2,266	)


Total revenues		430,458		199,334		237,848		(6,724	)
Expenses:
Cost of sales—propane		155,118		117,722		63,080		(25,684	)
Cost of sales—distillates		90,772		5,728		84,933		111
Cost of sales—other		12,688		6,692		6,516		(520	)
Operating expenses		88,651		39,176		47,454		2,021
General and administrative expenses		10,864		8,950		5,409		(3,495	)
Depreciation and amortization expense		25,496		11,450		13,059		987


Total expenses		383,589		189,718		220,451		(26,580	)


Segment operating income	$	46,869	$	9,616	$	17,397	$	19,856

(1): This data includes the operations of Osterman (acquired in October 2011) from April 1, 2012 through September 30, 2012, Pacer (acquired in January 2012) from April 1, 2012 through December 31, 2012, North American (acquired in February 2012) from April 1, 2012 through January 31, 2013, Downeast (acquired in May 2012), and certain other smaller retail propane business acquired during fiscal 2013.

Revenues. Propane sales for the year ended March 31, 2013 increased $113.0 million as compared to propane sales of $175.4 million during the year ended March 31, 2012. The principal reason for the increase in propane sales was the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane sales were lower during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to a decline in the average price per gallon sold of $0.33 during the year ended March 31, 2013, as compared to an average price per gallon sold of $2.24 during the year ended March 31, 2012. Excluding the effect of these acquisitions, volumes sold during the year ended March 31, 2013 were higher than volumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder than that of fiscal 2012. The winter of fiscal 2012 was one of the warmest on record, and these warm weather conditions resulted in a decrease in the demand for propane.

Our acquired Osterman, Pacer, North American, and Downeast operations generated propane sales of $117.7 million during the year ended March 31, 2013, consisting of 54.9 million gallons sold at an average price of $2.14 per gallon. The average selling price per gallon for the acquired operations was higher than the average selling price for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further away from the primary areas of propane supply than are the markets served by our historical operations.

We generated $106.2 million of revenue from the sales of distillates during the year ended March 31, 2013, consisting of 28.9 million gallons sold at an average selling price of $3.68 per gallon.

Cost of Sales. Propane cost of sales for the year ended March 31, 2013 increased $37.4 million as compared to propane cost of sales of $117.7 million during the year ended March 31, 2012. This

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increase in propane cost of sales is due primarily to the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane cost of sales was lower during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to a decline in the average cost per gallon sold of $0.47 during the year ended March 31, 2013, as compared to an average price per gallon sold of $1.50 during the year ended March 31, 2012. Excluding the effect of these acquisitions, volumes sold during the year ended March 31, 2013 were higher than volumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder than that of fiscal 2012.

Our acquired Osterman, Pacer, North American, and Downeast operations had propane cost of sales of $63.1 million during the year ended March 31, 2013, consisting of 54.9 million gallons sold at an average cost of $1.15 per gallon. The average cost per gallon for the acquired operations was higher than the average cost for our historical operations, due in part to the fact that the markets served by the acquired operations are, in general, further away from the primary areas of propane supply than are the markets served by our historical operations.

We had $90.8 million of cost of sales for distillates during the year ended March 31, 2013, consisting of 28.9 million gallons sold at an average cost of $3.15 per gallon.

Operating Expenses. Operating expenses of our retail propane segment increased $49.5 million during the year ended March 31, 2013 as compared to operating expenses of $39.2 million during the year ended March 31, 2012. This increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $47.5 million of operating expense during the year ended March 31, 2013.

General and Administrative Expenses. General and administrative expenses of our retail propane segment increased $1.9 million during the year ended March 31, 2013 as compared to general and administrative expenses of $9.0 million during the year ended March 31, 2012. The principal factor causing the increase is the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $5.4 million of general and administrative expense during the year ended March 31, 2013. General and administrative expense included $4.3 million of acquisition expenses during the year ended March 31, 2012.

Depreciation and Amortization. Depreciation and amortization expense of our retail propane segment increased $14.0 million during the year ended March 31, 2013 as compared to depreciation and amortization expense of $11.5 million during the year ended March 31, 2012. The increase is due primarily to the impact of our Osterman, Pacer, North American, and Downeast acquisitions, the operations of which incurred $13.1 million of depreciation and amortization expense during the year ended March 31, 2013.

Operating Income. Our retail propane segment had operating income of $46.9 million during the year ended March 31, 2013 compared to operating income of $9.6 million during the year ended March 31, 2012. The increased operating income is due in part to the acquired operations of Osterman, Pacer, North American, and Downeast. Excluding these acquired operations, our retail propane segment's operating income was higher during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to improved margins on propane sales, and to increased sales volumes. During the year ended March 31, 2012, the winter was one of the warmest on record. As a result, demand for propane was low, which resulted in reduced sales volumes during fiscal 2012.

Seasonality

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from October through March. Consequently, for these two segments, sales, operating profits and operating cash flows are generated mostly in the third and fourth quarters of each fiscal year. See "—Liquidity, Sources of Capital and Capital Resource Activities—Cash Flows."

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. Our cash flows from operations are discussed below.

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

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

We believe that our anticipated cash flows from operations and the borrowing capacity under our Revolving Credit Facility are sufficient to meet our liquidity needs for the next 12 months. If our plans or assumptions change or are inaccurate, or if we make acquisitions, we may need to raise additional capital. Our ability to raise additional capital, if necessary, depends on various factors and conditions, including market conditions. We cannot give any assurances that we can raise additional capital to meet these needs. Commitments or expenditures, if any, we may make toward any acquisition projects are at our discretion.

We continue to pursue a strategy of growth through acquisitions. We expect to consider financing future acquisitions through a variety of sources, including the use of available capacity on our Revolving Credit Facility, the issuance of equity to sellers of the businesses we acquire, private placements of common units or debt securities, and public offerings of common units or debt securities. Our ability to raise additional capital through the issuance of debt or equity securities will have a significant impact on our ability to continue to pursue our growth strategy.

Credit Agreement

On June 19, 2012, we entered into a credit agreement (as amended, the "Credit Agreement") with a syndicate of banks. The Credit Agreement includes a revolving credit facility to fund working capital needs (the "Working Capital Facility") and a revolving credit facility to fund acquisitions and expansion projects (the "Expansion Capital Facility," and together with the Working Capital Facility, the "Revolving Credit Facility").

The Working Capital Facility had a total capacity of $1.335 billion for cash borrowings and letters of credit at September 30, 2014. At that date, we had outstanding borrowings of $942.5 million and outstanding letters of credit of $209.2 million on the Working Capital Facility. The Expansion Capital Facility had a total capacity of $858.0 million for cash borrowings at September 30, 2014. At that date, we had outstanding borrowings of $137.0 million on the Expansion Capital Facility. The capacity

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available under the Working Capital Facility may be limited by a "borrowing base," as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time.

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

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At September 30, 2014, all borrowings under the Credit Agreement were LIBOR borrowings with an interest rate at September 30, 2014 of 1.91%, calculated as the LIBOR rate of 0.16% plus a margin of 1.75%. At September 30, 2014, the interest rate in effect on letters of credit was 2.00%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At September 30, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

	Amount

Expansion Capital Facility—
LIBOR borrowings	$	137,000	1.91	%
Working Capital Facility—
LIBOR borrowings		942,500	1.91	%

The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our leverage ratio, as defined in the Credit Agreement, cannot exceed 4.25 to 1 at any quarter end. At September 30, 2014, our leverage ratio was approximately 3.4 to 1. The Credit Agreement also specifies that our interest coverage ratio, as defined in the Credit Agreement, cannot be less than 2.75 to 1 at any quarter end. At September 30, 2014, our interest coverage ratio was approximately 4.8 to 1.

The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

At September 30, 2014, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

On July 9, 2014, we issued $400.0 million of 5.125% Senior Notes Due 2019 (the "2019 Notes") in a private placement exempt from registration under the Securities Act of 1933, as amended (the "Securities Act"), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $393.5 million, after the initial purchasers' discount of $6.0 million and estimated offering costs of $0.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

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

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The Partnership and NGL Energy Finance Corp. are co-issuers of the 2019 Notes, and the obligations under the 2019 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The purchase agreement and the indenture governing the 2019 Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At September 30, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2019 Notes.

We also entered into a registration rights agreement whereby we have committed to exchange the 2019 Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the 2019 Notes on or before July 9, 2015. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the 2019 Notes.

2021 Notes

On October 16, 2013, we issued $450.0 million of 6.875% Senior Notes Due 2021 (the "2021 Notes") in a private placement exempt from registration under the Securities Act pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $438.4 million, after the initial purchasers' discount of $10.1 million and offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

The 2021 Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the 2021 Notes prior to the maturity date, although we would be required to pay a premium for early redemption.

The Partnership and NGL Energy Finance Corp. are co-issuers of the 2021 Notes, and the obligations under the 2021 Notes are guaranteed by certain of our existing and future restricted subsidiaries that incur or guarantee indebtedness under certain of our other indebtedness, including the Revolving Credit Facility. The purchase agreement and the indenture governing the 2021 Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At September 30, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2021 Notes.

We also entered into a registration rights agreement whereby we have committed to exchange the 2021 Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the 2021 Notes on or before October 16, 2014. Our inability to register the notes on time may result in liquidated damages of approximately $0.1 million per month.

2022 Notes

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Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains substantially the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which is described above.

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) nonpayment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the 2022 Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the 2022 Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding 2022 Notes of any series may declare all of the 2022 Notes of such series to be due and payable immediately.

At September 30, 2014, we were in compliance with the covenants under the Note Purchase Agreement.

TLP Credit Facility

On March 9, 2011, TLP entered into an amended and restated senior secured credit facility ("TLP Credit Facility"), which has been subsequently amended from time to time. The TLP Credit Facility provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined in the TLP Credit Facility: $352.9 million at September 30, 2014). TLP may elect to have loans under the TLP Credit Facility that bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.50% per annum, depending on the total leverage ratio then in effect. TLP's obligations under the TLP Credit Facility are secured by a first priority security interest in favor of the lenders in the majority of TLP assets.

The terms of the TLP Credit Facility include covenants that restrict TLP's ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of its "available cash" as defined in the TLP partnership agreement. TLP may make acquisitions and investments that meet the definition of "permitted acquisitions"; "other investments" which may not exceed 5% of "consolidated net tangible assets"; and "permitted JV investments". Permitted JV investments include up to $225 million of investments in BOSTCO, the "Specified BOSTCO Investment". In addition to the Specified BOSTCO Investment, under the terms of the TLP Credit Facility, TLP may make an additional $75 million of other permitted JV investments

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(including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

The TLP Credit Facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the TLP Credit Facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) in the event TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times).

If TLP were to fail any financial performance covenant, or any other covenant contained in the TLP Credit Facility, TLP would seek a waiver from its lenders under such facility. If TLP was unable to obtain a waiver from its lenders and the default remained uncured after any applicable grace period, TLP would be in breach of the TLP Credit Facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. TLP was in compliance with all of the financial covenants under the TLP Credit Facility as of September 30, 2014.

At September 30, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility and no outstanding letters of credit.

The following table summarizes our basis in the assets and liabilities of TLP at September 30, 2014, inclusive of the impact of our acquisition accounting for the business combination with TransMontaigne (in thousands):


Cash and cash equivalents	$	726
Accounts receivable—trade, net		12,252
Accounts receivable—affiliates		1,105
Inventories		1,613
Prepaid expenses and other current assets		1,363
Property, plant and equipment, net		504,272
Goodwill		29,118
Intangible assets, net		38,571
Investments in unconsolidated entities		268,410
Other noncurrent assets		1,910
Accounts payable—trade		(4,009	)
Accounts payable—affiliates		(146	)
Accrued expenses and other payables		(11,625	)
Advance payments received from customers		(141	)
Long-term debt		(252,000	)
Other noncurrent liabilities		(4,247	)


Net assets	$	587,172

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Revolving Credit Balances

The following table summarizes Revolving Credit Facility borrowings:

	Average Daily Balance		Lowest Balance		Highest Balance

	(in thousands)
Six Months Ended September 30, 2014:
Expansion borrowings	$	346,855	$	114,000	$	578,500
Working capital borrowings		640,369		339,500		1,024,500
TLP credit facility		246,750		228,000		258,500
Six Months Ended September 30, 2013:
Expansion borrowings	$	440,423	$	255,000	$	546,000
Working capital borrowings		80,779		—		229,500

Business Combinations

Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, as described under "Business—Acquisitions Subsequent to Initial Public Offering."

Cash Flows

The following summarizes the sources (uses) of our cash flows:

	Six Months Ended September 30,

Cash Flows Provided by (Used in):	2014			2013
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	19,091		$	60,976
Changes in operating assets and liabilities		(80,726	)		(109,720	)


Operating activities	$	(61,635	)	$	(48,744	)
Investing activities		(750,288	)		(476,854	)
Financing activities		813,306			519,565

	Year Ended March 31,

Cash Flows Provided by (Used in):	2014			2013			2012
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	243,303		$	146,395		$	20,459
Changes in operating assets and liabilities		(158,067	)		(13,761	)		69,870


Operating activities	$	85,236		$	132,634		$	90,329
Investing activities		(1,455,373	)		(546,621	)		(296,897	)
Financing activities		1,369,016			417,716			198,063

Operating Activities. The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. The changes in our operating assets and liabilities caused by the seasonality of our retail and wholesale natural gas liquids businesses also have a significant impact on our net cash flows from operating activities. Increases in natural gas liquids prices will tend to result in reduced operating cash flows due to the need to use more cash to fund increases in inventories, and price decreases tend to increase our operating cash flow due to lower cash requirements to fund increases in inventories.

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

The growth in our operating cash flows over the period from fiscal 2012 to fiscal 2014 was driven primarily by increased operating activity resulting from acquisitions. Changes in working capital due to changes in the timing of cash receipts and payments can have a significant impact on cash flows from operations. During fiscal 2013 and fiscal 2014, our cash outflows from investing activities included the purchase of working capital in business combinations, a portion of which has benefitted (or will benefit) cash flows from operations as the working capital is recovered. Our operating cash flows during the year ended March 31, 2012 included the sale of $30.3 million of inventory (net of purchases). This was due in part to our acquisition of assets from SemStream on November 1, 2011, in which we acquired $104.2 million of inventory. The cash paid to complete the SemStream transaction is included within cash outflows from investing activities.

Investing Activities. Our cash flows from investing activities are primarily impacted by our capital expenditures. In periods where we are engaged in significant acquisitions, we will generally realize negative cash flows in investing activities, which, depending on our cash flows from operating activities, may require us to increase the borrowings under our Revolving Credit Facility. During the six months ended September 30, 2014, we paid $82.9 million for capital expenditures. Of this amount, $65.7 million represented expansion capital and $17.2 million represented maintenance capital. During the six months ended September 30, 2013, we paid $67.4 million for capital expenditures. Of this amount, $52.4 million represented expansion capital and $15.0 million represented maintenance capital. During the six months ended September 30, 2014, we paid (i) $554.5 million in the TransMontaigne acquisition, (ii) $82.9 million to acquire water disposal facilities, (iii) $15.0 million to acquire an interest in a water supply company, and (iv) $6.4 million to acquire retail propane businesses. During the six months ended September 30, 2013, we completed a number of business combinations for which we paid $392.6 million of cash, net of cash acquired, on a combined basis. During the year ended March 31, 2014, we completed a number of business combinations for which we paid $1.3 billion of cash, net of cash acquired, on a combined basis. Also during the year ended March 31, 2014, we paid $165.1 million for capital expenditures, which related primarily to water disposal and natural gas liquids terminal assets. Of this amount, $132.9 million represented expansion capital and $32.2 million represented maintenance capital. During the year ended March 31, 2014, we used $36.0 million of investing cash outflows from commodity derivatives and generated $24.7 million of investing cash inflows from the sale of long-lived assets. During the year ended March 31, 2013, we completed our merger with High Sierra, for which we paid $239.3 million, net of cash acquired. Also during the year ended March 31, 2013, we completed 12 other acquisitions, for which we paid $251.5 million of cash, net of cash acquired, on a combined basis. Also during the year ended March 31, 2013, we paid $72.5 million for capital expenditures in addition to the acquisitions of businesses. Of this amount, $58.7 million represented expansion capital and $13.8 million represented maintenance capital. During the year ended March 31, 2013, we generated $11.6 million of investing cash inflows from commodity derivatives and $5.1 million of investing cash inflows from the sale of long-lived assets. During the year ended March 31, 2012, we completed four significant acquisitions and several smaller acquisitions. We paid a combined cash amount of $297.4 million to complete these acquisitions.

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periods where our cash flows from operating activities are reduced (such as during our first and second quarters), we may fund the cash flow deficits through our Working Capital Facility. During the six months ended September 30, 2014, we borrowed $175.5 million on our revolving credit facilities (net of repayments). During the six months ended September 30, 2014, we issued the 2019 Notes for $400.0 million. During the six months ended September 30, 2014, we received net proceeds of $370.4 million from the sale of our common units. During the six months ended September 30, 2013, we borrowed $168.5 million on our Revolving Credit Facility (net of repayments). During the six months ended September 30, 2013, we received net proceeds of $415.1 million from the sale of our common units. During the year ended March 31, 2014, we borrowed $444.5 million on our Revolving Credit Facility (net of repayments) and issued $450.0 million of Unsecured Notes. During the year ended March 31, 2014, we paid $24.6 million of debt issuance costs. During the year ended March 31, 2013, we borrowed $263.5 million on our revolving credit facilities (net of repayments) and issued $250.0 million of Senior Notes. During the year ended March 31, 2013, we paid $20.2 million of debt issuance costs. During the year ended March 31, 2012, we borrowed $149.0 million on our revolving credit facilities (net of repayments), primarily to fund acquisitions.

Cash flows from financing activities include proceeds from sales of equity. During the year ended March 31, 2014, we completed three equity issuances for which we received net proceeds of $650.2 million on a combined basis.

Cash flows from financing activities also include distributions paid to owners. We expect our distributions to our partners to increase in future periods under the terms of our partnership agreement. Based on the number of common units outstanding at September 30, 2014 (exclusive of unvested restricted units issued pursuant to employee and director compensation programs), if we made distributions equal to our minimum quarterly distribution of $0.3375 per unit ($1.35 annualized), total distributions would equal $29.9 million per quarter ($119.7 million per year). To the extent our cash flows from operating activities are not sufficient to finance our required distributions, we may be required to increase the borrowings under our Working Capital Facility.

The following table summarizes the distributions declared since our IPO:

Date Declared	Record Date	Date Paid	Amount Per Unit		Amount Paid To Limited Partners		Amount Paid To General Partner

					(in thousands)		(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011		0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012		0.3500		7,735		10
April 18, 2012	April 30, 2012	May 15, 2012		0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012		0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012		0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013		0.4625		24,245		927
April 25, 2013	May 6, 2013	May 15, 2013		0.4775		25,605		1,189
July 25, 2013	August 5, 2013	August 14, 2013		0.4938		31,725		1,739
October 23, 2013	November 4, 2013	November 14, 2013		0.5113		35,908		2,491
January 23, 2014	February 4, 2014	February 14, 2014		0.5313		42,150		4,283
April 24, 2014	May 5, 2014	May 15, 2014		0.5513		43,737		5,754
July 24, 2014	August 4, 2014	August 14, 2014		0.5888		52,036		9,481
October 23, 2014	November 4, 2014	November 14, 2014		0.6088		53,902		11,141

Distributions to noncontrolling interest partners are primarily comprised of distributions that TLP is required to make within 45 days after the end of each quarter to its unitholders as of the record date. To the extent TLP's cash flows from operating activities are not sufficient to finance its required distributions, it may be required to increase borrowings under the TLP Credit Facility.

On May 5, 2011, we made a distribution of $3.9 million from available cash to our general partner and common unitholders at March 31, 2011. Also in May 2011, we used $65.0 million of the proceeds from our IPO to repay advances under our previous credit facility.

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Contractual Obligations

The following table summarizes our contractual obligations at September 30, 2014 for our fiscal years ending thereafter:

			Six Months Ending March 31, 2015		Years Ending March 31,

	Total		Six Months Ending March 31, 2015		2016		2017		2018		Thereafter
	(in thousands)
Principal payments on long-term debt—
Expansion capital borrowings	$	137,000	$	—	$	—	$	—	$	—	$	137,000
Working capital borrowings		942,500		—		—		—		—		942,500
2019 Notes		400,000		—		—		—		—		400,000
2021 Notes		450,000		—		—		—		—		450,000
2022 Notes		250,000		—		—		—		25,000		225,000
TLP Credit Facility		252,000		—		252,000		—		—		—
Other long-term debt		10,913		2,345		3,128		2,362		1,459		1,619
Interest payments on long-term debt—
Revolving credit facility(1)		115,595		14,097		28,194		28,194		28,194		16,916
2019 Notes		102,500		10,250		20,500		20,500		20,500		30,750
2021 Notes		232,031		15,469		30,938		30,938		30,938		123,748
2022 Notes		91,438		8,313		16,625		16,625		16,209		33,666
TLP Credit Facility(1)		5,868		3,352		2,516		—		—		—
Other long-term debt		655		220		206		123		78		28
Letters of credit		209,188		—		—		—		—		209,188
Future minimum lease payments under noncancelable operating leases		507,354		71,007		106,384		88,666		74,265		167,032
Future minimum throughput payments under noncancelable agreements(2)		441,168		41,822		95,050		82,916		62,565		158,815
Fixed-price commodity purchase commitments		102,000		101,344		656		—		—		—
Index-price commodity purchase commitments(3)		984,872		950,613		34,259		—		—		—


Total contractual obligations	$	5,235,082	$	1,218,832	$	590,456	$	270,324	$	259,208	$	2,896,262




Natural gas liquids gallons under fixed-price purchase commitments (thousands)(4)		88,574		87,944		630		—		—		—
Natural gas liquids gallons under index-price purchase commitments (thousands)(4)		528,459		520,243		8,216		—		—		—
Crude oil barrels under index-price purchase commitments (thousands)(4)		4,437		4,079		358		—		—		—

(1): The estimated interest payments on our revolving credit facilities are based on principal and letters of credit outstanding at September 30, 2014. See Note 7 to our condensed consolidated financial statements included in this Quarterly Report for additional information on our revolving credit facilities.

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(2): At September 30, 2014, we had agreements with crude oil and refined products pipeline operators obligating us to minimum throughput payments in exchange for pipeline capacity commitments.
(3): Index prices are based on a forward price curve at September 30, 2014. A theoretical change of $0.10 per gallon in the underlying commodity price at September 30, 2014 would result in a change of $52.8 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at September 30, 2014 would result in a change of $4.4 million in the value of our index-price crude oil purchase commitments.
(4): At September 30, 2014, we had fixed-price and index-price sales contracts for 278.4 million and 370.6 million gallons of natural gas liquids, respectively. At September 30, 2014, we had index-price sales contracts for 3.9 million barrels of crude oil.

Off-Balance Sheet Arrangements

We do not have any off balance sheet arrangements other than the operating leases described in Note 10 to our audited consolidated financial statements included elsewhere in this prospectus and in Note 9 to our unaudited condensed consolidated financial statements included elsewhere in this prospectus.

Environmental Legislation

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

Trends

Crude Oil Logistics

Crude oil prices fluctuate widely due to changes in supply and demand conditions. The opportunity to generate revenues in our crude oil logistics business is heavily influenced by the volume of crude oil being produced. Currently, production of crude oil in North America is high, but changes in the level of production could impact our ability to generate revenues in the future.

The spreads between the prices of crude oil in different locations can also fluctuate widely. If these price differences are wide, we are able to generate increased margins by transporting crude oil from lower-price markets to higher-price markets. During the six months ended September 30, 2013, spreads remained narrow. When price differences between markets are reduced, it is necessary to renegotiate price terms with producers and to not fully utilize our transportation fleet until this process has been completed and margins have improved. Crude oil prices declined steadily during the three months ended September 30, 2014. Declining prices can have an adverse impact on product margins, due to delays between when product is purchased and when it is sold. If prices continue to decline, low prices could have an adverse effect on the level of crude oil production. During the year ended March 31, 2014, spreads narrowed considerably, which had a significant impact on our operations in the Rocky Mountain and South Texas regions. During the year ended March 31, 2013, the spread between crude oil prices in the mid-continent region and crude oil prices in south Texas widened, which gave us the opportunity to generate favorable margins by transporting crude oil from one region to the other.

Water Solutions

Our opportunity to earn revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. Currently,

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production levels are increasing, and we are expanding our operations in Colorado and Texas to meet this demand.

Crude oil prices declined steadily during the three months ended September 30, 2014. A portion of our revenues are generated from the sale of recovered hydrocarbons, and therefore crude oil prices impact the revenues of our water solutions segment. If crude oil prices continue to decline, the low prices could have an adverse effect on the level of crude oil production.

During the year ended March 31, 2014, we completed three separate acquisitions of water solutions businesses with operations in Texas. As a result, the geographic mix of our water solutions segment has changed, and we expect a greater share of the revenues from this segment to be generated from our operations in the Permian and Eagle Ford Basins in Texas than in the past.

During the year ended March 31, 2014, the revenues of our water solutions segment were lower than our expectations and the operating expenses of our water solutions segment were higher than our expectations. This related primarily to our operations in the Eagle Ford Basin in Texas, which were obtained through several acquisitions during the year ended March 31, 2014.

Liquids

The volumes we sell in our wholesale natural gas liquids business are heavily dependent on the demand for propane and butane, which is influenced by weather conditions. The margins we generate in our wholesale natural gas liquids business are influenced by changes in prices over the course of a year. During years when demand is higher during the winter months, we have the opportunity to utilize our storage assets to increase margins.

Demand for natural gas liquids was high during the recent winter, due to cold weather conditions. Demand continued to be high during the six months ended September 30, 2014, as customers sought to replenish their supplies of natural gas liquids that had been depleted during the winter. As a result, sales volumes and prices were higher during the six months ended September 30, 2014 than during the corresponding period in the prior year. However, our product margin per gallon sold was lower during the six months ended September 30, 2014 than during the corresponding period in the prior year, as we began the year with inventory that had a high cost basis as a result of the high demand during the previous winter.

We use a weighted-average inventory costing method for our wholesale propane inventory, with the costing pools segregated based on the location of the inventory. During periods of declining prices, our margins are reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

Weather conditions during the recent winter season were colder than normal. As a result, the demand for natural gas liquids increased considerably, which had a favorable impact on our sales volumes. The demand has also resulted in increases to market prices for natural gas liquids. This has had a favorable impact on product margins, based on the fact that we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory.

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Retail Propane

The volumes we sell in our retail propane business are heavily dependent on weather conditions, as cold weather significantly increases customer demand for propane. During times of lower propane prices, margins per gallon typically increase. During times of higher propane prices, margins per gallon typically decrease. Weather conditions during the 2013 to 2014 winter season were colder than normal. As a result, the demand for natural gas liquids increased considerably, which had a favorable impact on our sales volumes. The demand also resulted in increases to market prices for natural gas liquids. This had a favorable impact on product margins, based on the fact that we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory. The sharp rise in prices may increase the collectability risk of accounts receivable, and the recent high prices may create downward pressure on future demand, as some customers may invest in making their homes more energy efficient or may take other steps to reduce their need for propane.

Refined Products and Renewables

The spread between the prices of ethanol in different locations can fluctuate widely. If these price differences are high, we are able to generate increased margins by transporting ethanol from lower-price markets to higher-price markets. During the last few months of the fiscal year ended March 31, 2014, the spread between ethanol prices in different markets widened, which gave us the opportunity to generate favorable margins by transporting ethanol from one region to the other. During April 2014, ethanol price spreads between regions narrowed considerably.

Demand for biodiesel is driven in part by EPA mandates for the volume of biodiesel that refiners and blenders must use. The EPA has not yet issued its final mandate for 2014 biodiesel usage. The current uncertainty regarding the requirements has reduced the demand for biodiesel, which has had an adverse impact on biodiesel prices and volumes.

Recent Accounting Pronouncement

In April 2014, the Financial Accounting Standards Board issued an Accounting Standards Update that changes the criteria for reporting discontinued operations. Under the new standard, a disposal of part of an entity is not classified as a discontinued operation unless the disposal represents a strategic shift that will have a major effect on an entity's operations and financial results. We adopted the new standard during the fiscal year ended March 31, 2014.

As described in Note 14 to our audited consolidated financial statements included elsewhere in this prospectus, during the year ended March 31, 2014, we sold our compressor leasing business and wound down our natural gas marketing business. These actions do not represent a strategic shift that had a major effect on our operations, and do not meet the criteria under the new accounting standard for these businesses to be reported as discontinued operations.

In May 2014, the Financial Accounting Standard Board issued Accounting Standards Update ("ASU") No. 2014-09, "Revenue from Contracts with Customers." ASU No. 2014-09 will replace most existing revenue recognition guidance in GAAP. The core principle of this ASU is that an entity should recognize revenue for the transfer of goods or services equal to the amount that it expects to be entitled to receive for those goods or services. The ASU is effective for the Partnership beginning April 1, 2017, and allows for both retrospective and prospective methods of adoption. We are in the process of determining the method of adoption and assessing the impact of this ASU on our consolidated financial statements.

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Critical Accounting Policies

The preparation of financial statements and related disclosures in compliance with GAAP requires the selection and application of appropriate accounting principles to the relevant facts and circumstances of the Partnership's operations and the use of estimates made by management. We have identified the following accounting policies that are most important to the portrayal of our financial condition and results of operations. Changes in these policies could have a material effect on the financial statements.

The application of these accounting policies necessarily requires subjective or complex judgments regarding estimates and projected outcomes of future events that could have a material effect on our financial statements.

Revenue Recognition

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record our terminaling, storage and service revenues at the time the service is performed and we record tank and other rentals over the term of the lease. Revenues for our water solutions business are recognized upon receipt of the wastewater at our disposal facilities.

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

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

Impairment of Long-Lived Assets

Goodwill is subject to at least an annual assessment for impairment. We perform our annual assessment of impairment during the fourth quarter of our fiscal year, and more frequently if circumstances warrant. To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. We completed the assessment of each of our reporting units and determined it was more likely than not that no impairment existed for the year ended March 31, 2014. The assessment of the value of our reporting units requires us to make certain assumptions relating to future operations. When evaluating operating performance, various factors are considered, such as current and changing economic conditions and the commodity price environment, among others. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge.

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

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

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Asset Retirement Obligations

We are required to recognize the fair value of a liability for an asset retirement obligation if a reasonable estimate of fair value can be made. In order to determine the fair value of such a liability, we must make certain estimates and assumptions including, among other things, projected cash flows, the estimated timing of retirement, a credit-adjusted risk-free interest rate, and an assessment of market conditions, which could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time. We have recorded a liability of $2.7 million at September 30, 2014. This liability is related to wastewater disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

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

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

Depreciation expense represents the systematic write-off of the cost of our property, plant and equipment, net of residual or salvage value (if any), to the results of operations for the quarterly and annual periods during which the assets are used. We depreciate the majority of our property, plant and equipment using the straight-line method, which results in our recording depreciation expense evenly over the estimated life of the individual asset. The estimate of depreciation expense requires us to make assumptions regarding the useful economic lives and residual values of our assets. At the time we acquire and place our property, plant and equipment in service, we develop assumptions about the lives and residual values of such assets that we believe to be reasonable; however, circumstances may develop that could require us to change these assumptions in future periods, which would change our depreciation expense prospectively. Examples of such circumstances include changes in laws and regulations that limit the estimated economic life of an asset, changes in technology that render an asset obsolete, or changes in expected salvage values.

Amortization of Intangible Assets

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

Business Combinations

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business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage and transportation contracts, and employee compensation commitments. The excess of the purchase price over the net fair value of acquired assets over the assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Generally, we have up to one year from the acquisition date to finalize the identification and valuation of assets acquired and liabilities assumed. The impact of subsequent changes to the identification of assets and liabilities may require retrospective adjustments to our previously-reported consolidated financial position and results of operations.

Inventory

Our inventory consists primarily of crude oil, natural gas liquids, refined products, ethanol, and biodiesel. The market values of these commodities change on a daily basis as supply and demand conditions change. We value our inventory using the weighted-average cost and first-in first-out methods. At the end of each fiscal year, we also perform a "lower of cost or market" analysis; if the cost basis of the inventory would not be recoverable based on market prices at the end of the year, we reduce the book value of the inventory to the recoverable amount. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business to sell the inventory in retail markets. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost or market write-down if we expect the market values to recover by our fiscal year end of March 31. We are unable to control changes in the market value of these commodities and are unable to determine whether write-downs will be required in future periods. In addition, write-downs at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

Equity-Based Compensation

Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. These units vest in tranches, subject to the continued service of the recipients.

We record the expense for the first tranche of each award on a straight-line basis over the period beginning with the grant date of the awards and ending with the vesting date of the tranche. We record the expense for succeeding tranches over the period beginning with the vesting date of the previous tranche and ending with the vesting date of the tranche.

At each balance sheet date, we adjust the cumulative expense recorded using the estimated fair value of the awards at the balance sheet date. We calculate the fair value of the awards using the closing price of our common units on the New York Stock Exchange on the balance sheet date, adjusted to reflect the fact that the holders of the unvested units are not entitled to distributions during the vesting period. We estimate the impact of the lack of distribution rights during the vesting period using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

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

Amortization of Intangible Assets

Amortization expense represents the systematic write-off of the cost of our amortizable intangible assets to the results of operations for the quarterly and annual periods during which the assets are

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

Business Combinations

We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using the "acquisition method," in which the assets acquired and liabilities assumed are recorded at their estimated fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage and transportation contracts, and employee compensation commitments. The excess of the purchase price over the net fair value of acquired assets and assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. The impact of subsequent changes to the identification of assets and liabilities may require retrospective adjustments to our previously-reported consolidated financial position and results of operations.

Inventories

Our inventories consist primarily of crude oil, natural gas liquids, refined products, ethanol, and biodiesel. The market values of these commodities change on a daily basis as supply and demand conditions change. We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. At the end of each fiscal year, we also perform a "lower of cost or market" analysis; if the cost basis of the inventories would not be recoverable based on market prices at the end of the year, we reduce the book value of the inventories to the recoverable amount. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business to sell the inventory in retail markets. When performing this analysis during interim periods within a fiscal year, accounting standards do not require us to record a lower of cost or market write-down if we expect the market values to recover by our fiscal year end of March 31. We are unable to control changes in the market value of these commodities and are unable to determine whether write-downs will be required in future periods. In addition, write-downs at interim periods could be required if we cannot conclude that market values will recover sufficiently by our fiscal year end.

Equity-Based Compensation

Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. These units vest in tranches, subject to the continued service of the recipients.

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

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

At September 30, 2014, a significant portion of our long-term debt is variable-rate debt. Changes in interest rates impact the interest payments of our variable-rate debt but generally do not impact the fair value of the liability. Conversely, changes in interest rates impact the fair value of the fixed-rate debt but do not impact its cash flows.

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2014, we had $1.1 billion of outstanding borrowings under our Revolving Credit Facility at a rate of 1.91%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.3 million, based on borrowings outstanding at September 30, 2014.

The TLP Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At September 30, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility at a rate of 2.66%. A change in interest rates of 0.125% would result in an increase or decrease in TLP's annual interest expense of $0.3 million, based on borrowings outstanding at September 30, 2014. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.2 million on the $922.0 million of outstanding borrowings on the Revolving Credit Facility at March 31, 2014.

Commodity Price and Credit Risk

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

As is customary in the crude oil industry, we generally receive payment from customers for sales of crude oil on a monthly basis. As a result, receivables from individual customers in our crude oil logistics segment are generally higher than the receivables from customers in our other segments.

Procedures and limits for managing commodity price risks and credit risks are specified in our market risk policy and credit risk policy, respectively. Open commodity positions and market price changes are monitored daily and are reported to senior management and to marketing operations personnel. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, restrictions on product liftings, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain transactions, as deemed appropriate. The principal counterparties associated with our operations at September 30, 2014 were retailers, resellers, energy marketers, producers, refiners and dealers.

The natural gas liquids and crude oil industries are "margin-based" and "cost-plus" businesses in which gross profits depend on the differential of sales prices over supply costs. As a result, our profitability may be impacted by changes in wholesale prices of natural gas liquids and crude oil. When there are sudden and sharp increases in the wholesale cost of natural gas liquids and crude oil, we may not be able to pass on these increases to our customers through retail or wholesale prices. Natural gas liquids and crude oil are commodities and the price we pay for them can fluctuate significantly in response to supply or other market conditions. We have no control over supply or market conditions. In addition, the timing of cost increases can significantly affect our realized margins. Sudden and extended wholesale price increases could reduce our gross margins and could, if continued over an

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extended period of time, reduce demand by encouraging end users to conserve or convert to alternative energy sources.

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

Although we use derivative commodity instruments to reduce the market price risk associated with forecasted transactions, we have not accounted for such derivative commodity instruments as hedges. We record the changes in fair value of these derivative commodity instruments within cost of sales. The following table summarizes the hypothetical impact on the fair value of our commodity derivatives of an increase of 10% in the value of the underlying commodity (in thousands):

	Increase (Decrease) To Fair Value

Crude oil (crude oil logistics segment)	$	(3,699	)
Crude oil (water solutions segment)		(10,595	)
Propane (liquids segment)		5,519
Other products (liquids segment)		(930	)
Refined products (refined products and renewables segment)		(51,414	)
Renewables (refined products and renewables segment)		346

Fair Value

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

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MANAGEMENT

Board of Directors of our General Partner

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

The board of directors of our general partner currently has eleven members. The board of directors of our general partner has determined that Mr. Kneale, Mr. Cropper, and Mr. Guderian satisfy the New York Stock Exchange ("NYSE") and SEC independence requirements. The NYSE does not require a listed publicly traded limited partnership like us to have a majority of independent directors on the board of directors of our general partner. In addition, we are not required to have a nominating and corporate governance committee.

In evaluating director candidates, the NGL Energy GP Investor Group assesses whether a candidate possesses the integrity, judgment, knowledge, experience, skill and expertise that are likely to enhance the ability of the board of directors of our general partner to manage and direct our affairs and business, including, when applicable, to enhance the ability of committees of the board to fulfill their duties. Our general partner has no minimum qualifications for director candidates. In general, however, the NGL Energy GP Investor Group reviews and evaluates both incumbent and potential new directors in an effort to achieve diversity of skills and experience among the directors of our general partner and in light of the following criteria:

•: experience in business, government, education, technology or public interests;
•: high-level managerial experience in large organizations;
•: breadth of knowledge regarding our business and industry;
•: specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law;
•: moral character and integrity;
•: commitment to our unitholders' interests;
•: ability to provide insights and practical wisdom based on experience and expertise;
•: ability to read and understand financial statements; and
•: ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on partnership matters.

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

Directors and Executive Officers

Directors of our general partner are appointed by the NGL Energy GP Investor Group and hold office until their successors have been duly elected and qualified or until the earlier of their death, resignation, removal or disqualification. Executive officers are appointed by, and serve at the discretion

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of, the board of directors of our general partner. The following table shows information regarding the current directors of our general partner and our executive officers.

Name		Position with NGL Energy Holdings LLC

H. Michael Krimbill	60	Chief Executive Officer and Director
Atanas H. Atanasov	41	Chief Financial Officer and Treasurer
James J. Burke	58	President, NGL Energy Partners and Director
Shawn W. Coady	52	President and Chief Operating Officer, Retail Division and Director
Todd M. Coady	56	Vice President, Administration
David C. Kehoe	55	Executive Vice President, NGL—Crude Logistics
Patrice A. Lemon	53	Senior Vice President, Accounting
Vincent J. Osterman	57	President, Eastern Retail Propane Operations and Director
Stephen L. Cropper	64	Director
Bryan K. Guderian	54	Director
James C. Kneale	62	Director
John T. Raymond	43	Director
Patrick Wade	44	Director

H. Michael Krimbill. Mr. Krimbill has served as our Chief Executive Officer since October 2010 and as a member of the board of directors of our general partner since its formation in September 2010. From February 2007 through September 2010, Mr. Krimbill managed private investments. Mr. Krimbill was the President and Chief Financial Officer of Energy Transfer Partners, L.P. from 2004 until his resignation in January 2007. Mr. Krimbill joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as Vice President and Chief Financial Officer in 1990. Mr. Krimbill was President of Heritage Propane Partners, L.P. from 1999 to 2000 and President and Chief Executive Officer of Heritage Propane Partners, L.P. from 2000 to 2005. Mr. Krimbill also served as a director of Energy Transfer Equity, the general partner of Energy Transfer Partners, L.P., from 2000 to January 2007. Mr. Krimbill is also currently a member of the board of directors of Pacific Commerce Bank.

Mr. Krimbill brings leadership, oversight and financial experience to the board. Mr. Krimbill provides expertise in managing and operating a publicly traded partnership, including substantial expertise in successfully acquiring and integrating propane and midstream businesses. Mr. Krimbill also brings financial expertise to the board, including through his prior service as a chief financial officer. As a director for other public companies, Mr. Krimbill also provides cross board experience.

Atanas H. Atanasov. Mr. Atanasov was appointed as our Chief Financial Officer in May 2013. Mr. Atanasov joined our management team in November 2011, and previously served as our Senior Vice President of Finance and Treasurer. Prior to joining NGL, Mr. Atanasov spent nine years at GE Capital, working in lending and leveraged equity. Prior to GE Capital, he was with The Williams Companies, Inc. Mr. Atanasov is a Certified Public Accountant and holds an M.B.A. from the University of Tulsa and a B.S. in Accounting from Oral Roberts University.

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

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also serves as the Managing Director of Impact Energy Services, LLC. Mr. Burke received his B.S. from University of Colorado in 1978.

Shawn W. Coady. Dr. Coady has served as our President and Chief Operating Officer, Retail Division, since April 2012 and previously served as our Co-President and Chief Operating Officer, Retail Division from October 2010 through April 2012. Dr. Coady has also served as a member of the board of directors of our general partner since its formation in September 2010. Dr. Coady has served as an officer of Hicks Oils & Hicksgas, Incorporated, or HOH, since March 1989. HOH contributed its propane and propane related assets to Hicks LLC, and the membership interests in Hicks LLC were contributed to us as part of our formation transactions. Dr. Coady was an executive officer of Bachtold Brothers, Incorporated, a family owned company, when it filed for Chapter 7 bankruptcy protection in October 2005. Dr. Coady was also the President of Gifford from March 1989 until the membership interests in Gifford were contributed to us as part of our formation transactions. Dr. Coady has served as a director and as a member of the executive committee of the Illinois Propane Gas Association since 2004. Dr. Coady has also served as the Illinois state director of the National Propane Gas Association since 2004. Dr. Coady has a B.A. in Chemistry from Emory University and an O.D. from the University of Houston. Dr. Coady is the brother of Mr. Coady.

Dr. Coady brings valuable management and operational experience to the board. Dr. Coady has over 25 years of experience in the retail propane industry, and provides expertise in both acquisition and organic growth strategies. Dr. Coady also provides insight into developments and trends in the propane industry through his leadership roles in national and state propane gas associations.

Todd M. Coady. Mr. Coady has served as our Vice President, Administration since April 2012 and previously served as our Co-President, Retail Division from October 2010 through April 2012. Mr. Coady has served as an officer of HOH since March 1989. HOH contributed its propane and propane related assets to Hicks LLC, and the membership interests in Hicks LLC were contributed to us as part of our formation transactions. Mr. Coady was also the Vice President of Gifford from March 1989 until the membership interests in Gifford were contributed to us as part of our formation transactions. Mr. Coady was an executive officer of Bachtold Brothers, Incorporated, a family owned company, when it filed for Chapter 7 bankruptcy protection in October 2005. Mr. Coady has a B.S. in Chemical Engineering from Cornell University and an M.B.A. from Rice University. Mr. Coady is the brother of Dr. Coady.

David C. Kehoe. Mr. Kehoe serves as the Executive Vice President of the NGL — Crude Logistics segment. Mr. Kehoe joined our management team through our June 2012 merger with High Sierra. Mr. Kehoe has served on High Sierra's management team since 2007. Prior to that, Mr. Kehoe held various leadership positions with Petro Source Partners, LP from 1989 to 2007.

Patrice A. Lemon. Ms. Lemon has served as our Senior Vice President of Accounting since May 2012. Ms. Lemon previously served several roles in accounting and SEC reporting with Energy Transfer Partners, L.P. and Heritage Propane Partners, L.P. from March 2001 through May 2012. In March 2001, Ms. Lemon joined Heritage Propane Partners, L.P., the predecessor of Energy Transfer Partners, L.P., as the Manager of Financial Reporting. Ms. Lemon's most recent role prior to joining NGL was the Director of Financial Reporting and Controller with Heritage Propane Partners, L.P. For ten years prior to joining Heritage Propane Partners, L.P., Ms. Lemon worked as an audit manager for a regional public accounting firm in Montana. Ms. Lemon received a B.A. in Accounting from Carroll College of Helena, Montana.

Vincent J. Osterman. Mr. Osterman has served as the President of Osterman Associated Companies, which contributed the assets of its propane operations to us on October 3, 2011, since August 1987. Mr. Osterman has served as President of our Eastern Retail Propane Operations and as a member of the board of directors of our general partner since October 2011. Mr. Osterman also serves

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as a director of the National Propane Gas Association, Propane Gas Association of New England, Energi Holdings, Inc., and the Board of Advisors of the Gaudette Insurance Agency.

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

Stephen L. Cropper. Mr. Cropper joined the board of directors of our general partner in June 2011. Mr. Cropper held various positions during his 25-year career at The Williams Companies, Inc., including serving as the President and Chief Executive Officer of Williams Energy Services, a Williams operating unit involved in various energy-related businesses, until his retirement in 1998. Mr. Cropper served as a director of Energy Transfer Partners L.P. from 2000 through 2005. Since Mr. Cropper's retirement from The Williams Companies, Inc. in 1998, he has been a consultant and private investor and also served as a director of Sunoco Logistics Partners, L.P., NRG Energy, Inc., and Berry Petroleum Company.

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

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

Mr. Guderian brings considerable upstream experience to the board including executive, operational and financial expertise from 30 years of petroleum industry involvement, the majority of which has been focused in exploration and production.

James C. Kneale. Mr. Kneale joined the board of directors of our general partner in May 2011. Mr. Kneale served as President and Chief Operating Officer of ONEOK, Inc., from January 2007, and ONEOK Partners, L.P., from May 2008, until his retirement in January 2010. After joining ONEOK in 1981, Mr. Kneale served in various other roles, including Chief Financial Officer from 1999 through 2006. Mr. Kneale also served as a director of ONEOK Partners, L.P. from 2006 until his retirement in January 2010. Mr. Kneale is a former CPA and has a B.B.A. in Accounting in 1973 from West Texas A&M in Canyon, Texas.

Mr. Kneale brings extensive executive, financial and operational experience to the board. With nearly 30 years of experience in the natural liquids gas industry in numerous positions, Mr. Kneale provides valuable insight into our business and industry.

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

Mr. Raymond is also currently a director of American Energy Ohio Holdings, LLC, Ferus Inc., Ferus Natural Gas Fuels Inc., Iron Ore Holdings, Lighthouse Oil & Gas GP, LLC, MarkWest Utica

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EMG, LLC, Medallion Midstream, LLC, Plains All American GP LLC and Tallgrass MLP GP LLC. Mr. Raymond manages various private investments through personally held Lynx Holdings, LLC. Mr. Raymond received a B.S.M. from the A.B. Freeman School of Business at Tulane University with dual concentrations in finance and accounting and currently sits on the Board of the Business School Council.

Patrick Wade. Mr. Wade has served as a member of the High Sierra board since November 2008 and a member of the board of directors of our general partner since 2012. Mr. Wade has twenty years of experience in the energy sector. In 2002, Mr. Wade co-founded Tiger Midstream Investments, a natural gas midstream development and investment company that was involved primarily in the United States Rockies. From 2005 to 2007, Mr. Wade was a Managing Director at Bear Energy LP, responsible for investments in natural gas midstream infrastructure, as well as contracting for a diverse portfolio of natural gas storage capacity. In 2008, Mr. Wade joined The Energy & Minerals Group ("EMG"), as a Managing Director in the Houston office. EMG is the management company for a series of specialized private equity funds. EMG focuses on investing across various facets of the global natural resource industry including the upstream and midstream segments of the energy complex. EMG has approximately $13.3 billion of regulatory assets under management (RAUM) and approximately $6.1 billion in commitments have been allocated across the energy sector since inception. EMG is the managing partner of EMG NGL HC LLC. Mr. Wade's primary focus is making direct investments across the natural resources industry. In addition, Mr. Wade serves on the board of directors of Medallion Midstream, L.L.C. and Ferus Inc. Mr. Wade received his Bachelor's degree from the University of Oklahoma in 1991 and his M.B.A. from the Jesse H. Jones School of Management at Rice University in 1995.

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

Director Appointment Rights

The Limited Liability Company Agreement of NGL Energy Holdings LLC grants certain parties the right to designate a specified number of persons to serve on the board of directors. EMG NGL HC LLC has the right to designate two persons to serve on the board of directors, and has designated John Raymond and Patrick Wade. The Coady Group (which consists of certain entities controlled by Shawn W. Coady and Todd M. Coady) and the IEP Parties (which consists of certain entities controlled by H. Michael Krimbill, Bradley K. Atkinson, and another investor who is not a member of management of the Partnership) each have the right to designate one person to serve on the board of directors. The Coady Group has designated Shawn W. Coady and the IEP Parties have designated H. Michael Krimbill.

Board Leadership Structure and Role in Risk Oversight

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

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

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Audit Committee

The board of directors of our general partner has established an audit committee. The audit committee assists the board in its oversight of the integrity of our financial statements and our compliance with legal and regulatory requirements and partnership policies and controls. The audit committee has the sole authority to, among other things:

•: retain and terminate our independent registered public accounting firm;
•: approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm; and
•: establish policies and procedures for the pre-approval of all non-audit services and tax services to be rendered by our independent registered public accounting firm.

The audit committee is also responsible for confirming the independence and objectivity of our independent registered public accounting firm. Our independent registered public accounting firm is given unrestricted access to the audit committee and our management, as necessary.

Mr. Cropper, Mr. Guderian, and Mr. Kneale currently serve on the audit committee, and Mr. Kneale serves as the chairman. The board of directors of our general partner has determined that Mr. Kneale, an independent director, is as an "audit committee financial expert" as defined under SEC rules and that each member of the audit committee is financially literate. In compliance with the requirements of the NYSE, all of the members of the audit committee are independent directors, as defined in the applicable NYSE rules.

Compensation Committee

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

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

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

Corporate Governance

The board of directors of our general partner has adopted a Code of Ethics for the Chief Executive Officer and Senior Financial Officers, or Code of Ethics, that applies to the chief executive officer, chief financial officer, chief accounting officer, controller and all other senior financial and accounting officers of our general partner. Amendments to or waivers from the Code of Ethics will be disclosed on our website. The board of directors of our general partner has also adopted Corporate Governance Guidelines that outline important policies and practices regarding our governance and a Code of Business Conduct and Ethics that applies to the directors, officers and employees of our general partner and the Partnership.

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We make available free of charge, within the "Governance" section of our website at http://www.nglenergypartners.com/governance, and in print to any unitholder who so requests, the Code of Ethics, the Corporate Governance Guidelines, the Code of Business Conduct and Ethics and the charters of the audit committee and the compensation committee of the board of directors of our general partner. Requests for print copies may be directed to Investor Relations at investorinfo@nglep.com or to Investor Relations, NGL Energy Partners LP, 6120 South Yale Avenue, Suite 805, Tulsa, OK 74136 or made by telephone at (918) 481-1119. The information contained on, or connected to, our website is not incorporated by reference into this Annual Report and should not be considered part of this or any other report that we file with or furnish to the SEC.

Meeting of Non-Management Directors and Communications with Directors

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

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

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The year "2014" in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2014.

Introduction

The board of directors of our general partner has responsibility and authority for compensation-related decisions for our executive officers. In November 2011, the board of directors formed a compensation committee to develop our compensation program, to determine the compensation of our Chief Executive Officer, and to make recommendations to the board of directors regarding the compensation of our other executive officers. Our executive officers are also officers of our operating companies and are compensated directly by our operating companies. While we reimburse our general partner and its affiliates for all expenses they incur on our behalf, our executive officers do not receive any additional compensation for the services they provide to our general partner.

Our "named executive officers" for fiscal 2014 were:

•: H. Michael Krimbill — Chief Executive Officer
•: Atanas H. Atanasov — Chief Financial Officer and Treasurer
•: James J. Burke — President
•: Shawn W. Coady — President and Chief Operating Officer, Retail Division
•: David C. Kehoe — Executive Vice President, NGL Crude Logistics

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Compensation Philosophy

Our compensation philosophy emphasizes pay-for-performance, focused primarily on the ability to increase sustainable quarterly distributions to our unitholders. Pay-for-performance is based on a combination of our performance and the individual executive officer's contribution to our performance. We believe this pay-for-performance approach generally aligns the interests of our executive officers with the interests of our unitholders, and at the same time enables us to maintain a lower level of cash compensation expense in the event our operating and financial performance do not meet our expectations.

Our executive compensation program is designed to provide a total compensation package that allows us to:

•: Attract and retain individuals with the background and skills necessary to successfully execute our business strategies;
•: Motivate those individuals to reach short-term and long-term goals in a way that aligns their interests with the interests of our unitholders; and
•: Reward success in reaching those goals.

Factors Enhancing Alignment with Unitholder Interests

•: Majority of officer pay is incentive compensation at risk based on annual financial performance and growth in unitholder value
•: Equity-based incentives are the largest single component of officer compensation
•: 50% of officers' equity awards subject to achievement of above-median total unitholder return relative to our performance peer group
•: No excise tax gross-ups
•: Compensation committee engages an independent compensation adviser

Compensation Setting Process

Our compensation program for our named executive officers supports our philosophy of pay-for-performance.

•: Role of Management: Our Chief Executive Officer also provides periodic recommendations to the compensation committee and the board of directors regarding the compensation of our other named executive officers.
•: Role of the Compensation Committee's Consultant: In carrying out its responsibilities for establishing, implementing and monitoring the effectiveness of our executive compensation philosophy, plans and programs, our compensation committee has the authority to engage outside experts to assist in its deliberations. During fiscal 2014, the compensation committee received compensation advice and data from Pearl Meyer & Partners ("PM&P"). PM&P conducted a competitive review of the principal components of compensation for our executives, including our Named Executive Officers. PM&P also provided input on peer group selection (compensation and performance peers), and short and long-term incentive plan design. The compensationcommittee reviewed the services provided by PM&P and determined that they are independent in providing executive compensation consulting services. In making this determination, the compensation committee noted that during fiscal 2014:
•: PM&P did not provide any services to the Company or management other than compensation consulting services requested by or with the approval of the compensation committee;

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•: PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or human resource outsourcing;
•: PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and procedures designed to ensure independence;
•: Fees paid to PM&P by NGL Energy Partners during fiscal 2014 were less than 1% of PM&P's total revenue;
•: None of the PM&P consultants working on Company matters had any business or personal relationship with compensation committee members;
•: None of the PM&P consultants working on Company matters (or any consultants at PM&P) had any business or personal relationship with any executive officer of the Company; and
•: None of the PM&P consultants working on Company matters own Company stock.

The compensation committee continues to monitor the independence of its compensation consultant on a periodic basis. The compensation committee is considering the recommendations provided by PM&P and is in the process of designing the fiscal 2015 compensation program.

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Elements of Executive Compensation

As part of our pay-for-performance approach to executive compensation, the compensation of our executive officers includes a significant component of incentive compensation based on our performance. We use three primary elements of compensation in our executive compensation program:

			Objective Supported

Element	Primary Purpose	How Amount Determined	Attract & Retain		Motivate & Pay for Performance		Unitholder Alignment
Base Salary	• Fixed income to compensate executive officers for their level of responsibility, expertise and experience	• Based on competition in the marketplace for executive talent and abilities		X
Cash Bonus Awards	• Rewards achievement of specific annual financial and operational performance goals	• Based on the named executive officer's relative contribution to achieving or exceeding annual goals		X		X		X
	• Recognizes individual contributions to our performance
Long-Term Equity Incentive Awards	• Motivates and rewards the achievement of long-term performance goals, including increasing the market price of our common units and the quarterly distributions to our unitholders	• Based on the named executive officer's expected contribution to long-term performance goals		X		X		X
	• Provides a forfeitable long-term incentive to encourage executive retention

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Base Salary

The compensation committee periodically reviews the base salaries of our named executive officers and may recommend adjustments as necessary. We do not make automatic annual adjustments to base salary.

•: Mr. Krimbill's base salary of $120,000 was originally determined as part of the negotiations for our formation transactions. In setting the base salaries, the parties considered various factors, including the compensation needed to attract or retain the officers, the historical compensation of the officers, and each officer's expected individual contribution to our performance. At the request of Mr. Krimbill, the parties agreed that he should receive a lower base salary than our other executive officers at the time because, as our Chief Executive Officer, a significant portion of his compensation should be performance-based, to further align his interests with the interests of our unitholders. In February 2012, the base salary of Mr. Krimbill was reduced to $60,000, based on our operating and financial performance as a result of an unusually warm winter. The base salary of Mr. Krimbill was restored to $120,000 effective November 12, 2012.
•: Mr. Atanasov's base salary of $195,000 was negotiated prior to his joining our management team in November 2011. The base salary of Mr. Atanasov was increased in July 2013 to $250,000.
•: Mr. Burke and Mr. Kehoe's base salaries, which became effective on June 19, 2012 when they joined our management team upon completion of our merger with High Sierra, were $353,000 and $293,000, respectively. The base salaries of Mr. Burke and Mr. Kehoe were increased in July 2013 to $375,000 and $340,000, respectively.
•: Dr. Coady's base salary of $300,000 was determined as part of the negotiations for our formation transactions. In February 2012, the base salary of Dr. Coady was reduced to $200,000 based on our operating and financial performance as a result of an unusually warm winter. The base salary of Dr. Coady was restored to $300,000 effective November 12, 2012.

Cash Bonus Awards

Neither the compensation committee nor the Board of Directors has yet approved bonuses to be paid to the named executive officers based on performance during fiscal 2014. For fiscal 2014, none of the named executive officers was subject to a formal bonus plan, and therefore annual bonus awards for fiscal 2014 performance, if any, would be discretionary.

During fiscal 2014, bonuses were paid to the named executive officers. These bonuses were approved by the Board of Directors in fiscal 2014 at the recommendation of the compensation committee, which determined the bonus amounts using recommendations provided by the Chief Executive Officer. The bonus amounts were determined based on the contributions of the individuals since the time they joined the Partnership through the date of the bonus and based on expectations of future performance. The amounts of these bonuses were as follows:


Atanas H. Atanasov			195,000
James J. Burke			450,000
Shawn W. Coady			200,000
David C. Kehoe			425,000

Also during fiscal 2014, the compensation committee approved a bonus of $475,000 to be paid to H. Michael Krimbill. The bonus amount was determined based on the contributions of Mr. Krimbill since the time the Partnership was formed through the date of the bonus and based on expectations of future performance.

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The cash bonus program for fiscal 2015 is still under development, as further described in the "Fiscal 2015 Compensation Program" section below.

Long-Term Equity Incentive Awards

In May 2011, our general partner adopted the NGL Energy Partners LP 2011 Long-Term Incentive Plan (the "LTIP") for the employees and directors of our general partner who perform services for us. The LTIP authorizes the grant of restricted units, phantom units, unit options, unit appreciation rights and other unit-based awards.

On June 27 2013, Mr. Atanasov was granted 10,000 restricted units in recognition of his increased responsibilities. The restricted units will vest in five equal annual installments, the first of which vests on July 1, 2014, subject to the continued service of Mr. Atanasov. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

Previously, the compensation committee granted awards of restricted units to certain of our named executive officers during fiscal year 2013. Initial grants under the LTIP were awarded in June 2012 upon formation of the award program. Additional grants were awarded in December 2012, primarily for officers and employees who joined the Partnership in the merger with High Sierra. The fiscal year 2013 awards were designed to incentivize retention and to enhance unitholder alignment by rewarding the officer if the value of common units increases over time. These awards vest in tranches, subject to the continued service of the recipient. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

The long-term equity incentive award program for fiscal 2015 is still under development, as further described in the "Competitive Review and Fiscal 2015 Compensation Program" section below.

Severance and Change in Control Benefits

We do not provide any severance or change of control benefits to our named executive officers. The board of directors has the option to accelerate the vesting of the restricted units in the event of a change in control of the Partnership, although it is not under any obligation to do so.

401(k) Plan

We have established a defined contribution 401(k) plan to assist our eligible employees in saving for retirement on a tax-deferred basis. The 401(k) plan permits all eligible employees, including our named executive officers, to make voluntary pre-tax contributions to the plan, subject to applicable tax limitations. We make an employer matching contribution equal to 50% of the employee's contribution that is not in excess of 6% of the employee's eligible compensation (subject to annual IRS contribution limits). Our matching contributions vest over 5 years.

Other Benefits

We do not maintain a defined benefit or pension plan for our executive officers, because we believe such plans primarily reward longevity rather than performance. We provide a basic benefits package available to substantially all full-time employees, which includes a 401(k) plan and medical, dental, disability and life insurance.

Competitive Review and Fiscal 2015 Compensation Program

During fiscal 2014, PM&P conducted a competitive review of our executive compensation program and provided input to the compensation committee regarding competitive compensation levels and

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compensation program design. In order to provide guidance to the compensation committee regarding competitive rates of compensation, PM&P collected pay data from the following sources:

•: Compensation surveys including data from published compensation surveys representative of other energy industry and broader general industry companies with revenues of between $1 billion and $6 billion; and
•: Peer group data including pay data from 10-K and proxy filings for a group of 20 publicly-traded midstream oil & gas partnerships of similar size and scope to us.

Compensation Peer Group Companies


AmeriGas Partners LP	Enbridge Energy Partners, L.P.	Crosstex Energy LP
Ferrellgas Partners LP	NuStar Energy L.P.	DCP Midstream Partners LP
Star Gas Partners, L.P.	Targa Resources Partners LP	Martin Midstream Partners LP
Suburban Propane Partners, L.P.	Buckeye Partners, L.P.	Regency Energy Partners LP
ONEOK Partners, L.P.	Genesis Energy LP	Boardwalk Pipeline Partners, LP
Kinder Morgan Energy Partners, L.P.	Crestwood Midstream Partners LP	Western Gas Partners LP
Williams Partners L.P.	Magellan Midstream Partners LP

PM&P defines "market" as the combination of survey data and peer group data. The compensation committee is considering the recommendations provided by PM&P and is in the process of designing the fiscal 2015 compensation program.

Employment Agreements

We do not have employment agreements with any of our named executive officers.

Deductibility of Compensation

We believe that the compensation paid to the named executive officers is generally fully deductible for federal income tax purposes. We are a limited partnership and we do not meet the definition of a "corporation" subject to deduction limitations under Section 162(m) of the Code. Nonetheless, the taxable compensation paid to each of our named executive officers in calendar 2013 was less than the Section 162(m) threshold of $1,000,000. Although the value of the restricted units granted during fiscal 2014 are reflected in the Summary Compensation Table below, the grant is subject to vesting conditions. The vesting of the award is a taxable event, but the granting of the award is not.

Relation of Compensation Policies and Practices to Risk Management

Our compensation arrangements contain a number of design elements that serve to minimize the incentive for taking excessive or inappropriate risk to achieve short-term, unsustainable results. This includes using restricted unit grants as a significant element of the executive compensation, as the restricted units are designed to reward the executives based on the long-term performance of the Partnership. In combination with our risk-management practices, we do not believe that risks arising from our compensation policies and practices for our employees are reasonably likely to have a material adverse effect on us.

Compensation Committee Interlocks and Insider Participation

Dr. Coady is a member of the board of directors and an executive officer of our general partner, and his brother, Mr. Coady, is an executive officer of our general partner. Dr. Coady and Mr. Coady also serve as officers and directors of HOH, a family owned company. Both Dr. Coady and Mr. Coady participate in the compensation setting process of the HOH board of directors.

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Summary Compensation Table for 2014

The following table includes the compensation earned by our named executive officers for fiscal years 2012-2014.

Name and Position

H. Michael Krimbill	2014	117,693	475,000	—	6,493	599,186
Chief Executive Officer	2013	82,849	—	—	2,492	85,341
	2012	110,769	—	—	2,700	113,469
Atanas H. Atanasov(4)	2014	232,500	195,000	259,696	7,038	694,234
Chief Financial Officer	2013	195,000	—	743,440	2,738	941,178
James J. Burke(5)	2014	367,385	450,000	—	24,651	842,036
President	2013	275,630	—	836,400	13,015	1,125,045
Shawn W. Coady	2014	300,000	200,000	—	19,630	519,630
President and Chief Operating Officer, Retail Division	2013	238,462	—	613,700	17,730	869,892
	2012	285,587	—	—	20,950	306,537
David C. Kehoe(5)	2014	323,731	425,000	—	15,932	764,663
Executive Vice President, NGL Crude Logistics	2013	228,781	—	836,400	13,490	1,078,671

(1): Amounts for fiscal 2014 include discretionary bonuses paid in 2014 based on contributions of the individuals since the time they joined the Partnership through the date of the bonus and based on expectations of future performance. Amounts payable based on fiscal 2014 performance, if any, have not yet been determined, but are expected to be determined during the first or second quarters of fiscal 2015.
(2): The fair values of the restricted units shown in the table above were calculated based on the closing market prices of our limited partner units on the grant dates, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution prior to the grant date and assumptions that a market participant might make about future distribution growth. This calculation of fair value is consistent with the provisions of ASC 718.
(3): The amounts in this column include matching contributions to our 401(k) plan. Amounts for Mr. Burke and Mr. Kehoe each include $8,124 for club memberships. The fiscal 2014 amount for Mr. Burke includes $9,000 for a car allowance. Amounts in this column for Dr. Coady include matching contributions to our 401(k) plan of $8,750 for fiscal 2014. Amounts in this column for Dr. Coady also include the incremental cost of the use of a company car, including depreciation, maintenance, insurance, and fuel, of $10,880 for fiscal 2014.
(4): Mr. Atanasov was not a named executive officer prior to fiscal 2013.
(5): Mr. Burke and Mr. Kehoe joined our management team upon completion of our merger with High Sierra on June 19, 2012.

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Restricted Unit Awards

During fiscal 2014, the board of directors granted an award of restricted units to Mr. Atanasov. The restricted units will vest in tranches, subject to his continued service. The restricted units may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

2014 Grants of Plan Based Awards Table

The number of restricted units granted to our named executive officers, and their grant date fair value, are summarized below:

Name	Grant Date

H. Michael Krimbill	n/a	—	—
Atanas H. Atanasov	June 27, 2013	10,000	259,696
James J. Burke	n/a	—	—
Shawn W. Coady	n/a	—	—
David C. Kehoe	n/a	—	—

The fair value of the restricted units shown in the table above were calculated based on the closing market price of our limited partner units on the grant date, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution at the grant date and assumptions that a market participant might make about future distribution growth.

We record in our consolidated financial statements the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through each reporting date using the estimated fair value of the awards at the reporting date.

Outstanding Equity Awards as of March 31, 2014

The number of unvested restricted units outstanding at March 31, 2014, and their fair values at March 31, 2014, are summarized below:

Name

H. Michael Krimbill	—	—
Atanas H. Atanasov	32,000	1,200,960
James J. Burke	40,000	1,501,200
Shawn W. Coady	10,000	375,300
David C. Kehoe	40,000	1,501,200

The fair values of the restricted units shown in the table above were calculated based on the closing market price of our limited partner units at March 31, 2014 of $37.53. No adjustments were made to reflect the fact that the restricted units are not entitled to distributions during the vesting period.

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2014 Option Exercises and Stock Vested

On July 1, 2013, certain of the restricted units granted vested. The value of the awards on the vesting date shown in the table below was calculated based of the closing market price of $30.49 per unit on the vesting date.

Name

H. Michael Krimbill	—	—
Atanas H. Atanasov	10,000	304,900
James J. Burke	10,000	304,900
Shawn W. Coady	10,000	304,900
David C. Kehoe	10,000	304,900

Upon vesting, certain of the named executive officers elected for us to remit payments to taxing authorities in lieu of issuing units. Mr. Atanasov elected to have 3,260 units withheld, Mr. Burke elected to have 3,181 units withheld, Dr. Coady elected to have 4,235 units withheld, and Mr. Kehoe elected to have 3,184 units withheld for this purpose.

Subsequent to vesting, these individuals received distributions of $1.54 on each of the vested units during the fiscal year ended March 31, 2014.

Potential Payments upon Termination or Change in Control

We do not provide any severance or change of control benefits to our executive officers. The board of directors has the option to accelerate the vesting of the restricted units in the event of a change in control of the Partnership, although it is not under any obligation to do so. If the board of directors were to exercise its discretion to accelerate the vesting of restricted units upon a change in control, the value of such units would be the same as reported in the "Outstanding Equity Awards as of March 31, 2014" table above.

Director Compensation

Officers or employees of our general partner and its affiliates who also serve as directors do not receive additional compensation for their service as a director of our general partner. Each director who is not an officer or employee of our general partner or its affiliates receives the following compensation for his board service:

•: an annual retainer of $60,000;
•: an annual retainer of $10,000 for the chairman of the audit committee; and
•: an annual retainer of $5,000 for each member of the audit committee other than the chairman.

All of our directors are also reimbursed for all out-of-pocket expenses incurred in connection with attending board or committee meetings. Each director is indemnified for his actions associated with being a director to the fullest extent permitted under Delaware law.

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Director Compensation for Fiscal 2014

The following table sets forth the compensation earned during fiscal 2014 by each director who is not an officer or employee of our general partner:

Name

Stephen L. Cropper	65,000	—	65,000
Bryan K. Guderian	65,000	—	65,000
James C. Kneale	70,000	—	70,000

These directors did not receive any equity grants under the LTIP during fiscal 2014. During fiscal 2013, each of these directors received a grant of unvested units under the LTIP. These units vest in tranches, contingent on the continued service of the directors. During fiscal 2014, a tranche of 5,000 units vested for each director. Subsequent to the vesting, these individuals received distributions of $1.54 on each of the vested units.

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the beneficial ownership, as of May 23, 2014 of our units by:

•: each person or group of persons known by us to be a beneficial owner of more than 5% of our outstanding units;
•: each director of our general partner;
•: each named executive officer of our general partner; and
•: all directors and executive officers of our general partner as a group.

Beneficial Owners

5% or greater unitholders (other than officers and directors):
SemGroup Corporation(2)	9,133,409	12.23	%	—	—		11.33	%
Oppenheimer Funds, Inc.(3)	8,559,178	11.46	%	—	—		10.62	%
Goldman Sachs Asset Management, L.P.(4)	4,938,229	6.61	%	—	—		6.12	%
Directors and officers:
Atanas H. Atanasov(5)	43,908	*		—	—		*
James J. Burke(6)	308,259	*		—	—		*
Kevin C. Clement	5,000	*		—	—		*
Shawn W. Coady(7)	1,326,370	1.78	%	1,125,351	19.01	%	3.04	%
Carlin G. Conner	—	—		—	—		—
Stephen L. Cropper	25,000	*		—	—		*
Bryan K. Guderian	20,000	*		—	—		*
David C. Kehoe(8)	315,823	*		—	—		*
James C. Kneale(9)	17,500	*		—	—		*
H. Michael Krimbill(10)	970,557	1.30	%	497,846	8.41	%	1.82	%
Vincent J. Osterman(11)	3,955,437	5.29	%	—	—		4.94	%
Patrick Wade	—	—		—	—		—
John T. Raymond(12)	2,176,634	2.91	%	—	—		2.70	%
All directors and executive officers as a group (15 persons)(13)	10,491,438	14.04	%	2,747,198	46.41	%	16.45	%

*

Less than 1.0%

(1): Based on 74,706,160 common units and 5,919,346 subordinated units outstanding at May 23, 2014.
(2): The mailing address for SemGroup Corporation is 6120 S. Yale Avenue, Suite 700, Tulsa, OK 74136. SemGroup Corporation also owns an 11.78% interest in our general partner. The information related to SemGroup Corporation, including the number of common units held, is based upon its Form 4 filed with the SEC on June 10, 2013.

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(3): The mailing address for OppenheimerFunds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281. OppenheimerFunds, Inc. reported shared voting and dispositive power with respect to all common units beneficially owned. The information related to OppenheimerFunds, Inc. is based on OppenheimerFunds, Inc.'s Form 13G filed with the SEC on April 10, 2014.
(4): The mailing address for Goldman Sachs Asset Management, L.P. is 200 West Street, New York, NY 10282. Goldman Sachs Asset Management, L.P. reported shared voting and dispositive power with respect to all common units beneficially owned. The information related to Goldman Sachs Asset Management, L.P. is based on Goldman Sachs Asset Management, L.P.'s Form 13G filed with the SEC on February 13, 2014.
(5): Atanas H. Atanasov also owns a 0.40% interest in our general partner.
(6): Impact Development, LLC owns 33,872 of these common units. Impact Development, LLC is solely owned by James J. Burke, who may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. Impact Development, LLC also owns a 2.87% interest in our general partner.
(7): Shawn W. Coady owns 21,330 of these common units. SWC Family Partnership LP owns 1,195,040 of these common units and 1,125,351 of these subordinated units. SWC Family Partnership LP is solely owned by SWC General Partner, LLC, of which Shawn W. Coady is the sole partner. Shawn W. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady Irrevocable Insurance Trust, which was established for the benefit of Shawn W. Coady's children, owns 110,000 of these common units. Shawn W. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. Shawn W. Coady also owns a 12.27% interest in our general partner through Coady Enterprises, LLC, of which he owns 100% of the membership interests.
(8): David C. Kehoe also owns a 0.75% interest in our general partner through DCK GP, LLC, of which he owns 100% of the membership interests.
(9): Of these common units, 12,500 are owned by the Suzanne and Jim Kneale Living Trust.
(10): Krim2010, LLC owns 407,002 of these common units and all of these subordinated units. Krimbill Enterprises LP, H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06% of Krim2010, LLC, respectively. H. Michael Krimbill exercises the sole voting and investment power for Krimbill Enterprises LP. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. H. Michael Krimbill also owns a 14.81% interest in our general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests. KrimGP2010 LLC owns 363,555 of these common units. KrimGP2010LLC is solely owned by H. Michael Krimbill. H. Michael Krimbill may be deemed to have sole voting and investment power over these units.
(11): Vincent J. Osterman owns 30,000 of these common units. The remaining common units are owned by AO Energy, Inc. (110,587 common units), E. Osterman, Inc. (394,350 common units), E. Osterman Gas Services, Inc. (301,700 common units), E. Osterman Propane, Inc. (669,300 common units), Milford Propane, Inc. (559,784 common units), Osterman Family Foundation (192,816 common units), Osterman Propane, Inc. (1,445,850 common units), Propane Gas, Inc. (36,450 common units) and Saveway Propane Gas Service, Inc. (214,600 common units). Each of these holding entities may be deemed to have sole voting and

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investment power over its own common units and Propane Gas, LLC, as sole shareholder of Propane Gas, Inc., may be deemed to have sole voting and investment power over those common units. Vincent J. Osterman is a director, executive officer and shareholder or member of each of these entities and may be deemed to have sole voting and investment power over 729,300 common units and shared voting and investment power (with his father, Ernest Osterman) over 3,281,137 common units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. Vincent J. Osterman also owns a 0.75% interest in our general partner through VE Properties XI LLC.

(12): EMG NGL HC, LLC owns all of these common units. John T. Raymond is the Chief Executive Officer and Managing Partner of NGP MR GP, LLC, the general partner of NGP MR, LP, the general partner of NGP Midstream & Resources, LLC, a member holding a majority interest in EMG NGL HC, LLC. John T. Raymond may be deemed to have shared voting and investment power over these units, but disdains beneficial ownership except to the extent of his pecuniary interest therein. EMG I NGL GP Holdings, LLC, an affiliate of EMG NGL HC, LLC, owns a 6.73% interest in our general partner. EMG II NGL GP Holdings, LLC, an affiliate of EMG NGL HC, LLC, owns a 5.36% interest in our general partner.
(13): The directors and executive officers of our general partner also collectively own a 68.00% interest in our general partner.

Unless otherwise noted, each of the individuals listed above is believed to have sole voting and investment power with respect to the units beneficially held by them. The mailing address for each of the officers and directors of our general partner listed above is 6120 South Yale Avenue, Suite 805, Tulsa, OK 74136.

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DESCRIPTION OF NOTES

You can find the definitions of certain terms used in this description under the subheading "—Definitions." In this description, the words "NGL Energy," "us," "our" and "we" refer only to NGL Energy Partners LP and not to any of its Subsidiaries, and the words "Finance Corp." refer solely to NGL Energy Finance Corp. The term "Issuers" refers to NGL Energy and Finance Corp., collectively.

The Issuers will issue new notes under an indenture dated as of October 16, 2013 (the "indenture"), among the Issuers, the Guarantors and U.S. Bank National Association, as trustee (the "trustee"), in exchange for old notes issued under the indenture in a private transaction that was not subject to the registration requirements of the Securities Act. See "Notice to Investors." The terms of the notes will include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act").

The following description is a summary of the material provisions of the indenture. It does not restate the indenture in its entirety. We urge you to read the indenture because it, and not this description, defines your rights as holders of the notes. The registered holder of a note will be treated as the owner of it for all purposes. Only registered holders will have rights under the indenture and all references to "holders" in this description are to registered holders of notes.

Brief Description of the Notes and the Note Guarantees

The Notes

The new notes will:

•: be general unsecured obligations of each of the Issuers;
•: be non-recourse to our general partner;
•: rankpari passu in right of payment with all existing and future unsecured senior Indebtedness of each of the Issuers;
•: rank senior in right of payment to any future subordinated Indebtedness of each of the Issuers;
•: be structurally subordinated to all obligations of any of our Subsidiaries;
•: be unconditionally guaranteed by the Guarantors on a senior unsecured basis; and
•: rank effectively junior in right of payment to all existing and future secured Indebtedness of each of the Issuers, including indebtedness under the Credit Agreement and the Existing Senior Secured Notes, which are secured by substantially all of the assets of NGL Energy and the Guarantors, to the extent of the assets of the Issuers constituting collateral securing such Indebtedness. See "Risk Factors—Risks Related to the Notes—The notes and the guarantees will be unsecured and effectively subordinated to our and our subsidiary guarantors' existing and future secured indebtedness. The notes and the guarantees will also be structurally subordinated to all indebtedness of our non-guarantor subsidiaries."

The Note Guarantees

Initially, the new notes will be guaranteed by each Restricted Subsidiary (other than Finance Corp.) that is a Domestic Subsidiary and an obligor under the Credit Agreement. In the future, other Restricted Subsidiaries will be required to guarantee the notes under the circumstances described below under "—Covenants—Additional Note Guarantees." Each guarantee of the notes will:

•: be a general unsecured obligation of the applicable Guarantor;

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•: rankpari passu in right of payment with all existing and future unsecured senior Indebtedness of such Guarantor;
•: rank senior in right of payment to any future subordinated Indebtedness of such Guarantor; and
•: rank effectively junior in right of payment to all existing and future secured Indebtedness of such Guarantor, including indebtedness under the Credit Agreement and the Existing Senior Secured Notes, to the extent of the assets of such Guarantor constituting collateral securing such Indebtedness.

As of the Issue Date, all of our Restricted Subsidiaries will guarantee the notes, other than NGL Gateway Terminals, Inc., High Sierra Energy GP, LLC, High Sierra Energy Shared Services, LLC, High Sierra Storage, LLC, Petro Source Products, LLC, High Sierra Energy Canada ULC, High Sierra Water Services Midcontinent, LLC and Indigo Injection #3-1, LLC. As of the Issue Date, none of these Subsidiaries Guarantees (or is otherwise liable for) any Obligations under any Credit Facility, including the Credit Agreement. As of the Issue Date, all of our Subsidiaries will be "Restricted Subsidiaries." However, under the circumstances described below under the caption "—Covenants—Designation of Restricted and Unrestricted Subsidiaries," we will be permitted to designate certain of our Subsidiaries as "Unrestricted Subsidiaries." Our Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. In the event of a bankruptcy, liquidation or reorganization of any Unrestricted Subsidiary, such Unrestricted Subsidiary will pay the holders of its debt and its trade creditors before it will be able to distribute any of its assets to NGL Energy.

Principal, Maturity and Interest

The Issuers will issue up to $450.0 million in aggregate principal amount of new notes in this exchange offer. The Issuers may issue additional notes under the indenture from time to time after this offering. Any issuance of additional notes is subject to all of the covenants in the indenture, including the covenant described below under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock." The notes and any additional notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. The Issuers will issue notes in denominations of $2,000 and integral multiples of $1,000 in excess of $2,000. The notes will mature on October 15, 2021.

Interest on the notes will accrue at the rate of 6.875% per annum and will be payable semi-annually in arrears on April 15 and October 15 of each year. The Issuers will make each interest payment to the holders of record on the immediately preceding April 1 and October 1.

Interest on the notes will accrue from the date of original issuance or, if interest has already been paid, from the date it was most recently paid. Interest will be computed on the basis of a 360-day year comprised of twelve 30-day months. If an interest payment date falls on a day that is not a Business Day, the interest payment to be made on such interest payment date will be made on the next succeeding Business Day with the same force and effect as if made on such interest payment date, and no Liquidated Damages will accrue as a result of such delayed payment.

Methods of Receiving Payments on the Notes

If a holder of notes has given wire transfer instructions to NGL Energy, NGL Energy will pay all principal, interest and premium, if any, on that holder's notes in accordance with those instructions to an account in the United States of America. All other payments on the notes will be made at the office or agency of the paying agent and registrar in New York, New York, unless we elect to make interest payments by check mailed to the noteholders at their address set forth in the register of holders.

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Paying Agent and Registrar for the Notes

The trustee is acting as paying agent and registrar. The Issuers may change the paying agent or registrar without prior notice to the holders of the notes, and NGL Energy or any of its Subsidiaries may act as paying agent or registrar.

Transfer and Exchange

A holder may transfer or exchange notes in accordance with the provisions of the indenture. The registrar and the trustee may require a holder, among other things, to furnish appropriate endorsements and transfer documents in connection with a transfer of notes. Holders will be required to pay all taxes due on transfer. The Issuers will not be required to transfer or exchange any note selected for redemption. Also, the Issuers will not be required to transfer or exchange any note for a period of 15 days before a selection of notes to be redeemed or between a record date and the next succeeding interest payment date.

Note Guarantees

Initially, all of the notes will be guaranteed on a senior unsecured basis by each of NGL Energy's current Restricted Subsidiaries (except Finance Corp.) that is a Domestic Subsidiary and an obligor under the Credit Agreement. In the future, Restricted Subsidiaries will be required to guarantee the notes under the circumstances described under "—Covenants—Additional Note Guarantees." These Note Guarantees will be joint and several obligations of the Guarantors. The obligations of each Guarantor under its Note Guarantee will be limited as necessary to prevent that Note Guarantee from constituting a fraudulent conveyance under applicable law, although this limitation may not be effective to prevent the Note Guarantees from being voided in bankruptcy. See "Risk Factors—Risks Related to the Notes—Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from subsidiary guarantors."

A Guarantor may not sell or otherwise dispose of, in one or more related transactions, all or substantially all of its properties or assets to, or consolidate with or merge with or into (regardless of whether such Guarantor is the surviving Person), another Person, other than NGL Energy or another Guarantor, unless:

(1) immediately after giving effect to such transaction or series of related transactions, no Default or Event of Default exists; and

(2) either:

(a) (i) such Guarantor is the surviving Person of such consolidation or merger or (ii) the Person acquiring the properties or assets in any such sale or other disposition or the Person formed by or surviving any such consolidation or merger (if other than such Guarantor) unconditionally assumes all the obligations of such Guarantor under the indenture (including its Note Guarantee) pursuant to a supplemental indenture satisfactory to the trustee; or

(b) such transaction or series of transactions does not violate the provisions of the indenture described under the caption "—Repurchase at the Option of Holders—Asset Sales."

The Note Guarantee of a Guarantor will be released automatically:

(1) in connection with any sale or other disposition of all or substantially all of the properties or assets of that Guarantor, by way of merger, consolidation or otherwise, to a Person that is not (either before or after giving effect to such transaction) NGL Energy or a Restricted Subsidiary of NGL Energy, if the sale or other disposition does not violate the "Asset Sales" provisions of the indenture described below under the caption "—Repurchase at the Option of Holders—Asset Sales;"

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(2) in connection with any sale or other disposition of the Capital Stock of that Guarantor (by way of merger, consolidation or otherwise) to a Person that is not (either before or after giving effect to such transaction) NGL Energy or a Restricted Subsidiary, if the sale or other disposition does not violate the "Asset Sale" provisions of the indenture described below under the caption "—Repurchase at the Option of Holders—Asset Sales" and the Guarantor ceases to be a Restricted Subsidiary as a result of the sale or other disposition;

(3) if NGL Energy designates such Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture;

(4) upon legal defeasance, covenant defeasance or satisfaction and discharge of the indenture as provided below under the captions "—Legal Defeasance and Covenant Defeasance" and "—Satisfaction and Discharge;"

(5) upon the liquidation or dissolution of such Guarantor, provided no Default or Event of Default occurs as a result thereof or has occurred or is continuing;

(6) upon such Guarantor consolidating with, merging into or transferring all of its properties or assets to NGL Energy or another Guarantor, and as a result of, or in connection with, such transaction such Guarantor dissolves or otherwise ceases to exist; or

(7) at such time as such Guarantor is no longer required to be a Guarantor pursuant to the provisions of the covenant described under the caption "—Covenants—Additional Note Guarantees."

Optional Redemption

Except as described below in this section or in the next-to-last paragraph of "—Repurchase at the Option of Holders—Change of Control," the notes are not redeemable at our option until October 15, 2016. On and after October 15, 2016, NGL Energy may redeem all or a part of the notes, from time to time, at the following redemption prices (expressed as a percentage of the principal amount) plus accrued and unpaid interest, if any, on the notes redeemed to the applicable redemption date (subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date), if redeemed during the twelve month period beginning on of the years indicated below:

Year

2016	105.156	%
2017	103.438	%
2018	101.719	%
2019 and thereafter	100.000	%

At any time or from time to time prior to 2016, NGL Energy may also redeem all or a part of the notes, at a redemption price equal to the Make-Whole Price, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

"Make-Whole Price" with respect to any notes to be redeemed, means an amount equal to the greater of:

(1) 100% of the principal amount of such notes; and

(2) the sum of the present values of (a) the redemption price of such notes at October 15, 2016 (as set forth above) and (b) the remaining scheduled payments of interest from the redemption date to October 15, 2016 (not including any portion of such payments of interest accrued as of the redemption date) discounted back to the redemption date on a semi-annual basis

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(assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined below) plus 50 basis points;

plus, in the case of both (1) and (2), accrued and unpaid interest on such notes, if any, to the redemption date.

"Comparable Treasury Issue" means, with respect to notes to be redeemed, the U.S. Treasury security selected by an Independent Investment Banker as having a maturity most nearly equal to the period from the redemption date to October 15, 2016, that would be utilized at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of a comparable maturity;provided that if such period is less than one year, then the U.S. Treasury security having a maturity of one year shall be used.

"Comparable Treasury Price" means, with respect to any redemption date, (1) the average of the Reference Treasury Dealer Quotations for such redemption date, after excluding the highest and lowest of such Reference Treasury Dealer Quotations, or (2) if the trustee obtains fewer than five such Reference Treasury Dealer Quotations, the average of all such Reference Treasury Dealer Quotations.

"Independent Investment Banker" means RBC Capital Markets, LLC, RBS Securities Inc. and Deutsche Bank Securities Inc., or one of their respective successors, or, if such firms or their respective successors, if any, as the case may be, are unwilling or unable to select the Comparable Treasury Issue, an independent investment banking institution of national standing appointed by NGL Energy.

"Primary Treasury Dealer" means a U.S. government securities dealer in the City of New York.

"Reference Treasury Dealer" means each of RBC Capital Markets, LLC, RBS Securities Inc. and Deutsche Bank Securities Inc. and two additional Primary Treasury Dealers selected by NGL Energy, and their respective successors; provided, however, that if any such firm or any such successor, as the case may be, shall cease to be a Primary Treasury Dealer, NGL Energy shall substitute therefor another Primary Treasury Dealer.

"Reference Treasury Dealer Quotations" means, with respect to each Reference Treasury Dealer and any redemption date, the average, as determined by the trustee, of the bid and asked prices for the Comparable Treasury Issue (expressed in each case as a percentage of its principal amount) quoted in writing to the trustee by such Reference Treasury Dealer at 5:00 p.m., New York City time, no later than the fourth Business Day preceding such redemption date.

"Treasury Rate" means, with respect to any redemption date, (1) the yield, under the heading which represents the average for the immediately preceding week, appearing in the most recently published statistical release designated "H.15(159)" or any successor publication that is published weekly by the Board of Governors of the Federal Reserve System and that establishes yields on actively traded U.S. Treasury securities adjusted to constant maturity under the caption "Treasury Constant Maturities," for the maturity corresponding to the Comparable Treasury Issue (if no maturity is within three months before or after the stated maturity, yields for the two published maturities most closely corresponding to the Comparable Treasury Issue shall be determined, and the Treasury Rate shall be interpolated or extrapolated from such yields on a straight-line basis, rounding to the nearest month) or (2) if such release (or any successor release) is not published during the week preceding the calculation date or does not contain such yields, the rate per annum equal to the semi-annual equivalent yield to maturity of the Comparable Treasury Issue, calculated using a price for the Comparable Treasury Issue (expressed as a percentage of its principal amount) equal to the Comparable Treasury Price for such redemption date. The Treasury Rate shall be calculated no later than the fourth Business Day preceding the redemption date.

The notice of redemption with respect to the foregoing redemption need not set forth the Make-Whole Price but only the manner of calculation thereof. NGL Energy will notify the trustee of

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the Make-Whole Price with respect to any redemption promptly after the calculation, and the trustee shall not be responsible for such calculation.

Prior to October 15, 2016, NGL Energy may on any one or more occasions redeem up to 35% of the principal amount of the notes with an amount of cash not greater than the amount of the net cash proceeds from one or more Equity Offerings at a redemption price equal to 106.875% of the principal amount thereof, plus accrued and unpaid interest, if any, on the notes redeemed to the redemption date (subject to the right of holders of record on the relevant record date to receive interest due on the relevant interest payment date);provided that

(1) at least 65% of the aggregate principal amount of the notes issued on the Issue Date (excluding notes held by NGL Energy and its Subsidiaries) remains outstanding after each such redemption; and

(2) the redemption occurs within 180 days after the closing of such Equity Offering. Unless NGL Energy defaults in the payment of the redemption price, interest, if any, will cease to accrue on the notes or portions thereof called for redemption on the applicable redemption date.

Selection and Notice

If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption on a pro rata basis (or, in the case of notes in global form, the trustee will select notes for redemption based on the method of The Depository Trust Company ("DTC") that most nearly approximates a pro rata selection), unless otherwise required by law or applicable stock exchange requirements.

No notes of $2,000 or less can be redeemed in part. Notices of optional redemption will be mailed by first class mail (or, in the case of notes in global form, pursuant to the applicable procedures of DTC) at least 30 but not more than 60 days before the redemption date to each holder of notes to be redeemed at its registered address, except that redemption notices may be sent more than 60 days prior to a redemption date if the notice is issued in connection with a defeasance of the notes or a satisfaction and discharge of the indenture.

If any note is to be redeemed in part only, the notice of redemption that relates to such note shall state the portion of the principal amount thereof to be redeemed. A new note in principal amount equal to the unredeemed portion thereof will be issued in the name of the holder thereof upon cancellation of the original note. Notes called for redemption become due on the date fixed for redemption, unless the redemption is subject to a condition precedent that is not satisfied or waived. On and after the redemption date, interest ceases to accrue on notes or portions of notes called for redemption, unless NGL Energy defaults in making the redemption payment. Any redemption or notice of redemption may, at our discretion, be subject to one or more conditions precedent and, in the case of a redemption with the net cash proceeds of an Equity Offering, be given prior to and conditioned on the completion of the related Equity Offering.

Open Market Purchases; No Mandatory Redemption or Sinking Fund

We may at any time and from time to time purchase notes in the open market or otherwise. The Issuers are not required to make mandatory redemption or sinking fund payments with respect to the notes.

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Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, each holder of notes will have the right, except as provided below, to require NGL Energy to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that holder's notes pursuant to an offer ("Change of Control Offer") on the terms set forth in the indenture. In the Change of Control Offer, NGL Energy will offer to make a cash payment (a "Change of Control Payment") equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest on the notes repurchased to the date of purchase (the "Change of Control Purchase Date"), subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, NGL Energy will send a notice to each holder of notes describing the transaction or transactions that constitute the Change of Control and offering to repurchase properly tendered notes on the Change of Control Purchase Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is sent, pursuant to the procedures required by the indenture and described in such notice. NGL Energy will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes of any series as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the indenture, NGL Energy will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such compliance.

Promptly following the expiration of the Change of Control Offer, NGL Energy will, to the extent lawful, accept for payment all notes or portions of notes properly tendered pursuant to the Change of Control Offer. Promptly after such acceptance, NGL Energy will, on the Change of Control Purchase Date:

(1) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

(2) deliver or cause to be delivered to the trustee the notes properly accepted together with an Officers' Certificate stating the aggregate principal amount of notes or portions of notes being purchased by NGL Energy.

The paying agent will promptly mail or wire transfer to each holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC), and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any;provided that each such new note will be in a principal amount of $2,000 or an integral multiple of $1,000 in excess of $2,000. Any note so accepted for payment will cease to accrue interest on and after the Change of Control Purchase Date, unless NGL Energy defaults in making the Change of Control Payment. NGL Energy will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Purchase Date.

The provisions described above that require NGL Energy to make a Change of Control Offer following a Change of Control will be applicable regardless of whether any other provisions of the indenture are applicable, except as described in the following paragraph. Except as described above with respect to a Change of Control, the indenture does not contain provisions that permit the holders of the notes to require that the Issuers repurchase or redeem the notes in the event of a takeover, recapitalization or similar transaction.

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NGL Energy will not be required to make a Change of Control Offer upon a Change of Control, if (1) a third party makes the Change of Control Offer in the manner, at the time and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by NGL Energy and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, (2) notice of redemption of all outstanding notes has been given pursuant to the indenture as described above under the caption "—Optional Redemption—Selection and Notice," unless and until there is a default in payment of the applicable redemption price, or (3) in connection with or in contemplation of any Change of Control, NGL Energy has made an offer to purchase (an "Alternate Offer") any and all notes validly tendered at a cash price equal to or higher than the Change of Control Payment and has purchased all notes properly tendered in accordance with the terms of the Alternate Offer. Notwithstanding anything to the contrary contained in the indenture, a Change of Control Offer or Alternate Offer may be made in advance of a Change of Control, conditioned upon the consummation of such Change of Control, if a definitive agreement is in place for the Change of Control at the time the Change of Control Offer or Alternate Offer is made.

In the event that holders of not less than 90% in aggregate principal amount of the outstanding notes accept a Change of Control Offer or Alternate Offer and NGL Energy (or any third party making such Change of Control Offer in lieu of NGL Energy as described above) purchases all of the notes held by such holders, NGL Energy will have the right, upon not less than 30 nor more than 60 days' prior notice, given not more than 30 days following the purchase pursuant to the Change of Control Offer or Alternate Offer described above, to redeem all of the notes that remain outstanding following such purchase at a redemption price equal to the Change of Control Payment plus, to the extent not included in the Change of Control Payment, accrued and unpaid interest on the notes that remain outstanding, to the date of redemption (subject to the right of holders of record on the relevant record date to receive interest due on an interest payment date that is on or prior to the redemption date).

The definition of Change of Control includes a phrase relating to the sale, lease, transfer, conveyance or other disposition of "all or substantially all" of the properties or assets of NGL Energy and its Restricted Subsidiaries taken as a whole. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, the ability of a holder of notes to require the Issuers to repurchase its notes as a result of a sale, lease, transfer, conveyance or other disposition of less than all of the assets of NGL Energy and its Restricted Subsidiaries taken as a whole to another Person or group may be uncertain.

Asset Sales

NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(1) NGL Energy or any of its Restricted Subsidiaries receives consideration (including by way of relief from, or any Person assuming responsibilities for, any liabilities, contingent or otherwise) at the time of the Asset Sale at least equal to the Fair Market Value (measured as of the date of the definitive agreement with respect to such Asset Sale) of the assets or Equity Interests issued or sold or otherwise disposed of; and

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since the Issue Date) is in the form of cash or Cash Equivalents. For purposes of this provision, each of the following will be deemed to be cash:

(a) any liabilities, as shown on NGL Energy's most recent consolidated balance sheet, of NGL Energy or any Restricted Subsidiary (other than contingent liabilities and Subordinated Debt) that are assumed by the transferee of any such assets pursuant to a customary novation or indemnity agreement (or other legal documentation with the same effect) that releases NGL Energy or such Restricted Subsidiary from or indemnifies NGL Energy or such Restricted Subsidiary against further liability;

(b) any securities, notes or other obligations received by NGL Energy or any such Restricted Subsidiary from such transferee that are, within 90 days after the Asset Sale, converted by NGL Energy or such Restricted Subsidiary into cash, to the extent of the cash received in that conversion; and

Within 365 days after the receipt of any Net Proceeds from an Asset Sale or, if NGL Energy has entered into a binding commitment or commitments with respect to any of the actions described in clauses (2) or (3) below, within the later of (x) 365 days after the receipt of any Net Proceeds from an Asset Sale and (y) 120 days after the entering into of such commitment or commitments, NGL Energy or one or more of its Restricted Subsidiaries may apply an amount equal to the amount of such Net Proceeds:

(1) to repay, redeem or repurchase any Senior Debtprovided that such repayment, redemption or repurchase may close up to 45 days after the end of such 365-day period;

(2) to invest in or acquire Additional Assets; or

(3) to make capital expenditures in respect of a Permitted Business.

Pending the final application of any Net Proceeds, NGL Energy or any of its Restricted Subsidiaries may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture. An amount equal to any Net Proceeds from Asset Sales that are not applied or invested as provided in in clauses (1) through (3) of the immediately preceding paragraph will constitute "Excess Proceeds." Within ten Business Days after the aggregate amount of Excess Proceeds exceeds $30.0 million, the Issuers will make an offer (an "Asset Sale Offer") to all holders of notes and all holders of other Indebtedness that ispari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase, prepay or redeem with the proceeds of sales of assets to purchase, prepay or redeem the maximum principal amount of notes and such otherpari passu Indebtedness (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith) that may be purchased, prepaid or redeemed out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of the principal amount, plus accrued and unpaid interest, if any, to the date of purchase, prepayment or redemption, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, NGL Energy or any Restricted Subsidiary may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and otherpari passu Indebtedness tendered in (or required to be prepaid or redeemed in connection with) such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes and such other pari passu Indebtedness to be purchased on apro rata basis (except that any notes represented by a note in global form will be selected by such method as DTC or its nominee or successor may require or, where such nominee or successor is the trustee, a method that most nearly approximates pro rata selection as

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the trustee deems fair and appropriate unless otherwise required by law), based on the amounts tendered or required to be prepaid or redeemed (with such adjustments as may be deemed appropriate by NGL Energy so that only notes in denominations of $2,000, or an integral multiple of $1,000 in excess thereof, will be purchased). Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

Notwithstanding the foregoing, the sale, conveyance or other disposition of all or substantially all of the properties or assets of NGL Energy and its Restricted Subsidiaries, taken as a whole, will be governed by the provisions of the indenture described under the caption "—Repurchase at the Option of Holders—Change of Control" and/or the provisions described under the caption "—Covenants—Merger, Consolidation or Sale of Substantially All Assets" and not by the provisions of the indenture described under the caption "—Repurchase at the Option of Holders—Asset Sales."

NGL Energy will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with each repurchase of notes pursuant to an Asset Sale Offer. To the extent that the provisions of any securities laws or regulations conflict with the Asset Sales provisions of the indenture, or compliance with the Asset Sale provisions of the indenture would constitute a violation of any such laws or regulations, NGL Energy will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Asset Sale provisions of the indenture by virtue of such compliance. The agreements governing NGL Energy's other Indebtedness contain, and future agreements may contain, prohibitions of certain events, including events that would constitute a Change of Control or an Asset Sale and including repurchases of or other prepayments in respect of the notes. The exercise by the holders of notes of their right to require the Issuers to repurchase the notes upon a Change of Control or an Asset Sale could cause a default under these other agreements, even if the Change of Control or Asset Sale itself does not, due to the financial effect of such repurchases on NGL Energy. In the event a Change of Control or Asset Sale occurs at a time when NGL Energy is prohibited from purchasing notes, NGL Energy could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If NGL Energy does not obtain a consent or repay those borrowings, NGL Energy will remain prohibited from purchasing notes. In that case, NGL Energy's failure to purchase tendered notes would constitute an Event of Default under the indenture which could, in turn, constitute a default under the other indebtedness. Finally, the Issuers' ability to pay cash to the holders of notes upon a repurchase may be limited by NGL Energy's then-existing financial resources. See "Risk Factors—Risks Relating to the Notes—We may not be able to repurchase the notes upon a Change of Control."

Covenants

Covenant Termination

From and after the occurrence of an Investment Grade Rating Event, and provided that no Default or Event of Default shall have occurred and be continuing, we and our Restricted Subsidiaries will no longer be subject to the following provisions of the indenture (collectively, the "Terminated Covenants"):

(a) clause (4) of the covenant described under "—Covenants—Merger, Consolidation or Sale of substantially All Assets" and

(b) the provisions of the indenture described above under the following headings:

•: "—Repurchase at the Option of Holders—Asset Sales;"
•: "—Covenants—Restricted Payments;"

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•: "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock;"
•: "—Covenants—Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries;" and
•: "—Covenants—Transactions with Affiliates."

Furthermore, after an Investment Grade Rating Event, NGL Energy may not designate any of its Subsidiaries as Unrestricted Subsidiaries.

Consequently, after the date on which we and our Restricted Subsidiaries are no longer subject to the Terminated Covenants, the notes will be entitled to substantially reduced covenant protection. However, we and our Restricted Subsidiaries will remain subject to all other covenants in the indenture. There can be no assurance that the notes will ever achieve or maintain an Investment Grade Rating.

Restricted Payments

NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

(1) declare or pay any dividend or make any other payment or distribution on account of NGL Energy's or any of its Restricted Subsidiaries' Equity Interests (including, without limitation, any payment in connection with any merger or consolidation involving NGL Energy or any of its Restricted Subsidiaries) or to the direct or indirect holders of NGL Energy's or any of its Restricted Subsidiaries' Equity Interests in their capacity as such (other than dividends or distributions payable in Equity Interests (other than Disqualified Stock) of NGL Energy and other than dividends or distributions payable to NGL Energy or a Restricted Subsidiary);

(2) purchase, redeem or otherwise acquire or retire for value (including, without limitation, in connection with any merger or consolidation involving NGL Energy) any Equity Interests of NGL Energy or any direct or indirect parent of NGL Energy;

(3) make any payment on or with respect to, or purchase, redeem, defease or otherwise acquire or retire for value, any Subordinated Debt (other than intercompany Indebtedness between or among NGL Energy and any of its Restricted Subsidiaries), except a payment of interest or principal within one year of the Stated Maturity thereof; or

(4) make any Restricted Investment

(all such payments and other actions set forth in clauses (1) through (4) above being collectively referred to as "Restricted Payments"), unless, at the time of and after giving effect to such Restricted Payment, no Default (except a Reporting Default) or Event of Default has occurred and is continuing or would occur as a consequence of such Restricted Payment and either:

(I) if the Fixed Charge Coverage Ratio for NGL Energy's most recently ended four full fiscal quarters for which internal financial statements are available at the time of such Restricted Payment (the "Trailing Four Quarters") is not less than 1.75 to 1.0, such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by NGL Energy and its Restricted Subsidiaries during the fiscal quarter in which such Restricted Payment is made (excluding Restricted Payments permitted by clauses (2), (3), (4), (5), (6), (7), (8), (9), (10) and (11) of the next succeeding paragraph), is less than the sum, without duplication, of:

(a) Available Cash from Operating Surplus with respect to NGL Energy's preceding fiscal quarter;plus

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(b) 100% of the aggregate net cash proceeds, and the Fair Market Value of any Capital Stock of Persons engaged primarily in a Permitted Business or other long-term assets that are used or useful in a Permitted Business, in each case received by NGL Energy since the Issue Date from (x) a contribution to the common equity capital of NGL Energy from any Person (other than a Restricted Subsidiary) or (y) the issuance and sale (other than to a Restricted Subsidiary) of Equity Interests (other than Disqualified Stock) of NGL Energy or from the issuance or sale (other than to a Restricted Subsidiary) of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of NGL Energy that have been converted into or exchanged for such Equity Interests (other than Disqualified Stock);plus

(c) to the extent that any Restricted Investment that was made after the Issue Date is sold for cash or Cash Equivalents or otherwise liquidated or repaid for cash or Cash Equivalents, the cash return of capital with respect to such Restricted Investment (less the cost of disposition, if any);plus

(d) the amount equal to the net reduction in Restricted Investments since the Issue Date resulting from (i) dividends, repayments of loans or advances, or other transfers of assets, in each case, to NGL Energy or any of its Restricted Subsidiaries from any Person (including, without limitation, any Unrestricted Subsidiary) or (ii) the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries, in each case, to the extent such amounts have not been included in Available Cash for any period commencing on or after the Issue Date (items (b), (c) and (d) being referred to as "Incremental Funds");minus

(e) the aggregate amount of Incremental Funds previously expended pursuant to this clause (I) and clause (II) below; or

(II) if the Fixed Charge Coverage Ratio for the Trailing Four Quarters is less than 1.75 to 1.0, such Restricted Payment, together with the aggregate amount of all other Restricted Payments made by NGL Energy and its Restricted Subsidiaries during the fiscal quarter in which such Restricted Payment is made (excluding Restricted Payments permitted by clauses (2), (3), (4), (5), (6), (7), (8), (9), (10) and (11) of the next succeeding paragraph), is less than the sum, without duplication, of:

(a) $200.0 million, less the aggregate amount of all prior Restricted Payments made by NGL Energy and its Restricted Subsidiaries pursuant to this clause (II)(a) since the Issue Date;plus

(b) Incremental Funds to the extent not previously expended pursuant to this clause (II) or clause (I) above;

provided, however, that the only Restricted Payments permitted to be made pursuant to this clause (II) are distributions on NGL Energy's common and subordinated units plus the related distributions on the General Partner's general partner interest and any distributions with respect to incentive distribution rights.

The preceding provisions will not prohibit:

(1) the payment of any dividend or distribution or the consummation of any irrevocable redemption within 60 days after the date of declaration of the dividend or distribution or giving of the redemption notice, as the case may be, if at the date of declaration or notice, the dividend, distribution or redemption payment would have complied with the provisions of the indenture;

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Interests of NGL Energy (other than Disqualified Stock), with a sale being deemed substantially concurrent if such purchase, redemption, defeasance or other acquisition or retirement for value occurs not more than 120 days after such sale;provided,however, that the amount of any such net cash proceeds that are utilized for any such purchase, redemption, defeasance or other acquisition or retirement for value will be excluded (or deducted, if included) from the calculation of Available Cash and Incremental Funds;

(3) the purchase, redemption, defeasance or other acquisition or retirement for value of Subordinated Debt with the net cash proceeds from an incurrence of, or in exchange for, Permitted Refinancing Indebtedness;

(4) the payment of any dividend or distribution by a Restricted Subsidiary to the holders of its Equity Interests on apro rata basis;

(5) as long as no Default has occurred and is continuing or would be caused thereby, the purchase, redemption or other acquisition or retirement for value of any Equity Interests of NGL Energy or any Restricted Subsidiary held by any of current or former directors or employees of the General Partner, NGL Energy or of any Restricted Subsidiary;provided,however, that the aggregate price paid for all such purchased, redeemed, acquired or retired Equity Interests may not exceed $7.5 million in any fiscal year (with any portion of such $7.5 million amount that is unused in any fiscal year to be carried forward to successive fiscal years and added to such amount)plus, to the extent not previously applied or included, (a) the cash proceeds received by NGL Energy or any of its Restricted Subsidiaries from sales of Equity Interests of NGL Energy to employees or directors of the General Partner, NGL Energy or its Affiliates that occur after the Issue Date (to the extent the cash proceeds from the sale of such Equity Interests have not otherwise been applied to the payment of Restricted Payments by virtue of clause (I)(b) or (II)(b) of the first paragraph of this covenant) and (b) the cash proceeds of key man life insurance policies received by NGL Energy or any of its Restricted Subsidiaries after the Issue Date;

(6) the purchase, redemption or other acquisition or retirement for value of Equity Interests deemed to occur upon the exercise of unit options, warrants, incentives, rights to acquire Equity Interests or other convertible securities if such Equity Interests represent a portion of the exercise or exchange price thereof, and any purchase, redemption or other acquisition or retirement for value of Equity Interests made in lieu of withholding taxes in connection with any exercise or exchange of unit options, warrants, incentives or rights to acquire Equity Interests;

(7) payments of cash, dividends, distributions, advances or other Restricted Payments, in each case, made in lieu of the issuance of fractional shares or units in connection with the exercise of warrants, options or other securities convertible or exchangeable for Equity Interests or in connection with the payment of a dividend or distribution to the holders of Equity Interests of NGL Energy in the form of Equity Interests (other than Disqualified Stock) of NGL Energy;

(8) the purchase, redemption or other acquisition or retirement for value of Equity Interests of NGL Energy or any Restricted Subsidiary representing fractional units of such Equity Interests in connection with a merger or consolidation involving NGL Energy or such Restricted Subsidiary or any other transaction permitted by the indenture;

(9) payments to the General Partner constituting reimbursements for expenses in accordance with the Partnership Agreement as in effect on the Issue Date and as it may be amended or replaced thereafter,provided that any such amendment or replacement is not materially less favorable to NGL Energy in any material respect than the agreement prior to such amendment or replacement;

(10) as long as no Default has occurred and is continuing or would be caused thereby, the declaration and payment of regularly scheduled or accrued dividends to holders of any class or

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series of Disqualified Stock of NGL Energy or any preferred securities of any Restricted Subsidiary issued on or after the Issue Date in accordance with the covenant described below under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock;"

(11) in connection with an acquisition by NGL Energy or any of its Restricted Subsidiaries, the return to NGL Energy or any of its Restricted Subsidiaries of Equity Interests of NGL Energy or its Restricted Subsidiaries constituting a portion of the purchase consideration in settlement of indemnification claims or purchase price adjustments; and

(12) the purchase, redemption, defeasance or other acquisition or retirement for value of any Subordinated Debt (a) at a purchase price not greater than 101% of the principal amount of such Subordinated Debt plus accrued interest in accordance with provisions similar to the covenant described under "—Repurchase at the Option of Holders—Change of Control" or (b) at a purchase price not greater than 100% of the principal amount thereof plus accrued interest in accordance with provisions similar to the covenant described under "—Repurchase at the Option of Holders—Asset Sales;"provided that, prior to or simultaneously with such purchase, redemption, defeasance or other acquisition or retirement for value, NGL Energy shall have complied with the provisions of the indenture described under the caption "—Repurchase at the Option of Holders—Change of Control" or "Repurchase at the Option of Holders—Asset Sales," as the case may be, and repurchased all notes validly tendered for payment in connection with the Change of Control Offer, Asset Sale Offer or Alternate Offer, as the case may be.

The amount of all Restricted Payments (other than cash) will be the Fair Market Value, determined as of the date of the Restricted Payment, of the Restricted Investment proposed to be made or the asset(s) or securities proposed to be transferred or issued by NGL Energy or such Restricted Subsidiary, as the case may be, pursuant to the Restricted Payment, except that the Fair Market Value of any non-cash dividend or distribution paid within 60 days after the date of its declaration shall be determined as of such date of declaration. The Fair Market Value of any

Restricted Investment, assets or securities that are required to be valued by this covenant will be determined in accordance with the definition of that term. For purposes of determining compliance with this "Restricted Payments" covenant, (x) in the event that a Restricted Payment meets the criteria of more than one of the categories of Restricted Payments described in the preceding clauses (1) through (12) of this covenant, or is permitted pursuant to the first paragraph of this covenant, NGL Energy will be permitted to classify (or later classify or reclassify in whole or in part in its sole discretion) such Restricted Payment (or portion thereof) on the date made or later reclassify such Restricted Payment (or portion thereof) in any manner that complies with this covenant; and (y) in the event a Restricted Payment is made pursuant to clause (I) or (II) of the first paragraph of this covenant, NGL Energy will be permitted to classify whether all or any portion thereof is being (and in the absence of such classification shall be deemed to have classified the minimum amount possible as having been) made with Incremental Funds.

Incurrence of Indebtedness and Issuance of Preferred Stock

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date on which such additional Indebtedness is incurred or such Disqualified Stock or such preferred stock is issued, as the case may be, would have been at least 2.0 to 1.0, determined on apro forma basis (including apro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock or the preferred stock had been issued, as the case may be, at the beginning of such four-quarter period.

Notwithstanding the foregoing, the first paragraph of this covenant will not prohibit the incurrence of any of the following items of Indebtedness or issuances of Disqualified Stock or preferred stock, as applicable (collectively, "Permitted Debt"):

(1) the incurrence by NGL Energy or any of its Restricted Subsidiaries of additional Indebtedness and letters of credit under Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) with letters of credit being deemed to have a principal amount equal to the maximum potential liability of NGL Energy and its Restricted Subsidiaries thereunder) not to exceed the greater of (a) $1.05 billion and (b) $250.0 millionplus 35.0% of the Total Assets of NGL Energy determined on the date of such incurrence;

(2) the incurrence by NGL Energy or its Restricted Subsidiaries of Existing Indebtedness;

(3) the incurrence by the Issuers and the Guarantors of Indebtedness represented by (a) the notes and the related Note Guarantees to be issued on the Issue Date and (b) the Exchange Notes and the related Note Guarantees to be issued pursuant to the Registration Rights Agreement;

(4) the incurrence by NGL Energy or any of its Restricted Subsidiaries of Indebtedness represented by Capital Lease Obligations, mortgage financings or purchase money obligations, in each case, incurred for the purpose of financing all or any part of the purchase price or cost of design, construction, installation or improvement of property, plant or equipment used in the business of NGL Energy or any of its Restricted Subsidiaries, in an aggregate principal amount, including all Permitted Refinancing Indebtedness incurred to extend, renew, refund, refinance, replace, defease or discharge any Indebtedness incurred pursuant to this clause (4) at any time;provided that, immediately after giving effect to any such incurrence, the principal amount of all Indebtedness incurred pursuant to this clause (4) and then outstanding does not exceed the greater of (a) $75.0 million and (b) 3.25% of the Total Assets of NGL Energy;

(5) the incurrence by NGL Energy or any of its Restricted Subsidiaries of Permitted Refinancing Indebtedness in exchange for, or the net proceeds of which are used to extend, renew, refund, refinance, replace, defease, discharge or otherwise retire for value, any Indebtedness (other than intercompany Indebtedness) or Disqualified Stock of NGL Energy, or Indebtedness (other than intercompany Indebtedness) or preferred stock of any Restricted Subsidiary, in each case that was permitted by the indenture to be incurred under the first paragraph of this covenant or clause (2), (3), (4), (13), (14) or (15) of this paragraph or this clause (5);

(6) the incurrence by NGL Energy or any of its Restricted Subsidiaries of intercompany Indebtedness between or among NGL Energy and any of its Restricted Subsidiaries;provided, however, that:

(a) if NGL Energy or any Guarantor is the obligor on such Indebtedness and the payee is not NGL Energy or a Guarantor, such Indebtedness must be unsecured and expressly subordinated to the prior payment in full in cash of all Obligations then due with respect to the notes, in the case of NGL Energy, or the Note Guarantee, in the case of a Guarantor; and

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Energy nor a Restricted Subsidiary, will be deemed, in each case, to constitute an incurrence of such Indebtedness by NGL Energy or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7) the issuance by any of NGL Energy's Restricted Subsidiaries to NGL Energy or to any of its Restricted Subsidiaries of shares of preferred stock;provided, however, that:

(a) any subsequent issuance or transfer of Equity Interests that results in any such preferred stock being held by a Person other than NGL Energy or a Restricted Subsidiary; and

(b) any sale or other transfer of any such preferred stock to a Person that is neither NGL Energy nor a Restricted Subsidiary, will be deemed, in each case, to constitute an issuance of such preferred stock by such Restricted Subsidiary that was not permitted by this clause (7);

(8) the incurrence by NGL Energy or any of its Restricted Subsidiaries of Hedging Obligations in the ordinary course of business and not for speculative purposes;

(9) the Guarantee by NGL Energy or any of its Restricted Subsidiaries of Indebtedness of NGL Energy or a Restricted Subsidiary to the extent that the guaranteed Indebtedness was permitted to be incurred by another provision of this covenant;provided that if the Indebtedness being guaranteed is subordinated to orpari passu with the notes, then the Guarantee must be subordinated orpari passu, as applicable, to the same extent as the Indebtedness Guaranteed;

(10) the incurrence by NGL Energy or any Restricted Subsidiary of Indebtedness consisting of the financing of insurance premiums in customary amounts consistent with the operations and business of NGL Energy and its Restricted Subsidiaries;

(11) the incurrence by NGL Energy or any of its Restricted Subsidiaries of Indebtedness constituting reimbursement obligations with respect to letters of credit;provided that, upon the drawing of such letters of credit, such obligations are reimbursed within 30 days following such drawing;

(12) the incurrence by NGL Energy or any of its Restricted Subsidiaries of liability in respect of the Indebtedness of any Unrestricted Subsidiary or any Joint Venture but only to the extent that such liability is the result of NGL Energy's or any such Restricted Subsidiary's being a general partner or member of, or owner of an Equity Interest in, such Unrestricted Subsidiary or Joint Venture and not as guarantor of such Indebtedness;

provided that, immediately after giving effect to any such incurrence, the principal amount of all Indebtedness incurred pursuant to this clause (12) and then outstanding does not exceed $25.0 million;

(13) the incurrence by NGL Energy or any of its Restricted Subsidiaries of Permitted Acquisition Indebtedness;

(14) the incurrence by any Foreign Subsidiary of Indebtedness that, in the aggregate together with all other Indebtedness of all Foreign Subsidiaries (including all Permitted Refinancing Indebtedness incurred to extend, renew, refund, refinance, replace, defease, discharge or otherwise retire for value any Indebtedness incurred pursuant to this clause (14)), does not exceed $50.0 million; and

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Indebtedness or Disqualified Stock incurred or issued pursuant to this clause (15)) does not exceed the greater of (a) $75.0 million and (b) 3.25% of the Total Assets of NGL Energy determined on the date of such incurrence.

NGL Energy will not incur, and will not permit any Guarantor to incur, any Indebtedness (including Permitted Debt) that is contractually subordinated in right of payment to any other Indebtedness of NGL Energy or such Guarantor unless such Indebtedness is also contractually subordinated in right of payment to the notes or the applicable Note Guarantee on substantially identical terms;provided, however, that no Indebtedness will be deemed to be contractually subordinated in right of payment to any other Indebtedness of NGL Energy or any Guarantor solely by virtue of being unsecured or by virtue of being secured on a junior priority basis.

For purposes of determining compliance with this "Incurrence of Indebtedness and Issuance of Preferred Stock" covenant, in the event that an item of Indebtedness (including Acquired Debt) meets the criteria of more than one of the categories of Permitted Debt described in clauses (1) through (15) above, or is entitled to be incurred pursuant to the first paragraph of this covenant, NGL Energy will be permitted in its sole discretion to divide, redivide, classify or reclassify such item of Indebtedness on the date of its incurrence, and later divide, redivide, classify or reclassify all or a portion of such item of Indebtedness, in any manner that complies with this covenant.

Indebtedness under Credit Facilities outstanding on the date on which notes are first issued and authenticated under the indenture will initially be deemed to have been incurred on such date in reliance on the exception provided by clause (1) of the definition of Permitted Debt. The accrual of interest or preferred stock dividends, the accretion or amortization of original issue discount, the payment of interest on any Indebtedness in the form of additional Indebtedness with the same terms, the reclassification of any obligation of NGL Energy or any Restricted Subsidiary as Indebtedness due to a change in accounting principles, and the payment of dividends on preferred stock or Disqualified Stock in the form of additional shares of the same class of preferred stock or Disqualified Stock will not be deemed to be an incurrence of Indebtedness or an issuance of preferred stock or Disqualified Stock for purposes of this covenant;provided that, in each such case, the amount thereof is included in Fixed Charges of NGL Energy as accrued to the extent required by the definition of such term.

For purposes of determining compliance with any U.S. dollar-denominated restriction on the incurrence of Indebtedness, the U.S. dollar-equivalent principal amount of Indebtedness denominated in a foreign currency shall be utilized, calculated based on the relevant currency exchange rate in effect on the date such Indebtedness was incurred, in the case of term Indebtedness, or first committed, in the case of revolving credit Indebtedness;provided that if such Indebtedness is incurred to refinance other Indebtedness denominated in a foreign currency, and such refinancing would cause the applicable U.S. dollar-denominated restriction to be exceeded if calculated at the relevant currency exchange rate in effect on the date of such refinancing, such U.S. dollar-denominated restriction shall be deemed not to have been exceeded so long as the principal amount of such refinancing Indebtedness does not exceed the principal amount of such Indebtedness being refinanced. Notwithstanding any other provision of this covenant, the maximum amount of Indebtedness that NGL Energy or any Restricted Subsidiary may incur pursuant to this covenant shall not be deemed to be exceeded solely as a result of fluctuations in exchange rates or currency values. The principal amount of any Permitted Refinancing Indebtedness incurred to refinance other Indebtedness, if incurred in a different currency from the Indebtedness being refinanced, shall be calculated based on the currency exchange rate applicable to the currencies in which such Permitted Refinancing Indebtedness is denominated that is in effect on the date of such refinancing.

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Liens

NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, create, incur, assume or otherwise cause or suffer to exist or become effective any Lien of any kind (other than Permitted Liens) securing Indebtedness upon any of their property or assets, now owned or hereafter acquired, unless the notes or any Note Guarantee are secured on an equal and ratable basis with the Indebtedness so secured until such time as such Indebtedness is no longer secured by a Lien (other than a Permitted Lien).

Any Lien securing the notes or Note Guarantees created pursuant to the preceding paragraph shall provide by its terms that such Lien shall be automatically and unconditionally released and discharged upon the unconditional release and discharge of the initial Lien whose existence resulted in the creation of such Lien securing the notes or Note Guarantees.

Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries

NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create or permit to exist or become effective any consensual encumbrance or restriction on the ability of any Restricted Subsidiary to:

(1) pay dividends or make any other distributions on its Capital Stock to NGL Energy or any of its Restricted Subsidiaries, or pay any Indebtedness owed to NGL Energy or any of its Restricted Subsidiaries;provided that the priority that any series of preferred stock of a Restricted Subsidiary has in receiving dividends or liquidating distributions before dividends or liquidating distributions are paid in respect of common stock of such Restricted Subsidiary shall not constitute a restriction on the ability to make dividends or distributions on Capital Stock for purposes of this covenant;

(2) make loans or advances to NGL Energy or any of its Restricted Subsidiaries (it being understood that the subordination of loans or advances made to NGL Energy or any such Restricted Subsidiary to other Indebtedness incurred by NGL Energy or any such Restricted Subsidiary shall not be deemed a restriction on the ability to make loans or advances); or

(3) sell, lease or transfer any of its properties or assets to NGL Energy or any of its Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(1) agreements governing the Credit Agreement, any Existing Indebtedness or any Credit Facilities or any other agreements or instruments, in each case as in effect on the Issue Date and any amendments, restatements, modifications, renewals, extensions, increases, supplements, refundings, replacements or refinancings of those agreements or the Indebtedness to which they relate;provided that the encumbrances or restrictions contained in the amendments, restatements, modifications, renewals, extensions, increases, supplements, refundings, replacements or refinancings are, in the reasonable good faith judgment of the Chief Financial Officer of the General Partner, not materially more restrictive, taken as a whole, with respect to such dividend and other payment restrictions than those contained in those agreements on the Issue Date;

(2) the indenture, the notes and the Note Guarantees;

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Financial Officer of the General Partner, not materially more restrictive, taken as a whole, than the provisions contained in the Credit Agreement and in the indenture as in effect on the Issue Date;

(4) the issuance of preferred stock by a Restricted Subsidiary or the payment of dividends thereon in accordance with the terms thereof;provided that issuance of such preferred stock is permitted pursuant to the covenant described under the caption "—Incurrence of Indebtedness and Issuance of Preferred Stock" and the terms of such preferred stock do not expressly restrict the ability of a Restricted Subsidiary to pay dividends or make any other distributions on its Capital Stock (other than requirements to pay dividends or liquidation preferences on such preferred stock prior to paying any dividends or making any other distributions on such other Capital Stock);

(5) applicable law, rule, regulation, order, approval, license, permit or similar restriction;

(6) any instrument governing Indebtedness or Capital Stock of a Person acquired by NGL Energy or any of its Restricted Subsidiaries as in effect at the time of such acquisition (except to the extent such Indebtedness or Capital Stock was incurred in connection with or in contemplation of such acquisition), which encumbrance or restriction is not applicable to any Person, or the properties or assets of any Person, other than the Person, or the property or assets of the Person, so acquired and any amendments, restatements, modifications, renewals, extensions, increases, supplements, refundings, replacements or refinancings thereof;provided that, the encumbrances or restrictions contained in any such amendments, restatements, modifications, renewals, extensions, increases, supplements, refundings, replacements or refinancings are, in the reasonable good faith judgment of the Chief Financial Officer of the General Partner, not materially more restrictive, taken as a whole, than those in effect on the date of the acquisition;provided, further, that, in the case of Indebtedness, such Indebtedness was permitted by the terms of the indenture to be incurred;

(7) customary non-assignment provisions in contracts or licenses, easements or leases, in each case, entered into in the ordinary course of business;

(8) purchase money obligations, security agreements or mortgage financings for property acquired in the ordinary course of business and Capital Lease Obligations that impose restrictions on the property purchased or leased of the nature described in clause (3) of the preceding paragraph;

(9) any agreement for the sale or other disposition of the Equity Interests in, or all or substantially all of the properties or assets of, a Restricted Subsidiary that restricts distributions by that Restricted Subsidiary pending the sale or other disposition;

(10) Permitted Refinancing Indebtedness;provided that the restrictions contained in the agreements governing such Permitted Refinancing Indebtedness are not materially more restrictive, taken as a whole, than those contained in the agreements governing the Indebtedness being refinanced;

(11) Liens permitted to be incurred under the provisions of the covenant described above under the caption "—Covenants—Liens" that limit the right of the debtor to dispose of the assets subject to such Liens;

(12) provisions limiting the disposition or distribution of assets or property in joint venture agreements, asset sale agreements, sale-leaseback agreements, stock sale agreements and other similar agreements (including agreements entered into in connection with a Restricted Investment) entered into with the approval of NGL Energy's Board of Directors, which limitation is applicable only to the assets that are the subject of such agreements;

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(13) any instrument governing Indebtedness of a FERC Subsidiary;provided that such Indebtedness was otherwise permitted by the terms of the indenture to be incurred;

(14) encumbrances or restrictions on cash, Cash Equivalents or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;

(15) any agreement or instrument relating to any property or assets acquired after the Issue Date, so long as such encumbrance or restriction relates only to the property or assets so acquired and is not and was not created in anticipation of such acquisition;

(16) Hedging Obligations permitted from time to time under the indenture; and

(17) Indebtedness incurred or Capital Stock issued by any Restricted Subsidiary;provided that the restrictions contained in the agreements or instruments governing such Indebtedness or Capital Stock (a) apply only in the event of a payment default or a default with respect to a financial covenant in such agreement or instrument or (b) will not materially affect NGL Energy's ability to make principal, interest and premium, if any, on the notes, as determined in the reasonable good faith judgment of the Chief Executive Officer and the Chief Financial Officer of the General Partner.

Merger, Consolidation or Sale of Assets

Neither of the Issuers may (1) consolidate or merge with or into another Person (regardless of whether such Issuer is the surviving entity), or (2) sell, assign, transfer, convey, lease or otherwise dispose of all or substantially all of its properties or assets, in one or more related transactions, to another Person, unless:

(1) either: (a) such Issuer is the surviving entity; or (b) the Person formed by or surviving any such consolidation or merger (if other than such Issuer) or to which such sale, assignment, transfer, conveyance or other disposition has been made is a Person organized or existing under the laws of the United States, any state of the United States or the District of Columbia;provided,however, that Finance Corp. may not consolidate or merge with or into any Person other than a corporation satisfying such requirement so long as NGL Energy is not a corporation;

(2) the Person formed by or surviving any such consolidation or merger (if other than such Issuer) or the Person to which such sale, assignment, transfer, conveyance or other disposition has been made assumes all the obligations of such Issuer under the notes and the indenture (and the Registration Rights Agreement, if any obligations thereunder remain unsatisfied) pursuant to a supplemental indenture or other agreement reasonably satisfactory to the trustee;

(3) immediately after such transaction, no Default or Event of Default exists;

(4) in the case of a transaction involving NGL Energy and not Finance Corp., immediately after giving effect to such transaction and any related financing transaction on apro forma basis as if the same had occurred at the beginning of the applicable four-quarter period, either (a) NGL Energy or the Person formed by or surviving any such consolidation or merger (if other than NGL Energy), or to which such sale, assignment, transfer, conveyance, lease or other disposition has been made, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock," or (b) the Fixed Charge Coverage Ratio of NGL Energy or the Person formed by or surviving any such consolidation or merger (if other than NGL Energy), or to which such sale, assignment, transfer, conveyance, lease or other disposition has been made, is equal to or greater than the Fixed Charge Coverage Ratio of NGL Energy immediately prior to such transaction; and

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(5) such Issuer has delivered to the trustee an Officers' Certificate and an opinion of counsel, each stating that such consolidation, merger or disposition and, if a supplemental indenture is required, such supplemental indenture, comply with the indenture.

Notwithstanding the restrictions described in the foregoing clause (4), any Restricted Subsidiary (other than Finance Corp.) may consolidate with, merge into or dispose of all or part of its properties or assets to NGL Energy without complying with the preceding clause (4) in connection with any such consolidation, merger or disposition.

Notwithstanding the second preceding paragraph, NGL Energy is permitted to reorganize as any other form of entity,provided that:

(1) the reorganization involves the conversion (by merger, sale, contribution or exchange of assets or otherwise) of NGL Energy into a form of entity other than a limited partnership formed under Delaware law;

(2) the entity so formed by or resulting from such reorganization is an entity organized or existing under the laws of the United States, any state thereof or the District of Columbia;

(3) the entity so formed by or resulting from such reorganization assumes all the obligations of NGL Energy under the notes and the indenture (and the Registration Rights Agreement, if any obligations thereunder remain unsatisfied) pursuant to a supplemental indenture or other agreement in a form reasonably satisfactory to the trustee;

(4) immediately after such reorganization no Default or Event of Default exists; and

(5) such reorganization is not materially adverse to the holders or Beneficial Owners of the notes (for purposes of this clause (5), a reorganization will not be considered materially adverse to the holders or Beneficial Owners of the notes solely because the successor or survivor of such reorganization (a) is subject to federal or state income taxation as an entity or (b) is considered to be an "includible corporation" of an affiliated group of corporations within the meaning of Section 1504(b) of the Internal Revenue Code or any similar state or local law).

For purposes of the foregoing, the transfer (by lease, assignment, sale or otherwise, in a single transaction or series of transactions) of all or substantially all of the properties or assets of one or more Restricted Subsidiaries, which properties or assets, if held by NGL Energy instead of such Restricted Subsidiaries, would constitute all or substantially all of the properties or assets of NGL Energy on a consolidated basis, shall be deemed to be the transfer of all or substantially all of the properties or assets of NGL Energy.

Notwithstanding anything in the indenture to the contrary, in the event that NGL Energy becomes a corporation or NGL Energy or the Person formed by or surviving any consolidation or merger (permitted in accordance with the terms of the indenture) is a corporation, Finance Corp. may be merged into NGL Energy or it may be dissolved and cease to be an Issuer.

Upon any consolidation or merger or any sale, assignment, transfer, conveyance, lease or other disposition of all or substantially all of the properties or assets of an Issuer in accordance with the foregoing in which such Issuer is not the surviving entity, the surviving Person formed by such consolidation or into or with which such Issuer is merged or to which such sale, assignment, transfer, conveyance, lease or other disposition is made shall succeed to, and be substituted for, and may exercise every right and power of, such Issuer under the indenture with the same effect as if such surviving Person had been named as such Issuer in the indenture, and thereafter (except in the case of a lease of all or substantially all of such Issuer's properties or assets), such Issuer will be relieved of all obligations and covenants under the indenture and the notes. Although there is a limited body of case law interpreting the phrase "substantially all," there is no precise established definition of the phrase under applicable law. Accordingly, in certain circumstances there may be a degree of uncertainty as to

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whether a particular transaction would involve "all or substantially all" of the properties or assets of a Person.

Transactions with Affiliates

NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, make any payment to or sell, lease, transfer or otherwise dispose of any of its properties or assets to, or purchase any property or assets from, or enter into or make or amend any transaction, contract, agreement, understanding, loan, advance or guarantee with, or for the benefit of, any Affiliate of NGL Energy (each, an "Affiliate Transaction"), unless:

(1) the Affiliate Transaction is on terms that are no less favorable to NGL Energy or the relevant Restricted Subsidiary than those that would have been obtained in a comparable transaction by NGL Energy or such Restricted Subsidiary with an unrelated Person or, if in the good faith judgment of the Board of Directors of NGL Energy, no comparable transaction is available with which to compare such Affiliate Transaction, such Affiliate Transaction is otherwise fair to NGL Energy or the relevant Restricted Subsidiary from a financial point of view; and

(2) NGL Energy delivers to the trustee:

(a) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $20.0 million but less than or equal to $40.0 million, an Officers' Certificate certifying that such Affiliate Transaction or series of related Affiliate Transactions complies with this covenant; and

(b) with respect to any Affiliate Transaction or series of related Affiliate Transactions involving aggregate consideration in excess of $40.0 million, a resolution of the Board of Directors of NGL Energy set forth in an Officers' Certificate certifying that such Affiliate Transaction or series of related Affiliate Transactions complies with this covenant and that such Affiliate Transaction or series of related Affiliate Transactions has been approved by either the Conflicts Committee of the Board of Directors of NGL Energy (so long as the members of the Conflicts Committee approving the Affiliate transaction or series of related Affiliate Transactions are disinterested) or a majority of the disinterested members of the Board of Directors of NGL Energy, if any.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(1) any employment, consulting or similar agreement or arrangement, employee benefit plan, equity award, equity option, equity appreciation, officer or director indemnification agreement, restricted unit agreement, severance agreement or other compensation plan or arrangement entered into by the General Partner, NGL Energy or any of its Restricted Subsidiaries in the ordinary course of business and payments, awards, grants or issuances of securities made pursuant thereto;

(2) transactions between or among NGL Energy and/or its Restricted Subsidiaries;

(3) transactions with a Person (other than an Unrestricted Subsidiary) that is an Affiliate of NGL Energy solely because NGL Energy owns, directly or through a Subsidiary, an Equity Interest in, or controls, such Person;

(4) payment of reasonable fees and reimbursements of expenses (pursuant to indemnity arrangements or otherwise) of, and compensation paid to, and indemnity or insurance provided on behalf of, officers, directors, employees or consultants of the General Partner, NGL Energy or any of its Restricted Subsidiaries, including, but not limited to, reimbursement or advancement of out-of-pocket expenses and provisions of officers' and directors' liability insurance;

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(5) any issuance of Equity Interests (other than Disqualified Stock) to, or receipt of capital contributions from, Affiliates of NGL Energy;

(6) Restricted Payments that do not violate the provisions of the indenture described above under the caption "—Covenants—Restricted Payments" or any Permitted Investments;

(7) payments to the General Partner with respect to reimbursement for expenses in accordance with the Partnership Agreement as in effect on the Issue Date and as it may be amended,provided that any such amendment is not less favorable to NGL Energy in any material respect than the agreement prior to such amendment;

(8) transactions between NGL Energy or any of its Restricted Subsidiaries and any other Person, a director of which is also on the Board of Directors of NGL Energy, and such common director is the sole cause for such other Person to be deemed an Affiliate of NGL Energy or any of its Restricted Subsidiaries;provided,however, that such director abstains from voting as a member of the Board of Directors of NGL Energy on any transaction with such other Person;

(9) (a) guarantees by NGL Energy or any of its Restricted Subsidiaries of performance of obligations of Unrestricted Subsidiaries in the ordinary course of business, except for guarantees of Indebtedness in respect of borrowed money, and (b) pledges by NGL Energy or any of its Restricted Subsidiaries of Equity Interests in Unrestricted Subsidiaries for the benefit of lenders or other creditors of Unrestricted Subsidiaries;

(10) payments to an Affiliate in respect of the notes or the Note Guarantees or any other Indebtedness of NGL Energy or any Restricted Subsidiary on the same basis as concurrent payments made or offered to be made in respect thereof to non-Affiliates;

(11) payment of loans or advances to employees not to exceed $5.0 million in the aggregate at any one time outstanding;

(12) any Affiliate Transaction with a Person in its capacity as a holder of Indebtedness or Capital Stock of NGL Energy or any Restricted Subsidiary if such Person is treated no more favorably than the other holders of Indebtedness or Capital Stock of NGL Energy or such Restricted Subsidiary;

(13) transactions with Unrestricted Subsidiaries, customers, clients, suppliers or purchasers or sellers of goods or services, or lessors or lessees of property, in each case in the ordinary course of business and otherwise in compliance with the terms of the indenture which are, in the aggregate (taking into account all the costs and benefits associated with such transactions), not materially less favorable to NGL Energy and its Restricted Subsidiaries than those that would have been obtained in a comparable transaction by NGL Energy or such Restricted Subsidiary with an unrelated person, in the good faith determination of NGL Energy's Board of Directors or any officer of NGL Energy involved in or otherwise familiar with such transaction, or are on terms at least as favorable as might reasonably have been obtained at such time from an unaffiliated party;

(14) any transaction in which NGL Energy or any of its Restricted Subsidiaries, as the case may be, delivers to the trustee a letter from an accounting, appraisal, advisory or investment banking firm of national standing stating that such transaction is fair to NGL Energy or such Restricted Subsidiary from a financial point of view or that such transaction meets the requirements of clause (1) of the preceding paragraph; and

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(15) in the case of contracts for gathering, transporting, treating, processing, marketing, distributing, storing or otherwise handling Hydrocarbons, or activities or services reasonably related or ancillary thereto, or other operational contracts, any such contracts that are entered into in the ordinary course of business on terms substantially similar to those contained in similar contracts entered into by NGL Energy or any of its Restricted Subsidiaries and third parties, or if neither NGL Energy nor any of its Restricted Subsidiaries has entered into a similar contract with a third party, then the terms of which are no less favorable than those available from third parties on an arm's-length basis.

Business Activities of Finance Corp.

Finance Corp. will not hold any material assets, become liable for any material obligations, engage in any trade or business, or conduct any business activity, other than the issuance of capital stock to NGL Energy, the incurrence of Indebtedness as a co-issuer, co-obligor or guarantor of Indebtedness incurred by NGL Energy including without limitation the notes) that is permitted to be incurred by NGL Energy under the covenant described under "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock" above, and activities incidental thereto.

Additional Note Guarantees

If, on any date after the Issue Date, any Domestic Subsidiary that is not already a Guarantor, Guarantees (or otherwise becomes liable for) any Obligations under any Credit Facility, including the Credit Agreement, then, within 20 Business Days after such date, such Domestic Subsidiary will unconditionally Guarantee the notes and concurrently become a Guarantor by executing a supplemental indenture in substantially the form specified in the indenture. Each Note Guarantee of a Guarantor will be released automatically at such time as such Guarantor is discharged or otherwise released from all its Obligations in respect of its Guarantee of (or other liability for) any Obligations under any Credit Facility;provided that such discharge or other release did not result directly from payment by such Guarantor in satisfaction of (a) its liability as a guarantor pursuant to such Guarantee, or (b) its primary liability for such Obligations (after demand or default under such Credit Facility). Furthermore, each Note Guarantee shall be subject to release as described under "—Note Guarantees."

Designation of Restricted and Unrestricted Subsidiaries

The Board of Directors of NGL Energy may designate any Restricted Subsidiary to be an Unrestricted Subsidiary if that designation would not cause a Default. If a Restricted Subsidiary is designated as an Unrestricted Subsidiary, the aggregate Fair Market Value of all outstanding Investments owned by NGL Energy and its Restricted Subsidiaries in the Subsidiary designated as an Unrestricted Subsidiary will be deemed to be an Investment made as of the time of the designation and will reduce the amount available for Restricted Payments under the covenant described above under the caption "—Covenants—Restricted Payments" or under one or more clauses of the definition of Permitted Investments, as determined by NGL Energy. That designation will only be permitted if the Investment would be permitted at that time and if the Restricted Subsidiary otherwise meets the definition of an Unrestricted Subsidiary. The Board of Directors of NGL Energy may redesignate any Unrestricted Subsidiary to be a Restricted Subsidiary if that redesignation would not cause a Default.

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Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption "—Incurrence of Indebtedness and Issuance of Preferred Stock," NGL Energy will be in default of such covenant.

The Board of Directors of NGL Energy may at any time designate any Unrestricted Subsidiary to be a Restricted Subsidiary;provided that such designation will be deemed to be an incurrence of Indebtedness by a Restricted Subsidiary of any outstanding Indebtedness of such Unrestricted Subsidiary, and such designation will only be permitted if: (1) such Indebtedness is permitted under the covenant described under the caption "—Incurrence of Indebtedness and Issuance of Preferred Stock," calculated on apro forma basis as if such designation had occurred at the beginning of the applicable reference period; and (2) no Default or Event of Default would be in existence following such designation.

Reports

Regardless of whether required by the rules and regulations of the SEC, so long as any notes are outstanding, NGL Energy will file with the SEC (unless the SEC will not accept such a filing) within the time periods specified in the SEC's rules and regulations, and upon request, NGL Energy will furnish (without exhibits) to the trustee for delivery to the holders of the notes:

(1) all quarterly and annual reports that would be required to be contained in a filing with the SEC on Forms 10-Q and 10-K if NGL Energy were required to file such forms, including a "Management's Discussion and Analysis of Financial Condition and Results of Operations" and, with respect to the annual information only, a report thereon by NGL Energy's certified independent accountants; and

(2) all current reports that would be required to be filed with the SEC on Form 8-K if NGL Energy were required to file such reports.

NGL Energy will be deemed to have furnished such reports and information described above to the holders of Notes (and the trustee shall be deemed to have delivered such reports and information to the holders of the notes) if NGL Energy has filed such reports or information, respectively, with the SEC using the EDGAR filing system (or any successor filing system of the SEC) or, if the SEC will not accept such reports or information, if NGL Energy has posted such reports or information, respectively, on its website, and such reports or information, respectively, are available to holders of notes through internet access.

For the avoidance of doubt, (a) such information will not be required to contain the separate financial information for Guarantors as contemplated by Rule 3-10 of Regulation S-X or any financial statements of unconsolidated subsidiaries or 50% or less owned Persons as contemplated by Rule 3-09 of Regulation S-X or any schedules required by Regulation S-X, or in each case any successor provisions, and (b) such information shall not be required to comply with Regulation G under the Exchange Act or Item 10(e) of Regulation S-K with respect to any non-GAAP financial measures contained therein.

Except as provided above, all such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports.

If NGL Energy has designated any of its Subsidiaries as Unrestricted Subsidiaries, then, to the extent material, the quarterly and annual financial information required by the preceding paragraphs will include a reasonably detailed presentation, either on the face of the financial statements or in the footnotes thereto, and in Management's Discussion and Analysis of Financial Condition and Results of Operations, of the financial condition and results of operations of NGL Energy and its Restricted

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Subsidiaries separate from the financial condition and results of operations of its Unrestricted Subsidiaries.

Any and all Defaults or Events of Default arising from a failure to furnish in a timely manner any financial information required by this covenant shall be deemed cured (and NGL Energy shall be deemed to be in compliance with this covenant) upon furnishing such financial information as contemplated by this covenant (but without regard to the date on which such financial statement or report is so furnished);provided that such cure shall not otherwise affect the rights of the holders under "—Events of Defaults and Remedies" if the principal of, premium, if any, on, and interest, if any, on, the notes have been accelerated in accordance with the terms of the indenture and such acceleration has not been rescinded or cancelled prior to such cure.

In addition, NGL Energy will hold and participate in annual conference calls with the holders of the notes, beneficial owners of the notes, bona fide prospective investors, securities analysts and market makers to discuss the financial information required to be furnished pursuant to clause (1) above no later than ten Business Days after distribution of such financial information. NGL Energy shall be permitted to combine this conference call with any other conference call for other debt or equity holders or lenders.

In addition, NGL Energy and the Guarantors agree that, for so long as any notes remain outstanding, if at any time they are not required to file with the SEC the reports required by the preceding paragraphs, they will furnish to the holders of notes and to securities analysts and prospective investors, upon their request, the information required to be delivered pursuant to Rule 144A(d)(4) under the Securities Act.

Events of Default and Remedies

Each of the following is an "Event of Default" with respect to the notes:

(1) default for 30 days in the payment when due of interest on the notes;

(2) default in the payment when due (at maturity, upon redemption or otherwise) of the principal of, or premium, if any, on, the notes;

(3) failure by NGL Energy to comply with its obligations under "—Covenants—Merger, Consolidation or Sale of Substantially All Assets" or to consummate a purchase of notes when required pursuant to the covenants described under the caption "—Repurchase at the Option of Holders;"

(4) failure by NGL Energy or any of its Restricted Subsidiaries for 30 days after written notice from the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes to comply with the provisions described under the captions "—Covenants—Restricted Payments" or "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock" or to comply with the provisions described under the captions "—Repurchase at the Option of Holders" to the extent not described in clause (3) above;

(5) (a) except as addressed in subclause (b) of this clause (5), failure by NGL Energy or any of its Restricted Subsidiaries for 60 days after written notice from the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes to comply with any of the other agreements in the indenture or the notes or (b) failure by NGL Energy for 180 days after notice from the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes to comply with the covenant described under the caption "—Covenants—Reports;"

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by NGL

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Energy or any of its Restricted Subsidiaries (or the payment of which is guaranteed by NGL Energy or any of its Restricted Subsidiaries), whether such Indebtedness or Guarantee now exists, or is created after the Issue Date, if that default:

(a) is caused by a failure to pay principal of, premium on, if any, or interest, if any, on such Indebtedness prior to the expiration of the grace period provided in such Indebtedness on the date of such default (a "Payment Default"); or

(b) results in the acceleration of such Indebtedness prior to its Stated Maturity,

and, in each case, the principal amount of any such Indebtedness, together with the principal amount of any other such Indebtedness under which there has been a Payment Default or the maturity of which has been so accelerated, aggregates $30.0 million or more;provided that if, prior to any acceleration of the notes, (i) any such default is cured or waived, (ii) any such acceleration of such Indebtedness is rescinded, or (iii) such Indebtedness is repaid, within a period of 10 Business Days from the continuation of such default beyond the applicable grace period or the occurrence of such acceleration, as the case may be, any Default or Event of Default (but not any acceleration of the notes) shall be automatically rescinded, so long as such rescission does not conflict with any judgment or decree;

(7) failure by NGL Energy or any Significant Subsidiary or group of NGL Energy's Restricted Subsidiaries that, taken together (as of the latest audited consolidated financial statements for NGL Energy and its Restricted Subsidiaries), would constitute a Significant Subsidiary to pay final judgments (entered by a court or courts of competent jurisdiction) aggregating in excess of $30.0 million (net of any amounts that a reputable and creditworthy insurance company has acknowledged liability for in writing), which judgments are not paid, discharged or stayed for a period of 60 days;

(8) except as permitted by the indenture, any Note Guarantee is held in any judicial proceeding to be unenforceable or invalid or ceases for any reason to be in full force and effect, or any Guarantor, or any Person acting on behalf of any Guarantor, denies or disaffirms its obligations under its Note Guarantee, except, in each case, by reason of the release of such Note Guarantee in accordance with the indenture; and

(9) certain events of bankruptcy or insolvency described in the indenture with respect to NGL Energy, Finance Corp. or any of NGL Energy's Restricted Subsidiaries that is a Significant Subsidiary or any group of its Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary.

The indenture will provide that in the case of an Event of Default arising from certain events of bankruptcy or insolvency, with respect to NGL Energy, any Restricted Subsidiary that is a Significant Subsidiary or any group of Restricted Subsidiaries that, taken together, would constitute a Significant Subsidiary, all then outstanding notes will become due and payable immediately without further action or notice. However, the effect of such provision may be limited by applicable law. If any other Event of Default occurs and is continuing, the trustee or the holders of at least 25% in aggregate principal amount of the then outstanding notes may declare all of the notes to be due and payable immediately by notice in writing to NGL Energy and, in case of a notice by holders, also to the trustee specifying the respective Event of Default and that it is a notice of acceleration.

Holders of the notes may not enforce the indenture or the notes except as provided in the indenture. Subject to certain limitations, holders of a majority in aggregate principal amount of the then outstanding notes may direct the trustee in its exercise of any trust or power. The trustee may withhold from holders of the notes notice of any continuing Default or Event of Default if it determines that withholding notice is in their interest, except a Default or Event of Default relating to the payment of principal, interest or premium, if any.

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Subject to the provisions of the indenture relating to the duties of the trustee, in case an Event of Default occurs and is continuing, the trustee will be under no obligation to exercise any of the rights or powers under the indenture at the request or direction of any holders of notes unless such holders have offered to the trustee reasonable indemnity or security against any loss, liability or expense. Except to enforce the right to receive payment of principal, premium, if any, or interest, when due, no holder of a note may pursue any remedy with respect to the indenture or the notes unless:

(1) such holder has previously given the trustee written notice that an Event of Default is continuing;

(2) holders of at least 25% in aggregate principal amount of the then outstanding notes make a written request to the trustee to pursue the remedy;

(3) such holder or holders offer and, if requested, provide to the trustee security or indemnity reasonably satisfactory to the trustee against any loss, liability or expense;

(4) the trustee does not comply with such request within 60 days after receipt of the request and the offer of security or indemnity; and

(5) during such 60-day period, holders of a majority in aggregate principal amount of the then outstanding notes do not give the trustee a direction inconsistent with such request.

The holders of a majority in aggregate principal amount of the then outstanding notes by written notice to the trustee may, on behalf of the holders of all of the notes, rescind an acceleration and its consequences if the rescission would not violate any judgment or decree and if all existing Events of Default (except nonpayment of principal, interest or premium or Liquidated Damages, if any, that has become due solely because of the acceleration) have been cured or waived.

The Issuers are required to deliver to the trustee annually a statement regarding compliance with the indenture. Within five Business Days of any executive officer of the General Partner or Finance Corp. becoming aware of any Default or Event of Default, the Issuers will be required to deliver to the trustee a statement specifying such Default or Event of Default.

No Personal Liability of Directors, Officers, Employees and Unitholders and No Recourse to General Partner

None of the General Partner or any director, officer, partner, employee, incorporator, manager, unitholder or other owner of Capital Stock of the General Partner, the Issuers or any Guarantor, as such, will have any liability for any obligations of the Issuers or the Guarantors under the notes, the indenture, the Note Guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. Each holder of notes by accepting a note waives and releases all such liability. The waiver and release are part of the consideration for issuance of the notes. The waiver may not be effective to waive liabilities under the federal securities laws.

Legal Defeasance and Covenant Defeasance

The Issuers may at any time, at the option of their respective Board of Directors evidenced by a resolution set forth in an Officers' Certificate, elect to have all of their obligations discharged with respect to the outstanding notes and all obligations of the Guarantors discharged with respect to their Note Guarantees ("Legal Defeasance") except for:

(1) the rights of holders of outstanding notes to receive payments in respect of the principal of, or interest or premium if any, on such notes when such payments are due from the trust referred to below;

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(2) the Issuers' obligations with respect to the notes concerning issuing temporary notes, registration of notes, mutilated, destroyed, lost or stolen notes and the maintenance of an office or agency for payment and money for security payments held in trust;

(3) the rights, powers, trusts, duties and immunities of the trustee under the indenture, and the Issuers' and the Guarantors' obligations in connection therewith; and

(4) the Legal Defeasance provisions of the indenture.

In addition, the Issuers may, at their option and at any time, elect to have their obligations and the obligations of the Guarantors released with respect to the provisions of the indenture described above under "—Repurchase at the Option of Holders" and under "—Covenants" (other than the covenant described under "—Covenants—Merger, Consolidation or Sale of Assets," except to the extent described below) and the limitation imposed by clause (4) under "—Covenants—Merger, Consolidation or Sale of Assets" (such release and termination being referred to as "Covenant Defeasance"), and thereafter any failure to comply with such obligations or provisions will not constitute a Default or Event of Default with respect to the notes. In the event Covenant Defeasance occurs, the Events of Default described under clauses (3) through (7) under the caption "—Events of Default and Remedies" and the Event of Default described under clause (9) under the caption "—Events of Default and Remedies" (but only with respect to Subsidiaries of NGL Energy), in each case, will no longer constitute an Event of Default with respect to the notes. If the Issuers exercise either their Legal Defeasance or Covenant Defeasance option, each Guarantor will be released and relieved of any Obligations under the indenture, including its Obligations in respect of its Subsidiary Guarantee.

In order to exercise either Legal Defeasance or Covenant Defeasance:

(1) The Issuers must irrevocably deposit with the trustee, in trust, for the benefit of the holders of the notes, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in amounts as will be sufficient, in the opinion of a nationally recognized investment bank, appraisal firm or firm of independent public accountants, to pay the principal of, or interest and premium, if any, on the outstanding notes on the stated date for payment thereof or on the applicable redemption date, as the case may be, and the Issuers must specify whether the notes are being defeased to such stated date for payment or to a particular redemption date;

(2) in the case of Legal Defeasance, the Issuers must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that (a) the Issuers have received from, or there has been published by, the Internal Revenue Service a ruling or (b) since the Issue Date, there has been a change in the applicable federal income tax law, in either case to the effect that, and based thereon such opinion of counsel will confirm that, the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Legal Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Legal Defeasance had not occurred;

(3) in the case of Covenant Defeasance, the Issuers must deliver to the trustee an opinion of counsel reasonably acceptable to the trustee confirming that the holders of the outstanding notes will not recognize income, gain or loss for federal income tax purposes as a result of such Covenant Defeasance and will be subject to federal income tax on the same amounts, in the same manner and at the same times as would have been the case if such Covenant Defeasance had not occurred;

(4) no Default or Event of Default has occurred and is continuing on the date of such deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit (and any similar concurrent deposit relating to other Indebtedness), and the granting of Liens to secure such borrowings);

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(5) such Legal Defeasance or Covenant Defeasance will not result in a breach or violation of, or constitute a default under, any material agreement or instrument (other than the indenture and the agreements governing any other Indebtedness being defeased, discharged or replaced) to which the Issuers or any of the Guarantors is a party or by which the Issuers or any of the Guarantors is bound;

(6) the Issuers must deliver to the trustee an Officers' Certificate stating that the deposit was not made by the Issuers with the intent of preferring the holders of notes over the other creditors of the Issuers with the intent of defeating, hindering, delaying or defrauding any creditors of the Issuers or others;

(7) NGL Energy must deliver to the trustee an Officers' Certificate, stating that all conditions precedent set forth in clauses (1) through (6) of this paragraph have been complied with; and

(8) NGL Energy must deliver to the trustee an opinion of counsel, stating that all conditions precedent set forth in clauses (2), (3) and (5) of this paragraph have been complied with.

Amendment, Supplement and Waiver

Except as provided in the next three succeeding paragraphs, the indenture or the notes or the Note Guarantees may be amended or supplemented with the consent of the holders of at least a majority in aggregate principal amount of the then outstanding notes (including, without limitation, additional notes, if any) voting as a single class (including, without limitation, consents obtained in connection with a tender offer or exchange offer for, or purchase of, the notes), and any existing Default or Event of Default (other than a Default or Event of Default in the payment of the principal of, premium on, if any, interest or Special Interest, if any, on, the notes, except a payment default resulting from an acceleration that has been rescinded) or compliance with any provision of the indenture or the notes or the Note Guarantees may be waived with the consent of the holders of a majority in aggregate principal amount of the then outstanding notes (including, without limitation, additional notes, if any) voting as a single class (including, without limitation, consents obtained in connection with a purchase of, or tender offer or exchange offer for, notes).

Without the consent of each holder of notes affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting holder):

(1) reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;

(2) reduce the principal of or change the fixed maturity of any note or alter or waive any of the provisions with respect to the redemption of the notes; provided, however, that any purchase or repurchase of notes, including pursuant to the covenants described above under the caption "—Repurchase at the Option of Holders," shall not be deemed a redemption of the notes;

(3) reduce the rate of or change the time for payment of interest, including default interest, on any note;

(4) waive a Default or Event of Default in the payment of principal of, or interest or premium, or Liquidated Damages, if any, on the notes (except a rescission of acceleration of the notes by the holders of at least a majority in aggregate principal amount of the then outstanding notes and a waiver of the payment default that resulted from such acceleration);

(5) make any note payable in currency other than that stated in the notes;

(6) make any change in the provisions of the indenture relating to waivers of past Defaults or the rights of holders of notes to receive payments of principal of, or interest or premium or Liquidated Damages, if any, on the notes;

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(7) waive a redemption payment with respect to any note; provided, however, that any purchase or repurchase of notes, including pursuant to the covenants described above under the caption "—Repurchase at the Option of Holders," shall not be deemed a redemption of the notes;

(8) release any Guarantor from any of its obligations under its Note Guarantee or the indenture, except in accordance with the terms of the indenture; or

(9) make any change in the preceding amendment, supplement and waiver provisions.

Notwithstanding the preceding, without the consent of any holder of notes, the Issuers, the Guarantors and the trustee may amend or supplement the indenture, the notes or the Note Guarantees:

(1) to cure any ambiguity, defect or inconsistency;

(2) to provide for uncertificated notes in addition to or in place of certificated notes;

(3) to provide for the assumption of an Issuer's or a Guarantor's obligations to holders of notes and Note Guarantees in the case of a merger or consolidation or sale of all or substantially all of such Issuer's or Guarantor's properties or assets, as applicable;

(4) to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the indenture of any holder;

(5) to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;

(6) to conform the text of the indenture or the notes to any provision of this Description of Notes to the extent that such provision in this Description of Notes was intended to be a verbatim recitation of a provision of the indenture, the notes or the Note Guarantees;

(7) to provide for the issuance of additional notes in accordance with the limitations set forth in the indenture as of the Issue Date;

(8) to secure the notes or the Note Guarantees;

(9) to add any additional Guarantor or to evidence the release of any Guarantor from its Note Guarantee, in each case as provided in the indenture; or

(10) to evidence or provide for the acceptance of appointment under the indenture of a successor trustee.

The consent of the holders is not necessary under the indenture to approve the particular form of any proposed amendment, supplement or waiver. It is sufficient if such consent approves the substance of the proposed amendment, supplement or waiver. After an amendment, supplement or waiver under the indenture requiring the approval of the holders becomes effective, NGL Energy will send to the holders a notice briefly describing the amendment, supplement or waiver. However, the failure to give such notice, or any defect in the notice, will not impair or affect the validity of the amendment, supplement or waiver.

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Satisfaction and Discharge

The indenture will be satisfied and discharged and will cease to be of further effect as to all notes issued thereunder (except as to surviving rights of registration of transfer or exchange of the notes and as otherwise specified in the indenture), when:

(1) either:

(a) all notes that have been authenticated, except lost, stolen or destroyed notes that have been replaced or paid and notes for whose payment money has been deposited in trust and thereafter repaid to the Issuers, have been delivered to the trustee for cancellation; or

(b) all notes that have not been delivered to the trustee for cancellation have become due and payable by reason of the sending of a notice of redemption or otherwise or will become due and payable within one year and either an Issuer or any Guarantor has irrevocably deposited or caused to be deposited with the trustee as trust funds in trust solely for the benefit of the holders, cash in U.S. dollars, non-callable Government Securities, or a combination thereof, in amounts as will be sufficient, without consideration of any reinvestment of interest, to pay and discharge the entire Indebtedness on the notes not delivered to the trustee for cancellation for principal of, or interest and premium, if any, on the notes to the date of maturity or redemption;

(2) in respect of clause 1(b), no Default or Event of Default has occurred and is continuing on the date of the deposit (other than a Default or Event of Default resulting from the borrowing of funds to be applied to such deposit and any similar deposit relating to other Indebtedness and, in each case, the granting of Liens to secure such borrowings) and the deposit will not result in a breach or violation of, or constitute a default under, any other material instrument to which either Issuer or any Guarantor is a party or by which either Issuer or any Guarantor is bound (other than with respect to the borrowing of funds to be applied concurrently to make the deposit required to effect such satisfaction and discharge and any similar concurrent deposit relating to other Indebtedness, and in each case the granting of Liens to secure such borrowings);

(3) the Issuers or any Guarantor have paid or caused to be paid all sums payable by them under the indenture; and

(4) the Issuers have delivered irrevocable instructions to the trustee under the indenture to apply the deposited money toward the payment of the notes at maturity or on the redemption date, as the case may be.

In addition, the Issuers must deliver (a) an Officers' Certificate, stating that all conditions precedent set forth in clauses (1) through (4) above have been satisfied and (b) an opinion of counsel, stating that the condition precedent set forth in clause (4) above has been satisfied.

Concerning the Trustee

U.S. Bank National Association will be the trustee under the indenture.

If the trustee becomes a creditor of either Issuer or any Guarantor, the indenture limits the right of the trustee to obtain payment of claims in certain cases, or to realize on certain property received in respect of any such claim as security or otherwise. The trustee will be permitted to engage in other transactions; however, if it acquires any conflicting interest it must eliminate such conflict within 90 days, apply to the SEC for permission to continue as trustee (if the indenture has been qualified under the Trust Indenture Act) or resign.

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The holders of a majority in aggregate principal amount of the then outstanding notes will have the right to direct the time, method and place of conducting any proceeding for exercising any remedy available to the trustee, subject to certain exceptions. The indenture provides that in case an Event of Default has occurred and is continuing, the trustee will be required, in the exercise of its power, to use the degree of care of a prudent man in the conduct of his own affairs. Subject to such provisions, the trustee will be under no obligation to exercise any of its rights or powers under the indenture at the request of any holder of notes, unless such holder has offered to the trustee reasonable indemnity or security satisfactory to it against any loss, liability or expense.

Governing Law

The indenture, the notes and the Note Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

Book-Entry, Delivery and Form

The new notes will be issued initially only in the form of one or more global notes (collectively, the "Global Notes"). The Global Notes will be deposited upon issuance with the trustee as custodian for The Depository Trust Company ("DTC"), in New York, New York, and registered in the name of DTC's nominee, Cede & Co., in each case for credit to an account of a direct or indirect participant in DTC as described below. Beneficial interests in the Global Notes may be held through the Euroclear System ("Euroclear") and Clearstream Banking, S.A. ("Clearstream") (as indirect participants in DTC).

The Global Notes may be transferred, in whole but not in part, only to another nominee of DTC or to a successor of DTC or its nominee. Beneficial interests in the Global Notes may not be exchanged for notes in registered, certificated form ("Certificated Notes") except in the limited circumstances described below. See "—Exchange of Global Notes for Certificated Notes."

In addition, transfers of beneficial interests in the Global Notes will be subject to the applicable rules and procedures of DTC and its direct or indirect participants (including, if applicable, those of Euroclear and Clearstream), which may change from time to time.

Depository Procedures

The following description of the operations and procedures of DTC, Euroclear and Clearstream are provided solely as a matter of convenience. These operations and procedures are solely within the control of the respective settlement systems and are subject to changes by them. The Issuers take no responsibility for these operations and procedures and urge investors to contact the system or their participants directly to discuss these matters.

DTC has advised the Issuers that DTC is a limited-purpose trust company created to hold securities for its participating organizations (collectively, the "Participants") and to facilitate the clearance and settlement of transactions in those securities between the Participants through electronic book-entry changes in accounts of its Participants. The Participants include securities brokers and dealers (including the initial purchasers), banks, trust companies, clearing corporations and certain other organizations. Access to DTC's system is also available to other entities such as banks, brokers, dealers and trust companies that clear through or maintain a custodial relationship with a Participant, either directly or indirectly (collectively, the "Indirect Participants"). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

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DTC has also advised the Issuers that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of the Participants designated by the initial purchasers with portions of the principal amount of the Global Notes; and

(2) ownership of these interests in the Global Notes will be shown on, and the transfer of ownership of these interests will be effected only through, records maintained by DTC (with respect to the Participants) or by the Participants and the Indirect Participants (with respect to other owners of beneficial interests in the Global Notes).

Except as described below, beneficial owners of interests in the Global Notes will not have notes registered in their names, will not receive physical delivery of Certificated Notes and will not be considered the registered owners or "holders" thereof under the indenture for any purpose.

Payments in respect of the principal of, and interest and premium, if any, on a Global Note registered in the name of DTC or its nominee will be payable to DTC in its capacity as the registered holder under the indenture. Under the terms of the indenture, the Issuers, the Guarantors and the trustee will treat the Persons in whose names the notes, including the Global Notes, are registered as the owners of the notes for the purpose of receiving payments and for all other purposes. Consequently, neither the Issuers, the Guarantors, the trustee nor any agent of the Issuers, the Guarantors or the trustee has or will have any responsibility or liability for:

(1) any aspect of DTC's records or any Participant's or Indirect Participant's records relating to or payments made on account of beneficial ownership interests in the Global Notes or for maintaining, supervising or reviewing any of DTC's records or any Participant's or Indirect Participant's records relating to the beneficial ownership interests in the Global Notes; or

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

DTC has advised the Issuers that its current practice, upon receipt of any payment in respect of securities such as the notes (including principal and interest), is to credit the accounts of the relevant Participants with the payment on the payment date unless DTC has reason to believe that it will not receive payment on such payment date. Each relevant Participant is credited with an amount proportionate to its beneficial ownership of an interest in the principal amount of the relevant security as shown on the records of DTC. Payments by the Participants and the Indirect Participants to the beneficial owners of notes will be governed by standing instructions and customary practices and will be the responsibility of the Participants or the Indirect Participants and will not be the responsibility of DTC, the trustee, the Issuers or the Guarantors. None of the Issuers, the Guarantors nor the trustee will be liable for any delay by DTC or any of the Participants or the Indirect Participants in identifying the beneficial owners of the notes, and the Issuers, the Guarantors and the trustee may conclusively rely on and will be protected in relying on instructions from DTC or its nominee for all purposes.

Subject to the transfer restrictions set forth under "Notice to Investors," transfers between the Participants will be effected in accordance with DTC's procedures, and will be settled in same-day funds, and transfers between participants in Euroclear and Clearstream will be effected in accordance with their respective rules and operating procedures.

Subject to compliance with the transfer restrictions applicable to the notes described herein, cross-market transfers between the Participants, on the one hand, and Euroclear or Clearstream participants, on the other hand, will be effected through DTC in accordance with DTC's rules on behalf of Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the

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established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to

its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositaries for Euroclear or Clearstream.

DTC has advised the Issuers that it will take any action permitted to be taken by a holder of notes only at the direction of one or more Participants to whose account DTC has credited the interests in the Global Notes and only in respect of such portion of the aggregate principal amount of the notes as to which such Participant or Participants has or have given such direction. However, if there is an Event of Default under the notes, DTC reserves the right to exchange the Global Notes for Certificated Notes, and to distribute such notes to its Participants.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes if:

(1) DTC (a) notifies the Issuers that it is unwilling or unable to continue as depositary for the Global Note or (b) has ceased to be a clearing agency registered under the Exchange Act, and in either case the Issuers fail to appoint a successor depositary;

(2) the Issuers, at their option, notify the trustee in writing that they elect to cause the issuance of Certificated Notes; or

(3) there has occurred and is continuing an Event of Default with respect to the notes and DTC notifies the trustee of its decision to exchange the Global Notes for Certificated Notes.

In addition, beneficial interests in a Global Note may be exchanged for Certificated Notes upon prior written notice given to the trustee by or on behalf of DTC in accordance with the indenture. In all cases, Certificated Notes delivered in exchange for any Global Note or beneficial interests in Global Notes will be registered in the names, and issued in any approved denominations, requested by or on behalf of the depositary (in accordance with its customary procedures) and will bear the applicable restrictive legend referred to in "Notice to Investors," unless that legend is not required by applicable law.

Exchange of Certificated Notes for Global Notes

Certificated Notes may not be exchanged for beneficial interests in any Global Note unless the transferor first delivers to the trustee a written certificate (in the form provided in the indenture) to the effect that such transfer will comply with the appropriate transfer restrictions applicable to such notes. See "Notice to Investors."

Same Day Settlement and Payment

The Issuers will make payments in respect of the notes represented by the Global Notes (including principal, premium, if any, and interest) by wire transfer of immediately available funds to the accounts specified by DTC or its nominee. The Issuers will make all payments of principal, interest and premium, if any, with respect to Certificated Notes in the manner described above under "—Methods of Receiving Payments on the Notes." The notes represented by the Global Notes are expected to trade in DTC's Same-Day Funds Settlement System, and any permitted secondary market trading activity in such notes will, therefore, be required by DTC to be settled in immediately available funds.

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The Issuers expect that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Because of time zone differences, the securities account of a Euroclear or Clearstream participant purchasing an interest in a Global Note from a Participant will be credited, and any such crediting will be reported to the relevant Euroclear or Clearstream participant, during the securities settlement processing day (which must be a business day for Euroclear and Clearstream) immediately following the settlement date of DTC. DTC has advised the Issuers that cash received in Euroclear or Clearstream as a result of sales of interests in a Global Note by or through a Euroclear or Clearstream participant to a Participant will be received with value on the settlement date of DTC but will be available in the relevant Euroclear or Clearstream cash account only as of the business day for Euroclear or Clearstream following DTC's settlement date.

Definitions

"Acquired Debt" means, with respect to any specified Person:

(1) Indebtedness of any other Person existing at the time such other Person is merged with or into or became a Subsidiary of such specified Person, regardless of whether such Indebtedness is incurred in connection with, or in contemplation of, such other Person merging with or into, or becoming a Restricted Subsidiary of, such specified Person, but excluding Indebtedness which is extinguished, retired or repaid in connection with such Person merging with or into or becoming a Subsidiary of such specified Person; and

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

"Additional Assets" means:

(1) any property or assets (other than Indebtedness and Capital Stock) to be used by NGL Energy or a Restricted Subsidiary in a Permitted Business;

(2) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by NGL Energy or another Restricted Subsidiary; or

(3) outstanding Capital Stock of any Restricted Subsidiary held by Persons other than Affiliates;provided that all the Capital Stock of such Restricted Subsidiary held by NGL Energy or any other Restricted Subsidiaries shall entitle NGL Energy or such other Restricted Subsidiary to not less than a pro rata portion of all dividends or other distributions made by such Restricted Subsidiary upon any of such Capital Stock;

provided, however, that, in the case of clauses (2) and (3), such Restricted Subsidiary is primarily engaged in a Permitted Business.

"Affiliate" of any specified Person means any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, "control," as used with respect to any Person, means the possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of such Person, whether through the ownership of voting securities, by agreement or otherwise. For purposes of this definition, the terms "controlling," "controlled by" and "under common control with" have correlative meanings.

"Asset Sale" means:

(1) the sale, lease, conveyance or other disposition of any assets or rights by NGL Energy or any of NGL Energy's Restricted Subsidiaries; provided that the sale, lease, conveyance or other disposition of all or substantially all of the assets of NGL Energy and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the

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caption "—Repurchase at the Option of Holders—Change of Control" and/or the provisions of the indenture described above under the caption "—Covenants—Merger, Consolidation or Sale of Assets" and not by the provisions of the Asset Sale covenant; and

(2) the issuance of Equity Interests by any of NGL Energy's Restricted Subsidiaries or the sale by NGL Energy or any of NGL Energy's Restricted Subsidiaries of Equity Interests in any of NGL Energy's Restricted Subsidiaries (other than, in each case, directors' qualifying shares or Equity Interests required by applicable law to be held by a Person other than NGL Energy or any of NGL Energy's Restricted Subsidiaries).

Notwithstanding the preceding, none of the following items will be deemed to be an Asset Sale:

(1) any single transaction or series of related transactions that involves assets having a Fair Market Value of less than $20.0 million;

(2) a transfer of assets between or among NGL Energy and its Restricted Subsidiaries;

(3) an issuance or sale of Equity Interests by a Restricted Subsidiary to NGL Energy or to a Restricted Subsidiary;

(4) the sale, lease or other disposition of equipment, inventory, products, services, accounts receivable or other assets in the ordinary course of business (including in connection with any compromise, settlement or collection of accounts receivable), and any sale or other disposition of damaged, worn-out or obsolete assets or assets that are no longer useful in the conduct of the business of NGL Energy and its Restricted Subsidiaries (including the abandonment or other disposition of intellectual property that is, in the reasonable judgment of NGL Energy, no longer economically practicable to maintain or useful in the conduct of the business of NGL Energy and its Restricted Subsidiaries taken as whole);

(5) licenses and sublicenses by NGL Energy or any of its Restricted Subsidiaries of software or intellectual property in the ordinary course of business;

(6) any surrender or waiver of contract rights or settlement, release, recovery on or surrender of contract, tort or other claims of any kind;

(7) the creation or perfection of a Lien not prohibited by the covenant described above under the caption "—Covenants—Liens," including a Permitted Lien and the exercise by any Person in whose favor a Permitted Lien is granted of any of its rights in respect of that Permitted Lien;

(8) the sale or other disposition of cash or Cash Equivalents;

(9) the sale or other disposition of Hedging Obligations or other financial instruments in the ordinary course of business;

(10) (a) a Restricted Payment that does not violate the covenant described above under the caption "—Covenants—Restricted Payments," including, without limitation, the issuance or sale of Equity Interests or the sale, lease or other disposition of products, services, equipment, inventory, accounts receivable or other assets pursuant to any such Restricted Payment, or (b) the consummation of a Permitted Investment, including, without limitation, unwinding any Hedging Obligations, and including the issuance or sale of Equity Interests or the sale, lease or other disposition of products, services, equipment, inventory, accounts receivable or other assets pursuant to any such Permitted Investment;

(11) the issuance, sale or other disposition of Equity Interests of an Unrestricted Subsidiary; and

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(12) any trade or exchange by NGL Energy or any of its Restricted Subsidiaries of assets for properties or assets owned or held by another Person used or useful in a Permitted Business (including Capital Stock of a Person engaged primarily in a Permitted Business that is or becomes a Restricted Subsidiary);provided that (a) the assets or properties exchanged or received by NGL Energy or any of its Restricted Subsidiaries may not include cash or Cash Equivalents except for relatively minors amounts necessary in order to achieve an exchange of equivalent value and (b) the Fair Market Value of the assets traded or exchanged by NGL Energy or such Restricted Subsidiary (together with any cash or Cash Equivalents to be delivered by NGL Energy or such Restricted Subsidiary) is reasonably equivalent to the Fair Market Value of the assets (together with any cash or Cash Equivalents) to be received by NGL Energy or such Restricted Subsidiary; andprovided, further, that any cash received must be applied in accordance with the provisions of the Asset Sale covenant.

"Available Cash" has the meaning assigned to such term in the Partnership Agreement, as in effect on the Issue Date.

"Beneficial Owner" has the meaning assigned to such term in Rule 13d-3 and Rule 13d-5 under the Exchange Act, except that in calculating the beneficial ownership of any particular "person" (as that term is used in Section 13(d)(3) of the Exchange Act), such "person" will be deemed to have beneficial ownership of all securities that such "person" has the right to acquire by conversion or exercise of other securities, whether such right is currently exercisable or is exercisable only after the passage of time. The terms "Beneficially Owns" and "Beneficially Owned" have corresponding meanings. For purposes of this definition, a Person shall be deemed not to Beneficially Own securities that are the subject of a stock purchase agreement, merger agreement, amalgamation agreement, arrangement agreement or similar agreement until consummation of the transactions or, as applicable, series of related transactions contemplated thereby.

"Board of Directors" means:

(1) with respect to a corporation, the board of directors of the corporation or any committee thereof duly authorized to act on behalf of such board;

(2) with respect to a partnership, the board of directors of the general partner of the partnership;

(3) with respect to a limited liability company, the managing member or members or any controlling committee of managing members thereof; and

(4) with respect to any other Person, the board or committee of such Person serving a similar function.

So long as NGL Energy is organized as a limited partnership, references to its Board of Directors are to the Board of Directors of the General Partner.

"Business Day" means each day that is not a Saturday, Sunday or other day on which banking institutions in New York, New York or another place of payment are authorized or required by law to remain closed.

"Capital Lease Obligation" means, at the time any determination is to be made, the amount of the liability in respect of a capital lease that would at that time be required to be capitalized on a balance sheet prepared in accordance with GAAP, and the Stated Maturity thereof shall be the date of the last payment of rent or any other amount due under such lease prior to the first date upon which such lease may be prepaid by the lessee without payment of a penalty. Notwithstanding the foregoing, any lease (whether entered into before or after the Issue Date) that would have been classified as an operating lease pursuant to GAAP as in effect on the Issue Date will be deemed not to represent a Capital Lease Obligation, notwithstanding any change in GAAP that occurs after the Issue Date.

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"Capital Stock" means:

(1) in the case of a corporation, corporate stock;

(2) in the case of an association or business entity, any and all shares, interests, participations, rights or other equivalents (however designated) of corporate stock;

(3) in the case of a partnership or limited liability company, partnership interests (whether general or limited) or membership interests; and

(4) any other interest or participation that confers on a Person the right to receive a share of the profits and losses of, or distributions of assets of, the issuing Person, but excluding from all of the foregoing any debt securities convertible into Capital Stock, regardless of whether such debt securities include any right of participation with Capital Stock.

"Cash Equivalents" means:

(1) United States dollars;

(2) Government Securities having maturities of not more than one year from the date of acquisition;

(3) certificates of deposit, demand deposit accounts and eurodollar time deposits with maturities of one year or less from the date of acquisition, bankers' acceptances with maturities not exceeding one year and overnight bank deposits, in each case, with any lender party to the Credit Agreement or with any domestic commercial bank having capital and surplus in excess of $250.0 million and a Thomson Bank Watch Rating of "B" or better;

(4) marketable general obligations issued by any state of the United States of America or any political subdivision of any such state or any public instrumentality thereof maturing within one year from the date of acquisition thereof and, at the time of acquisition thereof, having a credit rating of "A" or better from either S&P or Moody's;

(5) repurchase obligations with a term of not more than seven days for underlying securities of the types described in clauses (2), (3) or (4) above entered into with any financial institution meeting the qualifications specified in clause (3) above;

(6) commercial paper having one of the two highest ratings obtainable from Moody's or S&P and, in each case, maturing within one year after the date of acquisition;

(7) money market funds at least 95% of the assets of which constitute Cash Equivalents of the kinds described in clauses (1) through (6) of this definition; and

(8) deposits in any currency available for withdrawal on demand with any commercial bank that is organized under the laws of any country in which NGL Energy or any Restricted Subsidiary maintains its chief executive office or is engaged in a Permitted Business;provided that all such deposits are made in such accounts in the ordinary course of business.

"Change of Control" means the occurrence of any of the following:

(1) the sale, lease, transfer, conveyance or other disposition (other than by way of merger or consolidation), in one or a series of related transactions, of all or substantially all of the assets of NGL Energy and its Restricted Subsidiaries taken as a whole to any "person" (as such term is used in Sections 13(d) of the Exchange Act), other than a Permitted Holder;

(2) the adoption of a plan for the liquidation or dissolution of NGL Energy;

(3) the consummation of any transaction (including, without limitation, any merger or consolidation) the result of which is that any "person" or "group" (as those terms are used in

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Section 13(d)(3) or Section 14(d)(2) of the Exchange Act, or any successor provision), other than a Permitted Holder, becomes the Beneficial Owner, directly or indirectly, of more than 50% of the Voting Stock of the General Partner, measured by voting power rather than number of shares, units or the like; or

(4) the removal of the General Partner by the limited partners of NGL Energy in accordance with the terms of the Partnership Agreement.

Notwithstanding the preceding, a conversion of NGL Energy or any of its Restricted Subsidiaries from a limited partnership, corporation, limited liability company or other form of entity to a limited liability company, corporation, limited partnership or other form of entity or an exchange of all of the outstanding Equity Interests in one form of entity for Equity Interests in another form of entity shall not constitute a Change of Control, so long as following such conversion or exchange the "persons" (as that term is used in Section 13(d)(3) of the Exchange Act) who Beneficially Owned the Capital Stock of NGL Energy immediately prior to such transactions continue to Beneficially Own in the aggregate more than 50% of the Voting Stock of such entity, or continue to Beneficially Own sufficient Equity Interests in such entity or its general partner, as applicable, to elect a majority of its directors, managers, trustees or other persons serving in a similar capacity for such entity or its general partner, as applicable, and, in either case, no "person," other than a Permitted Holder, Beneficially Owns more than 50% of the Voting Stock of such entity or its general partner, as applicable.

"Consolidated Cash Flow" means, with respect to any specified Person for any period, the Consolidated Net Income of such Person for such period plus, without duplication:

(1) an amount equal to any extraordinary loss plus any net loss realized by such Person or any of its Restricted Subsidiaries in connection with an Asset Sale (together with any related provision for taxes and any related non-recurring charges relating to any premium or penalty paid, write-off of deferred financing costs or other financial recapitalization charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity), to the extent that such losses were deducted in computing such Consolidated Net Income;plus

(2) provision for taxes based on income or profits (including state franchise taxes accounted for as income taxes in accordance with GAAP) of such Person and its Restricted Subsidiaries for such period, to the extent that such provision for taxes was deducted in computing such Consolidated Net Income;plus

(3) the Fixed Charges of such Person and its Restricted Subsidiaries for such period, to the extent that such Fixed Charges were deducted in computing such Consolidated Net Income;plus

(4) depreciation, depletion, amortization, (including amortization of intangibles but excluding amortization of prepaid cash expenses that were paid in a prior period), abandonment, impairment and other non-cash charges and expenses (excluding any such non-cash charge or expense to the extent that it represents an accrual of or reserve for cash charges or expenses in any future period or amortization of a prepaid cash charge or expense that was paid in a prior period) of such Person and its Restricted Subsidiaries for such period to the extent that such depreciation, depletion, amortization, impairment and other non-cash charges or expenses were deducted in computing such Consolidated Net Income;plus

(5) all extraordinary, unusual or non-recurring expenses, including expenses related to the Fair Market Value of contingent consideration, to the extent that such extraordinary, unusual or non-recurring expenses were deducted in computing such Consolidated Net Income;minus

(6) non-cash items increasing such Consolidated Net Income for such period, other than the accrual of revenue in the ordinary course of business, in each case, on a consolidated basis and determined in accordance with GAAP.

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"Consolidated Net Income" means, with respect to any specified Person for any period, the aggregate of the net income (loss) of such Person and its Restricted Subsidiaries for such period, on a consolidated basis, determined in accordance with GAAP and without any reduction in respect of preferred stock dividends;provided that:

(1) any gain (loss) realized upon the sale or other disposition of any property, plant or equipment of such Person or its consolidated Restricted Subsidiaries (including pursuant to any sale or leaseback transaction) which is not sold or otherwise disposed of in the ordinary course of business and any gain (loss) realized upon the sale or other disposition of any Capital Stock of any Person will be excluded;

(2) the net income (but not loss) of any Person that is not a Restricted Subsidiary of such specified Person or that is accounted for by the equity method of accounting will be included only to the extent of the amount of dividends or similar distributions paid in cash to the specified Person or a Restricted Subsidiary of such specified Person;

(3) the net income (but not loss) of any Restricted Subsidiary of such specified Person that is not a Guarantor will be excluded to the extent that the declaration or payment of dividends or similar distributions by that Restricted Subsidiary of that net income is not at the date of determination permitted without any prior governmental approval (that has not been obtained) or, directly or indirectly, by operation of the terms of its charter or any instrument, judgment, decree, order, statute, rule or governmental regulation applicable to that Restricted Subsidiary or its stockholders, partners or members;provided, however, that the operation of this clause (3) shall be suspended with respect to any Restricted Subsidiary that is acquired by NGL Energy or any of its Restricted Subsidiaries (regardless of whether such acquisition is effected pursuant to a merger or otherwise), but such suspension shall cease immediately after the first six months following such acquisition;

(4) the cumulative effect of a change in accounting principles will be excluded;

(5) any unrealized losses and gains for such period under derivative instruments included in the determination of Consolidated Net Income, including, without limitation, those resulting from the application of FASB ASC 815, will be excluded;

(6) all non-cash equity-based compensation expense, including all non-cash charges related to restricted Equity Interests and redeemable Equity Interests granted to officers, directors and employees, will be excluded;

(7) any charges associated with any write-down, amortization or impairment of goodwill or other tangible or intangible assets will be excluded; and

(8) any non-cash or other charges relating to any premium or penalty paid, write off of deferred financing costs or other financial recapitalization charges in connection with redeeming or retiring any Indebtedness prior to its Stated Maturity (including, without limitation, premiums or penalties paid to counterparties in connection with the breakage, termination or unwinding of Hedging Obligations) will be excluded.

"continuing" means, with respect to any Default or Event of Default, that such Default or Event of Default has not been cured or waived.

"Credit Agreement" means that certain Credit Agreement, dated as of June 19, 2012, by and among NGL Energy, the subsidiary borrowers party thereto, NGL Energy Operating LLC, as borrowers' agent, the lenders party thereto, Deutsche Bank AG, New York Branch, as technical agent, and Deutsche Bank Trust Company Americas, as administrative agent and as collateral agent, as amended by the Facility Increase Agreement, dated November 1, 2012, Amendment No. 1 to Credit Agreement, dated as of January 15, 2013 and Amendment No. 2 to Credit Agreement, dated as of May 8, 2013, including

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any related notes, Guarantees, collateral documents, instruments and agreements executed in connection therewith, and, in each case, as amended, restated, modified, renewed, refunded, replaced in any manner (whether upon or after termination or otherwise) or refinanced (including by means of sales of debt securities to institutional investors) in whole or in part from time to time.

"Credit Facilities" means one or more debt facilities (including, without limitation, any Credit Agreement), commercial paper facilities or secured or unsecured capital markets financings, in each case, with banks or other institutional lenders or institutional investors providing for revolving credit loans, term loans, capital market financings, private placements, receivables financing (including through the sale of receivables to such lenders or to special purpose entities formed to borrow from such lenders against such receivables) or letters of credit, in each case, as amended, restated, modified, renewed, refunded, replaced in any manner (whether upon or after termination or otherwise) or refinanced (including refinancing with any capital markets transaction or otherwise by means of sales of debt securities to institutional investors) in whole or in part from time to time.

"Customary Recourse Exceptions" means, with respect to any Non-Recourse Debt of an Unrestricted Subsidiary or Joint Venture, (i) Liens on and pledges of the Equity Interests of any Unrestricted Subsidiary or any Joint Venture owned by NGL Energy or any Restricted Subsidiary to the extent securing otherwise Non-Recourse Debt of such Unrestricted Subsidiary or Joint Venture and (ii) exclusions from the exculpation provisions with respect to such Non-Recourse Debt for the voluntary bankruptcy of such Unrestricted Subsidiary or Joint Venture, fraud, misapplication of cash, environmental claims, waste, willful destruction and other circumstances customarily excluded by lenders from exculpation provisions or included in separate indemnification agreements in non-recourse financings.

"Default" means any event that is, or with the passage of time or the giving of notice or both would be, an Event of Default.

"Disqualified Stock" means any Capital Stock that, by its terms (or by the terms of any security into which it is convertible, or for which it is exchangeable, in each case at the option of the holder of the Capital Stock), or upon the happening of any event, matures or is mandatorily redeemable, pursuant to a sinking fund obligation or otherwise, or redeemable at the option of the holder of the Capital Stock, in whole or in part, on or prior to the date that is 91 days after the date on which the notes mature. Notwithstanding the preceding sentence, any Capital Stock that would constitute Disqualified Stock solely because the holders of the Capital Stock have the right to require NGL Energy to repurchase or redeem such Capital Stock upon the occurrence of a change of control or an asset sale will not constitute Disqualified Stock if the terms of such Capital Stock provide that NGL Energy may not repurchase or redeem any such Capital Stock pursuant to such provisions unless such repurchase or redemption complies with the covenant described above under the caption "—Covenants—Restricted Payments." The amount of Disqualified Stock deemed to be outstanding at any time for purposes of the indenture will be the maximum amount that NGL Energy and its Restricted Subsidiaries may become obligated to pay upon the maturity of, or pursuant to any mandatory redemption provisions of, such Disqualified Stock, exclusive of accrued dividends.

"Domestic Subsidiary" means any Restricted Subsidiary that was formed under the laws of the United States or any state of the United States or the District of Columbia or that guarantees or otherwise provides direct credit support for any Indebtedness of NGL Energy or any Restricted Subsidiary (other than a Foreign Subsidiary).

"Equity Interests" of any Person means Capital Stock and all warrants, options or other rights to acquire Capital Stock of such Person (but excluding any debt security that is convertible into, or exchangeable for, Capital Stock).

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"Equity Offering" means a sale of Equity Interests of NGL Energy (other than Disqualified Stock and other than to a Subsidiary of NGL Energy) made for cash on a primary basis by NGL Energy after the Issue Date.

"Exchange Notes" means an issue of notes with terms identical to the notes (except that the Exchange Notes will not be subject to restrictions on transfer, registration rights or Liquidated Damages) issued in an Exchange Offer pursuant to the indenture.

"Exchange Act" means the Securities Exchange Act of 1934, as amended.

"Existing Indebtedness" means all Indebtedness of NGL Energy and its Subsidiaries (other than Indebtedness under the Credit Agreement, the notes or the Note Guarantees) in existence on the Issue Date, until such amounts are repaid.

"Existing Senior Secured Notes" means NGL Energy's $250,000,000 aggregate principal amount of 6.65% Senior Secured Notes due June 19, 2022.

"Fair Market Value" means the value that would be paid by a willing buyer to an unaffiliated willing seller in a transaction not involving distress or necessity of either party, determined in good faith by the Board of Directors of NGL Energy in the case of amounts of $40.0 million or more and otherwise by an officer of the General Partner (unless otherwise provided in the indenture).

"FASB ASC 815" means Financial Accounting Standards Board Accounting Standards Codification 815.

"FERC Subsidiary" means a Restricted Subsidiary that is subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (or any successor thereof).

"Fitch" means Fitch Ratings, Inc. or any successor to the ratings business thereof.

"Fixed Charge Coverage Ratio" means with respect to any specified Person for any four-quarter reference period, the ratio of the Consolidated Cash Flow of such Person for such period to the Fixed Charges of such Person for such period. In the event that the specified Person or any of its Restricted Subsidiaries incurs, assumes, Guarantees, repays, repurchases, redeems, defeases or otherwise discharges any Indebtedness (other than ordinary working capital borrowings) or issues, repurchases or redeems preferred stock subsequent to the commencement of the period for which the Fixed Charge Coverage Ratio is being calculated and on or prior to the date on which the event for which the calculation of the Fixed Charge Coverage Ratio is made (the "Calculation Date"), then the Fixed Charge Coverage Ratio will be calculated givingpro forma effect to such incurrence, assumption, Guarantee, repayment, repurchase, redemption, defeasance or other discharge of Indebtedness, or such issuance, repurchase or redemption of preferred stock, and the use of the proceeds therefrom, as if the same had occurred at the beginning of the applicable four-quarter reference period. If any Indebtedness bears a floating rate of interest and is being givenpro forma effect, the interest expense on such Indebtedness will be calculated as if the average rate in effect from the beginning of such period to the Calculation Date had been the applicable rate for the entire period (taking into account any interest Hedging Obligation applicable to such Indebtedness, but if the remaining term of such interest Hedging Obligation is less than twelve months, then such interest Hedging Obligation shall only be taken into account for that portion of the period equal to the remaining term thereof). If any Indebtedness that is being givenpro forma effect bears an interest rate at the option of such Person, the interest rate shall be calculated by applying such option rate chosen by such Person. Interest on Indebtedness that may optionally be determined at an interest rate based upon a factor of a prime or similar rate, a Eurocurrency interbank offered rate, or other rate, shall be deemed to have been based upon the rate actually chosen, or if none, then based upon such optional rate chosen as such Person may designate.

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In addition, for purposes of calculating the Fixed Charge Coverage Ratio:

(1) acquisitions that have been made by the specified Person or any of its Restricted Subsidiaries, including through mergers, consolidations or otherwise (including acquisitions of assets used or useful in a Permitted Business), or any Person or any of its Restricted Subsidiaries acquired by the specified Person or any of its Restricted Subsidiaries, and including all related financing transactions and including increases in ownership of Restricted Subsidiaries, during the four-quarter reference period or subsequent to such reference period and on or prior to the Calculation Date, will be givenpro forma effect as if they had occurred on the first day of the four-quarter reference period;

(2) the Consolidated Cash Flow attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded;

(3) the Fixed Charges attributable to discontinued operations, as determined in accordance with GAAP, and operations or businesses (and ownership interests therein) disposed of prior to the Calculation Date, will be excluded, but only to the extent that the obligations giving rise to such Fixed Charges will not be obligations of the specified Person or any of its Restricted Subsidiaries following the Calculation Date;

(4) any Person that is a Restricted Subsidiary of the specified Person on the Calculation Date will be deemed to have been a Restricted Subsidiary at all times during such four-quarter period;

(5) any Person that is not a Restricted Subsidiary of the specified Person on the Calculation Date will be deemed not to have been a Restricted Subsidiary at any time during such four-quarter period; and

(6) interest income reasonably anticipated by such Person to be received during the applicable four-quarter period from cash or Cash Equivalents held by such Person or any Restricted Subsidiary of such Person, which cash or Cash Equivalents exist on the Calculation Date or will exist as a result of the transaction giving rise to the need to calculate the Fixed Charge Coverage Ratio, will be included.

For purposes of this definition, wheneverpro forma effect is to be given to any calculation under this definition, thepro forma calculations will be determined in good faith by a responsible financial or accounting officer of such Person, which determination shall be conclusive for all purposes under the indenture;provided that such officer may in such officer's discretion include any reasonably identifiable and factually supportablepro forma changes to Consolidated Cash Flow or Fixed Charges, including anypro forma expense and cost reductions or synergies that have occurred or are reasonably expected to occur within the 12 months immediately following the Calculation Date and are either (i) prepared and calculated in accordance with Regulation S-X under the Securities Act or (ii) set forth in an Officers' Certificate signed by the chief financial officer of such Person that states (a) the amount of each such adjustment and (b) that such adjustments are based on the reasonable good faith belief of the chief financial officer executing such Officers' Certificate at the time of such execution and the factual basis on which such good faith belief is based.

"Fixed Charges" means, with respect to any specified Person for any period, the sum, without duplication, of:

(1) the consolidated interest expense (less interest income) of such Person and its Restricted Subsidiaries for such period, whether paid or accrued (excluding write-off of deferred financing costs and accretion of interest charges on future retirement benefits and other obligations that do not constitute Indebtedness, but including, without limitation, amortization of debt issuance costs and original issue discount, non-cash interest payments, the interest component of any deferred

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payment obligations, the interest component of all payments associated with Capital Lease Obligations, commissions, discounts and other fees and charges incurred in respect of letter of credit or bankers' acceptance financings), and net of the effect of all payments made or received pursuant to Hedging Obligations in respect of interest rates;plus

(2) the consolidated interest expense of such Person and its Restricted Subsidiaries that was capitalized during such period;plus

(3) any interest on Indebtedness of another Person that is guaranteed by the specified Person or one or more of its Restricted Subsidiaries or secured by a Lien on assets of such specified Person or one or more of its Restricted Subsidiaries, regardless of whether such Guarantee or Lien is called upon;plus

(4) all dividends or distributions, whether paid or accrued and regardless of whether in cash, on any series of preferred stock of such Person or any of its Restricted Subsidiaries, other than dividends or distributions on Equity Interests payable solely in Equity Interests of such Person (other than Disqualified Stock) or to such Person or a Restricted Subsidiary of such Person, in each case, determined on a consolidated basis in accordance with GAAP.

"Foreign Subsidiary" means any Restricted Subsidiary that is not a Domestic Subsidiary.

"GAAP" means generally accepted accounting principles in the United States, that are in effect from time to time. All ratios and computations based on GAAP contained in the indenture will be computed in conformity with GAAP. At any time after the Issue Date, NGL Energy may elect to apply International Financial Reporting Standards ("IFRS") accounting principles in lieu of GAAP and, upon any such election, references herein to GAAP shall thereafter be construed to mean IFRS (except as otherwise provided in the indenture);provided that any such election, once made, shall be irrevocable;provided, further, that any calculation or determination in the indenture that requires the application of GAAP for periods that include fiscal quarters ended prior to NGL Energy's election to apply IFRS shall remain as previously calculated or determined in accordance with GAAP. NGL Energy shall give notice of any such election made in accordance with this definition to the trustee and the holders of notes.

"General Partner" means NGL Energy Holdings LLC, a Delaware limited liability company, and its successors and permitted assigns as the general partner of NGL Energy.

"Government Securities" means direct obligations of, or obligations Guaranteed by, the United States of America, and the payment for which the United States pledges its full faith and credit.

"Guarantee" means a guarantee other than by endorsement of negotiable instruments for collection in the ordinary course of business, direct or indirect, in any manner including, without limitation, by way of a pledge of assets or through letters of credit or reimbursement agreements in respect thereof, of all or any part of any Indebtedness (whether arising by virtue of partnership arrangements, or by agreements to keep-well, to purchase assets, goods, securities or services, to take or pay or to maintain financial statement conditions or otherwise). When used as a verb, "Guarantee" has a correlative meaning.

"Guarantors" means any of: (1) the Subsidiaries of NGL Energy, other than Finance Corp., executing the indenture as initial Guarantors; and (2) the Restricted Subsidiaries of NGL Energy that become Guarantors in accordance with the provisions of the indenture, and their respective successors and assigns, in each case, until the Note Guarantee of such Person has been released in accordance with the provisions of the indenture.

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"Hedging Obligations" means, with respect to any specified Person, the obligations of such Person under:

(1) interest rate swap agreements (whether from fixed to floating or from floating to fixed), interest rate cap agreements, interest rate collar agreements or other agreements or arrangements designed to manage interest rates or interest rate risk;

(2) any commodity futures contract, commodity option or other similar agreement or arrangement designed to protect such Person against fluctuations in the price of Hydrocarbons used, produced, processed or sold; and

(3) foreign exchange contracts, currency protection agreements or other agreements or arrangements designed to protect such Person against fluctuations in currency exchange rates.

"Hydrocarbons" means oil, natural gas, casing head gas, drip gasoline, natural gasoline, condensate, distillate, liquid hydrocarbons, gaseous hydrocarbons and all constituents, elements or compounds thereof and products refined or processed therefrom.

"Indebtedness" means, with respect to any specified Person, without duplication, any indebtedness of such Person, regardless of whether contingent:

(1) in respect of borrowed money;

(2) evidenced by or issued in exchange for bonds, notes, credit agreements, debentures or similar instruments or letters of credit (or reimbursement agreements in respect thereof);

(3) in respect of bankers' acceptances;

(4) representing Capital Lease Obligations;

(5) representing the balance deferred and unpaid of the purchase price of any property or services due more than six months after such property is acquired or such services are completed; or

(6) representing any Hedging Obligations,

if and to the extent any of the preceding items (other than letters of credit and Hedging Obligations) would appear as a liability upon a balance sheet of the specified Person prepared in accordance with GAAP. In addition, the term "Indebtedness" includes (a) all Indebtedness of others secured by a Lien on any asset of the specified Person (regardless of whether such Indebtedness is assumed by the specified Person);provided, that the amount of such Indebtedness will be the lesser of (i) the Fair Market Value of such asset at such date of determination and (ii) the amount of such Indebtedness of such other Person, and (b) to the extent not otherwise included, the Guarantee by the specified Person of any Indebtedness of any other Person. Indebtedness shall be calculated without giving effect to the effects of FASB ASC 815 and related interpretations to the extent such effects would otherwise increase or decrease an amount of Indebtedness for any purpose under the indenture as a result of accounting for any embedded derivatives created by the terms of such Indebtedness.

The amount of any Indebtedness outstanding as of any date will be:

(1) the accreted value of the Indebtedness, in the case of any Indebtedness issued with original issue discount;

(2) in the case of any Hedging Obligation, the termination value of the agreement or arrangement giving rise to such Hedging Obligation that would be payable by such Person at such date;

(3) in the case of any letter of credit, the face amount thereof;

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(4) the principal amount of the Indebtedness, together with any interest thereon that is more than 30 days past due, in the case of any other Indebtedness; and

(5) in respect of Indebtedness of another Person secured by a Lien on the assets of the specified Person, the lesser of:

(a) the Fair Market Value of such assets at the date of determination; and

(b) the amount of the Indebtedness of the other Person.

Notwithstanding the foregoing, the following shall not constitute "Indebtedness:"

(i) accrued expenses and trade accounts payable arising in the ordinary course of business;

(ii) any indebtedness that has been defeased in accordance with GAAP or defeased pursuant to the deposit of cash or Government Securities (in an amount sufficient to satisfy all such indebtedness obligations at maturity or redemption, as applicable, and all payments of interest and premium, if any) in a trust or account created or pledged for the sole benefit of the holders of such indebtedness, and subject to no other Liens, and the other applicable terms of the instrument governing such indebtedness;

(iii) Hydrocarbon balancing liabilities incurred in the ordinary course of business;

(iv) any unrealized losses or charges in respect of Hedging Obligations (including those resulting from the application of the FASB ASC 815);

(v) any obligations in respect of (a) bid, performance, completion, surety, appeal and similar bonds, (b) bankers' acceptances, (c) workers' compensation claims, health or other types of social security benefits, unemployment or other insurance or self-insurance obligations, reclamation and statutory obligations and (d) any Guarantees or standby letters of credit functioning as or supporting any of the foregoing bonds or obligations, to the extent not drawn;provided, however, that such bonds or obligations mentioned in subclause (a), (b), (c) or (d) of this clause (v) are incurred in the ordinary course of the business of NGL Energy and its Restricted Subsidiaries and do not relate to obligations for borrowed money;

(vi) any obligation arising from any agreement providing for indemnities, guarantees, purchase price adjustments, holdbacks, earnouts, contingency payment obligations based on the performance of the acquired or disposed assets or similar obligations (other than Guarantees of Indebtedness) incurred by any Person in connection with the acquisition or disposition of any business, assets or Capital Stock;

(vii) any obligation arising from the honoring by a bank or other financial institution of a check, draft or similar instrument drawn against insufficient funds in the ordinary course of business;provided that such obligation is extinguished within five Business Days of its incurrence;

(viii) any Treasury Management Arrangement;

(ix) any obligation arising out of advances on trade receivables, factoring of receivables, customer prepayments and similar transactions in the ordinary course of business and consistent with past practice; and

(x) all contracts and other obligations, agreements, instruments or arrangements described in clauses (18), (28) and (29) of the definition of "Permitted Liens." "Internal Revenue Code" means the Internal Revenue Code of 1986, as amended, and any successor statute.

"Investment Grade Rating" means a rating equal to or higher than:

(1) Baa3 (or the equivalent) by Moody's;

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(2) BBB- (or the equivalent) by S&P; or

(3) BBB- (or the equivalent) by Fitch,

or, if any such Rating Agency ceases to rate the notes for reasons outside of the control of NGL Energy, the equivalent investment grade credit rating from any other Rating Agency.

"Investment Grade Rating Event" means the first day on which (a) the notes have an Investment Grade Rating from at least two Rating Agencies, (b) no Default with respect to the notes has occurred and is then continuing under the indenture and (c) NGL Energy has delivered to the trustee an Officers' Certificate certifying as to the satisfaction of the conditions set forth in clauses (a) and (b) of this definition.

"Investments" means, with respect to any Person, all direct or indirect investments by such Person in other Persons (including Affiliates) in the forms of loans (including Guarantees or other obligations), advances or capital contributions (excluding (1) endorsements of negotiable instruments and documents in the ordinary course of business, and commission, travel and similar advances to officers, employees and consultants made in the ordinary course of business and (2) advances to customers in the ordinary course of business that are recorded as accounts receivable on the balance sheet of the Person making the advance), purchases or other acquisitions for consideration of Indebtedness, Equity Interests or other securities (excluding any interest in an oil or natural gas leasehold to the extent constituting a security under applicable law), together with all items that are or would be classified as investments on a balance sheet prepared in accordance with GAAP. If NGL Energy or any Restricted Subsidiary sells or otherwise disposes of any Equity Interests of any Restricted Subsidiary such that, after giving effect to any such sale or disposition, such Person is no longer a Restricted Subsidiary of NGL Energy, NGL Energy will be deemed to have made an Investment on the date of any such sale or disposition in an amount equal to the Fair Market Value of NGL Energy's Investments in such Subsidiary that were not sold or disposed of in an amount determined as provided in the final paragraph of the covenant described above under the caption "—Covenants—Restricted Payments." The acquisition by NGL Energy or any Restricted Subsidiary of a Person that holds an Investment in a third Person will be deemed to be an Investment by NGL Energy or such Restricted Subsidiary in such third Person in an amount equal to the Fair Market Value of the Investments held by the acquired Person in such third Person in an amount determined as provided in the final paragraph of the covenant described above under the caption "—Covenants—Restricted Payments." Except as otherwise provided in the indenture, the amount of an Investment will be determined at the time the Investment is made and without giving effect to subsequent changes in value or write-ups, write-downs or write-offs with respect to such Investment.

"Issue Date" means the first date on which notes are issued under the indenture.

"Joint Venture" means any Person that is not a direct or indirect Subsidiary of NGL Energy in which NGL Energy or any of its Restricted Subsidiaries makes any Investment.

"Lien" means, with respect to any asset, any mortgage, lien, pledge, charge, security interest or encumbrance of any kind in respect of such asset, regardless of whether filed, recorded or otherwise perfected under applicable law, including any conditional sale or other title retention agreement, any lease in the nature thereof, any option or other agreement to sell or give a security interest in and any filing of or agreement to give any financing statement under the Uniform Commercial Code (or equivalent statutes) of any jurisdiction other than a precautionary financing statement respecting a lease not intended as a security agreement.

"Moody's" means Moody's Investors Service, Inc. or any successor to the ratings business thereof.

"Net Proceeds" means the aggregate amount of cash proceeds and Cash Equivalents received by NGL Energy or any of its Restricted Subsidiaries in respect of any Asset Sale (including, without

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limitation, any cash or Cash Equivalents received upon the sale or other disposition of any non-cash consideration received in any Asset Sale, but excluding any non-cash consideration deemed to be cash for purposes of the "Asset Sales" provisions of the indenture), net of:

(1) the direct costs relating to such Asset Sale, including, without limitation, all legal, accounting, investment banking, title and recording tax expenses, commissions and other fees and expense incurred, and all federal, state, provincial, foreign and local taxes required to be paid or accrued as a liability under GAAP (after taking into account any available tax credits or deductions and any tax sharing agreements), as a consequence of such Asset Sale;

(2) all payments made on any Indebtedness that is secured by any assets subject to such Asset Sale, in accordance with the terms of such Indebtedness, or that must by its terms, or in order to obtain a necessary consent to such Asset Sale, or by applicable law be repaid out of the proceeds from such Asset Sale;

(3) all distributions and other payments required to be made to holders of minority interests in Subsidiaries or Joint Ventures as a result of such Asset Sale; and

(4) the deduction of appropriate amounts to be provided by the seller as a reserve, in accordance with GAAP, or held in escrow, in either case for as long as required to be held as reserve or in escrow for adjustment in respect of the sale price or for indemnification or any liabilities associated with the assets disposed of in such Asset Sale and retained by NGL Energy or any Restricted Subsidiary after such Asset Sale.

"Non-Recourse Debt" means Indebtedness:

(1) as to which neither NGL Energy nor any of its Restricted Subsidiaries (a) provides credit support of any kind (including any undertaking, Guarantee, indemnity, agreement or instrument that would constitute Indebtedness) or (b) is directly or indirectly liable as a guarantor or otherwise, in each case of clause (a) and (b) above, except for Customary Recourse Exceptions; and

(2) as to which the lenders have been notified in writing that they will not have any recourse to the Capital Stock or assets of NGL Energy or any of its Restricted Subsidiaries (other than the Equity Interests of any Unrestricted Subsidiary or Joint Venture), except for Customary Recourse Exceptions.

"Note Guarantee" means any Guarantee of the Issuers' obligations under the indenture and the notes by any Guarantor in accordance with the provisions of the indenture.

"Obligations" means any principal, interest, penalties, fees, indemnifications, reimbursements, damages and other liabilities payable under the documentation governing any Indebtedness.

"Officer" means, with respect to any Person, the Chairman of the Board, the Chief Executive Officer, the President, the Chief Operating Officer, the Chief Financial Officer, the Chief Accounting Officer, the Treasurer, any Assistant Treasurer, the Controller, the Secretary or any Vice-President of such Person (or, with respect to NGL Energy, so long as it remains a partnership, the General Partner).

"Officers' Certificate" means a certificate signed on behalf of NGL Energy by two Officers of NGL Energy or two Officers of the General Partner, one of whom must be the principal executive officer, the principal financial officer or the principal accounting officer of such Person, that meets the requirements of the indenture pertaining to such certificates.

"Operating Surplus" has the meaning assigned to such term in the Partnership Agreement, as in effect on the Issue Date.

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"Partnership Agreement" means the Second Amended and Restated Agreement of Limited Partnership of NGL Energy dated as of May 10, 2011, as amended by the First Amendment thereto dated as of October 20, 2011, the Second Amendment thereto dated as of January 6, 2012, the Third Amendment thereto dated as of January 20, 2012 and the Fourth Amendment thereto dated as of July 11, 2012, as such may be further amended, modified or supplemented from time to time.

"Permitted Acquisition Indebtedness" means Indebtedness or Disqualified Stock of NGL Energy or any of its Restricted Subsidiaries to the extent such Indebtedness or Disqualified Stock was Indebtedness or Disqualified Stock of:

(1) a Subsidiary prior to the date on which such Subsidiary became a Restricted Subsidiary; or

(2) a Person that was merged or consolidated into NGL Energy or a Restricted Subsidiary;

provided that on the date such Subsidiary became a Restricted Subsidiary or the date such Person was merged and consolidated into NGL Energy or a Restricted Subsidiary, as applicable, after givingpro forma effect thereto and to any related financing transaction as if the same had occurred at the beginning of the applicable four-quarter period:

(a) the Restricted Subsidiary or NGL Energy, as applicable, would be permitted to incur at least $1.00 of additional Indebtedness pursuant to the Fixed Charge Coverage Ratio test described under "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock," or

(b) the Fixed Charge Coverage Ratio for the Restricted Subsidiary or NGL Energy, as applicable, would be greater than the Fixed Charge Coverage Ratio for such Restricted Subsidiary or NGL Energy immediately prior to such transaction.

"Permitted Business" means either (a) gathering, transporting, compressing, treating, processing, marketing, distributing, storing or otherwise handling Hydrocarbons, or activities or services reasonably related or ancillary thereto, including water treatment, disposal and transportation, and entering into Hedging Obligations relating to any of the foregoing activities, or (b) any other business that generates gross income at least 90% of which constitutes "qualifying income" under Section 7704(d) of the Internal Revenue Code.

"Permitted Business Investments" means Investments by NGL Energy or any of its Restricted Subsidiaries in any Unrestricted Subsidiary or in any Joint Venture;provided that:

(1) either (a) at the time of such Investment and immediately thereafter, NGL Energy could incur $1.00 of additional Indebtedness under the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant described above under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock" or (b) such Investment does not exceed the aggregate amount of Incremental Funds (as defined in the covenant described under "—Covenants—Restricted Payments") not previously expended at the time of making such Investment;

(2) if such Unrestricted Subsidiary or Joint Venture has outstanding Indebtedness at the time of such Investment, either (a) all such Indebtedness is Non-Recourse Debt or (b) any such Indebtedness of such Unrestricted Subsidiary or Joint Venture that is recourse to NGL Energy or any of its Restricted Subsidiaries (which shall include, without limitation, all Indebtedness of such Unrestricted Subsidiary or Joint Venture for which NGL Energy or any of its Restricted Subsidiaries may be directly or indirectly, contingently or otherwise, obligated to pay, whether pursuant to the terms of such Indebtedness, by law or pursuant to any guarantee, including, without limitation, any "claw-back," "make-well" or "keep-well" arrangement) could, at the time such Investment is made, be incurred at that time by NGL Energy and its Restricted Subsidiaries under the Fixed Charge Coverage Ratio test set forth in the first paragraph of the covenant

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described above under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock;" and (3) such Unrestricted Subsidiary's or Joint Venture's activities are not outside the scope of the Permitted Business.

"Permitted Debt" is defined in the covenant described under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock."

"Permitted Holder" means: (i) any of Coady Enterprises, LLC, Shawn W. Coady, Thorndike, LLC, Todd M. Coady, SemGroup Corporation, KrimGP2010, LLC, H. Michael Krimbill, EMG I NGL GP Holdings, LLC and EMG II NGL GP Holdings, LLC; (ii) any wife, lineal descendant, legal guardian or other legal representative or estate of any of the Persons described in the preceding clause (i); (iii) any trust of which at least one of the trustees is any of the Persons described in the preceding clauses (i) or (ii); and (iv) any other Person that is controlled directly or indirectly by any one or more of the Persons described in the preceding clauses (i) through (iii). As of the Issue Date, (i) Shawn W. Coady is our President and Chief Operating Officer, Retail Division, (ii) Todd M. Coady is our Vice President, Administration and (iii) H. Michael Krimbill is our Chief Executive Officer and a member of our Board of Directors.

"Permitted Investments" means:

(1) any Investment in NGL Energy or in a Restricted Subsidiary;

(2) any Investment in Cash Equivalents;

(3) any Investment by NGL Energy or any Restricted Subsidiary in a Person, if as a result of such Investment:

(a) such Person becomes a Restricted Subsidiary; or

(b) such Person is merged, consolidated or amalgamated with or into, or transfers or conveys substantially all of its assets to, or is liquidated into, NGL Energy or a Restricted Subsidiary;

(4) any Investment made as a result of the receipt of non-cash consideration from an Asset Sale that was made pursuant to and in compliance with the covenant described above under the caption "—Repurchase at the Option of Holders—Asset Sales;"

(5) any Investment in a Person to the extent in exchange for the issuance of Equity Interests (other than Disqualified Stock) of NGL Energy;

(6) any Investments received in compromise or resolution of (a) obligations of trade creditors or customers that were incurred in the ordinary course of business of NGL Energy or any of its Restricted Subsidiaries, including pursuant to any plan of reorganization or similar arrangement upon the bankruptcy or insolvency of any trade creditor or customer, or as a result of a foreclosure by, or other transfer of title to, NGL Energy or any of its Restricted Subsidiaries with respect to any secured investment in default; or (b) litigation, arbitration or other disputes;

(7) Investments represented by Hedging Obligations;

(8) Investments in any Person to the extent such Investments consist of prepaid expenses, negotiable instruments held for collection and lease, utility and workers' compensation, performance and other deposits made in the ordinary course of business by NGL Energy or any of its Restricted Subsidiaries;

(9) advances to or reimbursements of employees for moving, entertainment and travel expenses, drawing accounts and similar expenditures in the ordinary course of business;

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(10) loans or advances to officers, directors or employees made in the ordinary course of business of the General Partner, NGL Energy or any Restricted Subsidiary in an aggregate principal amount not to exceed $5.0 million at any one time outstanding;

(11) repurchases of the notes;

(12) advances and prepayments for asset purchases in the ordinary course of business in a Permitted Business of NGL Energy or any of its Restricted Subsidiaries;

(13) receivables owing to NGL Energy or any Restricted Subsidiary created or acquired in the ordinary course of business and payable or dischargeable in accordance with customary trade terms;provided,however, that such trade terms may include such concessionary trade terms as NGL Energy or any such Restricted Subsidiary deems reasonable under the circumstances;

(14) any Guarantee of Indebtedness permitted to be incurred by the covenant entitled "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock" other than a guarantee of Indebtedness of an Affiliate of NGL Energy that is not a Restricted Subsidiary;

(15) any Investment existing on, or made pursuant to binding commitments existing on, the Issue Date and any Investment consisting of an extension, modification or renewal of any Investment existing on, or made pursuant to a binding commitment existing on, the Issue Date;provided that the amount of any such Investment may be increased (a) as required by the terms of such Investment as in existence on the Issue Date or (b) as otherwise permitted under the indenture;

(16) surety and performance bonds and workers' compensation, utility, lease, tax, performance and similar deposits and prepaid expenses in the ordinary course of business;

(17) guarantees by NGL Energy or any of its Restricted Subsidiaries of operating leases (other than Capital Lease Obligations) or of other obligations that do not constitute Indebtedness, in each case entered into by NGL Energy or any such Restricted Subsidiary in the ordinary course of business;

(18) Permitted Business Investments;

(19) Investments received as a result of a foreclosure by NGL Energy or any of its Restricted Subsidiaries with respect to any secured Investment in default;

(20) Investments acquired after the Issue Date as a result of the acquisition by NGL Energy or any Restricted Subsidiary of another Person, including by way of a merger, amalgamation or consolidation with or into NGL Energy or any of its Restricted Subsidiaries, or all or substantially all of the assets of another Person, in each case, in a transaction that is not prohibited by the covenant described above under the caption "—Merger, Consolidation or Sale of Assets" after the Issue Date to the extent that such Investments were not made in contemplation of such acquisition, merger, amalgamation or consolidation and were in existence on the date of such acquisition, merger, amalgamation or consolidation; and

(21) other Investments in any Person (including Investments in any Joint Venture) having an aggregate Fair Market Value (measured on the date each such Investment was made and without giving effect to subsequent changes in value), when taken together with all other Investments made pursuant to this clause (21) that are at the time outstanding that do not exceed the greater of (a) $75.0 million and (b) 3.25% of the Total Assets of NGL Energy;provided, however, that if any Investment pursuant to this clause (21) is made in any Person that is not a Restricted Subsidiary at the date of the making of such Investment and such Person becomes a Restricted Subsidiary after such date, such Investment shall thereafter be deemed to have been made pursuant to clause (1)

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above and shall cease to have been made pursuant to this clause (21) for so long as such Person continues to be a Restricted Subsidiary.

"Permitted Liens" means, with respect to any Person:

(1) Liens securing Indebtedness incurred under Credit Facilities that is permitted to be incurred pursuant to clause (1) of the definition of Permitted Debt in the covenant described under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock;"

(2) Liens securing (a) Indebtedness incurred under the first paragraph of the covenant described above under the caption "—Incurrence of Indebtedness and Issuance of Preferred Stock" not to exceed $250.0 million in the aggregate;provided that the Existing Senior Secured Notes and all Permitted Refinancing Indebtedness in respect thereof shall have been repaid, repurchased or redeemed in full or (b) up to $250.0 million of Indebtedness under the Existing Senior Secured Notes;

(3) Liens securing Indebtedness of Foreign Subsidiaries that is permitted to be incurred pursuant to clause (14) of the definition of Permitted Debt in the covenant described under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock;"

(4) Liens to secure Hedging Obligations and/or Obligations with respect to Treasury Management Arrangements incurred in the ordinary course of business;

(5) Liens on property of a Person existing at the time such Person becomes a Restricted Subsidiary or is merged with or into or consolidated with NGL Energy or any Restricted Subsidiary;provided that such Liens were in existence prior to the contemplation of such Person becoming a Restricted Subsidiary or such merger or consolidation and do not extend to any assets (other than improvements thereon, accessions thereto and proceeds thereof) other than those of the Person that becomes a Restricted Subsidiary or is merged with or into or consolidated with NGL Energy or any Restricted Subsidiary;

(6) Liens on property (including Capital Stock) existing at the time of acquisition of the property by NGL Energy or any Subsidiary of NGL Energy, including any acquisition by means of a merger or consolidation with or into NGL Energy or a Restricted Subsidiary;provided that such Liens were in existence prior to such acquisition and not incurred in contemplation of, such acquisition;

(7) Liens, pledges or deposits by such Person under workers' compensation laws, unemployment insurance laws or similar legislation, or good faith deposits in connection with bids, tenders, contracts (other than for the payment of Indebtedness) or leases to which such Person is a party, or deposits to secure public or statutory obligations of such Person or deposits or cash or United States government bonds to secure surety or appeal bonds to which such Person is a party, or deposits as security for contested taxes or import or customs duties or for the payment of rent, in each case incurred in the ordinary course of business;

(8) landlords', carriers', warehousemen's, mechanics', materialmen's, repairmen's or similar Liens arising by contract or statute in the ordinary course of business and with respect to amount that are not yet delinquent or are being contested in good faith by appropriate proceedings;

(9) Liens to secure Indebtedness (including Capital Lease Obligations) permitted by clause (4) of the definition of Permitted Debt in the covenant described under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock" covering only the assets acquired with or financed by such Indebtedness;

(10) Liens to secure Indebtedness of Restricted Subsidiaries that are not Guarantors permitted under the covenant entitled "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock;provided that such Liens may not extend to any property or assets of NGL Energy or any Guarantor other than the Capital Stock of any non-Guarantor Restricted Subsidiaries;

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(11) Liens on and pledges of the Equity Interests of any Unrestricted Subsidiary or any Joint Venture owned by NGL Energy or any Restricted Subsidiary to the extent securing Non-Recourse Debt or other Indebtedness of such Unrestricted Subsidiary or Joint Venture;

(12) Liens on any asset or property acquired, constructed or improved by NGL Energy or any of its Restricted Subsidiaries;provided that (a) such Liens are in favor of the seller of such asset or property, in favor of the Person or Persons developing, constructing, repairing or improving such asset or property, or in favor of the Person or Persons that provided the funding for the acquisition, development, construction, repair or improvement cost, as the case may be, of such asset or property, (b) such Liens are created within 360 days after the acquisition, development, construction, repair or improvement, (c) the aggregate principal amount of the Indebtedness secured by such Liens is otherwise permitted to be incurred under the indenture and does not exceed the greater of (i) the cost of the asset or property so acquired, constructed or improved plus related financing costs and (ii) the Fair Market Value of the asset or property so acquired, constructed or improved, measured at the date of such acquisition, or the date of completion of such construction or improvement, and (d) such Liens are limited to the asset or property so acquired, constructed or improved (including the proceeds thereof, accessions thereto, upgrades thereof and improvements thereto);

(13) Liens existing on the Issue Date;

(14) Liens for taxes, assessments or governmental charges or claims that are not yet delinquent or that are being contested in good faith by appropriate proceedings promptly instituted and diligently concluded;provided that any reserve or other appropriate provision as is required in conformity with GAAP has been made therefor;

(15) Liens imposed by law, such as carriers', warehousemen's, landlord's and mechanics' Liens, in each case, incurred in the ordinary course of business;

(16) survey exceptions, easements or reservations of, or rights of others for, licenses, rights-of-way, sewers, electric lines, telegraph and telephone lines and other similar purposes, leases and subleases of real property, or zoning or other restrictions as to the use of real property that were not incurred in connection with Indebtedness and that do not in the aggregate materially adversely affect the value of said properties or materially impair their use in the operation of the business of NGL Energy and its Restricted Subsidiaries, considered as a single enterprise;

(17) Liens created for the benefit of (or to secure) the notes or the Note Guarantees or other obligations under the indenture and Liens securing any Indebtedness equally and ratably with all Obligations due under the notes or any Note Guarantee pursuant to a contractual covenant that limits Liens in a manner substantially similar to the covenant described above under "—Covenants—Liens;"

(18) Liens on pipelines or pipeline facilities that arise by operation of law;

(19) Liens to secure any Permitted Refinancing Indebtedness permitted to be incurred under the indenture;provided, however, that the new Lien is limited to all or part of the same property and assets that secured or, under the written agreements pursuant to which the original Lien arose, could secure the original Lien (plus improvements and accessions to, such property or proceeds or distributions thereof);

(20) Liens on insurance policies and proceeds thereof, or other deposits, to secure insurance premium financings;

(21) filing of Uniform Commercial Code financing statements as a precautionary measure in connection with operating leases;

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(22) bankers' Liens, rights of setoff, Liens arising out of judgments, attachments or awards not constituting an Event of Default and notices oflis pendens and associated rights related to litigation being contested in good faith by appropriate proceedings and for which adequate reserves have been made;

(23) Liens on cash, Cash Equivalents or other property arising in connection with the defeasance, discharge or redemption of Indebtedness;

(24) Liens on specific items of inventory or other goods (and the proceeds thereof) of any Person securing such Person's obligations in respect of bankers' acceptances issued or created in the ordinary course of business for the account of such Person to facilitate the purchase, shipment or storage of such inventory or other goods;

(25) grants of software and other technology licenses in the ordinary course of business;

(26) Liens arising out of conditional sale, title retention, consignment or similar arrangements for the sale of goods entered into in the ordinary course of business;

(27) Liens in favor of the Issuers or any of the Guarantors;

(28) Liens arising under operating agreements, joint venture agreements, partnership agreements, construction agreements, oil and gas leases, farmout agreements, division orders, agreements for the purchase, gathering, processing, treatment, sale, transportation or exchange of Hydrocarbons, unitization and pooling designations, declarations, orders and agreements, development agreements, participating agreements, area of mutual interest agreements, gas balancing agreements, injection, repressuring and recycling agreements, salt water or other disposal agreements, and other agreements arising in the ordinary course of NGL Energy's or any of its Restricted Subsidiaries' business that are customary in the Permitted Business;

(29) Liens on, or related to, properties or assets to secure all or part of the costs incurred in the ordinary course of a Permitted Business for gathering, transporting, compressing, treating, processing, marketing, distributing, storing or otherwise handling Hydrocarbons, or activities or services reasonably related or ancillary thereto, including entering into Hedging Obligations to support these businesses and the development, manufacture or sale of equipment or technology related to these activities;

(30) Liens arising solely by virtue of any statutory or common law provisions relating to bankers' Liens, rights of set-off or similar rights and remedies as to deposit accounts or other funds maintained or deposited with a depositary institution;provided that:

(a) such deposit account is not a dedicated cash collateral account and is not subject to restrictions against access by NGL Energy in excess of those set forth by regulations promulgated by the Federal Reserve Board; and

(b) such deposit account is not intended by NGL Energy or any Restricted Subsidiary to provide collateral to the depository institution;

(31) Liens arising from Uniform Commercial Code financing statement filings regarding operating leases entered into by NGL Energy and its Restricted Subsidiaries in the ordinary course of business;

(32) Liens arising under the indenture in favor of the trustee under the indenture for its own benefit and similar Liens in favor of other trustees, agents and representatives arising under instruments governing Indebtedness permitted to be incurred under the indenture;provided that such Liens are solely for the benefit of the trustees, agents or representatives in their capacities as such and not for the benefit of the holders of the Indebtedness; and

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(33) Liens incurred in the ordinary course of business of NGL Energy or any Restricted Subsidiary with respect to obligations at any one time outstanding not to exceed the greater of (a) $75.0 million and (b) 3.25% of the Total Assets of NGL Energy.

"Permitted Refinancing Indebtedness" means any Indebtedness of NGL Energy or any of its Restricted Subsidiaries, any Disqualified Stock of NGL Energy or any preferred stock of any Restricted Subsidiary (a) issued in exchange for, or the net proceeds of which are used to extend, renew, refund, refinance, replace, defease, discharge or otherwise retire for value, in whole or in part, or (b) constituting an amendment, modification or supplement to or a deferral or renewal of (clauses (a) and (b), collectively, a "Refinancing," and the term "Refinanced" has a correlative meaning) any other Indebtedness of NGL Energy or any of its Restricted Subsidiaries (other than intercompany Indebtedness), any Disqualified Stock of NGL Energy or any preferred stock of a Restricted Subsidiary in a principal amount or, in the case of Disqualified Stock of NGL Energy or preferred stock of a Restricted Subsidiary, liquidation preference, not to exceed (after deduction of reasonable and customary fees and expenses incurred in connection with the Refinancing) the lesser of:

(1) the principal amount or, in the case of Disqualified Stock or preferred stock, liquidation preference, of the Indebtedness, Disqualified Stock or preferred stock so Refinanced (plus, in the case of Indebtedness, the amount of premium, if any paid in connection therewith); and

(2) if the Indebtedness being Refinanced was issued with any original issue discount, the accreted value of such Indebtedness (as determined in accordance with GAAP) at the time of such Refinancing.

Notwithstanding the preceding, no Indebtedness, Disqualified Stock or preferred stock will be deemed to be Permitted Refinancing Indebtedness, unless:

(i) such Indebtedness, Disqualified Stock or preferred stock has a final maturity date or redemption date, as applicable, no earlier than the final maturity date or redemption date, as applicable, of, and has a Weighted Average Life to Maturity equal to or greater than the Weighted Average Life to Maturity of, the Indebtedness, Disqualified Stock or preferred stock being Refinanced;

(ii) if the Indebtedness, Disqualified Stock or preferred stock being Refinanced is contractually subordinated or otherwise junior in right of payment to the notes, such Indebtedness (and any related Guarantee), Disqualified Stock or preferred stock is contractually subordinated or otherwise junior in right of payment to, the notes, on terms at least as favorable to the holders of notes as those contained in the documentation governing the Indebtedness, Disqualified Stock or preferred stock being Refinanced at the time of the Refinancing; and

(iii) such Indebtedness or Disqualified Stock is incurred or issued by NGL Energy or such Indebtedness, Disqualified Stock or preferred stock is incurred or issued by the Restricted Subsidiary who is the obligor on the Indebtedness being Refinanced or the issuer of the Disqualified Stock or preferred stock being Refinanced;provided that a Restricted Subsidiary that is also a Guarantor may guarantee Permitted Refinancing Indebtedness incurred by NGL Energy, regardless of whether such Restricted Subsidiary was an obligor or guarantor of the Indebtedness being Refinanced.

Notwithstanding the foregoing, any Indebtedness incurred under Credit Facilities shall be subject to the refinancing provision of the definition of Credit Facilities and not pursuant to the requirements set forth in this definition of Permitted Refinancing Indebtedness. "Person" means any individual, corporation, partnership, joint venture, association, joint-stock company, trust, unincorporated organization, limited liability company or government or other entity.

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"Rating Agency" means each of S&P, Moody's and Fitch, or if (and only if) any of S&P, Moody's or Fitch shall not make a rating on the notes publicly available, a nationally recognized statistical rating agency or agencies, as the case may be, selected by NGL Energy, which shall be substituted for S&P, Moody's or Fitch, as the case may be.

"Reporting Default" means a Default described in subclause (b) of clause (5) under "—Events of Default and Remedies."

"Restricted Investment" means an Investment other than a Permitted Investment.

"Restricted Subsidiary" means any Subsidiary of NGL Energy, other than an Unrestricted Subsidiary.

"S&P" means Standard & Poor's Ratings Services, a division of The McGraw-Hill Companies, Inc., or any successor to the rating business thereof.

"SEC" means the United States Securities and Exchange Commission.

"Securities Act" means the Securities Act of 1933, as amended.

"Senior Debt" means:

(1) all Indebtedness of NGL Energy or any of its Restricted Subsidiaries outstanding under Credit Facilities and all Hedging Obligations with respect thereto;

(2) the notes and any other Indebtedness of NGL Energy or any of its Restricted Subsidiaries permitted to be incurred under the terms of the indenture, unless the instrument under which such Indebtedness is incurred expressly provides that it is subordinated in right of payment to the notes or any Note Guarantee; and

(3) all Obligations with respect to the items listed in the preceding clauses (1) and (2).

Notwithstanding anything to the contrary in the preceding sentence, Senior Debt will not include:

(i) any intercompany Indebtedness of NGL Energy or any of its Subsidiaries to NGL Energy or any of its Affiliates;

(ii) any Indebtedness that is incurred in violation of the indenture; or

(iii) any trade payables or taxes owed or owing by NGL Energy or any of its Restricted Subsidiary.

"Significant Subsidiary" means any Restricted Subsidiary that would be a "significant subsidiary" as defined in Article 1, Rule 1-02 of Regulation S-X promulgated pursuant to the Securities Act, as such Regulation is in effect on the Issue Date.

"Stated Maturity" means, with respect to any installment of interest or principal on any series of Indebtedness, the date on which the payment of interest or principal was scheduled to be paid in the documentation governing such Indebtedness as of the first date it was incurred in compliance with the terms of the indenture, and will not include any contingent obligations to repay, redeem or repurchase any such interest or principal prior to the date originally scheduled for the payment thereof;provided that, in the case of debt securities that are by their terms convertible into Capital Stock (or cash or a combination of cash and Capital Stock based on the value of the Capital Stock) of NGL Energy, any obligation to offer to repurchase such debt securities on a date(s) specified in the original terms of such securities, which obligation is not subject to any condition or contingency, will be treated as a Stated Maturity date of such convertible debt securities.

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"Subordinated Debt" means Indebtedness of NGL Energy or a Guarantor that is contractually subordinated in right of payment (by its terms or the terms of any document or instrument relating thereto) to the notes or the Note Guarantee of such Guarantor, as applicable.

"Subsidiary" means, with respect to any specified Person:

(1) any corporation, association or other business entity (other than a partnership or a limited liability company) of which more than 50% of the total voting power of its Voting Stock is at the time owned or controlled, directly or indirectly, by that Person or one or more of the other Subsidiaries of that Person (or a combination thereof); and

(2) any partnership or limited liability company of which (a) more than 50% of the capital accounts, distribution rights, total equity and voting interests or general and limited partnership interests, as applicable, are owned or controlled, directly or indirectly, by such Person or one or more of the other Subsidiaries of that Person or a combination thereof, whether in the form of membership, general, special or limited partnership interests or otherwise, and (b) such Person or any Subsidiary of such Person is a controlling general partner or otherwise controls such entity.

"Total Assets" of any Person means, as of any date, the amount that, in accordance with GAAP, would be set forth under the caption "Total Assets" (or any like caption) on a consolidated balance sheet of such Person and its Restricted Subsidiaries, as of the end of the most recently ended fiscal quarter for which internal financial statements are available;provided,however that such amount shall be adjusted to givepro forma effect to any subsequent Investment, acquisition or disposition of any assets or Person (regardless of whether effected as a merger, purchase or sale of Equity Interests, asset acquisition or disposition or other form of acquisition or disposition) by such Person or any of its Restricted Subsidiaries, including any such Investment, acquisition or disposition that is pending and giving rise to the need to determine the amount of Total Assets, as if such transaction had occurred immediately prior to the end of such most recently ended fiscal quarter.

"Treasury Management Arrangement" means any agreement or other arrangement governing the provision of treasury or cash management services, including deposit accounts, overdraft, credit or debit card, funds transfer, automated clearinghouse, zero balance accounts, returned check concentration, controlled disbursement, lockbox, account reconciliation and reporting and trade finance services and other cash management services.

"Unrestricted Subsidiary" means any Subsidiary of NGL Energy (excluding Finance Corp.) that is designated by the Board of Directors of NGL Energy as an Unrestricted Subsidiary pursuant to a resolution of the Board of Directors, but only to the extent that such Subsidiary:

(1) except to the extent permitted by subclause (2)(b) of the definition of "Permitted Business Investments," has no Indebtedness other than Non-Recourse Debt owing to any Person other than NGL Energy or any of its Restricted Subsidiaries;

(2) is a Person with respect to which neither NGL Energy nor any of its Restricted Subsidiaries has any direct or indirect obligation (a) to subscribe for additional Equity Interests or (b) to maintain or preserve such Person's financial condition or to cause such Person to achieve any specified levels of operating results; and

(3) has not guaranteed or otherwise directly or indirectly provided credit support for any Indebtedness of NGL Energy or any of its Restricted Subsidiaries, except to the extent such Guarantee or credit support would be released upon such designation.

All Subsidiaries of an Unrestricted Subsidiary shall also be Unrestricted Subsidiaries.

"Voting Stock" of any specified Person as of any date means the Capital Stock of such Person entitling the holders thereof (whether at all times or only so long as no senior class of Capital Stock

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has voting power by reason of any contingency) to vote in the election of members of the Board of Directors of such Person;provided that, with respect to a limited partnership or other entity which does not have a Board of Directors, Voting Stock means the Capital Stock of the general partner of such limited partnership or other business entity with the ultimate authority to manage the business and operations of such Person.

"Weighted Average Life to Maturity" means, when applied to any Indebtedness at any date, the number of years obtained by dividing:

(1) the sum of the products obtained by multiplying (a) the amount of each then remaining installment, sinking fund, serial maturity or other required payments of principal, including payment at final maturity, in respect of the Indebtedness, by (b) the number of years (calculated to the nearest one-twelfth) that will elapse between such date and the making of such payment;by

(2) the then outstanding principal amount of such Indebtedness.

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PLAN OF DISTRIBUTION

Each broker-dealer that receives New Notes for its own account pursuant to the exchange offer must acknowledge that it will deliver a prospectus in connection with any resale of such New Notes. This prospectus, as it may be amended or supplemented from time to time, may be used by a broker-dealer in connection with resales of new notes received in exchange for old notes where such old notes were acquired as a result of market-making activities or other trading activities. We have agreed that, for a period of 180 days after the consummation of the exchange offer, we will make this prospectus, as amended or supplemented, available to any broker-dealer for use in connection with any such resale. In addition, until , 2014, all dealers effecting transactions in the new notes may be required to deliver a prospectus.

We will not receive any proceeds from any sale of new notes by broker-dealers. New notes received by broker-dealers for their own account pursuant to the exchange offer may be sold from time to time in one or more transactions in the over-the-counter market, in negotiated transactions, through the writing of options on the new notes or a combination of such methods of resale, at market prices prevailing at the time of resale, at prices related to such prevailing market prices or negotiated prices. Any such resale may be made directly to purchasers or to or through brokers or dealers who may receive compensation in the form of commissions or concessions from any such broker-dealer or the purchasers of any such new notes. Any broker-dealer that resells new notes that were received by it for its own account pursuant to the exchange offer and any broker or dealer that participates in a distribution of such new notes may be deemed to be an "underwriter" within the meaning of the Securities Act and any profit on any such resale of new notes and any commissions or concessions received by any such persons may be deemed to be underwriting compensation under the Securities Act. The letter of transmittal states that, by acknowledging that it will deliver and by delivering a prospectus, a broker-dealer will not be deemed to admit that it is an "underwriter" within the meaning of the Securities Act.

For a period of 180 days after the consummation of the exchange offer, we will promptly send additional copies of this prospectus and any amendment or supplement to this prospectus to any broker-dealer that requests such documents in the letter of transmittal. We have agreed to pay all reasonable expenses incident to the exchange offer (including the reasonable expenses of one counsel for the holders of the notes) other than commissions or concessions of any brokers or dealers and will indemnify the holders of the old notes (including any broker-dealers) against certain liabilities, including liabilities under the Securities Act.

Following completion of the exchange offer, we may, in our sole discretion, commence one or more additional exchange offers to holders of old notes who did not exchange their old notes for new notes in the exchange offer on terms which may differ from those contained in this prospectus and the enclosed letter of transmittal. This prospectus, as it may be amended or supplemented from time to time, may be used by us in connection with any additional exchange offers. These additional exchange offers may take place from time to time until all outstanding old notes have been exchanged for new notes, subject to the terms and conditions in the prospectus and letter of transmittal distributed by us in connection with these additional exchange offers.

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CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES

The following discussion is a summary of certain U.S. federal income tax considerations relevant to the exchange of old notes for new notes, but does not purport to be a complete analysis of all potential tax effects. The discussion is based upon the Internal Revenue Code of 1986, as amended, Treasury Regulations, Internal Revenue Service rulings and pronouncements and judicial decisions now in effect, all of which may be subject to change at any time by legislative, judicial or administrative action. These changes may be applied retroactively in a manner that could adversely affect a holder of new notes. We cannot assure you that the Internal Revenue Service will not challenge one or more of the tax consequences described in this discussion, and we have not obtained, nor do we intend to obtain, a ruling from the Internal Revenue Service or an opinion of counsel with respect to the U.S. federal tax consequences described herein. Some holders, including financial institutions, insurance companies, regulated investment companies, tax-exempt organizations, dealers in securities or currencies, persons whose functional currency is not the U.S. dollar or persons who hold the notes as part of a hedge, conversion transaction, straddle or other risk reduction transaction may be subject to special rules not discussed below.

We recommend that each holder consult his own tax advisor as to the particular tax consequences of exchanging such holder's old notes for new notes, including the applicability and effect of any foreign, state, local or other tax laws or estate or gift tax considerations.

We believe that the exchange of old notes for new notes will not be a taxable exchange to a holder for U.S. federal income tax purposes. Accordingly, a holder will not recognize gain or loss upon receipt of a new note in exchange for an old note in the exchange, and the holder's basis and holding period in the new note will be the same as its basis and holding period in the corresponding old note immediately before the exchange.

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LEGAL MATTERS

The validity of the new notes offered in this exchange offer will be passed on by Andrews Kurth LLP, Houston, Texas. Certain matters with respect to Colorado law will be passed upon by William G. Laughlin, Denver, Colorado, internal counsel to NGL Energy Partners LP. Certain matters with respect to Wyoming law will be passed upon by Holland & Hart LLP, Cheyenne, Wyoming. Certain matters with respect to Oklahoma law will be passed upon by Wilkin / McMurray PLLC, Tulsa, Oklahoma. Certain matters with respect to Alberta law will be passed upon by Norton Rose Fulbright Canada LLP, Calgary, Alberta.

EXPERTS

Management's assessment of the effectiveness of internal control over financial reporting of NGL Energy Partners LP included in the Partnership's Annual Report on Form 10-K which is included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The audited consolidated financial statements of NGL Energy Partners LP and subsidiaries as of March 31, 2014 and 2013 and for each of the three years ended March 31, 2014 included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent registered public accountants, upon the authority of said firm as experts in accounting and auditing.

The consolidated financial statements of High Sierra Energy GP, LLC and subsidiaries as of December 31, 2011 and 2010 and for each of the three years in the period ended December 31, 2011 included in this prospectus and elsewhere in the registration statement have been so included in reliance upon the report of Grant Thornton LLP, independent certified public accountants, upon the authority of said firm as experts in accounting and auditing.

The financial statements of SemStream, L.P. Non-Residential Division as of December 31, 2010 and 2009 and for the year ended December 31, 2010, and for the one month ended December 31, 2009 (Subsequent to Emergence), and for the eleven months ended November 30, 2009, and for the year ended December 31, 2008 (Prior to Emergence), included in this prospectus, have been so included in reliance on the report of BDO USA, LLP, an independent registered public accounting firm, appearing elsewhere herein, given upon the authority of said firm as experts in auditing and accounting.

The combined financial statements of the Businesses of the Osterman Associated Companies Contributed to NGL Energy Partners LP as of September 30, 2011 and 2010 and for each of the three years in the period ended September 30, 2011, included in this prospectus, have been audited by Graham Shepherd, PC, independent certified public accountants, as stated in their report included herein. Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The audited combined financial statements of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC as of December 31, 2011 and for the three years then ended, included in this prospectus, have been audited by EKS&H, LLLP, independent certified public accountants, as stated in their report included herein. The condensed combined financial statements of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Midstream Operations, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC as of September 30, 2012 and for the nine months ended September 30, 2012 and 2011, included in this prospectus, have been reviewed by EKS&H, LLLP, independent certified public accountants, as stated in their report included herein.

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Such financial statements have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The consolidated financial statements of Oilfield Water Lines, LP as of December 31, 2012 and for the period from inception (August 6, 2012) to December 31, 2012, the financial statements of High Roller Wells Pearsall SWD No. 1, Ltd. for the period from January 1, 2012 through August 28, 2012, the financial statements of High Roller Wells Karnes SWD No. 1, Ltd. for the period from inception (March 14, 2012) through December 4, 2012, and the financial statements of Lotus Oilfield Services, LLC for the period from January 1, 2012 to December 27, 2012, all of which are included in this prospectus, have been so included in reliance on the report of BDO USA, LLP, an independent registered public accounting firm, appearing elsewhere herein, given upon the authority of said firm as experts in auditing and accounting.

The combined financial statements of Gavilon Energy (The Energy Business Units of Gavilon, LLC) as of December 31, 2012 and 2011, and the related combined statements of operations, comprehensive income (loss), equity and cash flows for each of the years in the three-year period ended December 31, 2012, have been included herein in reliance upon the report of KPMG, LLP, independent auditors, included herein and upon the authority of said firm as experts in accounting and auditing. NGL Energy Partners LP has agreed to indemnify and hold KPMG LLP (KPMG) harmless against and from any and all legal costs and expenses incurred by KPMG in successful defense of any legal action or proceeding that arises as a result of KPMG's consent to the inclusion of its audit report on the past financial statements of Gavilon Energy (The Energy Business Units of Gavilon, LLC) included in this registration statement.

The combined financial statements of Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP as of and for the years ended December 31, 2013 and 2012, included in this Prospectus have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

221

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INDEX TO FINANCIAL STATEMENTS


Audited Consolidated Financial Statements of NGL Energy Partners LP and Subsidiaries as of March 31, 2014 and 2013 and for Each of the Three Years Ended March 31, 2014
Report of Independent Registered Public Accounting Firm			F-5
Report of Independent Registered Public Accounting Firm			F-6
Consolidated Balance Sheets at March 31, 2014 and 2013			F-8
Consolidated Statements of Operations for the years ended March 31, 2014, 2013, and 2012			F-9
Consolidated Statements of Comprehensive Income for the years ended March 31, 2014, 2013, and 2012			F-10
Consolidated Statements of Changes in Equity for the years ended March 31, 2014, 2013, and 2012			F-11
Consolidated Statements of Cash Flows for the years ended March 31, 2014, 2013, and 2012			F-12
Notes to Consolidated Financial Statements			F-13
Unaudited Condensed Consolidated Financial Statements of NGL Energy Partners LP and Subsidiaries as of September 30, 2014 and for the Three Months and Six Months Ended September 30, 2014
Unaudited Condensed Consolidated Balance Sheets			F-80
Unaudited Condensed Consolidated Statements of Operations			F-81
Unaudited Condensed Consolidated Statements of Comprehensive Loss			F-82
Unaudited Condensed Consolidated Statement of Changes in Equity			F-83
Unaudited Condensed Consolidated Statements of Cash Flows			F-84
Notes to Unaudited Condensed Consolidated Financial Statements			F-85
Consolidated Financial Statements of High Sierra Energy GP, LLC and Subsidiaries as of December 31, 2011 and 2010 and for Each of the Three Years in the Period Ended December 31, 2011
Report of Independent Certified Public Accountants			F-142
Consolidated Balance Sheets			F-143
Consolidated Statements of Operations			F-144
Consolidated Statements of Equity			F-145
Consolidated Statements of Cash Flows			F-146
Notes to the Consolidated Financial Statements			F-147
Financial Statements of SemStream, L.P. Non-Residential Division as of December 31, 2010 and 2009 and for the Year Ended December 31, 2010, and for the One Month Ended December 31, 2009 (Subsequent to Emergence), and for the Eleven Months Ended November 30, 2009, and for the Year Ended December 31, 2008 (Prior to Emergence)
Report of Independent Registered Public Accounting Firm			F-206
Balance Sheets			F-207
Statements of Operations			F-208
Statements of Changes in Net Parent Equity (Deficit)			F-209
Statements of Cash Flows			F-210
Notes to Financial Statements			F-211
Unaudited Condensed Balance Sheets			F-232
Unaudited Condensed Statements of Operations			F-233
Unaudited Condensed Statements of Cash Flows			F-234
Notes to Unaudited Condensed Financial Statements			F-235

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Combined Financial Statements of the Businesses of the Osterman Associated Companies Contributed to NGL Energy Partners LP as of September 30, 2011 and 2010 and for Each of the Three Years in the Period Ended September 30, 2011
Report of Independent Certified Public Accountants			F-244
Combined Balance Sheets			F-245
Combined Statements of Operations and Changes in Equity of Combined Companies			F-246
Combined Statements of Cash Flows			F-247
Notes to Combined Financial Statements			F-248
Audited Combined Financial Statements of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC as of December 31, 2011 and for the Three Years Then Ended
Independent Auditors' Report			F-262
Combined Balance Sheets			F-263
Combined Statements of Income			F-264
Combined Statement of Changes in Members' and Stockholders' Equity			F-265
Combined Statements of Cash Flows			F-266
Notes to Combined Financial Statements			F-267
Unaudited Condensed Combined Financial Statements of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Midstream Operations, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC as of September 30, 2012 and for the Nine Months Ended September 30, 2012 and 2011
Combined Balance Sheets			F-276
Unaudited Combined Statements of Income			F-277
Unaudited Combined Statement of Changes in Members' and Stockholders' Equity			F-278
Unaudited Combined Statements of Cash Flows			F-279
Notes to Unaudited Combined Financial Statements			F-280
Audited Consolidated Financial Statements of Oilfield Water Lines, LP as of December 31, 2012 and for the Period from Inception (August 6, 2012) through December 31, 2012
Independent Auditor's Report			F-289
Consolidated Balance Sheet			F-290
Consolidated Statement of Operations			F-291
Consolidated Statement of Changes in Partners' Capital			F-292
Consolidated Statement of Cash Flows			F-293
Notes to Consolidated Financial Statements			F-294
Audited Financial Statements of High Roller Wells Pearsall SWD No. 1, Ltd. for the Period from January 1, 2012 through August 28, 2012
Independent Auditor's Report			F-303
Statement of Operations			F-304
Statement of Partners' Capital			F-305
Statement of Cash Flows			F-306
Notes to Financial Statements			F-307

F-2

Table of Contents


Audited Financial Statements of High Roller Wells Karnes SWD No. 1, Ltd. for the Period from Inception (March 14, 2012) through December 4, 2012
Independent Auditor's Report			F-311
Statement of Operations and Partners' Capital			F-312
Statement of Cash Flows			F-313
Notes to Financial Statements			F-314
Audited Financial Statements of Lotus Oilfield Services, LLC for the period from January 1, 2012 through December 27, 2012
Independent Auditor's Report			F-318
Statement of Operations			F-319
Statement of Changes in Members' Equity			F-320
Statement of Cash Flows			F-321
Notes to Financial Statements			F-322
Unaudited Condensed Consolidated Financial Statements of Oilfield Water Lines, LP as of June 30, 2013 and for the Six Months Then Ended
Unaudited Condensed Consolidated Balance Sheets			F-326
Unaudited Condensed Consolidated Statement of Operations			F-327
Unaudited Condensed Consolidated Statement of Changes in Capital			F-328
Unaudited Condensed Consolidated Statement of Cash Flows			F-329
Notes to Unaudited Condensed Consolidated Financial Statements			F-330
Unaudited Condensed Financial Statements of High Roller Wells Pearsall SWD No. 1, Ltd. for the Six Months Ended June 30, 2012
Unaudited Condensed Statement of Operations			F-337
Unaudited Condensed Statement of Cash Flows			F-338
Notes to Unaudited Condensed Financial Statements			F-339
Unaudited Condensed Financial Statements of High Roller Wells Karnes SWD No. 1, Ltd. for the Period from Inception (March 14, 2012) through June 30, 2012
Unaudited Condensed Statement of Operations			F-343
Unaudited Condensed Statement of Cash Flows			F-344
Notes to Unaudited Condensed Financial Statements			F-345
Unaudited Condensed Financial Statements of Lotus Oilfield Services, LLC for the Six Months Ended June 30, 2012
Unaudited Condensed Statement of Operations			F-348
Unaudited Condensed Statement of Cash Flows			F-349
Notes to Unaudited Condensed Financial Statements			F-350

F-3

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Audited Combined Financial Statements of Gavilon Energy (The Energy Business Units of Gavilon, LLC) as of December 31, 2012 and 2011 and for the Three Years in the Period Ended December 31, 2012
Independent Auditors' Report			F-354
Combined Balance Sheets			F-355
Combined Statements of Operations			F-356
Combined Statements of Comprehensive Income (Loss)			F-357
Combined Statements of Equity			F-358
Combined Statements of Cash Flows			F-359
Notes to Combined Financial Statements			F-360
Unaudited Condensed Combined Financial Statements of Gavilon Energy (The Energy Business Units of Gavilon, LLC) as of September 30, 2013 and for the Nine Months Ended September 30, 2013 and 2012
Unaudited Condensed Combined Balance Sheets			F-376
Unaudited Condensed Combined Statements of Operations			F-377
Unaudited Condensed Combined Statements of Comprehensive Loss			F-378
Unaudited Condensed Combined Statement of Equity			F-379
Unaudited Condensed Combined Statements of Cash Flows			F-380
Notes to Unaudited Condensed Combined Financial Statements			F-381
Audited Combined Financial Statements of the Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP as of December 31, 2013 and 2012 and for the Two Years Then Ended
Independent Auditors' Report			F-395
Combined Balance Sheets			F-396
Combined Statements of Comprehensive Income (Loss)			F-397
Combined Statements of Equity			F-398
Combined Statements of Cash Flows			F-399
Notes to Combined Financial Statements			F-400
Unaudited Condensed Combined Financial Statements of the Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP as of June 30, 2014 and for the Six Months Ended June 30, 2014 and 2013
Unaudited Condensed Combined Balance Sheets			F-424
Unaudited Condensed Combined Statements of Comprehensive Loss			F-425
Unaudited Condensed Combined Statement of Equity			F-426
Unaudited Condensed Combined Statements of Cash Flows			F-427
Notes to Condensed Combined Financial Statements			F-428

F-4

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Report of Independent Registered Public Accounting Firm

Partners
NGL Energy Partners LP

�� We have audited the accompanying consolidated balance sheets of NGL Energy Partners LP (a Delaware limited partnership) and subsidiaries (the "Partnership") as of March 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, changes in equity, and cash flows for each of the three years in the period ended March 31, 2014. These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of NGL Energy Partners LP and subsidiaries as of March 31, 2014 and 2013, and the results of their operations and their cash flows for each of the three years in the period ended March 31, 2014 in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Partnership's internal control over financial reporting as of March 31, 2014, based on criteria established in the 1992Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), and our report dated May 30, 2014 (not included herein) expressed an unqualified opinion.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma
May 30, 2014 (except for Note 17, as to which the date is July 9, 2014)

F-5

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Report of Independent Registered Public Accounting Firm

Partners
NGL Energy Partners LP

We have audited the internal control over financial reporting of NGL Energy Partners LP (a Delaware limited Partnership) and subsidiaries (the "Partnership") as of March 31, 2014, based on criteria established in the 1992Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Partnership's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control Over Financial Reporting ("Management's Report"). Our responsibility is to express an opinion on the Partnership's internal control over financial reporting based on our audit. Our audit of, and opinion on, the Partnership's internal control over financial reporting does not include the internal control over financial reporting of Gavilon, LLC ("Gavilon"), a wholly-owned subsidiary, whose financial statements reflect total assets and revenues constituting 31 and 30 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended March 31, 2014. As indicated in Management's Report, Gavilon was acquired during the year ended March 31, 2014. Management's assertion on the effectiveness of the Partnership's internal control over financial reporting excluded internal control over financial reporting of Gavilon.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, the Partnership maintained, in all material respects, effective internal control over financial reporting as of March 31, 2014, based on criteria established in the 1992Internal Control—Integrated Framework issued by COSO.

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We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements of the Partnership as of and for the year ended March 31, 2014, and our report dated May 30, 2014 expressed an unqualified opinion on those financial statements.

/s/ GRANT THORNTON LLP

Tulsa, Oklahoma
May 30, 2014

F-7

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Balance Sheets

At March 31, 2014 and 2013

(U.S. Dollars in Thousands, except unit amounts)

	March 31,

	2014			2013
				(Note 2)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	10,440		$	11,561
Accounts receivable—trade, net of allowance for doubtful accounts of $2,822 and $1,760, respectively		900,904			562,757
Accounts receivable—affiliates		7,445			22,883
Inventories		310,160			126,895
Prepaid expenses and other current assets		80,350			37,891


Total current assets		1,309,299			761,987
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $109,564 and $50,127, respectively		829,346			526,437
GOODWILL		1,107,006			555,220
INTANGIBLE ASSETS, net of accumulated amortization of $116,728 and $44,155, respectively		714,956			441,432
INVESTMENTS IN UNCONSOLIDATED ENTITIES		189,821			—
OTHER NONCURRENT ASSETS		16,795			6,542


Total assets	$	4,167,223		$	2,291,618




LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	740,211		$	536,055
Accounts payable—affiliates		76,846			6,900
Accrued expenses and other payables		141,690			85,606
Advance payments received from customers		29,965			22,372
Current maturities of long-term debt		7,080			8,626


Total current liabilities		995,792			659,559
LONG-TERM DEBT, net of current maturities		1,629,834			740,436
OTHER NONCURRENT LIABILITIES		9,744			2,205
COMMITMENTS AND CONTINGENCIES
EQUITY, per accompanying statement:
General partner, representing a 0.1% interest, 79,420 and 53,676 notional units at March 31, 2014 and 2013, respectively		(45,287	)		(50,497	)
Limited partners, representing a 99.9% interest—Common units, 73,421,309 and 47,703,313 units issued and outstanding at March 31, 2014 and 2013, respectively		1,570,074			920,998
Subordinated units, 5,919,346 units issued and outstanding at March 31, 2014 and 2013		2,028			13,153
Accumulated other comprehensive income (loss)		(236	)		24
Noncontrolling interests		5,274			5,740


Total equity		1,531,853			889,418


Total liabilities and equity	$	4,167,223		$	2,291,618

The accompanying notes are an integral part of these consolidated financial statements.

F-8

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Operations

For the Years Ended March 31, 2014, 2013, and 2012

(U.S. Dollars in Thousands, except unit and per unit amounts)

	Year Ended March 31,

	2014			2013			2012
REVENUES:
Crude oil logistics	$	4,558,545		$	2,316,288		$	—
Water solutions		143,100			62,227			—
Liquids		2,650,425			1,604,746			1,111,139
Retail propane		551,815			430,273			199,334
Refined products		1,180,895			—			—
Renewables		176,781			—			—
Other		437,713			4,233			—


Total Revenues		9,699,274			4,417,767			1,310,473


COST OF SALES:
Crude oil logistics		4,477,397			2,244,647			—
Water solutions		11,738			5,611			—
Liquids		2,518,099			1,530,459			1,086,881
Retail propane		354,676			258,393			130,142
Refined products		1,172,754			—			—
Renewables		171,422			—			—
Other		426,613			—			—


Total Cost of Sales		9,132,699			4,039,110			1,217,023


OPERATING COSTS AND EXPENSES:
Operating		259,396			169,799			47,300
General and administrative		79,860			52,698			16,009
Depreciation and amortization		120,754			68,853			15,111


Operating Income		106,565			87,307			15,030
OTHER INCOME (EXPENSE):
Earnings of unconsolidated entities		1,898			—			—
Interest expense		(58,854	)		(32,994	)		(7,620	)
Loss on early extinguishment of debt		—			(5,769	)		—
Other, net		86			1,521			1,055


Income Before Income Taxes		49,695			50,065			8,465
INCOME TAX PROVISION		(937	)		(1,875	)		(601	)


Net Income		48,758			48,190			7,864
NET INCOME ALLOCATED TO GENERAL PARTNER		(14,148	)		(2,917	)		(8	)
NET (INCOME) LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(1,103	)		(250	)		12


NET INCOME ALLOCATED TO LIMITED PARTNERS	$	33,507		$	45,023		$	7,868



									��
BASIC AND DILUTED INCOME PER COMMON UNIT	$	0.51		$	0.96		$	0.32




BASIC AND DILUTED INCOME PER SUBORDINATED UNIT	$	0.32		$	0.93		$	0.58




BASIC AND DILUTED WEIGHTED AVERAGE UNITS OUTSTANDING:
Common units		61,970,471			41,353,574			15,169,983




Subordinated units		5,919,346			5,919,346			5,175,384

The accompanying notes are an integral part of these consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Comprehensive Income

For the Years Ended March 31, 2014, 2013, and 2012

(U.S. Dollars in Thousands)

	Year Ended March 31,

	2014			2013			2012
Net income	$	48,758		$	48,190		$	7,864
Other comprehensive loss, net of tax		(260	)		(7	)		(25	)


Comprehensive income	$	48,498		$	48,183		$	7,839

The accompanying notes are an integral part of these consolidated financial statements.

F-10

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Changes in Equity

For the Years Ended March 31, 2014, 2013, and 2012

(U.S. Dollars in Thousands, except unit and share amounts)

				Limited Partners

				Limited Partners											Accumulated Other Comprehensive Income
	General Partner			Common Units			Amount			Subordinated Units		Amount			Accumulated Other Comprehensive Income			Noncontrolling Interests			Total Equity
BALANCES, MARCH 31, 2011	$	72			10,933,568		$	47,225			—	$	—		$	56		$	—		$	47,353
Distribution to partners prior to initial public offering		(4	)		—			(3,846	)		—		—			—			—			(3,850	)
Conversion of common units to subordinated units		—			(5,919,346	)		(23,485	)		5,919,346		23,485			—			—			—
Sale of units in public offering, net		—			4,025,000			75,289			—		—			—			—			75,289
Repurchase of common units		—			(175,000	)		(3,418	)		—		—			—			—			(3,418	)
Units issued in business combinations, net of issuance costs		—			14,432,031			296,500			—		—			—			—			296,500
Contributions		386			—			—			—		—			—			440			826
Net income (loss)		8			—			6,472			—		1,396			—			(12	)		7,864
Distribution to partners subsequent to initial public offering		(20	)		—			(10,133	)		—		(5,057	)		—			—			(15,210	)
Other comprehensive loss		—			—			—			—		—			(25	)		—			(25	)


BALANCES, MARCH 31, 2012		442			23,296,253			384,604			5,919,346		19,824			31			428			405,329
Distributions		(1,778	)		—			(59,841	)		—		(9,989	)		—			(74	)		(71,682	)
Contributions		510			—			—			—		—			—			403			913
Units issued in business combinations, net of issuance costs		(52,588	)		24,250,258			550,873			—		—			—			4,733			503,018
Equity issued pursuant to incentive compensation plan		—			156,802			3,657			—		—			—			—			3,657
Net income		2,917			—			41,705			—		3,318			—			250			48,190
Other comprehensive loss		—			—			��			—		—			(7	)		—			(7	)


BALANCES, MARCH 31, 2013		(50,497	)		47,703,313			920,998			5,919,346		13,153			24			5,740			889,418
Distributions		(9,703	)		—			(123,467	)		—		(11,920	)		—			(840	)		(145,930	)
Contributions		765			—			—			—		—			—			2,060			2,825
Units issued in business combinations, net of issuance costs		—			2,860,879			80,591			—		—			—			—			80,591
Sales of units, net of issuance costs		—			22,560,848			650,155			—		—			—			—			650,155
Equity issued pursuant to incentive compensation plan		—			296,269			9,085			—		—			—			—			9,085
Disposal of noncontrolling interest		—			—			—			—		—			—			(2,789	)		(2,789	)
Net income		14,148			—			32,712			—		795			—			1,103			48,758
Other comprehensive loss		—			—			—			—		—			(260	)		—			(260	)


BALANCES, MARCH 31, 2014	$	(45,287	)		73,421,309		$	1,570,074			5,919,346	$	2,028		$	(236	)	$	5,274		$	1,531,853

The accompanying notes are an integral part of these consolidated financial statements.

F-11

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Consolidated Statements of Cash Flows

For the Years Ended March 31, 2014, 2013, and 2012

(U.S. Dollars in Thousands)

	Year Ended March 31,

	2014			2013			2012
OPERATING ACTIVITIES:
Net income	$	48,758		$	48,190		$	7,864
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization, including debt issuance cost amortization		132,653			77,513			17,188
Loss on early extinguishment of debt		—			5,769			—
Non-cash equity-based compensation expense		14,054			8,670			—
Loss (gain) on disposal or impairment of assets		3,597			187			(71	)
Provision for doubtful accounts		2,172			1,315			1,049
Commodity derivative (gain) loss		43,655			4,376			(5,974	)
Earnings of unconsolidated entities		(1,898	)		—			—
Other		312			375			403
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable—trade		21,388			2,562			(20,179	)
Accounts receivable—affiliates		18,002			(12,877	)		193
Inventories		(73,321	)		18,433			30,268
Prepaid expenses and other current assets		18,900			22,585			14,344
Accounts payable—trade		(146,152	)		(16,913	)		35,747
Accounts payable—affiliates		67,361			(6,813	)		4,549
Accrued expenses and other payables		(61,171	)		(9,689	)		366
Advance payments received from customers		(3,074	)		(11,049	)		4,582


Net cash provided by operating activities		85,236			132,634			90,329


INVESTING ACTIVITIES:
Purchases of long-lived assets		(165,148	)		(72,475	)		(7,544	)
Acquisitions of businesses, including acquired working capital, net of cash acquired		(1,268,810	)		(490,805	)		(297,401	)
Cash flows from commodity derivatives		(35,956	)		11,579			6,464
Proceeds from sales of assets		24,660			5,080			1,238
Investments in unconsolidated entities		(11,515	)		—			—
Distributions of capital from unconsolidated entities		1,591			—			—
Other		(195	)		—			346


Net cash used in investing activities		(1,455,373	)		(546,621	)		(296,897	)

									��
FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities		2,545,500			1,227,975			478,900
Payments on revolving credit facilities		(2,101,000	)		(964,475	)		(329,900	)
Issuances of notes		450,000			250,000			—
Proceeds from borrowings on other long-term debt		880			653			—
Payments on other long-term debt		(8,819	)		(4,837	)		(1,278	)
Debt issuance costs		(24,595	)		(20,189	)		(2,380	)
Contributions		2,825			913			440
Distributions		(145,930	)		(71,682	)		(19,060	)
Proceeds from sale of common units, net of offering costs		650,155			(642	)		74,759
Repurchase of common units		—			—			(3,418	)


Net cash provided by financing activities		1,369,016			417,716			198,063


Net increase (decrease) in cash and cash equivalents		(1,121	)		3,729			(8,505	)
Cash and cash equivalents, beginning of period		11,561			7,832			16,337


Cash and cash equivalents, end of period	$	10,440		$	11,561		$	7,832

The accompanying notes are an integral part of these consolidated financial statements.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 1—Nature of Operations and Organization

NGL Energy Partners LP ("we," "us," "our," or the "Partnership") is a Delaware limited partnership formed in September 2010 by several investors ("IEP Parties"). NGL Energy Holdings LLC serves as our general partner. At March 31, 2014, our operations 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.

Initial Public Offering

On May 17, 2011, we completed our initial public offering ("IPO"). We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. Our proceeds from the sale of 3,850,000 common units of $71.9 million, net of total offering costs of $9.0 million, were used to repay advances under our acquisition credit facility and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) from the underwriters' exercise of their option to purchase additional common units from us were used to redeem 175,000 of the common units outstanding prior to our IPO. Upon the completion of our IPO and the underwriters' exercise in full of their option to purchase additional common units from us and the redemption, we had outstanding 8,864,222 common units,

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 1—Nature of Operations and Organization (Continued)

5,919,346 subordinated units, a 0.1% general partner interest, and incentive distribution rights ("IDRs").

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, 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., whereby we acquired retail propane operations, primarily in the western United States.
•: In February 2012, we completed a business combination with North American Propane, Inc., whereby we acquired retail propane and distillate operations in the northeastern United States.
•: 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 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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 1—Nature of Operations and Organization (Continued)

that may be developed in the future. During March 2014, we purchased one additional facility under this agreement.

•: In August 2013, we completed a business combination whereby we acquired seven entities affiliated with Oilfield Water Lines LP (collectively, "OWL"). The businesses of OWL include 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.

Note 2—Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). The accompanying consolidated financial statements include the accounts of the Partnership and its controlled subsidiaries. All significant intercompany transactions and account balances have been eliminated in consolidation.

We have made certain reclassifications to the prior period financial statements to conform with classification methods used in fiscal 2014. These reclassifications had no impact on previously-reported amounts of equity or net income. In addition, certain balances at March 31, 2013 were adjusted to reflect the final acquisition accounting for certain business combinations.

Use of Estimates

The preparation of consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the consolidated financial statements and the reported amount of revenues and expenses during the period.

Critical estimates we make in the preparation of our consolidated financial statements include determining the fair value of assets and liabilities acquired in business combinations; the collectability of accounts receivable; the recoverability of inventories; useful lives and recoverability of property, plant and equipment and amortizable intangible assets; the impairment of goodwill; the fair value of derivative financial investments; and accruals for various commitments and contingencies, among others. Although we believe these estimates are reasonable, actual results could differ from those estimates.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

Fair Value Measurements

We apply fair value measurements to certain assets and liabilities, principally our commodity derivative instruments and assets and liabilities acquired in business combinations. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value is based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of our own nonperformance risk on our liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or, in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid). We evaluate the need for credit adjustments to our derivative instrument fair values in accordance with the requirements noted above. Such adjustments were not material to the fair values of our derivative instruments.

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

•: Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.
•: Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts and interest rate protection agreements. The majority of our fair value measurements related to our derivative financial instruments were categorized as Level 2 at March 31, 2014 and 2013 (see Note 12). We determine the fair value of all our derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing model include publicly available prices and forward curves generated from a compilation of data gathered from third parties.
•: Level 3—Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any fair value measurements categorized as Level 3 at March 31, 2014 or 2013.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs used to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement requires judgment, considering factors specific to the asset or liability.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

Derivative Financial Instruments

We record our derivative financial instrument contracts at fair value in the consolidated balance sheets, with changes in the fair value of our commodity derivative instruments included in our consolidated statements of operations in cost of sales. Contracts that qualify for the normal purchase or sale exemption and are designated as such are not accounted for as derivatives at market value and, accordingly, are recorded when the delivery occurs.

We have not designated any financial instruments as hedges for accounting purposes. All mark-to-market gains and losses on commodity derivative instruments that do not qualify as normal purchases or sales, whether cash transactions or non-cash mark-to-market adjustments, are reported within cost of sales in the consolidated statements of operations, regardless of whether the contract is physically or financially settled.

We utilize various commodity derivative financial instrument contracts to help reduce our exposure to variability in future commodity prices. We do not enter such contracts for trading purposes. Changes in assets and liabilities from commodity derivative financial instruments result primarily from changes in market prices, newly originated transactions, and the timing of the settlements. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on our assessment of anticipated market movements. Inherent in the resulting contractual portfolio are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from non-performance by suppliers, customers, or financial counterparties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures that we review on an ongoing basis. We monitor market risk through a variety of techniques and attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures.

Revenue Recognition

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

Cost of Sales

We include in cost of sales all costs we incur to acquire products, including the costs of purchasing, terminaling, and transporting inventory prior to delivery to our customers. Cost of sales does not include any depreciation of our property, plant and equipment. Cost of sales does include amortization of certain contract-based intangible assets of $6.2 million, $5.3 million, and $0.8 million during the years ended March 31, 2014, 2013, and 2012, respectively.

Depreciation and Amortization

Depreciation and amortization in the consolidated statements of operations includes all depreciation of our property, plant and equipment and amortization of intangible assets other than debt issuance costs, for which the amortization is recorded to interest expense, and certain contract-based intangible assets, for which the amortization is recorded to cost of sales.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase. At times, certain account balances may exceed federally insured limits.

Supplemental cash flow information is as follows:

	Year Ended March 31,

	2014		2013		2012
	(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees	$	31,827	$	27,384	$	4,966




Income taxes paid	$	1,639	$	1,027	$	430

Cash flows from commodity derivative instruments are classified as cash flows from investing activities in the consolidated statements of cash flows.

Accounts Receivable and Concentration of Credit Risk

We operate in the United States and Canada. We grant unsecured credit to customers under normal industry standards and terms, and have established policies and procedures that allow for an evaluation of each customer's creditworthiness as well as general economic conditions. The allowance for doubtful accounts is based on our assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. Accounts receivable are considered past due or delinquent based on contractual terms. We write off accounts receivable against the allowance for doubtful accounts when collection efforts have been exhausted.

We execute netting agreements with certain customers to mitigate our credit risk. Receivables and payables are reflected at a net balance to the extent a netting agreement is in place and we intend to settle on a net basis.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

Our accounts receivable consist of the following:

	March 31, 2014				March 31, 2013

Segment	Gross Receivable		Allowance for Doubtful Accounts		Gross Receivable (Note 2)		Allowance for Doubtful Accounts
	(in thousands)
Crude oil logistics	$	411,090	$	105	$	360,589	$	11
Water solutions		25,700		405		9,618		29
Liquids		192,529		617		144,267		76
Retail propane		75,606		1,667		49,233		1,644
Refined products		105,670		—		—		—
Renewables		54,466		—		—		—
Other		38,665		28		810		—


	$	903,726	$	2,822	$	564,517	$	1,760

Changes in the allowance for doubtful accounts are as follows:

	Year Ended March 31,

	2014			2013			2012
	(in thousands)
Allowance for doubtful accounts, beginning of period	$	1,760		$	818		$	161
Provision for doubtful accounts		2,172			1,315			1,049
Write off of uncollectible accounts		(1,110	)		(373	)		(392	)


Allowance for doubtful accounts, end of period	$	2,822		$	1,760		$	818

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. For the year ended March 31, 2013, sales of crude oil and natural gas liquids to our largest customer represented 10% of our consolidated total revenues. At March 31, 2013, one customer of our crude oil logistics segment represented 10% of our consolidated accounts receivable balance.

Inventories

We value our inventory at the lower of cost or market, with cost determined using either the weighted average cost or the first in, first out (FIFO) methods, including the cost of transportation. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business for sale in the retail markets.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

Inventories consist of the following:

	March 31,

	2014		2013
	(in thousands)
Crude oil	$	156,473	$	46,156
Natural gas liquids—
Propane		85,159		45,428
Butane and other		19,051		24,090
Refined products		23,209		—
Renewables		11,778		—
Other		14,490		11,221


	$	310,160	$	126,895

Investments in Unconsolidated Entities

As part of the December 2013 acquisition of Gavilon Energy, we acquired a 50% interest in Glass Mountain and an 11% interest in a limited liability company that owns an ethanol production facility. We account for these investments under the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our consolidated balance sheet; instead, our ownership interests are reported within "Investments in Unconsolidated Entities" on our consolidated balance sheet. We record our share of any income or loss generated by these entities as an increase to our equity method investments, and record any distributions we receive from these entities as reductions to our equity method investments.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following:

	March 31,

	2014		2013 (Note 4)
	(in thousands)
Accrued compensation and benefits	$	45,006	$	27,252
Derivative liabilities		42,214		12,701
Income and other tax liabilities		13,421		22,659
Product exchange liabilities		3,719		6,741
Other		37,330		16,253


	$	141,690	$	85,606

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

Property, Plant and Equipment

We record property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. As we dispose of assets, we remove the cost and related accumulated depreciation from the accounts, and any resulting gain or loss is included in other income. We compute depreciation expense using the straight-line method over the estimated useful lives of the assets (see Note 5).

We evaluate the carrying value of our property, plant and equipment for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group.

Intangible Assets

Our intangible assets include contracts and arrangements acquired in business combinations, including lease agreements, customer relationships, covenants not to compete, and trade names. In addition, we capitalize certain debt issuance costs incurred in our long-term debt arrangements. We amortize our intangible assets on a straight-line basis over the assets' estimated useful lives (see Note 7). We amortize debt issuance costs over the terms of the related debt on a method that approximates the effective interest method.

We evaluate the carrying value of our amortizable intangible assets for potential impairment when events and circumstances warrant such a review. A long-lived asset group is considered impaired when the anticipated undiscounted future cash flows from the use and eventual disposition of the asset group is lower than its carrying value. In that event, we recognize a loss equal to the amount by which the carrying value exceeds the fair value of the asset group. When we cease to use an acquired trade name, we test the trade name for impairment using the "relief from royalty" method and we begin amortizing the trade name over its estimated useful life as a defensive asset.

Goodwill

Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Business combinations are accounted for using the "acquisition method" (see Note 4). We expect that substantially all of our goodwill at March 31, 2014 is deductible for income tax purposes.

Goodwill and intangible assets determined to have an indefinite useful life are not amortized, but instead are evaluated for impairment periodically. We evaluate goodwill and indefinite-lived intangible assets for impairment annually, or more often if events or circumstances indicate that the assets might be impaired. We perform the annual evaluation at January 1 of each year.

To perform this assessment, we consider qualitative factors to determine whether it is more likely than not that the fair value of each reporting unit exceeds its carrying amount. If we conclude that it is

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

more likely than not that the fair value of a reporting unit exceeds its carrying amount, we perform the following two-step goodwill impairment test:

•: In the first step of the goodwill impairment test, we compare the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amount of a reporting unit exceeds its fair value, we perform the second step of the goodwill impairment test to measure the amount of impairment loss, if any.
•: In the second step of the goodwill impairment test, we compare the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess.

Estimates and assumptions used to perform the impairment evaluation are inherently uncertain and can significantly affect the outcome of the analysis. The estimates and assumptions we used in the annual assessment for impairment of goodwill included market participant considerations and future forecasted operating results. Changes in operating results and other assumptions could materially affect these estimates. Based on our assessment of qualitative factors, we determined that the two-step impairment test was not required. Accordingly, we did not record any goodwill impairments during the years ended March 31, 2014, 2013, and 2012.

Product Exchanges

Quantities of products receivable or returnable under exchange agreements are reported within prepaid expenses and other current assets or within accrued expenses and other payables on the consolidated balance sheets. We estimate the value of product exchange assets and liabilities based on the weighted-average cost basis of the inventory we have delivered or will deliver on the exchange, plus or minus location differentials.

Advance Payments Received from Customers

We record customer advances on product purchases as a liability on the consolidated balance sheets.

Noncontrolling Interests

Water Facility Development Agreement

In connection with one of our business combinations, we entered into a development agreement whereby we may acquire additional water disposal facilities in Texas. Under this agreement, the other party (the "Developer") may develop facilities in a designated area. We then have the option to operate the facility for a period of up to 90 days, during which time we may elect to purchase the

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 2—Significant Accounting Policies (Continued)

facility. If we elect to purchase the facility, the Developer may choose one of two options specified in the agreement for the calculation of the purchase price.

During the period between which we have begun operating the facility and we have decided whether to purchase the facility, we are entitled to a fee for operating the facility, which is forfeitable if we elect not to purchase the facility. We recognize revenue for these operator fees once they cease to be forfeitable. When we elect to purchase a facility, we account for the transaction as a business combination.

Business Combination Measurement Period

We record the assets acquired and liabilities assumed in a business combination at their acquisition date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time to obtain the information necessary to identify and measure the value of the assets acquired and liabilities assumed in a business combination. As described in Note 4, certain of our acquisitions during the year ended March 31, 2014 are still within this measurement period, and as a result, the acquisition-date fair values we have recorded for the acquired assets and assumed liabilities are subject to change.

Also as described in Note 4, we made certain adjustments during the year ended March 31, 2014 to our estimates of the acquisition date fair values of assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2013. We retrospectively adjusted the March 31, 2013 consolidated balance sheet for these adjustments. Due to the immateriality of these adjustments, we did not retrospectively adjust the consolidated statement of operations for the year ended March 31, 2013 for these measurement period adjustments.

Discontinued Operations

As described in Note 14, during the year ended March 31, 2014, we sold our compressor leasing business and wound down our natural gas marketing business. These actions do not represent a strategic shift that had a major effect on our operations, and do not meet the criteria under the new accounting standard for these businesses to be reported as discontinued operations.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 3—Earnings per Unit

Our earnings per common and subordinated unit were computed as follows:

	Year Ended March 31,

	2014			2013			2012
	(in thousands, except unit and per unit amounts)
Income attributable to parent equity	$	47,655		$	47,940		$	7,876
Income allocated to general partner(1)		(14,148	)		(2,917	)		(8	)


Income attributable to limited partners	$	33,507		$	45,023		$	7,868




Income allocated to:
Common unitholders	$	31,614		$	39,517		$	4,859




Subordinated unitholders	$	1,893		$	5,506		$	3,009




Weighted average common units outstanding		61,970,471			41,353,574			15,169,983




Weighted average subordinated units outstanding		5,919,346			5,919,346			5,175,384




Income per common unit—basic and diluted	$	0.51		$	0.96		$	0.32




Income per subordinated unit—basic and diluted	$	0.32		$	0.93		$	0.58

(1): The income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights ("IDRs"), which are described in Note 11.

The restricted units described in Note 11 were antidilutive for the years ended March 31, 2014, 2013, and 2012.

Note 4—Acquisitions

Year Ended March 31, 2014

Gavilon Energy

On December 2, 2013, we completed a business combination in which we acquired Gavilon Energy. We paid $832.4 million of cash, net of cash acquired, in exchange for these assets and operations. The acquisition agreement also contemplates a post-closing adjustment to the purchase price for certain working capital items. We incurred and charged to general and administrative expense $5.3 million of costs during the year ended March 31, 2014 related to the acquisition of Gavilon Energy.

The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana and a 50% interest in 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

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in the acquisition of Gavilon Energy. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending September 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):


Accounts receivable—trade	$	349,529
Accounts receivable—affiliates		2,564
Inventories		107,430
Prepaid expenses and other current assets		68,322
Property, plant and equipment:
Crude oil tanks and related equipment (3 - 40 years)		77,429
Vehicles (3 years)		791
Information technology equipment (3 - 7 years)		4,046
Buildings and leasehold improvements (3 - 40 years)		7,716
Land		6,427
Linefill and tank bottoms		15,230
Other (7 years)		170
Construction in process		7,190
Goodwill		359,169
Intangible assets:
Customer relationships (10 - 20 years)		101,600
Lease agreements (1 - 5 years)		8,700
Investments in unconsolidated entities		178,000
Other noncurrent assets		9,918
Accounts payable—trade		(342,792	)
Accounts payable—affiliates		(2,585	)
Accrued expenses and other payables		(70,999	)
Advance payments received from customers		(10,667	)
Other noncurrent liabilities		(44,740	)


Fair value of net assets acquired	$	832,448

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership, the opportunity to use the acquired business as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

Our preliminary estimate of the fair value of investments in unconsolidated subsidiaries exceeds our share of the historical net book value of these subsidiaries' net assets by approximately $70 million. This difference relates primarily to goodwill and customer relationships.

The acquisition method of accounting requires that executory contracts that are at unfavorable terms relative to current market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain crude oil storage lease commitments were at unfavorable terms relative to current market conditions, we recorded a liability of $12.9 million related to these lease commitments in the acquisition accounting, and we amortized $2.9 million of this balance through cost of sales during the period from the acquisition date through March 31, 2014. We will amortize the remainder of this liability over the term of the leases. The future amortization of this liability is shown below (in thousands):

Year Ending March 31,

2015	$	6,500
2016		3,260
2017		300

As described in Note 14, on March 31, 2014, we assigned all of the storage and transportation contracts of the natural gas marketing business to a third party. Since these contracts were at unfavorable terms relative to current market conditions, we paid $44.8 million to assign these contracts. We recorded a liability of $50.8 million related to these storage and transportation contracts in the acquisition accounting, and we amortized $6.0 million of this balance through cost of sales during the period from the acquisition date through the date we assigned the contracts.

We recorded $3.2 million of employee severance expense during the year ended March 31, 2014 as a result of personnel changes subsequent to the acquisition of Gavilon Energy. In addition, certain personnel who were employees of Gavilon Energy are entitled to a bonus, half of which was payable upon successful completion of the business combination and the remainder of which is payable in December 2014. We are recording this as compensation expense over the vesting period. We recorded expense of $5.0 million during the year ended March 31, 2014 related to these bonuses, and we expect to record an additional expense of $6.6 million during the year ending March 31, 2015.

�� The operations of Gavilon Energy have been included in our consolidated statement of operations since Gavilon Energy was acquired on December 2, 2013. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $2.9 billion and operating income of $11.0 million that were generated by the operations of Gavilon Energy.

Oilfield Water Lines, LP

On August 2, 2013, we completed a business combination with entities affiliated with OWL, whereby we acquired water disposal and transportation assets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL. The acquisition agreements included a provision whereby the purchase price could have been increased if certain performance targets were achieved in the six months following the acquisition. These performance targets were not achieved, and therefore no increase to the purchase price was

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

warranted. The acquisition agreements also contemplate a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense $0.8 million of costs related to the OWL acquisition during the year ended March 31, 2014.

We have completed the process of identifying and determining the fair value of the long-lived assets acquired in the acquisition of OWL. We have not yet finalized any post-closing payment for certain working capital items, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):


Accounts receivable—trade	$	7,268
Inventories		154
Prepaid expenses and other current assets		402
Property, plant and equipment:
Land		710
Water treatment facilities and equipment (3 - 30 years)		23,173
Vehicles (5 - 10 years)		8,157
Buildings and leasehold improvements (7 - 30 years)		2,198
Other (3 - 5 years)		53
Intangible assets:
Customer relationships (10 years)		110,000
Non-compete agreements (2.5 years)		2,000
Goodwill		89,699
Accounts payable—trade		(6,469	)
Accrued expenses and other payables		(992	)
Other noncurrent liabilities		(64	)


Fair value of net assets acquired	$	236,289

Consideration paid consists of the following (in thousands):


Cash paid, net of cash acquired	$	167,732
Value of common units issued		68,557


Total consideration paid	$	236,289

The customer relationships were valued using a variation of the income approach known as the excess earnings method. This methodology consists of deriving relevant cash flows to the underlying asset, and then deducting appropriate returns for other assets contributing to the generation of the relevant cash flows. This valuation methodology requires estimates of customer retention, which were based on our understanding of the level of competition in the region in which the assets operate. Our estimates of customer retention are also relevant to the determination of the estimated useful lives of the assets.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

The operations of OWL have been included in our consolidated statement of operations since OWL was acquired on August 2, 2013. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $26.2 million and operating income of $0.9 million that was generated by the operations of OWL.

Other Water Solutions Acquisitions

During the year ended March 31, 2014, we completed four separate acquisitions of businesses to expand our water solutions operations in Texas. On a combined basis, we issued 222,381 common units, valued at $6.8 million, and paid $178.9 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. Our consolidated statement of operations for the year ended March 31, 2014 includes revenues of $20.6 million and operating income of $7.1 million that was generated by the operations of these acquisitions. We incurred and charged to general and administrative expense $0.4 million of costs related to these acquisitions during the year ended March 31, 2014.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these four business combinations. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending September 30, 2014. We have

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):


Accounts receivable—trade	$	2,391
Inventories		390
Prepaid expenses and other current assets		61
Property, plant and equipment:
Land		419
Vehicles (5 - 10 years)		90
Water treatment facilities and equipment (3 - 30 years)		24,933
Buildings and leasehold improvements (7 - 30 years)		3,036
Other (3 - 5 years)		13
Intangible assets:
Customer relationships (8 - 10 years)		72,000
Trade names (indefinite life)		3,325
Non-compete agreements (3 years)		260
Water facility development agreement (5 years)		14,000
Water facility option agreement		2,500
Goodwill		63,031
Accounts payable—trade		(382	)
Accrued expenses and other payables		(300	)
Other noncurrent liabilities		(114	)


Fair value of net assets acquired	$	185,653

Consideration paid consists of the following (in thousands):


Cash paid, net of cash acquired	$	178,867
Value of common units issued		6,786


Total consideration paid	$	185,653

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

As part of one of these business combinations, we entered into an option agreement with the seller of the business whereby we had the option to purchase a salt water disposal facility that was under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this option agreement. On March 1, 2014, we purchased the saltwater disposal facility for additional cash consideration of $3.7 million. The assets associated with this facility are included in the data in the table above.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

As part of one of these business combinations, we entered into a development agreement that provides us a first right of refusal to purchase disposal facilities that may be developed by the seller within a defined area in the Eagle Ford Basin through June 2018. On March 1, 2014, we purchased our first disposal facility pursuant to the development agreement for $21.0 million. The assets associated with this facility are included in the data in the table above. In addition, we have exercised our option to operate, for evaluation purposes, three additional disposal facilities developed by the seller. Pending the results of our evaluation, we have the right to purchase any or all of these facilities within the 90-day evaluation period.

Crude Oil Logistics Acquisitions

During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our crude oil logistics business in Texas and Oklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. The agreement for the acquisition of one of these businesses contemplates a post-closing payment for certain working capital items. We incurred and charged to general and administrative expense during the year ended March 31, 2014 $0.1 million of costs related to these acquisitions.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these two business combinations. The estimates of fair value reflected at March 31, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2014. We have preliminarily estimated the fair value of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):


Accounts receivable—trade	$	1,235
Inventories		1,021
Prepaid expenses and other current assets		54
Property, plant and equipment:
Vehicles (5 - 10 years)		2,977
Buildings and leasehold improvements (5 - 30 years)		280
Crude oil tanks and related equipment (2 - 30 years)		3,462
Barges and towboats (20 years)		20,065
Other (3 - 5 years)		53
Intangible assets:
Customer relationships (3 years)		6,300
Non-compete agreements (3 years)		35
Trade names (indefinite life)		530
Goodwill		37,867
Accounts payable—trade		(665	)
Accrued expenses and other payables		(124	)


Fair value of net assets acquired	$	73,090

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

Consideration paid consists of the following (in thousands):


Cash paid, net of cash acquired	$	67,842
Value of common units issued		5,248


Total consideration paid	$	73,090

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Retail Propane and Liquids Acquisitions

During the year ended March 31, 2014, we completed four acquisitions of retail propane businesses and the acquisition of four natural gas liquids terminals. On a combined basis, we paid $21.9 million of cash to acquire these assets and operations. The agreements for certain of these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in certain of these business combinations, and as a result the estimates of fair value reflected at March 31, 2014 are subject to change.

Year Ended March 31, 2013

High Sierra Combination

On June 19, 2012, we completed a business combination with High Sierra, whereby we acquired all of the ownership interests in High Sierra. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. These common units were valued at $406.8 million using the closing price of our common units on the New York Stock Exchange (the "NYSE") on the merger date. We also paid $97.4 million of High Sierra Energy, LP's long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner. We recorded the value of the 2,685,042 common units issued to our general partner at $8.0 million, which represents an estimate, in accordance with GAAP, of the fair value of the equity issued by our general partner to the former owners of High Sierra's general partner. In accordance with the GAAP fair value model, this fair value was estimated based on assumptions of future distributions and a discount rate that a hypothetical buyer might use. Under this model, the potential for distribution growth resulting from the prospect of future acquisitions and capital expansion projects would not be considered in the fair value calculation. The difference between the estimated fair value of the general partner interests issued by our general partner of $8.0 million, calculated as described above, and the fair value of the common units issued to our general partner of $60.6 million, as calculated using the closing price of the common units on the NYSE, is reported as a reduction to equity. We incurred and charged to general and

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

administrative expense during the years ended March 31, 2013 $3.7 million of costs related to the High Sierra transaction. We also incurred or accrued costs of $0.6 million related to the equity issuance that we charged to equity.

The fair values of the assets acquired and liabilities assumed in our acquisition of High Sierra are summarized below (in thousands):


Accounts receivable—trade	$	395,311
Accounts receivable—affiliates		7,724
Inventories		43,575
Derivative assets		10,646
Forward purchase and sale contracts		34,717
Prepaid expenses and other current assets		11,131
Property, plant and equipment:
Land		5,723
Vehicles (5 - 10 years)		22,507
Water treatment facilities and equipment (3 - 30 years)		64,057
Crude oil tanks and related equipment (2 - 15 years)		17,851
Buildings and leasehold improvements (5 - 30 years)		19,145
Information technology equipment (3 years)		5,541
Other (2 - 30 years)		11,010
Construction in progress		9,621
Intangible assets:
Customer relationships (5 - 17 years)		245,000
Lease contracts (1 - 10 years)		12,400
Trade names (indefinite)		13,000
Goodwill		220,884
Accounts payable—trade		(417,369	)
Accounts payable—affiliates		(9,014	)
Advance payments received from customers		(1,237	)
Accrued expenses and other payables		(35,611	)
Derivative liabilities		(5,726	)
Forward purchase and sale contracts		(18,680	)
Long-term debt		(2,537	)
Other noncurrent liabilities		(3,224	)
Noncontrolling interest in consolidated subsidiary		(2,400	)


Consideration paid, net of cash acquired	$	654,045

Consideration paid consists of the following (in thousands):


Cash paid, net of cash acquired	$	239,251
Value of common units issued, net of issurance costs		414,794


Total consideration paid	$	654,045

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts.

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Pecos Combination

On November 1, 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 marketing and logistics operations in Texas and New Mexico. We paid $132.4 million of cash (net of cash acquired) and assumed certain obligations with a value of $10.2 million under certain equipment financing facilities. Also on November 1, 2012, we entered into a call agreement with the former owners of Pecos pursuant to which the former owners of Pecos agreed to purchase a minimum of $45.0 million or a maximum of $60.0 million of common units from us. On November 12, 2012, the former owners purchased 1,834,414 common units from us for $45.0 million pursuant to this call agreement. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.6 million of costs related to the Pecos combination.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Pecos:

	Final			Estimated at March 31, 2013			Change

	(in thousands)
Accounts receivable—trade	$	73,609		$	73,704		$	(95	)
Inventories		1,903			1,903			—
Prepaid expenses and other current assets		1,426			1,426			—
Property, plant and equipment:
Vehicles (5 - 10 years)		22,097			19,193			2,904
Buildings and leasehold improvements (5 - 30 years)		1,339			1,248			91
Crude oil tanks and related equipment (2 - 15 years)		1,099			913			186
Land		223			224			(1	)
Other (3 - 5 years)		36			177			(141	)
Intangible assets:
Customer relationships		—			8,000			(8,000	)
Trade names (indefinite life)		900			1,000			(100	)
Goodwill		91,747			86,661			5,086
Accounts payable—trade		(50,795	)		(50,808	)		13
Accrued expenses and other payables		(963	)		(1,020	)		57
Long-term debt		(10,234	)		(10,234	)		—


Fair value of net assets acquired	$	132,387		$	132,387		$	—

Consideration paid consists of the following (in thousands):


Cash paid, net of cash acquired	$	87,444
Value of common units issued		44,943


Total consideration paid	$	132,387

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

Third Coast Combination

On December 31, 2012, we completed a business combination transaction whereby we acquired all of the membership interests in Third Coast Towing, LLC ("Third Coast") for $43.0 million in cash. The business of Third Coast consists primarily of transporting crude oil via barge. Also on December 31, 2012, we entered into a call agreement with the former owners of Third Coast pursuant to which the former owners of Third Coast agreed to purchase a minimum of $8.0 million or a maximum of

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

$10.0 million of common units from us. On January 11, 2013, the former owners of Third Coast purchased 344,680 common units from us for $8.0 million pursuant to this agreement.

During the year ended March 31, 2014, we completed the acquisition accounting for this business combination. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of Third Coast:

	Final			Estimated at March 31, 2013			Change

	(in thousands)
Accounts receivable—trade	$	2,195		$	2,248		$	(53	)
Inventories		140			140			—
Property, plant and equipment:
Barges and towboats (20 years)		17,711			12,883			4,828
Other		—			30			(30	)
Intangible assets:
Customer relationships (3 years)		3,000			4,000			(1,000	)
Trade names (indefinite life)		850			500			350
Goodwill		18,847			22,551			(3,704	)
Other noncurrent assets		2,733			2,733			—
Accounts payable—trade		(2,429	)		(2,048	)		(381	)
Accrued expenses and other payables		(164	)		(154	)		(10	)


Fair value of net assets acquired	$	42,883		$	42,883		$	—

Consideration paid consists of the following (in thousands):


Cash paid, net of cash acquired	$	35,000
Value of common units issued		7,883


Total consideration paid	$	42,883

Other Crude Oil Logistics and Water Solutions Business Combinations

During the year ended March 31, 2013, we completed four separate acquisitions to expand the assets and operations of our crude oil logistics and water solutions businesses. On a combined basis, we paid $52.6 million in cash and assumed $1.3 million of long-term debt in the form of non-compete agreements. We also issued 516,978 common units, valued at $12.4 million, as partial consideration for one of these acquisitions. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.3 million of costs related to these acquisitions.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

During the year ended March 31, 2014, we completed the acquisition accounting for these business combinations. The following table presents the final calculation of the fair value of the assets acquired (and useful lives) and liabilities assumed in the acquisition of these businesses:

	Final			Estimated at March 31, 2013			Change

	(in thousands)
Accounts receivable—trade	$	2,676		$	2,660		$	16
Inventories		191			191			—
Prepaid expenses and other current assets		737			738			(1	)
Property, plant and equipment:
Land		218			191			27
Vehicles (5 - 10 years)		853			771			82
Water treatment facilities and equipment (3 - 30 years)		13,665			13,322			343
Buildings and leasehold improvements (5 - 30 years)		895			2,233			(1,338	)
Crude oil tanks and related equipment (2 - 15 years)		4,510			1,781			2,729
Other (3 - 5 years)		27			2			25
Construction in progress		490			693			(203	)
Intangible assets:
Customer relationships (5 - 10 years)		13,125			6,800			6,325
Non-compete agreements (3 years)		164			510			(346	)
Trade names (indefinite life)		2,100			500			1,600
Goodwill		34,451			43,822			(9,371	)
Accounts payable—trade		(3,374	)		(3,374	)		—
Accrued expenses and other payables		(1,914	)		(2,026	)		112
Notes payable		(1,340	)		(1,340	)		—
Other noncurrent liabilities		(156	)		(156	)		—
Noncontrolling interest		(2,333	)		(2,333	)		—


Fair value of net assets acquired	$	64,985		$	64,985		$	—

Consideration paid consists of the following (in thousands):


Cash paid, net of cash acquired	$	52,552
Value of common units issued		12,433


Total consideration paid	$	64,985

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

Retail Propane Combinations During the Year Ended March 31, 2013

During the year ended March 31, 2013, we entered into six separate business combination agreements to acquire retail propane and distillate operations, primarily in the northeastern and southeastern United States. On a combined basis, we paid cash of $71.4 million and issued 850,676 common units, valued at $18.9 million, in exchange for these assets. We also assumed $6.6 million of long-term debt in the form of non-compete agreements. We incurred and charged to general and administrative expense during the year ended March 31, 2013 $0.3 million related to these acquisitions. The fair values of the assets acquired and liabilities assumed in these six combinations are as follows (in thousands):


Accounts receivable—trade	$	8,715
Inventory		5,155
Other current assets		1,228
Property, plant and equipment:
Land		1,945
Retail propane equipment (5 - 20 years)		28,763
Vehicles (5 years)		11,344
Buildings and leasehold improvements (30 years)		7,052
Other		1,201
Intangible assets:
Customer relationships (10 - 15 years)		16,890
Trade names (indefinite)		2,924
Non-compete agreements (5 years)		1,387
Goodwill		21,983
Other non-current assets		784
Long-term debt, including current portion		(6,594	)
Other assumed liabilities		(12,511	)


Fair value of net assets acquired	$	90,266

Consideration paid consists of the following (in thousands):


Cash consideration paid	$	71,392
Value of common units issued		18,874


Total consideration	$	90,266

Goodwill represents the excess of the estimated consideration paid for the acquired businesses over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired entities and the Partnership, the opportunity to use the acquired businesses as a platform for growth, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

single present amount (discounted). The measurement is based on the value indicated by current market expectations about those future amounts. We estimated the useful life of the customer relationships by reference to historical customer retention data.

Pro Forma Results of Operations (Unaudited)

As described above, we completed a number of acquisitions during the years ended March 31, 2014 and 2013. The operations of each acquired business have been included in our consolidated results of operations since the date of acquisition of the business. The unaudited pro forma consolidated data presented below has been prepared as if the following acquisitions had been completed on April 1, 2012:

•: High Sierra;
•: Pecos;
•: Third Coast;
•: OWL; and
•: Gavilon Energy.

The unaudited pro forma consolidated data presented below has also been prepared as if the following transactions, which are described in Notes 8 and 11 to these consolidated financial statements, had been completed on April 1, 2012:

•: Our sale of common units in December 2013 in a private placement;
•: The amendment of our Credit Agreement in November 2013;
•: Our issuance of senior unsecured notes in October 2013;
•: Our sale of common units in September 2013 in a public offering;
•: The sale of common units in a public offering in July 2013;
•: Our entry into the Credit Agreement in June 2012; and
•: Our issuance of senior notes in June 2012.

	Year Ended March 31,

	2014			2013
	(in thousands, except per unit amounts)
Revenues	$	9,800,398		$	5,697,988
Net income (loss)		798			(72,171	)
Net loss attributable to limited partners		(14,446	)		(75,251	)
Basic and diluted loss per common unit		(0.18	)		(0.95	)
Basic and diluted loss per subordinated unit		(0.18	)		(0.95	)

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

The pro forma consolidated data in the table above was prepared by adding historical results of operations of acquired businesses to our historical results of operations and making certain pro forma adjustments. The pro forma information is not necessarily indicative of the results of operations that would have occurred if the transactions had occurred on April 1, 2012, nor is it necessarily indicative of future results of operations.

Gavilon Energy historically conducted trading operations, whereas we operate as a logistics business. Gavilon Energy's historical results of operations were subject to more volatility as a result of its trading operations than we would expect future results of operations to have under our business model. In the pro forma data in the table above, no pro forma effect was given to the change in business model from a trading business to a logistics business. Gavilon Energy historically recorded revenues net of product costs. In the pro forma table above, no pro forma effect was given to the fact that this accounting policy is different than our accounting policy.

The pro forma net loss for the year ended March 31, 2013 in the table above includes $4.8 million of expense related to the retirement of a liability associated with a business combination that OWL completed prior to our acquisition of OWL. This non-recurring expense is not excluded from the pro forma net loss, as it does not directly result from our acquisition of OWL.

The pro forma net loss for the year ended March 31, 2014 shown in the table above reflects depreciation and amortization expense estimates which are preliminary, as our identification of the assets and liabilities acquired, and the fair value determinations thereof, for the business combination with Gavilon Energy have not been completed.

The pro forma losses per unit have been computed based on earnings or losses allocated to the limited partners after deducting the total earnings allocated to the general partner. To calculate earnings attributable to the general partner, we have used historical distribution amounts. For purposes of this calculation, we have assumed that the common units outstanding at March 31, 2014 were outstanding during the full years presented above.

Year Ended March 31, 2012

Osterman

On October 3, 2011, we completed a business combination transaction with Osterman, whereby we acquired retail propane operations in the northeastern United States. We issued 4,000,000 common units and paid $94.9 million of cash, net of cash acquired, in exchange for the assets and operations of Osterman. The agreement also contemplated a post-closing payment of $4.8 million for certain specified working capital items, which was paid in November 2012. We valued the 4 million limited partner common units at $81.9 million based on the closing price of our common units on the closing date ($20.47 per unit). We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.8 million of costs incurred in connection with the Osterman transaction. We also incurred costs related to the equity issuance of $0.1 million that we charged to equity. The

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

following table presents the final allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):


Accounts receivable—trade	$	9,350
Inventories		3,869
Prepaid expenses and other current assets		215
Property, plant and equipment:
Land		2,349
Retail propane equipment (15 - 20 years)		47,160
Vehicles (5 - 20 years)		7,699
Buildings and leasehold improvements (30 years)		3,829
Other (3 - 5 years)		732
Intangible assets:
Customer relationships (20 years)		54,500
Trade names (indefinite life)		8,500
Non-compete agreements (7 years)		700
Goodwill		52,267
Assumed liabilities		(9,654	)


Consideration paid, net of cash acquired	$	181,516

Consideration paid consists of the following (in thousands):


Cash paid at closing, net of cash acquired	$	94,873
Fair value of common units issued at closing		81,880
Working capital payment (paid in November 2012)		4,763


Consideration paid, net of cash acquired	$	181,516

SemStream

On November 1, 2011, we completed a business combination with SemStream. We entered into this business combination in order to expand our liquids segment. SemStream contributed substantially all of its natural gas liquids business and assets to us in exchange for 8,932,031 of our limited partner

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Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

common units and a cash payment of $91.0 million. We have valued the 8.9 million limited partner common units at $184.8 million, based on the closing price of our common units on the closing date ($21.07) reduced by the expected present value of distributions for certain units which were not eligible for full distributions until the quarter ending September 30, 2012. In addition, in exchange for a cash contribution, SemStream acquired a 7.5% interest in our general partner. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.7 million of costs related to the SemStream transaction. We also incurred costs of less than $0.1 million related to the equity issuance that we charged to equity.

The acquired assets included 12 natural gas liquids terminals in Arizona, Arkansas, Indiana, Minnesota, Missouri, Montana, Washington and Wisconsin, 12 million gallons of aboveground propane storage, 3.7 million barrels of underground leased storage for natural gas liquids and a rail fleet of 350 leased and 12 owned cars.

We have included the results of SemStream's operations in our consolidated financial statements beginning November 1, 2011. The operations of SemStream are reflected in our liquids segment.

The following table presents the fair values of the assets acquired and liabilities assumed in the SemStream combination (in thousands):


Inventories	$	104,226
Derivative assets		3,578
Assets held for sale		3,000
Prepaid expenses and other current assets		9,833
Property, plant and equipment:
Land		3,470
Natural gas liquids terminal assets (20 - 30 years)		41,434
Vehicles and railcars (5 years)		470
Other (5 years)		3,326
Investment in capital lease		3,112
Intangible assets:
Customer relationships (8 - 15 years)		31,950
Lease contracts (1 - 4 years)		1,008
Goodwill		74,924
Assumed current liabilities		(4,591	)


Consideration paid	$	275,740

Goodwill represents the excess of the estimated consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities. Goodwill primarily represents the value of synergies between the acquired operations and the Partnership, the opportunity to use the acquired businesses as a platform to expand our wholesale marketing operations, and the acquired assembled workforce. We estimate that all of the goodwill will be deductible for federal income tax purposes.

We estimated the value of the customer relationship intangible asset using the income approach, which uses valuation techniques to convert future amounts (for example, cash flows or earnings) to a

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

Pacer Combination

On January 3, 2012, we completed a business combination with Pacer in order to expand our retail propane operations. The combination was funded with cash of $32.2 million and the issuance of 1.5 million common units. We valued the 1.5 million common units based on the closing price of our common units on the closing date. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $0.7 million of costs related to the Pacer transaction. We also incurred costs of $0.1 million related to the equity issuance that we charged to equity.

The assets contributed by Pacer consist of retail propane operations in Colorado, Illinois, Mississippi, Oregon, Utah and Washington. The contributed assets include 17 owned or leased customer service centers and satellite distribution locations. We have included the results of Pacer's operations in our consolidated financial statements beginning January 3, 2012. The operations of Pacer are reported within our retail propane segment.

Consideration paid consists of the following (in thousands):


Cash	$	32,213
Common units		30,375


Consideration paid	$	62,588

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed, based on their fair values (in thousands):


Accounts receivable—trade	$	4,389
Inventories		965
Prepaid expenses and other current assets		43
Property, plant and equipment:
Land		1,967
Retail propane equipment (15 - 20 years)		12,793
Vehicles (5 years)		3,090
Buildings and leasehold improvements (30 years)		409
Other (3 - 5 years)		59
Intangible assets:
Customer relationships (15 years)		23,560
Trade names (indefinite life)		2,410
Non-compete agreements		1,520
Goodwill		15,782
Assumed liabilities		(4,399	)


Consideration paid	$	62,588

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

North American Combination

On February 3, 2012, we completed a business combination with North American in order to expand our retail propane operations. The combination was funded with cash of $69.8 million. We incurred and charged to general and administrative expense during the year ended March 31, 2012 $1.6 million of costs related to the North American acquisition.

The assets acquired from North American include retail propane and distillate operations in Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, Pennsylvania, and Rhode Island.

The following table presents the allocation of the acquisition costs to the assets acquired and liabilities assumed, based on their fair values (in thousands):


Accounts receivable—trade	$	10,338
Inventories		3,437
Prepaid expenses and other current assets		282
Property, plant and equipment:
Land		2,251
Retail propane equipment (15 - 20 years)		24,790
Natural gas liquids terminal assets (15 - 20 years)		1,044
Vehicles (5 - 15 years)		5,819
Buildings and leasehold improvements (30 years)		2,386
Other (3 - 5 years)		634
Intangible assets:
Customer relationships (10 years)		12,600
Trade names (10 years)		2,700
Non-compete agreements (3 years)		700
Goodwill		13,978
Assumed liabilities		(11,129	)


Consideration paid	$	69,830

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 4—Acquisitions (Continued)

Other Acquisitions

During the year ended March 31, 2012, we closed three additional acquisitions for cash payments of $6.4 million on a combined basis. We also assumed $0.6 million in long-term debt in the form of non-compete agreements. These operations have been included in our results of operations since the acquisition dates, and have not been material to our consolidated financial statements.

Note 5—Property, Plant and Equipment

Our property, plant and equipment consists of the following:

	March 31,

Description and Estimated Useful Lives	2014			2013 (Note 2)
	(in thousands)
Natural gas liquids terminal assets (2 - 30 years)	$	75,141		$	63,637
Retail propane equipment (2 - 30 years)		160,758			152,802
Vehicles (3 - 25 years)		152,676			88,173
Water treatment facilities and equipment (3 - 30 years)		180,985			91,944
Crude oil tanks and related equipment (2 - 40 years)		106,125			22,577
Barges and towboats (5 - 40 years)		52,217			25,963
Information technology equipment (3 - 7 years)		20,768			12,169
Buildings and leasehold improvements (3 - 40 years)		60,004			48,975
Land		30,241			21,815
Linefill and tank bottoms		13,403			—
Other (5 - 30 years)		6,341			16,104
Construction in progress		80,251			32,405


		938,910			576,564
Less: Accumulated depreciation		(109,564	)		(50,127	)


Net property, plant and equipment	$	829,346		$	526,437

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 5—Property, Plant and Equipment (Continued)

Depreciation expense was $59.9 million, $39.2 million and $10.6 million during the years ended March 31, 2014, 2013 and 2012, respectively. During the year ended March 31, 2014, we capitalized $0.7 million of interest expense.

Note 6—Goodwill

The changes in the balance of goodwill were as follows:

	Year Ended March 31,

	2014		2013		2012
	(in thousands)
Beginning of period, as retrospectively adjusted (Note 2)	$	555,220	$	167,245	$	8,568
Acquisitions		551,786		387,975		158,677


End of period, as retrospectively adjusted (Note 2)	$	1,107,006	$	555,220	$	167,245

Goodwill by reportable segment is as follows:

	March 31,

	2014		2013
	(in thousands)
Crude oil logistics	$	606,383	$	246,345
Water solutions		262,203		109,470
Liquids		90,135		87,136
Retail propane		114,285		112,269
Refined products		22,000		—
Renewables		12,000		—


	$	1,107,006	$	555,220

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 7—Intangible Assets

Our intangible assets consist of the following:

		March 31, 2014				March 31, 2013

	Amortizable Lives	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount (Note 2)		Accumulated Amortization
				(in thousands)
Amortizable—
Customer relationships(1)	3 - 20 years	$	697,405	$	83,261	$	405,160	$	30,959
Water facility development agreement	5 years		14,000		2,100		—		—
Lease and other agreements	5 - 8 years		23,920		13,190		15,210		7,018
Non-compete agreements	2 - 7 years		14,161		6,388		11,509		2,871
Trade names	1 - 10 years		15,489		3,081		2,784		326
Debt issuance costs	5 - 10 years		44,089		8,708		19,494		2,981


Total amortizable			809,064		116,728		454,157		44,155
Non-amortizable—
Trade names			22,620				31,430


Total		$	831,684	$	116,728	$	485,587	$	44,155

(1): The weighted-average remaining amortization period for customer relationship intangible assets is approximately nine years.

Amortization expense was as follows:

	Year Ended March 31,

Recorded in	2014		2013		2012
	(in thousands)
Depreciation and amortization	$	60,855	$	29,657	$	4,538
Cost of sales		6,172		5,285		800
Interest expense		5,727		3,375		1,277
Loss on early extinguishment of debt		—		5,769		—


	$	72,754	$	44,086	$	6,615

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 7—Intangible Assets (Continued)

Expected amortization of our intangible assets is as follows (in thousands):

Year Ending March 31,

2015	$	88,970
2016		83,449
2017		76,826
2018		72,857
2019		66,826
Thereafter		303,408


	$	692,336

Note 8—Long-Term Obligations

Our long-term debt consists of the following:

	March 31,

	2014		2013
	(in thousands)
Revolving credit facility—
Expansion capital loans	$	532,500	$	441,500
Working capital loans		389,500		36,000
Senior notes		250,000		250,000
Unsecured notes		450,000		—
Other notes payable		14,914		21,562


		1,636,914		749,062
Less—current maturities		7,080		8,626


Long-term debt	$	1,629,834	$	740,436

Credit Agreement

The Working Capital Facility had a total capacity of $935.5 million for cash borrowings and letters of credit at March 31, 2014. At March 31, 2014, we had outstanding cash borrowings of $389.5 million and outstanding letters of credit of $270.6 million on the Working Capital Facility. The Expansion Capital Facility had a total capacity of $785.5 million for cash borrowings at March 31, 2014. At March 31, 2014, we had outstanding cash borrowings of $532.5 million on the Expansion Capital Facility. The capacity available under the Working Capital Facility may be limited by a "borrowing

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Table of Contents

NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 8—Long-Term Obligations (Continued)

base," as defined in the Credit Agreement, which is calculated based on the value of certain working capital items at any point in time.

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

All borrowings under the Credit Agreement bear interest, at our option, at (i) an alternate base rate plus a margin of 0.50% to 1.50% per annum or (ii) an adjusted LIBOR rate plus a margin of 1.50% to 2.50% per annum. The applicable margin is determined based on our consolidated leverage ratio, as defined in the Credit Agreement. At March 31, 2014, the interest rate in effect on outstanding LIBOR borrowings was 1.91%, calculated as the LIBOR rate of 0.16% plus a margin of 1.75%. At March 31, 2014, the interest rate in effect on letters of credit was 1.75%. Commitment fees are charged at a rate ranging from 0.38% to 0.50% on any unused credit. At March 31, 2014, our outstanding borrowings and interest rates under our Revolving Credit Facility were as follows (dollars in thousands):

	Amount

Expansion capital facility—
LIBOR borrowings	$	532,500	1.91	%
Working capital facility—
LIBOR borrowings		358,000	1.91	%
Base rate borrowings		31,500	4.00	%

The Credit Agreement is secured by substantially all of our assets. The Credit Agreement specifies that our "leverage ratio," as defined in the Credit Agreement, cannot exceed 4.25 to 1.0 at any quarter end. At March 31, 2014, our leverage ratio was approximately 3 to 1. The Credit Agreement also specifies that our "interest coverage ratio," as defined in the Credit Agreement, cannot be less than 2.75 to 1 as of the last day of any fiscal quarter. At March 31, 2014, our interest coverage ratio was approximately 7 to 1.

At March 31, 2014, we were in compliance with the covenants under the Credit Agreement.

Senior Notes

On June 19, 2012, we entered into a note purchase agreement (as amended, the "Note Purchase Agreement") whereby we issued $250.0 million of senior notes in a private placement (the "Senior Notes"). The Senior Notes have an aggregate principal amount of $250.0 million and bear interest at a

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 8—Long-Term Obligations (Continued)

fixed rate of 6.65%. Interest is payable quarterly. The Senior Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to pre-pay outstanding principal, although we would incur a pre-payment penalty. The Senior Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

The Note Purchase Agreement contains various customary representations, warranties, and additional covenants that, among other things, limit our ability to (subject to certain exceptions): (i) incur additional debt, (ii) pay dividends and make other restricted payments, (iii) create or permit certain liens, (iv) create or permit restrictions on the ability of certain of our subsidiaries to pay dividends or make other distributions to us, (v) enter into transactions with affiliates, (vi) enter into sale and leaseback transactions and (vii) consolidate or merge or sell all or substantially all or any portion of our assets. In addition, the Note Purchase Agreement contains the same leverage ratio and interest coverage ratio requirements as our Credit Agreement, which are described above.

The Note Purchase Agreement provides for customary events of default that include, among other things (subject in certain cases to customary grace and cure periods): (i) non-payment of principal or interest, (ii) breach of certain covenants contained in the Note Purchase Agreement or the Senior Notes, (iii) failure to pay certain other indebtedness or the acceleration of certain other indebtedness prior to maturity if the total amount of such indebtedness unpaid or accelerated exceeds $10.0 million, (iv) the rendering of a judgment for the payment of money in excess of $10.0 million, (v) the failure of the Note Purchase Agreement, the Senior Notes, or the guarantees by the subsidiary guarantors to be in full force and effect in all material respects and (vi) certain events of bankruptcy or insolvency. Generally, if an event of default occurs (subject to certain exceptions), the trustee or the holders of at least 51% in aggregate principal amount of the then outstanding Senior Notes of any series may declare all of the Senior Notes of such series to be due and payable immediately.

At March 31, 2014, we were in compliance with the covenants under the Note Purchase Agreement and the Senior Notes.

Unsecured Notes

On October 16, 2013, we issued $450.0 million of 6.875% senior unsecured notes (the "Unsecured Notes") in a private placement exempt from registration under the Securities Act of 1933, as amended (the "Securities Act"), pursuant to Rule 144A and Regulation S under the Securities Act. We received net proceeds of $438.4 million, after the initial purchasers' discount of $10.1 million and estimated offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

The Unsecured Notes mature on October 15, 2021. Interest is payable on April 15 and October 15 of each year. We have the right to redeem the Unsecured Notes prior to the maturity date, although we would be required to pay a premium for early redemption.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 8—Long-Term Obligations (Continued)

The purchase agreement and the indenture governing the Unsecured Notes contain various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At March 31, 2014, we were in compliance with the covenants under the Unsecured Notes.

We also entered into a registration rights agreement whereby we have committed to exchange the Unsecured Notes for a new issue of notes registered under the Securities Act that has substantially identical terms to the Unsecured Notes on or before October 16, 2014. If we are unable to fulfill this obligation, we would be required to pay liquidated damages to the holders of the Unsecured Notes.

Other Notes Payable

We have executed various non-interest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing, which have interest rates ranging from 2.1% to 4.9% at March 31, 2014.

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at March 31, 2014:

Year Ending March 31,	Revolving Credit Facility		Senior Notes		Unsecured Notes		Other Notes Payable		Total

					(in thousands)
2015	$	—	$	—	$	—	$	7,081	$	7,081
2016		—		—		—		3,614		3,614
2017		—		—		—		2,356		2,356
2018		—		25,000		—		1,449		26,449
2019		922,000		50,000		—		238		972,238
Thereafter		—		175,000		450,000		176		625,176


	$	922,000	$	250,000	$	450,000	$	14,914	$	1,636,914

Previous Credit Facilities

On June 19, 2012, we made a principal payment of $306.8 million to retire our previous revolving credit facility. Upon retirement of this facility, we wrote off the portion of the debt issuance cost asset that had not yet been amortized. This expense is reported as "Loss on early extinguishment of debt" in our consolidated statement of operations for the year ended March 31, 2013.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 9—Income Taxes

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

A publicly traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income for each of the calendar years since our IPO.

We evaluate uncertain tax positions for recognition and measurement in the consolidated financial statements. To recognize a tax position, we determine whether it is more likely than not that the tax position will be sustained upon examination, including resolution of any related appeals or litigation, based on the technical merits of the position. A tax position that meets the more likely than not threshold is measured to determine the amount of benefit to be recognized in the consolidated financial statements. We had no material uncertain tax positions that required recognition in the consolidated financial statements at March 31, 2014.

Note 10—Commitments and Contingencies

Legal Contingencies

We are party to various claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of our management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on our consolidated financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of our liabilities may change materially as circumstances develop.

Customer Dispute

A customer of our crude oil logistics segment has disputed the transportation rate schedule we used to bill the customer for services that we provided from November 2012 through February 2013, which was the same rate schedule that Pecos used to bill the customer from April 2011 through October 2012 (prior to our acquisition of Pecos). The customer has not paid $1.7 million of the amount we charged for services we provided from November 2012 through February 2013. In May 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. Later in May 2013, the customer filed an answer and counterclaim seeking to recover $5.5 million that it paid to Pecos prior to our acquisition of Pecos. We have not recorded revenue for the $1.7 million of unpaid fees charged from November 2012 through February 2013, pending resolution of the dispute.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 10—Commitments and Contingencies (Continued)

During August 2013, the customer notified us that it intended to withhold payment of $3.3 million for services performed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer has not disputed the validity of the amounts billed for services performed during this time frame. Upon receiving this notification, we ceased providing services under this contract, and on November 5, 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. We are not able to reliably predict the outcome of this dispute at this time, but we do not believe the outcome will have a material adverse effect on our consolidated financial position or results of operations.

Canadian Fuel and Sales Taxes

The taxing authority of a province in Canada completed an audit of fuel and sales tax payments and alleged that an entity we acquired should have collected from customers and remitted to the taxing authority fuel and sales taxes on certain historical sales. We recorded in the acquisition accounting a liability of $0.8 million (net of receivables for expected recoveries from other parties). We now believe this matter is resolved, and we removed the liability from our consolidated balance sheet and recorded a corresponding reduction to cost of sales during the year ended March 31, 2014.

Environmental Matters

Our operations are subject to extensive federal, state, and local environmental laws and regulations. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in our business, and there can be no assurance that significant costs will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

Asset Retirement Obligations

We have recorded a liability of $2.3 million at March 31, 2014 for asset retirement obligations. This liability is related to wastewater disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

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

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 10—Commitments and Contingencies (Continued)

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, and equipment. Future minimum lease payments under contractual commitments at March 31, 2014 are as follows (in thousands):

Year Ending March 31,

2015	$	133,170
2016		93,454
2017		64,209
2018		49,802
2019		29,213
Thereafter		58,182


Total	$	428,030

Rental expense relating to operating leases was $98.3 million, $84.2 million, and $5.2 million during the years ended March 31, 2014, 2013, and 2012, respectively.

Sales and Purchase Contracts

We have entered into sales and purchase contracts for products to be delivered in future periods for which we expect the parties to physically settle the contracts with inventory. At March 31, 2014, we had the following such commitments outstanding:

	Volume		Value

	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)		31,111	$	39,117
Natural gas liquids floating-price purchase commitments (gallons)		522,947		618,293
Natural gas liquids fixed-price sale commitments (gallons)		63,944		77,682
Natural gas liquids floating-price sale commitments (gallons)		272,495		395,095
Crude oil fixed-price purchase commitments (barrels)		4,016		364,557
Crude oil fixed-price sale commitments (barrels)		3,574		324,765

We account for the contracts shown in the table above as normal purchases and normal sales. Under this accounting policy election, we do not record the contracts at fair value at each balance sheet date; instead, we record the purchase or sale at the contracted value once the delivery occurs. Contracts in the table above may have offsetting derivative contracts (described in Note 12) or inventory positions (described in Note 2).

Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value on our consolidated balance sheet and are not included in the data in the table above. These contracts are included in the derivative disclosures in Note 12, and represent $43.5 million of our prepaid expenses and other current assets and $34.6 million of our accrued expenses and other payables at March 31, 2014.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity

Partnership Equity

The Partnership's equity consists of a 0.1% general partner interest and a 99.9% limited partner interest. Limited partner equity includes common and subordinated units. The common and subordinated units share equally in the allocation of income or loss. The principal difference between common and subordinated units is that in any quarter during the subordination period, holders of the subordinated units are not entitled to receive any distribution until the common units have received the minimum quarterly distribution plus any arrearages in the payment of the minimum quarterly distribution from prior quarters. Subordinated units will not accrue arrearages.

We expect the subordination period to end in August 2014. When the subordination period ends, all 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.

Our general partner is not obligated to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

Initial Public Offering

On May 17, 2011, we completed our IPO. We sold a total of 4,025,000 common units in our IPO at $21.00 per unit. Our proceeds from the sale of 3,850,000 common units of $71.9 million, net of total offering costs of $9.0 million, were used to repay advances under our acquisition credit facility and for general partnership purposes. Proceeds from the sale of 175,000 common units ($3.4 million) from the underwriters' exercise of their option to purchase additional common units from us were used to redeem 175,000 of the common units outstanding prior to our IPO. Upon the completion of our IPO and the underwriters' exercise in full of their option to purchase additional common units from us and the redemption, we had outstanding 8,864,222 common units, 5,919,346 subordinated units, a 0.1% general partner interest, and IDRs.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity (Continued)

Common Units Issued in Business Combinations

As described in Note 4, we issued common units as partial consideration for several acquisitions. These are summarized below:


Osterman combination			4,000,000
SemStream combination			8,932,031
Pacer combination			1,500,000


Total—Year Ended March 31, 2012			14,432,031




High Sierra combination			20,703,510
Retail propane combinations			850,676
Crude oil logistics and water solutions combinations			516,978
Pecos combination			1,834,414
Third Coast combination			344,680


Total—Year Ended March 31, 2013			24,250,258




Water solutions combinations			222,381
Crude oil logistics combinations			175,211
OWL combination			2,463,287


Total—Year Ended March 31, 2014			2,860,879

In connection with the completion of certain of these transactions, we amended our Registration Rights Agreement, which provides for certain registration rights for certain holders of our common units.

Equity Issuances

On July 5, 2013, we completed a public offering of 10,350,000 common units. We received net proceeds of $287.5 million, after underwriting discounts and commissions of $12.0 million and offering costs of $0.7 million.

On September 25, 2013, we completed a public offering of 4,100,000 common units. We received net proceeds of $127.6 million, after underwriting discounts and commissions of $5.0 million and offering costs of $0.2 million.

On December 2, 2013, we issued and sold 8,110,848 of our common units in a private placement. We received net proceeds of $235.1 million, after offering costs of $4.9 million.

Distributions

Our general partner has adopted a cash distribution policy that will require us to pay a quarterly distribution to the extent we have sufficient cash from operations after establishment of cash reserves

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity (Continued)

and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as "available cash," in the following manner:

•: First, 99.9% to the holders of common units and 0.1% to the general partner, until each common unit has received the specified minimum quarterly distribution, plus any arrearages from prior quarters.
•: Second, 99.9% to the holders of subordinated units and 0.1% to the general partner, until each subordinated unit has received the specified minimum quarterly distribution.
•: Third, 99.9% to all unitholders, pro rata, and 0.1% to the general partner.

The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions paid to the limited partners. These distributions are referred to as "incentive distributions."

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest in Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution per Unit." The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1% general partner interest, assume our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its IDRs and there are no arrearages on common units.

							Marginal Percentage Interest In Distributions

	Total Quarterly Distribution per Unit						Unitholders			General Partner
Minimum quarterly distribution					$	0.337500		99.9	%		0.1	%
First target distribution	above	$	0.337500	up to	$	0.388125		99.9	%		0.1	%
Second target distribution	above	$	0.388125	up to	$	0.421875		86.9	%		13.1	%
Third target distribution	above	$	0.421875	up to	$	0.506250		76.9	%		23.1	%
Thereafter	above	$	0.506250					51.9	%		48.1	%

On May 5, 2011, we made a distribution of $3.9 million from available cash to our general partner and common unitholders at March 31, 2011.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity (Continued)

The following table summarizes the distributions declared subsequent to our IPO:

Date Declared	Record Date	Date Paid	Amount Per Unit		Amount Paid to Limited Partners		Amount Paid to General Partner

					(in thousands)		(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011		0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012		0.3500		7,735		10
April 18, 2012	April 30, 2012	May 15, 2012		0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012		0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012		0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013		0.4625		24,245		927
April 25, 2013	May 6, 2013	May 15, 2013		0.4775		25,605		1,189
July 25, 2013	August 5, 2013	August 14, 2013		0.4938		31,725		1,739
October 23, 2013	November 4, 2013	November 14, 2013		0.5113		35,908		2,491
January 23, 2014	February 4, 20143	February 14, 2014		0.5313		42,150		4,283
April 24, 2014	May 5, 2014	May 15, 2014		0.5513		43,737		5,754

Several of our business combination agreements contained provisions that temporarily limited the distributions to which the newly-issued units were entitled. The following table summarizes the number of equivalent units that were not eligible to receive a distribution on each of the record dates:

Record Date		Equivalent Units Not Eligible

August 3, 2011			—
October 31, 2011			4,000,000
February 3, 2012			7,117,031
April 30, 2012			3,932,031
August 3, 2012			17,862,470
October 29, 2012			516,978
February 4, 2013			1,202,085
May 6, 2013			—
August 5, 2013			—
November 4, 2013			979,886
February 4, 2014			—
May 5, 2014			—

Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plan ("LTIP") which allows for the issuance of equity-based compensation to employees and directors. The board of directors of our general partner has granted certain restricted units to employees and directors, which will vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity (Continued)

The following table summarizes the restricted unit activity during the years ended March 31, 2014 and 2013:


Unvested restricted units at March 31, 2012	—
Units granted	1,684,400
Units vested and issued	(156,802	)
Units withheld for employee taxes	(61,698	)
Units forfeited	(21,000	)


Unvested restricted units at March 31, 2013	1,444,900
Units granted	494,000
Units vested and issued	(296,269	)
Units withheld for employee taxes	(122,531	)
Units forfeited	(209,000	)


Unvested restricted units at March 31, 2014	1,311,100

The scheduled vesting of the awards is summarized below:

Vesting Date		Number of Awards

July 1, 2014			408,300
January 1, 2015			4,000
July 1, 2015			341,300
January 1, 2016			4,000
July 1, 2016			322,500
January 1, 2017			4,000
July 1, 2017			192,500
January 1, 2018			4,000
July 1, 2018			30,500


Total unvested units at March 31, 2014			1,311,100

We record the expense for each tranche on a straight-line basis over the period beginning with the vesting of the previous tranche and ending with the vesting of the tranche. We adjust the cumulative expense recorded through the reporting date using the estimated fair value of the awards at the reporting date. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth. We estimate that the future expense we will record on the unvested awards at March 31, 2014 will be as follows (in thousands), after taking into consideration an estimate

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 11—Equity (Continued)

of forfeitures of 95,000 units. For purposes of this calculation, we have used the closing price of the common units on March 31, 2014, which was $37.53.

Year Ending March 31,

2015	$	14,393
2016		11,279
2017		7,429
2018		2,310
2019		229


Total	$	35,640

Following is a rollforward of the liability related to equity-based compensation, which is reported within accrued expenses and other payables on our consolidated balance sheets (in thousands):


Balance at March 31, 2012	$	—
Expense recorded		10,138
Value of units vested and issued		(3,627	)
Taxes paid on behalf of participants		(1,468	)


Balance at March 31, 2013		5,043
Expense recorded		17,804
Value of units vested and issued		(9,085	)
Taxes paid on behalf of participants		(3,750	)


Balance at March 31, 2014	$	10,012

The weighted-average fair value of the awards at March 31, 2014 was $33.78, which was calculated as the closing price of the common units on March 31, 2014, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common and subordinated units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common and subordinated units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations are not considered to be delivered under the LTIP. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At March 31, 2014, 6.2 million units remain available for issuance under the LTIP.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 12—Fair Value of Financial Instruments

Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values, due to their short-term nature. We believe the carrying amounts of our long-term debt instruments, including the Revolving Credit Facility and the Senior Notes, approximate their fair values, as we do not believe market conditions have changed materially since we entered into these debt agreements.

Commodity Derivatives

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2014:

	Derivative Assets			Derivative Liabilities

	(in thousands)
Level 1 measurements	$	4,990		$	(3,258	)
Level 2 measurements		49,605			(43,303	)


		54,595			(46,561	)
Netting of counterparty contracts(1)		(4,347	)		4,347
Cash collateral provided or held		456			—


Commodity contracts reported on consolidated balance sheet	$	50,704		$	(42,214	)

(1): Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with the counterparty.

The following table summarizes the estimated fair values of the commodity derivative assets (liabilities) reported on the consolidated balance sheet at March 31, 2013:

	Derivative Assets			Derivative Liabilities

	(in thousands)
Level 1 measurements	$	947		$	(3,324	)
Level 2 measurements		9,911			(13,280	)


		10,858			(16,604	)
Netting of counterparty contracts(1)		(3,503	)		3,503
Cash collateral provided or held		(1,760	)		400


Commodity contracts reported on consolidated balance sheet	$	5,595		$	(12,701	)

(1): Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with the counterparty.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 12—Fair Value of Financial Instruments (Continued)

The commodity derivative assets (liabilities) are reported in the following accounts on the consolidated balance sheets:

	March 31,

	2014			2013
	(in thousands)
Prepaid expenses and other current assets	$	50,704		$	5,551
Other noncurrent assets		—			44
Accrued expenses and other payables		(42,214	)		(12,701	)


Net asset (liability)	$	8,490		$	(7,106	)

The following table sets forth our open commodity derivative contract positions at March 31, 2014 and 2013. We do not account for these derivatives as hedges.

Contracts	Settlement Period	Total Notional Units (Barrels)			Fair Value of Net Assets (Liabilities)

		(in thousands)
At March 31, 2014—
Cross-commodity(1)	April 2014 - March 2015		140		$	(1,876	)
Crude oil fixed-price(2)	April 2014 - March 2015		(1,600	)		(2,796	)
Crude oil index(3)	April 2014 - December 2015		3,598			6,099
Propane fixed-price(4)	April 2014 - March 2015		60			1,753
Refined products fixed-price(5)	April 2014 - July 2014		732			560
Renewable products fixed-price(6)	April 2014 - July 2014		106			4,084
Other	April 2014		—			210


						8,034
Net cash collateral provided						456


Net value of commodity derivatives on consolidated balance sheet					$	8,490




At March 31, 2013—
Cross-commodity(1)	April 2013 - March 2014		430		$	(10,208	)
Crude oil fixed-price(2)	April 2013 - March 2014		(144	)		1,033
Crude oil index(3)	April 2013 - June 2014		(91	)		153
Propane fixed-price(4)	April 2013 - March 2014		(282	)		3,197
Other	May 2013 - June 2013		8			79


						(5,746	)
Net cash collateral held						(1,360	)


Net value of commodity derivatives on consolidated balance sheet					$	(7,106	)

(1): Cross-commodity—Our operating segments may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. The contracts

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 12—Fair Value of Financial Instruments (Continued)

listed in this table as "Cross-commodity" represent derivatives we have entered into as economic hedges against the risk of one commodity price moving relative to another commodity price.

(2): Crude oil fixed-price—Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Crude oil fixed-price" represent derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding the inventory.
(3): Crude oil index—Our crude oil logistics segment may purchase or sell crude oil where the underlying contract pricing mechanisms are tied to different crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as "Crude oil index" represent derivatives we have entered into as an economic hedge against the risk of one crude oil index moving relative to another crude oil index.
(4): Propane fixed-price—Our liquids segment routinely purchases inventory during the warmer months and stores the inventory for sale in the colder months. The contracts listed in this table as "Propane fixed-price" represent derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.
(5): Refined products fixed-price—Our refined products segment routinely purchases refined products inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Refined products fixed-price" represent derivatives we have entered into as an economic hedge against the risk that refined product prices will decline while we are holding the inventory.
(6): Renewable products fixed-price—Our renewables segment routinely purchases biodiesel and ethanol inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Renewable products fixed-price" represent derivatives we have entered into as an economic hedge against the risk that biodiesel or ethanol prices will decline while we are holding the inventory.

We recorded the following net gains (losses) from our commodity derivatives to cost of sales:

Year Ended March 31,

2014	$	(43,655	)
2013		(4,381	)
2012		5,676

Credit Risk

We maintain credit policies with regard to our counterparties on the derivative financial instruments that we believe minimize our overall credit risk, including an evaluation of potential counterparties' financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements, which allow for netting of positive and negative exposure associated with a single counterparty.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 12—Fair Value of Financial Instruments (Continued)

exposures with counterparties. The cash collateral agreements reduce the level of our net counterparty credit risk because the amount of collateral represents additional funds that we may access to net settle positions due us, and the amount of collateral adjusts each day in response to changes in the market value of counterparty derivatives.

Our counterparties consist primarily of financial institutions and energy companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions.

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 logistics are typically higher than the receivables from customers of our other segments.

Failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our consolidated statements of financial position and recognized in our net income.

Interest Rate Risk

Our Revolving Credit Facility is variable-rate debt with interest rates that are generally indexed to bank prime or LIBOR interest rates. At March 31, 2014, we have $922.0 million of outstanding borrowings under our Revolving Credit Facility at a rate of 1.98%. A change in interest rates of 0.125% would result in an increase or decrease of our annual interest expense of $1.2 million on the $922.0 million of outstanding borrowings on the revolving credit facility at March 31, 2014.

Note 13—Segments

Our reportable segments are based on the way in which our management structure is organized. Certain financial data related to our segments is shown below. Transactions between segments are recorded based on prices negotiated between the segments.

Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers, refiners, and producers. Our water solutions segment provides services for the transportation, treatment, and disposal of wastewater generated from crude oil and natural gas production, and generates revenue from the sale of recycled wastewater and recovered hydrocarbons. Our liquids segment supplies propane, butane, and other products, and provides natural gas liquids transportation, terminaling, and storage services to retailers, wholesalers, and refiners. Our retail propane segment sells propane and distillates to end users consisting of residential, agricultural, commercial, and industrial customers, and to certain re-sellers. Our retail propane segment consists of two divisions, which are organized based on the location of the operations.

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

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 13—Segments (Continued)

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 Energy.

Items labeled "corporate and other" in the table below include the operations of a compressor leasing business that we acquired in our June 2012 merger with High Sierra and sold in February 2014, and the natural gas marketing operations that we acquired in our December 2013 acquisition of Gavilon Energy and began winding down during fiscal 2014. The "corporate and other" category also includes certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our consolidated financial statements.

Certain information related to the results of operations of each segment is shown in the tables below:

	Year Ended March 31,

	2014			2013			2012
	(in thousands)
Revenues:
Crude oil logistics—
Crude oil sales	$	4,559,923		$	2,322,706		$	—
Crude oil transportation and other		36,469			16,442			—
Water solutions—
Water treatment and disposal		125,788			54,334			—
Water transportation		17,312			7,893			—
Liquids—
Propane sales		1,632,948			841,448			923,022
Other product sales		1,231,965			858,276			251,627
Other revenues		31,062			33,954			2,462
Retail propane—
Propane sales		388,225			288,410			175,417
Distillate sales		127,672			106,192			6,547
Other revenues		35,918			35,856			17,370
Refined products		1,180,895			—			—
Renewables		176,781			—			—
Corporate and other		437,713			4,233			—
Eliminations of intersegment sales		(283,397	)		(151,977	)		(65,972	)


Total revenues	$	9,699,274		$	4,417,767		$	1,310,473




Depreciation and amortization:
Crude oil logistics	$	22,111		$	9,176		$	—
Water solutions		55,105			20,923			—
Liquids		11,018			11,085			3,661
Retail propane		28,878			25,496			11,450
Refined products		109			—			—
Renewables		516			—			—
Corporate and other		3,017			2,173			—


Total depreciation and amortization	$	120,754		$	68,853		$	15,111

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 13—Segments (Continued)

	Year Ended March 31,

	2014			2013			2012
	(in thousands)
Operating income (loss):
Crude oil logistics	$	678		$	34,236		$	—
Water solutions		10,317			8,576			—
Liquids		71,888			30,336			9,735
Retail propane		61,285			46,869			9,616
Refined products		4,080			—			—
Renewables		2,434			—			—
Corporate and other		(44,117	)		(32,710	)		(4,321	)


Total operating income	$	106,565		$	87,307		$	15,030

The table below shows additions to property, plant and equipment for each segment. This information has been prepared on the accrual basis, and includes property, plant and equipment acquired in acquisitions.

	Year Ended March 31,

	2014		2013		2012
	(in thousands)
Additions to property, plant and equipment, including acquisitions (accrual basis):
Crude oil logistics	$	204,642	$	89,860	$	—
Water solutions		100,877		137,116		—
Liquids		52,560		15,129		50,276
Retail propane		24,430		66,933		150,181
Refined products		719		—		—
Renewables		519		—		—
Corporate and other		7,242		17,858		—


Total	$	390,989	$	326,896	$	200,457

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 13—Segments (Continued)

The following tables show long-lived assets (consisting of property, plant and equipment, intangible assets, and goodwill) and total assets by segment:

	March 31,

	2014		2013 (Note 2)
	(in thousands)
Total assets:
Crude oil logistics	$	1,723,812	$	801,351
Water solutions		875,714		466,412
Liquids		577,795		474,141
Retail propane		541,832		513,301
Refined products		157,581		—
Renewables		145,649		—
Corporate and other		144,840		36,413


Total	$	4,167,223	$	2,291,618




Long-lived assets, net:
Crude oil logistics	$	980,978	$	357,230
Water solutions		848,479		453,909
Liquids		274,846		238,192
Retail propane		438,324		441,762
Refined products		27,017		—
Renewables		33,703		—
Corporate and other		47,961		31,996


Total	$	2,651,308	$	1,523,089

Note 14—Disposals and Impairments

We acquired Gavilon Energy in December 2013, which operated a natural gas marketing business. During March 2014, we assigned all of the storage and transportation contracts of the natural gas marketing business to a third party. Since these contracts were at unfavorable terms relative to current market conditions, we paid $44.8 million to assign these contracts. We recorded a liability of $50.8 million related to these storage and transportation contracts in the acquisition accounting, and we amortized $6.0 million of this balance through cost of sales during the period from the acquisition date through the date we assigned the contracts. We also assigned all forward purchase and sale contracts and all financial derivative contracts, and thereby wound down the natural gas business. Our consolidated statement of operations for the year ended March 31, 2014 includes $1.4 million of operating income related to the natural gas business, which is reported within "corporate and other" in the segment disclosures in Note 13.

We acquired High Sierra in June 2012, which operated a compressor leasing business. We sold the compressor leasing business in February 2014 for $10.8 million (net of the amount due to the owner of the noncontrolling interest in the business). We recorded a gain on the sale of the business of $4.4 million, $1.6 million of which was attributable to the disposal of the noncontrolling interest. We

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 14—Disposals and Impairments (Continued)

reported the gain as a reduction to operating expenses in our consolidated statement of operations. Our consolidated statement of operations for the year ended March 31, 2014 includes $2.3 million of operating income related to the compressor leasing business, which is reported within "corporate and other" in the segment disclosures in Note 13.

During the year ended March 31, 2014, we recorded an impairment of $5.3 million to the property, plant and equipment of one of our natural gas liquids terminals. This loss is reported within operating expenses of our liquids segment.

During the year ended March 31, 2014, two of our water solutions facilities experienced damage to their property, plant and equipment as a result of lightning strikes. We recorded a write-down to property, plant and equipment of $1.5 million related to these incidents, which is reported within operating expenses in our consolidated statement of operations.

Note 15—Transactions with Affiliates

Since our business combination with SemStream on November 1, 2011, SemGroup Corporation ("SemGroup") has held ownership interests in us and in our general partner, and has the right to appoint two members to the board of directors of our general partner. Subsequent to November 1, 2011, we have sold product to and purchased product from affiliates of SemGroup. These transactions are included within revenues and cost of sales in our consolidated statements of operations.

Certain members of our management own interests in entities with which we have purchased products and services from and have sold products and services. The majority of these purchases represent crude oil purchases and are reported within cost of sales in our consolidated statements of operations, although $8.2 million of these transactions during the year ended March 31, 2014 represented capital expenditures and were recorded as increases to property, plant and equipment. The majority of these sales represent sales of crude oil and have been recorded within revenues in our consolidated statement of operations.

These transactions are summarized in the table below:

	Year Ended March 31,

	2014		2013		2012
	(in thousands)
Sales to SemGroup	$	306,780	$	32,431	$	29,200
Purchases from SemGroup		445,951		60,425		23,800
Sales to entities affiliated with management		110,824		16,828		—
Purchases from entities affiliated with management		120,038		60,942		—

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 15—Transactions with Affiliates (Continued)

Receivables from affiliates consist of the following:

	March 31,

	2014		2013
	(in thousands)
Receivables from entities affiliated with management	$	142	$	22,883
Receivables from SemGroup		7,303		—


	$	7,445	$	22,883

Payables to affiliates consist of the following:

	March 31,

	2014		2013
	(in thousands)
Payables to SemGroup	$	76,192	$	4,601
Payables to entities affiliated with management		654		2,299


	$	76,846	$	6,900

We completed a merger with High Sierra Energy, LP and High Sierra Energy GP, LLC in June 2012. We paid $91.8 million of cash, net of $5.0 million of cash acquired, and issued 18,018,468 common units to acquire High Sierra Energy, LP. We also paid $97.4 million of High Sierra Energy, LP's long-term debt and other obligations. Our general partner acquired High Sierra Energy GP, LLC by paying $50.0 million of cash and issuing equity. Our general partner then contributed its ownership interests in High Sierra Energy GP, LLC to us, in return for which we paid our general partner $50.0 million of cash and issued 2,685,042 common units to our general partner.

During the year ended March 31, 2014, we completed the acquisition of a crude oil logistics business owned by an employee. We paid $11.0 million of cash for this acquisition. During the year ended March 31, 2013, we completed two business combinations with entities in which members of our management owned interests. We paid $14.0 million of cash (net of cash acquired) on a combined basis for these two acquisitions. We also paid $5.0 million under a non-compete agreement to an employee.

Note 16—Quarterly Financial Data (Unaudited)

Our summarized unaudited quarterly financial data is presented below. The computation of net income per common and subordinated unit is done separately by quarter and year. The total of net income per common and subordinated unit of the individual quarters may not equal the net income per common and subordinated unit for the year, due primarily to the income allocation between the general partner and limited partners and variations in the weighted average units outstanding used in computing such amounts.

Our retail propane segment's business is seasonal due to weather conditions in our service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements, which generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and either net losses or lower

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 16—Quarterly Financial Data (Unaudited) (Continued)

net income during the period from April through September of each year. Our liquids segment is also subject to seasonal fluctuations, as demand for propane and butane is typically higher during the winter months. Our operating revenues from our other segments are less weather sensitive. Additionally, the acquisitions described in Note 4 impact the comparability of the quarterly information within the year, and year to year.

	Quarter Ended

	June 30, 2013			September 30, 2013			December 31, 2013		March 31, 2014		Year Ended March 31, 2014
	(in thousands, except unit and per unit data)
Total revenues	$	1,385,957		$	1,593,937		$	2,743,445	$	3,975,935	$	9,699,274
Total cost of sales	$	1,303,076		$	1,488,850		$	2,576,029	$	3,764,744	$	9,132,699
Net income (loss)	$	(17,508	)	$	(932	)	$	24,052	$	43,146	$	48,758
Net income (loss) attributable to parent equity	$	(17,633	)	$	(941	)	$	23,898	$	42,331	$	47,655
Earnings (loss) per unit, basic and diluted—
Common units	$	(0.35	)	$	(0.05	)	$	0.27	$	0.46	$	0.51
Subordinated units	$	(0.46	)	$	(0.09	)	$	0.23	$	0.46	$	0.32
Weighted average common units outstanding—basic and diluted		47,703,313			58,909,389			67,941,726		73,421,309		61,970,471
Weighted average subordinated outstanding units—basic and diluted		5,919,346			5,919,346			5,919,346		5,919,346		5,919,346

	Quarter Ended

	June 30, 2012			September 30, 2012		December 31, 2012		March 31, 2013		Year Ended March 31, 2013
	(in thousands, except unit and per unit data)
Total revenues	$	326,436		$	1,135,510	$	1,338,208	$	1,617,613	$	4,417,767
Total cost of sales	$	298,985		$	1,053,690	$	1,204,545	$	1,481,890	$	4,039,110
Net income (loss)	$	(24,710	)	$	10,082	$	40,477	$	22,341	$	48,190
Net income (loss) attributable to parent equity	$	(24,650	)	$	10,073	$	40,176	$	22,341	$	47,940
Earnings (loss) per unit, basic and diluted—
Common units	$	(0.76	)	$	0.18	$	0.75	$	0.39	$	0.96
Subordinated units	$	(0.77	)	$	0.18	$	0.75	$	0.39	$	0.93
Weighted average common units outstanding—basic and diluted		26,529,133			44,831,836		46,364,381		47,665,015		41,353,574
Weighted average subordinated outstanding units—basic and diluted		5,919,346			5,919,346		5,919,346		5,919,346		5,919,346

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly-owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the Unsecured Notes (described in Note 8). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the condensed consolidating financial information for NGL Energy Partners LP, NGL Energy Finance Corp. (which, along with NGL Energy Partners LP, is a co-issuer of the Unsecured Notes), the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below.

During the periods presented in the tables below, the status of certain subsidiaries changed, in that they either became guarantors of or ceased to be guarantors of the Unsecured Notes. Such changes have been given retrospective application in the tables below.

There are no significant restrictions upon the ability of the parent or any of the guarantor subsidiaries to obtain funds from their respective subsidiaries by dividend or loan. None of the assets of the guarantor subsidiaries represent restricted net assets pursuant to Rule 4-08(e)(3) of Regulation S-X under the Securities Act.

For purposes of the tables below, (i) the condensed consolidating financial information is presented on a legal entity basis, not a business segment basis, (ii) investments in consolidated subsidiaries are accounted for as equity method investments, and (iii) contributions, distributions, and advances to or from consolidated entities are reported on a net basis within net changes in advances with consolidated entities in the condensed consolidating cash flow tables below.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Balance Sheet
(U.S. Dollars in Thousands)

	March 31, 2014

	NGL Energy Partners LP (Parent)(1)		NGL Energy Finance Corp.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,181	$	—		$	8,728		$	531		$	—		$	10,440
Accounts receivable—trade, net of allowance for doubtful accounts		—		—			887,789			13,115			—			900,904
Accounts receivable—affiliates		—		—			7,445			—			—			7,445
Inventories		—		—			306,434			3,726			—			310,160
Prepaid expenses and other current assets		—		—			80,294			56			—			80,350


Total current assets		1,181		—			1,290,690			17,428			—			1,309,299
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation		—		—			764,014			65,332			—			829,346
GOODWILL		—		—			1,105,008			1,998			—			1,107,006
INTANGIBLE ASSETS, net of accumulated amortization		1,169		11,552			700,603			1,632			—			714,956
INVESTMENTS IN UNCONSOLIDATED ENTITIES		—		—			189,821			—			—			189,821
NET INTERCOMPANY RECEIVABLES (PAYABLES)		327,281		437,714			(720,737	)		(44,258	)		—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES		1,447,502		—			17,673			—			(1,465,175	)		—
OTHER NONCURRENT ASSETS		—		—			16,674			121			—			16,795


Total assets	$	1,777,133	$	449,266		$	3,363,746		$	42,253		$	(1,465,175	)	$	4,167,223




LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	—	$	—		$	726,252		$	13,959		$	—		$	740,211
Accounts payable—affiliates		—		—			73,703			3,143			—			76,846
Accrued expenses and other payables		554		14,266			124,923			1,947			—			141,690
Advance payments received from customers		—		—			29,891			74			—			29,965
Current maturities of long-term debt		—		—			7,058			22			—			7,080


Total current liabilities		554		14,266			961,827			19,145			—			995,792
LONG-TERM DEBT, net of current maturities		250,000		450,000			929,754			80			—			1,629,834
OTHER NONCURRENT LIABILITIES		—		—			9,663			81			—			9,744
EQUITY
Partners' equity (deficit)		1,526,579		(15,000	)		1,462,691			22,994			(1,470,449	)		1,526,815
Accumulated other comprehensive loss		—		—			(189	)		(47	)		—			(236	)
Noncontrolling interests		—		—			—			—			5,274			5,274


Total equity (deficit)		1,526,579		(15,000	)		1,462,502			22,947			(1,465,175	)		1,531,853


Total liabilities and equity	$	1,777,133	$	449,266		$	3,363,746		$	42,253		$	(1,465,175	)	$	4,167,223

(1): The parent is a co-issuer of the $450.0 million 6.875% Unsecured Notes that are included in the NGL Energy Finance Corp. column.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Balance Sheet
(U.S. Dollars in Thousands)

	March 31, 2013

	NGL Energy Partners LP (Parent)		Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	—	$	11,206		$	355		$	—		$	11,561
Accounts receivable—trade, net of allowance for doubtful accounts		—		561,560			1,197			—			562,757
Accounts receivable—affiliates		—		22,883			—			—			22,883
Inventories		—		126,024			871			—			126,895
Prepaid expenses and other current assets		—		37,784			107			—			37,891


Total current assets		—		759,457			2,530			—			761,987
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation		—		497,743			28,694			—			526,437
GOODWILL		—		553,222			1,998			—			555,220
INTANGIBLE ASSETS, net of accumulated amortization		717		439,365			1,350			—			441,432
NET INTERCOMPANY RECEIVABLES (PAYABLES)		237,736		(233,294	)		(4,442	)		—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES		895,779		20,371			—			(916,150	)		—
OTHER NONCURRENT ASSETS		—		6,542			—			—			6,542


Total assets	$	1,134,232	$	2,043,406		$	30,130		$	(916,150	)	$	2,291,618




LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	—	$	534,164		$	1,891		$	—		$	536,055
Accounts payable—affiliates		—		6,900			—			—			6,900
Accrued expenses and other payables		554		83,001			2,051			—			85,606
Advance payments received from customers		—		22,364			8			—			22,372
Current maturities of long-term debt		—		8,610			16			—			8,626


Total current liabilities		554		655,039			3,966			—			659,559
LONG-TERM DEBT, net of current maturities		250,000		490,433			3			—			740,436
OTHER NONCURRENT LIABILITIES		—		2,155			50			—			2,205
EQUITY
Partners' equity		883,678		895,779			26,087			(921,890	)		883,654
Accumulated other comprehensive income		—		—			24			—			24
Noncontrolling interests		—		—			—			5,740			5,740


Total equity		883,678		895,779			26,111			(916,150	)		889,418


Total liabilities and equity	$	1,134,232	$	2,043,406		$	30,130		$	(916,150	)	$	2,291,618

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

	Year Ended March 31, 2014

	NGL Energy Partners LP (Parent)(1)			NGL Energy Finance Corp.			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—		$	9,560,124		$	139,519		$	(369	)	$	9,699,274
COST OF SALES		—			—			9,011,011			122,057			(369	)		9,132,699
OPERATING COSTS AND EXPENSES:
Operating		—			—			253,214			6,182			—			259,396
General and administrative		—			—			77,756			2,104			—			79,860
Depreciation and amortization		—			—			117,573			3,181			—			120,754


Operating Income		—			—			100,570			5,995			—			106,565
OTHER INCOME (EXPENSE):
Earnings from unconsolidated entities		—			—			1,898			—			—			1,898
Interest expense		(16,818	)		(15,000	)		(27,031	)		(51	)		46			(58,854	)
Other, net		—			—			202			(70	)		(46	)		86


Income (Loss) Before Income Taxes		(16,818	)		(15,000	)		75,639			5,874			—			49,695
INCOME TAX PROVISION		—			—			(937	)		—			—			(937	)
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES		64,473			—			4,771			—			(69,244	)		—


Net Income (Loss)		47,655			(15,000	)		79,473			5,874			(69,244	)		48,758
NET INCOME ALLOCATED TO GENERAL PARTNER														(14,148	)		(14,148	)
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS														(1,103	)		(1,103	)


NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	47,655		$	(15,000	)	$	79,473		$	5,874		$	(84,495	)	$	33,507

(1): The parent is a co-issuer of the $450.0 million 6.875% Unsecured Notes that are included in the NGL Energy Finance Corp. column.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

	Year Ended March 31, 2013

	NGL Energy Partners LP (Parent)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	4,409,198		$	8,878		$	(309	)	$	4,417,767
COST OF SALES		—			4,038,251			1,168			(309	)		4,039,110
OPERATING COSTS AND EXPENSES:
Operating		—			164,944			4,855			—			169,799
General and administrative		—			52,461			237			—			52,698
Depreciation and amortization		—			66,916			1,937			—			68,853


Operating Income		—			86,626			681			—			87,307
OTHER INCOME (EXPENSE):
Interest expense		(13,041	)		(19,951	)		(48	)		46			(32,994	)
Loss on early extinguishment of debt		—			(5,769	)		—			—			(5,769	)
Other, net		—			1,666			(99	)		(46	)		1,521


Income (Loss) Before Income Taxes		(13,041	)		62,572			534			—			50,065
INCOME TAX PROVISION		��			(1,875	)		—			—			(1,875	)
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES		60,981			284			—			(61,265	)		—


Net Income		47,940			60,981			534			(61,265	)		48,190
NET INCOME ALLOCATED TO GENERAL PARTNER											(2,917	)		(2,917	)
NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS											(250	)		(250	)


NET INCOME ALLOCATED TO LIMITED PARTNERS	$	47,940		$	60,981		$	534		$	(64,432	)	$	45,023

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

	Year Ended March 31, 2012

	NGL Energy Partners LP (Parent)		Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—	$	1,310,473		$	225		$	(225	)	$	1,310,473
COST OF SALES		—		1,217,248			—			(225	)		1,217,023
OPERATING COSTS AND EXPENSES:
Operating		—		47,162			138			—			47,300
General and administrative		—		15,823			186			—			16,009
Depreciation and amortization		—		14,964			147			—			15,111


Operating Income (Loss)		—		15,276			(246	)		—			15,030
OTHER INCOME (EXPENSE):
Interest expense		—		(7,619	)		(46	)		45			(7,620	)
Other, net		—		1,100			—			(45	)		1,055


Income (Loss) Before Income Taxes		—		8,757			(292	)		—			8,465
INCOME TAX PROVISION		—		(601	)		—			—			(601	)
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES		7,876		(280	)		—			(7,596	)		—


Net Income (Loss)		7,876		7,876			(292	)		(7,596	)		7,864
NET INCOME ALLOCATED TO GENERAL PARTNER										(8	)		(8	)
NET LOSS ATTRIBUTABLE TO NONCONTROLLING INTERESTS										12			12


NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	7,876	$	7,876		$	(292	)	$	(7,592	)	$	7,868

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Comprehensive Income (Loss)
(U.S. Dollars in Thousands)

	Year Ended March 31, 2014

	NGL Energy Partners LP (Parent)(1)		NGL Energy Finance Corp.			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income (loss)	$	47,655	$	(15,000	)	$	79,473		$	5,874		$	(69,244	)	$	48,758
Other comprehensive loss, net of tax		—		—			(189	)		(71	)		—			(260	)


Comprehensive income (loss)	$	47,655	$	(15,000	)	$	79,284		$	5,803		$	(69,244	)	$	48,498

(1): The parent is a co-issuer of the $450.0 million 6.875% Unsecured Notes that are included in the NGL Energy Finance Corp. column.

	Year Ended March 31, 2013

	NGL Energy Partners LP (Parent)		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income	$	47,940	$	60,981	$	534		$	(61,265	)	$	48,190
Other comprehensive loss, net of tax		—		—		(7	)		—			(7	)


Comprehensive income	$	47,940	$	60,981	$	527		$	(61,265	)	$	48,183

	Year Ended March 31, 2012

	NGL Energy Partners LP (Parent)		Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income (loss)	$	7,876	$	7,876	$	(292	)	$	(7,596	)	$	7,864
Other comprehensive loss, net of tax		—		—		(25	)		—			(25	)


Comprehensive income (loss)	$	7,876	$	7,876	$	(317	)	$	(7,596	)	$	7,839

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)

	Year Ended March 31, 2014

	NGL Energy Partners LP (Parent)(1)			NGL Energy Finance Corp.			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(16,625	)	$	—		$	99,754		$	2,107		$	85,236
INVESTING ACTIVITIES:
Purchases of long-lived assets		—			—			(118,455	)		(46,693	)		(165,148	)
Acquisitions of businesses, including acquired working capital, net of cash acquired		(334,154	)		—			(932,373	)		(2,283	)		(1,268,810	)
Cash flows from commodity derivatives		—			—			(35,956	)		—			(35,956	)
Proceeds from sales of assets		—			—			12,884			11,776			24,660
Investments in unconsolidated entities		—			—			(11,515	)		—			(11,515	)
Distributions of capital from unconsolidated entities		—			—			1,591			—			1,591
Other		—			—			540			(735	)		(195	)


Net cash used in investing activities		(334,154	)		—			(1,083,284	)		(37,935	)		(1,455,373	)


FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities		—			—			2,545,500			—			2,545,500
Payments on revolving credit facilities		—			—			(2,101,000	)		—			(2,101,000	)
Issuances of notes		—			450,000			—			—			450,000
Proceeds from borrowings on other long-term debt		—			—			780			100			880
Payments on other long-term debt		—			—			(8,802	)		(17	)		(8,819	)
Debt issuance costs		(645	)		(12,286	)		(11,664	)		—			(24,595	)
Contributions		765			—			—			2,060			2,825
Distributions		(145,090	)		—			—			(840	)		(145,930	)
Proceeds from sale of common units, net of offering costs		650,155			—			—			—			650,155
Net changes in advances with consolidated entities		(153,225	)		(437,714	)		556,238			34,701			—


Net cash provided by financing activities		351,960			—			981,052			36,004			1,369,016


Net increase (decrease) in cash and cash equivalents		1,181			—			(2,478	)		176			(1,121	)
Cash and cash equivalents, beginning of period		—			—			11,206			355			11,561


Cash and cash equivalents, end of period	$	1,181		$	—		$	8,728		$	531		$	10,440

(1): The parent is a co-issuer of the $450.0 million 6.875% Unsecured Notes that are included in the NGL Energy Finance Corp. column.

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)

	Year Ended March 31, 2013

	NGL Energy Partners LP (Parent)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(12,428	)	$	140,794		$	4,268		$	132,634
INVESTING ACTIVITIES:
Purchases of long-lived assets		—			(59,903	)		(12,572	)		(72,475	)
Acquisitions of businesses, including acquired working capital, net of cash acquired		(452,087	)		(38,718	)		—			(490,805	)
Cash flows from commodity derivatives		—			11,579			—			11,579
Proceeds from sales of assets		—			5,080			—			5,080


Net cash used in investing activities		(452,087	)		(81,962	)		(12,572	)		(546,621	)


FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities		—			1,227,975			—			1,227,975
Payments on revolving credit facilities		—			(964,475	)		—			(964,475	)
Issuance of notes		250,000			—			—			250,000
Proceeds from borrowings on other long-term debt		—			634			19			653
Payments on other long-term debt		—			(4,837	)		—			(4,837	)
Debt issuance costs		(777	)		(19,412	)		—			(20,189	)
Contributions		510			—			403			913
Distributions		(71,608	)		—			(74	)		(71,682	)
Proceeds from sale of common units, net of offering costs		(642	)		—			—			(642	)
Net changes in advances with consolidated entities		286,991			(295,105	)		8,114			—


Net cash provided by (used in) financing activities		464,474			(55,220	)		8,462			417,716


Net increase (decrease) in cash and cash equivalents		(41	)		3,612			158			3,729
Cash and cash equivalents, beginning of period		41			7,594			197			7,832


Cash and cash equivalents, end of period	$	—		$	11,206		$	355		$	11,561

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Notes to Consolidated Financial Statements (Continued)

At March 31, 2014 and 2013, and for the Years Ended March 31, 2014, 2013, and 2012

Note 17—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)

	Year Ended March 31, 2012

	NGL Energy Partners LP (Parent)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	—		$	90,477		$	(148	)	$	90,329
INVESTING ACTIVITIES:
Purchases of long-lived assets		—			(6,667	)		(877	)		(7,544	)
Acquisitions of businesses, including acquired working capital, net of cash acquired		(291,097	)		(6,304	)		—			(297,401	)
Cash flows from commodity derivatives		—			6,464			—			6,464
Proceeds from sales of assets		—			1,238			—			1,238
Other		—			346			—			346


Net cash used in investing activities		(291,097	)		(4,923	)		(877	)		(296,897	)


FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities		—			478,900			—			478,900
Payments on revolving credit facilities		—			(329,900	)		—			(329,900	)
Payments on other long-term debt		—			(1,278	)		—			(1,278	)
Debt issuance costs		—			(2,380	)		—			(2,380	)
Contributions		—			—			440			440
Distributions		(19,060	)		—			—			(19,060	)
Proceeds from sale of common units, net of offering costs		74,759			—			—			74,759
Repurchase of common units		(3,418	)		—			—			(3,418	)
Net changes in advances with consolidated entities		238,816			(239,476	)		660			—


Net cash provided by (used in) financing activities		291,097			(94,134	)		1,100			198,063


Net increase (decrease) in cash and cash equivalents		—			(8,580	)		75			(8,505	)
Cash and cash equivalents, beginning of period		41			16,174			122			16,337

							��
Cash and cash equivalents, end of period	$	41		$	7,594		$	197		$	7,832

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Unaudited Condensed Consolidated Balance Sheets

(U.S. Dollars in Thousands, except unit amounts)

	September 30, 2014			March 31, 2014

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	11,823		$	10,440
Accounts receivable—trade, net of allowance for doubtful accounts of $2,816 and $2,822, respectively		1,433,117			900,904
Accounts receivable—affiliates		41,706			7,445
Inventories		941,589			310,160
Prepaid expenses and other current assets		156,818			80,350


Total current assets		2,585,053			1,309,299
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $153,057 and $109,564, respectively		1,433,313			829,346
GOODWILL		1,170,490			1,107,006
INTANGIBLE ASSETS, net of accumulated amortization of $166,484 and $116,728, respectively		838,088			714,956
INVESTMENTS IN UNCONSOLIDATED ENTITIES		482,644			189,821
OTHER NONCURRENT ASSETS		42,091			16,795


Total assets	$	6,551,679		$	4,167,223




LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	1,345,024		$	740,211
Accounts payable—affiliates		85,307			76,846
Accrued expenses and other payables		218,482			141,690
Advance payments received from customers		106,105			29,965
Current maturities of long-term debt		5,062			7,080


Total current liabilities		1,759,980			995,792
LONG-TERM DEBT, net of current maturities		2,437,351			1,629,834
OTHER NONCURRENT LIABILITIES		39,518			9,744
COMMITMENTS AND CONTINGENCIES
EQUITY, per accompanying statement:
General partner, representing a 0.1% interest, 88,634 and 79,420 notional units at September 30, 2014 and March 31, 2014, respectively		(39,690	)		(45,287	)
Limited partners, representing a 99.9% interest—
Common units, 88,545,764 and 73,421,309 units issued and outstanding at September 30, 2014 and March 31, 2014, respectively		1,785,823			1,570,074
Subordinated units, 5,919,346 units issued and outstanding at March 31, 2014		—			2,028
Accumulated other comprehensive loss		(73	)		(236	)
Noncontrolling interests		568,770			5,274


Total equity		2,314,830			1,531,853


Total liabilities and equity	$	6,551,679		$	4,167,223

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Unaudited Condensed Consolidated Statements of Operations

Three Months and Six Months Ended September 30, 2014 and 2013

(U.S. Dollars in Thousands, except unit and per unit amounts)

	Three Months Ended September 30,						Six Months Ended September 30,

	2014			2013			2014			2013
REVENUES:
Crude oil logistics	$	2,111,143		$	1,014,008		$	4,040,426		$	1,944,802
Water solutions		52,719			34,190			100,033			54,703
Liquids		539,753			484,874			1,014,910			845,833
Retail propane		68,358			59,380			146,260			131,597
Refined products and renewables		2,607,220			—			3,724,717			—
Other		1,333			1,485			2,794			2,959


Total Revenues		5,380,526			1,593,937			9,029,140			2,979,894


COST OF SALES:
Crude oil logistics		2,083,712			992,135			3,981,351			1,901,354
Water solutions		(9,439	)		3,782			1,134			4,365
Liquids		514,064			459,394			976,080			809,645
Retail propane		39,894			33,539			87,418			76,562
Refined products and renewables		2,550,851			—			3,665,164			—
Other		383			—			2,371			—


Total Cost of Sales		5,179,465			1,488,850			8,713,518			2,791,926


OPERATING COSTS AND EXPENSES:
Operating		101,553			55,769			169,421			104,814
General and administrative		41,639			14,312			69,512			32,766
Depreciation and amortization		50,099			25,061			89,474			47,785


Operating Income (Loss)		7,770			9,945			(12,785	)		2,603
OTHER INCOME (EXPENSE):
Earnings of unconsolidated entities		3,697			—			6,262			—
Interest expense		(28,651	)		(11,060	)		(49,145	)		(21,682	)
Other, net		(617	)		419			(1,008	)		469


Loss Before Income Taxes		(17,801	)		(696	)		(56,676	)		(18,610	)
INCOME TAX (PROVISION) BENEFIT		1,922			(236	)		887			170


Net Loss		(15,879	)		(932	)		(55,789	)		(18,440	)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER		(11,056	)		(2,451	)		(20,437	)		(4,139	)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS		(3,345	)		(9	)		(3,410	)		(134	)


NET LOSS ALLOCATED TO LIMITED PARTNERS	$	(30,280	)	$	(3,392	)	$	(79,636	)	$	(22,713	)




BASIC AND DILUTED LOSS PER COMMON UNIT	$	(0.34	)	$	(0.05	)	$	(0.93	)	$	(0.37	)




BASIC AND DILUTED WEIGHTED AVERAGE COMMON UNITS OUTSTANDING		88,331,653			58,909,389			81,267,742			53,336,969

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Unaudited Condensed Consolidated Statements of Comprehensive Loss

Three Months and Six Months Ended September 30, 2014 and 2013

(U.S. Dollars in Thousands)

	Three Months Ended September 30,						Six Months Ended September 30,

	2014			2013			2014			2013
Net loss	$	(15,879	)	$	(932	)	$	(55,789	)	$	(18,440	)
Other comprehensive income (loss)		(22	)		(5	)		163			(30	)


Comprehensive loss	$	(15,901	)	$	(937	)	$	(55,626	)	$	(18,470	)

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Unaudited Condensed Consolidated Statement of Changes in Equity

(U.S. Dollars in Thousands, except unit amounts)

				Limited Partners

				Limited Partners											Accumulated Other Comprehensive Loss
	General Partner			Common Units		Amount			Subordinated Units			Amount			Accumulated Other Comprehensive Loss			Noncontrolling Interests			Total Equity
BALANCES AT MARCH 31, 2014	$	(45,287	)		73,421,309	$	1,570,074			5,919,346		$	2,028		$	(236	)	$	5,274		$	1,531,853
Distributions		(15,235	)		—		(89,025	)		—			(6,748	)		—			(8,654	)		(119,662	)
Contributions		395			—		—			—			—			—			—			395
Sales of units, net of issuance costs		—			8,767,100		370,446			—			—			—			—			370,446
Conversion of subordinated units to common units		—			5,919,346		(8,733	)		(5,919,346	)		8,733			—			—			—
Equity issued pursuant to incentive compensation plan		—			438,009		18,684			—			—			—			—			18,684
Business combinations		—			—		—			—			—			—			568,740			568,740
Net income (loss)		20,437			—		(75,623	)		—			(4,013	)		—			3,410			(55,789	)
Other comprehensive income		—			—		—			—			—			163			—			163


BALANCES AT SEPTEMBER 30, 2014	$	(39,690	)		88,545,764	$	1,785,823			—		$	—		$	(73	)	$	568,770		$	2,314,830

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Unaudited Condensed Consolidated Statements of Cash Flows

(U.S. Dollars in Thousands)

	Six Months Ended September 30,

	2014			2013
OPERATING ACTIVITIES:
Net loss	$	(55,789	)	$	(18,440	)
Adjustments to reconcile net loss to net cash used in operating activities:
Depreciation and amortization, including debt issuance cost amortization		97,624			51,821
Non-cash equity-based compensation expense		11,758			6,762
Loss on disposal or impairment of assets		4,566			2,163
Provision for doubtful accounts		1,347			781
Commodity derivative (gain) loss		(38,496	)		17,881
Earnings of unconsolidated entities		(6,262	)		—
Distributions from unconsolidated entities		5,180			—
Other		(837	)		8
Changes in operating assets and liabilities, exclusive of acquisitions:
Accounts receivable—trade		(358,497	)		(28,013	)
Accounts receivable—affiliates		(33,733	)		19,812
Inventories		(203,965	)		(226,727	)
Prepaid expenses and other assets		(56,109	)		(10,830	)
Accounts payable—trade		463,767			60,725
Accounts payable—affiliates		8,392			11,529
Accrued expenses and other liabilities		25,719			18,162
Advance payments received from customers		73,700			45,622


Net cash used in operating activities		(61,635	)		(48,744	)


INVESTING ACTIVITIES:
Purchases of long-lived assets		(82,851	)		(67,399	)
Acquisitions of businesses, including acquired working capital, net of cash acquired		(658,764	)		(392,605	)
Cash flows from commodity derivatives		4,327			(19,074	)
Proceeds from sales of assets		8,741			2,224
Investments in unconsolidated entities		(26,390	)		—
Distributions of capital from unconsolidated entities		4,649			—


Net cash used in investing activities		(750,288	)		(476,854	)


FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities		1,979,500			1,061,500
Payments on revolving credit facilities		(1,804,000	)		(893,000	)
Issuance of notes		400,000			—
Proceeds from borrowings on other long-term debt		—			880
Payments on other long-term debt		(4,175	)		(4,507	)
Debt issuance costs		(9,198	)		(2,218	)
Contributions		395			2,444
Distributions to owners		(111,008	)		(60,623	)
Distributions to noncontrolling interest partners		(8,654	)		—
Proceeds from sale of common units, net of offering costs		370,446			415,089


Net cash provided by financing activities		813,306			519,565


Net increase (decrease) in cash and cash equivalents		1,383			(6,033	)
Cash and cash equivalents, beginning of period		10,440			11,561


Cash and cash equivalents, end of period	$	11,823		$	5,528

The accompanying notes are an integral part of these condensed consolidated financial statements.

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Notes to Unaudited Condensed Consolidated Financial Statements

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 1—Organization and Operations

NGL Energy Partners LP ("we," "us," "our," or the "Partnership") is a Delaware limited partnership. NGL Energy Holdings LLC serves as our general partner. At September 30, 2014, our operations include:

•: Our crude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased and owned railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.
•: Our water solutions segment, the assets of which include water treatment and disposal facilities. Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, and from the sale of recycled water and recovered hydrocarbons.
•: Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 22 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, petrochemical plants, and other participants in the wholesale markets.
•: Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.
•: Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.7% limited partner interest in TransMontaigne Partners L.P. ("TLP"), which conducts refined products terminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC ("BOSTCO") and a 50% interest in Frontera Brownsville LLC ("Frontera"), which are entities that own refined products storage facilities.

Note 2—Significant Accounting Policies

Basis of Presentation

The unaudited condensed consolidated financial statements as of and for the three months and six months ended September 30, 2014 and 2013 include our accounts and those of our controlled subsidiaries. Investments where we do not have the ability to exercise control, but do have the ability to exercise significant influence, are accounted for using the equity method of accounting. All significant intercompany transactions and account balances have been eliminated in consolidation. The unaudited condensed consolidated balance sheet at March 31, 2014 is derived from audited financial statements. We have made certain reclassifications to prior period financial statements to conform to classification

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

methods used in fiscal year 2015. These reclassifications had no impact on previously reported amounts of equity or net income.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("GAAP") for interim consolidated financial information in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed consolidated financial statements include all adjustments that we consider necessary for a fair presentation of our consolidated financial position and results of operations for the interim periods presented. Such adjustments consist of only normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed consolidated financial statements do not include all the information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed consolidated financial statements should be read in conjunction with our audited consolidated financial statements for the fiscal year ended March 31, 2014 included in elsewhere in this prospectus. Due to the seasonal nature of our natural gas liquids operations and other factors, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Use of Estimates

Significant Accounting Policies

Our significant accounting policies are consistent with those disclosed in Note 2 of our audited consolidated financial statements included elsewhere in this prospectus.

Revenue Recognition

We record revenues from product sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. We record terminaling, transportation, storage, and service revenues at the time the service is performed, and we record tank and other rentals over the term of the lease. Pursuant to terminaling services agreements with certain of our throughput customers, we are entitled to the volume of product gained resulting from differences in the measurement of product volumes received and distributed at our terminaling facilities. Such measurement differentials occur as the result of the inherent variances in measurement devices and methodology. We recognize as revenue the net proceeds from the sale of the product gained. Revenues for our water solutions business are recognized upon receipt of the wastewater at our disposal facilities.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

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

Fair Value Measurements

We use the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

•: Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that we have the ability to access at the measurement date.
•: Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means. Instruments categorized in Level 2 include non-exchange traded derivatives such as over-the-counter commodity price swap and option contracts and interest rate protection agreements. The majority of our fair value measurements related to our derivative financial instruments were categorized as Level 2 at September 30, 2014 and March 31, 2014 (see Note 11). We determine the fair value of all our derivative financial instruments utilizing pricing models for significantly similar instruments. Inputs to the pricing model include publicly available prices and forward curves generated from a compilation of data gathered from third parties.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

•: Level 3—Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. We did not have any fair value measurements categorized as Level 3 at September 30, 2014 or March 31, 2014.

Supplemental Cash Flow Information

Supplemental cash flow information is as follows:

	Three Months Ended September 30,				Six Months Ended September 30,

	2014		2013		2014		2013
	(in thousands)
Interest paid, exclusive of debt issuance costs and letter of credit fees	$	10,445	$	8,423	$	$36,429	$	16,908




Income taxes paid	$	1,241	$	369	$	2,246	$	650




Value of common units issued in business combinations	$	—	$	80,619	$	—	$	80,619

Cash flows from settlements of commodity derivative instruments are classified as cash flows from investing activities in the condensed consolidated statements of cash flows, and adjustments to the fair value of commodity derivative instruments are included in the reconciliation of net loss to net cash used in operating activities.

Inventories

We value our inventories at the lower of cost or market, with cost determined using either the weighted-average cost or the first in, first out (FIFO) methods, including the cost of transportation and storage. In performing this analysis, we take into consideration fixed-price forward sale commitments and the opportunity to transfer propane inventory from our wholesale business to our retail business for sale in the retail markets.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

Inventories consist of the following:

	September 30, 2014		March 31, 2014

	(in thousands)
Crude oil	$	136,722	$	156,473
Natural gas liquids—
Propane		207,694		85,159
Butane		84,822		15,106
Other		27,091		3,945
Refined products—
Gasoline		219,111		15,597
Diesel		214,567		7,298
Other		3,675		314
Renewables		36,517		11,778
Other		11,390		14,490


Total	$	941,589	$	310,160

Investments in Unconsolidated Entities

In December 2013, as part of our acquisition of Gavilon, LLC ("Gavilon Energy"), we acquired a 50% interest in Glass Mountain Pipeline, LLC ("Glass Mountain") and an 11% interest in a limited liability company that owns an ethanol production facility. In June 2014, we acquired an interest in a limited liability company that operates a water supply business. On July 1, 2014, as part of our acquisition of TransMontaigne Inc. ("TransMontaigne"), we acquired TLP, which owns a 42.5% interest in BOSTCO and a 50% interest in Frontera. We account for these investments using the equity method of accounting. Under the equity method, we do not report the individual assets and liabilities of these entities on our condensed consolidated balance sheets; instead, our ownership interests are reported within investments in unconsolidated entities on our condensed consolidated balance sheets. Under the equity method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions paid and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the book value of the net assets of the investment entity.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

Our investments in unconsolidated entities consist of the following:

	September 30, 2014		March 31, 2014

	(in thousands)
Glass Mountain(1)	$	189,847	$	181,488
Ethanol production facility		9,361		8,333
Water supply company		15,026		—
BOSTCO(2)		244,092		—
Frontera		24,318		—


Total	$	482,644	$	189,821

(1): When we acquired Gavilon we recorded the investment in Glass Mountain at fair value. The fair value of our investment in Glass Mountain exceeds our share of the historical net book value of Glass Mountain's net assets by approximately $70 million. This difference relates primarily to goodwill and customer relationships.
(2): When we acquired TransMontaigne, we recorded the investment in BOSTCO at fair value. The fair value of our investment in BOSTCO exceeds our share of the historical net book value of BOSTCO's net assets by approximately $24 million.

Accrued Expenses and Other Payables

Accrued expenses and other payables consist of the following:

	September 30, 2014		March 31, 2014

	(in thousands)
Accrued compensation and benefits	$	49,146	$	45,006
Derivative liabilities		39,023		42,214
Product exchange liabilities		43,185		3,719
Accrued interest		23,945		18,668
Income and other tax liabilities		38,255		13,421
Other		24,928		18,662


Total	$	218,482	$	141,690

Business Combination Measurement Period

We record the assets acquired and liabilities assumed in a business combination at their acquisition-date fair values. Pursuant to GAAP, an entity is allowed a reasonable period of time (not to exceed one year) to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. As described in Note 4, certain of our acquisitions are still within this measurement period, and as a result, the acquisition-date fair values we have recorded for the assets acquired and liabilities assumed are subject to change. Also as

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 2—Significant Accounting Policies (Continued)

described in Note 4, we made certain adjustments during the six months ended September 30, 2014 to our estimates of the acquisition-date fair values of assets acquired and liabilities assumed in business combinations that occurred during the year ended March 31, 2014.

Noncontrolling Interests

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

On July 1, 2014, as part of our acquisition of TransMontaigne, we acquired a 19.7% limited partner interest in TLP. We have attributed net earnings allocable to TLP's limited partners to the controlling and noncontrolling interests based on the relative ownership interests in TLP as well as including certain adjustments related to our acquisition accounting. Net earnings allocable to TLP's limited partners are net of the earnings allocable to TLP's general partner interest. The earnings allocable to TLP's general partner interest include the distributions of available cash (as defined by TLP's partnership agreement) attributable to the period to TLP's general partner interest and incentive distribution rights, net of adjustments for TLP's general partner's share of undistributed earnings. Undistributed earnings are allocated to TLP's limited partners and TLP's general partner interest based on their respective sharing of earnings or losses specified in TLP's partnership agreement, which is based on their ownership percentages of 98% and 2%, respectively.

Note 3—Earnings Per Unit

Our earnings per common unit were computed as follows:

	Three Months Ended September 30,						Six Months Ended September 30,

	2014			2013			2014			2013
	(in thousands, except unit and per unit amounts)
Net loss attributable to parent equity	$	(19,224	)	$	(941	)	$	(59,199	)	$	(18,574	)
Less: net income allocated to general partner(1)		(11,056	)		(2,451	)		(20,437	)		(4,139	)
Net loss allocated to subordinated unitholders(2)		—			562			4,013			3,076


Net loss allocated to common unitholders	$	(30,280	)	$	(2,830	)	$	(75,623	)	$	(19,637	)




Weighted average common units outstanding		88,331,653			58,909,389			81,267,742			53,336,969




Loss per common unit—basic and diluted	$	(0.34	)	$	(0.05	)	$	(0.93	)	$	(0.37	)

(1): The net income allocated to the general partner includes distributions to which it is entitled as the holder of incentive distribution rights, which are described in Note 10.
(2): All outstanding subordinated units converted to common units in August 2014. Since the subordinated units did not share in the distribution of cash generated during the three months

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 3—Earnings Per Unit (Continued)

ended September 30, 2014, we did not allocate any earnings or loss during this period to the subordinated unitholders. During the three months ended June 30, 2014 and the six months ended September 30, 2013, 5,919,346 subordinated units were outstanding. The loss per subordinated unit was $(0.68) for the three months ended June 30, 2014, $(0.09) for the three months ended September 30, 2013, and $(0.52) for the six months ended September 30, 2013.

The restricted units described in Note 10 were antidilutive during the three months and six months ended September 30, 2014 and 2013, but could impact earnings per unit in future periods.

Note 4—Acquisitions

Year Ending March 31, 2015

TransMontaigne Inc.

On July 1, 2014, we acquired TransMontaigne for $174.2 million of cash, net of cash acquired. As part of this transaction, we also purchased $380.4 million of inventory from the previous owner of TransMontaigne (including $346.9 million paid at closing and $33.5 million subsequently paid as the working capital settlement process progressed). The operations of TransMontaigne include the marketing of refined products and crude oil. As part of this transaction, we acquired the 2.0% general partner interest, the incentive distribution rights, and a 19.7% limited partner interest in TLP, and assumed certain terminaling service agreements with TLP from an affiliate of the previous owner of TransMontaigne. The acquisition agreement contemplates a post-closing adjustment to the purchase price for certain working capital items. We estimate that we will pay an additional $27.5 million once the working capital settlement process has been completed.

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in this business combination. The estimates of fair value reflected at September 30, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2015. We have preliminarily

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):


Cash and cash equivalents	$	1,469
Accounts receivable—trade		197,349
Accounts receivable—affiliates		528
Inventories		426,913
Prepaid expenses and other current assets		15,373
Property, plant and equipment:
Refined products terminal assets (20 years)		418,405
Buildings and leasehold improvements (20 years)		10,339
Crude oil tanks and related equipment (20 years)		28,666
Vehicles		1,565
Land		56,095
Information technology equipment		7,851
Other		12,592
Construction in progress		4,487
Goodwill(1)		29,118
Intangible assets:
Customer relationships (7 years)		50,000
Pipeline capacity rights (30 years)		87,000
Trade names (indefinite life)		5,000
Equity method investments		250,000
Other noncurrent assets		3,911
Accounts payable—trade		(140,597	)
Accounts payable—affiliates		(69	)
Accrued expenses and other payables		(73,565	)
Advance payments received from customers		(1,919	)
Long-term debt		(234,000	)
Other noncurrent liabilities		(34,856	)
Noncontrolling interests		(567,120	)


Fair value of net assets acquired	$	554,535

(1): Included in the refined products and renewables segment.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

The intangible asset for pipeline capacity rights relates to capacity allocations on a third-party refined products pipeline. Demand for use of this pipeline exceeds the pipeline's capacity, and the limited capacity is allocated based on a shipper's historical shipment volumes.

The fair value of the noncontrolling interests was calculated by multiplying the closing price of TLP's common units on the acquisition date by the number of TLP common units held by parties other than us.

We recorded in the acquisition accounting a liability of $2.5 million related to certain crude oil contracts with terms that were unfavorable at current market conditions. We amortized this balance to cost of sales during the three months ended September 30, 2014.

Employees of TransMontaigne participate in a plan whereby they are entitled to certain termination benefits in the event of a change in control of TransMontaigne and a subsequent change in job status. We recorded expense of $2.7 million during the three months ended September 30, 2014 related to these termination benefits, and we may record additional expense in future quarters as we continue our integration efforts.

The operations of TransMontaigne have been included in our condensed consolidated statements of operations since TransMontaigne was acquired on July 1, 2014. Our condensed consolidated statements of operations for the three months and six months ended September 30, 2014 include revenues of $1.1 billion and an operating loss of $0.3 million that were generated by the operations of TransMontaigne. We have not provided supplemental pro forma financial information as though the business combination had occurred on April 1, 2013. The previous owner of TransMontaigne conducted trading operations, whereas we strive to generate reliable and predictable cash flows. Because of the difference in strategies between the pre-acquisition and post-acquisition periods, the pre-acquisition operations of TransMontaigne have limited importance as an indicator of post-acquisition results.

Water Solutions Facilities

We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in these business combinations. The estimates of fair value reflected at September 30, 2014 are subject to change, and such changes could be material. We expect to complete this process prior to finalizing our financial statements for the quarter ending June 30, 2015. We have

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows (in thousands):


Accounts receivable—trade	$	939
Inventories		253
Prepaid expenses and other current assets		62
Property, plant and equipment:
Water treatment facilities and equipment (5 - 40 years)		23,066
Buildings and leasehold improvements (3 - 7 years)		2,599
Land		1,010
Other (7 years)		33
Goodwill		57,777
Other noncurrent assets		50
Accounts payable—trade		(58	)
Accrued expenses and other payables		(1,092	)
Other noncurrent liabilities		(149	)
Noncontrolling interest		(1,620	)


Fair value of net assets acquired	$	82,870

Goodwill represents the excess of the consideration paid for the acquired business over the fair value of the individual assets acquired, net of liabilities assumed. Goodwill primarily represents the value of synergies between the acquired entity and the Partnership and the opportunity to use the acquired business as a platform for growth. We estimate that all of the goodwill will be deductible for federal income tax purposes.

The operations of these water disposal facilities have been included in our condensed consolidated statement of operations since their acquisition date. Our condensed consolidated statement of operations for the quarter ended September 30, 2014 includes revenues of $7.1 million and operating income of $1.5 million that were generated by the operations of these water disposal facilities.

Retail Propane Acquisitions

During the six months ended September 30, 2014, we completed three acquisitions of retail propane businesses. On a combined basis, we paid $6.4 million of cash to acquire these assets and operations. The agreements for these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in certain of these business combinations, and as a result, the estimates of fair value reflected at September 30, 2014 are subject to change.

Water Supply Company

On June 9, 2014, we paid cash of $15.0 million in exchange for an interest in a water supply company operating in the DJ Basin. We account for this investment using the equity method of accounting.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

Year Ended March 31, 2014

As described in Note 2, pursuant to GAAP, an entity is allowed a reasonable period of time to obtain the information necessary to identify and measure the fair value of the assets acquired and liabilities assumed in a business combination. The business combinations for which this measurement period was still open as of March 31, 2014 are summarized below.

Gavilon Energy

The assets of Gavilon Energy include crude oil terminals in Oklahoma, Texas, and Louisiana, a 50% interest in Glass Mountain, which owns a crude oil pipeline that originates in western Oklahoma and terminates in Cushing, Oklahoma, and an 11% interest in an ethanol production facility in the Midwest. The operations of Gavilon Energy include the marketing of crude oil, refined products, ethanol, biodiesel, and natural gas liquids and owned and leased crude oil storage in Cushing, Oklahoma.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

During the three months ended September 30, 2014, we completed the acquisition accounting for this business combination. The following table presents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for this acquisition:

	Final			Estimated at at March 31, 2014			Change

	(in thousands)
Accounts receivable—trade	$	326,484		$	349,529		$	(23,045	)
Accounts receivable—affiliates		2,564			2,564			—
Inventories		107,430			107,430			—
Prepaid expenses and other current assets		68,322			68,322			—
Property, plant and equipment:
Vehicles (3 years)		327			791			(464	)
Crude oil tanks and related equipment (3 - 40 years)		83,797			77,429			6,368
Information technology equipment (3 - 7 years)		4,049			4,046			3
Buildings and leasehold improvements (3 - 40 years)		7,817			7,716			101
Land		6,427			6,427			—
Tank bottoms		16,930			15,230			1,700
Other (7 years)		162			170			(8	)
Construction in progress		7,180			7,190			(10	)
Goodwill(1)		342,769			359,169			(16,400	)
Intangible assets:
Customer relationships (10 - 20 years)		107,950			101,600			6,350
Lease agreements (1 - 5 years)		8,700			8,700			—
Pipeline capacity rights (30 years)		7,800			—			7,800
Investments in unconsolidated entities		183,000			178,000			5,000
Other noncurrent assets		2,287			9,918			(7,631	)
Accounts payable—trade		(342,792	)		(342,792	)		—
Accounts payable—affiliates		(2,585	)		(2,585	)		—
Accrued expenses and other payables		(49,447	)		(70,999	)		21,552
Advance payments received from customers		(10,667	)		(10,667	)		—
Other noncurrent liabilities		(46,056	)		(44,740	)		(1,316	)


Fair value of net assets acquired	$	832,448		$	832,448		$	—

(1): Primarily included in the crude oil logistics segment.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

The acquisition method of accounting requires that executory contracts that are at unfavorable terms relative to current market conditions at the acquisition date be recorded as assets or liabilities in the acquisition accounting. Since certain crude oil storage lease commitments were at unfavorable terms relative to current market conditions, we recorded a liability of $15.9 million related to these lease commitments in the acquisition accounting, and we amortized $5.0 million of this balance through cost of sales during the six months ended September 30, 2014. We will amortize the remainder of this liability over the term of the leases. The future amortization of this liability is shown below (in thousands):

Year Ending March 31,

2015 (six months)	$	3,670
2016		4,040
2017		360

Certain personnel who were employees of Gavilon Energy are entitled to a bonus, half of which was payable upon successful completion of the business combination and the remainder of which is payable in December 2014. We are recording this as compensation expense over the vesting period. We recorded expense of $5.2 million during the six months ended September 30, 2014 related to these bonuses, and we expect to record an additional expense of $1.6 million during the quarter ending December 31, 2014.

Oilfield Water Lines, LP

On August 2, 2013, we completed a business combination with entities affiliated with Oilfield Water Lines LP (collectively, "OWL"), whereby we acquired water disposal and transportation assets in Texas. We issued 2,463,287 common units, valued at $68.6 million, and paid $167.7 million of cash, net of cash acquired, in exchange for OWL. During the three months ended June 30, 2014, we completed the acquisition accounting for this business combination. The following table presents the final

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed in the acquisition of OWL:

	Final			Estimated at March 31, 2014			Change

	(in thousands)
Accounts receivable—trade	$	6,837		$	7,268		$	(431	)
Inventories		154			154			—
Prepaid expenses and other current assets		402			402			—
Property, plant and equipment:
Vehicles (5 - 10 years)		8,143			8,157			(14	)
Water treatment facilities and equipment (3 - 30 years)		23,173			23,173			—
Buildings and leasehold improvements (7 - 30 years)		2,198			2,198			—
Land		710			710			—
Other (3 - 5 years)		53			53			—
Intangible assets:
Customer relationships (8 - 10 years)		110,000			110,000			—
Non-compete agreements (3 years)		2,000			2,000			—
Goodwill		90,144			89,699			445
Accounts payable—trade		(6,469	)		(6,469	)		—
Accrued expenses and other payables		(992	)		(992	)		—
Other noncurrent liabilities		(64	)		(64	)		—


Fair value of net assets acquired	$	236,289		$	236,289		$	—

Other Water Solutions Acquisitions

During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our water solutions operations in Texas. On a combined basis, we issued 222,381 common units, valued at $6.8 million, and paid $151.6 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. During the three months ended June 30, 2014, we completed the acquisition accounting for these business combinations. The following table presents the final

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions:

	Final			Estimated at March 31, 2014			Change

	(in thousands)
Accounts receivable—trade	$	2,146		$	2,146		$	—
Inventories		192			192			—
Prepaid expenses and other current assets		62			61			1
Property, plant and equipment:
Vehicles (5 - 10 years)		76			90			(14	)
Water treatment facilities and equipment (3 - 30 years)		11,717			14,394			(2,677	)
Buildings and leasehold improvements (7 - 30 years)		3,278			1,906			1,372
Land		207			206			1
Other (3 - 5 years)		12			12			—
Intangible assets:
Customer relationships (8 - 10 years)		72,000			72,000			—
Trade names (indefinite life)		3,325			3,325			—
Non-compete agreements (3 years)		260			260			—
Water facility development agreement (5 years)		14,000			14,000			—
Water facility option agreement		2,500			2,500			—
Goodwill		49,067			47,750			1,317
Accounts payable—trade		(119	)		(119	)		—
Accrued expenses and other payables		(293	)		(293	)		—
Other noncurrent liabilities		(64	)		(64	)		—


Fair value of net assets acquired	$	158,366		$	158,366		$	—

As part of one of these business combinations, we entered into an option agreement with the seller of the business whereby we had the option to purchase a saltwater disposal facility that was under construction. We recorded an intangible asset of $2.5 million at the acquisition date related to this option agreement. On March 1, 2014, we purchased the saltwater disposal facility for additional cash consideration of $3.7 million.

In addition, as part of one of these business combinations, we entered into a development agreement that provides us a right to purchase water disposal facilities that may be developed by the seller through June 2018. On March 1, 2014, we purchased our first water disposal facility pursuant to the development agreement for $21.0 million.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

have preliminarily estimated the fair values of the assets acquired (and useful lives) and liabilities assumed as follows:

	Estimated At

	September 30, 2014			March 31, 2014			Change
	(in thousands)
Accounts receivable—trade	$	124		$	245		$	(121	)
Inventories		119			197			(78	)
Property, plant and equipment:
Water treatment facilities and equipment (3 - 30 years)		10,539			10,540			(1	)
Buildings and leasehold improvements (7 - 30 years)		1,130			1,130			—
Land		213			213			—
Other (3 - 5 years)		1			1			—
Goodwill		15,443			15,281			162
Accounts payable—trade		(232	)		(263	)		31
Accrued expenses and other payables		—			(7	)		7
Other noncurrent liabilities		(50	)		(50	)		—


Fair value of net assets acquired	$	27,287		$	27,287		$	—

Crude Oil Logistics Acquisitions

During the year ended March 31, 2014, we completed two separate acquisitions of businesses to expand our crude oil logistics operations in Texas and Oklahoma. On a combined basis, we issued 175,211 common units, valued at $5.3 million, and paid $67.8 million of cash, net of cash acquired, in exchange for the assets and operations of these businesses. During the three months ended June 30, 2014, we completed the acquisition accounting for these business combinations. The following table

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 4—Acquisitions (Continued)

presents the final calculation of the fair values of the assets acquired (and useful lives) and liabilities assumed for these acquisitions:

	Final			Estimated at March 31, 2014			Change

	(in thousands)
Accounts receivable—trade	$	1,221		$	1,235		$	(14	)
Inventories		1,021			1,021			—
Prepaid expenses and other current assets		58			54			4
Property, plant and equipment:
Vehicles (5 - 10 years)		2,980			2,977			3
Buildings and leasehold improvements (5 - 30 years)		58			280			(222	)
Crude oil tanks and related equipment (2 - 30 years)		3,822			3,462			360
Barges and towboats (20 years)		20,065			20,065			—
Other (3 - 5 years)		57			53			4
Intangible assets:
Customer relationships (3 years)		13,300			6,300			7,000
Non-compete agreements (3 years)		35			35			—
Trade names (indefinite life)		530			530			—
Goodwill		30,730			37,867			(7,137	)
Accounts payable—trade		(521	)		(665	)		144
Accrued expenses and other payables		(266	)		(124	)		(142	)


Fair value of net assets acquired	$	73,090		$	73,090		$	—

Retail Propane and Liquids Acquisitions

During the year ended March 31, 2014, we completed four acquisitions of retail propane businesses and the acquisition of four natural gas liquids terminals. On a combined basis, we paid $21.9 million of cash to acquire these assets and operations. The agreements for certain of these acquisitions contemplate post-closing payments for certain working capital items. We are in the process of identifying and determining the fair value of the assets acquired and liabilities assumed in certain of these business combinations, and as a result, the estimates of fair value reflected at September 30, 2014 are subject to change.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 5—Property, Plant and Equipment

Our property, plant and equipment consists of the following:

Description and Estimated Useful Lives	September 30, 2014			March 31, 2014

	(in thousands)
Natural gas liquids terminal assets (2 - 30 years)	$	127,258		$	75,141
Refined products and renewables terminal assets and equipment (20 years)		419,411			—
Retail propane equipment (2 - 30 years)		167,825			160,758
Vehicles and railcars (3 - 25 years)		172,799			152,676
Water treatment facilities and equipment (3 - 30 years)		209,644			180,985
Crude oil tanks and related equipment (2 - 40 years)		145,287			106,125
Barges and towboats (5 - 40 years)		56,094			52,217
Information technology equipment (3 - 7 years)		30,519			20,768
Buildings and leasehold improvements (3 - 40 years)		77,415			60,004
Land		88,350			30,241
Tank bottoms		17,679			13,403
Other (3 - 30 years)		16,770			6,341
Construction in progress		57,319			80,251


		1,586,370			938,910
Less: Accumulated depreciation		(153,057	)		(109,564	)


Net property, plant and equipment	$	1,433,313		$	829,346

Depreciation expense was $28.4 million and $13.7 million during the three months ended September 30, 2014 and 2013, respectively, and $46.9 million and $27.2 million during the six months ended September 30, 2014 and 2013, respectively.

Crude oil volumes required for the operation of storage tanks, known as tank bottoms, are recorded at historical cost. Tank bottoms are the volume of crude oil that must be maintained in a storage tank to enable operation of the storage tank. We recover tank bottom crude oil when we no longer use the storage tanks or the storage tanks are removed from service. At September 30, 2014, tank bottoms consisted of approximately 185,000 barrels.

Note 6—Goodwill and Intangible Assets

The changes in the balance of goodwill during the six months ended September 30, 2014 were as follows (in thousands):


Beginning of period	$	1,107,006
Revisions to acquisition accounting (Note 4)		(21,614	)
Acquisitions (Note 4)		86,895
Disposal		(1,797	)


End of period	$	1,170,490

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 6—Goodwill and Intangible Assets (Continued)

Goodwill by reportable segment is as follows:

	September 30, 2014		March 31, 2014

	(in thousands)
Crude oil logistics	$	579,845	$	606,383
Water solutions		320,106		262,203
Liquids		91,135		90,135
Retail propane		114,285		114,285
Refined products and renewables		65,119		34,000


Total	$	1,170,490	$	1,107,006

Our intangible assets consist of the following:

		September 30, 2014				March 31, 2014

	Amortizable Lives	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
		(in thousands)
Amortizable—
Customer relationships(1)	3 - 20 years	$	761,992	$	119,439	$	697,405	$	83,261
Pipeline capacity rights	30 years		94,800		942		—		—
Water facility development agreement	5 years		14,000		3,500		14,000		2,100
Executory contracts and other agreements	5 - 10 years		23,920		16,367		23,920		13,190
Non-compete agreements	2 - 7 years		14,412		8,302		14,161		6,388
Trade names	2 - 10 years		14,539		5,197		15,489		3,081
Debt issuance costs	5 - 10 years		53,289		12,737		44,089		8,708


Total amortizable			976,952		166,484		809,064		116,728
Non-amortizable—
Trade names			27,620				22,620


Total		$	1,004,572	$	166,484	$	831,684	$	116,728

(1): The weighted-average remaining amortization period for customer relationship intangible assets is approximately 9 years.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 6—Goodwill and Intangible Assets (Continued)

Amortization expense is as follows:

	Three Months Ended September 30,				Six Months Ended September 30,

Recorded In	2014		2013		2014		2013
	(in thousands)
Depreciation and amortization	$	21,711	$	11,324	$	42,604	$	20,600
Cost of sales		1,984		949		4,121		1,574
Interest expense		2,117		1,065		4,029		2,462


Total	$	25,812	$	13,338	$	50,754	$	24,636

Expected amortization of our intangible assets is as follows (in thousands):

Year Ending March 31,

2015 (six months)	$	50,570
2016		97,432
2017		90,795
2018		86,818
2019		79,587
Thereafter		405,266


Total	$	810,468

Note 7—Long-Term Debt

Our long-term debt consists of the following:

	September 30, 2014		March 31, 2014

	(in thousands)
Revolving credit facility—
Expansion capital borrowings	$	137,000	$	532,500
Working capital borrowings		942,500		389,500
5.125% Notes due 2019		400,000		—
6.875% Notes due 2021		450,000		450,000
6.650% Notes due 2022		250,000		250,000
TLP credit facility		252,000		—
Other long-term debt		10,913		14,914


		2,442,413		1,636,914
Less—current maturities		5,062		7,080


Long-term debt	$	2,437,351	$	1,629,834

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

Credit Agreement

	Amount

Expansion Capital Facility—
LIBOR borrowings	$	137,000	1.91	%
Working Capital Facility—
LIBOR borrowings		942,500	1.91	%

The Credit Agreement contains various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

indebtedness and liens. Our obligations under the Credit Agreement may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

At September 30, 2014, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

At September 30, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2019 Notes.

2021 Notes

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

after the initial purchasers' discount of $10.1 million and offering costs of $1.5 million. We used the net proceeds to reduce the outstanding balance on our Revolving Credit Facility.

At September 30, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2021 Notes.

2022 Notes

On June 19, 2012, we entered into a Note Purchase Agreement (as amended, the "Note Purchase Agreement") whereby we issued $250.0 million of Senior Notes in a private placement (the "2022 Notes"). The 2022 Notes bear interest at a fixed rate of 6.65%. Interest is payable quarterly. The 2022 Notes are required to be repaid in semi-annual installments of $25.0 million beginning on December 19, 2017 and ending on the maturity date of June 19, 2022. We have the option to prepay outstanding principal, although we would incur a prepayment penalty. The 2022 Notes are secured by substantially all of our assets and rank equal in priority with borrowings under the Credit Agreement.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

At September 30, 2014, we were in compliance with the covenants under the Note Purchase Agreement.

TLP Credit Facility

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

senior secured leverage ratio test (not to exceed 3.75 times) in the event TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times).

At September 30, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility and no outstanding letters of credit.


Cash and cash equivalents	$	726
Accounts receivable—trade, net		12,252
Accounts receivable—affiliates		1,105
Inventories		1,613
Prepaid expenses and other current assets		1,363
Property, plant and equipment, net		504,272
Goodwill		29,118
Intangible assets, net		38,571
Investments in unconsolidated entities		268,410
Other noncurrent assets		1,910
Accounts payable—trade		(4,009	)
Accounts payable—affiliates		(146	)
Accrued expenses and other payables		(11,625	)
Advanced payments received from customers		(141	)
Long-term debt		(252,000	)
Other noncurrent liabilities		(4,247	)


Net assets	$	587,172

Other Long-Term Debt

We have executed various noninterest bearing notes payable, primarily related to non-compete agreements entered into in connection with acquisitions of businesses. We also have certain notes payable related to equipment financing.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 7—Long-Term Debt (Continued)

Debt Maturity Schedule

The scheduled maturities of our long-term debt are as follows at September 30, 2014:

Year Ending March 31,	Revolving Credit Facility		2019 Notes		2021 Notes		2022 Notes		TLP Credit Facility		Other Long-Term Debt		Total

	(in thousands)
2015 (six months)	$	—	$	—	$	—	$	—	$	—	$	2,345	$	2,345
2016		—		—		—		—		252,000		3,128		255,128
2017		—		—		—		—		—		2,362		2,362
2018		—		—		—		25,000		—		1,459		26,459
2019		1,079,500		—		—		50,000		—		1,438		1,130,938
Thereafter		—		400,000		450,000		175,000		—		181		1,025,181


Total	$	1,079,500	$	400,000	$	450,000	$	250,000	$	252,000	$	10,913	$	2,442,413

Note 8—Income Taxes

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

A publicly-traded partnership is required to generate at least 90% of its gross income (as defined for federal income tax purposes) from certain qualifying sources. Income generated by our taxable corporate subsidiaries is excluded from this qualifying income calculation. Although we routinely generate income outside of our corporate subsidiaries that is non-qualifying, we believe that at least 90% of our gross income has been qualifying income for each of the calendar years since our initial public offering.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 8—Income Taxes (Continued)

financial statements. We had no material uncertain tax positions that required recognition in the consolidated financial statements at September 30, 2014.

Note 9—Commitments and Contingencies

Legal Contingencies

Customer Dispute

A customer of our crude oil logistics segment disputed the transportation rate schedule we used to bill the customer for services that we provided from November 2012 through February 2013, which was the same rate schedule that Pecos Gathering & Marketing, L.L.C. and certain of its affiliated companies (collectively, "Pecos"), used to bill the customer from April 2011 through October 2012 (prior to our November 1, 2012 acquisition of Pecos). The customer disputed a portion of the amount we charged for services we provided from November 2012 through February 2013. In May 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer. Later in May 2013, the customer filed an answer and counterclaim seeking to recover certain amounts that it paid to Pecos prior to our acquisition of Pecos.

During August 2013, the customer notified us that it intended to withhold payment due for services performed by us during the period from June 2013 through August 2013, pending resolution of the dispute, although the customer did not dispute the validity of the amounts billed for services performed during this time frame. Upon receiving this notification, we ceased providing services under this contract, and on November 5, 2013, we filed a petition in the District Court of Harris County, Texas seeking to collect these unpaid fees from the customer.

During September 2014, we reached an agreement with the former customer whereby the former customer agreed to pay us an agreed-upon amount to dismiss its claims against us, in return for which we agreed to dismiss our other claims against the former customer. We did not record a gain or loss upon settlement, as the amount we received approximated the amount we had recorded as receivable from the customer.

Environmental Matters

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 9—Commitments and Contingencies (Continued)

policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs. Accordingly, we have adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials designed to prevent material environmental or other damage, and to limit the financial liability that could result from such events. However, some risk of environmental or other damage is inherent in our business.

Asset Retirement Obligations

We have recorded a liability of $2.7 million at September 30, 2014 for asset retirement obligations. This liability is related to wastewater disposal facilities and crude oil facilities for which we have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are retired.

Operating Leases

We have executed various noncancelable operating lease agreements for product storage, office space, vehicles, real estate, railcars, and equipment. Future minimum lease payments under these agreements at September 30, 2014 are as follows (in thousands):

Year Ending March 31,

2015 (six months)	$	71,007
2016		106,384
2017		88,666
2018		74,265
2019		49,907
Thereafter		117,125


Total	$	507,354

Rental expense relating to operating leases was $29.3 million and $23.6 million during the three months ended September 30, 2014 and 2013, respectively, and $54.6 million and $45.5 million during the six months ended September 30, 2014 and 2013, respectively.

Pipeline Capacity Agreements

We have executed noncancelable agreements with crude and refined products pipeline operators, which guarantee us minimum monthly shipping capacity on the pipelines. In exchange, we are obligated to pay the minimum shipping fees in the event actual shipments are less than our allotted capacity.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 9—Commitments and Contingencies (Continued)

Future minimum throughput payments under these agreements at September 30, 2014 are as follows (in thousands):

Year Ending March 31,

2015 (six months)	$	41,822
2016		95,050
2017		82,916
2018		62,565
2019		51,278
Thereafter		107,537


Total	$	441,168

Sales and Purchase Contracts

We have entered into sales and purchase contracts for products to be delivered in future periods for which we expect the parties to physically settle the contracts with inventory. At September 30, 2014, we had the following such commitments outstanding:

	Volume		Value

	(in thousands)
Natural gas liquids fixed-price purchase commitments (gallons)		88,574	$	102,000
Natural gas liquids index-price purchase commitments (gallons)		528,459		601,719
Natural gas liquids fixed-price sale commitments (gallons)		278,391		351,137
Natural gas liquids index-price sale commitments (gallons)		370,639		512,900
Crude oil index-price purchase commitments (barrels)		4,437		383,153
Crude oil fixed-price sale commitments (barrels)		32		2,867
Crude oil index-price sale commitments (barrels)		3,920		337,528

Certain other forward purchase and sale contracts do not qualify for the normal purchase and normal sale election. These contracts are recorded at fair value on our condensed consolidated balance sheet and are not included in the table above. These contracts are included in the derivative disclosures in Note 11, and represent $44.4 million of our prepaid expenses and other current assets and $36.3 million of our accrued expenses and other payables at September 30, 2014.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 10—Equity

Partnership Equity

The Partnership's equity consists of a 0.1% general partner interest and a 99.9% limited partner interest, which consists of common units. Prior to August 2014, the Partnership's limited partner interest also included subordinated units. The subordination period ended in August 2014, at which time all remaining subordinated units were converted into common units on a one-for-one basis.

Our general partner is not obligated to make any additional capital contributions or to guarantee or pay any of our debts and obligations.

Equity Issuances

On June 23, 2014, we completed a public offering of 8,000,000 common units. We received net proceeds of $338.0 million, after underwriting discounts and commissions of $12.3 million and offering costs of $0.5 million. During July 2014, the underwriters exercised their option to purchase an additional 767,100 units, from which we received net proceeds of $32.4 million.

Distributions to Owners

Our general partner has adopted a cash distribution policy that requires us to pay a quarterly distribution to unitholders as of the record date to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to the general partner and its affiliates, referred to as "available cash." The general partner will also receive, in addition to distributions on its 0.1% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as "incentive distributions." Our general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in our partnership agreement.

The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest In Distributions" are the percentage interests of our general partner and the unitholders in any available cash from operating surplus we distribute up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit," until available cash from operating surplus we distribute reaches the next target distribution level, if any. The percentage interests shown for our unitholders and our general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for our general partner include its 0.1%

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 10—Equity (Continued)

general partner interest, assume our general partner has contributed any additional capital necessary to maintain its 0.1% general partner interest and has not transferred its incentive distribution rights.

				Marginal Percentage Interest In Distributions

	Total Quarterly Distribution Per Unit			Unitholders			General Partner
Minimum quarterly distribution			$0.337500		99.9	%		0.1	%
First target distribution		above $0.337500	up to $0.388125		99.9	%		0.1	%
Second target distribution		above $0.388125	up to $0.421875		86.9	%		13.1	%
Third target distribution		above $0.421875	up to $0.506250		76.9	%		23.1	%
Thereafter		above $0.506250			51.9	%		48.1	%

During the three months ended September 30, 2014, we distributed a total of $61.5 million ($0.5888 per common, subordinated, and general partner notional unit) to our unitholders of record on August 4, 2014, which included an incentive distribution of $9.5 million to the general partner. In October 2014, we declared a distribution of $0.6088 per common unit, to be paid on November 14, 2014 to unitholders of record on November 4, 2014. This distribution is expected to be $65.0 million, including amounts to be paid on common and general partner notional units and the amount to be paid on incentive distribution rights.

Distributions to Noncontrolling Interest Partners

TLP's general partner has adopted a cash distribution policy that requires it to pay a quarterly distribution to unitholders as of the record date to the extent TLP has sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to TLP's general partner and its affiliates, referred to as "available cash." TLP's general partner will also receive, in addition to distributions on its 2.0% general partner interest, additional distributions based on the level of distributions to the limited partners. These distributions are referred to as "incentive distributions." TLP's general partner currently holds the incentive distribution rights, but may transfer these rights separately from its general partner interest, subject to restrictions in TLP's partnership agreement.

The following table illustrates the percentage allocations of available cash from operating surplus between TLP's unitholders and TLP's general partner based on the specified target distribution levels. The amounts set forth under "Marginal Percentage Interest In Distributions" are the percentage interests of TLP's general partner and TLP's unitholders in any available cash from operating surplus TLP distributes up to and including the corresponding amount in the column "Total Quarterly Distribution Per Unit," until available cash from operating surplus TLP distributes reaches the next target distribution level, if any. The percentage interests shown for TLP's unitholders and TLP's general partner for the minimum quarterly distribution are also applicable to quarterly distribution amounts that are less than the minimum quarterly distribution. The percentage interests set forth below for TLP's general partner include its 2.0% general partner interest, assume TLP's general partner has

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 10—Equity (Continued)

contributed any additional capital necessary to maintain its 2.0% general partner interest and has not transferred its incentive distribution rights.

				Marginal Percentage Interest In Distributions

	Total Quarterly Distribution Per Unit			Unitholders			General Partner
Minimum quarterly distribution			$0.40		98	%		2	%
First target distribution		above $0.40	up to $0.44		98	%		2	%
Second target distribution		above $0.44	up to $0.50		85	%		15	%
Third target distribution		above $0.50	up to $0.60		75	%		25	%
Thereafter		above $0.60			50	%		50	%

During the three months ended September 30, 2014, TLP declared and paid a distribution of $0.665 per unit. The noncontrolling interest owners received a total of $8.7 million from this distribution. Pursuant to the terms of the agreement related to our acquisition of TransMontaigne, we remitted the amount we received on this distribution on our general partner interest, incentive distribution rights, and limited partner interest to the former owners of TransMontaigne.

In October 2014, TLP declared a distribution of $0.665 per unit, which was paid on November 7, 2014. The noncontrolling interest owners received a total of $8.7 million from this distribution.

Equity-Based Incentive Compensation

Our general partner has adopted a long-term incentive plan ("LTIP"), which allows for the issuance of equity-based compensation to employees and directors. Our general partner has granted certain restricted units to employees and directors, which will vest in tranches, subject to the continued service of the recipients. The awards may also vest in the event of a change in control, at the discretion of the board of directors. No distributions will accrue to or be paid on the restricted units during the vesting period.

The following table summarizes the restricted unit activity during the six months ended September 30, 2014:


Unvested restricted units at March 31, 2014	1,311,100
Units granted	333,903
Units vested and issued	(438,009	)
Units withheld for employee taxes	(231,194	)
Units forfeited	(117,000	)


Unvested restricted units at September 30, 2014	858,800

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 10—Equity (Continued)

The scheduled vesting of our unvested restricted units is summarized below:

Vesting Date		Number of Awards

July 1, 2015			334,800
July 1, 2016			314,000
July 1, 2017			178,500
July 1, 2018			31,500


Unvested restricted units at September 30, 2014			858,800

We recorded expense related to restricted unit awards of $13.8 million and $3.2 million during the three months ended September 30, 2014 and 2013, respectively, and $21.7 million and $10.3 million during the six months ended September 30, 2014 and 2013, respectively. We estimate that the future expense we will record on the unvested awards at September 30, 2014 will be as follows (in thousands), after taking into consideration an estimate of forfeitures of approximately 80,000 units. For purposes of this calculation, we used the closing price of our common units on September 30, 2014, which was $39.37.

Year Ending March 31,

2015 (six months)	$	6,343
2016		11,516
2017		7,262
2018		2,237
2019		249


Total	$	27,607

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 10—Equity (Continued)

Following is a rollforward of the liability related to equity-based compensation, which is reported within accrued expenses and other payables on our condensed consolidated balance sheets (in thousands):


Balance at March 31, 2014	$	10,012
Expense recorded		21,659
Value of units vested and issued		(18,763	)
Taxes paid on behalf of participants		(9,901	)


Balance at September 30, 2014	$	3,007

The weighted-average fair value of the awards at September 30, 2014 was $35.16 per common unit, which was calculated as the closing price of the common units on September 30, 2014, adjusted to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution and assumptions that a market participant might make about future distribution growth.

The number of common units that may be delivered pursuant to awards under the LTIP is limited to 10% of the issued and outstanding common units. The maximum number of units deliverable under the plan automatically increases to 10% of the issued and outstanding common units immediately after each issuance of common units, unless the plan administrator determines to increase the maximum number of units deliverable by a lesser amount. Units withheld to satisfy tax withholding obligations will not be considered to be delivered under the LTIP. In addition, if an award is forfeited, canceled, exercised, paid or otherwise terminates or expires without the delivery of units, the units subject to such award are again available for new awards under the LTIP. At September 30, 2014, 7.1 million units remain available for issuance under the LTIP.

Note 11—Fair Value of Financial Instruments

Our cash and cash equivalents, accounts receivable, accounts payable, accrued expenses, and other current assets and liabilities (excluding derivative instruments) are carried at amounts which reasonably approximate their fair values due to their short-term nature.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 11—Fair Value of Financial Instruments (Continued)

Commodity Derivatives

The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported on the condensed consolidated balance sheet at September 30, 2014:

	Derivative Assets			Derivative Liabilities

	(in thousands)
Level 1 measurements	$	48,632		$	(5,378	)
Level 2 measurements		51,389			(38,280	)


		100,021			(43,658	)
Netting of counterparty contracts(1)		(4,635	)		4,635
Cash collateral held		(13,704	)		—


Commodity derivatives on condensed consolidated balance sheet	$	81,682		$	(39,023	)

(1): Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with the counterparty.

The following table summarizes the estimated fair values of our commodity derivative assets and liabilities reported on the condensed consolidated balance sheet at March 31, 2014:

	Derivative Assets			Derivative Liabilities

	(in thousands)
Level 1 measurements	$	4,990		$	(3,258	)
Level 2 measurements		49,605			(43,303	)


		54,595			(46,561	)
Netting of counterparty contracts(1)		(4,347	)		4,347
Net cash collateral provided		456			—


Commodity derivatives on condensed consolidated balance sheet	$	50,704		$	(42,214	)

(1): Relates to derivative assets and liabilities that are expected to be net settled on an exchange or through a master netting arrangement with the counterparty.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 11—Fair Value of Financial Instruments (Continued)

Our commodity derivative assets and liabilities are reported in the following accounts on the condensed consolidated balance sheets:

	September 30, 2014			March 31, 2014

	(in thousands)
Prepaid expenses and other current assets	$	81,682		$	50,704
Accrued expenses and other payables		(39,023	)		(42,214	)


Net commodity derivative asset	$	42,659		$	8,490

The following table summarizes our open commodity derivative contract positions at September 30, 2014 and March 31, 2014. We do not account for these derivatives as hedges.

Contracts	Settlement Period	Total Notional Units (Barrels)			Fair Value of Net Assets (Liabilities)

		(in thousands)
At September 30, 2014—
Cross-commodity(1)	October 2014 - March 2015		(12	)	$	(1,283	)
Crude oil fixed-price(2)	October 2014 - December 2015		(1,638	)		9,380
Crude oil index(3)	October 2014 - July 2015		2,195			4,397
Propane fixed-price(4)	October 2014 - March 2015		1,238			53
Refined products fixed-price(5)	October 2014 - July 2015		(4,475	)		38,712
Renewable products fixed-price(6)	October 2014 - December 2015		(14	)		5,104


						56,363
Net cash collateral held						(13,704	)


Net commodity derivatives on condensed consolidated balance sheet					$	42,659




At March 31, 2014—
Cross-commodity(1)	April 2014 - March 2015		140		$	(1,876	)
Crude oil fixed-price(2)	April 2014 - March 2015		(1,600	)		(2,796	)
Crude oil index(3)	April 2014 - December 2015		3,598			6,099
Propane fixed-price(4)	April 2014 - March 2015		60			1,753
Refined products fixed-price(5)	April 2014 - July 2014		732			560
Renewable products fixed-price(6)	April 2014 - July 2014		106			4,084
Other	April 2014		—			210


						8,034
Net cash collateral provided						456


Net commodity derivatives on condensed consolidated balance sheet					$	8,490

(1): Cross-commodity—Our operating segments may purchase or sell a physical commodity where the underlying contract pricing mechanisms are tied to different commodity price indices. The contracts listed in this table as "Cross-commodity" represent derivatives we have entered into as an economic hedge against the risk of one commodity price moving relative to another commodity price.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 11—Fair Value of Financial Instruments (Continued)

(2): Crude oil fixed-price—Our crude oil logistics segment routinely purchases crude oil inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Crude oil fixed-price" represent derivatives we have entered into as an economic hedge against the risk that crude oil prices will decline while we are holding the inventory.
(3): Crude oil index—Our crude oil logistics segment may purchase or sell crude oil where the underlying contract pricing mechanisms are tied to different crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The contracts listed in this table as "Crude oil index" represent derivatives we have entered into as an economic hedge against the risk of one crude oil index moving relative to another crude oil index.
(4): Propane fixed-price—Our liquids segment routinely purchases propane inventory during the warmer months and stores the propane inventory for sale during the colder months. The contracts listed in this table as "Propane fixed-price" represent derivatives we have entered into as an economic hedge against the risk that propane prices will decline while we are holding the inventory.
(5): Refined products fixed-price—Our refined products and renewables segment routinely purchases refined products inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Refined products fixed-price" represent derivatives we have entered into as an economic hedge against the risk that refined product prices will decline while we are holding the inventory.
(6): Renewable products fixed-price—Our refined products and renewables segment routinely purchases biodiesel and ethanol inventory to enable us to fulfill future orders expected to be placed by our customers. The contracts listed in this table as "Renewable products fixed-price" represent derivatives we have entered into as an economic hedge against the risk that biodiesel or ethanol prices will decline while we are holding the inventory.

We recorded the following net gains (losses) from our commodity derivatives to cost of sales:

Three Months Ended September 30,					Six Months Ended September 30,

2014		2013			2014		2013
(in thousands)
$	55,981	$	(10,672	)	$	38,496	$	(17,881	)

Credit Risk

We may enter into industry standard master netting agreements and may enter into cash collateral agreements requiring the counterparty to deposit funds into a brokerage margin account. The netting agreements reduce our credit risk by providing for net settlement of any offsetting positive and negative exposures with counterparties. The cash collateral agreements reduce the level of our net counterparty credit risk because the amount of collateral represents additional funds that we may access to net settle positions due us, and the amount of collateral adjusts each day in response to changes in the market value of counterparty derivatives.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 11—Fair Value of Financial Instruments (Continued)

Failure of a counterparty to perform on a contract could result in our inability to realize amounts that have been recorded on our condensed consolidated balance sheets and recognized in our net income.

Interest Rate Risk

Fair Value of Notes

The following table provides estimates of the fair values of our fixed-rate notes at September 30, 2014 (in thousands):


5.125% Notes due 2019	$	390,000
6.875% Notes due 2021		475,000
6.650% Notes due 2022		275,000

For the 2019 Notes and the 2021 Notes, the fair value estimates were developed by reference to broker quotes. These estimates would be classified as Level 2 in the fair value hierarchy. For the 2022 Notes, the estimate was developed using observed yields on publicly-traded notes issued by other entities, adjusted for differences in the key terms of those notes and the key terms of our notes (examples include differences in the tenor of the debt, credit standing of the issuer, whether the notes are publicly-traded, and whether the notes are secured or unsecured). These estimates of fair value would be classified as Level 3 in the fair value hierarchy.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 12—Segments

Our crude oil logistics segment sells crude oil and provides crude oil transportation services to wholesalers, refiners, and producers. Our water solutions segment provides services for the treatment and disposal of wastewater generated from crude oil and natural gas production, and generates revenue from the sale of recycled water and recovered hydrocarbons. Our liquids segment supplies propane, butane, and other products, and provides natural gas liquids transportation, terminaling, and storage services to retailers, wholesalers, and refiners. Our retail propane segment sells propane and distillates to end users consisting of residential, agricultural, commercial, and industrial customers, and to certain re-sellers. Our retail propane segment consists of two divisions, which are organized based on the location of the operations. Our refined products and renewables segment provides integrated terminaling, storage, transportation, marketing, and related services for companies engaged in the trading, distribution and marketing of refined petroleum products, ethanol, and biodiesel. This segment began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne.

Items labeled "corporate and other" in the table below include the operations of a compressor leasing business that we sold in February 2014 and certain natural gas marketing operations that we acquired in our December 2013 acquisition of Gavilon Energy and wound down during fiscal year 2014. The "corporate and other" category also includes certain corporate expenses that are incurred and are not allocated to the reportable segments. This data is included to reconcile the data for the reportable segments to data in our condensed consolidated financial statements.

	Three Months Ended September 30,				Six Months Ended September 30,

	2014		2013		2014		2013
					(in thousands)
Revenues:
Crude oil logistics—
Crude oil sales	$	2,108,117	$	1,013,061	$	4,035,061	$	1,941,595
Crude oil transportation and other		13,082		9,794		25,196		19,729
Water solutions—
Water treatment and disposal		47,572		28,823		89,288		47,511
Water transportation		5,147		5,367		10,745		7,192
Liquids—
Propane sales		240,433		191,437		462,879		315,274
Other product sales		306,625		308,606		594,984		558,459
Other revenues		6,814		9,250		12,530		18,114
Retail propane—
Propane sales		48,552		40,651		100,578		87,342

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 12—Segments (Continued)

	Three Months Ended September 30,						Six Months Ended September 30,

	2014			2013			2014			2013
							(in thousands)
Distillate sales		11,530			10,562			30,225			28,431
Other revenues		8,276			8,198			15,457			15,898
Refined products and renewables—
Refined products sales		2,489,795			—			3,476,018			—
Renewables sales		117,425			—			248,699			—
Corporate and other		1,333			1,485			2,794			2,959
Elimination of intersegment sales		(24,175	)		(33,297	)		(75,314	)		(62,610	)


Total revenues	$	5,380,526		$	1,593,937		$	9,029,140		$	2,979,894




Depreciation and Amortization:
Crude oil logistics	$	9,240		$	3,330		$	18,971		$	8,014
Water solutions		17,573			11,438			34,665			18,794
Liquids		3,384			2,672			6,585			5,376
Retail propane		7,684			6,871			15,255			14,111
Refined products and renewables		11,917			—			12,761			—
Corporate and other		301			750			1,237			1,490


Total depreciation and amortization	$	50,099		$	25,061		$	89,474		$	47,785




Operating Income (Loss):
Crude oil logistics	$	38		$	5,884		$	1,501		$	12,493
Water solutions		14,792			2,913			13,885			5,956
Liquids		10,929			14,605			10,016			12,490
Retail propane		(3,062	)		(4,520	)		(4,648	)		(6,024	)
Refined products and renewables		8,822			—			7,567			—
Corporate and other		(23,749	)		(8,937	)		(41,106	)		(22,312	)


Total operating income (loss)	$	7,770		$	9,945		$	(12,785	)	$	2,603

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 12—Segments (Continued)

The following table summarizes additions to property, plant and equipment for each segment. This information has been prepared on the accrual basis, and includes property, plant and equipment acquired in acquisitions.

	Three Months Ended September 30,				Six Months Ended September 30,

	2014		2013		2014		2013
	(in thousands)
Additions to property, plant and equipment:
Crude oil logistics	$	39,464	$	31,336	$	81,413	$	35,462
Water solutions		40,610		62,473		48,072		70,182
Liquids		1,911		13,209		3,070		28,316
Retail propane		9,567		4,546		12,411		11,492
Refined products and renewables		512,281		—		512,281		—
Corporate and other		1,809		217		3,262		846


Total	$	605,642	$	111,781	$	660,509	$	146,298

The following tables summarize long-lived assets (consisting of net property, plant and equipment, net intangible assets, and goodwill) and total assets by segment:

	September 30, 2014		March 31, 2014

	(in thousands)
Total assets:
Crude oil logistics	$	2,079,380	$	1,723,812
Water solutions		964,336		875,714
Liquids		756,133		577,795
Retail propane		506,958		541,832
Refined products and renewables		2,183,674		303,230
Corporate and other		61,198		144,840


Total	$	6,551,679	$	4,167,223




Long-lived assets, net:
Crude oil logistics	$	996,615	$	980,978
Water solutions		910,467		848,479
Liquids		271,567		274,846
Retail propane		436,621		438,324
Refined products and renewables		772,916		60,720
Corporate and other		53,705		47,961


Total	$	3,441,891	$	2,651,308

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 13—Transactions with Affiliates

SemGroup Corporation ("SemGroup") holds ownership interests in us and in our general partner. We sell product to and purchase product from SemGroup, and these transactions are included within revenues and cost of sales in our condensed consolidated statements of operations. We also lease crude oil storage from SemGroup.

We purchase ethanol from one of our equity method investees. These transactions are reported within cost of sales in our condensed consolidated statements of operations.

Certain members of our management own interests in entities from which we have purchased products and services and to which we have sold products and services to. The majority of these purchases represented crude oil purchases and are reported within cost of sales in our condensed consolidated statements of operations, although $5.8 million of these transactions during the six months ended September 30, 2014 represented capital expenditures and were recorded as increases to property, plant and equipment. The majority of these sales represented crude oil sales and are reported within revenues in our condensed consolidated statements of operations.

The above transactions are summarized in the following table:

	Three Months Ended September 30,				Six Months Ended September 30,

	2014		2013		2014		2013
	(in thousands)
Sales to SemGroup	$	43,427	$	3,780	$	117,233	$	3,780
Purchases from SemGroup		45,730		28,377		118,997		47,916
Purchases from equity method investees		34,689		—		70,965		—
Sales to equity method investees		9,131		—		9,131		—
Sales to entities affiliated with management		1,706		58,769		1,854		109,872
Purchases from entities affiliated with management		3,845		48,522		6,984		56,346

Receivables from affiliates consist of the following:

	September 30, 2014		March 31, 2014

	(in thousands)
Receivables from SemGroup	$	39,331	$	7,303
Receivables from entities affiliated with management		1,705		142
Receivables from equity method investees		670		—


Total	$	41,706	$	7,445

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 13—Transactions with Affiliates (Continued)

Payables to affiliates consist of the following:

	September 30, 2014		March 31, 2014

	(in thousands)
Payables to SemGroup	$	44,015	$	27,738
Payables to equity method investees		39,549		48,454
Payables to entities affiliated with management		1,743		654


Total	$	85,307	$	76,846

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Certain of our wholly-owned subsidiaries have, jointly and severally, fully and unconditionally guaranteed the 2019 Notes and the 2021 Notes (described in Note 7). Pursuant to Rule 3-10 of Regulation S-X, we have presented in columnar format the condensed consolidating financial information for NGL Energy Partners LP, NGL Energy Finance Corp. (which, along with NGL Energy Partners LP, is a co-issuer of the 2019 Notes and 2021 Notes), the guarantor subsidiaries on a combined basis, and the non-guarantor subsidiaries on a combined basis in the tables below.

During the periods presented in the tables below, the status of certain subsidiaries changed, in that they either became guarantors of or ceased to be guarantors of the 2019 Notes and 2021 Notes. Such changes have been given retrospective application in the tables below.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Balance Sheet
(U.S. Dollars in Thousands)

	September 30, 2014

	NGL Energy Partners LP (Parent)(1)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	2,841	$	—	$	7,823		$	1,159		$	—		$	11,823
Accounts receivable—trade, net of allowance for doubtful accounts		—		—		1,419,442			13,675			—			1,433,117
Accounts receivable—affiliates		—		—		41,035			671			—			41,706
Inventories		—		—		937,814			3,775			—			941,589
Prepaid expenses and other current assets		—		—		155,332			1,486			—			156,818


Total current assets		2,841		—		2,561,446			20,766			—			2,585,053
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation		—		—		863,694			569,619			—			1,433,313
GOODWILL		—		—		1,139,374			31,116			—			1,170,490
INTANGIBLE ASSETS, net of accumulated amortization		1,307		17,619		778,960			40,202			—			838,088
INVESTMENTS IN UNCONSOLIDATED ENTITIES		—		—		214,234			268,410			—			482,644
NET INTERCOMPANY RECEIVABLES (PAYABLES)		248,893		849,526		(1,026,605	)		(71,814	)		—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES		1,743,573		—		10,470			—			(1,754,043	)		—
OTHER NONCURRENT ASSETS		—		—		40,035			2,056			—			42,091


Total assets	$	1,996,614	$	867,145	$	4,581,608		$	860,355		$	(1,754,043	)	$	6,551,679

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

	September 30, 2014

	NGL Energy Partners LP (Parent)(1)		NGL Energy Finance Corp.			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	—	$	—		$	1,333,780		$	11,244		$	—		$	1,345,024
Accounts payable—affiliates		—		—			85,237			70			—			85,307
Accrued expenses and other payables		554		19,021			186,226			12,681			—			218,482
Advance payments received from customers		—		—			105,597			508			—			106,105
Current maturities of long-term debt		—		—			5,004			58			—			5,062


Total current liabilities		554		19,021			1,715,844			24,561			—			1,759,980
LONG-TERM DEBT, net of current maturities		250,000		850,000			1,085,155			252,196			—			2,437,351
OTHER NONCURRENT LIABILITIES		��		—			35,160			4,358			—			39,518
EQUITY
Partners' equity (deficit)		1,746,060		(1,876	)		1,745,450			579,312			(2,322,813	)		1,746,133
Accumulated other comprehensive loss		—		—			(1	)		(72	)		—			(73	)
Noncontrolling interests		—		—			—			—			568,770			568,770


Total equity (deficit)		1,746,060		(1,876	)		1,745,449			579,240			(1,754,043	)		2,314,830


Total liabilities and equity	$	1,996,614	$	867,145		$	4,581,608		$	860,355		$	(1,754,043	)	$	6,551,679

(1): The parent is a co-issuer of the 2019 Notes and 2021 Notes that are included in the NGL Energy Finance Corp. column.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Balance Sheet
(U.S. Dollars in Thousands)

	March 31, 2014

	NGL Energy Partners LP (Parent)(1)		NGL Energy Finance Corp.		Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,181	$	—	$	8,728		$	531		$	—		$	10,440
Accounts receivable—trade, net of allowance for doubtful accounts		—		—		887,789			13,115			—			900,904
Accounts receivable—affiliates		—		—		7,445			—			—			7,445
Inventories		—		—		306,434			3,726			—			310,160
Prepaid expenses and other current assets		—		—		80,294			56			—			80,350


Total current assets		1,181		—		1,290,690			17,428			—			1,309,299
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation		—		—		764,014			65,332			—			829,346
GOODWILL		—		—		1,105,008			1,998			—			1,107,006
INTANGIBLE ASSETS, net of accumulated amortization		1,169		11,552		700,603			1,632			—			714,956
INVESTMENTS IN UNCONSOLIDATED ENTITIES		—		—		189,821			—			—			189,821
NET INTERCOMPANY RECEIVABLES (PAYABLES)		327,281		437,714		(720,737	)		(44,258	)		—			—
INVESTMENTS IN CONSOLIDATED SUBSIDIARIES		1,447,502		—		17,673			—			(1,465,175	)		—
OTHER NONCURRENT ASSETS		—		—		16,674			121			—			16,795


Total assets	$	1,777,133	$	449,266	$	3,363,746		$	42,253		$	(1,465,175	)	$	4,167,223

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

	March 31, 2014

	NGL Energy Partners LP (Parent)(1)		NGL Energy Finance Corp.			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
LIABILITIES AND EQUITY
CURRENT LIABILITIES:
Accounts payable—trade	$	—	$	—		$	726,252		$	13,959		$	—		$	740,211
Accounts payable—affiliates		—		—			73,703			3,143			—			76,846
Accrued expenses and other payables		554		14,266			124,923			1,947			—			141,690
Advance payments received from customers		—		—			29,891			74			—			29,965
Current maturities of long-term debt		—		—			7,058			22			—			7,080


Total current liabilities		554		14,266			961,827			19,145			—			995,792
LONG-TERM DEBT, net of current maturities		250,000		450,000			929,754			80			—			1,629,834
OTHER NONCURRENT LIABILITIES		—		—			9,663			81			—			9,744
EQUITY
Partners' equity (deficit)		1,526,579		(15,000	)		1,462,691			22,994			(1,470,449	)		1,526,815
Accumulated other comprehensive loss		—		—			(189	)		(47	)		—			(236	)
Noncontrolling interests		—		—			—			—			5,274			5,274


Total equity (deficit)		1,526,579		(15,000	)		1,462,502			22,947			(1,465,175	)		1,531,853


Total liabilities and equity	$	1,777,133	$	449,266		$	3,363,746		$	42,253		$	(1,465,175	)	$	4,167,223

(1): The parent is a co-issuer of the 2021 Notes that are included in the NGL Energy Finance Corp. column.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

	Three Months Ended September 30, 2014

	NGL Energy Partners LP (Parent)(1)			NGL Energy Finance Corp.			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—		$	5,325,186		$	55,364		$	(24	)	$	5,380,526
COST OF SALES		—			—			5,161,935			17,554			(24	)		5,179,465
OPERATING COSTS AND EXPENSES:
Operating		—			—			84,300			17,253			—			101,553
General and administrative		—			—			36,360			5,279			—			41,639
Depreciation and amortization		—			—			38,999			11,100			—			50,099


Operating Income		—			—			3,592			4,178			—			7,770
OTHER INCOME (EXPENSE):
Earnings of unconsolidated entities		—			—			2,310			1,387			—			3,697
Interest expense		(4,067	)		(13,134	)		(9,956	)		(1,506	)		12			(28,651	)
Other, net		—			—			(524	)		(81	)		(12	)		(617	)


Income (Loss) Before Income Taxes		(4,067	)		(13,134	)		(4,578	)		3,978			—			(17,801	)
INCOME TAX (PROVISION) BENEFIT		—			—			1,951			(29	)		—			1,922
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES		(15,157	)		—			604			—			14,553			—


Net Income (Loss)		(19,224	)		(13,134	)		(2,023	)		3,949			14,553			(15,879	)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER														(11,056	)		(11,056	)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS														(3,345	)		(3,345	)


NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(19,224	)	$	(13,134	)	$	(2,023	)	$	3,949		$	152		$	(30,280	)

(1): The parent is a co-issuer of the 2019 Notes and 2021 Notes.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

	Three Months Ended September 30, 2013

	NGL Energy Partners LP (Parent)			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	1,546,226		$	47,735		$	(24	)	$	1,593,937
COST OF SALES		—			1,445,442			43,432			(24	)		1,488,850
OPERATING COSTS AND EXPENSES:
Operating		—			52,979			2,790			—			55,769
General and administrative		—			14,089			223			—			14,312
Depreciation and amortization		—			23,970			1,091			—			25,061


Operating Income		—			9,746			199			—			9,945
OTHER INCOME (EXPENSE):
Interest expense		(4,179	)		(6,880	)		(13	)		12			(11,060	)
Other, net		—			528			(97	)		(12	)		419


Income (Loss) Before Income Taxes		(4,179	)		3,394			89			—			(696	)
INCOME TAX PROVISION		—			(236	)		—			—			(236	)
EQUITY IN NET INCOME OF CONSOLIDATED SUBSIDIARIES		3,238			80			—			(3,318	)		—


Net Income (Loss)		(941	)		3,238			89			(3,318	)		(932	)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER											(2,451	)		(2,451	)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS											(9	)		(9	)


NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(941	)	$	3,238		$	89		$	(5,778	)	$	(3,392	)

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2014

	NGL Energy Partners LP (Parent)(1)			NGL Energy Finance Corp.			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	—		$	8,952,772		$	76,421		$	(53	)	$	9,029,140
COST OF SALES		—			—			8,676,881			36,690			(53	)		8,713,518
OPERATING COSTS AND EXPENSES:
Operating		—			—			150,919			18,502			—			169,421
General and administrative		—			—			64,124			5,388			—			69,512
Depreciation and amortization		—			—			77,545			11,929			—			89,474


Operating Income (Loss)		—			—			(16,697	)		3,912			—			(12,785	)
OTHER INCOME (EXPENSE):
Earnings of unconsolidated entities		—			—			4,875			1,387			—			6,262
Interest expense		(8,313	)		(21,280	)		(18,058	)		(1,517	)		23			(49,145	)
Other, net		—			—			(1,056	)		71			(23	)		(1,008	)


Income (Loss) Before Income Taxes		(8,313	)		(21,280	)		(30,936	)		3,853			—			(56,676	)
INCOME TAX (PROVISION) BENEFIT		—			—			993			(106	)		—			887
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES		(50,886	)		—			337			—			50,549			—


Net Income (Loss)		(59,199	)		(21,280	)		(29,606	)		3,747			50,549			(55,789	)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER														(20,437	)		(20,437	)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS														(3,410	)		(3,410	)


NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(59,199	)	$	(21,280	)	$	(29,606	)	$	3,747		$	26,702		$	(79,636	)

(1): The parent is a co-issuer of the 2019 Notes and 2021 Notes.

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Operations
(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2013

	NGL Energy Partners LP (Parent)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES	$	—		$	2,914,531		$	65,421		$	(58	)	$	2,979,894
COST OF SALES		—			2,735,890			56,094			(58	)		2,791,926
OPERATING COSTS AND EXPENSES:
Operating		—			99,710			5,104			—			104,814
General and administrative		—			32,297			469			—			32,766
Depreciation and amortization		—			46,000			1,785			—			47,785


Operating Income		—			634			1,969			—			2,603
OTHER INCOME (EXPENSE):
Interest expense		(8,368	)		(13,309	)		(28	)		23			(21,682	)
Other, net		—			627			(135	)		(23	)		469


Income (Loss) Before Income Taxes		(8,368	)		(12,048	)		1,806			—			(18,610	)
INCOME TAX BENEFIT		—			170			—			—			170
EQUITY IN NET INCOME (LOSS) OF CONSOLIDATED SUBSIDIARIES		(10,206	)		1,672			—			8,534			—


Net Income (Loss)		(18,574	)		(10,206	)		1,806			8,534			(18,440	)
LESS: NET INCOME ALLOCATED TO GENERAL PARTNER											(4,139	)		(4,139	)
LESS: NET INCOME ATTRIBUTABLE TO NONCONTROLLING INTERESTS											(134	)		(134	)


NET INCOME (LOSS) ALLOCATED TO LIMITED PARTNERS	$	(18,574	)	$	(10,206	)	$	1,806		$	4,261		$	(22,713	)

				��		��

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statements of Comprehensive Income (Loss)
(U.S. Dollars in Thousands)

	Three Months Ended September 30, 2014

	NGL Energy Partners LP (Parent)(1)			NGL Energy Finance Corp.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
Net income (loss)	$	(19,224	)	$	(13,134	)	$	(2,023	)	$	3,949		$	14,553	$	(15,879	)
Other comprehensive income (loss)		—			—			4			(26	)		—		(22	)


Comprehensive income (loss)	$	(19,224	)	$	(13,134	)	$	(2,019	)	$	3,923		$	14,553	$	(15,901	)

(1): The parent is a co-issuer of the 2019 Notes and 2021 Notes.

	Three Months Ended September 30, 2013

	NGL Energy Partners LP (Parent)			Guarantor Subsidiaries		Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
Net income (loss)	$	(941	)	$	3,238	$	89		$	(3,318	)	$	(932	)
Other comprehensive loss		—			—		(5	)		—			(5	)


Comprehensive income (loss)	$	(941	)	$	3,238	$	84		$	(3,318	)	$	(937	)

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statements of Comprehensive Income (Loss)
(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2014

	NGL Energy Partners LP (Parent)(1)			NGL Energy Finance Corp.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
Net income (loss)	$	(59,199	)	$	(21,280	)	$	(29,606	)	$	3,747		$	50,549	$	(55,789	)
Other comprehensive income (loss)		—			—			189			(26	)		—		163


Comprehensive income (loss)	$	(59,199	)	$	(21,280	)	$	(29,417	)	$	3,721		$	50,549	$	(55,626	)

(1): The parent is a co-issuer of the 2019 Notes and 2021 Notes.

	Six Months Ended September 30, 2013

	NGL Energy Partners LP (Parent)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments		Consolidated
Net income (loss)	$	(18,574	)	$	(10,206	)	$	1,806		$	8,534	$	(18,440	)
Other comprehensive loss		—			—			(30	)		—		(30	)


Comprehensive income (loss)	$	(18,574	)	$	(10,206	)	$	1,776		$	8,534	$	(18,470	)

��

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Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2014

	NGL Energy Partners LP (Parent)(1)			NGL Energy Finance Corp.			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(8,180	)	$	(15,383	)	$	(56,019	)	$	17,947		$	(61,635	)
INVESTING ACTIVITIES:
Purchases of long-lived assets		—			—			(81,710	)		(1,141	)		(82,851	)
Acquisitions of businesses, including acquired working capital, net of cash acquired		—			—			(657,514	)		(1,250	)		(658,764	)
Cash flows from commodity derivatives		—			—			4,327			—			4,327
Proceeds from sales of assets		—			—			8,741			—			8,741
Investments in unconsolidated entities		—			—			(6,106	)		(20,284	)		(26,390	)
Distributions of capital from unconsolidated entities		—			—			2,774			1,875			4,649


Net cash used in investing activities		—			—			(729,488	)		(20,800	)		(750,288	)


FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facilities		—			—			1,923,500			56,000			1,979,500
Payments on revolving credit facilities		—			—			(1,766,000	)		(38,000	)		(1,804,000	)
Issuance of notes		—			400,000			—			—			400,000
Payments on other long-term debt		—			—			(4,173	)		(2	)		(4,175	)
Debt issuance costs		(269	)		(7,209	)		(1,720	)		—			(9,198	)
Contributions		395			—			—			—			395
Distributions to owners		(111,008	)		—			—			—			(111,008	)
Distributions to noncontrolling interest partners		—			—			—			(8,654	)		(8,654	)
Proceeds from sale of common units, net of offering costs		370,446			—			—			—			370,446
Net changes in advances with consolidated entities		(249,724	)		(377,408	)		632,995			(5,863	)		—


Net cash provided by financing activities		9,840			15,383			784,602			3,481			813,306


Net increase (decrease) in cash and cash equivalents		1,660			—			(905	)		628			1,383
Cash and cash equivalents, beginning of period		1,181			—			8,728			531			10,440


Cash and cash equivalents, end of period	$	2,841		$	—		$	7,823		$	1,159		$	11,823

(1): The parent is a co-issuer of the 2019 Notes and 2021 Notes.

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 14—Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

NGL ENERGY PARTNERS LP
Condensed Consolidating Statement of Cash Flows
(U.S. Dollars in Thousands)

	Six Months Ended September 30, 2013

	NGL Energy Partners LP (Parent)			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidated
OPERATING ACTIVITIES:
Net cash provided by (used in) operating activities	$	(8,312	)	$	(44,607	)	$	4,175		$	(48,744	)
INVESTING ACTIVITIES:
Purchases of long-lived assets		—			(37,180	)		(30,219	)		(67,399	)
Acquisitions of businesses, including acquired working capital, net of cash acquired		(334,085	)		(56,237	)		(2,283	)		(392,605	)
Cash flows from commodity derivatives		—			(19,074	)		—			(19,074	)
Proceeds from sales of assets		—			2,223			1			2,224


Net cash used in investing activities		(334,085	)		(110,268	)		(32,501	)		(476,854	)


FINANCING ACTIVITIES:
Proceeds from borrowings under revolving credit facility		—			1,061,500			—			1,061,500
Payments on revolving credit facility		—			(893,000	)		—			(893,000	)
Proceeds from borrowings on other long-term debt		—			780			100			880
Payments on other long-term debt		—			(4,499	)		(8	)		(4,507	)
Debt issuance costs		(133	)		(2,085	)		—			(2,218	)
Contributions		504			—			1,940			2,444
Distributions to owners		(60,258	)		—			(365	)		(60,623	)
Proceeds from sale of common units, net of offering costs		415,089			—			—			415,089
Net changes in advances with consolidated entities		(11,459	)		(15,123	)		26,582			—


Net cash provided by financing activities		343,743			147,573			28,249			519,565


Net increase (decrease) in cash and cash equivalents		1,346			(7,302	)		(77	)		(6,033	)
Cash and cash equivalents, beginning of period		—			11,206			355			11,561


Cash and cash equivalents, end of period	$	1,346		$	3,904		$	278		$	5,528

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NGL ENERGY PARTNERS LP AND SUBSIDIARIES

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

At September 30, 2014 and March 31, 2014, and for the
Three Months and Six Months Ended September 30, 2014 and 2013

Note 15—Subsequent Events

Water Solutions Facility Acquisitions

As described in Note 4, we are party to a development agreement that provides us a right to purchase water disposal facilities developed by the other party to the agreement. During October and November 2014, we purchased five facilities under this development agreement and paid $52.2 million of cash for these facilities.

Sale of Natural Gas Liquids Terminal

In November 2014, we reached an agreement to sell one of our natural gas liquids terminals. We expect the sale to close in December 2014. We expect to record during the three months ending December 31, 2014 a loss on disposal of approximately $29.0 million, consisting of a loss of $21.0 million on property, plant and equipment and $8.0 million of allocated goodwill.

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REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

NGL Energy Partners LP, the sole member of High Sierra Energy GP, LLC

We have audited the accompanying consolidated balance sheets of High Sierra Energy GP, LLC and subsidiaries (collectively, the "Company") as of December 31, 2011 and 2010, and the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2011. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America as established by the American Institute of Certified Public Accountants. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of High Sierra Energy GP, LLC and subsidiaries as of December 31, 2011 and 2010, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2011, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Denver, Colorado
September 4, 2012

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High Sierra Energy GP, LLC and Subsidiaries

Consolidated Balance Sheets

	Audited as of December 31,

	Audited as of December 31,				Unaudited as of March 31, 2012
	2011		2010		Unaudited as of March 31, 2012
	(in thousands)
Assets
Current assets
Cash and cash equivalents ($29 at December 31, 2010(1))	$	20,187	$	18,671	$	11,828
Accounts receivable, net
Trade ($29,716 at December 31, 2012(1))		266,806		212,667		299,547
Affiliate		476		—		819
Inventory, net ($7,140 at December 31, 2010(1))		94,971		59,272		77,831
Fair value of derivative instruments		4,481		2,327		5,946
Prepaids and other current assets ($3,227 at December 31, 2010(1))		15,759		20,301		15,395
Assets of operations held for sale		8,667		178,310		3,055


Total current assets		411,347		491,548		414,421


Property, plant and equipment, net		118,445		89,689		122,077
Goodwill		111,314		67,009		111,314
Other intangible assets, net		29,806		18,650		27,803
Other long-term assets		9,352		559		8,521


Total non-current assets		268,917		175,907		269,715


Total assets	$	680,264	$	667,455	$	684,136




Liabilities and equity
Current liabilities
Borrowings under lines of credit ($8,374 at December 31, 2010(1))	$	—	$	23,090	$	—
Current portion of debt		11,315		525		11,085
Accounts payable
Trade ($20,296 at December 31, 2010(1))		297,522		216,070		318,463
Affiliates		6,732		935		7,951
Accrued liabilities and other ($3,069 at December 31, 2010(1))		25,787		22,056		17,127
Fair value of derivative instruments		1,451		1,199		1,580
Liabilities of operations held for sale		376		113,370		369


Total current liabilities		343,183		377,245		356,575


Long-term debt, net of current portion		104,088		29,022		101,369
Other long-term liabilities		4,726		4,584		4,560


Total non-current liabilities		108,814		33,606		105,929


Total liabilities		451,997		410,851		462,504


Commitments and contingencies
Equity
Members' equity in High Sierra Energy GP, LLC		5,728		5,567		5,596
Noncontrolling common limited partner interests in High Sierra Energy, LP		221,036		222,105		214,811
Noncontrolling subordinated limited partner interests in High Sierra Energy, LP		876		845		708
Noncontrolling interests in subsidiaries of High Sierra Energy, LP		607		28,067		497
Accumulated other comprehensive income		20		20		20


Total equity		228,267		256,604		221,632


Total liabilities and equity	$	680,264	$	667,455	$	684,136

(1): Amounts in parentheses represent consolidated amounts attributable to a former variable interest entity.

The accompanying notes are an integral part of these consolidated financial statements.

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High Sierra Energy GP, LLC and Subsidiaries

Consolidated Statements of Operations

	Audited for the Years Ended December 31,									Unaudited for the Three Months Ended March 31,

	2011			2010			2009			2012			2011
	(in thousands)
Revenues
Product, transportation, fees and other	$	2,981,821		$	2,144,674		$	1,648,512		$	796,974		$	654,988
Unrealized gains (losses) on commodity derivative instruments		4,917			(3,919	)		88			1,194			872


Total revenues		2,986,738			2,140,755			1,648,600			798,168			655,860
Operating costs and expenses
Product and transportation expenses		2,856,010			2,050,159			1,523,605			760,646			633,852
Operating expenses		48,976			34,644			43,354			15,393			9,252
General and administrative expenses		22,116			20,224			23,971			8,408			4,837
Gain on sale of assets		(436	)		(851	)		(453	)		(48	)		(22	)
Depreciation and amortization expense		21,066			17,905			18,144			5,584			4,614


Total operating costs and expenses		2,947,732			2,122,081			1,608,621			789,983			652,533


Operating income		39,006			18,674			39,979			8,185			3,327
Other income (expense)
Interest income		26			25			226			12			67
Interest expense		(10,043	)		(5,769	)		(6,023	)		(2,791	)		(1,750	)
Loss from equity method investments		—			(1,454	)		(2,436	)		—			—
Other income (expense), net		3,310			(372	)		2,753			8			(181	)


Income from continuing operations before income taxes		32,299			11,104			34,499			5,414			1,463
Income tax expense (benefit)		(903	)		(1,568	)		2,118			338			1,215


Income from continuing operations		33,202			12,672			32,381			5,076			248
Discontinued operations
Income (loss) from discontinued operations, net		(3,133	)		(24,649	)		(51,120	)		(5,582	)		2,483
Loss on disposal of discontinued operations, net		(6,350	)		(3,913	)		—			(1,654	)		—


Income (loss) from discontinued operations, net		(9,483	)		(28,562	)		(51,120	)		(7,236	)		2,483


Net income (loss)	$	23,719		$	(15,890	)	$	(18,739	)	$	(2,160	)	$	2,731




Net income (loss) attributable to members' equity in High Sierra Energy GP, LLC	$	429		$	63		$	987		$	(39	)	$	26
Net income (loss) attributable to noncontrolling common limited partner interests in High Sierra Energy, LP		21,111			(17,168	)		(25,224	)		(2,151	)		1,284
Net income (loss) attributable to noncontrolling interests in subsidiaries of High Sierra Energy, LP		2,179			1,215			5,498			30			1,421


Net income (loss)	$	23,719		$	(15,890	)	$	(18,739	)	$	(2,160	)	$	2,731




Income (loss) from continuing operations attributable to members' equity in High Sierra Energy GP, LLC	$	614		$	525		$	2,008		$	106		$	4
Income (loss) from continuing operations attributable to noncontrolling common limited partner interests in High Sierra Energy, LP		30,223			5,450			24,789			4,940			216
Income (loss) from continuing operations attributable to noncontrolling interests in subsidiaries of High Sierra Energy, LP		2,365			6,697			5,584			30			28


Income (loss) from continuing operations	$	33,202		$	12,672		$	32,381		$	5,076		$	248




Income (loss) from discontinued operations attributable to members' equity in High Sierra Energy GP, LLC	$	(185	)	$	(462	)	$	(1,021	)	$	(145	)	$	22
Income (loss) from discontinued operations attributable to noncontrolling common limited partner interests in High Sierra Energy, LP		(9,112	)		(22,618	)		(50,013	)		(7,091	)		1,068
Income (loss) from discontinued operations attributable to noncontrolling interests in subsidiaries of High Sierra Energy, LP		(186	)		(5,482	)		(86	)		—			1,393


Income (loss) from discontinued operations	$	(9,483	)	$	(28,562	)	$	(51,120	)	$	(7,236	)	$	2,483

The accompanying notes are an integral part of these consolidated financial statements.

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High Sierra Energy GP, LLC and Subsidiaries

Consolidated Statements of Equity

Years Ended December 31, 2011, 2010 and 2009 (audited) and
Three Months Ended March 31, 2012 (unaudited)

	Members' Equity in High Sierra Energy GP, LLC			Noncontrolling Common Limited Partner Interests in High Sierra Energy, LP			Noncontrolling Subordinated Limited Partner Interests in High Sierra Energy, LP			Noncontrolling Interests in Subsidiaries of High Sierra Energy, LP			Accumulated Other Comprehensive Income		Total

Balance at January 1, 2009	$	8,089		$	290,617		$	55		$	7,962		$	20	$	306,743
Contributions		—			5			—			—			—		5
Contributions to variable interest entity		—			—			—			4,145			—		4,145
Distributions		(2,302	)		(33,407	)		—			(4,178	)		—		(39,887	)
Vesting of subordinated units		—			699			(699	)		—			—		—
Common units issued for business combinations		—			15,696			—			—			—		15,696
Unit based awards, net		—			—			954			—			—		954
Comprehensive income																—
Net income (loss)		987			(25,224	)		—			5,498			—		(18,739	)


Total comprehensive income (loss)																(18,739	)


Balance at December 31, 2009	$	6,774		$	248,386		$	310		$	13,427		$	20	$	268,917
Contributions		—			—			—			2,465			—		2,465
Distributions		(1,270	)		(9,257	)		—			(8,240	)		—		(18,767	)
Fair value of noncontrolling interest acquired(1)		—			—			—			19,200			—		19,200
Vesting of subordinated units		—			144			(144	)		—			—		—
Unit based awards, net		—			—			679			—			—		679
Comprehensive income (loss)																—
Net income (loss)		63			(17,168	)		—			1,215			—		(15,890	)


Total comprehensive income (loss)																(15,890	)


Balance at December 31, 2010	$	5,567		$	222,105		$	845		$	28,067		$	20	$	256,604
Contributions		—			10,010			—			—			—		10,010
Distributions		(268	)		(6,589	)		—			(2,829	)		—		(9,686	)
Noncontrolling interests acquired(2)		—			(24,245	)		—			(11,701	)		—		(35,946	)
Noncontrolling interests sold(3)		—			—			—			(15,109	)		—		(15,109	)
Fair value of units reacquired in settlement		—			(1,986	)		—			—			—		(1,986	)
Vesting of subordinated and restricted units		—			630			(630	)		—			—		—
Unit based awards, net		—			—			661			—			—		661
Comprehensive income (loss)																—
Net income (loss)		429			21,111			—			2,179			—		23,719


Total comprehensive income (loss)																23,719


Balance at December 31, 2011	$	5,728		$	221,036		$	876		$	607		$	20	$	228,267
Contributions		—			—			—			—			—		—
Distributions		(93	)		(4,397	)		—			(140	)		—		(4,630	)
Unit based awards, net		—			323			(168	)		—			—		155
Comprehensive income (loss)																—
Net income (loss)		(39	)		(2,151	)		—			30			—		(2,160	)


Total comprehensive income (loss)									��							(2,160	)


Balance at March 31, 2012	$	5,596		$	214,811		$	708		$	497		$	20	$	221,632

(1): Fair value of acquired noncontrolling interest in Monroe Gas Storage Company, LLC. SeeNote 4—Business Combinations.
(2): Noncontrolling interests in Anticline and Petro Source Products acquired. SeeNote 4—Business Combinations.
(3): Noncontrolling interests in Asgard and Monroe sold in 2011. SeeNote 5—Discontinued Operations, Dispositions and Held for Sale.

The accompanying notes are an integral part of these consolidated financial statements.

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High Sierra Energy GP, LLC and Subsidiaries

Consolidated Statements of Cash Flows

	Audited for the Years Ended December 31,									Unaudited for the Three Months Ended March 31,

	2011			2010			2009			2012			2011
	(in thousands)
Cash flows from operating activities
Net income (loss)	$	23,719		$	(15,890	)	$	(18,739	)	$	(2,160	)	$	2,731
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion		21,385			24,041			23,856			5,603			4,855
Bad debt expense (recovery)		1,152			1,871			1,254			(39	)		(71	)
Loss from equity method investments		—			1,454			2,436			—			—
Unit-based compensation		661			679			954			155			122
Change in fair value of derivative instruments, net		(4,373	)		9,164			(1,740	)		(959	)		(2,313	)
Gain on previously held equity investment of consolidated subsidiary		—			(5,436	)		—			—			—
Gain on units reacquired in settlement		(1,986	)		—			—			—			—
Loss on disposals of discontinued operations		6,350			3,913			—			1,654			—
Gain on sale of assets		(436	)		(1,050	)		(307	)		(48	)		(22	)
Impairment of assets		—			20,000			47,366			5,393			—
Changes in assets and liabilities:
Accounts receivable		(49,836	)		(40,182	)		(52,370	)		(33,445	)		(36,766	)
Inventory		(36,039	)		(3,263	)		(21,948	)		17,160			(1,433	)
Prepaids and other assets		13,521			(13,765	)		23,429			(925	)		847
Accounts payable, accrued liabilities and other		88,681			22,075			87,774			14,267			47,162


Net cash provided by operating activities		62,799			3,611			91,965			6,656			15,112


Cash flows from investing activities
Cash obtained upon consolidation of subsidiary		—			1,708			—			—			—
Cash paid for acquisitions of businesses and noncontrolling interests		(123,885	)		—			—			—			(33,515	)
(Increase) decrease in restricted cash		(2,961	)		(1,579	)		(500	)		—			3,407
Investment in certificates of deposit		—			—			(10,000	)		—			—
Proceeds upon redemption of certificates of deposit		—			2,000			8,000			—			—
Proceeds from disposals of discontinued operations		35,758			4,450			—			—			—
Investment in equity method investees		—			—			(23,274	)		—			—
Proceeds from sale of assets		1,119			9,520			1,707			91			324
Purchases of property, plant and equipment		(33,070	)		(17,262	)		(11,757	)		(7,451	)		(8,005	)


Net cash used in investing activities		(123,039	)		(1,163	)		(35,824	)		(7,360	)		(37,789	)


Cash flows from financing activities
Borrowings on lines of credit		61,184			114,549			47,873			—			15,804
Repayments on lines of credit		(104,213	)		(102,647	)		(51,074	)		—			(58,833	)
Borrowings on notes payable		—			—			2,561			—			—
Payments of principal on notes payable		(1,030	)		—			(5,247	)		—			(2,605	)
Borrowings on short-term notes and line of credit—PS Products		4,915			36,719			42,113			—			4,915
Repayments of short-term notes and line of credit—PS Products		(13,289	)		(28,345	)		(42,113	)		—			(13,289	)
Borrowings of long-term debt		145,079			—			1,237			—			72,500
Payments on long-term debt		(31,612	)		(7,484	)		(1,235	)		(2,821	)		(750	)
(Increase) decrease in cash restricted for debt service		6,793			(6,793	)		—			—			—
Refund (deposits) to collateralize letters of credit, net		3,215			(3,215	)		—			—			3,215
Deferred financing fees for credit facilities		(11,022	)		(65	)		—			—			(5,130	)
Distributions to non-controlling interest holders in subsidiaries of High Sierra Energy, LP		(2,829	)		(8,240	)		(4,178	)		(140	)		(2,609	)
Contributions from non-controlling interest holders in subsidiaries of High Sierra Energy, LP		—			2,465			—			—			79
Partner contributions in variable interest entity capital		—			—			4,145			—			—
Payments to affiliate		(138	)		(1,090	)		(142	)		—			(133	)
Distributions to partners of High Sierra Energy, LP		(6,723	)		(9,892	)		(35,626	)		(4,490	)		(133	)
Contributions from partners of High Sierra Energy, LP		10,010			—			5			—			—


Net cash provided by (used in) financing activities		60,340			(14,038	)		(41,681	)		(7,451	)		13,031


Net (decrease) increase in cash and cash equivalents		100			(11,590	)		14,460			(8,155	)		(9,646	)
Cash and cash equivalents, beginning of period		20,101			31,691			17,231			20,201			20,101


Cash and cash equivalents, end of period (including $14, $1,430, $0, $218 and $3,091 cash and cash equivalents of subsidiaries held for sale)	$	20,201		$	20,101		$	31,691		$	12,046		$	10,455




Supplemental disclosure of cash and non-cash activities
Cash paid for interest, net of amount capitalized	$	9,234		$	8,817		$	4,773		$	1,793		$	3,603
Cash paid for income taxes		—			308			974			—			—
Common units issued for business combinations		—			—			15,696			—			—

The accompanying notes are an integral part of these consolidated financial statements.

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High Sierra Energy GP, LLC and Subsidiaries

Notes to the Consolidated Financial Statements

As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 1—Organization and Basis of Presentation

Organization

High Sierra Energy GP, LLC is a Colorado limited liability company that was formed and commenced operations in 2004. As used in these financial statements, the term "the Company" refers to High Sierra Energy GP, LLC and its subsidiaries, unless the context indicates otherwise. The Company owns a 2% general partner interest in High Sierra Energy, LP ("HSE" or the "Partnership"), which is a Delaware limited partnership that was formed and began operations in 2004. The Company also owns a 98% interest in High Sierra Shared Services, LLC, a Colorado limited liability company. The Company has no significant revenue-generating operations other than its ownership interest in the Partnership.

The Partnership was formed in 2004 to operate similar to a Master Limited Partnership and conducts its operations through its primary operating subsidiaries, which have offices or facilities located in Colorado, Florida, Kansas, Oklahoma, Texas, Wyoming, Minnesota, Illinois, New Mexico, Pennsylvania, Louisiana, North Dakota, and in the Province of Alberta, Canada.

The Partnership, through its subsidiaries, is engaged in identifying, acquiring, managing, and integrating revenue generating assets in the oil and gas industry, primarily in connection with the transportation, treatment and disposal of oil and natural gas wastewater and the transportation and marketing of crude oil and natural gas liquids. The Partnership also leases well head compressor equipment under operating leases.

Basis of Consolidation and Presentation

High Sierra Energy GP, LLC consolidates all subsidiaries in which it has a controlling financial interest, including the Partnership. All significant intercompany transactions have been eliminated. The consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP").

The accompanying unaudited condensed consolidated financial statements as of March 31, 2012 and for the three months ended March 31, 2012 and 2011 have been prepared in accordance with GAAP for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission ("SEC"). The unaudited condensed consolidated financial statements include all adjustments that management considers necessary for a fair presentation of the financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed consolidated financial statements do not include all the information and notes required by GAAP for complete annual consolidated financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

The accompanying consolidated financial statements include the Company, High Sierra Shared Services, LLC, the Partnership, and all of the Partnership's controlled subsidiaries, which include: High Sierra Energy Operating, LLC ("Operating"), High Sierra Finance Corp., High Sierra Energy Marketing, LLC ("HS Marketing"), High Sierra Crude Oil and Marketing, LLC ("HSCOM"),

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As of December 31, 2011 and 2010 (audited) and March 31, 2012 (unaudited), and
For the Years Ended December 31, 2011, 2010 and 2009 (audited), and
For the Three Months Ended March 31, 2012 and 2011 (unaudited)

Note 1—Organization and Basis of Presentation (Continued)

Centennial Energy, LLC ("Centennial") and its Canadian subsidiary Centennial Gas Liquids, ULC ("CGL"), High Sierra Water Services, LLC ("HS Water"), High Sierra Water Holdings ("Water Holdings"), High Sierra Compression, LLC ("HS Compression"), High Sierra Water Services MidContinent, LLC (f/k/a/ National Coal County, LLC—"NCC"), High Sierra Transportation, LLC ("HS Transport"), Petro Source Transportation, LLC ("PS Transport"), High Sierra Ethanol, LLC ("Ethanol"), Greensburg Oil, LLC (d/b/a Nicholas Services—("Nicholas")), High Sierra Terminaling, LLC ("Terminaling"),High Sierra Monroe, LLC ("HS Monroe"), High Sierra Storage, LLC ("HS Storage"), and High Sierra Sertco, LLC ("Sertco"). During 2010, Sierra Asphalt Roofing Company, LLC ("Sarco") was merged into Terminaling. In addition, Petro Source Products, LLC ("PS Products"), a prior variable interest entity in which the Partnership was the primary beneficiary, which was purchased in March 2011, is included in the consolidated financial statements (See Note 6—Variable Interest Entity).

Investments in entities over which the Partnership has significant influence but not control are accounted for by the equity method and reported within long-term assets. As more fully discussed inNote 4—Business Combinations, HS Storage owned a 70% equity interest in Monroe Gas Storage Company, LLC ("Monroe"), a natural gas storage business, which was accounted for using the equity method of accounting until March 1, 2010. On March 1, 2010, HS Monroe became the manager and operator of Monroe and as a result the Partnership began reporting Monroe on a consolidated basis as of that date until the sale of Monroe in May 2011. The Partnership also owned a 50% equity interest in Bell Gas Gathering, LLC ("Bell Gas"), which was accounted for using the equity method of accounting until the sale of Bell Gas in 2009.

Noncontrolling Interests in Consolidated Subsidiaries

As the general partner of the Partnership, the Company has the right to control the Partnership. The equity of the Partnership's limited partners is reported asNoncontrolling limited partner interests in High Sierra Energy, LP in the accompanying Consolidated Balance Sheets and Consolidated Statements of Equity.

The Partnership has an 80% controlling interest in High Sierra Sertco, LLC ("Sertco"). The Partnership had a 75% controlling interest in Asgard Energy, LLC ("Asgard") until Asgard was sold in October 2011, a 60% controlling interest in AntiCline Disposal, LLC ("AntiCline") until the purchase of all of Anticline's membership interest not owned by the Partnership in March 2011, a 70% controlling interest in Monroe until Monroe was sold in May 2011 and a 75% interest in Redwood Resources Marketing, LLC ("Redwood") until Redwood was dissolved in 2009. In addition, until the purchase of all of PS Products' membership interests in March 2011, although it did not directly own a membership interest in PS Products, the Partnership was the primary beneficiary in, and consolidated PS Products, as further discussed inNote 6—Variable Interest Entity. Interests in subsidiaries held by other parties are reported asNoncontrolling interests in the accompanying consolidated financial statements. The noncontrolling interest amounts reported from 2012 relate to Sertco. The noncontrolling interest amounts reported for 2011 and 2010 relate to AntiCline, Asgard, Monroe,

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Sertco, and PS Products. The noncontrolling interest amounts reported for 2009 relate to AntiCline, Asgard, Sertco, PS Products and Redwood.

During 2009, among other changes as more fully described inNote 12—Goodwill and Intangible Assets, the Partnership's interest in AntiCline decreased from 75% to 60% as provided for in AntiCline's Amended and Restated Limited Liability Company Agreement, as amended, due to the attainment of certain technological and operational criteria with Anticline's discharge water treatment plant. As more fully described inNote 13—Investments in Unconsolidated Affiliate, the Partnership's interest in Monroe increased to 70% from 50% during 2009 as a result of additional cash investments by the Partnership.

Discontinued Operations and Held for Sale

During 2011, the Partnership committed to a plan to sell its interests in Terminaling, and completed the sale of its membership interests in Asgard and Monroe. During 2010, as more fully described inNote 5—Discontinued Operations, Dispositions and Held for Sale, the Partnership adopted plans to sell its interests in Asgard, NCC and Monroe, and completed the sale of certain assets of Ethanol and NCC. As a result, assets and liabilities of Asgard, Terminaling and Monroe are reported withinAssets of operations held for sale andLiabilities of operations held for sale at the lower of their carrying values or fair value less estimated costs to sell in the Consolidated Balance Sheets. The operating results of Asgard, Ethanol, NCC, Monroe and Terminaling, and the combined net loss on the disposals of Asgard, Ethanol, NCC and Monroe are reported withinDiscontinued Operations in the accompanying Consolidated Statements of Operations. Terminalling was sold in May 2012. SeeNote 5—Discontinued Operations.

Merger with NGL Energy Partners

On June 19, 2012, High Sierra Energy GP, LLC completed a merger with NGL Energy Holdings LLC whereby High Sierra Energy GP, LLC became a wholly-owned subsidiary of NGL Energy Holdings LLC. Concurrent with this merger, High Sierra Energy, LP completed a merger with NGL Energy Partners LP, whereby High Sierra Energy, LP became a wholly-owned subsidiary of NGL Energy Partners LP.

Note 2—Significant Accounting Policies

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities as of the date of the consolidated financial statements, and the reported amounts of revenues and expenses for the reporting period. Significant estimates are made with respect to, among other things, determining the fair value of derivative instruments; evaluating impairments of long-lived assets, intangible assets, goodwill and equity investments; determining the fair value of net assets resulting from business combinations, including previously held equity interests and

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noncontrolling interests; determining the fair value of assets and liabilities held for sale; the measurement and recognition of compensation expense associated with equity compensation awards; estimating accruals related to the self-funded portion of the employee health insurance benefit plan; estimating revenue and expense accruals; establishing estimated useful lives of long-lived assets; estimating asset retirement obligations; and determining liabilities, if any, associated with legal contingencies. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Cash and Cash Equivalents

Cash and cash equivalents consist of all demand deposits and funds invested in highly liquid instruments with original maturities of 90 days or less at acquisition. The Company continually monitors its positions and the credit quality of the financial institutions with which it invests and believes that its credit risk related to cash and cash equivalents is minimal. During the years ended December 31, 2011 and 2010 and the three months ended March 31, 2012, the Company has maintained balances in various operating accounts in excess of federally insured limits. The Company has not experienced any losses associated with these amounts.

Restricted Cash

In connection with the development of Monroe's natural gas storage facility, the Company had certain cash accounts which were restricted to funding construction costs and/or to servicing Monroe's debt obligations. As of December 31, 2010 restricted cash balances, all of which were reported in "Assets of operations held for sale" consisted of the following (in thousands):

Restricted Cash—Short Term	December 31, 2010

Debt Service Reserve Account	$	6,793
Capital Expenditure Reserve Account		4,232
Operating Expenditure Reserve Account		125

These restricted cash balances were held at one financial institution, and were in excess of FDIC insurance limits as of December 31, 2010.

Accounts Receivable, Accounts Payable and Offsetting Amounts Related to Certain Contracts

Certain accounts receivable, accounts payable and derivative assets and liabilities are presented on a net basis where a right of offset exists. The Company also offsets amounts of cash collateral held by the Company or deposited with counterparties arising from certain derivative instruments executed with the same counterparty under a master netting agreement against the fair value amounts reported for those derivative instruments.

Credit risk is the risk of loss that the Company would incur as a result of non-performance by counterparties pursuant to the terms of their contractual obligations. The Company grants credit in the

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normal course of business to customers in the United States and Canada and maintains credit policies with regard to its counterparties that management believes prudently manages overall credit risk. These policies include an evaluation of a counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements for the netting of positive and negative exposures associated with a single counterparty.

Management periodically reviews accounts receivable and reduces the carrying amount by an allowance for doubtful accounts that reflects management's best estimate of the amount that may not be collectible. Allowances for doubtful accounts receivable are based on available information and historical collection experience, including how recently payments have been received. The Company expenses trade receivables (i) on a general basis when a receivable reaches a certain age and (ii) on a specific identification basis when a receivable is no longer deemed collectible. Although the allowance for doubtful accounts is considered adequate, actual amounts collected could vary significantly from reported amounts.

Inventory

Inventory consists primarily of (i) natural gas liquids ("NGL"), mostly propane, butane and natural gasoline, (ii) asphalt flux and (iii) crude oil. Volumes held for immediate sale or exchange are reported as a current asset and are valued at the lower of cost or market, with cost determined using a weighted average cost method within the specific inventory pools. Transportation costs related to purchases are included in inventory.

At the end of each reporting period, an assessment of the carrying value of inventories is performed and any adjustments necessary to reduce the carrying value to lower of cost or market value are made.

Property, Plant and Equipment

Property, plant and equipment are stated at cost. Costs associated with asset purchases and/or improvements that expand existing capacity or lengthen the asset's estimated useful life are capitalized. Repairs and maintenance expenditures incurred in order to maintain the day-to-day operation of existing assets that do not extend the estimated useful lives of the related assets are charged to expense as incurred. Interest cost incurred on borrowings related to construction in progress during the construction period is also capitalized. Property, plant or equipment acquired as a result of a business combination is initially recorded at estimated fair value.

Leasehold improvements are amortized over the shorter of the improvement's estimated useful life or the lease term.

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Depreciation is provided using the straight-line method over the estimated useful lives of depreciable assets, as follows:

Asset Class		Depreciable Lives (years)

Railcars, transportation vehicles and equipment		5 to 10
Injection wells and equipment		3 to 30
Buildings, terminals, and improvements		6 to 30
Software		3

Asset Retirement Obligations

An asset retirement obligation ("ARO") is a legal obligation associated with the retirement of a tangible long-lived asset that generally results from the acquisition, construction, development or normal operation of the asset. The Company recognizes the fair value of an ARO as an addition to the cost of the related asset in the period incurred when a reasonable estimate of the amount can be made. Significant inputs used to estimate an ARO include: (i) the expected retirement date; (ii) the estimated costs of retirement, including adjustments for cost inflation and the time value of money; and (iii) the appropriate method for allocation of estimated asset retirement costs to expense. The cost for asset retirement is capitalized as part of the cost of the related long-lived assets and subsequently allocated to expense over the remaining useful lives of the assets associated with the obligation. The ARO liability accretes to the estimated total retirement obligation over the period the related assets are used through the expected retirement date.

Goodwill

Goodwill represents the cost of an acquisition less the fair value of the net assets of the acquired business. The Company evaluates goodwill for impairment as of the end of August of each year and on an interim basis whenever events or changes in circumstances indicate it is more likely than not that the fair value of a reporting unit is less than its carrying amount. Goodwill is tested for impairment at a level of reporting referred to as a "reporting unit." A reporting unit is an operating segment or one level below an operating segment for which discrete financial information is available and regularly reviewed by segment management.

Impairment testing of goodwill is a two-step process. The first step, used to identify potential impairment, compares the estimated fair value of the reporting unit with its book carrying amount, including goodwill, using a probability weighted discounted cash flow approach. When the estimated fair value is greater than book carrying value, the reporting unit's goodwill is not impaired. Conversely, if the book carrying value is greater than estimated fair value, a second step is performed to determine the amount of impairment. The second step compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying value of goodwill of a reporting unit exceeds the implied fair value of that goodwill, the excess of the carrying value over the fair value is recognized

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as an impairment loss. The implied fair value of goodwill is an estimate of the amount of goodwill that would be recognized if the reporting unit was acquired as of the impairment test date.

During the year ended December 31, 2010 the Company recognized an impairment of the goodwill in Terminaling, which is reported in "Discontinued operations—Loss from discontinued operations, net" in the Consolidated Statements of Operations. During the year ended December 31, 2009, the Company recognized an impairment of the goodwill in NCC which is reported in "Discontinued operations—Loss from discontinued operations, net" in the Consolidated Statements of Operations. SeeNote 8—Fair Value—Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis andNote 12—Goodwill and Intangible Assets for further information and disclosures.

Intangible Assets

The Company recognizes specifically identifiable intangible assets when specific rights and contracts are acquired. As more fully described inNote 12—Goodwill and Intangible Assets, all of the Company's intangible assets, other than goodwill, have finite lives and are amortized on a straight-line basis over their estimated useful lives, ranging from 4 to 25 years. Costs to renew or extend such contracts are not significant, and are expensed as incurred. The Partnership's intangible assets consist of customer contracts and relationships, patents, certain acquired permits and, prior to the sale of Monroe, Monroe's pad gas lease and tax abatement agreement which were held for sale as disclosed inNote 5—Discontinued Operations, Dispositions and Held for Sale.

The Company tests intangible assets for impairment whenever events or circumstances indicate that the carrying value may not be recoverable. The Company recognized impairments on certain intangible assets held and used by Monroe and Terminaling during the year ended December 31, 2010, and NCC during the year ended December 31, 2009. The impairment charges for discontinued operations are reported within "Discontinued operations—Loss from discontinued operations, net." SeeNote 5—Discontinued Operations, Dispositions and Held for Sale, Note 8—Fair Value—Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis andNote 12—Goodwill and Intangible Assets for further information.

Impairment of Long-Lived Assets

The Company reviews its long-lived assets, including intangible assets subject to amortization, to evaluate whether there has been an other than temporary impairment when certain events or changes in circumstances indicate that the carrying amount of the assets may not be recovered. The Company evaluates the carrying value of its long-lived assets at the business unit level. The carrying value of a long-lived asset group is considered to be unrecoverable when the undiscounted cash flows expected to result from the use and eventual disposition of the asset group are less than the asset group's carrying value. If the carrying value exceeds the sum of the undiscounted cash flows, an impairment loss equal to the amount by which the carrying value exceeds the fair value of the asset group is recognized. The

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Company considers various factors when determining if long-lived assets should be evaluated for impairment, including but not limited to:

•: A significant decrease in the market price of a long-lived asset;
•: A significant adverse change in the extent or manner in which a long-lived asset is being used or in its physical condition;
•: A significant adverse change in legal factors or in the business climate;
•: An accumulation of costs significantly in excess of the amount originally expected for the acquisition or construction of a long-lived asset;
•: A current-period operating or cash flow loss combined with a history of operating or cash flow losses or a projection or forecast that demonstrates continuing losses associated with the use of a long-lived asset; and
•: A current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

The Company also periodically evaluates its investments in unconsolidated affiliates for impairment. An impairment of an investment in an unconsolidated affiliate results when factors indicate that the investment's fair value is less than its carrying value and the reduction in value is other than temporary.

The Company recognized impairments on certain long-lived assets of Terminalling during the three months ended March 31, 2012, Monroe and Terminaling during the year ended December 31, 2010, and NCC during the year ended December 31, 2009. The impairment charges for discontinued operations are reported within "Discontinued operations—Loss from discontinued operations, net." SeeNote 5—Discontinued Operations, Dispositions and Held for Sale, Note 8—Fair Value andNote 12—Goodwill and Intangible Assets for further information.

Deferred Financing Costs

Deferred financing costs are amortized over the estimated lives of the related obligations or, in certain circumstances, accelerated if the obligation is refinanced or extinguished, on a straight-line basis, which approximates the effective interest method. Deferred financing costs are reported withinOther long-term assets in the Consolidated Balance Sheets.

Fair Value of Financial Instruments

Management believes that the carrying amounts of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities approximate fair value due to the short-term maturity of these instruments. The carrying amount of the amounts outstanding under the Company's credit facilities, notes payable, long-term debt and interest rate swap agreements approximate fair value primarily due to their variable interest rates that management believes approximate current borrowing rates, and their

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short-term duration. Derivative instruments are recorded at fair value based on available market information.

The fair value guidance defines fair value, establishes a framework for measuring fair value, establishes a three-level valuation hierarchy for disclosure of fair value measurements and expands the disclosures about fair value. A financial instrument's categorization within the valuation hierarchy is based upon the lowest level of input that is significant to the fair value measurement. The determination of fair values incorporates various factors, including the credit standing of the counterparties and the impact of credit enhancements (such as cash deposits and letters of credit). Assessment of the significance of a particular input to the fair value measurement requires judgment and considers factors specific to the asset or liability.

Fair value for financial instruments classified as Level 1 within the fair value hierarchy is based on unadjusted quoted prices for these contracts in highly liquid, active markets.

Fair value for financial instruments classified as Level 2 is based on pricing methodologies that use market prices for comparable actively traded contracts, pricing interpolated from recent trades of similar contracts, models using highly observable inputs, such as commodity options, forward prices and volatilities observable in active markets for the full term of the instruments.

Fair value for financial instruments classified as Level 3 is estimated using inputs requiring significant management judgment or estimation, and often requires the use of complex and subjective internal models and forecasts. Whenever possible, the Partnership uses market data that market participants would use when pricing an asset or liability. In addition to the unobservable inputs, Level 3 financial instruments typically include observable inputs that are not actively quoted or cannot be validated to external sources.

The methods described above may result in a fair value that may not be indicative of net realizable value or of future fair values. While the Company believes that its valuation methods are appropriate and consistent with those of other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different estimate of fair value.

SeeNote 7—Risk Management Activities and Derivative Instruments andNote 8—Fair Value for the related disclosures regarding the Company's financial derivative instruments.

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Rather than on an ongoing basis, certain assets and liabilities are measured to fair value on a nonrecurring basis when certain circumstances or events occur. These circumstances or events include but are not limited to fair value adjustments arising from impairments of long-lived assets, as a result of business combinations or a decision to hold assets for sale.

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Risk Management Activities and Derivative Instruments

The Company's primary business activities expose it to market risk from changes in commodity prices, which could cause variability in the Company's earnings and cash flows. The Company uses a variety of derivative instruments, both financial and physical based, to minimize the effects of commodity price fluctuations. Although the Company generally adopts a strategy of risk reduction through matching of physical purchases with a corresponding physical market sale, the Company's risk reduction strategy also includes the use of derivative contracts. Monroe's variable rate borrowings exposed the Company to interest rate risk from changes in Monroe's variable borrowing rate, which could have resulted in volatility in the Company's interest expense and cash interest paid. The Company used interest rate swaps for a portion of the variable rate borrowings to mitigate the effects of changes in Monroe's variable interest borrowing rate until May 2011 when the interest rate swap agreements were terminated in connection with the sale of the Company's interest in Monroe.

Interest on the Company's current borrowings as further described inNote 15—Debt under its High Sierra Credit Facility are at variable interest rates. The Company has elected not to use derivatives to mitigate the risk of interest rate changes on its interest expense and related cash flows for interest.

Derivative instruments, unless the instruments qualify for and an election has been made to apply normal purchase normal sale accounting, are reported at their fair value in the Consolidated Balance Sheets as assets or liabilities. The Company discloses the fair value of substantially all of its derivative instruments separate from other assets and liabilities under the captionFair value of derivative instruments in the accompanying Consolidated Balance Sheets.

Changes in the fair value of derivative instruments, including physically delivered derivatives for which the Company has not elected normal purchase normal sale accounting, are reported in the Consolidated Statements of Operations in the period that they occur within the financial statement line related to the item economically hedged by the instrument. Realized and unrealized gains and losses on derivative instruments are reported within eitherRevenues orInterest expense. Revenue gains or losses relate to instruments used to hedge the cash flow associated with the sale and purchase of products. Interest expense gains or losses related to interest rate swap agreements used to manage the interest rate risk associated with Monroe's variable interest borrowings. Changes in risk management activities are reported in cash flows from operating activities in the Company's Consolidated Statements of Cash Flows.

The Company has determined that substantially all of its forward physical commodity purchase and sale agreements, with certain exceptions, qualify for the normal purchase normal sale accounting. Revenues and costs of purchases associated with these contracts are recognized on the accrual basis of accounting on the date of sale or purchase, respectively.

Deferred Gain on Sale Leaseback Transaction

The Company amortizes deferred gains on the sale and leaseback of railcar equipment under operating leases on a straight-line basis over the related lease terms. The amortization of these gains is

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reported as a reduction to the related rent expense. SeeNote 20—Commitments and Contingencies—Sale Leaseback Transaction for additional information.

Revenue Recognition

Revenues from sales of crude oil, NGL, water and other hydrocarbon products are recognized on a gross basis at the time title to the product sold transfers to the purchaser and collection of those amounts is reasonably assured. Sales or purchases with the same counterparty that are entered into in contemplation of one another are reported on a net basis as one transaction. Revenue from wastewater disposal trucking services is recognized when the wastewater is picked up from the customer's location, and in other cases upon delivery of the wastewater to a specific delivery location, depending upon the terms of the contractual agreements. Revenue from other transportation services is recognized upon completion of the services as defined in the customer agreement. Revenue on equipment leased under operating leases is billed and recognized monthly according to the terms of the related lease agreement with the customer over the term of the lease. Net gains and losses resulting from commodity derivative instruments are recognized within revenues.

Revenues for the wastewater disposal business are recognized upon delivery of the wastewater to the disposal facilities. Certain agreements require customers to deliver minimum quantities of wastewater for an agreed upon period. Revenue is recognized when the wastewater is delivered, with an adjustment for the minimum volume delivery in the event that actual delivered wastewater is less than the committed minimum. Revenues from crude oil condensate recovered from wastewater are recognized upon delivery to the customer.

Revenues from Monroe's firm natural gas storage reservation agreements provided for a fixed monthly capacity reservation fee payable regardless of the actual capacity utilized, and were recognized ratably over the terms of the related storage agreements. Firm storage revenues for the use of injection and withdrawal services based on the volume of natural gas nominated for injection or withdrawal were recognized as the volumes are nominated. Hub service revenues, including "park and loan" services, were recognized in revenue as the services were provided.

Amounts billed to customers for shipping and handling costs are included inRevenues in the Consolidated Statements of Operations. Shipping and handling costs associated with product sales are included inOperating expenses in the Consolidated Statements of Operations. Taxes collected from customers and remitted to the appropriate taxing authority are excluded fromRevenues in the Consolidated Statements of Operations.

Revenue and Expense Accruals

The Company routinely makes accruals based on estimates for both revenues and expenses due to the amount of time required to receive third party information, compile billing information and reconcile the Company's records with those of its third party customers and vendors. Information that is delayed includes, among others, actual volumes purchased, transported or sold, adjustments to inventory and invoices for purchases, actual product deliveries, and other operating expenses. The

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Company makes accruals that report these items at their estimated amounts based on internal records and information from third parties. Estimated accruals are reversed in the following month when actual information has been received from third parties and reconciled to the Company's internal records.

Foreign Currency Translation

The functional currency of the Partnership's Canadian subsidiary, CGL, is the US dollar. As of January 1, 2009, CGL had cumulative translation adjustments of $20,000 which will remain in accumulated other comprehensive income until the entity is sold or dissolved.

Comprehensive Income

Other than net income (loss), the Company had no other sources of comprehensive income for the three months ended March 31, 2012 and for the years ended December 31, 2011, 2010 and 2009.

Business Combinations

Transactions or events in which the Company acquires a controlling financial interest in a business are accounted for under the acquisition method. The identifiable assets, liabilities, any previously held equity interest and any noncontrolling interests are recorded at their estimated fair values as of the business combination date. The excess of consideration paid over the fair value of the net assets acquired, if any, is recognized as goodwill.

Equity Method of Accounting

Investments in the equity of entities where the Company has significant influence, but not a controlling financial interest or a variable interest in which the Company is not the primary beneficiary, were accounted for under the equity method of accounting. The Company has no equity method investees as of March 31, 2012, December 31, 2011, and December 31, 2010. The assets or liabilities of equity investees are not consolidated. The Company's share of the net income or loss of its equity investees is reported as one line item in the Consolidated Statements of Operations, and increases or decreases, as applicable, the carrying value of the Company's investments in equity investees in its Consolidated Balance Sheets. Contributions from the Company to these investees increase the carrying value of the Company's investment. Distributions to the Company from these investees reduce the carrying value of the Company's investment. Both contributions to and distributions from investees involving the Company are reported withinInvesting Activities in the Consolidated Statements of Cash Flows.

Accounting for Changes in Ownership Interests in Subsidiaries or Equity Investees

The Company's ownership interest in a consolidated subsidiary may change if the Company sells a portion of its interest, purchases a portion of the subsidiary's interest not owned by the Company, or if the subsidiary issues new equity or repurchases equity. If the transaction does not result in a change in the Company's controlling financial interest in the subsidiary and is not deemed a sale of real estate,

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the transaction is accounted for as an equity transaction. If the transaction results in a change in controlling financial interest, it is accounted for as a business combination at fair value where control is acquired, or as a sale and deconsolidation where control is relinquished.

In March 2011, the Partnership acquired all of the noncontrolling membership interests of Anticline and PS Products. These acquisitions did not result in a change in the Partnership's controlling interest in these subsidiaries and were accounted for within equity.

In March 2010, the Partnership acquired a controlling financial interest in Monroe, a previously held equity investee, which was accounted for as a business combination. SeeNote 4—Business Combinations for a description of this event and its effect on the consolidated financial statements.

Income Taxes

The Company and the Partnership have elected to be treated as partnerships for federal and state income tax purposes within the United States ("U.S."). As such, the Company does not directly pay U.S. federal income taxes, but does pay taxes in certain states that are accounted for as income taxes. The Company's U.S. taxable income or loss, which may vary substantially from the net income or loss reported in the accompanying Consolidated Statements of Operations, is includable in the income tax returns of the Company's members and the Partnership's partners. However, the Partnership's wholly-owned Canadian subsidiary CGL is taxable in Canada. The income tax expense or benefit reported in the Consolidated Statements of Operations represents Canadian income taxes on CGL's taxable income.

The Company accounts for income taxes using the asset and liability method. Deferred income taxes are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their bases for income tax purposes, capital loss carryforwards and net operating loss and credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of any tax rate change on deferred taxes is recognized in the period that includes the enactment date of the tax rate change. Realizability of deferred tax assets is assessed, and if it is more likely than not that a portion or all of the deferred tax assets will not be realized, a valuation allowance is recorded to reduce the deferred tax assets to their estimated net realizable value. Deferred tax amounts expected to be settled within the next twelve months are classified as current, and all other deferred tax amounts are classified as long term in the accompanying Consolidated Balance Sheets.

To account for uncertainty in income taxes, the Company applies a "more likely than not" recognition threshold and measurement attribute to the financial statement recognition and measurement of an income tax position taken or expected to be taken in an income tax return. The Company records penalties related to income tax items as a component of general and administrative expenses, and interest expense related to income tax items as a component of interest expense.

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Note 2—Significant Accounting Policies (Continued)

Other Taxes

The Company is subject to other taxes assessed by various governmental authorities such as goods and services tax, sales and use tax, utility users' tax, business franchise taxes, and Propane Education Research Council assessments. The Company records these taxes withinOperating costs and expenses in the accompanying Consolidated Statements of Operations.

Unit-Based Compensation

Equity classified unit-based compensation cost is measured at fair value, based on the estimated fair value of the common unit at the grant date, and is recognized as expense over the vesting period. The Company estimates the fair value of units granted using prices paid by third parties for the same instrument, or values disclosed in financial statements filed with the Securities and Exchange Commission by an investor on or nearest to the grant date adjusted for various factors including voting rights, the lack of liquidity, the existence of minority interests and distribution rights.

Note 3—Recently Issued Accounting Pronouncements

The following outlines the recent guidance that is applicable to the Company and has or may have an impact on the consolidated financial statements and related disclosures:

Fair Value Measurements and Disclosures

In May 2011, the Financial Accounting Standards Board amended the accounting guidance for fair value measurement and disclosure. The amended guidance was intended to associate the fair value measurement and disclosure requirements under GAAP with those under International Financial Reporting Standards. The amendment primarily clarifies the application of the existing guidance and provides for increased disclosures, particularly related to Level 3 fair value measurements. The amended guidance became effective for the Company prospectively as of January 1, 2012. The adoption of the amended guidance did not have a material effect on the Company's consolidated financial statements.

Intangibles—Goodwill and Other

In September 2011, the FASB amended the accounting guidance for goodwill impairment testing. The amended guidance provides an entity with an option to first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as the basis for determining whether it is necessary to perform the two-step goodwill impairment test. This guidance became effective for the Company as of January 1, 2012. The adoption of the amended guidance did not have a material effect on the Company's consolidated financial statements.

In December 2010 the FASB has issued an update to its guidance regarding goodwill impairment testing for reporting units with zero or negative carrying amounts. For those reporting units, "Step 2" of the goodwill impairment test is required if it is more likely than not that a goodwill impairment exists. In determining whether it is more likely than not that a goodwill impairment exists, the guidance

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requires consideration of qualitative factors that are consistent with the existing guidance and examples, which require that goodwill of a reporting unit be tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. This guidance became effective for the Company on January 1, 2012. The adoption of the amended guidance did not have a material effect on the Company's consolidated financial statements.

Note 4—Business Combinations

The results of operations for all business combinations are included in the Company's Consolidated Statements of Operations beginning with the date of the business combination. As more fully described inNote 12—Goodwill and Intangible Assets, the purchase price for certain business combinations made prior to 2009 included contingent consideration in the form of subordinated units that are accounted for as additional consideration provided certain vesting conditions are met.

High Sierra Water Services, LLC

On June 1, 2011, the Partnership acquired substantially all of the wastewater disposal assets of Marcum Midstream 1995-2 Business Trust and Marcum Midstream 1995-EC Holdings, LLC ("Marcum") (the "Marcum Acquisition"), which assets had been operated under the trade name Conquest Water Services ("Conquest"). The Marcum Acquisition was completed in exchange for $85.2 million in cash and, pursuant to two employment agreements which were entered into as part of the acquisition, additional estimated future cash consideration of $1.4 million payable 26 months after the purchase date. The amount of additional cash consideration that may ultimately be paid by the Partnership is based upon a multiple of earnings before interest, income taxes, depreciation and amortization ("EBITDA") less a portion of accumulated capital expenditures for the twelve months ending June 30, 2013, or the twelve months prior to termination of employment, whichever occurs earlier. Subsequent adjustments to the estimated fair value of the additional cash consideration will be reported as a component of operating expenses until ultimate cash settlement of the liability occurs. Changes in the estimated value of this liability, which were $0 and a reduction of $0.2 million for the three months ended March 31, 2012 and the year ended December 31, 2011, respectively, are recorded withinOperating expenses in the Consolidated Statement of Operations. The goodwill amount recognized relates primarily to the assembled workforce and expected growth of the business.

The Marcum Acquisition was funded from an increase in the Company's credit facility and the proceeds from issuance of 385,000 common units in exchange for $10.0 million cash. Information regarding the credit facility is disclosed inNote 15—Debt. Information regarding common units issued is disclosed inNote 17—Partners' Capital and Distributions.

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Note 4—Business Combinations (Continued)

The recognized amounts of identifiable assets acquired and liabilities assumed, based upon their estimated fair values as of June 1, 2011, were as follows (in thousands):


Other current assets	$	259
Property, plant and equipment		22,110
Intangible assets(1)		20,250
Goodwill		44,305


Total assets		86,924


Accrued liabilities		104
Asset retirement obligations		176
Deferred compensation liability(2)		1,431


Total liabilities		1,711


Net assets acquired	$	85,213

(1): Intangible assets consist of customer relationships and non-compete agreements of $20 million and $0.3 million, respectively.
(2): The estimated fair value of the earnings based future cash consideration at the purchase date. The amount of this liability will increase or decrease based upon a multiple of EBITDA less a portion of capital expenditures. Amounts due are payable in cash on July 30, 2013. As of March 31, 2012 the estimated value of this liability was $1.3 million.

Anticline and Petro Source Products

On March 16, 2011 the Partnership acquired all of the remaining membership interests in Anticline. The purchase price was $30.0 million. The purchase also included a payment of 40% of the working capital amount in excess of $0.8 million to the former noncontrolling members, which amounted to $2.0 million and was paid in June 2011. In addition a payment in the amount $2.2 million representing distributions due to Anticline's former noncontrolling members was made. Finally the Partnership and Anticline agreed to terminate the existing Royalty Agreement between the parties.

On March 16, 2011 the Partnership acquired all of the membership interests in PS Products. The purchase price was $6.7 million, which was the amount of equity contributed by, plus accrued interest due to, the previous noncontrolling interest owners. There are no other payments or adjustments related to the purchase of PS Products.

Monroe Gas Storage Company, LLC

Effective March 1, 2010, HS Monroe became the operator and manager of Monroe, and as a result HS Storage gained a controlling financial interest in Monroe. Monroe is a developer and operator of a natural gas storage facility located in Mississippi. The results of operations of Monroe were consolidated with those of the Partnership beginning March 1, 2010. No cash or other

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Note 4—Business Combinations (Continued)

consideration was exchanged for Monroe, and no significant transactions costs were incurred. Membership interests in Monroe owned by the Partnership as of the transaction date had a fair value of $44.8 million. The recognized amounts of identifiable assets acquired and liabilities assumed, based upon their fair values as of March 1, 2010, were as follows (in thousands):


Current assets (including cash acquired of $1.7 million)	$	6,039
Long term assets		142,995
Intangible customer assets		128
Other intangible assets		22,493
Non-recourse long-term debt		(98,412	)
Other liabilities assumed		(9,243	)


Total net assets acquired	$	64,000

The Partnership recognized a gain of $5.4 million as a result of remeasuring to fair value its previously held equity investment in Monroe as of the date of the business combination. The fair value of the previously held equity interest was estimated using a weighting of income and market values for similar gas storage companies. The gain was recognized in "Discontinued operations—Loss from discontinued operations, net" in the Consolidated Statement of Operations for the year ended December 31, 2010.

As discussed further inNote 5—Discontinued Operations, Dispositions and Held for Sale, the Partnership committed to a plan to sell its interest in Monroe effective November 1, 2010, and concluded the sale of its interest in Monroe in May 2011. The Partnership was subsequently notified of claims by the purchaser for alleged breach of representations in the merger agreement. SeeNote 20—Commitments and Contingencies—Legal Contingencies.

Note 5—Discontinued Operations, Dispositions and Held for Sale

Discontinued Operations

During 2011, the Partnership committed to plans to dispose of its wholly-owned subsidiary, Terminaling. During 2010, the Partnership committed to plans to dispose of its 75% controlling interest in the business operations of Asgard, the Partnership's wholly-owned subsidiary NCC, and HS Storage's 70% controlling interest in the business operations of Monroe. The Partnership will not and does not have continuing involvement in the operations of Asgard, NCC or Monroe and their operations and cash flows have been eliminated from those of other ongoing operations of the Partnership.

Terminaling. Terminaling is held for sale as of December 31, 2011 and March 31, 2012. As discussed further inNote 23—Subsequent Events, the Partnership completed the sale of Terminalling on May 31, 2012. In connection with the sale, the Partnership recognized an impairment of the carrying value of the Teminalling assets of $5.4 million, which is reported inIncome (loss) from discontinued operations, net in the Consolidated Statement of Operations for the three months ended March 31, 2012.

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Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

Asgard. Asgard was held for sale as of December 2010. In October 2011, the Partnership sold its membership interests in Asgard for $6.2 million plus the value of Asgard's derivative contracts of $2.8 million, subject to customary working capital adjustments. The Partnership has been notified of claims by one of Asgard's trading partners, and a similar claim by the purchaser of Asgard, for alleged breach of representation in the purchase and sale agreement. SeeNote 20—Commitments and Contingencies—Legal Contingencies for additional information.

Ethanol. In October 2010, the Partnership sold Ethanol's tangible and intangible assets for approximately $2.3 million. Ethanol was dissolved in November 2010.

NCC. Effective December 31, 2010, the Partnership sold substantially all of NCC's tangible and intangible assets to a related party for $2.2 million. In addition, the Partnership agreed to sell an additional land parcel for $300,000, contingent upon providing the buyer with satisfactory title to the land. The land parcel was sold during December 2011. The Partnership was contingently liable for environmental claims asserted by the buyer within 180 days, up to a maximum of $2.2 million as of December 31, 2010. The Partnership accrued an estimated $0.4 million for these contingencies as of December 31, 2010; during 2011, this accrual was released as no environmental liabilities or claims were asserted during the allotted time frame.

In June 2011, the Partnership entered into a settlement agreement with the former owners from the original acquisition of NCC by the Partnership in which the parties agreed to a full release and dismissal of all claims. In connection with this settlement the former owners of NCC agreed to relinquish all rights, title and interest in their 76,389 Partnership units ("Relinquished Units"). The Partnership received $0.5 million of amounts previously held in escrow, and agreed to pay a total of $0.4 million to the former owners of NCC, contingent upon receipt of satisfactory title to two of NCC's land properties. In addition, in prior years the Partnership had accrued $2.1 million for an estimated settlement related to the acquisition of NCC. As a result of the settlement with the former owners of NCC, the Partnership reversed the entire $2.1 million accrual. The $0.5 million escrow settlement received and the reversal of the accrual were recorded withinOther Income (expense)—Other income (loss), net in the accompanying Consolidated Statement of Operations for the year ended December 31, 2011. The Partnership recorded a gain of $2.0 million related to the Relinquished Units asOther Income (expense)—Other income (loss), net in the accompanying Consolidated Statement of Operations for the year ended December 31, 2011.

Monroe. Monroe was held for sale as of December 31, 2010. In May 2011, the Partnership sold its 70% membership interest in Monroe for $147.0 million together with a purchase option on land for an adjacent natural gas storage property for $1.0 million, subject to normal working capital adjustments. In connection with the closing, amounts due under the Monroe credit facility and the Monroe Interest Rate Swap agreements aggregating $103.7 million were repaid in full. Cash proceeds received by the Partnership after deductions for a pro rata share of funds held in escrow and transaction costs were $20.9 million. In addition, the Partnership received a $6.8 million repayment of principal and interest loaned to Monroe by the Partnership, and $1.0 million for the sale of an option to purchase a property

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Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

adjacent to the Monroe site. These proceeds, along with other available funds from operations, were used to pay down principal on the Partnership's credit facility term loans.

In connection with the sale of Monroe a portion of the sales price was held in escrow to provide a general indemnity to the purchaser amounting to $11.6 million, and an additional escrow of $0.5 million to provide for the settlement of customary working capital items. Of the total escrowed amounts, the Partnership was entitled to 70%, with the remaining 30% to Monroe's former noncontrolling interest holders. As of December 31, 2011, the Partnership was in negotiations regarding several working capital items, and had been notified by the purchaser of a claim of breach of representations in the merger agreement. SeeNote 20—Commitments and Contingencies—Legal Contingencies for additional information. At December 31, 2011, the Partnership had recorded an allowance of approximately $1.9 million on the funds in escrow. Included withinPrepaids and other current assets on the accompanying Consolidated Balance Sheet at December 31, 2011 was $6.7 million related to the Partnership's share of the funds in escrow, net of the allowance. In May 2012, the Partnership and the purchaser agreed to a settlement whereby the Partnership would receive approximately $5.0 million of the funds in escrow. The Partnership recorded a loss of $1.7 million, reported withinLoss on disposal of discontinued operations in the accompanying Consolidated Statement of Operations for the three months ended March 31, 2012, to reduce the carrying value of the asset to the recoverable amount.

Redwood. Redwood was held for sale and was sold in 2008. After the sale of Redwood in 2008, certain assets and liabilities, primarily open inventory positions, were retained. The retained net assets were sold during 2009. Revenues and expenses in 2010 relate to proceeds and expenses associated with the settlement of a legal dispute.

High Sierra Power Marketing, LLC and Sierra Power Asset Marketing, LLC. In 2008, the Partnership adopted a plan to discontinue operations of two subsidiaries, High Sierra Power Marketing, LLC ("HS Power") and Sierra Power Asset Marketing, LLC ("Sierra Power") which together comprised the Power Marketing Business group. Neither HS Power nor Sierra Power had remaining assets or liabilities and were dissolved effective December 30, 2009.

The revenues, net income (loss) and gain (loss) on disposal from these companies reported withinDiscontinued operations within the accompanying Consolidated Statements of Operations are as follows (in thousands):

	Year Ended December 31, 2011

	Asgard(1)		Monroe(2)			NCC		Terminaling			Total
Revenues	$	40,466	$	5,806		$	16	$	6,947		$	53,235
Income (loss) from operations(3)		58		(1,167	)		909		(1,102	)		(1,302	)
Net income (loss)(3)		58		(15,574	)		1,547		(1,102	)		(15,071	)
Gain (loss) on disposal		7,475		(14,407	)		582		—			(6,350	)

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Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

	Year Ended December 31, 2010

	Asgard			Ethanol		Monroe			NCC			Redwood		Terminaling			Total
Revenues	$	45,780		$	688	$	12,816		$	11,626		$	759	$	20,417		$	92,086
Income (loss) from operations		(2,331	)		2,464		(12,585	)		(6,265	)		695		(9,658	)		(27,680	)
Net income (loss)(3)		(2,562	)		2,474		(14,482	)		(6,523	)		241		(9,774	)		(30,626	)
Gain (loss) on disposal		—			2,034		—			(5,947	)		—		—			(3,913	)

	Year Ended December 31, 2009

	Asgard		Ethanol		NCC			Redwood			Terminaling			HS Power			Sierra Power		Total
Revenues	$	39,743	$	861	$	14,227		$	7,383		$	13,972		$	6		$	57	$	76,249
Income (loss) from operations		4,534		592		(56,217)	(4)		(70	)		(1,097	)		(36	)		57		(52,237	)
Net income (loss)(3)		4,478		609		(56,795	)		(42	)		(1,256	)		(25	)		95		(52,936	)

	Three Months Ended March 31, 2012

	Monroe			NCC			Terminaling			Total
Revenues	$	—		$	—		$	671		$	671
Income (loss) from operations(3)		—			(259	)		(5,323	)		(5,582	)
Net income (loss)(3)		(1,654	)		(259	)		(5,323	)		(7,236	)
Gain (loss) on disposal		(1,654	)		—			—			(1,654	)

	Three Months Ended March 31, 2011

	Asgard		Monroe		NCC			Terminaling			Total
Revenues	$	23,946	$	3,494	$	7		$	1,737		$	29,184
Income (loss) from operations(3)		2,496		368		(105	)		(301	)		2,458
Net income (loss)(3)		2,424		214		(105	)		(368	)		2,165
Gain (loss) on disposal		—		—		—			—			—

(1): Amounts for Asgard are for the ten month period beginning January 1, 2011, through October 31, 2011, the date Asgard was sold.
(2): Amounts for Monroe are for the five month period beginning January 1, 2011 through May 31, 2011, the date Monroe was sold.
(3): Amounts of net income (loss) above include intercompany interest and corporate allocations that are excluded from theLoss from discontinued operations, net reported in the Consolidated Statements of Operations.
(4): Includes an impairments of $47.4 million.

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Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

Held for Sale

As of March 31, 2012 and December 31, 2011 the assets and liabilities of Terminaling have been reported as held for sale at the lower of their carrying value or estimated fair value less costs to sell. The carrying amounts of the major classes of assets and liabilities were as follows (in thousands):

	December 31, 2011 Terminaling		March 31, 2012 Terminaling

Cash and cash equivalents	$	14	$	218
Trade accounts receivable, net		468		109
Inventory		211		192
Prepaids and other current assets		121		76
Property, plant and equipment, net		6,595		2,222
Other intangibles, net		1,258		238


Total assets of operations held for sale	$	8,667	$	3,055




Accounts payable—trade	$	110	$	126
Accrued liabilities and other current liabilities		266		243


Total liabilities of operations held for sale	$	376	$	369

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Notes to the Consolidated Financial Statements (Continued)

Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

As of December 31, 2010 the assets and liabilities of Asgard and Monroe were reported as held for sale at the lower of their carrying value or estimated fair value less costs to sell. The carrying amounts of the major classes of assets and liabilities were as follows (in thousands):

	December 31, 2010

	Asgard		Monroe		Total
Cash and cash equivalents	$	566	$	864	$	1,430
Restricted cash		—		11,150		11,150
Trade accounts receivable, net		11,322		1,505		12,827
Inventory		935		—		935
Prepaids and other current assets		395		403		798
Property, plant and equipment, net		2		132,215		132,217
Other intangibles, net		—		11,395		11,395
Other long-term assets		—		7,558		7,558


Total assets of operations held for sale	$	13,220	$	165,090	$	178,310




Borrowings under non-recourse credit facility—current	$	—	$	6,300	$	6,300
Accounts payable—trade		7,217		1,370		8,587
Accrued liabilities and other current liabilities		951		1,033		1,984
Fair value of derivative instruments—current		1,890		1,361		3,251
Borrowings under non-recourse credit facility—long term		—		89,651		89,651
Fair value of derivative instruments—non current		323		1,083		1,406
Other long term liabilities		—		2,191		2,191


Total liabilities of operations held for sale	$	10,381	$	102,989	$	113,370

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Notes to the Consolidated Financial Statements (Continued)

Note 5—Discontinued Operations, Dispositions and Held for Sale (Continued)

Assets and Liabilities of Discontinued Operations Included in Consolidated Balance Sheets

As of December 31, 2011 and 2010, amounts for NCC that are included in the Consolidated Balance Sheets, but not included in the assets and liabilities of operations held for sale, were as follows (in thousands):

	December 31,

	2011			2010
Cash and cash equivalents	$	152		$	278
Trade accounts receivable, net		4			1,504
Accounts receivable—intercompany		—			77
Prepaids and other current assets		110			520
Property, plant and equipment, net		83			70


Total assets	$	349		$	2,449




Accounts payable—trade	$	9		$	2,688
Accounts payable—affiliates		—			19,153
Accrued liabilities and other current liabilities		653			1,136
Other long term liabilities		—			392


Total liabilities		662			23,369


Member equity		(313	)		(20,920	)


Total liabilities and equity	$	349		$	2,449

Remaining activities at NCC are primarily reclamation of a disposal pit property.

Note 6—Variable Interest Entity

Petro Source Products, LLC

PS Products ("the former VIE") is engaged primarily in the purchase or brokering of condensate, NGLs and crude oil. PS Products sells its products to other third parties and also to a subsidiary of the Partnership, which then sells the products to its third party customers. In March 2011 the Partnership purchased all of the membership interests in PS Products and became the sole member.

At inception on January 1, 2009, prior to its acquisition by the Partnership, PS Products was financed through member equity contributions and a bank line of credit as more fully described inNote 15—Debt—Petro Source Products Credit Facility. The Partnership did not own PS Products membership interests until March 2011. Some members of PS Products were also common unitholders, officers and/or employees of the Partnership.

PS Products entered into a Trading Agreement, as amended, (the "Agreement") with the Partnership on January 1, 2009. As defined in the Agreement, the Partnership earned a residual amount of income calculated as the former VIE's gross margin less operating costs and a fixed return

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Note 6—Variable Interest Entity (Continued)

to its equity members. The former VIE reported net income (loss) of $0.1 million during the period January 1, 2011 through March 16, 2011, and $(1.3) million and $0.5 million for the years ended December 31, 2010 and 2009, respectively. The Partnership earned income and collected cash from PS Products in accordance with the Trading Agreement from January 1, 2009 through March 16, 2011. During the period January 1, 2011 through March 16, 2011, the Partnership earned $0.6 million. For the years ended December 31, 2010 and 2009, the Partnership earned $2.7 million and $2.2 million, respectively. PS Products made no cash distributions to the Partnership during the period January 1, 2011 through March 16, 2011, and $1.25 million and zero cash distributions for the years ended December 31, 2010 and 2009, respectively. The Company eliminates all intercompany transactions in the Company's consolidated financial statements.

Significant Judgments Regarding PS Products

Prior to purchasing the membership interests of PS Products, the Partnership had determined that it was the primary beneficiary of the former VIE because per the Agreement the former VIE's equity members (i) lacked the right to receive residual returns of PS Products, and (ii) the Partnership was obligated to provide a full indemnity for trading losses, if any, incurred by PS Products. No amounts were incurred or paid under this indemnity, and no financial support was provided to the former VIE by the Partnership from its inception through its acquisition by the Partnership.

Financial Statement Impact of PS Products

Prior to March 2011, as the primary beneficiary, the Partnership consolidated the former VIE and recognized a noncontrolling interest for PS Products' membership equity. The assets, liabilities and

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Note 6—Variable Interest Entity (Continued)

operations attributable to PS Products while it was a VIE included in the Partnership's consolidated financial statements were as follows (in thousands):

Balance Sheet	As of December 31, 2010

Cash and cash equivalents	$	29
Accounts receivable, trade		29,716
Accounts receivable intercompany(1)		25,647
Inventory		7,140
Prepaids and other current assets		3,227


Total assets	$	65,759




Borrowings under line of credit	$	8,374
Accounts payable, trade		20,296
Accounts payable, intercompany(1)		30,674
Accrued liabilities and other		3,069


Total liabilities		62,413
Partner's capital(1)		3,346


Total liabilities and partners' capital	$	65,759

(1): Eliminates in consolidation

Statement of Operations	For the Period January 1 - March 16, 2011		Year ended December 31, 2010			Year ended December 31, 2009

Revenue	$	119,518	$	396,054		$	150,010
Operating, product, transportation and general and administrative expenses		118,414		394,112			146,233


Operating income		1,104		1,942			3,777
Interest income and expense, net		994		3,214			3,304


Net income (loss) attributable to noncontrolling interests	$	110	$	(1,272	)	$	473


Net income (loss) attributable to the Partnership	$	—	$	—		$	—

Prior to March 2011, the assets of PS Products were the property of the former VIE and were not available to the Partnership for any purpose. The creditors of PS Products had recourse only to the assets of the former VIE, and no recourse to the Partnership's general assets or credit.

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Note 7—Risk Management Activities and Derivative Instruments

Commodity Instruments

The Partnership's primary risk management objective is to reduce the volatility in its cash flows arising from changes in commodity prices related to future sales or purchases of NGLs, crude oil and, prior to the sale of the Partnership's interest in Asgard, natural gas. Derivative instruments are used to economically hedge exposure to price fluctuations with respect to these commodities. The derivative instruments used consist primarily of swaps traded in over-the-counter markets. The Partnership has mitigated a significant portion of its expected commodity price risk with derivative agreements that expire at various times through March 2013.

Physical transactions that are derivatives and are ineligible, or become ineligible, for normal purchase normal sale accrual accounting are accounted for as derivative assets or liabilities at fair value, with the changes in fair value recorded net in revenues. Substantially all of the Partnership's physical purchase and sale forward contracts qualify for the normal purchase normal sale election and accordingly are recognized under accrual accounting as the purchases or sales occur.

The use of commodity derivatives may allow the Partnership to reduce volatility in its realized margins as realized gains or losses on derivative instruments generally are offset by corresponding gains or losses in the Partnership's sales or purchases of physical products. While realized derivative gains and losses are generally expected to be offset by increases or decreases in value of physical sales or purchases, the Partnership's derivative instruments are reported at fair value in the Company's Consolidated Balance Sheets.

Credit reviews of derivative counterparties are conducted and agreements containing collateral requirements are made when considered necessary. In addition, the Partnership uses standard master netting agreements with several of its counterparties that allow for the offset of positive and negative exposures with its counterparties and offsets the assets and liabilities associated with the fair value of the derivatives with these counterparties, and with amounts related to the Partnership's right to receive or obligation to pay cash collateral.

The use of derivative instruments may create exposure to the risk of financial loss in certain circumstances, including when (i) NGLs do not trade at historical levels relative to crude oil, (ii) sales volumes are less than expected, requiring market purchases to meet commitments, or (iii) counterparties fail to purchase or deliver contracted commodity quantities or otherwise fail to perform. To the extent the Partnership engages in derivative activities, it may be prevented from realizing the benefits of favorable market price changes in the physical market. However, the Partnership may be similarly insulated against losses resulting from unfavorable changes in market pricing in the physical market.

Position Management Program

In connection with managing inventory positions and maintaining a constant presence in the marketplace, both necessary for the Partnership's core business, the Partnership has established maximum net open position limits (the sum of the absolute values of all long and short positions for which there is no offsetting purchase or sale within the same product type), a stop loss limit (the

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Note 7—Risk Management Activities and Derivative Instruments (Continued)

maximum aggregate dollar value of cumulative physical and financial realized and unrealized losses on open positions), and tenor limits (the maximum permitted term of open contract positions). These activities are monitored independently by the Partnership's risk management function and take place within predefined limits and authorizations.

Interest Rate Instruments

Prior to the sale of Monroe, the Partnership's borrowings included both fixed and variable interest rate debt. Monroe had entered into interest rate swap agreements to manage the interest rate risk associated with its variable rate borrowings, which effectively converted a portion of Monroe's variable interest rate payments to fixed rate interest payments per the agreements. As a result, a portion of Monroe's interest payment cash flows were insulated from the effects of increases in the variable borrowing rate. Conversely, Monroe was similarly prevented from realizing a portion of the benefits of favorable changes in the variable interest borrowing rate.

Financial Statement Impact of Derivative Instruments

The Partnership does not designate or account for derivatives as either cash flow or fair value hedges. Changes in the fair value of commodity derivatives are reported within revenues each period. Changes in the fair value of interest rate derivatives were reported as a component of interest expense each period. Cash settlements associated with derivative activities are reported as operating cash flows in the Consolidated Statements of Cash Flows.

The impact of the Partnership's derivative instruments on the Company's Consolidated Balance Sheets and Statements of Operations are summarized below (in thousands):

	Derivative Assets Fair Value As Of						Derivative Liabilities Fair Value As Of

Derivative contracts and their location in the Consolidated Balance Sheets	December 31, 2011		December 31, 2010		March 31, 2012		December 31, 2011		December 31, 2010			March 31, 2012
*Commodity Contracts*
Fair value of derivative instruments—current	$	4,481	$	2,327	$	5,946	$	1,451	$	3,412		$	1,580
Liabilities of operations held for sale		—		—		—		—		(2,213	)		—
*Interest Rate Contracts*
Fair value of derivative instruments—current		—		—		—		—		2,444			—
Liabilities of operations held for sale		—		—		—		—		(2,444	)		—


Total	$	4,481	$	2,327	$	5,946	$	1,451	$	1,199		$	1,580

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Note 7—Risk Management Activities and Derivative Instruments (Continued)

	Year Ended December 31,								Three Months Ended March 31,

Derivative contracts and the location of gain or loss in the Consolidated Statements of Operations	Year Ended December 31,								Three Months Ended March 31,
	2011		2010			2009			2012			2011
*Revenue: Derivative gain (loss)*
Realized gain (loss)	$	10,140	$	6,677		$	18,349		$	(3,515	)	$	(302	)
Unrealized gain (loss)		4,373		(7,958	)		1,740			1,194			872
*Interest Expense: Derivative gain (loss)*
Realized gain (loss)		—		(1,463	)		—			—			—
Unrealized gain (loss)		—		(1,206	)		—			—			—


		14,513		(3,950	)		20,089			(2,321	)		570
Discontinued operations(1)		1,753		4,039			(1,652	)		—			954


Total gain (loss)	$	16,266	$	89		$	18,437		$	(2,321	)	$	1,524

(1): Represents amounts for Asgard and Monroe reported inDiscontinued operations—Loss from discontinued operations, net in the Consolidated Statements of Operations.

Outstanding Derivative Contracts

The following tables provide information on the volume of the Partnership's net outstanding commodity forward derivative purchase and (sales) contracts for positions related to commodity risk as of December 31, 2011 and March 31, 2012 (in thousands):

	Volumes (Barrels)

Commodity	December 31, 2011			March 31, 2012
Crude Oil		(918	)		1,469
Normal Butane		253			587
Propane		996			619
Unleaded Gasoline		(16	)		—
Natural Gasoline		217			33

Note 8—Fair Value

Fair Value Measurement

Fair value measurements and disclosures relate principally to the Partnership's derivative positions. For a description of the fair value guidance and the fair value hierarchy, seeNote 2—Significant Accounting Polices—Fair Value of Financial Instruments.

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Note 8—Fair Value (Continued)

The following table presents the gross and net financial instruments that are measured at fair value on a recurring basis at December 31, 2011 and 2010 and at March 31, 2012, and by valuation hierarchy and includes amounts held for sale (in thousands):

As of March 31, 2012	Derivative Assets			Derivative Liabilities

*Commodity Contracts*
Observable inputs—Level 1	$	—		$	—
Significant other observable inputs—Level 2		16,830			9,748
Significant unobservable inputs—Level 3		—			—


		16,830			9,748
Netting of counterparty contracts under master netting agreements		(8,168	)		(8,168	)
Cash collateral held or provided with counterparties		(2,716	)		—


*Total All Contracts*	$	5,946		$	1,580

As of December 31, 2011	Derivative Assets			Derivative Liabilities

*Commodity Contracts*
Observable inputs—Level 1	$	—		$	—
Significant other observable inputs—Level 2		9,433			3,546
Significant unobservable inputs—Level 3		—			—


		9,433			3,546
Netting of counterparty contracts under master netting agreements		(1,928	)		(1,928	)
Cash collateral held or provided with counterparties		(3,024	)		(167	)


*Total All Contracts*	$	4,481		$	1,451

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Note 8—Fair Value (Continued)

As of December 31, 2010	Assets			Liabilities

*Commodity Contracts*
Observable inputs—Level 1	$	—		$	—
Significant other observable inputs—Level 2		10,416			11,658
Significant unobservable inputs—Level 3		—			—


		10,416			11,658
Netting of counterparty contracts under master netting agreements		(8,085	)		(8,085	)
Cash collateral held or provided with counterparties		(4	)		(161	)


Total Commodity Contracts, net		2,327			3,412
*Interest Rate Contracts*
Significant other observable inputs—Level 2		—			2,444


Total Interest Rate Contracts		—			2,444
*Total All Contracts*		2,327			5,856
Commodity contracts reported in liabilities held for sale, net		—			(2,213	)
Interest rate contracts reported in liabilities held for sale, net		—			(2,444	)


*Total*	$	2,327		$	1,199

Rollforward of Level 3 Net Liability

The following table provides a reconciliation of changes in fair value of derivatives measured at fair value using inputs classified as Level 3 in the fair value hierarchy (in thousands):

	Year Ended December 31,

	2011		2010			2009
Fair value, beginning of period	$	—	$	(145	)	$	—
Realized and unrealized gains and (losses)(1)		—		—			(145	)
Transfers In/Out of Level 3, net(2)		—		145			—


Fair value, end of period	$	—	$	—		$	(145	)

(1): Gains and losses associated with Level 3 commodity derivatives are reported within revenues and gains and losses associated with Level 3 interest rate derivatives are reported as a component ofInterest expense. Unrealized losses on Monroe Level 3 interest rate swaps are reported inDiscontinued operations—Loss from discontinued operations, net and are excluded from this schedule
(2): Transfers out of Level 3 represent existing assets or liabilities that were re-categorized to Level 2 because inputs to the model became observable.

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Note 8—Fair Value (Continued)

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

In June 2011 the Partnership completed the Marcum Acquisition. The transaction was accounted for as a purchase using the acquisition method of accounting, under which the assets and liabilities acquired are accounted for at their fair values on the acquisition date. The fair values of these assets and liabilities were estimated primarily using income and adjusted cost replacement approaches, based on significant unobservable inputs (Level 3).See Note 4—Business Combinations.

Effective March 1, 2010, the Partnership assumed control over the operations and management of Monroe and as a result, the Partnership acquired a controlling financial interest in Monroe. The Partnership accounted for this event as a business combination using the acquisition method of accounting, which requires that Monroe's assets and liabilities, and the Partnership's previously held equity interest and noncontrolling interest in Monroe, be measured to fair value. The fair values of these assets, liabilities and interests were estimated primarily using income and adjusted cost replacement approaches, based on significant unobservable inputs (Level 3).See Note 4—Business Combinations.

During 2011, the Partnership committed to a plan to sell the assets of Terminaling and in 2010, the Partnership committed to plans to sell, a fleet of railcars, the assets of NCC, its controlling interest in Asgard and its controlling interest in Monroe. The related assets and liabilities held for sale are reported at the lower of their historical carrying values or estimated fair value less costs to sell, with fair value estimated using a market approach based on significant unobservable inputs (Level 3). SeeNote 5—Discontinued Operations, Dispositions and Held for Sale.

In November 2010, certain long-lived assets and intangible assets of Monroe were remeasured to fair value in conjunction with the Partnership's impairment evaluation for long-lived assets associated with the expected sale of Monroe. Property, plant and equipment, intangible assets and the pad gas lease asset with net book values of $144.4 million, $12.4 million and $8.3 million, respectively, were written down to their estimated fair values of $132.2 million, $11.4 million and $7.5 million, respectively, resulting in a total impairment loss of $14.0 million. The fair values of the remaining long-lived assets, which consist of gas storage facilities, related equipment and certain intangible assets were estimated based primarily on an income and market approach using significant unobservable inputs (Level 3) and indications of fair value less costs to sell from prospective buyers (Level 3).

As of August 2010, certain long-lived assets, intangible assets and the goodwill of Terminaling were remeasured to fair value in conjunction with the Partnership's impairment evaluation for long-lived assets. Property, plant and equipment, intangible assets and goodwill with a net book value of $10.2 million, $2.1 million and $0.7 million, respectively, were written down during 2010 to an estimated fair value of $5.6 million, $1.4 million and zero, respectively, resulting in a total impairment loss of $6.0 million. The fair values of the remaining long-lived assets, which consist of asphalt manufacturing facilities and related equipment, were estimated primarily based on an income and market approach using significant unobservable inputs (Level 3) and indications of value from prospective buyers.

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Note 8—Fair Value (Continued)

As of August 2009, certain long-lived assets, intangible assets and the goodwill of NCC were remeasured to fair value in conjunction with the Partnership's impairment evaluation for long-lived assets. Property, plant and equipment, intangible assets and goodwill with a net book value of $26.2 million, $5.3 million and $25.3 million, respectively, were written down during 2009 to an estimated fair value of $9.4 million, resulting in an impairment loss of $47.4 million. The fair values of the remaining long-lived assets, which consist of transportation vehicles and related equipment, were estimated based on a market approach using significant unobservable inputs (Level 3).

Note 9—Accounts Receivable

Receivables consist of the following, including accounts receivable from affiliates (in thousands):

	December 31,

	December 31,						March 31, 2012
	2011			2010			March 31, 2012
Accounts receivable	$	271,376		$	229,287		$	304,063
Allowance for doubtful accounts		(3,626	)		(3,793	)		(3,588	)


Total accounts receivable, net		267,750			225,494			300,475
Assets of operations held for sale		(468	)		(12,827	)		(109	)


Total carrying value in the Consolidated Balance Sheets	$	267,282		$	212,667		$	300,366

The Partnership accrues unbilled revenue primarily due to timing differences between the delivery of crude oil, natural gas and condensate and the receipt of a delivery statement. The Partnership had $25.5 million and $22.9 million of unbilled revenues as of December 31, 2011 and 2010, respectively. Of these amounts, unbilled revenues included inAssets of operations held for sale were zero and $9.2 million as of December 31, 2011 and 2010, respectively. Unbilled receivables included inAccounts receivable, net were $25.5 million and $13.7 million as of December 31, 2011 and 2010, respectively. The Partnership had $77.6 million of unbilled revenues at March 31, 2012. Unbilled accounts receivable included inAccounts receivable, net were $77.6 million at March 31, 2012.

The changes in the allowance for doubtful accounts were as follows (in thousands):

	Year ended December 31, 2011			2010			Three Months Ended March 31, 2012

Beginning balance allowance for doubtful accounts	$	3,793		$	2,202		$	3,626
Additions		657			1,959			(38	)
Writeoffs and other		(824	)		(368	)		—


		3,626			3,793			3,588
Less: Assets of operations held for sale		(3,117	)		—			(3,117	)


Ending balance allowance for doubtful accounts	$	509		$	3,793		$	471

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Note 9—Accounts Receivable (Continued)

During 2009 the Partnership recovered $3.5 million of accounts receivable that had been reserved in 2008. The recovery was reported withinOther income (expense)—Other income (loss), net in the Consolidated Statements of Operations for the year ended December 31, 2009. As discussed further inNote 20—Commitments and Contingencies—Legal Contingencies, the Partnership indemnified the purchaser for loss in the event the purchased claim was subsequently disallowed or impaired. The purchaser made a claim for the indemnity during 2011 at which time the partnership recorded a $2.2 million loss withinOther income (expense) —Other income (loss), net in the Consolidated Statements of Operations. SeeNote 20—Commitments and Contingencies—Legal Contingencies for further discussion regarding this claim.

Note 10—Inventory

Inventory held for sale or exchange consisted of the following (in thousands):

	December 31, 2011							December 31, 2010							March 31, 2012

	Total		Assets of Operations Held For Sale			Total Carrying Value		Total		Assets of Operations Held For Sale			Total Carrying Value		Total		Assets of Operations Held For Sale			Total Carrying Value
Asphalt flux	$	1,571	$	(211	)	$	1,360	$	1,938	$	—		$	1,938	$	1,898	$	(192	)	$	1,706
Propane		29,803		—			29,803		22,900		—			22,900		12,018		—			12,018
Normal butane		25,864		—			25,864		16,276		—			16,276		8,141		—			8,141
Natural gas		—		—			—		935		(935	)		—		—		—			—
Natural gasoline		186		—			186		172		—			172		40		—			40
Crude oil		36,618		—			36,618		17,677		—			17,677		55,685		—			55,685
Other		1,140		—			1,140		309		—			309		241		—			241


Total inventory	$	95,182	$	(211	)	$	94,971	$	60,207	$	(935	)	$	59,272	$	78,023	$	(192	)		77,831

The Partnership recorded non-cash charges of approximately $1.9 million, $47,000 and $9,000 for the years ended December 31, 2011, 2010 and 2009, respectively, related to the write down of predominantly NGL inventories to the lower of cost or market, primarily as a result of declines in commodity prices during these periods. The Partnership recorded non-cash charges of approximately $1.4 million and $0.1 million for the three months ended March 31, 2012 and 2011, respectively, related to the write down of NGL inventories to the lower of cost or market, primarily as a result of declines in commodity prices during these periods.

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Note 11—Property, Plant and Equipment

Property, plant and equipment consist of the following (in thousands):

	December 31, 2011									December 31, 2010									March 31, 2012

	Total			Assets of Operations Held For Sale			Total Carrying Value			Total			Assets of Operations Held For Sale			Total Carrying Value			Total			Assets of Operations Held For Sale			Total Carrying Value
Land	$	7,104		$	(1,200	)	$	5,904		$	4,532		$	(91	)	$	4,441		$	7,104		$	(1,200	)	$	5,904
Transportation vehicles and equipment		26,278			(33	)		26,245			20,475			(107	)		20,368			28,188			(24	)		28,164
Equipment		86,162			(7,973	)		78,189			116,838			(48,259	)		68,579			84,774			(4,471	)		80,303
Buildings, terminals, improvements		33,321			(1,529	)		31,792			103,554			(85,668	)		17,886			32,612			(668	)		31,944
Software		5,602			—			5,602			5,317			—			5,317			6,340			—			6,340
Construction in progress		10,817			—			10,817			7,489			(1,339	)		6,150			12,924			—			12,924


		169,284			(10,735	)		158,549			258,205			(135,464	)		122,741			171,942			(6,363	)		165,579
Accumulated depreciation		(44,245	)		4,141			(40,104	)		(36,299	)		3,247			(33,052	)		(47,643	)		4,141			(43,502	)


Total property, plant and equipment	$	125,039		$	(6,594	)	$	118,445		$	221,906		$	(132,217	)	$	89,689		$	124,299		$	(2,222	)	$	122,077

Depreciation expense for the years ended December 31, 2011, 2010 and 2009 was $13.4 million, $11.1 million and $14.0 million, respectively. The Partnership capitalizes interest on major projects during construction. For the years ended December 31, 2011, 2010 and 2009 capitalized interest was $154,000, $108,000 and $4,000, respectively. Depreciation expense for the three months ended March 31, 2012 and 2011 was $3.6 million and $ 2.7 million, respectively. For the three months ended March 31, 2012 and 2011, capitalized interest was $106,000 and $0, respectively.

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Note 12—Goodwill and Intangible Assets

Goodwill

The Company tests its reporting units for impairment of goodwill in the third quarter. SeeNote 2—Significant Accounting Policies. The change in the carrying amount of goodwill is as follows (in thousands):

	Year Ended December 31,					Three Months Ended March 31, 2012

	2011		2010			Three Months Ended March 31, 2012
Beginning of period	$	67,009	$	67,688		$	111,314
Purchase allocations		44,305		—			—
Impairment		—		(679	)		—


End of period	$	111,314	$	67,009		$	111,314

As further disclosed inNote 4—Business Combinations, in June 2011 the Partnership completed the Marcum Acquisition. In connection with this acquisition, the Partnership recognized $44.3 million of goodwill.

Due to unfavorable construction and low demand for asphalt products in Florida, operating profits and cash flows for Terminaling were much lower than expected during 2010, resulting in reduced earnings and cash flow forecasts for Terminaling. Effective August 2010, a goodwill impairment loss of $0.7 million, representing the entire goodwill of Terminaling, was recognized and is reported withinDiscontinued operations—Loss from discontinued operations, net in the Consolidated Statements of Operations. The fair value of Terminaling was estimated using the expected present value of forecasted future cash flows (Level 3).

Due to unfavorable commodity prices for natural gas, unfavorably wet weather conditions and increased competition in the water disposal and related water truck transportation business in Oklahoma, operating profits and cash flows for NCC were much lower than expected during 2009, resulting in reduced earnings and cash flow forecasts for NCC. Effective August 2009, a goodwill impairment loss of $25.3 million, representing the entire goodwill of NCC, was recognized and reported withinDiscontinued operations—Loss from discontinued operations, net in the Consolidated Statements of Operations. The fair value of NCC was estimated using the expected present value of forecasted future cash flows (Level 3).

Contingent Subordinated Units and Additional Goodwill

As part of the consideration for certain business combinations, the Partnership included in the offering price contingent consideration in the form of subordinated units which vest and convert to common units upon achievement of certain vesting conditions, or are forfeited if the vesting conditions are not met. Depending upon the acquisition agreements, vesting conditions included attainment of certain technological targets or EBITDA targets. These subordinated units convert to common units upon attainment of the vesting conditions. The status of the subordinated unit contingent consideration

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Note 12—Goodwill and Intangible Assets (Continued)

as of and during the years ended December 31, 2011, 2010 and 2009 and the three months ended March 31, 2012 is as follows (in thousands, except for the number of subordinated units):

	Contingent Subordinated Units

	Number			Fair Value
Unvested—December 31, 2008		1,310,601		$	23,595
Vested		(971,130	)		(15,696	)
Forfeited		(201,539	)		(4,619	)


Unvested—December 31, 2009		137,932		$	3,280
Vested		—			—
Forfeited		—			—


Unvested—December 31, 2010		137,932		$	3,280
Vested		—			—
Forfeited		(68,966	)		(1,640	)


Unvested—December 31, 2011		68,966		$	1,640
Vested		—			—
Cancelled		(68,966	)		(1,640	)


Unvested—March 31, 2012		—			—

The purchase price for Barr Energy, LLC (acquisition date July 2007) included contingent consideration of 206,897 subordinated units of HSE with a grant date fair value of $23.78 per unit or $4.9 million. As of July 31, 2009, one third, or 68,965 of the contingent subordinated units valued at $1.6 million related to the acquisition of Barr Energy, LLC had vested and their fair value was recognized as additional goodwill.

As of December 31, 2011 and 2010 the remaining contingent subordinated units outstanding are for the Barr Energy, LLC acquisition. In March 2012 in exchange for a payment of $5,000 by the Partnership, the remaining unvested contingent subunits were cancelled.

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Notes to the Consolidated Financial Statements (Continued)

Note 12—Goodwill and Intangible Assets (Continued)

Intangible Assets

Intangible assets subject to amortization and the changes in the carrying value are as follows (in thousands):

	Gross Carrying Amount As of December 31, 2011

													March 31, 2012
				Additions			Impairments		Other		Held for Sale		Gross Carrying Amount			Accumulated Amortization
Customer relationships	$	57,688		$	—		$	—	$	—	$	—	$	57,688		$	31,855
Customer contracts		10,125			—			—		—		—		10,125			8,622
Non-compete agreements		6,727			—			—		—		—		6,727			6,512
Other intangible assets(1)		702			—			—		—		—		702			450


	$	75,242		$	—		$	—	$	—	$	—	$	75,242
Accumulated amortization		(45,436	)		(2,003	)		—		—		—		(47,439	)


	$	29,806											$	27,803

	Gross Carrying Amount As of December 31, 2010

														December 31, 2011
				Additions			Impairments		Other		Held for Sale(1)			Gross Carrying Amount			Accumulated Amortization
Customer relationships	$	40,535		$	20,000		$	—	$	—	$	(2,847	)	$	57,688		$	30,071
Customer contracts		10,125			—			—		—		—			10,125			8,446
Non-compete agreements		7,032			250			—		—		(555	)		6,727			6,483
Other intangible assets		808			—			—		—		(106	)		702			436


	$	58,500		$	20,250		$	—	$	—	$	(3,508	)	$	75,242
Accumulated amortization		(39,850	)		(7,835	)		—		—		2,249			(45,436	)


	$	18,650												$	29,806

(1): "Held for sale" at December 31, 2011 represents intangibles owned by Terminaling.

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Note 12—Goodwill and Intangible Assets (Continued)

	Gross Carrying Amount As of December 31, 2009

																December 31, 2010
				Additions			Impairments			Other(1)			Held for Sale(2)			Gross Carrying Amount			Accumulated Amortization
Customer relationships	$	41,069		$	—		$	(534	)	$	—		$	—		$	40,535		$	25,126
Customer contracts		10,575			128			(9	)		(450	)		(119	)		10,125			7,654
Non-compete agreements		7,171			—			(139	)		—			—			7,032			6,630
Other intangible assets(1)		759			12,969			(1,095	)		—			(11,825	)		808			440


	$	59,574		$	13,097		$	(1,777	)	$	(450	)	$	(11,944	)	$	58,500
Accumulated amortization		(32,203	)		(8,490	)		—			294			549			(39,850	)


	$	27,371														$	18,650

(1): "Other" at December 31, 2010 is a disposal of Ethanol's sales contracts in connection with the Ethanol asset sale.
(2): "Held for sale" at December 31, 2010 represents intangibles owned by Monroe.

The Partnership tests its finite lived intangible assets when circumstances or events occur that indicate a potential impairment, seeNote 2—Significant Accounting Policies.

In November 2010, certain long-lived assets and intangible assets of Monroe were remeasured to fair value in conjunction with the Partnership's impairment evaluation for long-lived assets associated with the expected sale of Monroe. As a result of the Partnership's decision to sell Monroe, and indications of fair value less costs to sell from prospective buyers, the Partnership recognized an impairment charge on Monroe's intangibles of $1.1 million, representing a portion of the unamortized balance of Monroe's customer contracts and other intangible assets. This is recorded inDiscontinued operations—Loss on discontinued operations, net in the Consolidated Statement of Operations in 2010.

Due to the reasons discussed above underGoodwill, operating profits and cash flows for Terminaling and NCC were much lower than expected during 2010 and 2009, respectively, resulting in reduced earnings and cash flow forecasts. Effective August 2010, the Partnership recognized an impairment charge of $0.7 million, representing a portion of the unamortized balance of Terminaling's customer contracts, non-compete agreements and other intangible assets. Effective August 2009, the Partnership recognized an impairment charge of $5.3 million, representing the entire unamortized balance of NCC's customer relationships, customer contracts, non-compete agreements and other intangible assets.

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Notes to the Consolidated Financial Statements (Continued)

Note 12—Goodwill and Intangible Assets (Continued)

The remaining intangible assets are expected to be amortized as follows (in thousands):

	Years Ending December 31

	Customer Relationships		Customer Contracts		Non- Compete Agreements		Other Intangibles		Total
2012	$	4,035	$	400	$	64	$	35	$	4,534
2013		2,856		577		63		25		3,521
2014		2,856		526		62		17		3,461
2015		1,478		—		26		14		1,518
2016		1,176		—		—		14		1,190
Thereafter		13,432		—		—		147		13,579


	$	25,833	$	1,503	$	215	$	252	$	27,803

(1): Other intangibles consist primarily of patent costs associated with Anticline.

Amortization expense for the years ended December 31, 2011, 2010 and 2009 was $7.8 million, $8.5 million and $9.4 million, respectively. As of December 31, 2011, the remaining amortization periods range from four to 25 years. The weighted average remaining amortization period is approximately fourteen years. Amortization expense for the three months ended March 31, 2012 and 2011 was $2.0 million and $1.9 million, respectively.

Note 13—Investments in Unconsolidated Affiliate

Monroe Gas Storage Company, LLC

During the period January 1, 2009 through March 1, 2010 and prior, the Partnership applied the equity method of accounting to its interests in Monroe. As discussed further inNote 4—Business Combinations—Monroe Gas Storage Company, LLC, the Partnership gained control of Monroe effective March 1, 2010 and as of that date the Partnership discontinued the equity method of accounting for Monroe and the Partnership began reporting Monroe on a consolidated basis. As of January 1, 2010 the Partnership owned a 70% interest in Monroe and the carrying value of the Partnership's equity investment in Monroe was $40.8 million.

As of December 31, 2010 and December 31, 2009, the Partnership owned a 70% interest in Monroe. During 2009, pursuant to several agreements, the Partnership attained additional membership interests in Monroe increasing its interest from 50% to 70% of Monroe's Class A membership interests.

The Partnership sold all of its membership interest in Monroe in May 2011, as discussed further inNote 5—Discontinued Operations, Dispositions and Held for Sale.

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Notes to the Consolidated Financial Statements (Continued)

Note 14—Asset Retirement Obligations

The Partnership's asset retirement obligations are related to the wastewater disposal assets, crude oil lease automatic custody units, and prior to the sale of Monroe, its natural gas storage business, which have contractual and regulatory obligations to perform remediation and, in some instances, dismantlement and removal activities when the assets are abandoned.

The following is a reconciliation of the changes in the Partnership's asset retirement obligations from January 1, 2010 through March 31, 2012 (in thousands):

	Year Ended December 31,

	Year Ended December 31,						Three Months Ended March 31, 2012
	2011			2010			Three Months Ended March 31, 2012
Beginning asset retirement obligation	$	1,166		$	2,244		$	1,552
Business combination(1)		176			1,524			—
Liabilities incurred		1,234			171			259
Liabilities disposed and paid(2)		(1,114	)		(1,233	)		(424	)
Accretion expense		90			204			19
Held for sale(1)		—			(1,744	)		—


Ending asset retirement obligation	$	1,552		$	1,166		$	1,406

(1): "Business combination" and "Held for sale" at December 31, 2010 represents asset retirement obligations of Monroe.
(2): "Liabilities disposed and paid" represent asset retirement obligations of NCC which were retained and paid in 2011, and disposed of in the sale of NCC in 2010, respectively.

Because remediation activities are still in process at NCC, $0.4 million of the $1.4 million total asset retirement obligation related to NCC properties at March 31, 2012, is reported withinAccrued liabilities and other, and $1.0 million is reported withinOther long-term liabilities. At December 31, 2011, $0.5 million of the $1.6 million total asset retirement obligation related to NCC properties is reported withinAccrued liabilities and other, and $1.1 million is reported withinOther long-term liabilities. The entire obligation at December 31, 2010 is reported withinOther long-term liabilities. At December 31, 2011 and 2010, there were no assets legally restricted for the purpose of settling asset retirement obligations. The asset retirement obligation is reported as part ofOther long-term liabilities in the accompanying Consolidated Balance Sheets.

As of December 31, 2011 and 2010, $0.5 million in cash of one of the Partnership's water disposal subsidiaries was segregated into a highly liquid, short-term investment account to be used to fund that subsidiary's estimated asset retirement obligations. These amounts are reported inOther long-term assets in the accompanying Consolidated Balance Sheets.

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Notes to the Consolidated Financial Statements (Continued)

Note 15—Debt

Debt consists of the following (in thousands):

	December 31,

	December 31,					March 31, 2012
Credit Facilities	2011		2010			March 31, 2012
High Sierra Energy Credit Facility, 3.50% interest, due March 16, 2014.	$	—	$	—		$	—
High Sierra Energy, LP Revolver Facility, 4.29% interest, paid in full March 2011.		—		35,000			—
Centennial Energy, LLC, Centennial Gas Liquids, ULC, High Sierra Crude Oil and Marketing, LLC and Asgard Energy, LLC as Co-Borrowers Revolver facility, 5.50% interest, paid in full March 2011.		—		8,029			—
Monroe Gas Storage Company, LLC Construction and Term Loan Facility, non-recourse to the Partnership, 5.54% interest, paid in full May 2011.		—		95,550			—
Petro Source Products, LLC (the former VIE) Revolver Facility, 9.0% interest, paid in full March 2011.		—		8,374			—


Total Borrowings under lines of credit				146,953			—
Borrowings included inLiabilities of operations held for sale		—		(95,550	)		—


				51,403			—
Current liabilities—Borrowings under lines of credit		—		(23,090	)		—


Total all Credit Facilities	$	—	$	28,313		$	—




Term loan with variable interest of 4.30% at December 31, 2011. In addition to interest, quarterly payments of principal of $1.2 million are required through March 2013, thereafter $0.8 million through March 2014, at which time the remaining principal of $42.1 million plus accrued interest will become due in full. The loan is collateralized by substantially all of the assets of the Partnership and its subsidiaries. The loan was retired on June 19, 2012.	$	51,535	$	—		$	49,472
Term loan with variable interest of 4.30% at December 31, 2011. In addition to interest, quarterly payments of principal of $1.5 million are required through March 2013, thereafter $1.0 million through March 2014, at which time the remaining principal of $51.8 million plus accrued interest will become due in full. The loan is collateralized by substantially all of the assets of the Partnership and its subsidiaries. The loan was retired on June 19, 2012.		63,428		—			62,771

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Notes to the Consolidated Financial Statements (Continued)

Note 15—Debt (Continued)

	December 31,

	December 31,						March 31, 2012
Credit Facilities	2011			2010			March 31, 2012
Note payable with interest fixed at 3.76%. The note is related to an insurance policy, requires 9 monthly payments of principal and interest of $65,118, and matures February 2012. The notes were retired on June 19, 2012.		128			—			—
Capital lease obligation with interest fixed at 5.75%. The obligation is for a lease of water processing filtration equipment, requires monthly payments of principal and interest of $26,790, and matures December 2012.		312			—			211
Note payable with interest fixed at 7.33%. The note required monthly payments of principal and interest of $8,871, had an original maturity of November 2013 and was collateralized by certain High Sierra Sertco, LLC compressor equipment.(1)		—			279			—
Note payable with interest fixed at 5.83%. The note required monthly payments of principal and interest of $10,038, had an original maturity of February 2014 and was collateralized by certain High Sierra Sertco, LLC compressor equipment.(1)		—			356			—
Note payable with interest fixed at 2.92%. The note is related to an insurance policy, required monthly payments of principal and interest of $68,872. Paid in full April 2011.		—			204			—
Note payable with interest fixed at 5.96%. The note required monthly payments of principal and interest of $11,716, had an original maturity of January 2014 and was collateralized by certain High Sierra Sertco, LLC compressor equipment.(1)		—			395			—


		115,403			1,234			112,454
Less current portion of debt		(11,315	)		(525	)		(11,085	)


Long-term debt, net of current portion	$	104,088		$	709		$	101,369

(1): These notes were paid in full in February 2011.

High Sierra Credit Facility

On March 16, 2011 the Partnership and certain of its wholly-owned subsidiaries ("the Borrowers") collectively entered into a credit facility agreement (the "Credit Facility") with a syndicate of participating lenders (collectively "the Lenders"). The Credit Facility provides for maximum borrowings of up to $215.0 million in the form of term loans, working capital loans, revolving credit facility loans

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Notes to the Consolidated Financial Statements (Continued)

Note 15—Debt (Continued)

or letters of credit, subject to the available borrowing base as defined. The Credit Facility is secured by substantially all assets of the borrowers and requires compliance with certain financial and restrictive covenants. Interest on borrowings under the Credit Facility is charged at the Bank Base Rate plus a margin, or the Eurodollar rate plus a margin that is based upon the Leverage Ratio of the Partnership, as defined, and as selected by the Partnership (the "Base Borrowing Rate").

Interest on amounts borrowed under the Credit Facility term loans is at the Base Borrowing Rate plus a margin ranging from 4.0% to 4.5%, and is repayable in an amount equal to 1.875% of the initial aggregate principal amount, any accrued but unpaid interest due thereon, and any fees in respect thereof on the last day of each Fiscal Quarter, commencing with the fiscal quarter ending on June 30, 2011. Interest on amounts borrowed under the working capital facility is at the Base Borrowing Rate plus a margin ranging from 2.5% to 4.0%. Interest on amounts borrowed under the revolving credit facility is at the Base Borrowing Rate plus a margin ranging from 3% to 4.5%.

Letter of credit fees range from 3.25% to 4% depending upon the Leverage Ratio of the Partnership, and whether the letters of credit are working capital letters of credit or for other purposes. Unutilized credit fees range from .625% to 0.75% on the unutilized portions of the working capital and revolving credit facilities. Amounts borrowed under the working capital and revolving credit facilities are due and payable no later than March 16, 2014, the termination date of the Credit Facility. The proceeds of the Credit Facility were partially utilized to pay off the HSE Credit Facility, the Marketing Credit Facility and the PS Products Facility. All three of these facilities were terminated, and no further borrowings or letters of credit are available under these facilities.

At March 31, 2012 there were $43.7 million of letters of credit outstanding under the Credit Facility. At December 31, 2011, there were $56.6 million of letters of credit outstanding under the Credit Facility.

In May 2011, the Partnership amended the Credit Facility ("Amendment No. 1"). Among other changes, the Partnership obtained consent from the Lenders to acquire Marcum, and an additional $80 million term loan commitment (the "Marcum Term Loan") under the Credit Facility (thereby increasing the maximum Credit Facility borrowings to $295 million). Further, the Credit Facility term loan repayment schedule was amended to require repayment of the Marcum Term Loan in an amount equal to 1.875% of the initial aggregate principal amount, any accrued but unpaid interest due thereon and any fees in respect thereof on the last day of each Fiscal Quarter, commencing with the fiscal quarter ending on June 30, 2011. In addition, High Sierra Water Services, LLC, a wholly-owned subsidiary formed to own and operate the acquired Marcum business, was added as a co-borrower to the Credit Facility.

Total letter of credit fees expensed under all facilities and reported inInterest expense in the accompanying Consolidated Statements of Operations were $2.7 million, $2.9 million and $1.1 million for the years ended December 31, 2011, 2010 and 2009, respectively. Total letter of credit fees expensed under all facilities and reported inInterest Expense in the accompanying consolidated statements of operations were $0.5 million and $0.8 million for the three months ended March 31, 2012 and 2011, respectively.

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Notes to the Consolidated Financial Statements (Continued)

Note 15—Debt (Continued)

The High Sierra Credit Facility was retired on June 19, 2012 upon completion of the merger with NGL Energy Partners LP, as described inNote 23—Subsequent Events.

High Sierra Energy, LP Credit Facility

On June 1, 2007, HSE entered into a Revolving Credit Agreement (the "HSE Credit Facility" or the "Facility") with a lending institution. The borrowers included HSE and certain of its subsidiaries. The HSE Credit Facility was amended and extended several times, with the most recent amendment, the Tenth Amendment, dated December 15, 2010. The amended HSE Credit Facility provided for maximum borrowings of up to $45 million, and permitted letters of credit of up to $10 million under the HSE Credit Facility. Interest on amounts borrowed under this credit facility ranged from 2.0% to 3.0% over Prime or 3.5% to 4.5% over LIBOR depending up the Consolidated Leverage Ratio of the Partnership, as defined. As of December 31, 2010 the Partnership had outstanding letters of credit under the HSE Credit Facility of $4.0 million.

In March 2011, in connection with the Credit Facility, the HSE Credit Facility was paid in full.

High Sierra Energy Marketing Companies Credit Facility

In June 2005, Centennial, its wholly-owned Canadian subsidiary CGL, HSCOM and Asgard (collectively "the Co-Borrowers") together with HS Marketing as guarantor, entered into a Credit Agreement (the "Marketing Credit Facility") with a lending institution. The Marketing Credit Facility permitted borrowings in the form of term loans, overdrafts, letters of credit or revolving loans for the purposes of (i) financing working capital requirements related to crude oil, natural gas, NGL's, asphalt and petroleum products, (ii) funding payments due Fortis under any swap contracts as defined, or (iii) providing letters of credit. The Marketing Credit Facility was amended several times, with the most recent amendment dated December 15, 2010.

The amended Marketing Credit Facility permitted maximum borrowings of up to $30.0 million, available either as letters of credit or cash borrowings. Interest on borrowings, except for outstanding letters of credit, ranged from: (i) the greater of the Federal Funds Rate plus 0.50% per annum or the lender's prime rate plus 2.25% per annum (the "Base Rate"), or (ii) the Fortis Offered Rate ("FOR Rate") plus 3.75% per annum. As of December 31, 2010 the Co-Borrowers had letters of credit of $14.8 million outstanding under the Marketing Credit Facility at 5.5% interest.

Monroe Credit and Term Loan Facility—Non-Recourse to the Partnership

In June 2008, Monroe closed on a Credit and Term Loan Facility ("Monroe Credit Facility") with a bank and a syndicate of lenders which provided for a construction loan, converting to a term loan upon "substantial completion", as defined, and certain other conditions. In connection with the Monroe Credit Facility, Monroe entered into a Pad Gas Lease Agreement (the "Original Pad Gas Lease"), as further discussed inNote 20—Commitments and Contingencies—Pad Gas Lease Agreements.

The Monroe Credit Facility, as amended, provided for a construction loan commitment not to exceed $105 million. Interest on the construction loan and upon conversion, the term loan, was based

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Notes to the Consolidated Financial Statements (Continued)

Note 15—Debt (Continued)

upon the Company's maximum total debt to EBITDA ratio to a range of: (i) Fortis' prime rate plus a margin of 2.25% up to 4.25%, or (ii) LIBOR plus a margin of 3.25% up to 5.25%, at management's option. The repayment schedule, as amended, required quarterly payments of 1.5% of the principal amount outstanding under the Monroe Credit Facility commencing September 30, 2010, and at each quarter end thereafter. In addition the Monroe Credit Facility required that the Monroe maintain a debt service reserve and restricted contingent cash accounts. The terms of the amended Monroe Credit Facility also required maintenance of certain financial and other customary borrower covenants. Amounts and obligations associated with the Monroe Credit Facility were secured solely by the assets of Monroe.

In connection with the sale of Monroe in May 2011, all amounts then due under the Monroe Credit Facility, were paid in full.

Monroe Interest Rate Swap Transactions

In November 2008, Monroe entered into an interest rate swap agreement for a five-year period as an economic hedge of the risk associated with the variable rate interest payments under Monroe's Credit Facility. The notional principal amount of the swap contract at inception was $45 million. Pursuant to the swap agreement, Monroe paid 3.13% fixed interest and received LIBOR based variable interest from the swap counterparty ("swap 1 interest"). The difference between the fixed and LIBOR based "swap 1" interest amounts was received or paid every three months in arrears commencing September 1, 2009.

In December 2008, Monroe entered into a second interest rate swap agreement for a five-year period as an economic hedge of the risk associated with the variable rate interest payments under Monroe's Credit Facility. The notional principal amount of the swap contract at inception was $15 million. Pursuant to the swap agreement, Monroe paid 2.74% fixed interest and received LIBOR based variable interest from the swap counterparty ("swap 2 interest"). The difference between the fixed and LIBOR based "swap 2" interest amounts was received or paid every three months in arrears commencing September 1, 2009.

In connection with the sale of Monroe and the repayment in full of the Monroe Credit and Term Loan Facility in May 2011, the interest rate swap agreements were terminated.

Petro Source Products Credit Facility

In August 2009, PS Products entered into a credit agreement with a bank (the "PS Products Facility"). The PS Products Facility as amended provided for cash borrowings or letters of credit up to a maximum amount of $55.0 million. PS Products paid an annual administrative fee of 2% of the maximum credit facility. Interest was payable monthly at an annual rate of 9%. The PS Products Facility was secured solely by substantially all assets of PS Products, guaranteed by certain PS Products members, and required compliance with certain financial covenants. At December 31, 2010 there were $34.4 million of letters of credit outstanding under the PS Products Facility.

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Note 15—Debt (Continued)

Interest incurred under the PS Products Facility was $.05 million, $0.1 million and $0.2 million for the years ended December 31, 2011, 2010 and 2009, respectively. Letter of credit fees expensed during the years ended December 31, 2011, 2010 and 2009 were $0.7 million, $2.0 million and $0.4 million, respectively, and are reported inInterest expense in the accompanying Consolidated Statements of Operations.

In March 2011 in connection with HSE's Credit Facility and HSCOM's acquisition of PS Products, HSE provided a replacement letter of credit to the lender under the PS Products Facility for the existing letters of credit outstanding under the PS Products Facility at the acquisition date.

Extinguishment of Debt

In connection with a sale leaseback of its railcar fleet as discussed inNote 20—Commitments and Contingencies—Sale Leaseback Transaction, the Partnership used $3.6 million of the sale proceeds to extinguish three notes payable. In connection with the extinguishment of debt the Partnership paid $0.2 million of prepayment fees, which are reported inOther income, net in the Consolidated Statements of Operations for the year ended December 31, 2010.

Aggregate Maturities

The aggregate maturities of long-term obligations are as follows (in thousands):

Years ending December 31,	As of March 31, 2012

2012	$	8,366
2013		9,188
2014		94,900


	$	112,454

Note 16—Equity Compensation Plan

The Partnership has an Equity Incentive Plan (the "Plan"), which provides for two separate equity programs, (i) the Unit Issuance Program and (ii) the Option Grant Program. The Unit Issuance Program provides for awards of the Partnership's common units, subordinated units, restricted units or phantom units, either through immediate purchase or as a bonus for services. The Option Grant Program provides for the award of options to purchase limited partnership units of the Partnership, including common units, subordinated units, restricted units or phantom units. The term of an option may not exceed ten years from the date of grant. The Plan was amended in December 2011 to permit the award of restricted units and to clarify that equity awards would not have the same rights as common units to the extent provided in the award.

The Partnership Agreement was amended in May 2011 to clarify that unvested equity awards are not allocated profits and losses and in December 2011 to clarify that equity awards may be made in exchange for services.

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Note 16—Equity Compensation Plan (Continued)

Administration of the Plan has been delegated by the Board of Directors to the Compensation Committee ("Committee"). The Committee may make awards to employees, non-employee members of the Board or non-employee consultants and other independent advisors. The Committee has authority to determine the number of units or options awarded, the vesting conditions, the purchase or exercise prices for units or options awarded, respectively, the term and any other features of the awards.

The maximum number of units that may be issued over the term of the Plan is limited to no more than ten percent of the Partnership's outstanding units on a fully diluted basis, not including the units issuable under the Plan. Unvested units and options issued that subsequently fail to vest and are forfeited or cancelled are available for subsequent reissue under the Plan. As of December 31, 2011, 2010 and 2009 the number of outstanding subunits, restricted units and unexercised options awarded under the Plan was 167,608, 247,074 and 217,457, respectively. The Plan terminates upon the earlier of (i) ten years from adoption of the Plan, (ii) the date that all available units have been issued, or (iii) in connection with a merger, consolidation resulting in more than a 50% ownership change or a sale, transfer or disposition of substantially all of the Partnership's assets or units.

Under the Unit Issuance Program, holders of common unit awards are entitled to full limited partner rights, including voting rights and the right to distributions. Holders of unvested subordinated units and phantom units awarded under the Unit Issuance Program, and option holders under the Option Issuance Program do not have any such rights until the awards have vested.

Option Grants

In March 2006, options to purchase 5,000 common units were granted, which vest in equal annual 25% increments from the grant date, and expire six years from January 1, 2006, the effective date of grant. Of these, 1,250 were exercised and another 1,250 were forfeited during 2007. During the years ended December 31, 2007 through 2010, an additional 625 options vested in each year, and there were no exercises or forfeitures. As a result there are no unvested option grants under the Plan as of December 31, 2011. There have been no other option grants made by the Partnership. The Partnership computed the total fair value for these options using the Black Scholes option pricing model and the following weighted average assumptions:


Approximate risk free rate		4.20	%
Expected dividend yield		8.50	%
Expected volatility		29	%
Expected weighted average life		5 years
Exercise price	$	21.18

Compensation expense for options was recognized on a straight-line basis over the related service period, adjusted for estimated pre-vesting forfeitures.

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Note 16—Equity Compensation Plan (Continued)

Unit grants

Subordinated, restricted and phantom units granted (collectively "Grant Units") convert to common units upon vesting. The units granted vest based upon employee service, and in some cases, based upon both employee service and achievement of performance targets, including targeted gross margin generated by the employee or a targeted distribution per limited partner unit.

Compensation expense related to Grant Units with only service-based vesting is recognized on a straight-line basis over the applicable vesting period. Compensation expense for Grant Units with both service and performance based vesting is recognized beginning in the period management concludes it probable that the performance condition will be achieved, net of an estimate of pre-vesting forfeitures due to termination of employment prior to vesting.

The following table summarizes employee equity compensation activity by type of equity instrument for the years ended December 31, 2011, 2010 and 2009 and for the three months ended March 31, 2012.

	Options					Subordinated and Restricted					All Units

	Units			Fair Value		Units			Fair Value		Units			Fair Value
Unvested—January 1, 2009		1,250		$	21.18		115,742		$	18.08		116,992		$	18.11
Granted		—					33,000			17.05		33,000			17.05
Vested		(625	)		21.18		(55,717	)		18.98		(56,342	)		19.00
Forfeited		—					(16,000	)		21.07		(16,000	)		21.07


Unvested—December 31, 2009		625		$	21.18		77,025		$	17.30		77,650		$	17.33
Granted		—					55,500			12.98		55,500			12.98
Vested		(625	)		21.18		(25,883	)		17.45		(26,508	)		17.53
Forfeited		—					—			—		—


Unvested—December 31, 2010		—		$	—		106,642		$	15.04		106,642		$	15.01
Granted		—					42,500			18.90		42,500			18.90
Vested		—					(43,833	)		14.70		(43,833	)		14.70
Forfeited		—					(9,167	)		13.63		(9,167	)		13.63


Unvested—December 31, 2011		—			—		96,142		$	15.52		96,142		$	15.52
Granted		—			—		650,000			18.61		650,000			18.61
Vested		—			—		(30,167	)		15.37		(30,167	)		15.37
Forfeited		—			—		—			—		—			—


Unvested—March 31, 2012		—		$	—		715,975		$	18.53		715,975		$	18.53




Exercisable—March 31, 2012		2,500		$	21.18							2,500		$	21.18

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Notes to the Consolidated Financial Statements (Continued)

Note 16—Equity Compensation Plan (Continued)

Total unit-based compensation recorded during the years ended December 31, 2011, 2010 and 2009 related to subordinated units, restricted units and options totaled $0.7 million, $0.7 million and $1.0 million, respectively. Total unit-based compensation recorded during the three months ended March 31, 2012 and 2011 related to subordinated units, restricted units and options totaled $0.2 million and $0.1 million, respectively. Compensation expense to be recognized in future periods related to the vesting of unvested subordinated and restricted units will be approximately $11.7 million over a weighted average period of 2.7 years, provided all performance and service conditions of the awards are met. As of March 31, 2012, there were 719,844 units available for grant under the Plan. In addition to the grants in the table above, the Partnership paid $5,000 in exchange for 68,966 unvested contingent subordinated units with a fair value per unit of $23.78 related to a business combination, which were then cancelled (seeNote 12—Goodwill and Intangible Assets).

On June 19, 2012, in connection with the merger with NGL Energy Partners, 645,833 of the subordinated and restricted units vested and 70,142 of the subordinated and restricted units were forfeited.

Note 17—Equity

High Sierra Energy GP, LLC Members' Equity

The ownership interests in the Company consist of membership interests, with each membership interest evidencing a specific interest in the Company during its existence and in its assets upon dissolution. Generally, distributions paid by the Company are paid to the members on a pro rata basis in accordance with the membership interests held by each member.

High Sierra Energy, LP Partners' Capital

Partners' capital at March 31, 2012 consists of 14,684,863 common units outstanding, representing a 98% effective aggregate ownership interest in the Partnership and its subsidiaries after giving effect to the 2% general partner interest.

General Partner

The Company retains a two percent ownership interest in the Partnership. In addition to managing all of the operations of the Partnership, the Company has the authority to, among other things, distribute the Partnership's cash, and to acquire, dispose or mortgage any or all of the Partnership's assets. The Partnership reimburses the Company on a monthly basis for all direct and indirect expenses the Company incurs on its behalf, including rent. For the years ended December 31, 2011, 2010 and 2009, and for the three months ended March 31, 2012 and 2011, amounts incurred by the Company on behalf of the Partnership were not significant.

Incentive Distribution Rights

Incentive Distribution Rights ("IDR's") are non-voting Limited Partner Interests issued to the Company that entitle the Company to receive incentive distributions if the amount distributed with

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Notes to the Consolidated Financial Statements (Continued)

Note 17—Equity (Continued)

respect to any quarter exceeds levels specified in the partnership agreement. Under the quarterly incentive distribution provisions, the Company is entitled, without duplication, to 15% of amounts distributed in excess of $0.45 per unit, referred to as the minimum quarterly distribution ("MQD"), 25% of amounts distributed in excess of $0.5625 per unit, and 50% of amounts distributed in excess of $0.675 per unit.

Partnership Distributions

The Partnership may elect to distribute 100% of its available cash within 45 days after the end of each quarter to unit holders of record and to its general partner. Available cash is generally defined as all cash and cash equivalents on hand at the end of each quarter, less reserves established by the Company for future requirements.

Per unit cash distributions on outstanding units and the portion of the distributions representing an excess over the MQD were as follows:

	Year Ended December 31,

	Year Ended December 31,												Three Months Ended March 31, 2012
	2011				2010				2009				Three Months Ended March 31, 2012
	Distribution(1)		Excess Over MQD		Distribution(1)		Excess Over MQD		Distribution(1)		Excess Over MQD		Distribution(1)		Excess Over MQD
First Quarter	$	—	$	—	$	0.6300	$	0.1800	$	0.6100	$	0.1600	$	0.30	$	—
Second Quarter	$	—	$	—	$	—	$	—	$	0.6100	$	0.1600
Third Quarter	$	0.1500	$	—	$	—	$	—	$	0.6300	$	0.1800
Fourth Quarter	$	0.3000	$	—	$	—	$	—	$	0.6300	$	0.1800

(1): Distributions represent those declared in the applicable period.

Total distributions made to common unitholders and the Company were as follows (in thousands):

	Distributions Paid

Year	Common Unitholders		General Partner Incentive		General Partner 2%		Total
2012	$	4,397	$	—	$	90	$	4,487
2011		6,589		—		134		6,723
2010		9,257		452		183		9,892
2009		33,407		1,537		682		35,626

No distributions were made or for any of the four quarters during the year ended December 31, 2010. The Partnership recommenced making cash distributions in August 2011. On May, 15, 2012, the Partnership paid a distribution of $0.30 per unit to unitholders of record on March 31, 2012 for the period January 1, 2012 through March 31, 2012. The total distribution paid was $4.5 million, including $4.4 million to common unit holders and $0.1 million paid to the Company for its general partner interest.

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Note 17—Equity (Continued)

Common Unitholder Repurchase Right

In May 2011 the Partnership sold 385,000 common limited partner units to two investors at $26.00 unit, receiving cash proceeds of approximately $10.0 million. The proceeds were used to partially fund the Marcum Acquisition.

The holders of these units have the right to require the Partnership to repurchase these units plus any unpaid distributions during the 90 day period following the earlier of May 13, 2014 or a change in control. The repurchase price per unit is fixed at $32.75 per unit. In addition, the Partnership has the right to purchase 77,000 of these common limited partner units from the unitholders for a repurchase price per unit of $26.00 plus an amount equivalent to 8% per annum as of the call date, plus unpaid distributions. The Partnership's repurchase right is effective beginning on the issuance date until the earlier of a change in control, an initial public offering or a transfer of the common limited partner units to another investor.

Note 18—Significant Customers

The Partnership had one customer that accounted for approximately 17%, 18% and 20% of consolidated revenues for the years ended December 31, 2011, 2010 and 2009, respectively, and for 20% and 14% of consolidated revenues for the three months ended March 31, 2012 and 2011, respectively. This same customer accounted for 14% and 22% of consolidated accounts receivable as of December 31, 2011 and 2010, respectively, and for 14% of consolidated accounts receivable as of March 31, 2012 and 2011. One other customer of the Partnership accounted for 12%, 3% and 6% of consolidated revenues for the years ended December 31, 2011, 2010 and 2009, respectively, and for 9% and 6% of consolidated revenues for the three months ended March 31, 2012 and 2011, respectively. This same customer accounted for 11% and 8% of consolidated accounts receivable as of December 31, 2011 and 2010, respectively, and for 1% and 6% of consolidated accounts receivable as of March 31, 2012 and 2011, respectively. No other customers who accounted for greater than 10% of consolidated revenues or accounts receivable.

Note 19—Related Parties

The Partnership transacts business with several related party entities. These related parties are owned and or operated by officers and or employees of the Partnership. Types of transactions with related parties include purchasing and selling product, purchasing transportation service, leasing of office and yard space, purchasing administrative and clerical services, dismantling of facilities, advancing funds to and from, purchasing of equipment services, purchases of engineering feasibility consulting services, purchases of project management services, purchasing pipeline transportation, purchases

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Note 19—Related Parties (Continued)

environmental remediation services and loans from/ to. The following table summarizes the activity with these related parties (in thousands):

	Year Ended December 31,						Three Months Ended March 31, 2012

	2011		2010		2009		Three Months Ended March 31, 2012
Purchases of product, primarily crude oil	$	63,770	$	35,124	$	25,877	$	20,077
Sales of product, primarily crude oil		4,438		4,331		3,981		—
Purchases of transportation services		657		—		—		370
Rentals paid for office and facilities under lease agreements		41		88		386		3
Administrative and clerical service fees paid		372		36		1,595		122
Fees paid for equipment services		121		10		28		—
Engineering and feasibility consulting fees		142		11		1,573		139
Project management fees		163		2		—		125
Environmental remediation services costs paid		602		—		—		—

As of December 31, 2011 and 2010 the Partnership had payables of $6.7 million and $1.0 million, respectively, to these related parties, and as of December 31, 2011 and 2010, the Partnership had receivables of $0.5 million and zero, respectively, from these related parties. As of March 31, 2012, the Partnership had payables of $7.9 million to these parties and receivables of $0.8 million from these parties.

Note 20—Commitments and Contingencies

Offset to Outstanding Derivative Contracts

The Partnership maintains a minimum and measured exposure to commodity price risk through a combination of purchase and sale contracts and hedging policies. A large percentage of our business is hedged by contracting on a "back-to-back" basis where physical purchases are matched with physical sales. In those instances when the matching of physical transactions may be less than optimal, the Partnership utilizes financial hedges to lock-in margins. Although the Partnership seeks to maintain an aggregate position that is balanced within our supply and logistics activities, the Partnership purchases crude oil, condensate, and NGLs from hundreds of locations and may experience net unbalanced physical positions for short periods of time as result of production, transportation and delivery variances. All financial derivative positions have a direct physical offset.

Royalties

In connection with the purchase of AntiCline, the Partnership agreed to pay a 5% royalty if the technology acquired was used outside of the current leased property. No royalties were incurred or

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Notes to the Consolidated Financial Statements (Continued)

Note 20—Commitments and Contingencies (Continued)

paid during the years ended December 31, 2011, 2010 or 2009 under this commitment. This provision terminated in March 2011 with the acquisition of the remaining membership interests in Anticline by the Partnership.

Operating Leases

The Company leases land, office space, and equipment under leases with varying expiration dates through 2017. Rental expense for the years ended December 31, 2011, 2010 and 2009 was $21.4 million, $17.1 million and $14.7 million, respectively. Rental expense for the three months ended March 31, 2012 and 2011 was $6.1 million and $4.6 million, respectively. Future minimum rental commitments for the next five years and thereafter are as follows (in thousands):

Years Ending December 31,	As of March 31, 2012

2012	$	23,049
2013		27,157
2014		23,351
2015		17,062
2016		16,124
Thereafter		39,725


	$	146,468

Sale Leaseback Transaction

�� In June 2010 a wholly-owned subsidiary of the Partnership entered into a sale leaseback of its fleet of railcars. Proceeds from the sale were $8.1 million, which were utilized in part to retire three notes payable with aggregate outstanding principal and interest of $3.6 million. The railcars had a carrying value of $2.6 million. Of the total gain on sale of $5.6 million, the Partnership recognized $0.6 million as of the sale date withinOther income (loss), net, and has amortized $0.5 million of the deferred gain as a reduction to rent expense during each of the years ended December 31, 2011 and 2010 withinOperating expenses in the Consolidated Statements of Operations. The current and noncurrent portions of the remaining unamortized deferred gain of $0.9 million and $2.5 million, respectively, are reported inAccrued liabilities and other andOther long term liabilities in the Consolidated Balance Sheet at December 31, 2011.

Under the lease agreement, the Partnership leased the railcars back from the purchaser for periods ranging from three to seven years. Required minimum lease payments totaling $3.8 million are included in the future minimum lease rental commitments information above. The obligations of the subsidiary under the lease are guaranteed by another of the Partnership's wholly-owned subsidiaries.

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Notes to the Consolidated Financial Statements (Continued)

Note 20—Commitments and Contingencies (Continued)

Pad Gas Lease Agreements

On June 13, 2008, Monroe entered into a Pad Gas Master Lease Agreement (the "Original Pad Gas Lease") with an affiliate of Fortis (the "Original Lessor"). Under the Original Pad Gas Lease, Monroe agreed to lease 3,500,000 MMBtu's of pipeline quality natural pad gas for injection into the project reservoir to provide reservoir pressures adequate to enable injection and withdrawal of natural gas from the reservoir. Delivery of pad gas did not occur and the Original Pad Gas Lease was terminated during June 2009. In connection with the termination of the Original Pad Gas Lease, Monroe paid $2.4 million to terminate the lease and novate certain related contractual commitments.

Simultaneous with the termination of the Original Pad Gas Lease, Monroe entered into a New Pad Gas Lease Agreement. The New Pad Gas Lease required an initial upfront payment of $17.2 million at inception to secure delivery and to novate the prior contractual commitments associated with the prior lease. The fair value of $7.6 million assigned to the New Pad Gas Lease was reported inCurrent assets—Assets of operations held for sale in the Consolidated Balance Sheets as of December 31, 2010, along with other held for sale assets. Amortization expense recognized withinLoss from discontinued operations, net was $3.1 million for the year ended December 31, 2010. During November 2010, the Partnership recognized an impairment charge of $0.7 million withinLoss from discontinued operations, net, representing a portion of the unamortized balance of the New Pad Gas Lease.

During May 2010, pursuant to an agreement related to the contractual gas delivery schedule, Monroe agreed to pay the lease counterparty $0.9 million as compensation for losses incurred as a result of Monroe's actual vs. scheduled acceptance of gas under the terms of the New Pad Gas Lease. On June 9, 2010, Monroe took delivery of the entire remaining pad gas in exchange for a cash payment of $1.2 million in full settlement of Monroe's obligation, which is reported withinLoss from discontinued operations, net in the Consolidated Statements of Operations.

Legal Contingencies

The Partnership is subject to a variety of risks and disputes, and is a party to various legal proceedings in the normal course of its business. The Partnership maintains insurance policies in amounts and with coverage and deductibles as it believes reasonable and prudent. While it is not possible to predict the outcome of the legal actions with certainty, management is of the opinion that appropriate provisions and accruals for potential losses associated with all legal actions have been made in the consolidated financial statements.

In February 2012, the Partnership, several of its subsidiaries and other unaffiliated parties, were notified of a claim for wrongful death and failure to maintain adequate safety precautions. At this time, the Partnership is not able to determine what amount, if any, for which it might ultimately be held liable. In March 2012, a vehicle collided with a truck owned and operated by the Partnership, which resulted in a fatality. At this time, the Partnership is not able to determine whether it will be held liable for this incident. The Company believes that the amount of its liability for these incidents, if any, would be covered under existing insurance coverage.

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Notes to the Consolidated Financial Statements (Continued)

Note 20—Commitments and Contingencies (Continued)

During January 2012, the purchaser of Asgard ("Purchaser of Asgard") notified the Partnership of a claim of a breach in representation by the Partnership, because the Partnership did not disclose the existence of certain alleged swap and option transactions with a third party that occurred prior to the sale of Asgard to Purchaser of Asgard. The Partnership claims that it did not enter into these alleged transactions and is disputing the claims. Purchaser of Asgard is seeking indemnification from the sellers (the Partnership and its partner in Asgard) for losses it may sustain. The Partnership believes that the maximum amount being claimed is $2.7 million; however, in any event that the maximum liability of the sellers is $1.6 million under the purchase and sale agreement, and the Partnership's share of any loss is limited to 75% of the total loss. The Partnership believes the allegations made by the Purchaser of Asgard are without merit and intends to vigorously defend against the alleged claims.

In November 2011, the purchaser of Monroe ("Purchaser of Monroe") notified the Partnership of a claim of breach of contract in connection with the Partnership's sale of Monroe, which closed on May 31, 2011. Purchaser of Monroe claimed that the gas storage reservoir that was sold in conjunction with the sale of Monroe contained over two and one half Bcf of natural gas less than what the Partnership had represented during the sales process; Purchaser of Monroe claimed that, as a result, it has sustained a financial loss, including excess operating and capital costs, of between $10 million and $20 million. The Partnership's share of total escrowed sales proceeds remained in escrow pending settlement. SeeNote 23—Subsequent Events, for additional information regarding this settlement.

In September 2010, Pemex Exploracion y Produccion ("Pemex") filed a lawsuit against a number of defendants, including the Partnership. Pemex alleges that the Partnership and the other defendants purchased condensate from a source that had acquired the condensate illegally from Pemex. The Partnership does not believe that it had knowledge at the time of the purchases of the condensate that such condensate would later be alleged to have been sold illegally. The proceedings are in an early stage, and as a result, the Company cannot reliably predict the outcome of this litigation. The Partnership believes that it has good defenses and also believes that, in the event of an adverse outcome, its total exposure is not expected to be material to the Company. However, future adverse rulings by the court could result in material increases to the maximum potential exposure. The Partnership recorded an accrued liability during the three months ended March 31, 2012, based on its best estimate of the low end of the range of probable loss.

In May 2010, two lawsuits were filed in Kansas and Oklahoma by numerous oil and gas producers (the "Associated Producers"), asserting that they were entitled to enforce lien rights on crude oil purchased by the Partnership. These cases were subsequently transferred to the United States Bankruptcy Court for the District of Delaware, where they are pending. These claims relate to the bankruptcy of SemCrude, L.P. The Associated Producers are claiming damages against all defendants in excess of $72 million and assert that the Partnership's allocated share of that is in excess of $2.1 million. The parties are in the discovery phase of the cases and no trial date has been set.

During 2009, the Partnership filed lawsuits against the former owners of NCC that claim the prior owners operated NCC imprudently subsequent to the Partnership's acquisition of NCC, and violations of certain provisions of the purchase agreement. The defendants filed a motion for arbitration, which was denied and was appealed to the state Court of Civil Appeals. The motion for arbitration was

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Notes to the Consolidated Financial Statements (Continued)

Note 20—Commitments and Contingencies (Continued)

awarded by the Court of Civil Appeals and was upheld by the Oklahoma State Supreme Court. In June 2011 the Partnership and the prior owners of NCC (collectively the "parties") reached a settlement and mutually agreed to release each other from all claims. Among other things, the parties agreed to distribute unsettled escrow equally to each party in the amount of $0.5 million, and in addition the prior owners agreed to relinquish all rights, title and interest in 76,389 common LP units previously held as of the settlement date.

In July 2009, HSCOM sold a bankruptcy claim it had against SemCrude LP to SilverPoint Capital Partners, LLC ("SPCP") for $3.5 million. Under the related sales agreement, if the claim was subsequently disallowed or impaired, in whole or in part, SPCP is entitled to sell the impaired portion back to HSCOM under certain conditions. Those conditions have occurred and HSCOM negotiated a settlement with SPCP in February 2012 in the amount of $2.2 million, including interest, HSCOM recorded the settlement withinOther Income (expense)—Other income (loss), net in the accompanying Consolidated Statement of Operations for the year ended December 31, 2011. In a related matter, as a result of settlement of all remaining priority claims with SemGroup, HSCOM received a payment of $443,000 in March 2012.

In early 2011, IC-CO, Inc. and W.E.O.C., Inc. filed an action in the United States District Court for the Eastern District of Oklahoma against J. Aron & Company. The claims asserted in the IC-Co action are identical to those asserted in the Samson and Associated Producers actions. IC-CO and W.E.O.C. sought recovery of sums they were owed for crude oil they had sold and not been paid for. The amount of their claims is relatively small, approximately $80,000. However, their Complaint also seeks Class Action Certification status on behalf of all other producers located in the State of Oklahoma. The Company believes it has meritorious defenses to the claims, including those which it has raised in the Associated Producers action and that the IC-CO claims are now barred by applicable statute of limitations.

Centennial and HSCOM settled a claim alleging injection of nonconforming crude oil into a crude oil pipeline during 2009 with payment in the amount of $0.5 million which was reported withinGeneral and administrative expenses in the Consolidated Statements of Operations during 2009.

During July 2008, there was a fatal accident at one of the Partnership's water facilities that resulted in the death of an employee while the employee was performing routine job responsibilities. The family of the employee filed a substantial certainty claim under Oklahoma law against the Partnership in July 2009. This claim was settled in February 2011. The amount of the claim that was not covered by the Partnership's insurance was $0.2 million, which was recognized asGeneral and administrative expenses in the Consolidated Statement of Operations during 2010 and paid to the employee's family in March 2011.

In July 2008, the Partnership executed an agreement to sell the majority of the methyl tertiary butyl ether ("MTBE") plant assets to a third party. During 2009, the Partnership received a final payment due of $0.4 million and title of the asset transferred to the purchaser. In connection with the dismantlement, relocation and rebuilding of the MTBE plant, the Partnership was involved in a dispute with a construction contractor. In March 2009, the contractor agreed to pay to the Partnership

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Notes to the Consolidated Financial Statements (Continued)

Note 20—Commitments and Contingencies (Continued)

$0.3 million, and the Partnership agreed to pay the contractor $0.2 million in full settlement of all claims.

One of the Partnership's facilities is operating with all but one of the required permits. The Partnership has applied for the permit, which is necessary for ongoing operations. The Partnership has been informed by the State of Wyoming that it has fulfilled all of the obligations necessary to receive the permit; however, the Partnership believes that denial of the permit application could adversely affect operations. The Partnership has continued to communicate with the State of Wyoming about the status of the permit. The Partnership believes that the permit will be granted, but is unable to determine the timing of any action by the State of Wyoming.

Note 21—Employee Benefits

In March 2007 the Partnership adopted the High Sierra Shared Services, LLC 401(k) & Profit Sharing Plan (the "Plan"). Employees of the Partnership and its subsidiaries over 18 years of age are eligible to participate in the Plan upon completion of 60 days of service. The Partnership may make discretionary matching contributions of 50% of the first 6% of participating employee compensation. The Partnership may also make additional discretionary profit sharing contributions. The Partnership elected to make discretionary matching contributions of 3% of an eligible employee's salary to all eligible employees' 401(k) plan accounts for the years ended December 31, 2011 and 2009 and the three months ended March 31, 2012. The Partnership did not elect to make a discretionary matching contribution for the year ended December 31, 2010.

The Partnership made contributions of approximately $0.5 million, $0.9 million and $1.2 million during the years ended December 31, 2011, 2010 and 2009, respectively, and $0.3 million and $0.1 million during the three months ended March 31, 2012 and 2011, respectively. In addition, the Partnership made discretionary profit sharing contributions of $0.5 million for eligible participants to the Plan during the first quarter of 2012 and none during the first quarter of 2011.

The Plan was amended effective January 1, 2012. Among other changes, the discretionary matching contribution was changed to 100% of the first 1% of participating employee eligible compensation and 50% of the next 5% of participating employee compensation.

Note 22—Income Taxes

Current income tax expense of $0.4 million and $1.2 million are reported inIncome tax expense (benefit) in the Consolidated Statements of Operations for the three months ended March 31, 2012 and 2011, respectively. Deferred income tax (benefit) of $(0.9) million is reported inIncome tax expense (benefit) in the Consolidated Statements of Operations for the year ended December 31, 2011. Current and deferred income tax (benefit) of $(0.2) million and $(1.4) million, respectively, is reported inIncome tax expense (benefit) in the Consolidated Statements of Operations for the year ended December 31, 2010. Current and deferred tax expense of $0.5 million and $1.6 million, respectively, is reported inIncome tax expense (benefit) in the Consolidated Statement of Operations for the year ended December 31, 2009. Deferred tax (benefit) and expense for the years ended December 31, 2011,

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Notes to the Consolidated Financial Statements (Continued)

Note 22—Income Taxes (Continued)

2010 and 2009 resulted from a deferred tax liability and asset, respectively, for unrealized gains and losses recognized by CGL, the Partnership's Canadian subsidiary. The deferred tax asset amounts are reported inPrepaids and other assets, while the liability amounts are reported inAccrued liabilities and other in the Consolidated Balance Sheets at December 31, 2011 and 2010.

The Partnership does not have any material unrecognized tax benefits associated with uncertain tax positions.

Note 23—Subsequent Events

The Company evaluated subsequent events through September 4, 2012, the date the financial statements were issued.

Credit Facility Covenant Waiver

In March 2012, the Partnership and the Credit Facility lenders determined that there was noncompliance with a restrictive covenant under the Credit Facility. The restrictive covenant requires perfection of security interests in collateral property, and the Partnership had not perfected a security interest on a property with a cost of approximately $4.6 million. On March 30, 2012 the Partnership was granted a waiver permitting the Partnership a period of ninety days to cure the covenant violation. The credit facility was retired on June 19, 2012.

Monroe Settlement

As a result of continuing settlement negotiations, the Partnership and the Purchaser of Monroe reached an agreement in principle to settle the alleged claims made by the Purchaser of Monroe, as discussed above inNote 20—Commitments and Contingencies—Legal Contingencies. The Partnership's total settlement amount was $3.6 million (net of the working capital settlement described below), of which $1.9 million was recorded as a loss during the year ended December 31, 2011, and of which $1.7 million was recorded as a loss during the three months ended March 31, 2012.

In addition to the above, the Partnership and the Purchaser of Monroe have also agreed in principle to finalize the working capital adjustment, discussed inNote 5—Discontinued Operations, Dispositions and Held for Sale—Monroe, whereby the Partnership is to receive approximately $0.3 million, representing the Partnership's portion of the working capital adjustment amount.

Sale of High Sierra Terminalling

On May 31, 2012, the Partnership completed the sale of High Sierra Terminalling, LLC to an officer of the Company in exchange for $2.5 million in cash, subject to a working capital adjustment of $0.2 million. As a result of the sale, the Company recognized an impairment of the Terminalling assets held for sale as of March 31, 2012 in the amount of $5.4 million, which is reported withinLoss from discontinued operations, net in the accompanying Consolidated Statement of Operations for the three months ended March 31, 2012.

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Notes to the Consolidated Financial Statements (Continued)

Note 23—Subsequent Events (Continued)

Acquisition

On May 22, 2012 the Partnership completed the purchase of a group of companies involved in the crude oil gathering, trucking, and waste water disposal businesses, in exchange for an aggregate cash payment of $23.4 million, subject to customary adjustments for working capital and certain capital expenditures.

Merger with NGL Energy Partners LP

On June 19, 2012, the Company completed a merger with NGL Energy Holdings LLC whereby the Company became a wholly-owned subsidiary of NGL Energy Holdings LLC. The members of the Company received consideration of $50 million in cash and ownership interests in NGL Energy Holdings LLC. Concurrent with this merger, the Partnership completed a merger with NGL Energy Partners LP, whereby the Partnership became a wholly-owned subsidiary of NGL Energy Partners LP. The partners of the Partnership received consideration of $194.2 million in cash (inclusive of payments made by NGL Energy Partners LP to settle certain of High Sierra Energy, LP's long-term debt and other obligations) and 18,018,468 common units in NGL Energy Partners LP. Upon completion of the merger, the Partnership retired all of its term loans and notes payable.

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Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders
SemGroup Corporation
Tulsa, Oklahoma

We have audited the accompanying balance sheets of SemStream Non-Residential Division (the "Company") as of December 31, 2010 and 2009 (Subsequent to Emergence), and the related statements of operations, changes in net parent equity (deficit), and cash flows for the year ended December 31, 2010, and for the one month ended December 31, 2009 (Subsequent to Emergence), and for the eleven months ended November 30, 2009, and for the year ended December 31, 2008 (Prior to Emergence). These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of SemStream Non-Residential Division at December 31, 2010 and 2009 (Subsequent to Emergence), and the results of its operations and its cash flows the year ended December 31, 2010 and for the one month ended December 31, 2009 (Subsequent to Emergence), and for the eleven months ended November 30, 2009 and for the year ended December 31, 2008 (Prior to Emergence), in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the financial statements, effective November 30, 2009, the Company emerged from bankruptcy and applied fresh-start accounting. As a result, the statements of operations and cash flows for the year ended December 31, 2010 and for the one month ended December 31, 2009, are presented on a different basis than that for the periods before fresh-start and, therefore, are not comparable.

/s/ BDO USA, LLP

BDO USA, LLP
Dallas, Texas
November 3, 2011

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Balance Sheets

(Dollars in thousands)

	Subsequent to Emergence

	December 31, 2010		December 31, 2009
*ASSETS*
Current assets:
Accounts receivable	$	81,555	$	43,300
Inventories		103,411		133,710
Derivative assets		4,367		2,560
Margin deposits		12,570		26,876
Other current assets		995		7,694


Total current assets		202,898		214,140


Property, plant and equipment (net of accumulated depreciation of $2,342 at December 31, 2010 and $175 at December 31, 2009)		48,028		42,812
Goodwill		50,071		50,071
Other intangible assets (net of accumulated amortization of $3,077 at December 31, 2010 and $217 at December 31, 2009)		13,923		16,783
Other assets		3,297		3,854


Total assets	$	318,217	$	327,660




*LIABILITIES AND NET PARENT EQUITY*
Current liabilities:
Accounts payable	$	73,530	$	44,708
Advances from parent		—		5,045
Derivative liabilities		13,418		25,804
Payables to pre-petition creditors		202		10,202
Other current liabilities		3,224		2,318


Total current liabilities		90,374		88,077


Other noncurrent liabilities		167		161
Commitments and contingencies (Note 6)
Net parent equity		227,676		239,422


Total liabilities and net parent equity	$	318,217	$	327,660

The accompanying notes are an integral part of these financial statements.

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SemStream Non-Residential Division

Statements of Operations

(Dollars in thousands)

	Subsequent to Emergence						Prior to Emergence

	Year Ended December 31, 2010			Month Ended December 31, 2009			Eleven Months Ended November 30, 2009			Year Ended December 31, 2008



Revenues, including revenues from affiliates (Note 9):
Product sales	$	712,270		$	63,261		$	418,521		$	1,505,020
Other		2,194			184			2,049			4,889


Total revenues		714,464			63,445			420,570			1,509,909
Expenses, including expenses from affiliates (Note 9):
Costs of products sold, exclusive of depreciation and amortization shown below		691,823			75,699			420,611			1,675,912
Operating		6,985			1,468			7,229			7,667
General and administrative		8,110			1,290			4,123			5,698
Depreciation and amortization		5,040			392			3,815			3,927


Total expenses		711,958			78,849			435,778			1,693,204


Operating income (loss)		2,506			(15,404	)		(15,208	)		(183,295	)
Other expenses (income):
Interest expense		3,703			761			2,154			1,711
Other expense (income), net		(2,983	)		—			(2	)		61


Total other expenses, net		720			761			2,152			1,772


Income (loss) before reorganization items		1,786			(16,165	)		(17,360	)		(185,067	)
Reorganization items gain (loss), including expenses allocated from affiliates (Note 9)		—			—			26,470			(25,247	)


Net income (loss)	$	1,786		$	(16,165	)	$	9,110		$	(210,314	)

The accompanying notes are an integral part of these financial statements.

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Statements of Changes in Net Parent Equity (Deficit)

(Dollars in thousands)


Balance at December 31, 2007 (Prior to emergence)	$	(36,249	)
Net loss		(210,314	)
SemGroup interest capitalized to property, plant and equipment		99


Balance at December 31, 2008 (Prior to emergence)		(246,464	)
Net loss, prior to implementation of Plan of Reorganization		(89,823	)


Balance prior to implementation of Plan of Reorganization		(336,287	)
Implementation of Plan of Reorganization		590,075


Balance at November 30, 2009 (Subsequent to emergence)		253,788
Net loss		(16,165	)
Net contributions from SemGroup		1,799


Balance at December 31, 2009 (Subsequent to emergence)		239,422
Net income		1,786
Net distributions to SemGroup		(13,532	)


Balance at December 31, 2010 (Subsequent to emergence)	$	227,676

The accompanying notes are an integral part of these financial statements.

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SemStream Non-Residential Division

Statements of Cash Flows

(Dollars in thousands)

	Subsequent to Emergence						Prior to Emergence

	Year Ended December 31, 2010			Month Ended December 31, 2009			Eleven Months Ended November 30, 2009			Year Ended December 31, 2008



Cash flows from operating activities:
Net income (loss)	$	1,786		$	(16,165	)	$	9,110		$	(210,314	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		5,040			392			3,815			3,927
Loss (gain) on disposal of long-lived assets		(34	)		—			—			61
Provision for losses on accounts receivable		—			617			—			40
Gain on fresh start reporting		—			—			(98,933	)		—
Other non-cash reorganization items		—			—			2,113			—
Changes in assets and liabilities:
Decrease (increase) in accounts receivable		(38,255	)		(3,587	)		22,115			75,263
Decrease (increase) in inventory		29,129			3,321			(41,628	)		103,384
Change in net derivative assets/liabilities		(14,193	)		7,395			24,362			(49,713	)
Decrease (increase) in margin deposits		14,306			(4,497	)		(14,779	)		43,917
Decrease (increase) in other assets		7,256			4,332			(6,352	)		(3,637	)
Increase (decrease) in accounts payable		28,072			2,529			38,137			(125,635	)
Decrease in payables to pre-petition creditors		(10,000	)		—			—			—
Increase (decrease) in other liabilities		1,323			212			(5,317	)		1,197


Net cash provided by (used in) operating activities		24,430			(5,451	)		(67,357	)		(161,510	)


Cash flows from investing activities:
Capital expenditures		(6,129	)		(1,732	)		(2,806	)		(7,189	)
Proceeds from sale of long-lived assets		687			—			—			9


Net cash used in investing activities		(5,442	)		(1,732	)		(2,806	)		(7,180	)


Cash flows from financing activities:
Change in book overdrafts		(400	)		339			(220	)		238
Principal payments on capital lease obligations		(11	)		—			(11	)		(9	)
Net contributions from (distributions to) SemGroup		(18,577	)		6,844			70,394			168,461


Net cash provided by (used in) financing activities		(18,988	)		7,183			70,163			168,690


Net change in cash and cash equivalents		—			—			—			—
Cash and cash equivalents at beginning of period		—			—			—			—


Cash and cash equivalents at end of period	$	—		$	—		$	—		$	—

The accompanying notes are an integral part of these financial statements.

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SemStream Non-Residential Division

Notes to Financial Statements

1. OVERVIEW

Basis of presentation

SemStream, L.P. is a wholly owned subsidiary of SemGroup Corporation engaged in the terminalling, storage, marketing and distribution of propane and other natural gas liquids in the United States. Its operations included sales to retail, wholesale and commercial customers linked to purchases from suppliers, and encompassed three primary focus areas: (i) wholesale marketing at both private and common carrier terminals; (ii) natural gas liquids supply to retail, petrochemical and commercial customers; and (iii) residential propane supply in Arizona.

As described in Note 10, on November 1, 2011, SemStream, L.P. contributed certain of its assets to NGL Energy Partners LP ("NGL Energy"). The contributed assets included SemStream, L.P.'s primary operating assets, excluding those of its residential operations. The accompanying financial statements of the SemStream Non-Residential Division reflect the historical activity of the operations that were contributed to NGL Energy. The SemStream Non-Residential Division will hereinafter be referred to as "SemStream".

SemGroup Corporation is a Delaware Corporation with its headquarters in Tulsa, Oklahoma. SemGroup Corporation is the successor entity of SemGroup, L.P., which was an Oklahoma limited partnership. The term "SemGroup" refers to SemGroup Corporation, SemGroup, L.P., and their other controlled subsidiaries.

These financial statements have been prepared in accordance with accounting principles generally accepted in the United States.

Operations

SemStream's operations included the following:

•: twelve natural gas liquids terminals across the United States;
•: approximately 290,000 barrels of owned natural gas liquids storage capacity;
•: an additional 3.8 million barrels of leased natural gas liquids storage capacity; and
•: thirteen owned and over 350 leased railcars.

Bankruptcy

On July 22, 2008 (the "Petition Date"), SemGroup, L.P. and SemStream, L.P. filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. While in bankruptcy, SemGroup, L.P. filed a Plan of Reorganization with the court, which was confirmed on October 28, 2009. The Plan of Reorganization determined, among other things, how pre-Petition Date obligations would be settled, the equity structure of the reorganized company upon emergence, and the financing arrangements upon emergence. SemGroup Corporation and SemStream, L.P. emerged from bankruptcy protection on November 30, 2009 (the "Emergence Date").

The accompanying financial statements of SemStream include its activities prior to emergence from bankruptcy and its activities subsequent to emergence from bankruptcy. As described in Note 3, SemStream applied fresh-start reporting on the Emergence Date. As a result, the financial statements of SemStream subsequent to the Emergence Date are not comparable to its financial statements prior to the Emergence Date.

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Notes to Financial Statements (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

USE OF ESTIMATES—The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures in the financial statements. SemStream's significant estimates include, but are not limited to: (1) allowances for doubtful accounts receivable; (2) estimated useful lives of assets, which impacts depreciation; (3) estimated fair values of long-lived assets recorded in fresh-start reporting; (4) estimated fair values of long-lived assets used in impairment tests; (5) fair values of derivative instruments; and (6) accrual and disclosure of contingent losses. Although management believes these estimates are reasonable, actual results could differ materially from these estimates.

FRESH-START REPORTING—SemGroup adopted fresh-start reporting on the Emergence Date. In connection with fresh-start reporting, SemStream recorded its assets and liabilities at fair value at the Emergence Date.

CASH AND CASH EQUIVALENTS—Cash includes currency on hand and demand and time deposits with banks or other financial institutions. Cash equivalents include highly liquid investments with maturities of three months or less at the date of purchase.

ACCOUNTS RECEIVABLE—Accounts receivable are reported net of the allowance for doubtful accounts. SemStream's assessment of the allowance for doubtful accounts is based on several factors, including the overall creditworthiness of its customers, existing economic conditions, and the amount and age of past due accounts. SemStream entered into netting arrangements with certain counterparties to help mitigate credit risk. Receivables subject to netting are presented as gross receivables (with the related accounts payable also presented gross) until such time as the balances are settled. Receivables are considered past due if full payment is not received by the contractual due date. Past due accounts are written off against the allowance for doubtful accounts only after all collection attempts have been exhausted. At the Emergence Date, as part of fresh-start reporting, SemStream recorded accounts receivable at fair value. This was accomplished by reducing the allowance for doubtful accounts to $-0- and recording a corresponding reduction to accounts receivable.

INVENTORIES—Inventories primarily consist of natural gas liquids. Inventories are valued at the lower of cost or market, with cost generally determined using the weighted-average method, although as described above, inventory was adjusted to fair value at November 30, 2009 upon adoption of fresh-start reporting. The cost of inventory includes applicable transportation costs.

Prior to emergence from bankruptcy, SemStream's policy was to measure the fair value of inventory, for the purpose of determining whether to lower the carrying value from cost to market, on a monthly basis. Subsequent to emergence from bankruptcy, SemStream's policy is to measure the fair value of inventory, for the purpose of determining whether to lower the carrying value from cost to market, on a quarterly basis.

SemStream enters into exchanges with third parties whereby it acquires products that differ in location, grade, or delivery date from products SemStream has available for sale. These exchanges are valued at cost, and although a transportation, location or product differential may be recorded, generally no significant gain or loss is recognized.

PROPERTY, PLANT AND EQUIPMENT—Property, plant and equipment is recorded at cost (although, as described above, property, plant and equipment was adjusted to fair value at

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Notes to Financial Statements (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

November 30, 2009 upon adoption of fresh-start reporting). SemStream capitalizes costs that extend or increase the future economic benefits of property, plant and equipment, and expenses maintenance costs that do not. When assets are disposed of, their cost and related accumulated depreciation are removed from the balance sheet, and any resulting gain or loss is recorded within operating expenses in the statements of operations.

Depreciation is calculated primarily on the straight-line method over the following estimated useful lives:


Storage and terminal facilities		10 - 25 years
Pipelines and related facilities		20 years

LINEFILL—Pipelines and storage facilities generally require a minimum volume of product in the system to enable the system to operate. Such product, known as linefill, is generally not available to be withdrawn from the system. Linefill owned by SemStream in facilities operated by SemStream is recorded at historical cost, is included in property, plant and equipment on the balance sheets, and is not depreciated. SemStream also owned linefill in third party facilities, which is included in inventory on the balance sheets.

IMPAIRMENT OF LONG-LIVED ASSETS—SemStream tests long-lived asset groups for impairment when events or circumstances indicate that the net book value of the asset group may not be recoverable. SemStream tests an asset group for impairment by estimating the undiscounted cash flows expected to result from its use and eventual disposition. If the estimated undiscounted cash flows are lower than the net book value of the asset group, SemStream estimates the fair value of the asset group and records a reduction to the net book value of the assets and a corresponding impairment loss.

GOODWILL—SemStream tests goodwill for impairment on an annual basis, or more often if circumstances warrant, by estimating the fair value of its assets and comparing this to the net book value of its assets. If fair value is less than net book value, SemStream estimates the implied fair value of goodwill, reduces the book value of the goodwill to the implied fair value, and records a corresponding impairment loss. Prior to the Emergence Date, SemStream's policy was to test goodwill for impairment on December 31 of each year. Subsequent to the Emergence Date, SemStream's policy is to test goodwill for impairment on October 1 of each year. For the October 1, 2010 impairment test, SemStream developed estimates of future cash flows for a period of 15 years, and also developed an estimated terminal value using an assumed 3% growth rate. Estimated cash flows were then discounted to present value using a rate of 9.36%.

OTHER INTANGIBLE ASSETS—Other intangible assets consist of customer relationships and contracts. Prior to the Emergence Date, intangible assets were generally amortized on a straight-line basis over the expected period of benefit. Subsequent to the Emergence Date, intangible assets are generally amortized on an accelerated basis over the estimated period of benefit. These assets could be subject to impairment in the event relationships are not maintained with the customers to which the assets relate. SemStream recorded intangible asset amortization expense of $2.9 million for the year ended December 31, 2010, $0.2 million for the month ended December 31, 2009, $0.6 million for the eleven months ended November 30, 2009, and $0.8 million for the year ended December 31, 2008. At

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Notes to Financial Statements (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

December 31, 2010, amortization of other intangible assets was scheduled to be as follows (in thousands):


For the year ending:
December 31, 2011	$	2,268
December 31, 2012		1,916
December 31, 2013		1,627
December 31, 2014		1,366
December 31, 2015		1,115
Thereafter		5,631


Total scheduled amortization expense	$	13,923

DERIVATIVE INSTRUMENTS AND MARGIN DEPOSITS—SemStream generally records the fair value of derivative instruments on its balance sheets and the change in fair value as an increase or decrease to product revenue. The fair values of derivatives and related margin deposits at December 31, 2010 and 2009 are reported within current assets or current liabilities on the balance sheets. Margin deposits have generally not been netted against derivative assets or liabilities at December 31, 2010 and 2009.

The fair value of a derivative contract is determined based on the nature of the transaction and the market in which the transaction was executed. Quoted market prices, when available, are used to value derivative transactions. In situations where quoted market prices are not readily available, SemStream estimates the fair value using other valuation techniques that reflect the best information available under the circumstances. Fair value measurements of derivative assets include consideration of counterparty credit risk. Fair value measurements of derivative liabilities include consideration of SemGroup's creditworthiness.

SemStream has elected "normal purchase" and "normal sale" treatment for certain commitments to purchase or sell petroleum products at future dates. This election is only available when a transaction is expected to result in physical delivery of product over a reasonable period in the normal course of business and is not expected to be net settled. Agreements accounted for under this election are not recorded at fair value; instead, the transaction is recorded when title to the product is transferred.

INTERCOMPANY ACCOUNTS—SemStream participated in SemGroup's cash management program. Under this program, cash SemStream received from customers was transferred to SemGroup on a regular basis; when SemStream remitted payments to suppliers, SemGroup transferred cash to SemStream to cover the payments. In addition, SemGroup incurred certain expenses on SemStream's behalf that are reported within SemStream's statements of operations.

SemStream recorded transactions with SemGroup and its other controlled subsidiaries to intercompany accounts. When SemStream's intercompany accounts were in a net receivable position, the balance has been reported as a reduction to equity on the balance sheet. When SemStream's intercompany accounts were in a net payable position, the balance has been reported as a current liability on the balance sheet. In the statements of cash flows, SemStream has reported the net change in the intercompany accounts as a financing cash flow within "net contributions from (distributions to)

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SemStream Non-Residential Division

Notes to Financial Statements (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

SemGroup". SemStream has reported the net change in equity associated with these transactions as "net contributions from SemGroup" or "net distributions to SemGroup" in the statements of changes in net parent equity.

SemStream's intercompany accounts were in a net receivable position of $13.5 million at December 31, 2010. SemStream has reported this balance as a reduction to equity on the balance sheet, as SemStream does not expect to collect these intercompany receivables. SemStream's intercompany accounts were in a net payable position of $5.0 million at December 31, 2009.

PAYABLES TO PRE-PETITION CREDITORS—SemGroup's Plan of Reorganization specified the total amount of consideration it would provide to all pre-petition creditors in settlement of their claims. SemGroup has not yet completed the process of disbursing funds to settle pre-petition claims, as it has not yet completed the process of resolving all of the claims. Upon emergence from bankruptcy, SemStream recorded a liability to reflect its obligations to these claimants pursuant to the Plan of Reorganization.

CONTINGENT LOSSES—SemStream records a liability for a contingent loss when it is probable that a loss has been incurred and the amount of the loss can be reasonably estimated. SemStream records attorneys' fees incurred in connection with a contingent loss at the time the fees are incurred. SemStream does not record liabilities for attorneys' fees that are expected to be incurred in the future.

ASSET RETIREMENT OBLIGATIONS—Asset retirement obligations include legal or contractual obligations associated with the retirement of long-lived assets, such as requirements to incur costs to dispose of equipment or to remediate the environmental impacts of the normal operation of the assets. SemStream records liabilities for asset retirement obligations when a known obligation exists under current law or contract and when a reasonable estimate of the value of the liability can be made.

REVENUE RECOGNITION—Sales of product are recognized at the time title to the product transfers to the purchaser. Any transportation costs incurred to ship product on third-party infrastructure are included in the price of product sold to customers, and are included within product revenues and costs of goods sold. Taxes collected from customers and remitted to governmental authorities are recorded on a net basis (excluded from revenue).

SemStream routinely enters into transactions to purchase inventory from, and sell inventory to, the same counterparty. Revenues for such transactions that are entered into in contemplation of one another are recorded net of costs of products sold. SemStream accounted for $118.9 million of such transactions on a net basis during the year ended December 31, 2010, $3.6 million of such transactions on a net basis during the month ended December 31, 2009, $10.2 million of such transactions on a net basis during the eleven months ended November 30, 2009, and $222.6 million of such transactions on a net basis during the year ended December 31, 2008.

INTEREST EXPENSE—The interest expense reported in SemStream's statements of operations consists of letter of credit fees. SemGroup has been a borrower on several corporate credit agreements (and SemStream's assets served as collateral under these agreements), but SemGroup did not allocate this debt to its subsidiaries. SemGroup did not charge SemStream interest on the balances in its intercompany accounts.

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SemStream Non-Residential Division

Notes to Financial Statements (Continued)

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

OTHER INCOME—Other income in the statement of operations for the year ended December 31, 2010 includes a $1.2 million gain on the settlement of a dispute related to the cancellation of a contract by a counterparty during 2008, and also includes a gain of $1.2 million related to the settlement of a dispute related to certain transportation fees charged to SemStream by an unaffiliated party during the years 2005-2009.

INCOME TAXES—SemStream, L.P. is a pass-through entity for federal and state income tax purposes. Its earnings are allocated to its owners, who are responsible for any related income taxes. Because of this, no provision for income taxes is reported in the accompanying statements of operations.

REORGANIZATION ITEMS—As described in Note 1, SemGroup and SemStream, L.P. operated as debtors-in-possession subject to the jurisdiction of the bankruptcy court during the period from the Petition Date to the Emergence Date. Revenues, expenses, realized gains and losses, and provisions for losses resulting from the reorganization and restructuring of the business are reported as reorganization items in the statements of operations. The effects of the adjustments to the reported amounts of assets and liabilities resulting from the adoption of fresh-start reporting are reported within reorganization items in the statement of operations for the eleven months ended November 30, 2009.

SUBSEQUENT EVENTS—SemStream has evaluated subsequent events for accrual or disclosure in these financial statements through November 3, 2011, which is the date these financial statements were issued.

3. REORGANIZATION

On July 22, 2008, SemGroup and many of its affiliates (including SemStream, L.P.), filed voluntary petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. Certain claims against SemGroup in existence prior to the filing of the petitions for relief under the federal bankruptcy laws were stayed while SemGroup continued business operations as a debtor-in-possession. SemGroup received approval from the court to pay or otherwise honor certain of its obligations incurred before the Petition Date. The court also approved SemGroup's use of cash to meet post-Petition Date obligations.

While in bankruptcy, SemGroup filed a Plan of Reorganization with the court, which was confirmed on October 28, 2009. The Plan of Reorganization determined, among other things, how pre-Petition Date obligations would be settled, SemGroup's equity structure upon emergence, and SemGroup's financing arrangements upon emergence.

Determination of reorganization value

An essential element in negotiating a reorganization plan with the various classes of creditors is the determination of reorganization value by the parties in interest. In the event that the parties in interest cannot agree on the reorganization value, the court may be called upon to determine the reorganization value of the entity before a plan of reorganization can be confirmed.

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SemStream Non-Residential Division

Notes to Financial Statements (Continued)

3. REORGANIZATION (Continued)

During SemGroup's reorganization process, a reorganization value was proposed. This reorganization value was ultimately agreed to by the creditors and confirmed by the court. The proposed reorganization value was determined by applying the following valuation methods:

•: a "guideline company" approach, in which valuation multiples observed from industry participants were considered and comparisons were made between SemGroup's expected performance relative to other industry participants to determine appropriate multiples to apply;
•: analysis of recent transactions involving companies determined to be similar to SemGroup; and
•: a calculation of the present value of SemGroup's estimated future cash flows.

After completing this analysis, the reorganization value of SemGroup was determined to be $1.5 billion. This proposed reorganization value was determined using numerous projections and assumptions. These estimates are subject to significant uncertainties, many of which are beyond SemGroup's control, including, but not limited to, the following:

•: changes in the economic environment;
•: changes in supply or demand for petroleum products;
•: changes in prices of petroleum products;
•: the ability to successfully implement expansion projects;
•: the ability to improve relationships with customers and suppliers, as these relationships were adversely impacted by the bankruptcy filing;
•: the ability to renew certain business operations that were limited during the bankruptcy due to limitations on access to capital; and
•: the ability to manage the additional costs associated with being a public company.

The use of different estimates could have resulted in a materially different proposed reorganization value, and there can be no assurance that actual results will be consistent with the estimates that were used to determine the proposed reorganization value. The reorganization value confirmed by the court was utilized in the application of fresh-start reporting.

Valuation of SemStream's assets and liabilities

SemGroup determined that $253.8 million of its reorganization value was attributable to SemStream. Accordingly, SemStream recorded individual assets and liabilities based on their estimated fair values at the Emergence Date.

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Notes to Financial Statements (Continued)

3. REORGANIZATION (Continued)

November 30, 2009 balance sheet

The following table shows the effects of the emergence from bankruptcy on SemStream's November 30, 2009 balance sheet (in thousands):

	Prior to Emergence			Reorganization Adjustments			Fresh Start Adjustments			Subsequent to Emergence

ASSETS
Current assets:
Accounts receivable	$	40,330		$	—		$	—		$	40,330
Receivable from affiliate		1,799			(1,799)	(a)		—			—
Inventories		100,529			—			36,502	(h)		137,031
Derivative assets		2,894			—			1,700	(h)		4,594
Margin deposits		22,379			—			—			22,379
Other current assets		11,994			—			—			11,994


Total current assets		179,925			(1,799	)		38,202			216,328


Property, plant and equipment, net		37,826			—			4,281	(h)		42,107
Goodwill		2,425			—			47,646	(h)		50,071
Other intangible assets, net		3,288			—			13,712	(h)		17,000
Other assets		3,886			—			—			3,886


Total assets	$	227,350		$	(1,799	)	$	103,841		$	329,392




LIABILITIES AND NET PARENT EQUITY (DEFICIT)
Current liabilities:
Accounts payable	$	43,565		$	(534)	(b)	$	—		$	43,031
Advances from parent		476,451			(476,451)	(c)		—			—
Derivative liabilities		15,943			(408)	(d)		4,908	(h)		20,443
Payables to pre-petition creditors		—			10,202	(e)		—			10,202
Other current liabilities		1,768			—			—			1,768


Total current liabilities		537,727			(467,191	)		4,908			75,444


Liabilities subject to compromise		25,750			(25,750)	(f)		—			—
Other noncurrent liabilities		160			—			—			160
Net parent equity (deficit):
Net parent equity (deficit)—Predecessor		(336,287	)		336,287	(g)		—			—
Net parent equity—Successor		—			154,855	(g)		98,933	(i)		253,788


Net parent equity (deficit)		(336,287	)		491,142			98,933			253,788


Total liabilities and net parent equity (deficit)	$	227,350		$	(1,799	)	$	103,841		$	329,392


					��

(a): Prior to emergence from bankruptcy, SemStream had a receivable from SemCanada Crude Company, which is a wholly-owned subsidiary of SemGroup that applied for bankruptcy protection in Canada in July 2008 and emerged from bankruptcy on November 30, 2009, concurrent with the emergence of SemGroup and SemStream. SemCanada Crude Company was not under SemGroup's control during the bankruptcy.

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Notes to Financial Statements (Continued)

3. REORGANIZATION (Continued)

(b): SemStream elected not to cancel certain contracts that were in effect prior to the Petition Date. For these contracts, SemStream was required to make payments to the counterparties to cure defaults on the contracts. These payments were made by SemGroup upon emergence from bankruptcy.
(c): SemStream's liabilities to SemGroup and its controlled subsidiaries were extinguished pursuant to the Plan of Reorganization.
(d): Reflects the transfer to SemGroup of a commodity derivative contract.
(e): SemGroup's Plan of Reorganization specified the total amount of consideration it would provide to all pre-petition creditors in settlement of their claims. SemGroup has not yet completed the process of disbursing funds to settle pre-petition claims, as it has not yet completed the process of resolving all of the claims. Upon emergence from bankruptcy, SemStream recorded a liability to reflect its obligations to these claimants pursuant to the Plan of Reorganization.
(f): Represents the transfer to SemGroup of liabilities subject to compromise, pursuant to the Plan of Reorganization.
(g): Reflects the cancellation of predecessor equity and the issuance of successor equity.
(h): Reflects the adjustments to the recorded values of assets and liabilities resulting from fresh-start reporting.
(i): Reflects the reorganization items gain resulting from fresh-start reporting.

Reorganization items

The reorganization items gain (loss) shown on the statements of operations consists of the following (in thousands):

	Prior to Emergence

	Eleven Months Ended November 30, 2009			Year Ended December 31, 2008
Gain on asset revaluation in fresh-start reporting(a)	$	98,933		$	—
Professional fees(b)		(68,120	)		(24,430	)
Uncollectable accounts expense(c)		(6,213	)		—
Adjustment to liabilities subject to compromise(d)		4,100			—
Employment costs(e)		(2,059	)		(817	)
Other		(171	)		—


Total reorganization items gain (loss)	$	26,470		$	(25,247	)

(a): SemStream revalued its assets and liabilities in fresh-start reporting, and recorded a reorganization gain for the increase in fair value of the net assets over the previously recorded values.

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Notes to Financial Statements (Continued)

3. REORGANIZATION (Continued)

(b)

SemGroup incurred a variety of professional fees related to the restructuring of the business, including, among others:

•: legal fees related to the reorganization process, including those related to bankruptcy court filings and hearings, negotiation of credit agreements, settlements of disputes with claimants, and other matters;
•: general management consulting services related to the disposal of assets, the reconciliation and negotiation of pre-petition claims, preparation for emergence from bankruptcy, and other matters;
•: valuation advisory fees for the determination of the reorganization value of the business required for the Plan of Reorganization and the valuation of long-lived assets required by fresh-start reporting;
•: accounting fees for assistance with fresh-start reporting and preparation for public company financial reporting obligations; and
•: fees paid to the United States Trustee.
SemGroup allocated a portion of these fees to SemStream, based on the reorganization value of SemStream relative to the total reorganization value of SemGroup's United States subsidiaries that emerged from bankruptcy.

(c)

Represents the write-off of receivables in situations where SemStream believed the customer non-payment was related to the bankruptcy.

(d)

Represents refinements to the estimated amount of valid claims by pre-petition creditors. During 2008, SemStream recorded an estimated loss for the total amount of valid claims subject to compromise. During 2009, SemStream refined this estimate as it reviewed the claims, and reversed a $4.1 million loss that had been recorded to general and administrative expense in 2008.

(e)

Employment costs include severance related to the termination of employment relationships and bonuses paid to retain personnel during the reorganization.

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Notes to Financial Statements (Continued)

4. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consists of the following (in thousands):

	Subsequent to Emergence

	December 31, 2010			December 31, 2009
Land	$	3,006		$	3,006
Pipelines and related facilities		4,277			2,741
Storage and terminal facilities		39,895			35,515
Linefill		1,170			—
Other property and equipment		931			846
Construction-in-progress		1,091			879


Property, plant and equipment, gross		50,370			42,987
Accumulated depreciation		(2,342	)		(175	)


Property, plant and equipment, net	$	48,028		$	42,812

SemStream recorded depreciation expense of $2.2 million for the year ended December 31, 2010, $0.2 million for the month ended December 31, 2009, $3.2 million for the eleven months ended November 30, 2009, and $3.1 million for the year ended December 31, 2008.

SemStream includes within the cost of property, plant and equipment interest costs incurred by SemGroup while an asset is being constructed. SemStream capitalized $0.1 million of interest costs during the year ended December 31, 2008. Since the related debt was recorded by SemGroup, rather than by SemStream, no interest expense related to SemGroup's debt is reported in SemStream's statements of operations. The increase in the value of property, plant and equipment associated with capitalized interest is reported as an increase to SemStream's net parent equity.

5. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK

Commodity derivative contracts

SemStream's results of operations and cash flows are impacted by changes in market prices for petroleum products. This exposure to commodity price risk was managed, in part, by entering into various commodity derivatives.

During 2009 and 2010, SemStream managed commodity price risk by limiting its net open positions subject to outright price risk and basis risk resulting from grade, location or time differences. SemStream did so by selling and purchasing similar quantities of natural gas liquids with purchase and sale transactions for current or future delivery, by entering into future delivery and purchase obligations with futures contracts or other commodity derivatives and employing its storage and transportation assets. At times SemStream hedged its natural gas liquids commodity price exposure with derivatives on commodities other than natural gas liquids due to the limited size of the market for natural gas liquids derivatives. In addition, physical transaction sale and purchase strategies were intended to lock in positive margins for SemStream, e.g., the sales price was sufficient to cover purchase costs, any other fixed and variable costs and SemStream's profit. All marketing activities were subject to SemGroup's risk management policy, which established limits to manage risk and mitigate financial exposure.

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5. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

During 2010 and 2009, SemStream's commodity derivatives were comprised of natural gas liquids swaps, forward contracts and futures contracts. These are defined as follows:

Swaps—Over the counter transactions where a floating price, basis or index is exchanged for a fixed (or a different floating) price, basis, or index at a preset schedule in the future according to an agreed upon formula.

Forward contracts—Over the counter contracts to buy or sell a commodity at an agreed upon future date. The buyer and seller agree on specific terms (price, quantity, delivery period, and location) and conditions at the inception of the contract.

Futures contracts—Exchange traded contracts to buy or sell a commodity. These contracts are standardized by the exchange in terms of quality, quantity, delivery period and location for each commodity.

The table below summarizes the balances of derivative assets and liabilities at December 31, 2010 and 2009 (in thousands):

	Subsequent to Emergence

	December 31, 2010														December 31, 2009
	Level 1			Level 2			Level 3			Netting		Total			Level 1		Level 2		Level 3			Netting			Total
Assets	$	84		$	1,785		$	2,498		$	—	$	4,367		$	—	$	1,605	$	982		$	(27	)	$	2,560
Liabilities		2,123			6,631			4,664			—		13,418			—		1,193		24,638			(27	)		25,804


Net assets (liabilities) at fair value	$	(2,039	)	$	(4,846	)	$	(2,166	)	$	—	$	(9,051	)	$	—	$	412	$	(23,656	)	$	—		$	(23,244	)

"Level 1" measurements were obtained using unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. These include futures contracts that are traded on an exchange.

"Level 2" measurements use as inputs market observable and corroborated prices for similar derivative contracts. Assets and liabilities classified as Level 2 include over-the-counter (OTC) traded forward contracts and swaps.

"Level 3" measurements were obtained using information from a pricing service and internal valuation models incorporating observable and unobservable market data. These include commodity derivatives, such as forward contracts and swaps for which there is not a highly liquid market and therefore are not included in Level 2 above.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. SemStream's assessment of the significance of a particular input to the measurement requires judgment, and may affect the valuation of assets and liabilities and their placement within the fair value levels.

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5. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

The following table reconciles changes in the fair value of commodity derivatives classified as Level 3 in the fair value hierarchy (in thousands):

	Subsequent to Emergence						Prior to Emergence

	Year Ended December 31, 2010			Month Ended December 31, 2009			Eleven Months Ended November 30, 2009



Beginning balance	$	(23,656	)	$	(16,071	)	$	11,335
Transfers out of Level 3(*)		4,072			—			—
Total gain or loss (realized and unrealized) included in product revenues		(6,270	)		(13,587	)		(18,603	)
Settlements		23,688			6,002			(5,596	)
Fresh-start and plan effect adjustments		—			—			(3,207	)


Ending balance	$	(2,166	)	$	(23,656	)	$	(16,071	)




Amount of total loss included in earnings for the period attributable to the change in unrealized loss relating to assets and liabilities still held at the reporting date	$	(6,270	)	$	(13,587	)	$	(18,603	)

(*): SemStream's policy is to recognize transfers in and transfers out as of the beginning of the reporting period.

The following table sets forth the notional quantities for derivative instruments entered into during the periods indicated (amounts in thousands of barrels):

	Subsequent to Emergence				Prior to Emergence

	Year Ended December 31, 2010		Month Ended December 31, 2009		Eleven Months Ended November 30, 2009



Sales		9,884		720		8,923
Purchases		8,797		345		3,784

Realized and unrealized losses from SemStream's commodity derivatives were recorded to product revenue in the following amounts (in thousands):

	Subsequent to Emergence						Prior to Emergence

	Year Ended December 31, 2010			Month Ended December 31, 2009			Eleven Months Ended November 30, 2009



Commodity Contracts	$	(10,215	)	$	(13,871	)	$	(32,522	)

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5. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

Transfer of derivative positions in July 2008

During July 2008, SemStream transferred to SemGroup certain of its open derivative positions and related margin deposits, and recorded a corresponding increase of $105.3 million to its intercompany liabilities. SemGroup subsequently transferred these derivatives (along with certain derivatives entered into by its other subsidiaries) to a third party, and SemGroup recorded a loss of $143 million on this third-party transaction. The losses on these derivatives prior to their transfer to SemGroup are reflected in SemStream's statements of operations, and the losses subsequent to the transfer of these derivatives to SemGroup are not reflected in SemStream's statements of operations.

Concentrations of risk

Customers from which SemStream generated more than 10% of its total revenue included the following (in thousands):

	Subsequent to Emergence										Prior to Emergence

	Year Ended December 31, 2010					Month Ended December 31, 2009					Eleven Months Ended November 30, 2009					Year Ended December 31, 2008


			Percentage of Total Revenues					Percentage of Total Revenues					Percentage of Total Revenues					Percentage of Total Revenues
	Revenues					Revenues					Revenues					Revenues
	Revenues					Revenues					Revenues					Revenues
Customer A	$	83,422		12	%	$	16,330		26	%	$	65,728		16	%	$	151,964		10	%
Customer B		*		*		$	9,300		15	%	$	56,394		13	%		*		*
Customer C		*		*		$	7,250		11	%		*		*			*		*
Customer D		*		*		$	6,734		11	%		*		*			*		*
Customer E		*		*			*		*			*		*		$	191,936		13	%

*: Revenues from this customer were less than 10% of total revenue for the period

SemStream's customers with accounts receivable balances greater than 10% of its total accounts receivable included the following (in thousands):

	Subsequent to Emergence

	December 31, 2010					December 31, 2009
	Accounts Receivable		Percentage of Total Accounts Receivable			Accounts Receivable		Percentage of Total Accounts Receivable
Customer F	$	11,734		14	%		*		*
Customer G	$	10,516		13	%		*		*
Customer B		*		*		$	9,772		23	%
Customer A		*		*		$	5,498		13	%

*: Accounts receivable trade balance at December 31st was less than 10% of reported accounts receivable balance.

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5. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

Suppliers from which SemStream's purchases represented more than 10% of SemStream's total costs of products sold included the following (in thousands):

	Subsequent to Emergence										Prior to Emergence

	Year Ended December 31, 2010					Month Ended December 31, 2009					Eleven Months Ended November 30, 2009					Year Ended December 31, 2008


			Percentage of Total Costs of Products Sold					Percentage of Total Costs of Products Sold					Percentage of Total Costs of Products Sold					Percentage of Total Costs of Products Sold

	Purchases					Purchases					Purchases					Purchases
	Purchases					Purchases					Purchases					Purchases
Supplier A**	$	96,065		14	%	$	17,640		23	%	$	74,995		18	%	$	173,031		10	%
Supplier B	$	75,708		11	%		*		*		$	47,162		11	%		*		*
Supplier C	$	71,008		10	%		*		*		$	43,443		10	%		*		*
Supplier D***		*		*		$	20,556		27	%	$	42,137		10	%		*		*
Supplier E		*		*			*		*			*		*		$	522,667		31	%
Supplier F		*		*			*		*			*		*		$	231,562		14	%

*: Purchases for the period was less than 10% of total costs of products sold.
**: Supplier A is the same entity as Customer F in the tables above.
***: Supplier D is the same entity as Customer G in the tables above.

As described in Note 9, SemStream also generated significant revenues and expenses during the periods from 2008 through 2010 from other subsidiaries of SemGroup.

6. COMMITMENTS AND CONTINGENCIES

Bankruptcy matters

(a): Confirmation order appeals

Manchester Securities appeal. On October 21, 2009, Manchester Securities Corporation, a creditor of SemGroup Holdings, L.P. (a subsidiary of SemGroup), filed an objection to the Plan of Reorganization. In the objection, Manchester argued that the Plan of Reorganization should not be confirmed because it did not provide for an alleged $50 million claim of SemGroup Holdings, L.P. against SemCrude Pipeline, L.L.C. (another subsidiary of SemGroup). On October 28, 2009, the bankruptcy court overruled the objection and entered the confirmation order approving the Plan of Reorganization. On November 4, 2009, Manchester filed a notice of appeal of the confirmation order. On December 4, 2009, Manchester's appeal was docketed in the United States District Court for the District of Delaware.

SemGroup filed a motion to dismiss the appeal as equitably moot. On February 18, 2011, the District Court granted SemGroup's motion to dismiss the appeal. On March 22, 2011, Manchester filed a notice to appeal this order. While SemGroup believes that this action is without merit and is vigorously defending this matter on appeal, an adverse ruling on this action could have a material adverse impact.

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6. COMMITMENTS AND CONTINGENCIES (Continued)

Luke Oil appeal. On October 21, 2009, Luke Oil Company, C&S Oil/Cross Properties, Inc., Wayne Thomas Oil and Gas and William R. Earnhardt Company (collectively, "Luke Oil") filed an objection to the Plan of Reorganization "to the extent that the Plan of Reorganization may alter, impair, or otherwise adversely affect Luke Oil's legal rights or other interests." On October 28, 2009, the bankruptcy court overruled the Luke Oil objection and entered the confirmation order. On November 6, 2009, Luke Oil filed a notice of appeal. On December 23, 2009, Luke Oil's appeal was docketed in the United States District Court for the District of Delaware. SemGroup filed a motion to dismiss the appeal as equitably moot. Luke Oil has filed a motion to stay the briefing on SemGroup's motion to dismiss. On February 18, 2011, the District Court denied the stay motion and ordered the parties to complete briefing. While SemGroup believes that this action is without merit and is vigorously defending this matter on appeal, an adverse ruling on this action could have a material adverse impact.

(b): Claims reconciliation process

A large number of parties have made claims against SemStream for obligations alleged to have been incurred prior to the Petition Date. On September 15, 2010, the bankruptcy court entered an order estimating the contingent, unliquidated and disputed claims and authorizing distributions to holders of allowed claims. Pursuant to that order, SemGroup has begun making distributions to the claimants. SemGroup continues to attempt to settle unresolved claims.

Pursuant to the Plan of Reorganization, SemGroup committed to settle authorized and allowed bankruptcy claims by paying a specified amount of cash, issuing a specified number of warrants, and issuing a specified number of shares of SemGroup Corporation common stock. SemGroup does not believe the resolution of the remaining outstanding claims will exceed the total amount of consideration established under the Plan of Reorganization for all claimants; instead, the resolutions of the remaining claims in some cases will impact the relative share of the established pool of common stock and warrants that certain claimants receive.

However, under certain circumstances SemGroup could be required to pay additional funds to settle the specified group of claims to be settled with cash. Pursuant to the Plan of Reorganization, a specified amount of restricted cash was set aside at the Emergence Date, which SemGroup expects to be sufficient to settle this group of claims. Since the Emergence Date, SemGroup has made significant progress in resolving these claims, and continues to believe that the cash set aside at the Emergence Date will be sufficient to settle these claims. However, SemGroup has not yet reached a resolution of all of these claims, and if the total settlement amount of all of these claims exceeds the specified amount, SemGroup will be required to pay additional funds to satisfy the total settlement amount for this specified group of claims. If this were to become probable of occurring, SemGroup would be required to record a liability and a corresponding expense, and SemStream could be required to share in this expense.

Environmental

SemStream may from time to time experience leaks of petroleum products from its facilities, as a result of which it may incur remediation obligations or property damage claims. In addition, SemStream is subject to numerous environmental regulations. Failure to comply with these regulations could result in the assessment of fines or penalties by regulatory authorities.

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6. COMMITMENTS AND CONTINGENCIES (Continued)

Asset retirement obligations

SemStream may be subject to removal and restoration costs upon retirement of their facilities. However, SemGroup does not believe the present value of such obligations under current laws and regulations, after taking into account the estimated lives of the facilities, is material to SemStream's financial position or results of operations.

Other matters

SemStream is party to various other claims, legal actions, and complaints arising in the ordinary course of business. In the opinion of SemGroup's management, the ultimate resolution of these claims, legal actions, and complaints, after consideration of amounts accrued, insurance coverage, and other arrangements, will not have a material adverse effect on SemStream's financial position, results of operations or cash flows. However, the outcome of such matters is inherently uncertain, and estimates of SemStream's liabilities may change materially as circumstances develop.

Leases

SemStream has entered into operating lease agreements for office space, office equipment, land, trucks and tank storage. Future minimum payments required under operating leases that have initial or remaining non-cancelable lease terms in excess of one year at December 31, 2010 are as follows (in thousands):



For the year ending:
December 31, 2011	$	858
December 31, 2012		825
December 31, 2013		808
December 31, 2014		806
December 31, 2015		230
Thereafter		2


Total future minimum lease payments	$	3,529

SemStream recorded lease and rental expenses of $4.2 million for the year ended December 31, 2010, $0.4 million for the month ended December 31, 2009, $3.9 million for the eleven months ended November 30, 2009, and $4.4 million for the year ended December 31, 2008.

Purchase and sale commitments

SemStream routinely entered into agreements to purchase and sell petroleum products at specified future dates. SemStream established a margin for these purchases by entering into various types of physical and financial sales and exchange transactions through which it sought to maintain a position that was substantially balanced between purchases on the one hand and sales and future delivery obligations on the other. SemStream accounted for these commitments as normal purchases and sales,

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6. COMMITMENTS AND CONTINGENCIES (Continued)

and therefore did not record assets or liabilities related to these agreements until the product was purchased or sold. At December 31, 2010, such commitments included the following (in thousands):

		Value

Floating price purchases	1,574	$	85,765
Floating price sales	792	$	44,786

Certain of the commitments shown in the table above relate to agreements to purchase product from a counterparty and to sell a similar amount of product (in a different location) to the same counterparty. Many of the commitments shown in the table above are cancellable by either party, as long as notice is given within the time frame specified in the agreement (generally 30 to 120 days).

SemStream has also entered into an agreement under which it is obligated to purchase all of the propane produced by a third-party refinery at a price that floats based on market rates. Under one of these agreements, which expires March 31, 2012, SemStream purchased 11.3 million gallons of propane during 2010 for a total price of $14.2 million.

SemStream has also entered into a long term marketing agreement to market all natural gas liquids produced by a third party's natural gas processing plants. The agreement expires March 31, 2022. SemStream marketed 60.5 million gallons of natural gas liquids at a purchase cost of $77.3 million during 2010 pursuant to this agreement.

7. EMPLOYEE BENEFITS AND EQUITY-BASED COMPENSATION

SemStream did not directly employ any persons to manage or operate its business, as these functions were performed by employees of SemGroup. At December 31, 2010, SemGroup had approximately 50 employees who were dedicated primarily to the management and operation of SemStream's business. None of these employees were represented by labor unions, and none were subject to collective bargaining agreements.

Equity-based compensation

Certain of SemGroup's employees who supported SemStream participated in SemGroup's equity-based compensation program. Awards under this program generally represented awards of restricted stock of SemGroup, which were subject to specified vesting periods. SemGroup charged SemStream $0.4 million during the year ended December 31, 2010 related to such equity-based compensation.

Retention awards

Certain of SemGroup's employees who supported SemStream were granted retention awards by SemGroup. Each award had a specified value that would be payable either in cash or in shares of SemGroup common stock upon vesting. SemGroup charged SemStream $0.6 million during the year ended December 31, 2010 related to these awards.

Defined contribution plan

Most of the employees of SemGroup who supported SemStream participated in one of SemGroup's defined contribution plans. SemGroup charged SemStream $0.2 million during each of the

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7. EMPLOYEE BENEFITS AND EQUITY-BASED COMPENSATION (Continued)

year ended December 31, 2010, the eleven months ended November 30, 2009, and the year ended December 31, 2008, for contributions made by SemGroup to this plan.

Allocated employee compensation expenses

As described in Note 9, SemGroup allocated certain corporate general and administrative expenses to SemStream. These allocated expenses included equity-based compensation, retention awards, and defined contribution plan benefits for corporate employees, and such expenses are in addition to the expenses described above for employees who directly supported SemStream's operations.

Prior to emergence

Prior to the Petition Date, certain of SemGroup's employees who supported SemStream participated in equity-based compensation programs. These awards were cancelled in the reorganization. Certain other employees participated in a supplemental executive retirement plan, which was terminated on December 31, 2008.

8. SUPPLEMENTAL INFORMATION—STATEMENTS OF CASH FLOWS

The non-cash reorganization items shown on the statement of cash flows for the eleven months ended November 30, 2009 include a $6.2 million allowance for uncollectable accounts and a $4.1 million gain on adjustments to liabilities subject to compromise.

As described in Note 3, SemStream transferred certain assets and liabilities to SemGroup on November 30, 2009, pursuant to SemGroup's Plan of Reorganization. This non-cash activity is not reflected in SemStream's statement of cash flows for the eleven months ended November 30, 2009.

9. TRANSACTIONS WITH SEMGROUP

Direct employee expenses

SemStream did not directly employ any persons to manage or operate its business; these functions were performed by employees of SemGroup. SemGroup charged SemStream $6.7 million during the year ended December 31, 2010, $0.6 million during the month ended December 31, 2009, $5.2 million during the eleven months ended November 30, 2009, and $4.1 million during the year ended December 31, 2008 for direct employee costs. These expenses were recorded to operating expenses and general and administrative expenses in SemStream's statements of operations.

Allocated expenses

SemGroup incurs expenses to provide certain indirect corporate general and administrative services to its subsidiaries. Such expenses include employee compensation costs, professional fees, and rental fees for office space, among other expenses.

In 2008 and for the eleven months ended November 30, 2009, SemGroup's corporate general and administrative expenses were allocated to its subsidiaries based on percentages established by SemGroup management. At the beginning of each year, management estimated corporate general and administrative costs and assigned the subsidiaries a flat monthly charge of that amount. From time to time, the monthly charges were reviewed and adjusted. In addition to the flat monthly charge, the

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9. TRANSACTIONS WITH SEMGROUP (Continued)

subsidiaries would also be allocated a portion of the over or under allocation of actual corporate general and administrative expense from the prior month. This monthly "true up" was based on each subsidiary's year to date allocation as a percentage of the total year to date corporate general and administrative expense.

Beginning in December 2009, the general and administrative expenses of each corporate department were allocated to the subsidiaries based on criteria such as actual usage, headcount, and estimates of effort or benefit. The method for allocating cost is based on the type of service being provided. For example, internal audit costs are based on an estimate of effort attributable to a subsidiary. In contrast, certain accounting department costs are allocated based on the number of transactions processed for a given subsidiary compared to the total number processed.

SemGroup charged SemStream $5.0 million during the year ended December 31, 2010, $1.1 million during the month ended December 31, 2009, $2.4 million during the eleven months ended November 30, 2009, and $1.2 million during the year ended December 31, 2008 for such allocated costs. These expenses were recorded to general and administrative expenses in SemStream's statements of operations.

Allocated reorganization expenses

As described in Note 3, the reorganization items in SemStream's statements of operations include professional fees allocated from SemGroup of $68.0 million for the eleven months ended November 30, 2009 and $24.4 million for the year ended December 31, 2008. The reorganization items in the statements of operations also include employee expenses allocated from SemGroup of $1.4 million for the eleven months ended November 30, 2009 and $0.6 million for the year ended December 31, 2008.

SemGroup credit facilities

SemGroup was a borrower under various credit agreements during the periods included in these financial statements. SemStream, L.P., along with other subsidiaries of SemGroup, served as a subsidiary guarantor under certain of these agreements. SemGroup did not allocate this debt to its subsidiaries, and SemStream's statements of operations do not include any allocated interest expense. SemGroup did not charge SemStream interest expense on intercompany payables during the years from 2008 through 2010.

SemStream utilized letters of credit under SemGroup's credit facilities. At December 31, 2010, SemStream had outstanding letters of credit of $81 million. The statements of operations include direct charges from SemGroup for letter of credit usage, which is reported within interest expense.

Subsequent to the contribution of the SemStream assets to NGL Energy on November 1, 2011, these assets no longer serve as collateral under SemGroup's credit agreements.

Cash management

SemStream participated in SemGroup's cash management program. Under this program, cash SemStream received from customers was transferred to SemGroup on a regular basis; when SemStream remitted payments to suppliers, SemGroup transferred cash to them to cover the payments. As described in Note 2, such cash transfers were recorded to intercompany accounts.

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9. TRANSACTIONS WITH SEMGROUP (Continued)

Product purchases and sales

SemStream routinely entered into purchase and sale transactions with other controlled subsidiaries of SemGroup, including the following:

•: The sale of condensate and natural gasoline to SemCrude, L.P.;
•: The sale of condensate and natural gasoline to SemCanada Crude Company;
•: The sale of propane to the residential division of SemStream, L.P.; and
•: The purchase of natural gas liquids from SemGas, L.P.

The following table summarizes these transactions (amounts in thousands):

	Subsequent to Emergence				Prior to Emergence

	Year Ended December 31, 2010		Month Ended December 31, 2009		Eleven Months Ended November 30, 2009			Year Ended December 31, 2008



Revenues from SemCrude, L.P.(*)	$	35,410	$	2,952	$	26,306		$	104,822
Revenues from SemCanada Crude Company	$	16,811	$	1,525			(**)			(**)
Revenues from SemStream, L.P. residential division	$	8,089	$	1,293	$	5,367		$	10,333
Purchases from SemGas, L.P.	$	22,961	$	1,804	$	12,893		$	11,546

(*): Certain of the purchases from SemCrude, L.P. were fixed-price forward purchases, which were recorded at fair value at each balance sheet date. The revenue amounts in this table include any unrealized gains and losses on these contracts.
(**): SemCanada Crude Company was not consolidated by SemGroup during the period between the Petition Date and the Emergence Date, as SemCanada Crude's bankruptcy was administered in a different jurisdiction than that of SemGroup and SemStream, L.P. Transactions with SemCanada Crude Company during the period of time it was not consolidated by SemGroup are not included in table above. SemStream sold $13.8 million and $3.1 million of product to SemCanada Crude during the eleven months ended November 30, 2009 and the period from July 22, 2008 to December 31, 2008, respectively.

10. CONTRIBUTION OF ASSETS AND LIABILITIES TO NGL ENERGY

On November 1, 2011, SemStream, L.P. contributed many of the assets of the SemStream Non-Residential Division to NGL Energy, including the majority of the inventory, derivative assets, other current assets, property, plant and equipment, goodwill, other intangible assets, and other noncurrent assets. As part of this transaction, SemStream, L.P. also contributed certain of the liabilities of the SemStream Non-Residential Division to NGL Energy, including the derivative liabilities and capital leases. In return for this contribution, SemStream received $93 million of cash from NGL Energy (subject to post-closing adjustments), 8,932,031 common units representing limited partner interests in NGL Energy, and a 7.5% interest in the general partner of NGL Energy. Also as part of this transaction, SemStream agreed to waive its distribution rights on certain of the common units for a specified period of time.

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Unaudited Condensed Balance Sheets

(Dollars in thousands)

	June 30, 2011		December 31, 2010

*ASSETS*
Current assets:
Accounts receivable	$	37,382	$	81,555
Inventories		60,715		103,411
Derivative assets		9,273		4,367
Margin deposits		5,158		12,570
Other current assets		1,733		995


Total current assets		114,261		202,898


Property, plant and equipment (net of accumulated depreciation of $3,811 at June 30, 2011 and $2,342 at December 31, 2010)		47,306		48,028
Goodwill		50,071		50,071
Other intangible assets (net of accumulated amortization of $4,213 at June 30, 2011 and $3,077 at December 31, 2010)		12,787		13,923
Other assets		3,042		3,297


Total assets	$	227,467	$	318,217




*LIABILITIES AND NET PARENT EQUITY*
Current liabilities:
Accounts payable	$	38,191	$	73,530
Derivative liabilities		12,836		13,418
Other current liabilities		2,195		3,426


Total current liabilities		53,222		90,374


Other noncurrent liabilities		167		167
Commitments and contingencies (Note 3)
Net parent equity		174,078		227,676


Total liabilities and net parent equity	$	227,467	$	318,217

The accompanying notes are an integral part of these unaudited condensed financial statements.

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Unaudited Condensed Statements of Operations

(Dollars in thousands)

	Six Months Ended June 30, 2011			Six Months Ended June 30, 2010

Revenues, including revenues from affiliates (Note 5):
Product sales	$	359,809		$	343,326
Other		674			3,218


Total revenues		360,483			346,544
Expenses, including expenses from affiliates (Note 5):
Costs of products sold, exclusive of depreciation and amortization shown below		355,524			332,355
Operating		4,436			3,948
General and administrative		4,562			4,402
Depreciation and amortization		2,623			2,495


Total expenses		367,145			343,200


Operating income (loss)		(6,662	)		3,344
Other expenses (income):
Interest expense		1,364			1,778
Other expense (income), net		27			(2,422	)


Total other expenses (income), net		1,391			(644	)


Net income (loss)	$	(8,053	)	$	3,988

The accompanying notes are an integral part of these unaudited condensed financial statements.

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Unaudited Condensed Statements of Cash Flows

(Dollars in thousands)

	Six Months Ended June 30, 2011			Six Months Ended June 30, 2010

Cash flows from operating activities:
Net income (loss)	$	(8,053	)	$	3,988
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		2,623			2,495
Loss (gain) on disposal of long-lived assets		65			(34	)
Changes in assets and liabilities:
Decrease in accounts receivable		44,173			13,481
Decrease in inventory		42,696			70,689
Change in net derivative assets / liabilities		(5,488	)		(24,916	)
Decrease in margin deposits		7,412			23,067
Decrease (increase) in other assets		(483	)		6,853
Decrease in accounts payable		(35,302	)		(20,546	)
Decrease in payables to pre-petition creditors		(202	)		(10,059	)
Increase (decrease) in other liabilities		(817	)		2,370


Net cash provided by operating activities		46,624			67,388


Cash flows from investing activities:
Capital expenditures		(889	)		(3,320	)
Proceeds from sale of long-lived assets		22			687


Net cash used in investing activities		(867	)		(2,633	)


Cash flows from financing activities:
Change in book overdrafts		(212	)		(559	)
Net distributions to SemGroup		(45,545	)		(64,196	)


Net cash used in financing activities		(45,757	)		(64,755	)


Net change in cash and cash equivalents		—			—
Cash and cash equivalents at beginning of period		—			—


Cash and cash equivalents at end of period	$	—		$	—

The accompanying notes are an integral part of these unaudited condensed financial statements.

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SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements

1. OVERVIEW

Basis of presentation

As described in Note 6, on November 1, 2011, SemStream, L.P. contributed certain of its assets to NGL Energy Partners LP ("NGL Energy"). The contributed assets included SemStream, L.P.'s primary operating assets, excluding those of its residential operations. The accompanying financial statements of the SemStream Non-Residential Division reflect the historical activity of the operations that were contributed to NGL Energy. The SemStream Non-Residential Division will hereinafter be referred to as "SemStream".

The accompanying condensed financial statements are unaudited. The condensed balance sheet at December 31, 2010 is derived from audited financial statements.

These unaudited condensed financial statements as of June 30, 2011 and for the six months ended June 30, 2011 and 2010 have been prepared in accordance with accounting principles generally accepted in the United States and the rules and regulations of the Securities and Exchange Commission. These unaudited condensed financial statements include all normal and recurring adjustments that, in the opinion of management, are necessary to present fairly the financial position of SemStream and the results of its operations and its cash flows. We have evaluated subsequent events for accrual or disclosure in these unaudited condensed financial statements through November 3, 2011, which is the date these financial statements were issued.

Pursuant to the rules and regulations of the Securities and Exchange Commission, the accompanying financial statements do not include all of the information and notes normally included with financial statements prepared in accordance with accounting principles generally accepted in the United States. These unaudited condensed financial statements should be read in conjunction with the audited financial statements and notes thereto for the year ended December 31, 2010.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States requires management to make estimates and assumptions that affect the amounts and disclosures in the financial statements. Although management believes these estimates are reasonable, actual results could differ materially from these estimates. Due to the seasonal nature of SemStream's operations and other factors, the results of operations for the six months ended June 30, 2011 are not necessarily indicative of the results to be expected for the full year ending December 31, 2011.

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Table of Contents

SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements (Continued)

1. OVERVIEW (Continued)

Operations

SemStream's operations included the following:

•: twelve natural gas liquids terminals across the United States;
•: approximately 290,000 barrels of owned natural gas liquids storage capacity;
•: an additional 3.8 million barrels of leased natural gas liquids storage capacity; and
•: thirteen owned and over 350 leased railcars.

Bankruptcy

On July 22, 2008 SemGroup, L.P. and SemStream, L.P. filed petitions for reorganization under Chapter 11 of the U.S. Bankruptcy Code. While in bankruptcy, SemGroup, L.P. filed a Plan of Reorganization with the court, which was confirmed on October 28, 2009. The Plan of Reorganization determined, among other things, how pre-Petition Date obligations would be settled, the equity structure of the reorganized company upon emergence, and the financing arrangements upon emergence. SemGroup Corporation and SemStream, L.P. emerged from bankruptcy protection on November 30, 2009 (the "Emergence Date").

2. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK

During 2011 and 2010, SemStream managed commodity price risk by limiting its net open positions subject to outright price risk and basis risk resulting from grade, location or time differences. SemStream did so by selling and purchasing similar quantities of natural gas liquids with purchase and sale transactions for current or future delivery, by entering into future delivery and purchase obligations with futures contracts or other commodity derivatives and employing its storage and transportation assets. At times SemStream hedged its natural gas liquids commodity price exposure with derivatives on commodities other than natural gas liquids due to the limited size of the market for natural gas liquids derivatives. In addition, physical transaction sale and purchase strategies were intended to lock in positive margins for SemStream, e.g., the sales price was sufficient to cover purchase costs, any other fixed and variable costs and SemStream's profit. All marketing activities were subject to SemGroup's risk management policy, which established limits to manage risk and mitigate financial exposure.

During 2011 and 2010, SemStream's commodity derivatives were comprised of natural gas liquids swaps, forward contracts and futures contracts. These are defined as follows:

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Table of Contents

SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements (Continued)

2. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

The table below summarizes the balances of derivative assets and liabilities at June 30, 2011 and December 31, 2010 (in thousands):

	June 30, 2011															December 31, 2010

	Level 1			Level 2			Level 3			Netting			Total			Level 1			Level 2			Level 3			Netting		Total
Assets	$	14		$	2,132		$	7,359		$	(232	)	$	9,273		$	84		$	1,785		$	2,498		$	—	$	4,367
Liabilities		26			3,466			9,576			(232	)		12,836			2,123			6,631			4,664			—		13,418


Net liabilities at fair value	$	(12	)	$	(1,334	)	$	(2,217	)	$	—		$	(3,563	)	$	(2,039	)	$	(4,846	)	$	(2,166	)	$	—	$	(9,051	)

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Table of Contents

SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements (Continued)

2. FINANCIAL INSTRUMENTS AND CONCENTRATIONS OF RISK (Continued)

The following table reconciles changes in the fair value of commodity derivatives classified as Level 3 in the fair value hierarchy (in thousands):

	Six Months Ended June 30, 2011			Six Months Ended June 30, 2010

Beginning balance	$	(2,166	)	$	(23,656	)
Transfers out of Level 3(*)		(425	)		—
Total loss (realized and unrealized) included in product revenues		(785	)		(1,265	)
Settlements		1,159			25,585


Ending balance	$	(2,217	)	$	664




Amount of total loss included in earnings for the period attributable to the change in unrealized loss relating to assets and liabilities still held at the reporting date	$	(785	)	$	(1,265	)

(*): SemStream's policy is to recognize transfers in and transfers out as of the beginning of the reporting period.

The following table sets forth the notional quantities for derivative instruments entered into during the periods indicated (amounts in thousands of barrels):



Sales	8,401	3,332
Purchases	8,797	2,234

Realized and unrealized gains (losses) from SemStream's commodity derivatives were recorded to product revenue in the following amounts (in thousands):

		Six Months Ended June 30, 2011			Six Months Ended June 30, 2010

Commodity contracts		$	(4,333	)	$	8,341

3. COMMITMENTS AND CONTINGENCIES

Bankruptcy matters

(a): Confirmation order appeals

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Table of Contents

SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements (Continued)

3. COMMITMENTS AND CONTINGENCIES (Continued)

Reorganization. On November 4, 2009, Manchester filed a notice of appeal of the confirmation order. On December 4, 2009, Manchester's appeal was docketed in the United States District Court for the District of Delaware.

(b): Claims reconciliation process

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Table of Contents

SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements (Continued)

3. COMMITMENTS AND CONTINGENCIES (Continued)

this specified group of claims. If this were to become probable of occurring, SemGroup would be required to record a liability and a corresponding expense, and SemStream could be required to share in this expense.

Environmental

Asset retirement obligations

Other matters

Purchase and sale commitments

		Value

Floating price purchases	1,722	$	110,353
Floating price sales	789	$	51,273

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Table of Contents

SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements (Continued)

3. COMMITMENTS AND CONTINGENCIES (Continued)

SemStream has also entered into an agreement under which it is obligated to purchase all of the propane produced by a third-party refinery at a price that floats based on market rates. Under this agreement, which expires March 31, 2012, SemStream purchased 8.8 million gallons of propane during the six months ended June 30, 2011 for a total price of $13.2 million.

SemStream has also entered into a long term marketing agreement to market all natural gas liquids produced by a third party's natural gas processing plants. The agreement expires March 31, 2022. SemStream marketed 26.9 million gallons of natural gas liquids at a purchase cost of $41.8 million during the six months ended June 30, 2011 pursuant to this agreement.

4. NET PARENT EQUITY

The following table shows the changes in SemStream's net parent equity from December 31, 2010 to June 30, 2011 (in thousands):


Balance at December 31, 2010	$	227,676
Net loss		(8,053	)
Net distributions to SemGroup		(45,545	)


Balance at June 30, 2011	$	174,078

5. TRANSACTIONS WITH SEMGROUP

Intercompany Accounts

SemStream participated in SemGroup's cash management program. Under this program, cash SemStream received from customers was transferred to SemGroup on a regular basis; when SemStream remitted payments to suppliers, SemGroup transferred cash to SemStream to cover the payments. In addition, SemGroup incurred certain expenses on SemStream's behalf that are reported within SemStream's statements of operations.

SemStream's intercompany accounts were in a net receivable position of $59.1 million at June 30, 2011 and $13.5 million at December 31, 2010. SemStream has reported these balances as a reduction to equity on the balance sheet, as SemStream does not expect to collect these intercompany receivables.

Direct employee expenses

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Table of Contents

SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements (Continued)

5. TRANSACTIONS WITH SEMGROUP (Continued)

employee costs. These expenses were recorded to operating expenses and general and administrative expenses in SemStream's statements of operations.

Allocated expenses

SemGroup charged SemStream $2.4 million during the six months ended June 30, 2011 and $2.9 million during the six months ended June 30, 2010 for such allocated costs. These expenses were recorded to general and administrative expenses in SemStream's statements of operations.

SemGroup credit facilities

SemStream utilized letters of credit under SemGroup's credit facilities. At June 30, 2011, SemStream had outstanding letters of credit of $46.1 million. The statements of operations include direct charges from SemGroup for letter of credit usage, which is reported within interest expense.

Subsequent to the contribution of the SemStream assets to NGL Energy on November 1, 2011, these assets no longer serve as collateral under SemGroup's credit agreements.

Product purchases and sales

SemStream routinely entered into purchase and sale transactions with other controlled subsidiaries of SemGroup, including the following:

•: The sale of condensate and natural gasoline to SemCrude, L.P.;
•: The sale of condensate and natural gasoline to SemCanada Crude Company;
•: The sale of propane to the residential division of SemStream, L.P.; and
•: The purchase of natural gas liquids from SemGas, L.P.

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Table of Contents

SemStream Non-Residential Division

Notes to Unaudited Condensed Financial Statements (Continued)

5. TRANSACTIONS WITH SEMGROUP (Continued)

The following table summarizes these transactions (amounts in thousands):

	Six Months Ended June 30, 2011		Six Months Ended June 30, 2010

Revenues from SemCrude, L.P.(*)	$	29,523	$	15,350
Revenues from SemCanada Crude Company	$	—	$	9,350
Revenues from SemStream, L.P. residential division	$	6,071	$	4,267
Purchases from SemGas, L.P.	$	15,313	$	10,898

(*): Certain of the purchases from SemCrude, L.P. were fixed-price forward purchases, which were recorded at fair value at each balance sheet date. The revenue amounts in this table include any unrealized gains and losses on these contracts.

6. CONTRIBUTION OF ASSETS AND LIABILITIES TO NGL ENERGY

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Table of Contents

REPORT OF INDEPENDENT CERTIFIED PUBLIC ACCOUNTANTS

To the Partners of
NGL Energy Partners LP:

We have audited the accompanying combined balance sheets of the Businesses of Osterman Associated Companies Contributed to NGL Energy Partners LP (taken as a whole the "Company") as of September 30, 2011 and 2010 and the related combined statements of operations and changes in equity of the combined companies and cash flows for the years ended September 30, 2011, 2010 and 2009. These combined financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these combined financial statements based on our audit.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America established by the American Institute of Certified Public Accountants. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the combined financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined financial statements referred to above present fairly, in all material aspects, the combined financial position of the Businesses of Osterman Associated Companies Contributed to NGL Energy Partners LP as of September 30, 2011 and 2010 and the combined results of their operations and their cash flows for the years ended September 30, 2011, 2010 and 2009 in conformity with accounting principles generally accepted in the United States of America.

/s/ Graham Shepherd, PC
Worcester, Massachusetts
November 14, 2012

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Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Combined Balance Sheets

September 30, 2011 and 2010

(U.S. Dollars in Thousands)

	2011		2010

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	21,908	$	13,416
Accounts receivable, net of allowance for doubtful accounts of $650 and $550, respectively		6,295		5,305
Accounts receivable from stockholders and other related parties		5,931		4,064
Inventories		3,771		2,824
Prepaid expenses		1,045		1,324
Deferred income taxes		266		80
Other current assets		101		101


Total current assets		39,317		27,114
PROPERTY, PLANT AND EQUIPMENT, net of accumulated depreciation of $41,899 and $38,517, respectively		17,635		18,729
GOODWILL		380		380
INTANGIBLE ASSETS, net of accumulated amortization of $3,045 and $2,616, respectively		3,436		3,865
OTHER NON-CURRENT ASSETS		233		235


Total assets	$	61,001	$	50,323




LIABILITIES AND NET EQUITY OF COMBINED COMPANIES
CURRENT LIABILITIES:
Trade accounts payable	$	2,615	$	3,258
Income taxes payable		542		301
Accrued expenses and other payables		1,897		1,398
Customer deposits		4,033		3,701
Current maturities of long-term debt		—		385
Due to stockholders		6		5


Total current liabilities		9,093		9,048
LONG-TERM LIABILITIES:
Long-term debt, net of current maturities		—		2,312
Payable to related parties		755		681
Deferred income taxes		592		414
COMMITMENTS AND CONTINGENCIES
NET EQUITY OF COMBINED COMPANIES		50,561		37,868


Total liabilities and net equity of combined companies	$	61,001	$	50,323

The accompanying notes are an integral part of these combined financial statements.

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Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Combined Statements of Operations and Changes in Equity of Combined Companies

For the Years Ended September 30, 2011, 2010 and 2009

(U.S. Dollars in Thousands)

	2011			2010			2009

REVENUES:
Propane sales	$	105,592		$	87,678		$	82,877
Sales of parts and appliances		5,385			2,924			3,098
Other operating revenues		1,041			1,108			909


Total Revenues		112,018			91,710			86,884
COST OF SALES		69,753			52,993			43,792


Gross Margin		42,265			38,717			43,092
OPERATING COSTS AND EXPENSES:
Operating and general and administrative		23,341			21,801			22,368
Depreciation and amortization		3,811			3,871			3,687


Operating Income		15,113			13,045			17,037
OTHER INCOME (EXPENSE):
Interest expense		(62	)		(211	)		(341	)
Interest income		231			114			191
Other, net		1,334			38			211


INCOME BEFORE INCOME TAXES		16,616			12,986			17,098
PROVISION FOR INCOME TAXES		563			733			736


Net Income	$	16,053		$	12,253		$	16,362
Net equity of combined companies, beginning of period		37,868			30,042			19,077
Contributions		579			1,387			97
Distributions		(3,939	)		(5,814	)		(5,494	)


Net equity of combined companies, end of period	$	50,561		$	37,868		$	30,042

The accompanying notes are an integral part of these combined financial statements.

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Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Combined Statements of Cash Flows

For the Years Ended September 30, 2011, 2010 and 2009

(U.S. Dollars in Thousands)

	2011			2010			2009

OPERATING ACTIVITIES:
Net income	$	16,053		$	12,253		$	16,362
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		3,811			3,871			3,687
Deferred income tax (benefit) provision		(8	)		75			(22	)
(Gain) loss on sale of assets		(1,141	)		—			(119	)
Changes in operating assets and liabilities—
Accounts receivable		(990	)		(863	)		2,475
Inventories		(947	)		(663	)		1,390
Prepaid expenses and other current assets		279			(707	)		(51	)
Accounts payable		(643	)		422			(1,496	)
Accrued expenses and other payables		499			(14	)		254
Income taxes payable		241			(399	)		549
Customer deposits		332			503			(1,327	)


Net cash provided by operating activities		17,486			14,478			21,702


INVESTING ACTIVITIES :
Purchases of long-lived assets		(2,537	)		(3,841	)		(6,542	)
Proceeds from sales of assets		1,390			—			164
Net (advances to) repayments from related parties		2			(35	)		—
Other		—			—			(100	)


Net cash used in investing activities		(1,145	)		(3,876	)		(6,478	)


FINANCING ACTIVITIES:
Proceeds from long-term debt		—			—			1,978
Payments on long-term debt		(2,697	)		(2,166	)		(2,164	)
Net (advances to) repayments from stockholders and related parties		(1,792	)		(6,567	)		1,756
Contributions from stockholders		579			1,387			97
Distributions		(3,939	)		(5,814	)		(5,494	)


Net cash used in financing activities		(7,849	)		(13,160	)		(3,827	)


Net change in cash and cash equivalents		8,492			(2,558	)		11,397	��
Cash and cash equivalents, beginning of period		13,416			15,974			4,577


Cash and cash equivalents, end of period	$	21,908		$	13,416		$	15,974

The accompanying notes are an integral part of these combined financial statements.

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Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements

For the Years Ended September 30, 2011, 2010 and 2009

Note 1—Nature of Operations and Organization

The accompanying combined financial statements represent the financial statements of the Osterman Associated Companies (collectively, "the Company"), consisting of the following individual entities which are related through common control and ownership:

E. Osterman Gas Service, Inc.—An S Corporation formed in 1968.

Milford Propane, Inc.—An S Corporation formed in 1974 to acquire the assets of Milford Bottled Gas and expand market operations in Southeastern Massachusetts.

Saveway Propane Gas Service, Inc.—A C corporation formed in 1987 to market retail propane and appliance sales and service to the Eastern Connecticut area.

E. Osterman, Inc.—An S Corporation formed in 1988 to expand wholesale propane sales and propane transportation services.

Osterman Propane, Inc.—An S Corporation formed in 1993 to acquire the assets of Agway Petroleum Corporation and expand market operations in Western Massachusetts.

Osterman Associated Companies, Inc.—A C corporation formed in 1999 solely to protect the legal name "Osterman Associated Companies".

Propane Gas, Inc.—A C corporation acquired in 2007 by Propane Gas, LLC (a disregarded entity for tax purposes) to expand market operations in the Cape Cod area.

E. Osterman Propane, Inc.—An S Corporation formed in 2008 to expand market operations in Connecticut.

A O Energy, Inc.—An S Corporation formed in 1992 to sell liquid propane gas to large commercial accounts.

Osterman Propane Storage Limited Partnership—A limited partnership formed in 2001 to own and rent propane storage facilities for Osterman Associated Companies.

VE Properties III, LLC—A limited partnership and corporation formed in 1995, reorganized as a limited liability company in 2009, to own and operate rental real estate in Northbridge and Chester, MA.

VE Properties V, LLC—A limited liability company formed in 2009 to own and operate rental real estate in Chesterfield, NH.

VE Properties VI, LLC—A limited liability company formed in 2009 to own and operate rental real estate in Palmer, Sterling and Southbridge, MA.

The Company operates primarily in the retail propane business throughout New England and New York.

On October 3, 2011, the Company closed an agreement to contribute substantially all of its assets to NGL Energy Partners LP ("NGL Energy") in exchange for $96.0 million and 4 million common units of NGL Energy (see Note 14). The agreement contemplated a post-closing working capital payment of $4.8 million for certain working capital items.

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Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies

Basis of Presentation

The accompanying combined financial statements are prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All significant intercompany transactions have been eliminated in preparing these combined financial statements.

Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience and various other assumptions that they believe to be reasonable under the circumstances.

Critical estimates made in the preparation of these combined financial statements include the collectability of accounts receivable; the recoverability of inventories; useful lives and recoverability of property, plant and equipment and amortized intangible assets; the impairment of goodwill; accruals for various commitments and contingencies; allocations of corporate level expenses; and provision for income taxes, among others. Although management believes these estimates are reasonable, actual results could differ from the estimates.

Fair Value Measurements

The Company applies fair value measurements to certain assets and liabilities, principally assets and liabilities acquired in a business combination. Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly transaction between market participants at the measurement date. Fair value should be based upon assumptions that market participants would use when pricing an asset or liability, including assumptions about risk and risks inherent in valuation techniques and inputs to valuations. This includes not only the credit standing of counterparties and credit enhancements but also the impact of the Company's own nonperformance risk on its liabilities. Fair value measurements assume that the transaction occurs in the principal market for the asset or liability or in the absence of a principal market, the most advantageous market for the asset or liability (the market for which the reporting entity would be able to maximize the amount received or minimize the amount paid).

Management uses the following fair value hierarchy, which prioritizes the inputs to valuation techniques used to measure fair value into three broad levels:

•: Level 1—Quoted prices (unadjusted) in active markets for identical assets and liabilities that the Company has the ability to access at the measurement date.
•: Level 2—Inputs other than quoted prices included within Level 1 that are either directly or indirectly observable for the asset or liability, including quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in inactive markets, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived from observable market data by correlation or other means.

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Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies (Continued)

•: Level 3—Unobservable inputs for the asset or liability including situations where there is little, if any, market activity for the asset or liability. The Company did not have any assets or liabilities measured at fair value categorized as Level 3 at September 30, 2011 or 2010.

The fair value hierarchy gives the highest priority to quoted prices in active markets (Level 1) and the lowest priority to unobservable data (Level 3). In some cases, the inputs to measure fair value might fall into different levels of the fair value hierarchy. The lowest level input that is significant to a fair value measurement in its entirety determines the applicable level in the fair value hierarchy. Assessing the significance of a particular input to the fair value measurement in its entirety requires judgment, considering factors specific to the asset or liability.

Revenue Recognition

The Company's revenue is primarily generated by the sale of propane, propane-related appliances, parts and fittings, rental of equipment and by services provided to its customers in the northeastern United States.

The Company accrues revenues from propane and propane-related sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser or installation of the appliance. The Company records service revenues at the time the service is performed and tank and other rentals over the term of the lease. The Company records product purchases at the time title to the product transfers to the Company, which typically occurs upon receipt of the product. Revenue-related taxes collected from customers and remitted to taxing authorities, principally sales and use taxes, are presented on a net basis.

Cost of Sales

"Cost of Sales" includes all costs incurred to acquire propane, including the costs of purchasing, terminalling, and storing inventory prior to delivery to the customer, as well as any costs related to the sale of propane appliances and equipment. Cost of sales does not include any depreciation or amortization of property, plant and equipment or intangible assets. Depreciation and amortization is separately classified in the combined statements of operations.

Operating and General and Administrative Expenses

"Operating and General and Administrative Expenses" include costs of personnel, vehicles, delivery, handling, plants, district offices, selling, marketing, credit and collections and other functions related to the retail distribution of propane and related equipment and supplies and the direct and allocated expenses of personnel, executives, corporate office locations and other functions related to centralized corporate and overhead activities.

Advertising Costs

The Company expenses advertising costs as incurred. The total advertising expense for the years ended September 30, 2011, 2010 and 2009 was approximately $367,000, $437,000 and $375,000, respectively.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies (Continued)

Cash and Cash Equivalents

The Company considers all highly liquid investments with a maturity of three months or less at acquisition date as cash equivalents.

In the ordinary course of business, the Company has, at various times, cash deposits with a bank which are in excess of federally insured limits. Management believes that the possibility of any loss is minimal.

Supplemental cash flow information:

	2011		2010		2009

	(in thousands)
Interest paid	$	62	$	107	$	184




Income taxes paid	$	148	$	1,742	$	248

Accounts Receivable and Concentration of Credit Risk

The Company grants credit to customers for the purchase of propane and propane-related products. Accounts receivable are uncollateralized customer obligations due under normal trade terms. Accounts receivable are stated at the amount billed to the customer plus any accrued and unpaid interest on unpaid and past due accounts receivable. Interest charges during the periods presented were not material.

The carrying amount of accounts receivable is reduced by a valuation allowance that reflects management's best estimate of the uncollectible amounts. Management individually reviews past due accounts receivable balances and provides a specific reserve based on an assessment of current customer creditworthiness. Management also provides a general allowance amount for accounts not currently delinquent.

Changes in the allowance for doubtful accounts during the periods indicated are as follows:

	2011			2010			2009

	(in thousands)
Allowance for doubtful accounts, beginning of period	$	550		$	500		$	500
Bad debt provision		755			274			596
Write off of uncollectible accounts, net of recoveries		(655	)		(224	)		(596	)


Allowance for doubtful accounts, end of period	$	650		$	550		$	500

For the years ended September 30, 2011, 2010 and 2009, no individual customer accounted for more than 10% of the Company's combined revenues.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies (Continued)

Accounts Receivable From (Due to) Stockholders and Other Related Parties

The current receivables from (due to) the Company's stockholders and other related parties are unsecured and have no stated repayment terms but are due on demand.

Inventories

The Company's inventories consist primarily of propane, valued at cost determined using the average cost method. Cost includes the cost of transportation and storage. Parts and supplies inventories are carried at the lower of cost or market, with cost determined using the average cost method.

Inventories consisted of the following:

	2011		2010

	(in thousands)
Propane	$	2,966	$	2,024
Parts, appliances and other		805		800

			��
Total	$	3,771	$	2,824

Property, Plant and Equipment, Depreciation and Impairments

Property, plant and equipment are stated at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. When the Company disposes of assets, the cost and related accumulated depreciation are removed from the accounts and any resulting gain or loss is included in other income. Depreciation expense is computed primarily using the straight-line method over the useful lives (see Note 5).

The Company evaluates the carrying value of its long-lived assets for potential impairment when events and circumstances warrant such a review. A long-lived asset is considered impaired when the anticipated undiscounted future cash flows from a logical grouping of assets is less than its carrying value. In that event, a loss is recognized equal to the amount by which the carrying value exceeds the fair value of the assets. No impairments of long-lived assets were recorded for the years ended September 30, 2011, 2010 and 2009.

Intangible Assets

The Company's identifiable intangible assets consist primarily of customer lists and covenants not to compete acquired in business combinations. The Company capitalizes acquired intangible assets if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of an intent to do so.

Intangible assets with estimable useful lives are amortized over their respective useful lives on a straight-line basis to their estimated residual values, and reviewed for impairment annually (see Note 6).

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies (Continued)

Goodwill

Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Changes to recorded goodwill during the three year period ended September 30, 2011 were as follows:

	2011		2010		2009

	(in thousands)
Balance, beginning of period	$	380	$	380	$	300
Acquisitions of retail propane businesses		—		—		80


Balance, end of period	$	380	$	380	$	380

The Company evaluates goodwill for impairment annually or when events or circumstances occur indicating that goodwill might be impaired. The Company performs this impairment testing at year end.

The annual impairment assessment of goodwill is a two-step process:

•: In step 1 of the goodwill impairment test, the Company compares the fair value of the reporting unit with its carrying amount, including goodwill. If the fair value of a reporting unit exceeds its carrying amount, goodwill of the reporting unit is not considered impaired. If the carrying amount of a reporting unit exceeds its fair value, the Company performs the second step of the goodwill impairment test to measure the amount of impairment loss, if any.
•: In step 2 of the goodwill impairment test, the Company compares the implied fair value of reporting unit goodwill with the carrying amount of that goodwill. If the carrying amount of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in an amount equal to that excess.

The Company utilizes the market approach in determining the fair value of the reporting unit. The market approach considers forecasted discounted future cash flows and a terminal value which applies a market multiple to adjusted cash flows. Based upon this analysis, the Company concluded that the fair value of the reporting unit exceeded its carrying value and therefore step 2 of goodwill impairment testing was not required for any of the periods presented.

Estimates and assumptions used to perform the impairment testing are inherently uncertain and can significantly affect the outcome of the impairment test. The estimates and assumptions the Company used in the annual assessment for impairment of goodwill included market participant considerations and future forecasted operating results. Changes in operating results and other assumptions could materially affect these estimates.

Asset Retirement Obligations

The Company records the fair value of an asset retirement obligation as a liability in the period a legal obligation for the retirement of tangible long-lived assets is incurred, typically at the time the assets are placed into service if the Company can reasonably estimate such retirement obligations. A corresponding asset is also recorded and depreciated over the life of the asset. After the initial

F-253

Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 2—Summary of Significant Accounting Policies (Continued)

measurement, the Company also recognizes changes in the amount of the liability resulting from the passage of time and revisions to either the timing or amount of estimated cash flows.

The Company has determined that it is obligated by contractual requirements to remove facilities or perform other remediation upon retirement of certain assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including expected settlement dates, future retirement costs, future inflation rates and the credit-adjusted risk-free interest rates. However, the Company is not able to reasonably measure the fair value of the asset retirement obligations as of September 30, 2011, 2010 or 2009 because the settlement dates were indeterminable. An asset retirement obligation will be recorded in the periods the Company can reasonably determine the settlement dates.

Income Taxes

Certain of the companies included in these combined financial statements are S corporations or limited liability companies whose earnings or losses for federal and state income tax purposes are included in the tax returns of the individual owners. For those entities, net earnings for financial statement purposes may differ significantly from taxable income reportable to such owners as a result of differences between the tax basis and financial reporting basis of assets and liabilities. The Company pays income taxes to certain states as required by the tax code of the respective states.

Those combined companies which are taxable ("C") corporations follow the asset and liability method of accounting for income taxes, under which deferred income taxes are recorded based upon differences between the financial reporting and tax basis of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled (see Note 8).

On October 1, 2009 the Company adopted the provision for the accounting for uncertainty in income tax positions. The Company is required to recognize in its financial statements the impact of the tax position if it is more likely than not the position will not be sustained on audit based on the technical merits of the position.

The Company files federal, Massachusetts, Connecticut, Rhode Island, New Hampshire, New York, Maine and Vermont income tax returns. The income tax returns for tax years 2009 and beyond remain subject to examination by the Internal Revenue Service and the Department of Revenue for all states in which the Company files.

The Company did not have unrecognized tax benefits as of September 30, 2011 and does not expect this to change significantly over the next 12 months. The Company will recognize interest and penalties accrued on any unrecognized tax benefits as a component of income tax expense.

Customer Deposits

The Company records customer advances and deposits on product purchases as a liability in the combined balance sheets.

F-254

Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 3—Recent Accounting Standards

In September 2011, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update No. 2011-08. Intangibles—Goodwill and Other (Topic 350): Testing Goodwill for Impairment ("ASU 2011-08"), which simplifies how entities test goodwill for impairment. ASU 2011-08 gives entities the option, under certain circumstances, to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether further impairment testing is necessary. ASU 2011-08 is effective for fiscal years beginning after December 15, 2011, and early adoption is permitted. The Company does not expect that the adoption of this standard will materially impact its financial position or results of operations.

During 2009, the Company adopted the updated GAAP rules for subsequent events. Under this update, management is required to evaluate subsequent events through the date that the combined financial statements are available to be issued and to disclose the date through which subsequent events are evaluated. The adoption of this standard does not change the Company's practices with respect to evaluating, recording, and disclosing subsequent events; therefore, adoption of this update had no impact on the Company's combined balance sheets or statements of results of operations.

Note 4—Acquisitions of Businesses

On October 6, 2008 the Company entered into an agreement to purchase the assets of Wesco Propane, Inc. as detailed below. The acquisition was accomplished through the use of the Company's line of credit and internally generated funds.

On September 1, 2009, the Company entered into an agreement to purchase the assets of Mack Bros., Inc. located in Readsboro, Vermont, as detailed below. The acquisition was accomplished through the use of internally generated funds.

The fair values of the assets acquired in these acquisitions are as follows (in thousands):

	2009

	Wesco		Mack Bros.
	(in thousands)
Accounts receivable	$	52	$	—
Inventory		—		5
Tanks and other equipment		450		190
Transportation equipment		85		30
Computer and office equipment		20		2
Customer lists		1,560		83
Non-compete agreement		—		200
Goodwill		—		80


	$	2,167	$	590

The Company included the results of operations in its financial statements beginning on the acquisition closing date. The pro forma impact of these acquisitions is not presented as such impact is not material.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 5—Property, Plant and Equipment

Property, plant and equipment consist of the following:

	Estimated Useful Lives (Years)	2011		2010

		(in thousands)
Retail propane equipment and tanks	5 - 20	$	37,200	$	35,752
Vehicles	5 - 7		14,845		14,322
Buildings and improvements	15 - 40		4,614		4,047
Land	N/A		2,216		2,466
Other	5 - 7		659		659


			59,534		57,246
Less: Accumulated depreciation			41,899		38,517


Net property, plant and equipment		$	17,635	$	18,729

Depreciation expense was as follows for the periods indicated:

2011		2010		2009

(in thousands)
$	3,382	$	3,442	$	3,298

Note 6—Intangible Assets

Intangible assets (all amortizable) consist of the following:

	Estimated Useful Lives (Years)	2011		2010

		(in thousands)
Customer lists	15	$	6,313	$	6,313
Non-compete agreements	5		168		168


Total intangible assets			6,481		6,481
Less: Accumulated amortization			3,045		2,616


Net intangible assets		$	3,436	$	3,865

Amortization expense was approximately $429,000, $429,000 and $389,000 for the years ended September 30, 2011, 2010 and 2009, respectively.

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THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 6—Intangible Assets (Continued)

Future amortization expense is estimated as follows (in thousands):


2012	$	429
2013		429
2014		414
2015		370
2016		349
Thereafter		1,445


	$	3,436

Note 7—Long-Term Debt

The Company's long-term debt consists of the following:

	2011		2010

	(in thousands)
Line of credit agreement with bank	$	—	$	2,697
Revolving credit facility with bank		—		—


		—		2,697
Less—current maturities		—		385


Long-term debt	$	—	$	2,312



					��

The line of credit agreement provides that the Company may borrow on a revolving basis until April 30, 2012 up to $11 million for acquisitions and asset purchases based upon an annual calculation. Interest is payable monthly in arrears. The Company has agreed to pay minimally the outstanding principal as of August 1st in each year in monthly installments equal to¹/84th of the outstanding principal balance. At September 30, 2011 and 2010 the monthly principal payments due were approximately $0 and $32,000, respectively. The Company has the right to select an interest rate based on the Bank's Prime Rate or the LIBOR 1-month index rate plus 190 basis points. In addition, an Unused Facility Fee of 0.25% per annum is charged quarterly on the average daily-undisbursed amount of the line of credit. The line of credit contains certain loan covenants and the Company was in compliance with all loan covenants at September 30, 2011 and 2010. The interest rates at September 16, 2011 and September 30, 2010 were 2.08% and 2.16%, respectively.

Long-term debt is secured by substantially all of the assets of the Company with recourse limited to real estate. The total borrowings of the revolving note agreement and the line of credit agreement may not exceed $18 million in the aggregate. The line of credit was paid in full on August 17, 2011 and terminated on September 16, 2011.

In addition, the Company has long-term debt payable to a related party of $755,000 and $681,000 at September 30, 2011 and 2010, respectively. This consists primarily of loans for which there are no established payment terms and which the Company believes will not require payment during the next 12 months.

F-257

Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 8—Income Taxes

The Company's provision for income taxes consists of the following:

	2011			2010		2009

	(in thousands)
Current:
Federal	$	20		$	8	$	75
State		551			650		682
Deferred:
Federal		(17	)		49		(56	)
State		9			26		35


	$	563		$	733	$	736

The Company's effective income tax rate differs from the Federal statutory rate of 35% due to the taxable income of the tax pass through entities (S corporations, limited partnerships and limited liability companies) and the effect of state income taxes.

The Company's Subchapter S corporations pay a portion of state corporate income tax to certain states as dictated by the tax code of the respective states. The aggregate amount of state corporate income tax expense based on these calculations is approximately $551,000, $633,000 and $667,000 for the years ended September 30, 2011, 2010 and 2009 respectively.

Net deferred tax liabilities represent the tax effects of taxable and deductible temporary differences between financial and income tax reporting. The taxable temporary differences consist primarily of net property and equipment values, net intangible asset values and net operating losses.

The net deferred tax liability consists of the following:

	2011			2010

	(in thousands)
Deferred tax assets related to:
Accounts receivable
State	$	29			25
Net operating loss carryovers
Federal		234			270
State		3			2
Deferred state tax
Federal		25			30
Deferred tax liabilities related to:
Property and equipment, net
Federal		(134	)		(178	)
State		(290	)		(272	)
Intangible assets, net
Federal		(151	)		(165	)
State		(42	)		(46	)


Net liability	$	(326	)	$	(334	)

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Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 8—Income Taxes (Continued)

The amounts are presented in the Company's combined balance sheets as follows:

	2011		2010

	(in thousands)
Deferred tax assets—current
Federal	$	234	$	54
State		32		26


	$	266	$	80




Deferred tax liabilities—non-current
Federal	$	260	$	97
State		332		317


	$	592	$	414

Note 9—Commitments and Contingencies

Environmental Matters

The Company's operations are subject to extensive Federal, state and local environmental laws and regulations that could require expenditures for remediation of operating facilities. Although management believes the Company's operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the propane distribution, terminal and storage business, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations or prior operations, could result in substantial costs and liabilities. Accordingly, the Company has adopted policies, practices and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability which could result from such events. However, some risk of environmental or other damage is inherent in the Company's business.

Litigation

The Company is involved in claims and legal actions arising in the ordinary course of business. Management believes that the ultimate disposition of these matters will not have a material adverse effect on the Company's financial position and results of operations.

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Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 10—Net Equity of Combined Companies

Net equity of the combined companies on the combined balance sheets includes the common stock of the combined entities. The legal capital of each such entity is as follows at September 30, 2011 and 2010:

	Par or Stated Value

	(in thousands)
E. Osterman Gas Service, Inc.
Common stock, no par value, 100 shares authorized, issued and outstanding.	$	1
Milford Propane, Inc.
Common stock, no par value, 100 shares authorized, issued and outstanding.		4
Saveway Propane Gas Service, Inc.
Common stock, no par value, 5,000 shares authorized, issued and outstanding.		2
E Osterman, Inc.
Common stock, no par value, 100 shares voting and 900 shares nonvoting authorized, issued and outstanding.		1
Osterman Propane, Inc.
Common stock, no par value, 5,000 shares authorized, 100 shares issued and outstanding.		1
A O Energy, Inc.
Common stock, no par value, 200,000 shares authorized, 100 shares issued and outstanding.		10
Osterman Propane Storage, Inc.
Common stock, no par value, 200,000 shares authorized, 1,000 shares issued and outstanding.		1
Osterman Associated Companies, Inc.
Common stock, no par value, 1,000 shares authorized, 100 shares issued and outstanding.		—
Propane Gas, Inc.
Common stock, no par value, 20,000 shares authorized, 12,000 shares issued and outstanding.		—
E Osterman Propane, Inc.
Common stock, no par value, 100 shares authorized, issued and outstanding.		—


Total common stock	$	20

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Table of Contents

THE BUSINESSES OF THE OSTERMAN ASSOCIATED COMPANIES
CONTRIBUTED TO NGL ENERGY PARTNERS LP

Notes to Combined Financial Statements (Continued)

For the Years Ended September 30, 2011, 2010 and 2009

Note 11—Fair Value of Financial Instruments

For cash and cash equivalents, accounts receivable, accounts payable, accrued expenses and other payables, the carrying value is a reasonable estimate of fair value, primarily because of the short-term nature of the instruments (considered to be Level 1). The Company has no assets or liabilities that are required to be recorded on the basis of fair value at September 30, 2011 or 2010.

Note 12—Employee Benefits

The Company has a qualified deferred compensation plan, 401(k) and profit sharing plan, which covers substantially all employees who are at least twenty-one years of age and have completed three months of service. The plan is administered by an independent third party. The Company provides profit sharing at 3.0% of employees' salaries and matches 50% of employee contributions up to a maximum of 6% of participants' compensation. These benefits may be altered at the discretion of the Board of Directors. The Company's contributions to the plan were approximately $430,000, $484,000, and $430,000 for the years ended September 30, 2011, 2010 and 2009, respectively.

Note 13—Concentration of Suppliers

The Company purchased propane from multiple suppliers. The four major suppliers collectively represented the following total percentage of purchases for the indicated periods.

2011			2010			2009

	86	%		76	%		80	%

Management does not believe that this represents a significant concentration risk in that, if necessary, purchases could be made from other suppliers at comparable terms.

Note 14—Subsequent Events

Management has evaluated subsequent events through November 14, 2012, the date the combined financial statements were available to be issued.

As discussed in Note 1, on October 3, 2011 the Company concluded an agreement to contribute substantially all of the Company's assets to NGL Energy. Associated with this contribution, the Company has reorganized to consolidate the remaining assets and those liabilities not assumed by NGL Energy consisting primarily of all receivables and payables with stockholders and other related parties and all income tax assets and liabilities.

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Table of Contents

INDEPENDENT AUDITORS' REPORT

Members and Stockholders
Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC,
Blackhawk Gathering, Toro Operating Company, Inc., and
Striker Oilfield Services, LLC
Austin, Texas

We have audited the accompanying combined balance sheets of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, Toro Operating Company, Inc., and Striker Oilfield Services, LLC (the "Companies") as of December 31, 2011 and 2010, and the related combined statements of income, changes in members' and stockholders' equity, and cash flows for each of the three years ended December 31, 2011, 2010, and 2009. These combined financial statements are the responsibility of the Companies' management. Our responsibility is to express an opinion on these combined financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the combined financial statements are free of material misstatement. An audit includes consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Companies' internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the combined financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall combined financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the financial position of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, Toro Operating Company, Inc., and Striker Oilfield Services, LLC at December 31, 2011 and 2010, and the results of their operations and their cash flows for each of the three years ended December 31, 2011, 2010, and 2009, in conformity with accounting principles generally accepted in the United States of America.

/s/ EKS&H, LLLP

January 14, 2013
Denver, Colorado

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Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Combined Balance Sheets

	December 31,

	2011			2010
Assets
Current assets
Cash and cash equivalents	$	9,906,016		$	1,042,956
Accounts receivable		51,860,802			30,210,911
Inventory		1,348,826			799,619
Due from related parties		85,805			38,296
Prepaid expenses and other current assets		401,727			104,919


Total current assets		63,603,176			32,196,701


Non-current assets
Property, plant, and equipment, net of accumulated depreciation of $4,908,488 and $2,807,540 at December 31, 2011 and 2010, respectively		16,083,842			4,361,964
Land		230,253			277,656
Deposits—related party		250,000			250,000
Deposits		9,434			5,329


Total non-current assets		16,573,529			4,894,949


Total assets	$	80,176,705		$	37,091,650




Liabilities and Members' and Stockholders' Equity
Current liabilities
Line-of-credit	$	6,000,000		$	3,200,091
Accounts payable—crude oil purchases		32,974,766			15,953,689
Accounts payable		832,660			1,373,986
Accrued expenses		2,895,742			1,049,605
Due to related parties		12,000			30,348
Notes payable—current portion		4,861,915			1,246,460
Distributions payable		2,008,113			—


Total current liabilities		49,585,196			22,854,179


Non-current liabilities
Notes payable, less current portion		7,563,434			1,188,161


Total liabilities		57,148,630			24,042,340


Commitments and contingencies (Note 7)
Members' and stockholders' equity
Common stock, 30,000 shares authorized, 15,594 shares outstanding, par value $0.10		1,559			1,559
Additional paid-in capital		582,822			582,822
Retained earnings (accumulated deficit)		82,037			(76,155	)
Note receivable—member		(73,609	)		(140,156	)
Members' equity		22,435,266			12,681,240


Total members' and stockholders' equity		23,028,075			13,049,310


Total liabilities and members' and stockholders' equity	$	80,176,705		$	37,091,650

See notes to combined financial statements.

F-263

Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Combined Statements of Income

	Year Ended December 31,

	2011			2010			2009
Revenue
Crude oil sales	$	483,106,890		$	269,442,521		$	152,515,550
Crude oil hauling		14,834,234			263,911			—


Total revenue		497,941,124			269,706,432			152,515,550


Product expenses		471,703,255			257,064,193			143,344,684


Operating expenses
Transportation expenses		3,308,633			2,157,004			1,548,502
Personnel expenses		4,173,651			2,749,365			2,438,043
Equipment and facilities' expenses		1,144,538			620,648			579,830
General and administrative expenses		1,866,536			1,155,757			1,361,973
Depreciation		2,100,948			931,547			807,415


Total operating expenses		12,594,306			7,614,321			6,735,763


Other (expense) income
Interest expense		(643,300	)		(386,487	)		(325,505	)
Interest income		2,195			7,670			7,862
Gain on sale of assets		—			149,981			73,223


Total other expense, net		(641,105	)		(228,836	)		(244,420	)


Net income	$	13,002,458		$	4,799,082		$	2,190,683

See notes to combined financial statements.

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Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Combined Statement of Changes in Members' and Stockholders' Equity

Years Ended December 31, 2011, 2010 and 2009

										Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, and Striker Oilfield Services, LLC

	Toro Operating, Inc.
	Common Stock
	Common Stock						Retained Earnings (Accumulated Deficit)									Total Members' and Stockholders' Equity
	Shares		Par Value		Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)			Note Receivable Member			Members' Equity			Total Members' and Stockholders' Equity
Balance—December 31, 2008		15,594	$	1,559	$	582,822	$	(115,399	)	$	—		$	7,595,733		$	8,064,715
Distributions		—		—		—		—			—			(1,027,000	)		(1,027,000	)
Net income		—		—		—		79,386			—			2,111,297			2,190,683


Balance—December 31, 2009		15,594		1,559		582,822		(36,013	)		—			8,680,030			9,228,398
Note receivable—Member		—		—		—		—			(140,156	)		—			(140,156	)
Contributions		—		—		—		—			—			250,000			250,000
Distributions		—		—		—		(30,000	)		—			(1,058,014	)		(1,088,014	)
Net (loss) income		—		—		—		(10,142	)		—			4,809,224			4,799,082


Balance—December 31, 2010		15,594		1,559		582,822		(76,155	)		(140,156	)		12,681,240			13,049,310
Payment on note receivable from member		—		—		—		—			66,547			—			66,547
Distributions		—		—		—		—			—			(3,090,240	)		(3,090,240	)
Net income		—		—		—		158,192			—			12,844,266			13,002,458


Balance—December 31, 2011		15,594	$	1,559	$	582,822	$	82,037		$	(73,609	)	$	22,435,266		$	23,028,075

See notes to combined financial statements.

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Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Combined Statements of Cash Flows

	For the Years Ended December 31,

	2011			2010			2009
Cash flows from operating activities
Net income	$	13,002,458		$	4,799,082		$	2,190,683


Adjustments to reconcile net income to net cash provided by operating activities
Depreciation		2,100,948			931,547			807,415
Gain on sale of assets		—			(149,981	)		(73,223	)
Loss (gain) on derivatives		127,450			(51,409	)		18,885
Changes in operating assets and liabilities
Accounts receivable		(21,520,215	)		(11,790,199	)		(10,261,006	)
Inventory		(549,207	)		(204,640	)		(392,474	)
Due to/from related parties, net		(65,857	)		(3,719	)		36,703
Prepaid expenses and other current assets		(300,914	)		(36,916	)		1,013,578
Accounts payable—crude oil purchases		17,021,077			6,884,931			6,714,113
Accounts payable		(541,326	)		139,813			984,586
Accrued expenses		1,846,137			535,847			131,694
Deferred revenue		—			—			(75,530	)


		(1,881,907	)		(3,744,726	)		(1,095,259	)


Net cash provided by operating activities		11,120,551			1,054,356			1,095,424


Cash flows from investing activities
Purchase of land, property, plant, and equipment		(1,043,832	)		(197,454	)	��	(166,957	)
Proceeds from disposal of assets		—			299,962			146,446
Cash flows from derivatives		(257,126	)		(174,875	)		(42,000	)


Net cash used in investing activities		(1,300,958	)		(72,367	)		(62,511	)


Cash flows from financing activities
Borrowings from line-of-credit		142,720,000			149,466,624			85,553,897
Payments on line-of-credit		(139,920,091	)		(147,630,430	)		(84,890,000	)
Payments on notes payable		(2,740,863	)		(1,066,995	)		(1,311,747	)
Net advance on note receivable—member		—			(200,000	)		—
Member contributions		—			250,000			—
Member distributions		(1,015,579	)		(1,028,170	)		(1,027,000	)


Net cash used in financing activities		(956,533	)		(208,971	)		(1,674,850	)


Net increase (decrease) in cash and cash equivalents		8,863,060			773,018			(641,937	)
Cash and cash equivalents—beginning of year		1,042,956			269,938			911,875


Cash and cash equivalents—end of year	$	9,906,016		$	1,042,956		$	269,938

Supplemental disclosure of cash flow information:

Cash paid for interest for the years ended December 31, 2011, 2010, and 2009 was $643,300, $386,476, and $325,505, respectively.

Supplemental disclosure of non-cash activity:

During the years ended December 31, 2011, 2010, and 2009, the Companies acquired equipment of $12,731,591, $2,121,572, and $363,006, respectively, with the issuance of long-term debt.

During 2011, the Companies distributed $66,547 that was used by one of the members to partially satisfy the note receivable balance due from the member (Note 8).

During 2010, the Companies distributed $59,844 that was used by one of the members to partially satisfy the note receivable balance due from the member (Note 8).

As of December 31, 2011, the Companies recorded distributions payable of $2,008,113 (Note 6).

See notes to combined financial statements.

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Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements

Note 1—Description of Business and Summary of Significant Accounting Policies

Organization

Pecos Gathering and Marketing, LLC ("Pecos") is a Colorado limited liability company ("LLC") headquartered in Austin, Texas. Transwest Leasing, LLC ("Transwest"), Blackhawk Gathering, LLC ("Blackhawk"), and Toro Operating Company, Inc. ("Toro") are all affiliated companies through common ownership. Striker Oilfield Services, LLC ("Striker") is a Texas LLC that has common ownership with Pecos but with different ownership percentages among its members. Pecos, Transwest, Blackhawk, Toro, and Striker are collectively referred to as the "Companies" in the combined financial statements.

Operations

The Companies gather crude oil from producing leases in Texas and New Mexico and deliver it to truck unloading facilities. The truck unloading facilities are connected to common carrier pipelines or, in one case, with a direct company pipeline to a refinery. The Companies have crude oil treatment plants that treat and process crude oil to pipeline standards. The Companies lease trucks and trailers to related parties for the purpose of transporting and hauling oil. In south Texas, Striker operates primarily as a contract trucker for one significant customer and to a lesser extent buys and sells crude oil.

Principles of Combination

The accompanying combined financial statements include the accounts of Pecos, Transwest, Blackhawk, Toro, and Striker. All Companies are affiliated and controlled by common ownership. All intercompany accounts and transactions have been eliminated in combination.

Use of Estimates

The preparation of combined financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent liabilities at the date of the combined financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

The Companies consider all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Companies continually monitor their positions with, and the credit quality of, the financial institutions with which they invest. As of the combined balance sheet date, and periodically throughout the year, the Companies have maintained balances in various operating accounts in excess of federally insured limits.

F-267

Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 1—Description of Business and Summary of Significant Accounting Policies (Continued)

Accounts Receivable

The Companies consider accounts receivable to be fully collectible; accordingly, no allowance for doubtful accounts has been established. Management reviews account balances regularly, and if amounts become uncollectible, the uncollectible portion is recorded to bad debt expense.

Concentrations of Credit Risk

The Companies sell crude oil to two significant customers, Customer A, which operates a refinery at Big Springs, Texas, and Customer B at the Centurion pipeline in Midland and Andrews, Texas. As of December 31, 2011, Customer A and Customer B accounted for 67% and 33%, respectively, of accounts receivable. For the year ended December 31, 2011, Customer A and Customer B accounted for 62% and 35%, respectively, of total revenue. As of December 31, 2010, Customer A and Customer B accounted for 65% and 31%, respectively, of accounts receivable. For the year ended December 31, 2010, Customer A and Customer B accounted for 60% and 39%, respectively, of total revenue. For the year ended December 31, 2009, Customer A and Customer B accounted for 63% and 36%, respectively, of total revenue.

Inventory

Inventory consists of crude oil and is stated at the lower of cost or market, determined using the first-in, first-out method.

Property, Plant, and Equipment

Property, plant, and equipment are stated at cost. Depreciation on property, plant, and equipment is calculated utilizing the straight-line method over the estimated useful life, which ranges from three to fifteen years, net of an estimated salvage value of the property and equipment. The Companies periodically review the reasonableness of estimates regarding useful lives and salvage values of property, plant, and equipment based upon the Companies' experience with similar assets and conditions in the used revenue equipment market. Future changes in useful life or salvage value estimates, or fluctuations in market value that are not reflected in the estimated salvage value, would have an effect on the Companies' results of operations. Trucks and trailers are depreciated over a period of five years, facilities are depreciated over a period of fifteen years, and equipment is depreciated over a period of seven years.

Revenue Recognition

The Companies record revenue from the sales of crude oil when the product is delivered, title has transferred, and collection is reasonably assured. The Companies record revenue from the hauling of crude oil when the product is delivered and collection is reasonably assured.

Income Taxes

With the exception of Toro, the entities have elected to be treated as partnerships for income tax purposes. Accordingly, taxable income and losses from all entities, except Toro, are reported in the

F-268

Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 1—Description of Business and Summary of Significant Accounting Policies (Continued)

income tax returns of the respective members, and no provision for income taxes has been recorded in the Companies' combined financial statements. Toro is taxed as a C corporation, and during the years ended December 31, 2011 and 2010, it had an immaterial amount of net taxable income. Toro's current taxable income is also reduced due to the utilization of the remaining net operating loss carryforwards from prior years. Toro's deferred tax assets and deferred tax liabilities are immaterial as of December 31, 2011 and 2010.

The Companies follow authoritative guidance on accounting for uncertainty in income taxes. With the exception of Toro, if taxing authorities were to disallow any tax positions taken by the Companies, the additional income taxes, if any, would be imposed on the members rather than the Companies. Tax positions taken by Toro are insignificant. Accordingly, there would only be a minimal impact on the Companies' combined financial statements.

Interest and penalties associated with tax positions are recorded in the period assessed as general and administrative expenses. No interest or penalties have been assessed as of December 31, 2011, 2010, and 2009. The estimated returns for tax years subject to examination by tax authorities include 2007 and 2008 through the current period for state and federal tax reporting purposes, respectively.

Long-Lived Assets

The Companies review their long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Companies look primarily to the estimated undiscounted future cash flows in their assessment of whether or not long-lived assets have been impaired. The Companies did not record any impairments during the years ended December 31, 2011, 2010, and 2009.

Fair Value of Financial Instruments

The carrying amounts of financial instruments, including cash, receivables, prepaids, notes receivable, accounts payable and accrued expenses, approximated fair value as of December 31, 2011 and 2010 because of the relatively short maturity of these instruments.

The carrying amounts of notes payable and debt issued approximate fair value as of December 31, 2011 and 2010 because interest rates on these instruments approximate market interest rates.

The brokerage margin account is recorded at fair value as discussed in Note 5.

The Companies disclose the fair value as determined for certain assets and liabilities and disclose how fair value is determined using a hierarchy for which these assets and liabilities are grouped, based on significant levels of inputs as follows:

Level 1: Quoted prices in active markets for identical assets or liabilities;

Level 2: Quoted prices in active markets for similar assets and liabilities and inputs that are observable for the asset or liability; or

Level 3: Unobservable inputs in which there is little or no market data, which requires the reporting entity to develop its own assumptions.

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Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 2—Balance Sheet Disclosures

Property, plant, and equipment consist of the following:

	December 31,

	2011			2010
Trucks	$	11,907,676		$	2,980,700
Trailers		6,040,215			2,349,316
Facilities		1,485,844			1,031,528
Equipment		885,387			615,544
Other vehicles		581,409			175,684
Leasehold improvements		56,790			—
Computer equipment and software		35,009			16,732


		20,992,330			7,169,504
Less accumulated depreciation		(4,908,488	)		(2,807,540	)


	$	16,083,842		$	4,361,964

Depreciation expense for the years ended December 31, 2011, 2010, and 2009 was $2,100,948, $931,547, and $807,415, respectively.

Accrued expenses consist of the following:

	December 31,

	2011		2010
Severance taxes payable	$	2,455,230	$	993,610
Other		440,512		55,995


	$	2,895,742	$	1,049,605

Note 3—Line-of-Credit

On December 31, 2011, the Companies entered into a new credit agreement (the "Agreement") with a bank. The Companies could have borrowed the lesser of the borrowing base as defined by the Agreement or $30,000,000. The borrowing base as of December 31, 2011 was $22,662,523. At December 31, 2011, the borrowings outstanding under this Agreement were $6,000,000. Borrowings accrued interest per annum equal to either the base rate advance or Eurodollar rate advance. The base rate advance was equal to the prime rate plus 2.75% (6.00% at December 31, 2011). The Eurodollar rate advance was based on the two-week, one-month, two-month, or three-month BBA LIBOR plus 4.00% (4.68% to 5.29% at December 31, 2011), as elected by the Companies and subject to certain restrictions. At December 31, 2011, all of the outstanding debt under the Agreement was based on the Eurodollar rate advance. All of the Companies' assets were pledged as collateral with the exception of Transwest. However, all assets of Transwest were pledged as collateral against the Companies' notes payable described in Note 4. The Agreement terminates and borrowings would have been due upon the occurrence of certain events or at the discretion of the lenders as defined in the Agreement. The

F-270

Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 3—Line-of-Credit (Continued)

Companies were required to meet certain financial covenants and were in compliance with all financial covenants at December 31, 2011.

As of December 31, 2010, the Companies had a line-of-credit agreement with Bank of America. At December 31, 2010, the borrowings outstanding under this Agreement were $3,200,091. Interest accrued at one-month LIBOR plus 2.75% (3.013% at December 31, 2010). The Companies were required to meet certain financial covenants and were in compliance with all covenants at December 31, 2010. During 2011, the Companies paid the outstanding balance of the line-of-credit.

Note 4—Notes Payable

Notes payable consist of the following:

	December 31,

	2011			2010
The Companies have various note payable agreements to third-party banks for certain trucks and trailers. Interest rates on these agreements range from 3.96% to 5.90%. The maturity dates on the notes payable range from January 2012 to March 2015. The Transwest portion of the Companies' assets are pledged as collateral, and there are guarantees by certain members of the Companies.	$	12,425,349		$	2,434,621
Less current portion		(4,861,915	)		(1,246,460	)


	$	7,563,434		$	1,188,161

Maturities of the notes payable are as follows:

Year Ending December 31,

2012	$	4,861,915
2013		4,640,705
2014		2,853,136
2015		69,593


	$	12,425,349

Note 5—Derivatives

The Companies routinely enter into contracts for the purchase and sale of crude oil at future delivery dates. The Companies enter into these contracts with the expectation that they will result in physical delivery of crude oil. The Companies account for these contracts as normal purchases and normal sales. Under this accounting policy election, the contracts are not recorded at fair value at the balance sheet dates; instead, the purchase or sale is recorded at the contracted value once the delivery occurs.

F-271

Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 5—Derivatives (Continued)

The Companies' crude oil purchase and sale contracts are priced based on various crude oil indices. These indices may vary in the type or location of crude oil, or in the timing of delivery within a given month. The Companies have entered into certain financial derivative contracts, which consist primarily of crude oil futures contracts, as hedges against the risk that changes in the different index prices would reduce the margins between the purchase and the sale transactions.

The Companies record these derivative contracts at fair value within accounts receivable on the combined balance sheets. The Companies value the derivative contracts using quoted prices in active markets for identical contracts and consider the fair value to be a Level 1 measurement in the fair value hierarchy. All of the contracts are maintained by a broker, and the Companies report these contracts, along with any related margin deposits, on a net basis on the combined balance sheets. The balance associated with these contracts, including related margin deposits, was $379,075 at December 31, 2011 and $249,399 at December 31, 2010, respectively.

The Companies report the realized and unrealized gains and losses associated with these derivative contracts within product expenses in the combined statements of income. These gains and losses consist of the following:

	For the Years Ended December 31,

	2011			2010		2009
Unrealized gain (loss)	$	122,700		$	38,860	$	8,600
Realized gain (loss)		(250,150	)		12,549		(27,485	)


Total	$	(127,450	)	$	51,409	$	(18,885	)

The Companies include net cash transfers to or from the brokerage account in investing cash flows in the combined statements of cash flows.

Note 6—Members' and Stockholders' Equity

Individual capital accounts have been established based on the initial contribution to the Companies. Profits and losses are allocated to the members' capital accounts based upon percentages of ownership in the Companies. Additional capital contributions may be made upon a unanimous vote of all members. The Companies' operating agreements require available cash to be distributed at the end of each calendar year subject to certain limitations. As distributions made during the year ended December 31, 2011 were not pro rata with each member's ownership interest, as of December 31, 2011, Pecos and Striker accrued distributions of $808,113 and $1,200,000, respectively, payable to one or more members. These balances are included in distributions payable and have been shown as a liability on the combined balance sheets.

Toro is the only affiliate with common stock. Each share of outstanding common stock is entitled to voting rights on matters affecting Toro.

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Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 7—Commitments and Contingencies

Letters-of-Credit

On December 1, 2011, the Companies issued a $6,650,000 letter-of-credit that has not been drawn upon. This letter-of-credit expires in one to three month increments and can be renewed at the end of each term. The letter-of-credit was issued to secure the amounts owed to one of the Companies' crude oil suppliers. On June 1, 2012, the Companies issued a revision to this letter-of-credit for $4,950,000 to extend the letter-of-credit through July 31, 2012. The revised letters-of-credit have not had an impact on the Companies' combined 2011 results of operations.

On June 1, 2012, the Companies issued a separate $3,000,000 letter-of-credit that has not been drawn upon. The letter-of-credit was issued to secure the amounts owed to one of the Companies' crude oil suppliers. No amounts were recorded in conjunction with the issuance of this letter-of-credit, which is irrevocable until December 31, 2012. The letters-of-credit incur interest at 3.75% per annum plus issuing fees of $300 and a $75 cancellation fee.

Asset Retirement Obligation

The Companies are required to recognize the fair value of a liability for an asset retirement obligation when it is incurred (generally in the period in which they acquire, construct, or install an asset) if a reasonable estimate of fair value can be made. If a reasonable estimate cannot be made in the period the asset retirement obligation is incurred, the liability should be recognized when a reasonable estimate of fair value can be made.

In order to determine fair value of such liability, the Companies must make certain estimates and assumptions, including, among other things, projected cash flows, a credit-adjusted risk-free interest rate, and an assessment of market conditions, that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time.

The Companies have determined that they are obligated by contractual or regulatory requirements to remove certain of their assets or perform other remediation of the sites where such assets are located upon the retirement of those assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including estimated settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, the Companies do not believe the present value of such asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of the Companies' facilities, is material to their financial position or results of operations.

Litigation

In the normal course of business, the Companies are party to litigation from time to time. The Companies maintain insurance to cover certain actions and believe that resolution of such litigation will not have a material adverse effect on the Companies.

F-273

Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, TORO OPERATING COMPANY, INC., AND
STRIKER OILFIELD SERVICES, LLC

Notes to Combined Financial Statements (Continued)

Note 8—Related Party Transactions

In February 2010, the Companies entered into a note receivable agreement with a member for $200,000. The note was due February 2013 and had an interest rate of 2% per annum. During the years ended December 31, 2011 and 2010, the Companies' distributions totaling $66,547 and $59,844, respectively, were applied to this member note receivable, which are reflected as non-cash distributions on the combined statements of cash flows. Subsequent to December 31, 2011, the remaining note receivable balance was collected.

During the year ended December 31, 2011, the Companies paid $170,000 in management fees to a related party, which is included in general and administrative expenses on the combined statements of income.

The Companies also have various related party receivables and payables outstanding. Receivables from related parties totaled $85,805 and $38,296 at December 31, 2011 and 2010, respectively. Payables due to related parties totaled $12,000 and $30,348 at December 31, 2011 and 2010, respectively. The Companies also have a $250,000 deposit with a related party at December 31, 2011 and 2010.

Note 9—Subsequent Events

Midstream Operations, LLC ("Midstream") was formed on January 1, 2012. Midstream is a management company that is owned by two of the Companies' members and stockholders and allocates general and administrative overhead charges to the Companies. These allocated charges include salaries and office expenses.

On October 23, 2012, the Companies, including Midstream, entered into an Equity Purchase Agreement (the "NGL Agreement") with NGL Energy Partners LP ("NGL") to purchase all of the equity in Pecos, Transwest, Blackhawk, Striker, and Midstream, which closed November 2012. Under the NGL Agreement, NGL would also have first right of refusal to purchase one of the two properties owned by Toro. The Companies are also required to provide remediation for this property, as well as provide assistance and set-up of a new processing facility to be operated by NGL. As part of the NGL Agreement, the line-of-credit was paid in full as well as a portion of the notes payable.

The Companies have evaluated all subsequent events through January 14, 2013, which is the date the combined financial statements were available for issuance.

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INDEPENDENT ACCOUNTANTS' REVIEW REPORT

Board of Directors, Members, and Stockholders
Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC,
Blackhawk Gathering, LLC, Midstream Operations, LLC, Toro
Operating Company, Inc., and Striker Oilfield Services, LLC
Austin, Texas

We have reviewed the accompanying combined balance sheets of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Midstream Operations, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC (the "Companies") as of September 30, 2012 and 2011, and the related combined statements of income, changes in members' and stockholders' equity, and cash flows for the nine months ended September 30, 2012 and 2011. A review includes primarily applying analytical procedures to management's financial data and making inquiries of management. A review is substantially less in scope than an audit, the objective of which is the expression of an opinion regarding the combined financial statements as a whole. Accordingly, we do not express such an opinion.

Management is responsible for the preparation and fair presentation of the combined financial statements in accordance with accounting principles generally accepted in the United States of America and for designing, implementing, and maintaining internal controls relevant to the preparation and fair presentation of the combined financial statements.

Our responsibility is to conduct the review in accordance withStatements on Standards for Accounting and Review Services issued by the American Institute of Certified Public Accountants. Those standards require us to perform procedures to obtain limited assurance that there are no material modifications that should be made to the combined financial statements. We believe that the results of our procedures provide a reasonable basis for our report.

Based on our reviews, we are not aware of any material modifications that should be made to the accompanying combined financial statements in order for them to be in conformity with accounting principles generally accepted in the United States of America.

The combined financial statements for the year ended December 31, 2011, were audited by us, and we expressed an unqualified opinion on them in our report dated January 14, 2013, but we have not performed any auditing procedures since that date.

/s/ EKS&H, LLLP

January 14, 2013
Denver, Colorado

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Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Combined Balance Sheets

(See Independent Accountants' Review Report)

	September 30, 2012		December 31 2011

	(unaudited)		(audited)
Assets
Current assets
Cash and cash equivalents	$	7,749,810	$	9,906,016
Accounts receivable		83,432,762		51,860,802
Inventory		1,531,145		1,348,826
Due from related parties		360,276		85,805
Prepaid expenses and other current assets		965,903		401,727


Total current assets		94,039,896		63,603,176


Non-current assets
Property, plant, and equipment, net of accumulated depreciation of $8,029,823 and $4,908,488, at September 30, 2012 and December 31, 2011, respectively		21,662,896		16,083,842
Land		236,453		230,253
Deposits—related party		—		250,000
Deposits		—		9,434


Total non-current assets		21,899,349		16,573,529


Total assets	$	115,939,245	$	80,176,705




Liabilities and Stockholders' Equity
Current liabilities
Line of credit	$	5,000,000	$	6,000,000
Accounts payable—crude oil purchases		52,259,802		32,974,766
Accounts payable		1,837,789		832,660
Accrued expenses		4,680,551		2,895,742
Due to related parties		—		12,000
Notes payable—current portion		7,307,463		4,861,915
Distributions payable		—		2,008,113


Total current liabilities		71,085,605		49,585,196
Non-current liabilities
Long-term debt, less current portion		8,168,677		7,563,434


Total liabilities		79,254,282		57,148,630


Commitments and contingencies (Note 7)
Members' and stockholders' equity
Common stock, 30,000 shares authorized, 15,594 shares outstanding, par value $0.10		1,559		1,559
Additional paid-in capital		582,822		582,822
Retained earnings (accumulated deficit)		21,799		82,037
Note receivable—member		—		(73,609	)
Members' equity		36,078,783		22,435,266


Total members' and stockholders' equity		36,684,963		23,028,075


Total liabilities and members' and stockholders' equity	$	115,939,245	$	80,176,705

See notes to unaudited combined financial statements.

F-276

Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Unaudited Combined Statements of Income

(See Independent Accountants' Review Report)

	Nine Months Ended September 30,

	2012			2011
Revenues
Crude oil sales	$	637,163,966		$	337,620,173
Crude oil hauling		22,117,354			8,832,916
Rental revenue—related parties		51,032			—


Total revenues		659,332,352			346,453,089


Product expenses		625,771,712			330,479,968


Operating expenses
Transportation expenses		1,234,691			1,315,972
Personnel expenses		5,698,940			2,839,012
Equipment and facilities' expenses		577,961			807,565
General and administrative expenses		1,641,151			1,344,730
Depreciation		3,283,939			1,345,324


Total operating expenses		12,436,682			7,652,603


Other (expense) income
Interest expense		(877,625	)		(421,448	)
Interest income		13,506			5,701
Loss on disposal of assets		(660	)		—


Total other expense, net		(864,779	)		(415,747	)


Net income	$	20,259,179		$	7,904,771

See notes to unaudited combined financial statements.

F-277

Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Unaudited Combined Statement of Changes in Members' and Stockholders' Equity

Nine Months Ended September 30, 2012

(See Independent Accountants' Review Report)

										Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Midstream Operations, LLC, and Striker Oilfield Services, LLC

	Toro Operating, Inc.
	Common Stock
	Common Stock				Additional Paid-In Capital		Retained Earnings			Note Receivable Members'			Members' Equity			Total Stockholders' Equity
	Shares		Par Value		Additional Paid-In Capital		Retained Earnings			Note Receivable Members'			Members' Equity			Total Stockholders' Equity
Balance—December 31, 2011		15,594	$	1,559	$	582,822	$	82,037		$	(73,609	)	$	22,435,266		$	23,028,075
Payment on note receivable from member		—		—		—		—			73,609			—			73,609
Distributions		—		—		—		—			—			(6,925,900	)		(6,925,900	)
Contributions		—		—		—		—			—			250,000			250,000
Net income (loss)		—		—		—		(60,238	)		—			20,319,417			20,259,179


Balance—September 30, 2012		15,594	$	1,559	$	582,822	$	21,799		$	—		$	36,078,783		$	36,684,963

See notes to unaudited combined financial statements.

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Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Unaudited Combined Statements of Cash Flows

(See Independent Accountants' Review Report)

	Nine Months Ended September 30,

	2012			2011
Cash flows from operating activities	��
Net income	$	20,259,179		$	7,904,771


Adjustments to reconcile net income to net cash provided by operating activities
Depreciation		3,283,939			1,345,324
Loss on sale of assets		660			—
Gain on derivatives		(582,129	)		(209,015	)
Changes in assets and liabilities
Accounts receivable		(30,989,831	)		(13,671,976	)
Inventory		(182,319	)		506,807
Due to/from related parties, net		(286,471	)		(78,748	)
Prepaid expenses and other current assets		(554,742	)		(71,455	)
Deposits		250,000			—
Accounts payable—crude oil purchases		19,285,036			8,432,609
Accounts payable		1,005,129			(868,615	)
Accrued expenses		1,784,809			963,119


		(6,985,919	)		(3,651,950	)


Net cash provided by operating activities		13,273,260			4,252,821


Cash flows from investing activities
Purchase of land, property, plant, and equipment		(1,779,592	)		(777,184	)
Proceeds from sale of property, plant, and equipment		444,802			—
Cash flows from derivatives		—			(257,126	)


Net cash used in investing activities		(1,334,790	)		(1,034,310	)


Cash flows from financing activities
Borrowings from line-of-credit		6,000,000			114,320,000
Payments on line-of-credit		(7,000,000	)		(113,020,000	)
Payments on notes payable		(4,484,272	)		(1,669,878	)
Member contributions		250,000			—
Member distributions		(8,860,404	)		(948,739	)


Net cash used in financing activities		(14,094,676	)		(1,318,617	)


Net (decrease) increase in cash and cash equivalents		(2,156,206	)		1,899,894
Cash and cash equivalents—beginning of period		9,906,016			1,042,956


Cash and cash equivalents—end of period	$	7,749,810		$	2,942,850

Supplemental disclosure of cash flow information:

Cash paid for interest for the nine months ended September 30, 2012 and 2011 was $877,625 and $421,448, respectively.

Supplemental disclosure of non-cash activity:

During the nine months ended September 30, 2012 and 2011, the Companies acquired equipment of $7,535,063 and $8,854,020, respectively, with the issuance of long-term debt.

During 2012, the Companies distributed $73,609, which was used by one of the Members to satisfy the note receivable balance due from the Member (Note 8).

During 2011, the Companies distributed $49,785, which was used by one of the Members to partially satisfy the note receivable balance due from the Member (Note 8).

See notes to unaudited combined financial statements.

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Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements

(See Independent Accountants' Review Report)

Note 1—Description of Business and Summary of Significant Accounting Policies

Organization

Pecos Gathering and Marketing, LLC ("Pecos") is a Colorado limited liability company ("LLC") headquartered in Austin, Texas. Transwest Leasing, LLC ("Transwest"), Blackhawk Gathering, LLC ("Blackhawk"), Midstream Operations, LLC ("Midstream"), and Toro Operating Company, Inc. ('Toro") are all affiliated companies through common ownership. Striker Oilfield Services, LLC ("Striker") is a Texas LLC that has common ownership with Pecos but with different ownership percentages among its members. Pecos, Transwest, Blackhawk, Midstream, Toro, and Striker are collectively referred to as the "Companies" in the combined financial statements.

Financial Statement Presentation

The Companies have prepared these unaudited interim combined financial statements included herein pursuant to the rules and regulations of the United States Securities and Exchange Commission. In the Companies' opinion, the unaudited interim combined financial statements contain all adjustments (consisting of only normal recurring adjustments) necessary to present fairly, in all material respects, the combined financial position as of September 30, 2012, the interim results of operations for the nine months ended September 30, 2012 and 2011, and cash flows for the nine months ended September 30, 2012. These interim statements have not been audited. The balance sheet as of December 31, 2011 was derived from the Companies' audited combined financial statements. The interim combined financial statements contained herein should be read in conjunction with our audited combined financial statements, including the notes thereto, for the year ended December 31, 2011.

Operations

The Companies gather crude oil from producing leases in Texas and New Mexico and deliver it to truck unloading facilities. The truck unloading facilities are connected to common carrier pipelines or, in one case, to a direct company pipeline to a refinery. The Companies have crude oil treatment plants that treat and process crude oil to pipeline standards. The Companies lease trucks and trailers to related parties for the purpose of transporting and hauling oil. In South Texas, Striker operates primarily as a contract trucker for one significant customer and, to a lesser extent, buys and sells crude oil.

Principles of Combination

The accompanying combined financial statements include the accounts of Pecos Gathering and Marketing, LLC, Transwest Leasing, LLC, Blackhawk Gathering, LLC, Midstream Operations, LLC, Toro Operating Company, Inc., and Striker Oilfield Services, LLC. All Companies are affiliated and controlled by common ownership. All intercompany accounts and transactions have been eliminated in combination.

F-280

Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 1—Description of Business and Summary of Significant Accounting Policies (Continued)

Use of Estimates

The preparation of combined financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosures of contingent assets and liabilities at the date of the combined financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Cash and Cash Equivalents

The Companies considers all highly liquid instruments purchased with an original maturity of three months or less to be cash equivalents. The Companies continually monitors its positions with, and the credit quality of, the financial institutions it invests with. As of the balance sheet date, and periodically throughout the year, the Company has maintained balances in various operating accounts in excess of federally insured limits.

Accounts Receivable

The Companies consider accounts receivable to be fully collectible; accordingly, no allowance for doubtful accounts is required. Management reviews account balances regularly, and, if amounts become uncollectible, the uncollectible portion is recorded to bad debt expense.

Concentrations of Credit Risk

The Companies sell crude oil to two significant customers, Customer A, which operates a refinery in Big Springs, Texas, and Customer B, at the Centurion pipeline in Midland and Andrews, Texas. As of September 30, 2012, Customer A and Customer B accounted for 59% and 18%, respectively, of accounts receivable. As of December 31, 2011, Customer A and Customer B accounted for 67% and 33%, respectively, of accounts receivable. For the nine months ended September 30, 2012, Customer A and Customer B accounted for 57% and 19%, respectively, of total revenue. For the nine months ended September 30, 2011, Customer A and Customer B accounted for 60% and 35%, respectively, of total revenue.

Inventory

Inventory consists of crude oil and is stated at the lower of cost or market, determined using the first-in, first-out method.

Property, Plant, and Equipment

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 1—Description of Business and Summary of Significant Accounting Policies (Continued)

conditions in the used revenue equipment market. Future changes in useful life or salvage value estimates, or fluctuations in market value that are not reflected in the estimated salvage value, would have an effect on the Companies' results of operations. Trucks and trailers are depreciated over a period of five years, facilities are depreciated over a period of fifteen years, and equipment is depreciated over a period of seven years.

Revenue Recognition

Revenue on the rental of trucks and trailers is recognized on a straight-line basis over the term of the lease. The Companies' standard lease agreements are non-cancelable operating leases and provide for monthly lease payments for three years.

Income Taxes

With the exception of Toro, the entities have elected to be treated as partnerships for income tax purposes. Accordingly, taxable income and losses from all entities, except for Toro, are reported in the income tax returns of the respective members, and no provision for income taxes has been recorded in the Companies' combined financial statements. Toro is taxed as a C corporation, and during the nine months ended September 30, 2012, it had an immaterial amount of net taxable income. Toro's current taxable income is also reduced due to the utilization of the remaining net operating loss carryforwards from prior years. Toro's deferred tax assets and deferred tax liabilities are immaterial as of September 30, 2012.

Income Taxes (continued)

Interest and penalties associated with tax positions are recorded in the period assessed as general and administrative expenses. No interest or penalties have been assessed as of September 30, 2012. The estimated returns for tax years subject to examination by tax authorities include 2007 and 2008 through the current period for state and federal tax reporting purposes, respectively.

Long-Lived Assets

The Companies review the long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of the asset may not be recovered. The Companies look primarily to the undiscounted future cash flows in its assessment of whether or not long-lived

F-282

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 1—Description of Business and Summary of Significant Accounting Policies (Continued)

assets have been impaired. The Companies did not record any impairments during the nine months ended September 30, 2012 and 2011.

Fair Value of Financial Instruments

The carrying amounts of financial instruments including cash and cash equivalents, short-term investments, receivables, prepaids, notes receivable, accounts payable, and accrued expenses approximated fair value as of September 30, 2012 because of the relatively short maturity of these instruments.

The carrying amounts of notes payable and debt issued approximate fair value as of September 30, 2012 because interest rates on these instruments approximate market interest rates.

The brokerage margin account is recorded at fair value as discussed in Note 5.


Level 1:		Quoted prices in active markets for identical assets or liabilities;
Level 2:		Quoted prices in active markets for similar assets and liabilities and inputs that are observable for the asset or liability; or
Level 3:		Unobservable inputs in which there is little or no market data, which requires the reporting entity to develop its own assumptions.

Note 2—Balance Sheet Disclosures

Property and equipment consist of the following:

	September 30, 2012			December 31. 2011

Trucks	$	16,162,106		$	11,907,676
Trailers		9,392,446			6,040,215
Equipment		1,878,639			885,387
Facilities		1,564,205			1,485,844
Other vehicles		593,846			581,409
Leasehold improvements		55,232			56,790
Computer equipment and software		46,245			35,009


		29,692,719			20,992,330
Less accumulated depreciation		(8,029,823	)		(4,908,488	)


	$	21,662,896		$	16,083,842

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 2—Balance Sheet Disclosures (Continued)

Depreciation expense for the nine months ended September 30, 2012 and 2011 was $3,283,939 and $1,345,324, respectively.

Accrued expenses consist of the following:

	September 30, 2012		December 31, 2011

Severance taxes payable	$	3,772,927	$	2,455,230
Other		907,624		440,512


	$	4,680,551	$	2,895,742

Note 3—Line-of-Credit

On December 13, 2011, the Companies entered into a new credit agreement ("Agreement") with a bank. The Companies could have borrowed the lesser of the borrowing base, as defined by the Agreement, or $30,000,000. The borrowing base as of September 30, 2012 was $34,248,095. At September 30, 2012, there was $5,000,000 outstanding under this Agreement. Borrowings accrued interest per annum equal to either the base-rate advance or Eurodollar-rate advance. The base-rate advance was equal to the prime rate plus 2.75% (6.00% at September 30, 2012). The Eurodollar rate advance was based on the two-week, one-month, two-month, or three-month BBA LIBOR plus 4.00% (4.20% to 4.42% at September 30, 2012), as elected by the Companies and subject to certain restrictions. At September 30, 2012, all of the outstanding debt under the Agreement was based on the Eurodollar-rate advance. All of the Companies' assets were pledged as collateral with the exception of Transwest. The assets of Transwest are pledged as collateral against the Companies' notes payable described in Note 4. The Agreement terminates and borrowings were due upon the occurrence of certain events or at the discretion of the lenders, as defined in the Agreement. The Companies were required to meet certain financial covenants and were in compliance with all financial covenants at September 30, 2012.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 4—Notes Payable

Notes payable consist of the following:

	September 30, 2012			December 31 2011

The Companies have various note payable agreements to third-party banks for certain trucks and trailers. Interest rates on these agreements range from 3.82% to 5.90%. The maturity dates on the notes payable range from April 2013 to September 2015. The Transwest portion of the Companies' assets are pledged as collateral, and there are guarantees by certain members and stockholders of the Companies.	$	15,476,140		$	12,425,349
Less current portion		(7,307,463	)		(4,861,915	)


	$	8,168,677		$	7,563,434

Maturities of the notes payable are as follows:

Year Ending December 31,

2012 (three months)	$	2,012,471
2013		7,087,231
2014		5,407,545
2015		968,893


	$	15,476,140

Note 5—Derivatives

The Companies have entered into certain financial derivative contracts, which consist primarily of crude oil futures contracts. The Companies record these derivative contracts at fair value within accounts receivable on the condensed combined balance sheets. The Companies value the derivative contracts using quoted prices in active markets for identical contracts and considers the fair value to be a Level 1 measurement in the fair value hierarchy. All of the contracts are maintained by a broker, and the Companies report these contracts, along with any related margin deposits, on a net basis on the combined balance sheets. The balance associated with these contracts, including related margin deposits, was $961,205 at September 30, 2012 and $379,075 at December 31, 2011, respectively.

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Table of Contents

PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 5—Derivatives (Continued)

The Companies report the realized and unrealized gains and losses associated with these derivative contracts within other income (expense) in the combined statements of income. These gains and losses consist of the following:

	For the Nine Months Ended September 30,

	2012			2011
Unrealized gain (loss)	$	(79,480	)	$	(599,500	)
Realized gain (loss)		661,609			808,515


Total	$	582,129		$	209,015

The Companies include net cash transfers to or from the brokerage account in investing cash flows in the combined statements of cash flows.

Note 6—Members' and Stockholders' Equity

Toro is the only affiliate with common stock. Each share of outstanding common stock is entitled to voting rights on matters affecting Toro.

Note 7—Commitments and Contingencies

Letters-of-Credit

On December 1, 2011, the Companies issued a $6,650,000 letter-of-credit that has not been drawn upon. This letter-of-credit expires in one- to three-month increments and can be renewed at the end of each term. The letter-of-credit was issued to secure the amounts owed to one of the Companies' crude oil suppliers. On June 1, 2012, the Companies issued a revision to this letter-of-credit for $4,950,000 to extend the letter-of-credit through July 31, 2012. The revised letter-of-credit has not had an impact on the Companies' combined 2011 results of operations.

The letters-of-credit incur interest at 3.75% per annum plus issuing fees of $300 and a $75 cancellation fee.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 7—Commitments and Contingencies (Continued)

Asset Retirement Obligations

In order to determine fair value of such liability, the Companies must make certain estimates and assumptions including, among other things, projected cash flows, a credit-adjusted risk-free interest rate, and an assessment of market conditions that could significantly impact the estimated fair value of the asset retirement obligation. These estimates and assumptions are very subjective and can vary over time.

The Companies have determined that they are obligated by contractual or regulatory requirements to remove certain of their assets or perform other remediation of the sites where such assets are located upon the retirement of those assets. Determination of the amounts to be recognized is based upon numerous estimates and assumptions, including estimated settlement dates, future retirement costs, future inflation rates, and the credit-adjusted risk-free interest rates. However, the Companies do not believe the present value of such asset retirement obligations, under current laws and regulations, after taking into consideration the estimated lives of the Companies facilities, is material to their financial position or results of operations.

Litigation

Note 8—Related Party Transactions

In February 2010, the Companies entered into a note receivable agreement with a member for $200,000. The note was due February 2013 and had an interest rate of 2% per annum. During the nine-month period ended September 30, 2012, distributions totaling $73,609 were applied to this member note receivable, which are reflected as non-cash distributions on the combined statement of cash flows. During the nine-month period ended September 30, 2012, the note was paid off.

During the nine-month periods ended September 30, 2012 and 2011, the Companies paid $153,000 and $119,000, respectively, in management fees to a related party, which is included in general and administrative expenses on the combined statements of income.

The Companies also have various related party receivables outstanding totaling $360,276 at September 30, 2012. There were no related party payables outstanding as of September 30, 2012.

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PECOS GATHERING AND MARKETING, LLC, TRANSWEST LEASING, LLC,
BLACKHAWK GATHERING, LLC, MIDSTREAM OPERATIONS, LLC,
TORO OPERATING COMPANY, INC., AND STRIKER OILFIELD SERVICES, LLC

Notes to Unaudited Combined Financial Statements (Continued)

(See Independent Accountants' Review Report)

Note 9—Subsequent Events

On October 23, 2012, the Companies entered into an Equity Purchase Agreement (the "NGL Agreement") with NGL Energy Partners LP ("NGL") to purchase all of the equity in Pecos, Transwest, Blackhawk, Striker, and Midstream, which closed November 2012. Under the NGL Agreement, NGL would also have first right of refusal to purchase one of the two properties owned by Toro. The Companies are also required to provide remediation for this property, as well as provide assistance and set-up of a new processing facility to be operated by NGL. As part of the NGL Agreement, the line-of-credit was paid in full, as well as a portion of the notes payable.

The Companies have evaluated all subsequent events through January 14, 2013, which is the date the unaudited combined financial statements were available for issuance.

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Independent Auditor's Report

General Partner
Oilfield Water Lines, LP
Dallas, Texas

We have audited the accompanying consolidated financial statements of Oilfield Water Lines, LP and its subsidiaries, which comprise the consolidated balance sheet as of December 31, 2012, and the related consolidated statements of operations, changes in partners' capital, and cash flows for the period from inception (August 6, 2012) to December 31, 2012, and the related notes to the consolidated financial statements.

Management's Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of Oilfield Water Lines, LP and its subsidiaries as of December 31, 2012, and the results of their operations and their cash flows for the period from inception (August 6, 2012) to December 31, 2012 in accordance with accounting principles generally accepted in the United States of America.

Basis of Presentation

As discussed in Note 10, the operating subsidiaries of Oilfield Water Lines, LP, were sold on August 2, 2013.

/s/ BDO USA, LLP
Dallas, Texas
September 27, 2013

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Oilfield Water Lines, LP

Consolidated Balance Sheet

	December 31, 2012

Assets
Current assets
Cash and cash equivalents	$	3,853,865
Accounts receivable—trade		3,834,236
Prepaid expenses and other		323,158


Total current assets		8,011,259
Property and equipment, net		23,386,066
Goodwill		18,682,609
Other assets		325,749


Total assets	$	50,405,683




Liabilities and Capital
Current liabilities
Accounts payable—trade	$	4,333,007
Insurance notes payable		248,714
Accrued expenses		425,776
Related party debt		1,676,357


Total current liabilities		6,683,854


Commitments and contingencies (Note 8)
Capital
General partner (0.1%)		19,466
Limited partners (99.9%)		37,369,386


Total partners' capital		37,388,852


Non-controlling interests		6,332,977
Total capital		43,721,829


Total liabilities and capital	$	50,405,683

The accompanying notes are an integral part of these consolidated financial statements.

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Oilfield Water Lines, LP

Consolidated Statement of Operations

	Period from inception (August 6, 2012) to December 31, 2012

Revenues
Crude oil sales	$	4,337,774
Water disposal services		1,338,726


Total revenues		5,676,500
Expenses
Well servicing		1,614,710
General and administrative		429,881
Acquisition transaction costs		328,509
Depreciation and amortization		269,239


Total expenses		2,642,339
Operating income		3,034,161
Other expense
Interest expense		(17	)
Interest expense—related party		(176,357	)
Interest expense—non-controlling interest		(4,750,000	)


Total other expense		(4,926,374	)
Loss before income taxes		(1,892,213	)
Provision for income taxes		(34,368	)


Net loss		(1,926,581	)
Net income attributable to non-controlling interest		936,477


Net loss attributable to partners	$	(2,863,058	)

The accompanying notes are an integral part of these consolidated financial statements.

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Oilfield Water Lines, LP

Consolidated Statement of Changes in Partners' Capital

	General Partner			Limited Partners			Non- Controlling Interest			Total Equity

Balance at inception (August 6, 2012)	$	—		$	—		$	—		$	—
Contributions		22,330			41,306,056			—			41,328,386
Purchase of non-controlling interest		—			—			6,660,000			6,660,000
Distributions		—			(1,076,476	)		(1,263,500	)		(2,339,976	)
Net (loss) income		(2,864	)		(2,860,194	)		936,477			(1,926,581	)


Balance at December 31, 2012	$	19,466		$	37,369,386		$	6,332,977		$	43,721,829

The accompanying notes are an integral part of these consolidated financial statements.

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Consolidated Statement of Cash Flows

	Period from inception (August 6, 2012) to December 31, 2012

Cash flows from operating activities
Net loss	$	(1,926,581	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization expense		269,239
Interest expense—non-controlling interest		4,750,000
Changes in operating assets and liabilities, net of amounts acquired in acquisitions:
Accounts receivable		(930,696	)
Prepaid expenses and other current assets		(32,622	)
Other assets		(325,749	)
Accounts payable—trade		3,412,861
Accrued expenses and other liabilities		279,332
Related party debt		176,357


Net cash provided by operating activities		5,672,141


Cash flows from investing activities
Purchases of property and equipment		(7,308,995	)
Acquisitions of subsidiaries, net of cash acquired		(24,987,691	)


Net cash used by investing activities		(32,296,686	)


Cash flows from financing activities
Payments on acquisition debt		(8,510,000	)
Contributions from partners		41,328,386
Distributions to non-controlling interests		(1,263,500	)
Withdrawals by partners		(1,076,476	)


Net cash provided by financing activities		30,478,410


Net increase in cash and cash equivalents		3,853,865
Cash and cash equivalents
Beginning of period		—


End of period	$	3,853,865

The accompanying notes are an integral part of these consolidated financial statements.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements

1. Organization and Nature of Business

Oilfield Water Lines, LP (the "Partnership") is a Texas Limited Partnership formed on August 6, 2012. The Partnership is engaged in the water services and hauling businesses, the assets of which primarily include water treatment and disposal facilities, trucks and trailers.

The general partner of the Partnership is Oilfield Water Lines GP, LLC.

2. Summary of Significant Accounting Policies

Principles of Consolidation

The Partnership's consolidated financial statements as of December 31, 2012 include the accounts of Oilfield Water Lines, LP and its controlled subsidiaries, which are HR OWL, LLC, OWL Operating, LLC, OWL Pearsall SWD, LLC, OWL Karnes SWD, LLC, OWL Cotulla SWD, LLC, OWL Nixon SWD, LLC, OWL Lotus, LLC and Lotus Oilfield Services, LLC. All significant intercompany balances and transactions have been eliminated in consolidation.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of the Partnership's assets, liabilities, revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that it believes to be reasonable under the circumstances.

Critical estimates management makes in the preparation of the Partnership's consolidated financial statements include the collectability of accounts receivable, estimates of useful lives and recoverability of property, plant and equipment, valuation of goodwill and accruals for various commitments and contingencies, among others. Although management believes these estimates are reasonable, actual results could differ from these estimates.

Revenue Recognition

The Partnership generates revenues from the gathering, hauling, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recovered hydrocarbons.

The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records water disposal revenues at the time the services are performed, which is upon receipt of the wastewater at the Partnership's disposal facilities.

The Partnership recognizes revenue upon completion of hauling services, provided collection of the relevant receivables is probable, persuasive evidence of an arrangement exists, and the price is fixed or determinable.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Cash and Cash Equivalents

The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

The Partnership grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on management's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. There were no allowances for doubtful accounts as of December 31, 2012.

Property and Equipment

Property and equipment are recorded at cost. Improvements or betterments that extend the useful life of the assets are capitalized. Expenditures for maintenance and repairs are charged to expense when incurred. The costs of assets retired or otherwise disposed of and the related accumulated depreciation are eliminated from the accounts in the period of disposal. Gains or losses resulting from property disposals are credited or charged to operations currently. Depreciation is recorded using the straight-line method over the estimated useful lives of the assets.

Goodwill

Goodwill represents the excess of cost over the fair value of net assets of acquired businesses. Goodwill is not amortized, but instead the Partnership evaluates goodwill for impairment annually, or more often if events or circumstances indicate that the asset might be impaired.

Impairments of Long-Lived Assets

In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment", long-lived assets, such as property and equipment and finite-lived intangibles subject to amortization, are reviewed for impairment whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 for the year ended December 31, 2012 and concluded that no impairment of long-lived assets existed.

Non-Controlling Interests

The Partnership has four consolidated subsidiaries in which outside parties own interests. The Partnership's ownership interests in these subsidiaries range from 74% to 75%. The non-controlling

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

interest shown in the Partnership's consolidated financial statements represents the other owners' interests in these entities.

Environmental

The Partnership is subject to extensive federal, state, and local environmental laws and regulations. These laws regulate the discharge of materials into the environment and may require the Partnership to remove or mitigate the adverse environmental effects of the disposal or release of petroleum or chemical substances at various sites. Environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

The Partnership may be subject to removal and restoration costs upon retirement of its facilities. Management is currently unable to predict when, or if, these facilities will become obsolete and require restoration. Accordingly, no provision for this liability has been made in these financial statements as both the amount and timing of such potential future costs are indeterminable.

Income Tax

The Partnership is not subject to federal income taxes; instead, the taxable earnings or losses of the Partnership are reported by the Partners in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Partnership is subject to the Texas margin tax, and a provision for this expense is included in the statement of operations.

The Partnership recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Partnership has evaluated tax positions taken or expected to be taken in the course of preparing the Partnership's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. All tax years since inception of the Partnership (August 6, 2012) remain open.

Comprehensive Income

Comprehensive income is defined as a change in equity of a business enterprise during a period from transactions and other events and circumstances from non-owner sources and includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. The Partnership has no items of comprehensive income other than net income in any period presented. Therefore, net income as presented in the consolidated statement of operations equals comprehensive income.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

3. Acquisitions

On August 28, 2012, the Partnership acquired a 74% interest in OWL Pearsall SWD, LLC, a Limited Liability Company formed to own the operating assets, contracts and proprietary information of a water services business operating in South Texas.

The fair values of the assets acquired are summarized below:


Saltwater disposal well	$	4,500,000
Permits		550,000
Goodwill		10,950,000


Fair value of assets acquired		16,000,000
Non-controlling interest		(4,160,000	)
Acquisition debt		(3,760,000	)


Consideration paid	$	8,080,000

On August 28, 2012 the Partnership paid cash of $8,080,000 and had a fixed obligation to the sellers in the amount of $3,760,000. The Partnership also paid $203,986 in transaction costs associated with the acquisition.

In December 2012, the fixed obligation of $3,760,000 was renegotiated, and the Partnership paid $8,510,000 to settle the obligation. The $4,750,000 difference between the liability recorded at the acquisition date and the amount ultimately paid to settle the liability is reported as "interest expense—non-controlling interest" in the Partnership's consolidated statement of operations. The Partnership also incurred and accrued $176,357 of interest expense related to this obligation, which is reported within "interest expense—related party" in the Partnership's consolidated statement of operations.

On December 4, 2012, the Partnership purchased a 75% interest in OWL Karnes SWD, LLC, a Limited Liability Company formed to own the operating assets, contracts and proprietary information of a water services business operating in South Texas. The Partnership paid $7,500,000 cash for the ownership interest and paid $53,776 in transaction costs associated with the acquisition.

The fair values of the assets acquired are summarized below:


Saltwater disposal well	$	5,500,000
Permits		550,000
Real estate		64,440
Goodwill		3,885,560


Fair value of assets acquired		10,000,000
Non-controlling interest		(2,500,000	)

			��
Consideration paid	$	7,500,000

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Notes to Consolidated Financial Statements (Continued)

3. Acquisitions (Continued)

On December 27, 2012 the Partnership purchased all of the ownership interest in Lotus Oilfield Services, LLC, a company engaged in the wastewater hauling business, in South Texas for approximately $11,000,000 cash, inclusive of $1,500,000 of acquisition related debt. The Partnership paid $70,747 in transaction costs associated with the acquisition.

The fair values of the assets acquired and liabilities assumed are summarized below:


Accounts receivable	$	2,903,540
Property and equipment		5,181,870
Other current assets		41,822
Goodwill		3,847,049
Accounts payable		(920,146	)
Other current liabilities		(146,444	)


Fair value of net assets acquired		10,907,691
Note payable to related party (see Note 6)		(1,500,000	)


Consideration paid	$	9,407,691

Fair Value Methodology

FASB ASC 805-20-30-1 "Business Combinations—Related Issues" states that "The acquirer shall measure the identifiable assets acquired, the liabilities assumed, and any non-controlling interest in the acquiree at their acquisition-date fair values." The determination of fair value in a business combination must be consistent with the definition of fair value and the fair value measurement principles described in FASB ASC 820 "Fair Value Measurement and Disclosures."

Below is a discussion of the methodology the Partnership used to calculate the fair values for the identifiable assets acquired and liabilities assumed.

Saltwater Disposal Well and Property Plant and Equipment

In arriving at the fair value, the Partnership utilized the cost approach using a replacement cost adjusted for various forms of depreciation.

Permits

The Partnership utilized a market approach based on recent transactions in the Eagle Ford Shale.

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Oilfield Water Lines, LP

Notes to Consolidated Financial Statements (Continued)

3. Acquisitions (Continued)

Real Estate

The Partnership valued real estate acquired using the market approach based on prior acquisitions on a per-acre basis.

Other Assets and Liabilities

The remaining assets and liabilities acquired are short-term in nature and their carrying values represent fair values at acquisition date.

4. Property and Equipment

Property and equipment at December 31, 2012 consist of the following:

	Estimated Life	Book Value

Disposal wells	2 - 30 years	$	16,245,158
Logistics equipment	2 - 7 years		5,181,869
Building, furniture and improvements	2 - 30 years		532,546
Software	3 years		24,870
Permits and bonds			1,125,000
Land			545,862


			23,655,305
Accumulated depreciation			(269,239	)


		$	23,386,066

5. Accrued Expenses

Accrued expenses at December 31, 2012 consist of the following:


Accrued wages	$	165,065
Accrued income taxes		34,368
Accrued acquisition costs		139,854
Other accrued expenses		86,489


Total accrued expenses	$	425,776

6. Related Party Debt

Related party debt at December 31, 2012 consisted of the following:


Related party note payable and interest	$	1,500,000
Related party accrued interest payable		176,357


	$	1,676,357

Related party debt is payable in installments through December 27, 2013. The note bears interest at a rate of 6% per annum.

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Notes to Consolidated Financial Statements (Continued)

7. Related Party Transactions

The Partnership enters into transactions with related parties in the normal course of business. Related party balances result from transactions with related parties.

During the period from inception (August 6, 2012) to December 31, 2012, the Partnership paid $574,000 to related parties for reimbursement of expenses paid by related parties, chemicals, equipment rental, disposal fees and other operating and miscellaneous costs. Sales to related parties totaled $268,000 for the period from inception (August 6, 2012) to December 31, 2012.

On December 5, 2012, the Partnership paid $8,510,000 to satisfy acquisition debt of $3,760,000. Accordingly, a charge of $4,750,000 was recorded as additional interest expense on the consolidated statement of operations. This amount excludes $176,357 of accrued interest associated with the note payable to a related party as of December 31, 2012.

Management Agreement

Included in the Partnership's Limited Partnership Agreement are provisions for a fee to be paid to its general partner for management expenses and overhead expenses. The fees are not to exceed $50,000 per month or 10% of distributable cash flow.

8. Commitments and Contingencies

Concentrations of Credit Risk

Financial instruments which subject the Partnership to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the Partnership's non-interest bearing cash balances were fully insured at December 31, 2012 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning in 2013, insurance coverage reverted to $250,000 per depositor at each financial institution, and the Partnership's cash balances may again exceed federally insured limits.

The Partnership's customer base consists primarily of oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the year ended December 31, 2012, one customer accounted for 76% of total revenues. There were no other customers that amounted to 10% or more of total revenues.

Trade accounts receivable are from companies within the oil and natural gas industry and, as such, the Partnership is exposed to normal industry credit risks. As of December 31, 2012, two customers constituted 20% and 14% of total accounts receivable, respectively. There were no other customers that amounted to 10% or more of total accounts receivable balance at December 31, 2012.

Risk and Uncertainties

As an independent oilfield services contractor that provides hauling services to oil and natural gas companies in Texas, the Partnership's revenue, profitability, cash flows and future rate of growth are substantially dependent on its ability to (1) maintain adequate equipment utilization, (2) maintain adequate pricing for the services it provides, and (3) maintain a trained work force. Failure to do so could adversely affect the Partnership's financial position, results of operations, and cash flows.

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Notes to Consolidated Financial Statements (Continued)

8. Commitments and Contingencies (Continued)

Because the Partnership's revenues are generated primarily from customers who are subject to the same factors generally impacting the oil and natural gas industry, the Partnership's operations are also susceptible to market volatility resulting from economic, cyclical, weather related, or other factors related to the industry. Changes in the level of operating and capital spending in the industry, decreases in oil and natural gas prices, or industry perception about future oil and natural gas prices could materially decrease the demand for the Partnership's services, adversely affecting its financial position, results of operations and cash flows.

Employment Agreement

On December 27, 2012 the Partnership entered into an employment agreement with the president of its water hauling subsidiary. The agreement has a term of two years and is renewable for an additional year on its annual anniversary, without prior written notice of intent to cancel. Included in the agreement is a provision for monthly bonuses paid to the employee based on net profits of the subsidiary and net profits of water disposal subsidiaries.

Management Agreement

Included in the Partnership's Limited Partnership Agreement dated August 31, 2012 are provisions for a fee to be paid to its general partner for management and overhead expenses. The fees are not to exceed $50,000 per month or 10% of distributable cash flow.

Litigation

The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. Management does not believe that any of these claims and actions, individually or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition, results of operations, or cash flows, although management cannot guarantee that a material adverse effect will not occur.

Capital Commitments

On August 31, 2012, a Limited Liability Company in which the Partnership owns a 75% interest was formed for the purpose of developing a water disposal facility in South Texas. Included in the Limited Liability Company Agreement is a provision to provide a carried interest to a related party in the amount of 25% of the first $5,000,000 in return for services rendered and to be rendered in the drilling of the disposal well. On December 27, 2012, a Limited Liability Company in which the Partnership owns 75% was formed for the purpose of developing a water disposal facility in South Texas. Included in the Limited Liability Company Agreement is a provision to provide a carried interest to a related party in the amount of 25% of the first $5,000,000 in return for services rendered and to be rendered in the drilling of the disposal well.

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Notes to Consolidated Financial Statements (Continued)

9. Supplemental Cash Flow Information

	Period From inception (August 6, 2012) to December 31, 2012

Cash paid for
Interest	$	17
Supplemental schedule of non-cash investing and financing activities
Financing of insurance notes	$	248,714

10. Subsequent Events

On August 2, 2013, NGL Energy Partners LP acquired all of the operating subsidiaries of Oilfield Water Lines, LP for 2,463,287 common units and $168 million in cash, plus net working capital.

The agreement with NGL Energy Partners LP includes a provision whereby the purchase price may be increased if certain performance targets are achieved. If the acquired assets generate Adjusted EBITDA, as defined in the agreement, in excess of $40 million on an annualized basis during any one of the six months following the acquisition, the purchase price will be increased by six times the amount by which this annualized target is exceeded. The maximum potential increase to the purchase price under this provision is $60 million.

The Partnership has evaluated subsequent events through September 27, 2013, the date the financial statements were available for issuance.

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Independent Auditor's Report

The Partners'
High Roller Wells Pearsall SWD No.1, Ltd.
Center, Texas

We have audited the accompanying financial statements of High Roller Wells Pearsall SWD No.1, Ltd. (the "Partnership"), which comprise the statements of operations, partners' capital and cash flows for the period from January 1, 2012 through August 28, 2012, and the related notes to the financial statements.

Management's Responsibility for the Financial Statements

�� Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

Our responsibility is to express an opinion on these financial statements based on our audit. We conducted our audit in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor's judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity's preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations of High Roller Wells Pearsall SWD No.1, Ltd. and its cash flows for the period from January 1, 2012 through August 28, 2012 in accordance with accounting principles generally accepted in the United States of America.

Basis of Presentation

As discussed in Note 1, these financial statements reflect the results of operations of the Partnership through the date on which substantially all operating assets were contributed to a newly formed entity in preparation for sale. These financial statements are not intended to be indicative of the actual operations of the Partnership for a full year.

/s/ BDO USA, LLP
Dallas, Texas
September 27, 2013

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High Roller Wells Pearsall SWD No. 1, Ltd.

Statement of Operations

	Period from January 1, 2012 through August 28, 2012

Revenues
Water disposal services	$	4,254,661
Crude oil sales		4,746,835


Total revenues		9,001,496
Expenses
Well servicing		3,566,967
General and administrative		571,058
Depreciation and amortization		242,846


Total expenses		4,380,871
Operating income		4,620,625
Other Expense
Interest expense		(11,514	)


Income before taxes		4,609,111
Income tax expense		(68,400	)


Net income	$	4,540,711

The accompanying notes are an integral part of these financial statements.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Statement of Partners' Capital

	Partners' Capital

Balance at December 31, 2011	$	1,698,645
Contributions		1,123,595
Withdrawals		(2,850,671	)
Net income		4,540,711


Balance at August 28, 2012	$	4,512,280

The accompanying notes are an integral part of these financial statements.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Statement of Cash Flows

	Period from January 1, 2012 through August 28, 2012

Cash flows from operating activities
Net income	$	4,540,711
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		242,846
Changes in operating assets and liabilities:
Accounts receivable		(1,092,314	)
Accounts receivable—related parties		(268,597	)
Other current assets		(23,924	)
Accounts payable—trade		472,556
Accounts payable—related parties		(810,396	)
Accrued expenses		657,805


Net cash provided by operating activities		3,718,687


Cash flows from investing activities
Purchases of property and equipment		(1,511,575	)


Net cash used in investing activities		(1,511,575	)


Cash flows from financing activities
Partner Contributions		1,123,595
Partner Withdrawals		(2,850,671	)


Net cash used in financing activities		(1,727,076	)


Net increase in cash and cash equivalents		480,036
Cash and cash equivalents
Beginning of period		78


End of period	$	480,114

The accompanying notes are an integral part of these financial statements.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Financial Statements

1. Organization and Nature of Operations

Formation Transactions

High Roller Wells Pearsall SWD No. 1, Ltd. ("Partnership") is a Texas Limited Partnership formed on November 18, 2011. The Partnership had an initial capitalization of $287,891 representing the net assets of an existing business contributed to the partnership by its partners.

The initial assets contributed to the Partnership are summarized as follows:


Tangible well equipment	$	538,315
Intangible drilling costs		809,985


Total assets		1,348,300
Current liabilities		1,060,509


Net assets	$	287,791

Basis of Presentation

The financial statements have been prepared to report the results of operations of the Partnership through the date of acquisition by Oilfield Water Lines, LP (the "Acquirer"). Such financial statements, rather than complete financial statements, are presented because the primary operating assets were acquired by Oilfield Water Lines, LP and ceased to be operated by the Partnership. The financial statements presented are not representative of the actual operations of the Partnership for a full year.

Nature of Business

The Partnership is engaged in the water services business, the assets of which include water treatment and disposal facilities. The Partnership generates revenues from the gathering, treatment, and disposal of wastewater generated from oil and natural gas production operations, and from the sale of recovered hydrocarbons.

2. Summary of Significant Accounting Policies

Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of the Partnership's revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that management believes are reasonable under the circumstances. Although management believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records water disposal revenues at the time the service is performed, which is upon receipt of the wastewater at the disposal facilities.

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Notes to Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Depreciation and Amortization

Depreciation and amortization in the statement of operations includes depreciation and amortization of the Partnership's property, plant and equipment.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase.

Accounts Receivable and Concentration of Credit Risk

The Partnership grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on the Partnership's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes.

Property, Plant and Equipment

The Partnership records property, plant and equipment at cost, less accumulated depreciation. Acquisitions and improvements are capitalized, and maintenance and repairs are expensed as incurred. The Partnership computes depreciation expense using the straight-line method over the estimated useful lives of the assets, which ranges from three to thirty years.

Impairments

In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment, are reviewed whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 which resulted in no impairment for the period from January 1, 2012 through August 28, 2012.

Environmental

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Notes to Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

Income taxes

The Partnership is not subject to federal income taxes; instead, the taxable earnings or losses of the Partnership are reported by the Partners' in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Partnership is subject to the Texas margin tax, and a provision for this expense is included in the statement of operations.

The Partnership recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Partnership has evaluated tax positions taken or expected to be taken in the course of preparing the Partnership's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Partnership remain open.

3. Related Party Transactions

The Partnership enters into transactions with related parties in the normal course of conducting business.

The Partnership pays royalties of 9% of crude oil sales and $0.05 per barrel of water disposal to one of its partners, the seller of the mineral rights. Total royalties paid during the period ended August 28, 2012 were $675,612.

For the period ended August 28, 2012, the Partnership had sales totaling $70,439 to a related party. The Partnership paid $1,569,250 to related parties for reimbursement of Partnership expenses paid by related parties, chemicals, freight, equipment rental, disposal fees and other operating and miscellaneous costs.

During the period ended August 28, 2012, the Partnership paid $15,000 per month to an affiliate for accounting and administrative support.

4. Commitments and Contingencies

Concentrations of Credit Risk

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Financial Statements (Continued)

4. Commitments and Contingencies (Continued)

December 28, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.

The Partnership's customer base consists primarily of multi-national and independent oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the period ended August 28, 2012, two customers accounted for 59% and 12% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues for the period ended August 28, 2012.

Litigation

The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. The Partnership does not believe that any of these claims and actions, separately or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition, results of operations, or cash flows, although no guarantee can be made that a material adverse effect will not occur.

5. Subsequent Events

On August 28, 2012, the Partnership contributed all assets, excluding cash and accounts receivable, and certain contracts and proprietary information, to a newly-formed limited liability company ("Newco"). Contemporaneously, the partners of the Partnership entered into a Purchase and Sale Agreement with Oilfield Water Lines, LP for the sale of 74% of the membership interests of Newco.

The Partnership has evaluated all subsequent events through September 27, 2013, the date the financial statements were available for issuance.

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Independent Auditor's Report

The Partners
High Roller Wells Karnes SWD No.1, Ltd.
Center, Texas

We have audited the accompanying financial statements of High Roller Wells Karnes SWD No.1, Ltd. (the "Partnership"), which comprise the statements of operations and partners' capital and cash flows for the period from inception (March 14, 2012) through December 4, 2012, and the related notes to the financial statements.

Management's Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free from material misstatement, whether due to fraud or error.

Auditor's Responsibility

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations and cash flows of High Roller Wells Karnes SWD No.1, Ltd. for the period from inception (March 14, 2012) through December 4, 2012 in accordance with accounting principles generally accepted in the United States of America.

Basis of Presentation

/s/ BDO USA, LLP
Dallas, Texas
September 27, 2013

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High Roller Wells Karnes SWD No. 1, Ltd.

Statement of Operations and Partners' Capital

	Period from inception (March 14, 2012) through December 4, 2012

Revenues
Water disposal services	$	1,323,392
Crude oil sales		3,335,524


Total revenues		4,658,916


Expenses
Well servicing		2,323,408
General and administrative		221,367
Depreciation		301,148


Total expenses		2,845,923


Operating income		1,812,993
Other Income (Expense)
Interest expense		(18,468	)


Income before taxes		1,794,525


Provision for taxes		(26,800	)


Net income		1,767,725
Partners' Capital, at inception		—
Capital Contributions		5,400,000


Partners' Capital, at December 4, 2012	$	7,167,725

The accompanying notes are an integral part of these financial statements.

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High Roller Wells Karnes SWD No. 1, Ltd.

Statement of Cash Flows

	Period from inception (March 14, 2012) through December 4, 2012

Cash flows from operating activities
Net income	$	1,767,725
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		301,148
Changes in operating assets and liabilities:
Accounts receivable		(438,377	)
Other current assets		(4,640	)
Accounts payable		288,504
Accrued expenses		298,500


Net cash provided by operating activities		2,212,860


Cash flows from investing activities
Purchases of property and equipment		(7,085,110	)


Net cash used in investing activities		(7,085,110	)


Cash flows from financing activities
Partner contributions		5,400,000
Borrowings on debt—related party		800,000
Repayment of debt—related party		(400,000	)


Net cash provided by financing activities		5,800,000


Net increase in cash and cash equivalents		927,750
Cash and cash equivalents, at inception		—


Cash and cash equivalents, at December 4, 2012	$	927,750

The accompanying notes are an integral part of these financial statements.

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High Roller Wells Karnes SWD No. 1, Ltd.

Notes to Financial Statements

1. Organization and Nature of Operations

Formation Transactions

High Roller Wells Karnes SWD No. 1, Ltd. (the "Partnership") is a Texas Limited Liability Company formed on March 14, 2012. The Partnership had an initial capitalization of $250,000 with partner commitments for additional contributions as needed for working capital. Additional capital contributions made through December 4, 2012 totaled $5,150,000.

Basis of Presentation

As described in Note 6, Oilfield Water Lines, LP acquired a controlling interest in the Partnership on December 4, 2012. These financial statements have been prepared to report the results of operations of the Partnership through the date of acquisition by Oilfield Water Lines, LP (the "Acquirer"). Such financial statements, rather than complete financial statements, are presented because the primary operating assets were acquired by Oilfield Water Lines, LP and ceased to be operated by the Partnership. The financial statements presented are not representative of the actual operations of the Partnership for a full year.

Nature of Business

2. Summary of Significant Accounting Policies

Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of the Partnership's revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that management believes to be reasonable under the circumstances. Although management believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records water disposal revenues at the time the service is performed, which is upon receipt of the wastewater at the disposal facilities.

Depreciation

Depreciation in the statement of operations includes all depreciation of property, plant and equipment. Property, plant and equipment consist primarily of water treatment and disposal facilities, which have an estimated useful life of 30 years.

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High Roller Wells Karnes SWD No. 1, Ltd.

Notes to Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase.

Impairments

In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment, are reviewed whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 which resulted in no impairment for the period from inception (March 14, 2012) through December 4, 2012.

Environmental

Income taxes

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High Roller Wells Karnes SWD No. 1, Ltd.

Notes to Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Partnership remain open.

3. Long-Term Debt—Related Party

On August 21, 2012, the Partnership executed a loan agreement with an entity owned by its partners whereby it borrowed a total of $800,000. The Partnership made principal payments on the note totaling $400,000 through December 4, 2012, leaving a principal balance of $400,000 at December 4, 2012. The note bore interest at a rate of 4% per with a maturity date of August 21, 2014. The note was subsequently paid in full on December 4, 2012.

4. Related Party Transactions

The Partnership enters into transactions with related parties in the normal course of conducting business.

The Partnership pays royalties of 9% of crude oil sales and $0.05 per barrel of water disposal to the related party land owner for disposal operations. Total royalties paid during the period ended December 4, 2012 were $411,566.

Throughout 2012, the Partnership paid $15,000 per month to an affiliate for administrative support.

During the period ended December 4, 2012, the Partnership paid approximately $257,000 for construction labor provided by an affiliate at the Partnership's well site.

In 2012, the Partnership borrowed a total of $800,000 from an entity owned by its partners (see Note 3 above). Related party interest expense was $18,468 for the period ended December 4, 2012.

5. Commitments and Contingencies

Concentrations of Credit Risk

The Partnership's customer base consists primarily of multi-national and independent oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the period ended December 4, 2012, one customer accounted for 72% of total revenues. There were no other customers that amounted to 10% or more of total revenues.

Litigation

The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. Management does not believe that any of these claims and actions, separately or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition,

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High Roller Wells Karnes SWD No. 1, Ltd.

Notes to Financial Statements (Continued)

5. Commitments and Contingencies (Continued)

results of operations, or cash flows, although no guarantee can be made that a material adverse effect will not occur.

6. Subsequent Events

On December 4, 2012, the Partnership contributed all assets, excluding cash, accounts receivable, certain contracts and proprietary information, to a newly-formed limited liability company ("Newco"). Contemporaneously, the partners of the Partnership entered into a Purchase and Sale Agreement with Oilfield Water Lines, LP for the sale of 75% of the membership interests of Newco.

The Partnership has evaluated subsequent events through September 27, 2013, the date the financial statements were available for issuance.

F-317

Table of Contents

Independent Auditor's Report

The Members
Lotus Oilfield Services, LLC
Alice, TX

We have audited the accompanying financial statements of Lotus Oilfield Services, LLC (the "Company"), which comprise the statements of operations, changes in members' equity, and cash flows for the period from January 1, 2012 to December 27, 2012, and the related notes to the financial statements.

Management's Responsibility for the Financial Statements

Auditor's Responsibility

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the results of operations of Lotus Oilfield Services, LLC and its cash flows for the period of January 1, 2012 to December 27, 2012 in accordance with accounting principles generally accepted in the United States of America.

Basis of Presentation

As discussed in Note 1, these financial statements reflect the results of operations of the Company through the date on which all members' interests were sold.

/s/ BDO USA, LLP
Dallas, Texas
September 27, 2013

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Lotus Oilfield Services, LLC

Statement of Operations

	Period from January 1, 2012 to December 27, 2012

Trucking revenues	$	8,402,100
Expenses
Equipment expenses		6,935,858
General and administrative		232,259
Depreciation and amortization		409,150


Total expenses		7,577,267


Operating income		824,833
Other income (expense)
Interest expense		(131,924	)
Other income, net		13,643


Income before income taxes		706,552
Provision for income taxes		(35,900	)


Net income	$	670,652

The accompanying notes are an integral part of these financial statements.

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Lotus Oilfield Services, LLC

Statement of Changes in Members' Equity

	Members' Equity		Retained Earnings		Total

Balance at December 31, 2011	$	31,973	$	500,314	$	532,287
Member contributions		12,110		—		12,110
Net income		—		670,652		670,652


Balance at December 27, 2012	$	44,083	$	1,170,966	$	1,215,049

The accompanying notes are an integral part of these financial statements.

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Lotus Oilfield Services, LLC

Statement of Cash Flows

	Period from January 1, 2012 to December 27, 2012

Cash flows from operating activities
Net income	$	670,652
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization expense		409,150
Gain on sale of equipment		24,152
Changes in operating assets and liabilities:
Accounts receivable		(2,374,663	)
Accounts receivable—related parties		(1,572	)
Prepaid expenses and other current assets		6,428
Accounts payable—trade		646,322
Accounts payable—related parties		1,851,031
Accrued expenses		149,787


Net cash provided by operating activities		1,381,287


Cash flows from investing activities
Purchases of property and equipment		(4,314,725	)
Proceeds from sale of property and equipment		65,404


Net cash used in investing activities		(4,249,321	)


Cash flows from financing activities
Borrowings on line of credit		303,948
Increase in equipment obligations		2,583,565
Partner contributions		12,110


Net cash provided by financing activities		2,899,623


Net increase in cash and cash equivalents		31,589
Cash and cash equivalents
Beginning of period		60,720


End of period	$	92,309

The accompanying notes are an integral part of these financial statements.

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Lotus Oilfield Services, LLC

Notes to Financial Statements

1. Organization and Nature of Operations

Nature of Business

Lotus Oilfield Services, LLC (the "Company") is an oilfield services contractor that provides fluid hauling services from well sites to reclamation and disposal sites. The Company's primary operating assets are tractors and trailers utilized in the hauling services business. The Company is a Texas Limited Liability Company formed April 19, 2010.

Basis of Presentation

As described in Note 8, on December 27, 2012, the Company was acquired by OWL Lotus, LLC (the "Acquirer"). The financial statements have been prepared to report the results of operations of the Company through the date of acquisition by the Acquirer.

2. Risk and Uncertainties

As an independent oilfield services contractor that provides hauling services to oil and natural gas companies in Texas, the Company's revenue, profitability, cash flows and future rate of growth are substantially dependent on the Company's ability to (1) maintain adequate equipment utilization, (2) maintain adequate pricing for the services the Company provides, and (3) maintain a trained work force. Failure to do so could adversely affect the Company's financial position, results of operations, and cash flows.

Because the Company's revenues are generated primarily from customers who are subject to the same factors generally impacting the oil and natural gas industry, the Company's operations are also susceptible to market volatility resulting from economic, cyclical, weather related, or other factors related to such industry. Changes in the level of operating and capital spending in the industry, decreases in oil and natural gas prices, or industry perception about future oil and natural gas prices could materially decrease the demand for the Company's services, adversely affecting the Company's financial position, results of operations and cash flows.

3. Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles in the United States ("GAAP") requires the Company to make estimates and assumptions that affect the reported amounts of the Company's revenues, expenses and costs. These estimates are based on the Company's knowledge of current events, historical experience, and various other assumptions that the Company believes to be reasonable under the circumstances.

Critical estimates made in the preparation of the Company's financial statements include the collectability of accounts receivable, estimates of useful lives and recoverability of property, plant and equipment, and accruals for various commitments and contingencies, among others. Although the Company believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

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Lotus Oilfield Services, LLC

Notes to Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

determinable. In accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 605-45 "Principal Agent Considerations" ("ASC 605-45") revenues are presented net of any sales taxes collected by Lotus Oilfield Services from its customers that are remitted to governmental authorities.

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

The Company grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on the Company's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes.

Property and Equipment

Impairments

In accordance with ASC Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment are reviewed whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Company evaluated its asset group in accordance with ASC 360 which resulted in no impairment for the period ended December 27, 2012.

Income taxes

The Company is not subject to federal income taxes, rather the taxable earnings or losses of the Company are reported by the members in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Company is subject to the Texas margin tax, an income tax, and a provision for this expense is included in the statement of operations.

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Table of Contents

Lotus Oilfield Services, LLC

Notes to Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

The Company recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Company has evaluated tax positions taken or expected to be taken in the course of preparing the Company's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Company remain open.

4. Equipment Notes Payable

During the year ended December 31, 2011, the Company financed the purchase of certain vehicles and equipment through loans with commercial lenders. These loans were repayable in monthly installments with maturity dates through February 2016. Interest accrued at rate of 6% and was payable monthly. The loans were collateralized by equipment purchased with the proceeds of such loans and by second liens on accounts receivable. All notes were retired subsequent to December 27, 2012 in connection with the acquisition of the Company (see Note 8).

5. Related Party Transactions

The Company enters into transactions with related parties in the normal course of conducting business.

During the period ended December 27, 2012, the Company paid $1,164,000 to related parties for reimbursement of expenses paid by related parties, chemicals, equipment rental, disposal fees and other operating and miscellaneous costs. Sales to related parties totaled $360,167 for the period ended December 27, 2012.

The Company borrowed funds from related parties during the period ended December 27, 2012. Interest accrued at rate of 6% and interest expense relating to these borrowings was $13,939 for the period ended December 27, 2012.

6. Commitments and Contingencies

Concentrations of Credit Risk

Financial instruments which subject the Company to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the Company's non-interest bearing cash balances were fully insured at December 27, 2012 due to a temporary federal program in effect from December 31, 2010 through December 28, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.

The Company's customer base consists primarily of multi-national and independent oil and natural gas producers. The Company does not require collateral on its trade receivables. For the period ended December 27, 2012, two customers accounted for 14% and 11% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues for the period ended December 27, 2012.

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Lotus Oilfield Services, LLC

Notes to Financial Statements (Continued)

6. Commitments and Contingencies (Continued)

Litigation

The Company is subject to various other claims and legal actions that arise in the ordinary course of business. The Company does not believe that any of these claims and actions, separately or in the aggregate, will have a material adverse effect on the Company's business, financial condition, results of operations, or cash flows, although the Company cannot guarantee that a material adverse effect will not occur.

7. Supplemental Cash Flow Information

	Periods from January 1, 2012 to December 27, 2012

Cash paid for
Interest	$	57,312

8. Subsequent Events

On December 27, 2012, the Company was acquired by OWL Lotus, LLC. This acquisition has not been pushed down to the Company and these financial statements reflect no adjustments for acquisition accounting under ASC 805.

On December 27, 2012, the Company entered into an employment agreement with its president. The agreement has a term of two years and is renewable for an additional year on its annual anniversary, without prior written notice of intent to cancel. Included in the agreement is a provision for monthly bonuses paid to the employee based on net profits of the Company and net profits of related party entities.

The Company has evaluated subsequent events through September 27, 2013, the date the financial statements were available for issuance.

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Table of Contents

Oilfield Water Lines, LP

Unaudited Condensed Consolidated Balance Sheets

	June 30, 2013		December 31, 2012

Assets
Current assets
Cash and cash equivalents	$	1,143,664	$	3,853,865
Accounts receivable—trade		7,143,976		3,834,236
Prepaid expenses and other		1,293,772		323,158


Total current assets		9,581,412		8,011,259
Property and equipment, net		32,816,035		23,386,066
Goodwill		18,681,334		18,682,609
Receivables from affiliates		72,573		—
Other assets		591,697		325,749


Total assets	$	61,743,051	$	50,405,683




Liabilities and capital
Current liabilities
Accounts payable—trade	$	3,630,360	$	4,333,007
Book overdrafts		655,653		—
Insurance notes payable		—		248,714
Accrued expenses		2,189,950		425,776
Current portion of long-term debt		1,046,953		—
Related party debt		1,880,016		1,676,357


Total current liabilities		9,402,932		6,683,854


Long-term debt		1,902,948		—
Commitments and contingencies (Note 7)
Capital
General partner (0.1%)		24,678		19,466
Limited partners (99.9%)		43,126,220		37,369,386


Total partners' capital		43,150,898		37,388,852


Non-controlling interests		7,286,273		6,332,977
Total capital		50,437,171		43,721,829


Total liabilities and capital	$	61,743,051	$	50,405,683

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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Oilfield Water Lines, LP

Unaudited Condensed Consolidated Statement of Operations

	Six Months Ended June 30, 2013

Revenues
Crude oil sales	$	12,590,048
Water disposal services		3,474,691
Trucking revenue		8,029,506


Total revenues		24,094,245
Expenses
Well servicing		11,920,178
General and administrative		2,983,318
Loss on sale of assets		13,902
Depreciation		1,296,590


Total expenses		16,213,988
Operating income		7,880,257
Interest expense		(123,097	)


Income before income taxes		7,757,160
Provision for income taxes		(156,331	)


Net income		7,600,829


Net income attributable to non-controlling interest		2,388,148


Net income attributable to partners	$	5,212,681

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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Oilfield Water Lines, LP

Unaudited Condensed Consolidated Statement of Changes in Capital

	General Partner		Limited Partners			Non- Controlling Interest			Total Capital

Balance at December 31, 2012	$	19,466	$	37,369,386		$	6,332,977		$	43,721,829
Contributions		—		3,673,943			514,040			4,187,983
Distributions		—		(3,124,578	)		(1,948,892	)		(5,073,470	)
Net income		5,212		5,207,469			2,388,148			7,600,829


Balance at June 30, 2013	$	24,678	$	43,126,220		$	7,286,273		$	50,437,171

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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Oilfield Water Lines, LP

Unaudited Condensed Consolidated Statement of Cash Flows

	Six Months Ended June 30, 2013

Cash flows from operating activities
Net income	$	7,600,829
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation expense		1,296,590
Provision for doubtful accounts		258,000
Changes in operating assets and liabilities:
Accounts receivable		(3,567,740	)
Accounts receivable—affiliates		(72,573	)
Prepaid expenses and other current assets		(970,614	)
Other assets		(265,948	)
Accounts payable—trade		(702,647	)
Book overdrafts		655,653
Accrued expenses and other liabilities		1,765,808
Related party debt		203,659


Net cash provided by operating activities		6,201,017


Cash flows from investing activities
Purchases of property and equipment		(10,726,919	)


Net cash used in investing activities		(10,726,919	)


Cash flows from financing activities
Proceeds from borrowings		2,949,902
Payment of insurance note payable		(248,714	)
Contributions from partners		4,187,983
Distributions to non-controlling interests		(1,948,892	)
Withdrawals by partners		(3,124,578	)


Net cash provided by financing activities		1,815,701


Net decrease in cash and cash equivalents		(2,710,201	)
Cash and cash equivalents
Beginning of period		3,853,865


End of period	$	1,143,664

The accompanying notes are an integral part of these unaudited condensed
consolidated financial statements.

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Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements

1. Organization and Nature of Business

2. Summary of Significant Accounting Policies

Principles of Consolidation

The Partnership's consolidated financial statements as of June 30, 2013 and for the six months then ended include the accounts of Oilfield Water Lines, LP and its controlled subsidiaries, which are HR OWL, LLC, OWL Operating, LLC, OWL Pearsall SWD, LLC, OWL Karnes SWD, LLC, OWL Cotulla SWD, LLC, OWL Nixon SWD, LLC, OWL Lotus, LLC and Lotus Oilfield Services, LLC. All significant intercompany balances and transactions have been eliminated in consolidation.

The accompanying unaudited condensed consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim consolidated financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed consolidated financial statements include all adjustments that the Partnership considers necessary for a fair presentation of the financial position and results of operations for the interim period presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed consolidated financial statements do not include all the information and notes required by GAAP for complete annual consolidated financial statements. However, the Partnership believes that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed consolidated financial statements should be read in conjunction with the audited financial statements of the Partnership for the period from inception (August 6, 2012) through December 31, 2012. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Use of Estimates

The preparation of financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of the Partnership's assets, liabilities, revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that it believes to be reasonable under the circumstances.

Revenue Recognition

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Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

The Partnership generally recognizes revenue when the customer takes ownership or assumes the risk of loss; collection of the relevant receivable is probable, persuasive evidence of arrangement exists; and the transaction price is fixed or determinable. Revenues are presented net of any sales taxes collected by the Partnership from its customers and remitted to taxing authorities.

Cash and Cash Equivalents

The Partnership considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

The Partnership grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on management's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. The allowance for doubtful accounts was $258,000 and $-0- at June 30, 2013 and December 31, 2012, respectively.

Property and Equipment

Goodwill

Impairments of Long-Lived Assets

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Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 for the six months ended June 30, 2013 and concluded that no impairment of long-lived assets existed.

Non-Controlling Interests

The Partnership has four consolidated subsidiaries in which outside parties own interests. The Partnership's ownership interests in these subsidiaries range from 74% to 75%. The non-controlling interest shown in the Partnership's consolidated statement of operations represents the other owners' interests in these entities.

Environmental

Income Tax

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Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Comprehensive Income

3. Property and Equipment

Property and equipment consist of the following:

		June 30, 2013			December 31, 2012

Disposal wells	2 - 30 years	$	23,062,266		$	16,245,158
Logistics equipment	2 - 7 years		8,825,550			5,181,869
Building, furniture and improvements	2 - 30 years		765,670			532,546
Software	3 years		24,870			24,870
Permits and bonds			1,125,000			1,125,000
Land			569,148			545,862


			34,372,504			23,655,305
Accumulated depreciation			(1,556,469	)		(269,239	)


		$	32,816,035		$	23,386,066

4. Accrued Expenses

Accrued expenses consist of the following:

	June 30, 2013		December 31, 2012

Accrued wages	$	623,542	$	165,065
Accrued income taxes		170,918		34,368
Accrued acquisition costs		—		139,854
Other accrued expenses		1,395,490		86,489


Total accrued expenses	$	2,189,950	$	425,776

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Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

5. Related Party Debt

Related party debt consisted of the following:

	June 30, 2013		December 31, 2012

Related party note payable and interest	$	1,500,000	$	1,500,000
Related party accrued interest payable		22,500		176,357
Related party accounts payable		357,516		—


	$	1,880,016	$	1,676,357

Related party debt is payable in installments through December 27, 2013. The note bears interest at a rate of 6% per annum.

6. Related Party Transactions

The Partnership enters into transactions with related parties in the normal course of business. Related party balances result from transactions with related parties.

During the six months ended June 30, 2013, the Partnership paid $4,743,174 to related parties for reimbursement of expenses paid by related parties, chemicals, equipment rental, disposal fees and other operating and miscellaneous costs. Sales to related parties totaled $30,174 for the six months ended June 30, 2013.

Management Agreement

7. Commitments and Contingencies

Concentrations of Credit Risk

Financial instruments which subject the Partnership to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the Partnership's non-interest bearing cash balances were fully insured at December 31, 2012 due to a temporary federal program in effect from December 31, 2010 through December 31, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts. Beginning 2013, insurance coverage reverted to $250,000 per depositor at each financial institution, and the Partnership's non-interest bearing cash balances may again exceed federally insured limits. The Partnership restricts investment of temporary cash investments to financial institutions with high credit standings.

The Partnership's customer base consists primarily of multi-national and independent oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the six months ended June 30, 2013, three customers accounted for 29%, 22%, and 17% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues.

Trade accounts receivable are from companies within the oil and natural gas industry and as such the Partnership is exposed to normal industry credit risks. At June 30, 2013, one customer accounted

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Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

7. Commitments and Contingencies (Continued)

for 37% of total accounts receivable. As of December 31, 2012, two customers constituted 20% and 14% of total accounts receivable, respectively. There were no other customers that amounted to 10% or more of total accounts receivable balance at June 30, 2013 or December 31, 2012.

Risks and Uncertainties

Employment Agreement

Management Agreement

Included in the Partnership's Limited Partnership Agreement dated August 31, 2012 are provisions for a fee to be paid to its general partner for management expenses and overhead expenses. The fees are not to exceed $50,000 per month or 10% of distributable cash flow.

Litigation

Capital Commitments

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Oilfield Water Lines, LP

Notes to Unaudited Condensed Consolidated Financial Statements (Continued)

7. Commitments and Contingencies (Continued)

drilling of the disposal well. On December 27, 2012, a Limited Liability Company in which the Partnership owns 75% was formed for the purpose of developing a water disposal facility in South Texas. Included in the Limited Liability Company Agreement is a provision to provide a carried interest to a related party in the amount of 25% of the first $5,000,000 in return for services rendered and to be rendered in the drilling of the disposal well.

8. Supplemental Cash Flow Information

	Six Months Ended June 30, 2013

Cash paid for
Interest	$	78,098

9. Subsequent Events

On August 2, 2013, NGL Energy Partners LP acquired all of the operating subsidiaries of Oilfield Water Lines, LP for 2,463,287 common units and $168 million in cash, plus net working capital.

The agreement with NGL Energy Partners LP includes a provision whereby the purchase price may be increased if certain performance targets are achieved. If the acquired assets generate Adjusted EBITDA, as defined in the agreement, in excess of $40 million on an annualized basis during any one of the six months following the acquisition, the purchase price will be increased by six times the amount by which this target is exceeded. The maximum potential increase to the purchase price under this provision is $60 million.

The Partnership has evaluated subsequent events through October 17, 2013, the date the financial statements were available for issuance.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Unaudited Condensed Statement of Operations

	Six Months Ended June 30, 2012

Revenues
Water disposal services	$	3,177,552
Crude oil sales		3,703,352


Total revenues		6,880,904
Expenses
Well servicing		2,649,793
General and administrative		163,924
Depreciation		170,646


Total expenses		2,984,363
��

Income before taxes		3,896,541
Income tax expense		(53,487	)


Net income	$	3,843,054

The accompanying notes are an integral part of these unaudited condensed financial statements.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Unaudited Condensed Statement of Cash Flows

	Six Months Ended June 30, 2012

Cash flows from operating activities
Net income	$	3,843,054
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		170,646
Changes in operating assets and liabilities:
Accounts receivable		(1,465,585	)
Accounts receivable—related parties		(363,207	)
Other current assets		(36,036	)
Accounts payable—trade		503,776
Accounts payable—related parties		(548,399	)
Accrued expenses		35,982


Net cash provided by operating activities		2,140,231


Cash flows from investing activities
Purchases of property and equipment		(1,384,559	)


Net cash used in investing activities		(1,384,559	)


Cash flows from financing activities
Partner Contributions		1,760,134
Partner Withdrawals		(2,183,014	)


Net cash used in financing activities		(422,880	)


Net increase in cash and cash equivalents		332,792
Cash and cash equivalents
Beginning of period		78


End of period	$	332,870

The accompanying notes are an integral part of these unaudited condensed financial statements.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Unaudited Condensed Financial Statements

1. Organization and Nature of Operations

Formation

High Roller Wells Pearsall SWD No. 1, Ltd. ("Partnership") is a Texas Limited Partnership formed on November 18, 2011.

Basis of Presentation

The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed financial statements include all adjustments that the Partnership considers necessary for a fair presentation of the financial position and results of operations for the interim period presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed financial statements do not include all the information and notes required by GAAP for complete annual financial statements. However, the Partnership believes that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed financial statements should be read in conjunction with the audited financial statements of the Partnership for the period from January 1, 2012 through August 28, 2012. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Nature of Business

2. Summary of Significant Accounting Policies

Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of the Partnership's revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that management believes to be reasonable under the circumstances. Although management believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records disposal revenues at the time the service is performed, which is upon receipt of the wastewater at the disposal facilities.

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Unaudited Condensed Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Depreciation

Depreciation in the statement of operations includes depreciation of the Partnership's property, plant and equipment.

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase.

Accounts Receivable and Concentration of Credit Risk

The Partnership grants unsecured credit to customers under normal industry standards and terms and evaluates each customer's creditworthiness as well as general economic conditions. An allowance for doubtful accounts is established, if necessary, based on the Partnership's assessment of the collectability of customer accounts, which assessment considers the overall creditworthiness of customers and any specific disputes. There was no allowance for doubtful accounts as of June 30, 2012.

Property, Plant and Equipment

Impairments

In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment, are reviewed for impairment whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 for the six months ended June 30, 2012 and concluded that no impairment of long-lived assets existed.

Environmental

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Unaudited Condensed Financial Statements (Continued)

2. Summary of Significant Accounting Policies (Continued)

Liabilities for expenditures of a non-capital nature are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated.

Income taxes

The Partnership is not subject to federal income taxes, rather the taxable earnings or losses of the Partnership are reported by the Partners' in their separate income tax returns. Accordingly, no provision for federal income taxes has been made in these financial statements. The Partnership is subject to the Texas margin tax, and a provision for this expense is included in the statements of operations.

The Partnership recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Partnership has evaluated tax positions taken or expected to be taken in the course of preparing the Partnership's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Partnership remain open.

3. Related Party Transactions

The Partnership enters into transactions with related parties in the normal course of conducting business. Accounts payable-affiliates result from transactions with affiliates which the Partnership believes are at terms consistent with those available to third-party customers and from third-party vendors.

For the six months ended June 30, 2012, the Partnership had sales totaling $36,715 to a related party. The Partnership paid $648,975 to related parties for reimbursement of Partnership expenses paid by related parties, chemicals, freight, equipment rental, disposal fees and other operating and miscellaneous costs.

During the six months ended June 30, 2012, the Partnership paid $15,000 per month to an affiliate for accounting and administrative support.

4. Commitments and Contingencies

Concentrations of Credit Risk

Financial instruments which subject the Partnership to credit risk consist primarily of cash balances maintained in excess of federal depository insurance limits and trade receivables. All of the

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High Roller Wells Pearsall SWD No. 1, Ltd.

Notes to Unaudited Condensed Financial Statements (Continued)

4. Commitments and Contingencies (Continued)

Partnership's non-interest bearing cash balances were fully insured at June 30, 2012 due to a temporary federal program in effect from December 31, 2010 through December 28, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.

The Partnership's customer base consists primarily of multi-national and independent oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the six months ended June 30, 2012, three customers accounted for 28%, 14%, and 12% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues for the six months ended June 30, 2012.

Litigation

The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. The Partnership does not believe that any of these claims and actions, individually or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition, results of operations, or cash flows, although no guarantee can be made that a material adverse effect will not occur.

5. Subsequent Events

The Partnership has evaluated subsequent events through October 17, 2013, the date the financial statements were available for issuance.

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High Roller Wells Karnes SWD No. 1, Ltd.

Unaudited Condensed Statement of Operations

	Period from inception (March 14, 2012) through June 30, 2012

Revenues
Water disposal services	$	247,456
Crude oil sales		400,987


Total revenues		648,443


Expenses
Well servicing		482,800
General and administrative		61,978
Depreciation		64,010


Total expenses		608,788


Operating income		39,655
Other income (expense)
Interest expense		(274	)


Income before taxes		39,381


Provision for taxes		(3,746	)


Net income		35,635

The accompanying notes are an integral part of these unaudited condensed financial statements.

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High Roller Wells Karnes SWD No. 1, Ltd.

Unaudited Condensed Statement of Cash Flows

	Period from inception (March 14, 2012) to June 30, 2012

Cash flows from operating activities
Net income	$	35,635
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation		64,010
Changes in operating assets and liabilities:
Accounts receivable		(203,778	)
Accounts receivable—related party		(279,661	)
Other current assets		(99,923	)
Accounts payable		889,757
Accrued expenses		90,196


Net cash provided by operating activities		496,236


Cash flows from investing activities
Purchases of property and equipment		(6,289,970	)


Net cash used in investing activities		(6,289,970	)


Cash flows from financing activities
Partner contributions		5,487,525
Borrowings from related parties		306,209


Net cash provided by financing activities		5,793,734


Net increase in cash and cash equivalents		—
Cash and cash equivalents, at inception		—


Cash and cash equivalents, at June 30, 2012	$	—

The accompanying notes are an integral part of these unaudited condensed financial statements.

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1. Organization and Nature of Operations

Formation Transactions

High Roller Wells Karnes SWD No. 1, Ltd. (the "Partnership") is a Texas Limited Liability Company formed on March 14, 2012.

Basis of Presentation

The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed financial statements include all adjustments that the Partnership considers necessary for a fair presentation of the financial position and results of operations for the interim period presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed financial statements do not include all the information and notes required by GAAP for complete annual financial statements. However, the Partnership believes that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed financial statements should be read in conjunction with the audited financial statements of the Partnership for the period from inception (March 14, 2012) through December 4, 2012. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

Nature of Business

2. Summary of Significant Accounting Policies

Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of the Partnership's revenues, expenses and costs. These estimates are based on management's knowledge of current events, historical experience, and various other assumptions that management believes to be reasonable under the circumstances. Although management believes these estimates are reasonable, actual results could differ from those estimates.

Revenue Recognition

The Partnership records revenues from crude oil sales at the time title to the product transfers to the purchaser, which typically occurs upon receipt of the product by the purchaser. The Partnership records water disposal revenues at the time the service is performed, which is upon receipt of the wastewater at the disposal facilities.

Depreciation

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2. Summary of Significant Accounting Policies (Continued)

Cash and Cash Equivalents

Cash and cash equivalents include cash on hand, demand and time deposits, and funds invested in highly liquid instruments with maturities of three months or less at the date of purchase.

Impairments

In accordance with Financial Accounting Standards Board ("FASB") Accounting Standard Codification ("ASC") Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment, are reviewed for impairment whenever events or circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Partnership evaluated its asset group in accordance with ASC 360 for the period from inception (March 14, 2012) through June 30, 2012, and concluded that no impairment of long-lived assets existed.

Environmental

Income taxes

The Partnership recognizes uncertain tax positions only if it is "more likely than not" that the position is sustainable, based solely on its technical merits and consideration of the relevant taxing authority's widely understood administrative practices and precedents. The Partnership has evaluated tax positions taken or expected to be taken in the course of preparing the Partnership's tax returns to determine whether the tax positions are more likely than not to be sustained by the applicable tax authority. Based on this analysis, all material tax positions were deemed to meet a more likely than not threshold. Therefore, no tax expense, including any interest and penalties, was recorded in the current period. Tax years from inception of the Partnership remain open.

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3. Related Party Transactions

The Partnership enters into transactions with related parties in the normal course of conducting business which the Partnership believes are at terms consistent with those available to third-party customers and from third-party vendors.

Throughout 2012, the Partnership paid $15,000 per month to an affiliate for administrative support.

During the period from inception (March 14, 2012) through June 30, 2012, the Partnership paid approximately $204,810 for construction labor provided by an affiliate at the Partnership's well site.

4. Commitments and Contingencies

Concentrations of Credit Risk

The Partnership's customer base consists primarily of multi-national and independent oil and natural gas producers. The Partnership does not require collateral on its trade receivables. For the period from inception (March 14, 2012) through June 30, 2012, two customers accounted for 57% and 11% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues.

Litigation

The Partnership is subject to various other claims and legal actions that arise in the ordinary course of business. Management does not believe that any of these claims and actions, individually or in the aggregate, will have a material adverse effect on the Partnership's business, financial condition, results of operations, or cash flows, although no guarantee can be made that a material adverse effect will not occur.

5. Subsequent Events

On December 4, 2012, the Partnership contributed all assets, excluding cash and accounts receivable, certain contracts and proprietary information, to a newly-formed limited liability company ("Newco"). Contemporaneously, the partners of the Partnership entered into a Purchase and Sale Agreement with Oilfield Water Lines, LP for the sale of 75% of the membership interests of Newco.

The Partnership has evaluated subsequent events through October 17, 2013, the date the financial statements were available for issuance.

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Lotus Oilfield Services, LLC

Unaudited Condensed Statement of Operations

	Six Months Ended June 30, 2012

Trucking revenue	$	3,290,651


Expenses
Equipment expenses		2,822,587
General and administrative		63,059
Depreciation		118,325


Total expenses		3,003,971


Operating income		286,680
Other income (expense)
Interest expense		(49,626	)
Other income, net		4,500


Income before income taxes		241,554
Provision for income taxes		(18,057	)


Net income	$	223,497

The accompanying notes are an integral part of these unaudited condensed financial statements.

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Lotus Oilfield Services, LLC

Unaudited Condensed Statement of Cash Flows

	Six Months Ended June 30, 2012

Cash flows from operating activities
Net income	$	223,497
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation expense		118,325
Gain on sale of equipment		(4,500	)
Changes in operating assets and liabilities:
Accounts receivable		(614,454	)
Accounts receivable—related parties		(72,491	)
Prepaid expenses and other current assets		20,379
Accounts payable—trade		(119,485	)
Accounts payable—related parties		338,770
Accrued expenses		124,077


Net cash provided by operating activities		14,118


Cash flows from investing activities
Purchases of property and equipment		(927,242	)
Proceeds from sale of property and equipment		27,500


Net cash used in investing activities		(899,742	)


Cash flows from financing activities
Repayments on debt		(222,866	)
Borrowings on line of credit		200,000
Borrowings on related party note		(30,567	)
Increase in equipment obligations		956,133
Other		(5,794	)


Net cash provided by financing activities		896,906


Net increase in cash and cash equivalents		11,282
Cash and cash equivalents
Beginning of period		60,720


End of period	$	72,002

The accompanying notes are an integral part of these unaudited condensed financial statements.

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Lotus Oilfield Services, LLC

Notes to Unaudited Condensed Financial Statements

1. Organization and Nature of Operations

Nature of Business

Basis of Presentation

The accompanying unaudited condensed financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP") for interim financial information and in accordance with the rules and regulations of the Securities and Exchange Commission. The unaudited condensed financial statements include all adjustments that the Company considers necessary for a fair presentation of the results of operations for the interim period presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed financial statements do not include all the information and notes required by GAAP for complete annual financial statements. However, the Company believes that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed financial statements should be read in conjunction with the audited financial statements of the Company for the period from January 1, 2012 through December 27, 2012. The results of operations for an interim period are not necessarily indicative of the results to be expected for a full year.

2. Risk and Uncertainties

As an independent oilfield services contractor that provides hauling services to oil and natural gas companies onshore in Texas, the Company's revenue, profitability, cash flows and future rate of growth are substantially dependent on the Company's ability to (1) maintain adequate equipment utilization, (2) maintain adequate pricing for the services the Company provides, and (3) maintain a trained work force. Failure to do so could adversely affect the Company's financial position, results of operations, and cash flows.

3. Summary of Significant Accounting Policies

Use of Estimates

The preparation of financial statements in accordance with generally accepted accounting principles in the United States ("GAAP") requires the Company to make estimates and assumptions that affect the reported amounts of the Company's assets, liabilities, revenues, expenses and costs. These estimates are based on the Company's knowledge of current events, historical experience, and various other assumptions that the Company believes to be reasonable under the circumstances.

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Lotus Oilfield Services, LLC

Notes to Unaudited Condensed Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

Revenue Recognition

The Company recognizes revenue upon completion of hauling services, provided collection of the relevant receivables is probable, persuasive evidence of an arrangement exists, and the price is fixed or determinable. In accordance with Financial Accounting Standards Board ("FASB") Accounting Standards Codification ("ASC") Topic 605-45 "Principal Agent Considerations" ("ASC 605-45") revenues are presented net of any sales taxes collected by Lotus Oilfield Services from its customers that are remitted to governmental authorities.

Cash and Cash Equivalents

The Company considers all highly liquid investments purchased with an original maturity of three months or less to be cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

Property and Equipment

Impairments

In accordance with ASC Topic 360 "Property, Plant and Equipment" ("ASC 360"), long-lived assets, such as property, and equipment are reviewed whenever events in circumstances indicate that the carrying amount of such assets may not be recoverable. Recoverability of assets to be held and used is measured by a comparison of the carrying amount of such assets to estimated undiscounted future cash flows expected to be generated by the assets. Expected future cash flows and carrying values are aggregated at their lowest identifiable level. If the carrying amount of such assets exceeds their estimated future cash flows, an impairment charge is recognized in the amount by which the carrying amount of such assets exceeds the fair value of the assets. The Company evaluated its asset group in accordance with ASC 360 for the six months ended June 30, 2012 and concluded that no impairment of long-lived assets existed.

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Lotus Oilfield Services, LLC

Notes to Unaudited Condensed Financial Statements (Continued)

3. Summary of Significant Accounting Policies (Continued)

Income taxes

4. Equipment Notes Payable

During the year ended December 31, 2011, the Company financed the purchase of certain vehicles and equipment through commercial loans with commercial lenders. These loans were repayable in monthly installments with the maturity dates through February 2016. Interest accrued at rate of 6% and was payable monthly. The loans were collateralized by equipment purchased with the proceeds of such loans and by second liens on accounts receivable. All notes were retired subsequent to December 27, 2012 in connection with the acquisition of the Company (see note 8).

5. Related Party Transactions

The Company enters into transactions with related parties in the normal course of conducting business. Accounts receivable-related parties and Accounts payable-related parties result from transactions with related parties which the Company believes are at terms consistent with those available to third-party customers and from third-party vendors.

During the six months ended June 30, 2012, the Company paid $617,401 to related parties for reimbursement of expenses paid by related parties, chemicals, equipment rental, disposal fees and other operating and miscellaneous costs. Sales to related parties totaled $125,281 for the six months ended June 30, 2012.

The Company borrowed funds from related parties during the six months ended June 30, 2012. Interest accrued at rate of 6% and interest expense relating to these borrowings was $6,400 for the six months ended June 30, 2012.

6. Commitments and Contingencies

Concentrations of Credit Risk

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Lotus Oilfield Services, LLC

Notes to Unaudited Condensed Financial Statements (Continued)

6. Commitments and Contingencies (Continued)

program in effect from December 31, 2010 through December 28, 2012. Under the program, there is no limit to the amount of insurance for eligible accounts.

The Company's customer base consists primarily of multi-national and independent oil and natural gas producers. The Company does not require collateral on its trade receivables. For the six months ended June 30, 2012, two customers accounted for 24% and 17% of total revenues, respectively. There were no other customers that amounted to 10% or more of total revenues for the six months ended June 30, 2012.

Litigation

The Company is subject to various other claims and legal actions that arise in the ordinary course of business. The Company does not believe that any of these claims and actions, individually or in the aggregate, will have a material adverse effect on the Company's business, financial condition, results of operations, or cash flows, although the Company cannot guarantee that a material adverse effect will not occur.

7. Supplemental Cash Flow Information

	Six Months Ended June 30, 2012

Cash paid for
Interest	$	40,614

8. Subsequent Events

The Company has evaluated subsequent events through October 17, 2013, the date the financial statements were available for issuance.

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Independent Auditors' Report

The Board of Managers
Gavilon Energy (The Energy Business Units of Gavilon, LLC):

We have audited the accompanying combined financial statements of Gavilon Energy (The Energy Business Units of Gavilon, LLC) (the Company), which comprise the combined balance sheets as of December 31, 2012 and 2011, and the related combined statements of operations, comprehensive income (loss), equity, and cash flows for each of the years in the three-year period ended December 31, 2012, and the related notes to the combined financial statements.

Management's Responsibility for the Combined Financial Statements

Management is responsible for the preparation and fair presentation of these combined financial statements in accordance with U.S. generally accepted accounting principles; this responsibility includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of combined financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility

Our responsibility is to express an opinion on these combined financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the combined financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the combined financial statements. The procedures selected depend on the auditors' judgment, including the assessment of the risks of material misstatement of the combined financial statements, whether due to fraud or error. In making those risk assessments, the auditors consider internal control relevant to the entity's preparation and fair presentation of the combined financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the combined financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the combined financial statements referred to above present fairly in all material respects, the financial position of Gavilon Energy (The Energy Business Units of Gavilon, LLC) as of December 31, 2012 and 2011, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2012 in accordance with U.S. generally accepted accounting principles.

/s/ KPMG LLP

Omaha, Nebraska
June 24, 2013

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Combined Balance Sheets

December 31, 2012 and 2011

(Dollars in millions)

	2012

Assets
Current assets:
Cash	$	5.0		12.7
Trade accounts receivable, less allowance for doubtful accounts of $1.0 and $0.6, respectively		473.5		568.4
Inventories		969.4		923.1
Derivative assets		58.4		90.0
Other current assets		21.2		81.3


Total current assets		1,527.5		1,675.5


Property, plant, and equipment:
Land and land improvements		13.8		7.5
Buildings		0.6		0.6
Machinery and equipment		7.9		6.9
Tanks and pipelines		88.6		81.6
Construction in progress		1.4		5.0


		112.3		101.6
Less accumulated depreciation		(6.9	)	(2.3	)


Net property, plant, and equipment		105.4		99.3
Goodwill		33.0		33.0
Intangible assets, net		15.9		22.3
Equity method investments		73.6		—
Other assets		13.5		14.3


Total assets	$	1,768.9		1,844.4




Liabilities and Equity
Current liabilities:
Current portion of long term debt	$	10.4		4.5
Accounts payable		592.2		542.4
Advances on sales		8.9		7.4
Derivative liabilities		32.2		82.5
Accrued expenses		17.6		50.2
Payable due to parent		434.3		394.6


Total current liabilities		1,095.6		1,081.6
Long-term debt		29.7		37.0
Other noncurrent liabilities		0.3		0.3


Total liabilities		1,125.6		1,118.9


Total equity:
Parent Company's equity investment		530.2		464.9
Retained earnings		111.5		245.1
Accumulated other comprehensive income		1.6		15.5


Total equity		643.3		725.5


Commitments and contingencies (notes 13 and 14)
Total liabilities and equity	$	1,768.9		1,844.4

See accompanying notes to combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Combined Statements of Operations

Years ended December 31, 2012, 2011, and 2010

(Dollars in millions)

	2012

Net sales	$	239.8		379.3		192.9
Cost of goods sold		193.2		151.2		81.8


Gross profit		46.6		228.1		111.1
Selling, general, and administrative expenses		49.6		62.9		30.3
Corporate allocated expense		50.2		27.9		23.0
Depreciation and amortization		6.9		6.6		6.2


Operating income (loss)		(60.1	)	130.7		51.6
Interest expense, net		44.3		37.6		19.8


Income (loss) from continuing operations before income taxes		(104.4	)	93.1		31.8
Income tax expense		0.2		1.6		—


Income (loss) from continuing operations		(104.6	)	91.5		31.8
Net income (loss) from discontinued operations		(29.0	)	(5.5	)	3.7


Net income (loss)	$	(133.6	)	86.0		35.5

See accompanying notes to combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Combined Statements of Comprehensive Income (Loss)

Years ended December 31, 2012, 2011, and 2010

(Dollars in millions)

	2012

Net income (loss)	$	(133.6	)	86.0	35.5
Other comprehensive income (loss):
Foreign currency translation adjustments		0.1		—	—
Net gain (loss) on derivative instruments designated and qualifying as cash flow hedges		(14.1	)	7.6	19.9
Available-for-sale securities		0.1		0.1	(0.2	)


Total comprehensive income (loss)	$	(147.5	)	93.7	55.2

See accompanying notes to combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Combined Statements of Equity

Years ended December 31, 2012 and 2011

(Dollars in millions)

	Parent Company's equity investment

Balance at December 31, 2009	$	410.4		123.6		(11.9	)	522.1
Net income		—		35.5		—		35.5
Contributed capital		89.0		—		—		89.0
Other comprehensive income		—		—		19.7		19.7


Balance at December 31, 2010		499.4		159.1		7.8		666.3
Net income		—		86.0		—		86.0
Return of capital		(34.5	)	—		—		(34.5	)
Other comprehensive income		—		—		7.7		7.7


Balance at December 31, 2011		464.9		245.1		15.5		725.5
Net loss		—		(133.6	)	—		(133.6	)
Contributed capital		65.3		—		—		65.3
Other comprehensive loss		—		—		(13.9	)	(13.9	)


Balance at December 31, 2012	$	530.2		111.5		1.6		643.3

See accompanying notes to combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Combined Statements of Cash Flows

Years ended December 31, 2012, 2011, and 2010

(Dollars in millions)

	2012

Cash flows from operating activities:
Net income (loss)	$	(133.6	)	86.0		35.5
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization		11.4		8.6		6.2
Provision for bad debts		0.9		(0.3	)	(0.1	)
Amortization of debt issue costs		0.5		0.5		—
Other items		(1.0	)	0.1		(0.2	)
Changes in operating assets and liabilities, net of acquisitions:
Accounts receivable		93.9		(327.0	)	95.0
Inventories		(46.3	)	(632.0	)	148.7
Other current assets		60.1		(74.6	)	(3.2	)
Derivative assets and liabilities		(32.8	)	21.4		(17.4	)
Accounts payable		52.2		206.5		(67.4	)
Advances on sales		1.5		7.0		(8.4	)
Other accrued liabilities		(32.5	)	24.4		(4.9	)
Noncurrent assets and liabilities		0.1		19.1		(25.7	)


Net cash provided by (used in) operating activities		(25.6	)	(660.3	)	158.1


Cash flows from investing activities:
Acquisitions, less cash acquired		—		(8.0	)	—
Additions to property, plant, and equipment		(12.1	)	(36.2	)	(62.1	)
Investment in equity method investments		(73.6	)	—		—


Net cash used in investing activities		(85.7	)	(44.2	)	(62.1	)


Cash flows from financing activities:
Issuance of long-term debt		4.6		52.7		—
Repayments of long-term debt		(6.0	)	(11.2	)	—
Debt issue costs		—		(2.7	)	(1.3	)
Contribution (return of) capital		65.3		(34.5	)	89.0
Payable due to parent		39.7		712.4		(177.8	)


Net cash provided by (used in) financing activities		103.6		716.7		(90.1	)


Net change in cash and cash equivalents		(7.7	)	12.2		5.9
Cash and cash equivalents at beginning of year		12.7		0.5		(5.4	)


Cash and cash equivalents at end of year	$	5.0		12.7		0.5




Supplemental cash and noncash flow information:
Noncash construction payable	$	—		1.3		5.5
Cash paid for interest		2.5		2.5		—

See accompanying notes to combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements

December 31, 2012 and 2011

(1) Business Description

The accompanying combined financial statements include the accounts of all operations that comprise the energy operations of Gavilon, LLC (collectively, the Company). The Company operates the marketing, trading, and distribution of energy commodities. Gavilon, LLC is a wholly owned subsidiary of The Gavilon Group, LLC (The Gavilon Group). The Gavilon Group, LLC is in the process of restructuring Gavilon, LLC to ultimately acquire, own, and operate the energy operations, which are set forth in these combined financial statements. Historically, the business units comprising Gavilon, LLC have been consolidated with The Gavilon Group. Material related party activity is summarized in note 16. As part of the potential separation of the energy operations, The Gavilon Group expects to transfer substantially all of its energy business units to Gavilon, LLC and transfer out any non-energy related business units to another subsidiary of The Gavilon Group. In addition, the Company has completed several restructuring initiatives, which have impacted the energy business units. These business units have been included in discontinued operations in the accompanying combined statement of operations for all years presented (note 15).

(2) Basis of Presentation

The accompanying combined financial statements include the energy business units of Gavilon, LLC. When the Company does not have a controlling interest, but exerts a significant influence over the entity, the Company applies the equity method of accounting. All significant intercompany balances and transactions have been eliminated.

(3) Summary of Significant Accounting Policies

(a) Use of Estimates

The preparation of the combined financial statements, in accordance with generally accepted accounting principles (GAAP) in the United States of America, requires management to make estimates and assumptions that affect the amounts reported in the combined financial statements and accompanying notes. The most significant estimates relate to the valuation of derivatives, inventories, and the useful lives of fixed assets.

Management evaluates its estimates and assumptions on an ongoing basis using historical experience and other factors, including the current economic environment, which management believes to be reasonable under the circumstances. The Company adjusts such estimates and assumptions when facts and circumstances dictate. As future events and their effects cannot be determined with precision, actual results could differ significantly from these estimates. Changes in those estimates resulting from continuing changes in the economic environment will be reflected in the combined financial statements in future periods.

(b) Trade Accounts Receivable

Trade accounts receivable are recorded at the invoiced amount and do not bear interest. The Company maintains an allowance for doubtful accounts for estimated losses inherent in its accounts receivable portfolio. In establishing the required allowance, management considers historical losses, current receivables aging, and existing industry and economic data.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(3) Summary of Significant Accounting Policies (Continued)

(c) Inventories

The Company uses the lower of cost or market for inventories, except crude oil inventory designated in a fair value hedging relationship. Cost is determined using the weighted average cost method. The Company uses fair value for crude oil inventory designated in a fair value hedging relationship.

(d) Equity Method Investments

The investments in and the operating results of 50% or less-owned entities not required to be consolidated are included in the combined financial statements on the basis of the equity method of accounting.

(e) Property, Plant, and Equipment

The Company's accounting for property, plant, and equipment is to record asset additions at cost. The estimated useful lives of the respective classes of assets are as follows:


Land improvements		15 years
Buildings and building improvements		15 - 40 years
Machinery and equipment		7 - 15 years
Tanks and pipeline		5 - 40 years

Long-lived assets, such as property, plant, and equipment, and purchased intangible assets are subject to amortization, and are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If circumstances require a long-lived asset or asset group be tested for possible impairment, the Company first compares undiscounted cash flows expected to be generated by that asset or asset group to its carrying value. If the carrying value of the long-lived asset or asset group is not recoverable on an undiscounted cash flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values, and third-party independent appraisals, as considered necessary. There were no circumstances that indicated the carrying value of long-lived assets or intangible assets may not be recoverable during the year ended December 31, 2012 or 2011.

(f) Goodwill

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(3) Summary of Significant Accounting Policies (Continued)

value of the reporting unit is less than its carrying value, an indication of goodwill impairment exists for the reporting unit and the enterprise must perform step two of the impairment test (measurement). Under step two, an impairment loss is recognized for any excess of the carrying amount of the reporting unit's goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price allocation. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill. Fair value of the reporting unit is determined using a discounted cash flow analysis. If the fair value of the reporting unit exceeds its carrying value, step two does not need to be performed. The Company performs its annual impairment review of goodwill at June 30 and when a triggering event occurs between annual impairment tests. For 2012, the Company performed a qualitative assessment of goodwill and determined that it is more likely than not that the fair values of its reporting units are greater than the carrying amounts. Accordingly, there were no impairments of goodwill for the year ended December 31, 2012 or 2011.

(g) Derivatives

The Company uses commodity futures, options, and forward purchase and sales contracts in the normal course of business. The Company also uses interest rate related derivative instruments to manage its exposure related to changes in interest rates on its variable rate debt instruments. These derivative instruments are recognized at fair value in the combined balance sheets and changes in the fair value of derivatives not accounted for as hedges are recognized in earnings. For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or recognized in accumulated other comprehensive income until the hedged item is recognized in earnings.

For all hedging relationships, the Company formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged item, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method of measuring ineffectiveness. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting cash flows of hedged items. For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing hedge ineffectiveness are recognized in current earnings.

The Company discontinues hedge accounting prospectively when it determines that the derivative is no longer effective in offsetting cash flows of the hedged item, the derivative expires or is sold, terminated, or exercised, the derivative is designated as a hedging instrument because it is unlikely that a forecasted transaction will occur, or management determines that designation of the derivative as a hedging instrument is no longer appropriate.

In all situations in which hedge accounting is discontinued and the derivative is retained, the Company continues to carry the derivative at its fair value on the balance sheet and recognizes any

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(3) Summary of Significant Accounting Policies (Continued)

subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Company discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income.

(h) Fair Values of Financial Instruments

Unless otherwise specified, the Company believes the carrying value of its financial instruments approximates their fair value.

(i) Netting of Accounts

Where derivatives and accounts receivable and payable are subject to a master netting agreement and the accounting criteria to offset are met, the Company presents these accounts on a net basis in the combined financial statements.

(j) Revenue Recognition

Revenue is recognized when title and risk of loss are transferred to customers upon delivery based on terms of sale and collectibility is reasonably assured. Changes in the fair value of commodity derivatives are recognized in earnings immediately. Sales related to trading activities are recorded net, and margins earned on such transactions are included as a component of net sales. Net sales and cost of goods sold, if reported on a gross basis for these activities, would be increased by $18,819.6 million, $17,300.9 million, and $10,165.4 million for the years ended December 31, 2012, 2011, and 2010, respectively.

(k) Income Taxes

As a limited liability company, the Company does not pay U.S. federal or state income taxes under the provisions of the Internal Revenue Code. However, the Company's Canadian operations are subject to tax in its local jurisdiction.

The Company recognizes the effect of income tax positions only if those positions are more likely than not of being sustained. Recognized income tax positions are measured at the largest amount that is greater than 50% likely of being realized. Changes in recognition or measurement are reflected in the period in which the change in judgment occurs.

(l) Debt Issuance Costs

The Company incurred certain financing costs associated with debt issuance (note 10). These costs were capitalized and are being amortized to expense using the effective interest rate method.

(m) Recently Issued Accounting Pronouncements

In December 2011, the Financial Accounting Standards Board (FASB) issued ASU No. 2011-11,Balance Sheet (Topic 210): Disclosures about Offsetting Assets and Liabilities. ASU 2011-11 requires an entity to disclose information about offsetting and related arrangements to enable users of financial

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(3) Summary of Significant Accounting Policies (Continued)

statements to understand the effect of those arrangements on its financial position, and to allow investors to better compare financial statements prepared under U.S. GAAP with financial statements prepared under International Financial Reporting Standards (IFRS). The new standards are effective for annual periods beginning January 1, 2013, and interim periods within those annual periods. Retrospective application is required. The Company will implement these required disclosures provisions as of January 1, 2013.

(4) Business Combination

During 2011, the Company acquired the refined products rack marketing business from Plains All American Pipeline, LP (Plains All American Pipeline). The final purchase price was approximately $8.0 million.

The following table summarizes the fair values of the assets acquired and liabilities assumed for Plains All American Pipeline (in millions). The fair value assigned is based upon the final valuation for those assets:


Intangible assets	$	1.3
Property and equipment		1.1
Goodwill		5.6


Total cash consideration	$	8.0

(5) Goodwill and Intangible Assets

Goodwill represents the excess of the purchase price over the estimated fair value of the net tangible and intangible assets acquired. The Company's goodwill includes goodwill that was allocated by The Gavilon Group as part of the overall purchase price allocation for all legal entities acquired. Factors that contributed to a purchase price resulting in goodwill included the Company's favorable market position in profitable and growing markets, favorable logistics and asset network, and intellectual capital associated with the Company. Goodwill is fully tax deductible to the members.

The fair value of identifiable intangible assets consist of customer relationships (7 year weighted average useful life) and contractual obligations. Identifiable intangible assets as of December 31, 2012 and 2011 are as follows (in millions):

	Gross carrying amounts

December 31, 2012:
Customer relationships	$	43.1	(27.3	)	15.8
Contractual obligations		7.5	(7.4	)	0.1


Total	$	50.6	(34.7	)	15.9

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(5) Goodwill and Intangible Assets (Continued)

	Gross carrying amounts

December 31, 2011:
Customer relationships	$	43.1	(21.1	)	22.0
Contractual obligations		7.5	(7.2	)	0.3


Total	$	50.6	(28.3	)	22.3

Aggregate amortization expense for amortizing intangible assets was $6.9 million, $6.3 million, and $6.2 million for the years ended December 31, 2012, 2011, and 2010 respectively. Estimated amortization expense for the next five years is $6.4 million in 2013, $6.2 million in 2014, $3.1 million in 2015, $0.1 million in 2016, and $0.1 million in 2017.

(6) Derivatives and Hedging Activities

The Company purchases and sells commodities, such as gas, ethanol, natural gas, biodiesel and crude oil. The Company generally follows a policy of using commodity derivatives to minimize its net position of commodity inventories and forward cash purchase and sales contracts. The Company will also use commodity derivatives as components of market strategies designed to enhance margins. The results of these strategies can be significantly impacted by factors such as the volatility of the relationship between the value of commodity derivatives and the cash prices of the underlying commodities, counterparty contract defaults, and volatility of transportation markets.

Changes in the fair value of commodity derivatives are recognized in earnings immediately, except for certain energy contracts and interest rate swaps that have been designated in a cash flow hedging relationship. The Company reports the fair value of its derivative assets and liabilities, including derivatives used in hedging relationships, on the combined balance sheets, as commodity and other contracts at fair value.

For risk management purposes, the Company utilizes fair value hedges, cash flow hedges, and economic hedges. In addition to the use of derivative instruments to manage commodity price risk, the Company also enters into certain commodity derivative instruments for trading purposes. The majority of the Company's purchase and sales contracts qualify as derivative instruments and the change in fair value is reported in net sales and cost of sales in the accompanying combined statements of operations.

For derivatives designated in hedging relationships, changes in the fair value are either offset through earnings against the change in fair value of the hedged item attributable to the risk being hedged or initially reported as a component of accumulated other comprehensive income and then recorded in income in the period or periods during which the hedged forecasted transaction affects income.

The Company's policy is to report gains and losses associated with derivatives as follows:

Contract/derivative nature		Line item

Commodities		Net sales
Interest rate swap		Interest expense

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(6) Derivatives and Hedging Activities (Continued)

While a majority of the Company's use of derivative instruments is to manage market risks by economically hedging the Company's inventory and forward purchase and sales commitments, the Company also designates cash flow hedges. The Company has designated cash flow hedges associated with the future purchase and sales of natural gas anticipated for the period from January 2013 to February 2013. The object of the Company's cash flow hedges is to fix the price of natural gas purchase and sales at existing market prices that the Company deems favorable.

The Company entered into an interest rate swap agreement to manage the variability of cash flows over certain portions of the interest payments related to the variable rate on the term loan (note 10). The interest rate swap agreement used by the Company has been recorded at fair value in the combined balance sheets with changes in fair value recorded in accumulated other comprehensive income. This amount is subsequently reclassified into interest expense as a yield adjustment of the hedged interest payments in the same period in which the related interest affects earnings. Amounts subsequently reclassified into interest expense during the year were immaterial, and no ineffectiveness was recognized during 2012, 2011, or 2010.

As of December 31, 2012 and 2011, the fair value of the Company's interest rate swap agreement designated in a cash flow hedging relationship was an unrealized loss of $1.8 million. As of December 31, 2012 and 2011, the fair value of the Company's natural gas futures designated in a cash flow hedging relationship was $3.3 million and $17.4 million, respectively.

The following table provides information about the gain or loss recognized in income and other comprehensive income (loss) on the Company's cash flow hedging derivative instruments for the years ended December 31, 2012, 2011, and 2010 (in thousands). Also, the information presents the notional volume of outstanding cash flow hedge derivative contracts by type of instrument.

Cash Flow Hedges

	Gain (loss) recognized in AOCI on derivatives (effective portion)

			Gain (loss) reclassified from AOCI into income (effective portion)				Gain (loss) recognized in income on derivatives (ineffective portion)
				2012 Amount				2012 Amount
Commodity type	2012 Amount		Location	2012 Amount			Location	2012 Amount
Natural gas	$	4,540	Net sales	$	18,646		Net sales	$	—
Interest rate swaps		767	Interest expense		(778	)	Interest expense		—

Commodity type	2011 Amount			Location	2011 Amount			Location	2011 Amount

Natural gas	$	6,654		Net sales	$	(2,716	)	Net sales	$	—
Interest rate swaps		(804	)	Interest expense		(979	)	Interest expense		—

Commodity type		2010 Amount			Location		2010 Amount			Location		2010 Amount

Natural gas		$	7,995		Net sales		$	(11,905	)	Net sales		$	—

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(6) Derivatives and Hedging Activities (Continued)

Derivative instrument

Natural gas futures (MMBtu's)	931	930	(25,340	)
Interest rate swaps (millions of $)	36	41	—

The following table summarizes the Company's outstanding interest rate swap agreement as of December 31, 2012:

Term		Notional amount		Fixed rate			Variable rate

1/24/11 - 3/31/18		36 million			2.393			0.311

The following table summarizes the Company's outstanding interest rate swap agreement as of December 31, 2011:

Term		Notional amount		Fixed rate			Variable rate

1/24/11 - 3/31/18		41 million			2.393			0.579

The Company did not exclude any components of the derivatives instruments' gains or losses from the assessment of hedge effectiveness for its cash flow hedging relationships. The Company expects that all of the unrealized gains (losses) as of December 31, 2012 on the natural gas cash flow hedging relationships will be reclassified into net sales over the next two months as a result of the hedged transaction affecting earnings. The deferred gains (losses) as of December 31, 2012 on the interest rate cash flow hedging relationships will be classified into interest expense over the term of the outstanding debt instruments (note 10).

The Company has designated fair value hedges used to hedge certain crude oil inventories. The following table provides information about the gain or loss recognized in income on the Company's fair value hedging derivative instruments for the year ended December 31, 2012, 2011, and 2010 (in thousands). Also, the information presents the notional volume (in thousands) of outstanding derivative contracts designated in the fair value hedging relationships at December 31, 2012, 2011, and 2010.

Fair Value Hedges

	Gain (loss) recognized in income on derivatives				Gain (loss) recognized in income on hedged item			Gain (loss) recognized in income on derivatives (ineffective portion)

Commodity type	Location	2012 Amount			Location	2012 Amount		Location	2012 Amount
Crude oil inventory	Net sales	$	(10,899	)	Net sales	$	13,815	Net sales	$	2,916

Commodity type		Location		2011 Amount			Location		2011 Amount			Location		2011 Amount

Crude oil inventory		Net sales		$	2,388		Net sales		$	(1,574	)	Net sales		$	814

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(6) Derivatives and Hedging Activities (Continued)

Commodity type		Location		2010 Amount			Location		2010 Amount			Location		2010 Amount

Crude oil inventory		Net sales		$	(244	)	Net sales		$	(10,143	)	Net sales		$	(10,387	)

Derivative instrument		Notional contract volumes (as of December 31, 2012)			Notional contract volumes (as of December 31, 2011)			Notional contract volumes (as of December 31, 2010)

Crude oil futures (barrels)			9,661			7,321			3,211

The following table summarizes the Company's notional volumes for their economic and trading derivative financial instruments as of December 31, 2012 and 2011 (amounts in thousands) by type of instrument:

	Exchange- traded

	Exchange- traded			Non-exchange traded
	Net (short) long			Non-exchange traded
2012	Net (short) long			(Short)			Long
Natural gas (MMBtu's):
Futures		(4,700	)		—			—
Options		—			—			—
Swaps		(7,238	)		—			78
Forwards		—			(6,551	)		—
Oil (barrels):
Futures		(3,262	)		—			—
Options		35			—			—
Forwards		—			(2,112	)		2,396

	Exchange- traded

	Exchange- traded			Non-exchange traded
	Net (short) long			Non-exchange traded
2011	Net (short) long			(Short)			Long
Natural gas (MMBtu's):
Futures		(8,730	)		—			—
Options		2,123			—			—
Swaps		(4,928	)		(536	)		1,052
Forwards		—			(7,267	)		—
Oil (barrels):
Futures		(6,598	)		—			—
Forwards		—			(26,052	)		37,990

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(6) Derivatives and Hedging Activities (Continued)

with less creditworthy counterparties through prepayments, letters of credit, and other security agreements, such as inventory, property, or other tangible assets. The use of master netting agreements is driven by industry practice, and anticipated volumes and complexity of the business relationship with the counterparty. The Company assumes credit and performance risk associated with commodity derivative contracts within the energy and agriculture industries; however, no counterparty was greater than 10% of the Company's net exposure.

The Company has policies that limit the dollar risk exposure for each of its businesses. The Company also monitors the amount of associated counterparty credit risk for all nonexchange-traded transactions. The Company's trading activities are limited in terms of maximum dollar exposure, as measured by a value-at-risk methodology, and monitored to ensure compliance.

As of December 31, 2012, the Company held certain derivative contracts with settlement dates through March 2016. However, approximately 95% of the Company's notional amount of commodity derivative contracts has settlement dates of less than one year. The Company also has interest rate swaps with settlement dates through March 2018.

(7) Equity Method Investments

The Company's equity method investment in Glass Mountain Pipeline of $73.6 million at December 31, 2012 relates to a 50% interest in a development-stage limited liability company formed in May 2012. This investment includes the buyout of one of the original investors on October 9, 2012. The Company paid $52.3 for an additional 25% interest. Glass Mountain pipeline's operations consist of construction of an intrastate crude oil common carrier pipeline system in Oklahoma. Glass Mountain's total assets as of December 31, 2012 are $86.2 million and primarily represent cash and construction in progress. Glass Mountain's total liabilities as of December 31, 2012 are $0.1 million and primarily represent construction-related payables.

(8) Inventories

The major classes of inventories at December 31, 2012 and 2011 are as follows (in millions):

	2012

Crude oil inventories carried at fair value	$	873.3	721.7
Inventories carried at lower of cost or market:
Crude oil		6.8	13.9
Natural gas		31.2	53.0
Fuels		57.6	126.0
Other		0.5	8.5


	$	969.4	923.1

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(9) Fair Value Measurements

Financial assets and liabilities carried at fair value will be classified and disclosed in one of the following three categories:

Level 1—Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities and listed derivatives.

Level 2—Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived principally from or corroborated by observable market data by correlation or other means.

Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management's best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

Exchange-traded futures and options contracts are valued based on unadjusted quoted prices in active markets and are classified within Level 1. The Company's forward commodity purchase and sale contracts are classified as a Level 2 measurement. The Company estimates fair values based on exchange quoted prices, adjusted as appropriate for differences in local markets. These differences are generally valued using inputs from broker or dealer quotations, or market transactions in either the listed or over-the-counter (OTC) markets. The determination of the fair values also factor the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit, and priority interests), and also the impact of the Company's nonperformance risk on its liabilities.

The Company also utilizes a midmarket pricing convention (the midpoint price between bid and ask prices) for valuing a significant portion of its assets and liabilities measured and reported at fair value. The Company is able to classify fair value balances based on the observability of inputs.

The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were accounted for at fair value on a recurring basis as of December 31, 2012 and 2011. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels.

	December 31, 2012

	Level 1		Level 2		Level 3		Nettings			Total
Assets (in millions):
Inventory	$	873.3		—		—		—			873.3
Derivative assets		13.1		2,930.1		—		(2,884.8	)		58.4
Liabilities (in millions):
Derivative liabilities	$	—		2,917.0		—		(2,884.8	)		32.2

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(9) Fair Value Measurements (Continued)

	December 31, 2011

	Level 1		Level 2		Level 3		Nettings			Total
Assets (in millions):
Inventory	$	721.7		—		—		—			721.7
Derivative assets		28.7		4,583.7		—		(4,522.4	)		90.0
Liabilities (in millions):
Derivative liabilities	$	—		4,604.9		—		(4,522.4	)		82.5

(10) Long-Term Debt

Long-term obligations are as follows (in millions):

	2012

Term loan, variable interest rate, 5.74% and 6.16% at December 31, 2012 and 2011, respectively.	$	40.1		41.5


		40.1		41.5
Less current portion		(10.4	)	(4.5	)


Total long-term debt	$	29.7		37.0

During 2011, the Company issued $52.7 million in term loans to finance the construction of the crude oil tank farm. The term loan bears interest at the one-month LIBOR until December 31, 2012 and then three-month LIBOR thereafter and requires annual debt service payments beginning in March 2012 with the balance due December 2019. The term loans include an excess cash sweep provision that requires the Company to make additional principal payments if operating cash flows exceed a certain threshold. The Company has fixed this interest through the use of interest rate swaps for an effective interest rate of 7.05%.

Principal Maturities—Principal maturities of long-term debt at December 31, 2012 are as follows (in millions):


2013	$	10.4
2014		5.3
2015		5.5
2016		5.8
2017		6.0
Thereafter		7.1

The term loan contains various restrictive covenants including a debt service coverage ratio. The term loan also provides for a first security interest in the property, plant, and equipment of the Company. The Company was in compliance with all financial debt covenants as of December 31, 2012 and 2011.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(11) Accumulated Other Comprehensive Loss

The following table summarizes the balances of accumulated other comprehensive income (in millions):

	December 31

	2012		2011
Cash flow hedging derivatives	$	1.5		15.6
Available-for-sale securities		—		(0.1	)
Currency translation adjustment		0.1		—


	$	1.6		15.5

(12) Income Taxes

As a limited liability company, the Company does not pay U.S. federal or state income taxes under the provisions of the Internal Revenue Code. However, the Company operates a wholly owned foreign subsidiary located in Canada. The tax consequences for these operations are reported on an accrual basis at the statutory rate of the respective jurisdictions.

The components of the Company's income tax provision for the years ended December 31, 2012 and 2011 are as follows (in millions):

	2012

Pretax income—subject to Canadian tax	$	0.6		5.9
Provision for income taxes:
Current	$	0.3		1.6
Deferred		(0.1	)	—


	$	0.2		1.6

(13) Leases and Other Commitments

Lease expense under operating leases and other commitment expenses totaled $6.4 million, $6.5 million, and $3.8 million for the years ended December 31, 2012, 2011, and 2010, respectively. The following is a summary (in millions) of operating leases consisting of rail, land and building, and other

F-372

Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(13) Leases and Other Commitments (Continued)

commitments as of December 31, 2012. Other commitments primarily consist of obligations for storage of natural gas, crude and other fuels:

	Leases

2013	$	5.4	49.0
2014		3.3	42.3
2015		2.4	39.3
2016		2.2	16.7
2017		1.5	7.5
Later years		1.5	3.5


	$	16.3	158.3

(14) Contingencies

The Company is party to a number of claims arising out of the operation of its business. Management records charges for probable losses that can be estimated. After taking into account liabilities recorded for all of the foregoing matters, management believes the ultimate resolution of such matters should not have a material adverse effect on the Company's combined financial position, results of operations, or liquidity. Costs of legal services are recognized in earnings as services are provided.

(15) Discontinued Operations

During 2012, the Company completed restructuring initiatives that eliminated the operations of the Import/Export Ethanol, Glycerin, and weather and portfolio trading business units. Additionally, during 2012, the Company's management approved a plan to sell the Thackerville Propane Terminal. These operations are classified as held for sale and included in discontinued operations.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(15) Discontinued Operations (Continued)

These business lines meet the criteria for being reported as discontinued operations and has been segregated from continuing operations. The following table summarizes the results from discontinued operations (in millions):

	Net sales

2012:
Import/export ethanol	$	(14.2	)	(20.2	)
Glycerin		11.7		(6.1	)
Thackerville propane terminal		0.1		(0.2	)
Weather and portfolio trading		(1.7	)	(2.5	)


Total	$	(4.1	)	(29.0	)




2011:
Import/export ethanol	$	2.4		(1.2	)
Glycerin		10.7		(2.7	)
Thackerville propane terminal		—		(0.2	)
Weather and portfolio trading		(0.7	)	(1.4	)


Total	$	12.4		(5.5	)




2010:
Import/export ethanol	$	—		—
Glycerin		12.7		2.0
Weather and portfolio trading		2.0		1.7


Total	$	14.7		3.7

(16) Related-Party Transactions

The Gavilon Group provides a variety of services to the Company, such as information technology, treasury and cash management, payroll and human resources, legal, tax, facilities, general accounting and other corporate functions. Where possible, The Gavilon Group directly allocates costs to the Company based on usage or other direct allocation methods. Direct allocations to the Company are generally related to information technology, risk management, human resources, business development, compliance and facilities. The direct allocations are included in corporate allocations in the accompanying combined statement of operations, and were $7.8 million, $5.9 million and $5.1 million for the years ended December 31, 2012, 2011, and 2010, respectively.

In addition to direct allocations from The Gavilon Group, indirect corporate expenses are allocated to the Company. These expenses are allocated to the Company based on historical company policy and may not be reflective of actual expenses incurred by the Company on a stand-alone basis. Indirect allocations charged to the Company are related to corporate departments such as executive, corporate finance and treasury, legal, communications, and stock-based compensation and were $43.5 million, $23.1 million, and $18.3 million for the years ended December 31, 2012, 2011, and 2010, respectively, and included in corporate allocated expense in the accompanying combined statements of

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Combined Financial Statements (Continued)

December 31, 2012 and 2011

(16) Related-Party Transactions (Continued)

operations. For the years ended December 31, 2012, 2011, and 2010, stock-based compensation expense included in the indirect allocations was $23.9 million, $13.5 million, and $11.0 million, respectively.

The Gavilon Group also allocates corporate interest expense to the Company based on total invested and trade working capital utilized by the business and may not be reflective of interest expense incurred on a standalone basis. Interest expense allocated by The Gavilon Group to the Company was $39.3 million, $29.6 million, and $16.2 million for the years ended December 31, 2012, 2011, and 2010, respectively, and is included in the accompanying combined statement of operations.

The amounts due to (from) The Gavilon Group are classified as payable due to (from) parent in current liabilities within the accompanying combined balance sheet and reflects the net cash transferred between the Companies for operating capital requirements, which includes corporate expense and interest allocations.

(17) Subsequent Event

The Company received $29.3 million in January 2013 for a blender's tax credit from the federal government for blending biodiesel sold during 2012. This has been recognized in net sales during fiscal 2013 consistent with the enactment of the tax rule change.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Unaudited Condensed Combined Balance Sheets

September 30, 2013 and December 31, 2012

(Dollars in millions)

	September 30, 2013

Assets
Current assets:
Cash	$	206.4		5.0
Trade accounts receivable, less allowance for doubtful accounts of $0.7 and $1.0, respectively		439.3		473.5
Inventories		176.5		969.4
Derivative assets		45.9		58.4
Other current assets		12.9		21.2


Total current assets		881.0		1,527.5


Property, plant, and equipment:
Land and land improvements		13.8		13.8
Buildings		0.6		0.6
Machinery and equipment		24.8		7.9
Tanks and pipelines		88.7		88.6
Construction in progress		7.1		1.4


		135.0		112.3
Less accumulated depreciation		(19.0	)	(6.9	)


Net property, plant, and equipment		116.0		105.4
Goodwill		33.0		33.0
Intangible assets, net		11.0		15.9
Equity method investments		100.1		73.6
Other assets		12.9		13.5


Total assets	$	1,154.0		1,768.9




Liabilities and Equity
Current liabilities:
Current portion of long term debt	$	—		10.4
Accounts payable		415.3		592.2
Advances on sales		6.4		8.9
Derivative liabilities		12.2		32.2
Accrued expenses		24.8		17.6
Payable due to parent		—		434.3


Total current liabilities		458.7		1,095.6
Long-term debt		—		29.7
Other noncurrent liabilities		2.1		0.3


Total liabilities		460.8		1,125.6


Total equity:
Parent Company's equity investment		592.6		530.2
Retained earnings		99.3		111.5
Accumulated other comprehensive income		1.3		1.6


Total equity		693.2		643.3


Commitments and contingencies (note 11)
Total liabilities and equity	$	1,154.0		1,768.9

See accompanying notes to unaudited condensed combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Unaudited Condensed Combined Statements of Operations

Nine months ended September 30, 2013 and 2012

(Dollars in millions)

	Nine months ended September 30,

	2013			2012
Net sales	$	224.4			196.3
Cost of goods sold		158.4			168.2


Gross profit		66.0			28.1
Selling, general, and administrative expenses		48.9			65.3


Operating income (loss)		17.1			(37.2	)
Interest expense, net		27.5			39.8


Loss from continuing operations before income taxes		(10.4	)		(77.0	)
Income tax expense		—			(0.2	)


Loss from continuing operations		(10.4	)		(77.2	)
Net loss from discontinued operations		(1.8	)		(24.1	)


Net loss	$	(12.2	)		(101.3	)

See accompanying notes to unaudited condensed combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Unaudited Condensed Combined Statements of Comprehensive Loss

Nine months ended September 30, 2013 and 2012

(Dollars in millions)

	Nine months ended September 30,

	2013			2012
Net loss	$	(12.2	)		(101.3	)
Other comprehensive income (loss):
Foreign currency translation adjustments		—			0.2
Net loss on derivative instruments designated and qualifying as cash flow hedges		(0.2	)		(18.3	)
Available-for-sale securities		(0.1	)		—


Total comprehensive loss	$	(12.5	)		(119.4	)

See accompanying notes to unaudited condensed combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Unaudited Condensed Combined Statement of Equity

Nine months ended September 30, 2013

(Dollars in millions)

	Parent Company's equity investment

Balance at December 31, 2012	$	530.2	111.5		1.6		643.3
Net loss		—	(12.2	)	—		(12.2	)
Contributed capital		62.4	—		—		62.4
Other comprehensive loss		—	—		(0.3	)	(0.3	)


Balance at September 30, 2013	$	592.6	99.3		1.3		693.2

See accompanying notes to unaudited condensed combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Unaudited Condensed Combined Statements of Cash Flows

Nine months ended September 30, 2013 and 2012

(Dollars in millions)

	Nine months ended September 30,

	2013			2012
Cash flows from operating activities:
Net loss	$	(12.2	)		(101.3	)
Adjustments to reconcile net loss to net cash provided by (used in) operating activities:
Depreciation and amortization		9.0			8.3
Provision for bad debts		0.3			0.3
Amortization of debt issue costs		1.7			0.4
Other items		2.8			(0.4	)
Changes in operating assets and liabilities:
Accounts receivable		33.9			(286.0	)
Inventories		793.0			320.0
Other current assets		12.6			46.3
Derivative assets and liabilities		(7.7	)		(30.4	)
Accounts payable		(177.4	)		48.0
Advances on sales		(2.4	)		9.0
Other accrued liabilities		7.2			(32.0	)
Noncurrent assets and liabilities		(1.0	)		0.3


Net cash provided by operating activities		659.8			(17.5	)


Cash flows from investing activities:
Additions to property, plant, and equipment		(4.9	)		(10.7	)
Investment in equity method investments		(26.5	)		(15.7	)
��

Net cash used in investing activities		(31.4	)		(26.4	)


Cash flows from financing activities:
Issuance of long-term debt		—			4.6
Repayments of long-term debt		(40.1	)		(3.4	)
Debt issue costs		(5.8	)		—
Contribution (return of) capital		53.2			(41.8	)
Payable due to parent		(434.3	)		82.7


Net cash provided by (used in) financing activities		(427.0	)		42.1


Net change in cash and cash equivalents		201.4			(1.8	)
Cash and cash equivalents at beginning of year		5.0			12.7


Cash and cash equivalents at end of year	$	206.4			10.9




Supplemental cash and noncash flow information:
Cash paid for interest	$	1.1			1.9
Contribution of property, plant, and equipment from parent		9.2			—

See accompanying notes to unaudited condensed combined financial statements.

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(1) Business Description

The accompanying combined financial statements include the accounts of all operations that comprise the energy operations of Gavilon, LLC (collectively, the Company). The Company operates the marketing, trading, and distribution of energy commodities. Gavilon, LLC was a wholly owned subsidiary of The Gavilon Group, LLC (The Gavilon Group). During 2013, the Gavilon Group, LLC restructured Gavilon, LLC to acquire, own, and operate the energy operations, which are set forth in these combined financial statements. Historically, the business units comprising Gavilon, LLC have been consolidated with The Gavilon Group. Material related party activity is summarized in note 13. As part of the separation of the energy operations, The Gavilon Group transferred substantially all of its energy business units to Gavilon, LLC and transferred out any non-energy related business units to another subsidiary of The Gavilon Group. In addition, the Company has completed several restructuring initiatives, which have impacted the energy business units. These business units have been included in discontinued operations in the accompanying combined statements of operations for all periods presented (note 12).

(2) Basis of Presentation

The accompanying unaudited condensed combined financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim combined financial information and in accordance with the rules and regulations of the Securities and Exchange Commission (SEC). The unaudited condensed combined financial statements include all adjustments that the Company considers necessary for a fair presentation of the financial position and results of operations for the interim periods presented. Such adjustments consist only of normal recurring items, unless otherwise disclosed herein. Accordingly, the unaudited condensed combined financial statements do not include all the information and notes required by GAAP for complete annual combined financial statements. However, the Company believes that the disclosures made are adequate to make the information not misleading. These interim unaudited condensed combined financial statements should be read in conjunction with the Company's audited combined financial statements for the year ended December 31, 2012. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year.

(3) Summary of Significant Accounting Policies

(a) Use of Estimates

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(3) Summary of Significant Accounting Policies (Continued)

(b) Trade Accounts Receivable

(c) Inventories

(d) Equity Method Investments

(e) Property, Plant, and Equipment

The Company's accounting for property, plant, and equipment is to record asset additions at cost. The estimated useful lives of the respective classes of assets are as follows:


Land improvements		15 years
Buildings and building improvements		15 - 40 years
Machinery and equipment		7 - 15 years
Tanks and pipeline		5 - 40 years

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(3) Summary of Significant Accounting Policies (Continued)

flow basis, an impairment is recognized to the extent that the carrying value exceeds its fair value. Fair value is determined through various valuation techniques including discounted cash flow models, quoted market values, and third-party independent appraisals, as considered necessary. There were no circumstances that indicated the carrying value of long-lived assets or intangible assets may not be recoverable during the nine months ended September 30, 2013 or 2012.

(f) Goodwill

Goodwill represents the excess of the aggregate purchase price of acquired businesses over the estimated fair value of the net assets acquired in business combinations. Goodwill is reviewed for impairment at least annually. Goodwill is initially assessed based on qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-step goodwill impairment test. The more-likely-than-not threshold is defined as having a likelihood of more than 50%. If it is determined by this assessment that, more likely than not, goodwill is impaired, the first step of testing is to compare the fair value of the reporting unit with its carrying value (including goodwill). If the fair value of the reporting unit is less than its carrying value, an indication of goodwill impairment exists for the reporting unit and the enterprise must perform step two of the impairment test (measurement). Under step two, an impairment loss is recognized for any excess of the carrying amount of the reporting unit's goodwill over the implied fair value of that goodwill. The implied fair value of goodwill is determined by allocating the fair value of the reporting unit in a manner similar to a purchase price allocation. The residual fair value after this allocation is the implied fair value of the reporting unit goodwill. Fair value of the reporting unit is determined using a discounted cash flow analysis. If the fair value of the reporting unit exceeds its carrying value, step two does not need to be performed. The Company performs its annual impairment review of goodwill at June 30 and when a triggering event occurs between annual impairment tests. For 2013 and 2012, the Company performed a qualitative assessment of goodwill and determined that it is more likely than not that the fair values of its reporting units are greater than the carrying amounts. Accordingly, there were no impairments of goodwill for the nine months ended September 30, 2013 or 2012.

(g) Derivatives

For all hedging relationships, the Company formally documents the hedging relationship and its risk management objective and strategy for undertaking the hedge, the hedging instrument, the hedged

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(3) Summary of Significant Accounting Policies (Continued)

item, the nature of the risk being hedged, how the hedging instrument's effectiveness in offsetting the hedged risk will be assessed prospectively and retrospectively, and a description of the method of measuring ineffectiveness. The Company also formally assesses, both at the hedge's inception and on an ongoing basis, whether the derivatives that are used in hedging transactions are highly effective in offsetting cash flows of hedged items. For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income and reclassified into earnings in the same period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing hedge ineffectiveness are recognized in current earnings.

In all situations in which hedge accounting is discontinued and the derivative is retained, the Company continues to carry the derivative at its fair value on the balance sheet and recognizes any subsequent changes in its fair value in earnings. When it is probable that a forecasted transaction will not occur, the Company discontinues hedge accounting and recognizes immediately in earnings gains and losses that were accumulated in other comprehensive income.

(h) Fair Values of Financial Instruments

Unless otherwise specified, the Company believes the carrying value of its financial instruments approximates their fair value.

(i) Netting of Accounts

(j) Revenue Recognition

Revenue is recognized when title and risk of loss are transferred to customers upon delivery based on terms of sale and collectibility is reasonably assured. Changes in the fair value of commodity derivatives are recognized in earnings immediately. Sales related to trading activities are recorded net, and margins earned on such transactions are included as a component of net sales. Net sales and cost of goods sold, if reported on a gross basis for these activities, would be increased by $12,095.9 million and $13,933.1 million for the nine months ended September 30, 2013 and 2012, respectively.

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(3) Summary of Significant Accounting Policies (Continued)

(k) Income Taxes

(l) Debt Issuance Costs

The Company incurred certain financing costs associated with debt issuance (note 9). These costs were capitalized and are being amortized to expense using the effective interest rate method.

(4) Goodwill and Intangible Assets

The fair value of identifiable intangible assets consist of customer relationships (7 year weighted average useful life) and contractual obligations. Identifiable intangible assets as of September 30, 2013 and December 31, 2012 are as follows (in millions):

	Gross carrying amounts

September 30, 2013:
Customer relationships	$	43.1	(32.1	)	11.0
Contractual obligations		7.5	(7.5	)	—


Total	$	50.6	(39.6	)	11.0

	Gross carrying amounts

December 31, 2012:
Customer relationships	$	43.1	(27.3	)	15.8
Contractual obligations		7.5	(7.4	)	0.1


Total	$	50.6	(34.7	)	15.9

F-385

Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(4) Goodwill and Intangible Assets (Continued)

Aggregate amortization expense for amortizing intangible assets was $4.8 million and $4.9 million for the nine months ended September 30, 2013 and 2012, respectively. Estimated future amortization expense is $1.6 million for the last three months of 2013, $6.2 million for 2014, $3.1 million for 2015, $0.1 million for 2016.

(5) Derivatives and Hedging Activities

The Company purchases and sells commodities, such as gas, ethanol, natural gas, biodiesel and crude oil. The Company generally follows a policy of using commodity derivatives to minimize its net position of commodity inventories and forward cash purchase and sales contracts. The Company also uses commodity derivatives as components of market strategies designed to enhance margins. The results of these strategies can be significantly impacted by factors such as the volatility of the relationship between the value of commodity derivatives and the cash prices of the underlying commodities, counterparty contract defaults, and volatility of transportation markets.

The Company's policy is to report gains and losses associated with derivatives as follows:

Contract/derivative nature		Line item

Commodities		Net sales
Interest rate swap		Interest expense

While a majority of the Company's use of derivative instruments is to manage market risks by economically hedging the Company's inventory and forward purchase and sales commitments, the Company also designates cash flow hedges. The Company has designated cash flow hedges associated with the future purchase and sales of natural gas. The object of the Company's cash flow hedges is to fix the price of natural gas purchase and sales at existing market prices that the Company deems favorable.

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(5) Derivatives and Hedging Activities (Continued)

The Company entered into an interest rate swap agreement to manage the variability of cash flows over certain portions of the interest payments related to the variable rate on the term loan (note 9). The interest rate swap agreement used by the Company has been recorded at fair value in the combined balance sheets with changes in fair value recorded in accumulated other comprehensive income. This amount is subsequently reclassified into interest expense as a yield adjustment of the hedged interest payments in the same period in which the related interest affects earnings. Amounts subsequently reclassified into interest expense during the year were immaterial, and no ineffectiveness was recognized. During the nine months ended September 30, 2013, the Company settled the interest rate swap agreement for a payment of $1.1 million.

As of December 31, 2012, the fair value of the Company's interest rate swap agreement designated in a cash flow hedging relationship was an unrealized loss of $1.8 million. As of September 30, 2013 and December 31, 2012, the fair value of the Company's natural gas futures designated in a cash flow hedging relationship was $0.7 million and $3.3 million, respectively.

The following table provides information about the gain or loss recognized in income and other comprehensive income (loss) on the Company's cash flow hedging derivative instruments for the nine months ended September 30, 2013 and 2012 (in thousands). Also, the information presents the notional volume of outstanding cash flow hedge derivative contracts by type of instrument.

Cash Flow Hedges

	Gain (loss) recognized in AOCI on derivatives (effective portion)

			Gain (loss) reclassified from AOCI into income (effective portion)			Gain (loss) recognized in income on derivatives (ineffective portion)
				2013 Amount			2013 Amount
Commodity type	2013 Amount		Location	2013 Amount		Location	2013 Amount
Natural gas	$	2,162	Net sales	$	4,157	Net sales	$	—
Interest rate swaps		1,794	Interest expense		—	Interest expense		—

Commodity type	2012 Amount			Location	2012 Amount		Location	2012 Amount

Natural gas	$	554		Net sales	$	18,646	Net sales	$	—
Interest rate swaps		(213	)	Interest expense		—	Interest expense		—

Derivative instrument

Natural gas futures (MMBtu's)	3,088	931
Interest rate swaps (millions of $)	—	36

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(5) Derivatives and Hedging Activities (Continued)

The following table summarizes the Company's outstanding interest rate swap agreement as of December 31, 2012:

Term		Notional amount		Fixed rate			Variable rate

1/24/11 - 3/31/18		36 million			2.393			0.311

The Company did not exclude any components of the derivatives instruments' gains or losses from the assessment of hedge effectiveness for its cash flow hedging relationships.

The Company has designated fair value hedges used to hedge certain crude oil inventories. The following table provides information about the gain or loss recognized in income on the Company's fair value hedging derivative instruments for the nine months ended September 30, 2013 and 2012 (in thousands). Also, the information presents the notional volume (in thousands) of outstanding derivative contracts designated in the fair value hedging relationships at September 30, 2013 and December 31, 2012.

Fair Value Hedges

	Gain (loss) recognized in income on derivatives				Gain (loss) recognized in income on hedged item			Gain (loss) recognized in income on derivatives (ineffective portion)

Commodity type	Location	2013 Amount			Location	2013 Amount		Location	2013 Amount
Crude oil inventory	Net sales	$	(27,879	)	Net sales	$	6,962	Net sales	$	(20,917	)

Commodity type		Location		2012 Amount			Location		2012 Amount			Location		2012 Amount

Crude oil inventory		Net sales		$	16,636		Net sales		$	(11,972	)	Net sales		$	4,664

Derivative instrument		Notional contract volumes (as of September 30, 2013)			Notional contract volumes (as of December 31, 2012)

Crude oil futures (barrels)			580			9,661

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(5) Derivatives and Hedging Activities (Continued)

The following table summarizes the Company's notional volumes for their economic and trading derivative financial instruments as of September 30, 2013 and December 31, 2012 (amounts in thousands) by type of instrument:

	Exchange- traded			Non-exchange traded

September 30, 2013	(Short) long			(Short)			Long
Natural gas (MMBtu's):
Futures		1,670			—			—
Options		379			—			—
Swaps		(350	)		(40,026	)		73,353
Forwards		(8,538	)
Oil (barrels):
Futures		(684	)		—			—
Forwards		—			(87,224	)		87,021

	Exchange- traded

	Exchange- traded			Non-exchange traded
	Net (short) long			Non-exchange traded
December 31, 2012	Net (short) long			(Short)			Long
Natural gas (MMBtu's):
Futures		(4,700	)		—			—
Options		—			—			—
Swaps		(7,238	)		—			78
Forwards		—			(6,551	)		—
Oil (barrels):
Futures		(3,262	)		—			—
Options		35			—			—
Forwards		—			(2,112	)		2,396

The Company has established guidelines, controls, and limits to manage and mitigate credit risk within risk tolerances established by the Company's Risk Committee. In addition, the Company has a credit committee that includes senior executives who meet on a regular basis to review the Company's credit activities and monitor compliance with the policies adopted by the Company. The Company attempts to mitigate its credit exposure by setting tenor and credit limits commensurate with counterparty financial strength, obtaining master netting agreements, and mitigating credit exposure with less creditworthy counterparties through prepayments, letters of credit, and other security agreements, such as inventory, property, or other tangible assets. The use of master netting agreements is driven by industry practice, and anticipated volumes and complexity of the business relationship with the counterparty. The Company assumes credit and performance risk associated with commodity derivative contracts within the energy and agriculture industries; however, no counterparty was greater than 10% of the Company's net exposure.

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(5) Derivatives and Hedging Activities (Continued)

As of September 30, 2013, the Company held certain derivative contracts with settlement dates through 2016. However, approximately 95% of the Company's notional amount of commodity derivative contracts have settlement dates of less than one year.

(6) Equity Method Investments

The Company's equity method investment in Glass Mountain Pipeline of $100.1 million at September 30, 2013 and $73.6 million at December 31, 2012 relates to a 50% interest in a development-stage limited liability company formed in May 2012. Glass Mountain pipeline's operations consist of construction of an intrastate crude oil common carrier pipeline system in Oklahoma. Glass Mountain's total assets as of September 30, 2013 are $159.5 million and primarily represent cash and construction in progress. Glass Mountain's total liabilities as of September 30, 2013 are $21.3 million and primarily represent construction-related payables.

(7) Inventories

The major classes of inventories at September 30, 2013 and December 31, 2012 are as follows (in millions):

	September 30, 2013

Crude oil inventories carried at fair value	$	56.3	873.3
Inventories carried at lower of cost or market:
Crude oil		14.6	6.8
Natural gas		28.9	31.2
Fuels		76.7	57.6
Other		—	0.5


	$	176.5	969.4

(8) Fair Value Measurements

Financial assets and liabilities carried at fair value will be classified and disclosed in one of the following three categories:

F-390

Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(8) Fair Value Measurements (Continued)

The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were accounted for at fair value on a recurring basis as of September 30, 2013 and December 31, 2012. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels.

	September 30, 2013

	Level 1		Level 2		Level 3		Nettings			Total
Assets (in millions):
Inventory	$	56.3		—		—		—			56.3
Derivative assets		14.1		1,218.0		—		(1,186.2	)		45.9
Liabilities (in millions):
Derivative liabilities	$	—		1,198.4		—		(1,186.2	)		12.2

F-391

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GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(8) Fair Value Measurements (Continued)

	December 31, 2012

	Level 1		Level 2		Level 3		Nettings			Total
Assets (in millions):
Inventory	$	873.3		—		—		—			873.3
Derivative assets		13.1		2,930.1		—		(2,884.8	)		58.4
Liabilities (in millions):
Derivative liabilities	$	—		2,917.0		—		(2,884.8	)		32.2

(9) Credit Facility Agreement

The Company has a $650 million Credit Facility Agreement (the credit agreement) expiring in June 2014. While the credit agreement provides for up to $650 million in credit, the actual credit available is based on eligible assets of the Company as determined by the provisions included in the credit agreement and is collateralized by inventory. At September 30, 2013, the Company had no cash borrowings under the credit agreement and had outstanding letters of credit of $325.7 million.

The Company may elect to borrow under the credit agreement based on either prime rate plus 1.5% or London Interbank Offered Rate (LIBOR) plus 2.5%. Debt issue costs of $1.4 million were capitalized related to the credit facility agreement in 2013.

The Company is required to comply with certain financial covenants related to minimum interest coverage ratio and maximum leverage ratio. In addition, the credit agreement limits the amount of additional borrowings by the Company.

The Company retired the Credit Facility Agreement upon the sale of the Company in December 2013, as described in note 15.

(10) Accumulated Other Comprehensive Income

The following table summarizes the balances of accumulated other comprehensive income (in millions):

	September 30, 2013

Cash flow hedging derivatives	$	1.3		1.5
Available-for-sale securities		(0.1	)	—
Currency translation adjustment		0.1		0.1


	$	1.3		1.6

(11) Contingencies

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Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(11) Contingencies (Continued)

such matters should not have a material adverse effect on the Company's combined financial position, results of operations, or liquidity. Costs of legal services are recognized in earnings as services are provided.

(12) Discontinued Operations

These business lines meet the criteria for being reported as discontinued operations and have been segregated from continuing operations. The following table summarizes the results from discontinued operations (in millions):

	Net sales

Nine months ended September 30, 2013:
Import/export ethanol	$	(0.3	)	(0.7	)
Glycerin		0.5		(0.8	)
Thackerville propane terminal		—		(0.1	)
Weather and portfolio trading		—		(0.2	)


Total	$	0.2		(1.8	)




Nine months ended September 30, 2012:
Import/export ethanol	$	(13.0	)	(18.4	)
Glycerin		9.5		(4.1	)
Thackerville propane terminal		—		(0.1	)
Weather and portfolio trading		(1.0	)	(1.5	)


Total	$	(4.5	)	(24.1	)

(13) Related-Party Transactions

The Gavilon Group provides a variety of services to the Company, such as information technology, treasury and cash management, payroll and human resources, legal, tax, facilities, general accounting and other corporate functions. Where possible, The Gavilon Group directly allocates costs to the Company based on usage or other direct allocation methods. Direct allocations to the Company are generally related to information technology, risk management, human resources, business development, compliance and facilities. The direct allocations are included in corporate allocations in the accompanying combined statements of operations, and were $3.1 million and $5.9 million for the nine months ended September 30, 2013 and 2012, respectively.

In addition to direct allocations from The Gavilon Group, indirect corporate expenses are allocated to the Company. These expenses are allocated to the Company based on historical company

F-393

Table of Contents

GAVILON ENERGY
(The Energy Business Units of Gavilon, LLC)

Notes to Unaudited Condensed Combined Financial Statements (Continued)

As of September 30, 2013 and December 31, 2012, and for the
Nine Months Ended September 30, 2013 and 2012

(13) Related-Party Transactions (Continued)

policy and may not be reflective of actual expenses incurred by the Company on a stand-alone basis. Indirect allocations charged to the Company are related to corporate departments such as executive, corporate finance and treasury, legal, communications, and stock-based compensation and were $4.0 million and $17.0 million for the nine months ended September 30, 2013 and 2012, respectively, and included in corporate allocated expense in the accompanying combined statements of operations.

The Gavilon Group also allocates corporate interest expense to the Company based on total invested and trade working capital utilized by the business and may not be reflective of interest expense incurred on a standalone basis. Interest expense allocated by The Gavilon Group to the Company was $17.9 million and $29.4 million for the nine months ended September 30, 2013 and 2012, respectively, and is included in the accompanying combined statements of operations.

The amounts due to (from) The Gavilon Group are classified as payable due to (from) parent in current liabilities within the accompanying combined balance sheet as of December 31, 2012 and reflect the net cash transferred between the Companies for operating capital requirements, which includes corporate expense and interest allocations.

(14) Blender's Tax Credit

(15) Subsequent Event

On December 2, 2013, The Gavilon Group completed the sale of Gavilon, LLC to NGL Energy Partners LP for $890.0 million of cash. The purchase price is subject to adjustment for certain specified working capital items. The agreement for the sale of Gavilon, LLC specified that Gavilon, LLC would have $198 million of working capital, as defined in the agreement, at the closing date. At the time of closing, Gavilon, LLC paid a distribution to its parent of approximately $187 million, which was calculated as the amount by which working capital, as defined in the agreement, was estimated to exceed $198 million. Since NGL Energy Partners LP is a pass-through entity for income tax purposes, no pro forma income tax expense or benefit has been reported in these notes to unaudited condensed combined financial statements.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To NGL Energy Partners LP

�� We have audited the accompanying combined balance sheets of the Businesses Associated with TransMontaigne Inc. acquired by NGL Energy Partners LP (the "Businesses) as of December 31, 2013 and 2012, and the related combined statements of comprehensive income (loss), equity, and cash flows for the years then ended. These financial statements are the responsibility of the Businesses' management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Businesses are not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Businesses' internal control over financial reporting. Accordingly, we express no such opinion. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such combined financial statements present fairly, in all material respects, the financial position of the Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP as of December 31, 2013 and 2012, and the results of their operations and their cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Denver, Colorado
November 5, 2014
(December 24, 2014 as to Note 12)

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Combined Balance Sheets

(In thousands)

	December 31, 2013		December 31, 2012

ASSETS
Current assets:
Cash and cash equivalents	$	74,762	$	15,156
Rack sales accounts receivable, net		243,520		307,757
Pipeline sales accounts receivable		684,881		520,944
Inventories in pipelines and terminals		629,567		660,044
Inventories in transit via truck and rail		53,216		59,703
Derivative contracts		47,372		13,390
Other pipeline accrued receivables		6,123		2,808
Other		17,548		15,067


		1,756,989		1,594,869
Property, plant and equipment, net		445,495		467,187
Investment in unconsolidated affiliates		211,605		105,164
Other assets		18,357		19,469


	$	2,432,446	$	2,186,689




LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	64,351	$	100,651
Product purchases accounts payable		785,112		705,863
Excise taxes payable		39,648		55,139
Inventories due under exchange agreements		31,280		35,343
Derivative contracts		30,066		11,947
Accrued environmental obligations		4,303		6,215
Variation margin payables		35,528		30,633
Other pipeline accrued payables		20,589		18,953
Other accrued liabilities		23,263		27,935


		1,034,140		992,679
Bank debt		212,000		184,000
Other		9,362		11,895


Total liabilities		1,255,502		1,188,574


Equity:
Equity attributable to noncontrolling interests		359,418		299,205
Equity attributable to parent		817,526		698,910


		1,176,944		998,115


	$	2,432,446	$	2,186,689

See accompanying notes to combined financial statements.

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Combined Statements of Comprehensive Income (Loss)

(In thousands)

	Year ended December 31, 2013			Year ended December 31, 2012

Marketing and distribution:
Revenues	$	8,579,362		$	10,877,459
Cost of product sold and other direct costs and expenses		(8,463,720	)		(10,983,348	)


Net operating margins (loss), exclusive of depreciation and amortization shown separately below		115,642			(105,889	)


Terminals and pipelines:
Revenues		59,844			52,715
Direct costs and expenses		29,414			(21,234	)


Net operating margins, exclusive of depreciation and amortization shown separately below		30,430			31,481


Total net operating margins (loss)		146,072			(74,408	)


Costs and expenses:
Selling, general and administrative		(65,019	)		(67,971	)
Depreciation and amortization		(34,261	)		(32,267	)
Gain (loss) on disposition of assets, net		(2,022	)		856
Earnings (loss) from unconsolidated affiliates		(321	)		558


Total costs and expenses		(101,623	)		(98,824	)


Operating income (loss)		44,449			(173,232	)


Other income (expenses):
Interest expense		(5,974	)		(6,549	)
Foreign currency transaction gain (loss)		(13	)		51


Total other expenses		(5,987	)		(6,498	)


Earnings (loss) before income taxes		38,462			(179,730	)
Income tax expense		(242	)		(188	)


Net income (loss)		38,220			(179,918	)
Noncontrolling interests share in earnings of TransMontaigne Partners		(23,590	)		(27,086	)


Net income (loss) attributable to parent		14,630			(207,004	)
Other comprehensive income—foreign currency translation adjustments attributable to noncontrolling interests		56			128
Other comprehensive income—foreign currency translation adjustments attributable to parent		27			63


Comprehensive income (loss)	$	14,713		$	(206,813	)

See accompanying notes to combined financial statements.

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Combined Statements of Equity

Years ended December 31, 2012 and 2013

(in thousands)

	Equity attributable to noncontrolling interests			Equity attributable to Parent, Net			Total equity

Balance at December 31, 2011	$	301,478		$	1,280,928		$	1,582,406
Distributions paid to noncontrolling TransMontaigne Partners' common units		(29,801	)		—			(29,801	)
Purchase of common units by TransMontaigne Partners' long-term incentive plan		(239	)		—			(239	)
Deferred equity-based compensation related to restricted phantom units and other		553			—			553
Net income (loss)		27,086			(207,004	)		(179,918	)
Net capital distributed to parent company		—			(375,077	)		(375,077	)
Other comprehensive income—foreign currency translation adjustments		128			63			191


Balance at December 31, 2012		299,205			698,910			998,115
Proceeds from offering of TransMontaigne Partners' common units		68,774			—			68,774
Distributions paid to noncontrolling TransMontaigne Partners' common units		(32,419	)		—			(32,419	)
Purchase of common units by TransMontaigne Partners' long-term incentive plan		(335	)		—			(335	)
Deferred equity-based compensation related to restricted phantom units and other		289			—			289
Net income		23,590			14,630			38,220
Net capital contributed by parent company		—			103,825			103,825
Other comprehensive income—foreign currency translation adjustments		56			27			83
Foreign currency translation adjustments reclassified in entirety into loss on disposition of assets, net, upon the sale of TransMontaigne Partners' Mexico operations		258			134			392


Balance at December 31, 2013	$	359,418		$	817,526		$	1,176,944

See accompanying notes to combined financial statements.

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Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Combined Statements of Cash Flows

(In thousands)

	Year ended December 31, 2013			Year ended December 31, 2012

Cash flows from operating activities:
Net income (loss)	$	38,220		$	(179,918	)
Adjustments to reconcile net income to net cash provided (used) by operating activities:
Depreciation and amortization		34,261			32,267
Loss (gain) on disposition of assets, net		2,022			(856	)
Amortization of financing costs		1,373			1,165
Loss (earnings) from unconsolidated affiliates		321			(558	)
Distributions from unconsolidated affiliates		1,467			1,435
Amortization of deferred revenue, utility deposits returned and other		(6,060	)		(3,430	)
Changes in operating assets and liabilities:
Rack sales accounts receivable, net		64,111			61,962
Pipeline sales accounts receivable		(163,937	)		(96,685	)
Inventories in pipelines and terminals		30,477			180,905
Inventories in transit via truck and rail		6,487			10,457
Derivative contracts		(15,864	)		688
Other pipeline accrued receivables		(3,315	)		166
Other current assets		(3,109	)		(955	)
Accounts payable		(33,531	)		30,194
Product purchases accounts payable		79,249			308,006
Excise taxes payable		(15,489	)		(6,855	)
Inventory due under exchange agreements		(4,063	)		15,435
Accrued environmental liabilities		(1,912	)		238
Variation margin payables		4,895			11,688
Other pipeline accrued payables		1,636			2,291
Other current liabilities		(2,187	)		(1,652	)


Net cash provided by operating activities		15,052			365,988


Cash flows from investing activities:
Investments in unconsolidated affiliates		(108,229	)		(80,166	)
Capital expenditures		(17,405	)		(31,178	)
Proceeds from sale of assets		2,294			19,085


Net cash used in investing activities		(123,340	)		(92,258	)


Cash flows from financing activities:
Proceeds from issuance of TransMontaigne Partners' common units		68,774			—
Borrowings of bank debt		168,500			147,000
Repayments of bank debt		(140,500	)		(83,000	)
Deferred debt issuance costs		—			(736	)
Net capital contributed by (distributed to) parent company		103,825			(375,077	)
Distributions paid to noncontrolling TransMontaigne Partners' common units		(32,419	)		(29,801	)
Purchase of common units by TransMontaigne Partners' long-term incentive plan		(335	)		(239	)


Net cash provided by (used in) financing activities		167,845			(341,853	)


Increase (decrease) in cash and cash equivalents		59,557			(68,123	)
Foreign currency translation effect on cash		49			63


Cash and cash equivalents at beginning of year		15,156			83,216


Cash and cash equivalents at end of year	$	74,762		$	15,156




Supplemental disclosures of cash flow information:
Cash paid for interest expense	$	(4,443	)	$	(5,430	)




Property, plant and equipment acquired with accounts payable	$	718		$	3,473

See accompanying notes to combined financial statements.

F-399

Table of Contents

Notes to Combined Financial Statements

Years ended December 31, 2013 and 2012

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Nature of business

The accompanying combined financial statements include the accounts of all operations of the Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP (collectively, the "Company", "we", "us" or "our"). On July 1, 2014, Morgan Stanley consummated the sale of its indirect 100% ownership interest in the Business to NGL Energy Partners LP ("NGL"). TransMontaigne Inc. is the indirect parent and sole member of TransMontaigne GP L.L.C., which is the sole general partner ("General Partner") of TransMontaigne Partners L.P. ("TLP" or the "Partnership"), a publicly traded master limited partnership. The sale also included Morgan Stanley's limited partnership interests in TLP, the assignment from an affiliate of Morgan Stanley to NGL of certain terminaling services agreements with TLP, and the transfer of certain inventory owned by Morgan Stanley (collectively, the "Transaction"). The Transaction does not involve the sale or purchase of any of the limited partnership units in TLP held by the public and the TLP limited partnership units continue to trade on the New York Stock Exchange.

TransMontaigne Inc., ("TransMontaigne") is a Delaware corporation headquartered in Denver, Colorado, that was formed in 1995 as a refined petroleum products marketing and distribution company. TransMontaigne and its wholly-owned subsidiaries conduct operations in the United States primarily in the Southeast, Florida, and Midwest regions. TransMontaigne primarily provides integrated marketing and distribution services to end-users of refined petroleum products and, to a lesser extent, users of crude oil and renewable fuels.

TransMontaigne's less than wholly-owned subsidiary includes the publicly traded master limited partnership of TLP. TLP was formed in February 2005 as a Delaware limited partnership to own and operate refined petroleum products terminaling and transportation facilities. TLP conducts its operations in the United States along the Gulf Coast, in the Midwest, in Houston and Brownsville, Texas, along the Mississippi and Ohio rivers, and in the Southeast. TLP provides integrated terminaling, storage, transportation and related services for companies engaged in the trading, distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. TransMontaigne and NGL, subsequent to the Transaction, have an interest in TLP through the ownership of approximately 20% of the limited partner interests, a 2% general partner interest and the incentive distribution rights.

(b) Basis of presentation and use of estimates

In preparing the combined financial statements, we have followed the accounting policies of Morgan Stanley, a broker—dealer, and TransMontaigne Inc., which are in accordance with United States generally accepted accounting principles or "GAAP". The combined financial statements of the Company have been prepared from the separate records maintained by Morgan Stanley and TransMontaigne Inc. and may not necessarily be indicative of the conditions that would have existed, or the results of operations, if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various assets comprising the Company, Morgan Stanley's net investment in the business is shown as net parent equity, in lieu of owner's equity, in the combined financial statements. All intercompany balances have been eliminated. Transactions between us and Morgan Stanley operations have been identified in the combined financial statements as transactions between affiliates. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the combined financial statements.

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Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. The following estimates, in our opinion, are subjective in nature and require the exercise of judgment: allowance for doubtful accounts; fair value of inventories; fair value of derivative contracts; useful lives of our plant and equipment; and accrued environmental obligations. Changes in these estimates and assumptions will occur as a result of the passage of time and the occurrence of future events. Actual results could differ from these estimates.

(c) Accounting for marketing and distribution operations

In our marketing and distribution operations, we enter into contracts to purchase refined petroleum products, renewable fuel products and crude oil, schedule them for delivery to our terminals, as well as terminals owned by third parties, and then sell those products to our customers through rack spot sales, contract sales, and bulk sales. Revenue from our sales of physical inventory is recognized pursuant to the accrual method of accounting. Revenue from rack spot sales and contract sales is recognized when the product is delivered to the customer through a truck loading rack or marine fueling equipment. Revenue from bulk sales is recognized when the title to the product is transferred to the customer, which generally occurs upon delivery of the sale. Taxes collected from customers and remitted to taxing authorities are reported on a net basis in the combined statements of comprehensive income (loss).

Storage and transportation costs attributable to our marketing and distribution operations are included in cost of product sold in the accompanying combined statements of comprehensive income (loss). Storage costs at our terminals include the direct operating costs and expenses associated with our terminal operations, out of which we market and distribute our petroleum products. Such costs consist of directly related wages and employee benefits for employees working at the terminals, utilities, communications, repairs and maintenance, rent, property taxes, vehicle expenses, environmental compliance costs, materials and supplies. Storage costs at terminals owned by third parties include contractual amounts agreed to between us and third parties under terminaling services agreements.

Gains and losses associated with hedging the value of petroleum products owned and included in inventory and trading around that inventory are recorded on a net basis within cost of product sold in the accompanying combined statements of comprehensive income (loss).

(d) Accounting for terminal and pipeline operations

In connection with our terminal and pipeline operations, we utilize the accrual method of accounting for revenue and expenses. We generate revenue in our terminal and pipeline operations from transactions with unaffiliated third parties primarily for terminaling services fees and pipeline transportation fees. Terminaling services revenue is recognized ratably over the term of the agreement for storage fees and minimum revenue commitments that are fixed at the inception of the agreement and when product is delivered to the customer for fees based on a rate per barrel of throughput; pipeline transportation revenue is recognized when the product has been delivered to the customer at the specified delivery location.

Direct operating costs and expenses for our terminal and pipeline operations consist of direct operating costs and expenses associated with our terminal operations under contract with unaffiliated

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Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

third parties. Such costs consist of directly related wages and employee benefits for employees working at the terminals, utilities, communications, repairs and maintenance, rent, property taxes, vehicle expenses, environmental compliance costs, materials and supplies.

(e) Cash and cash equivalents

We consider all short-term investments with a remaining maturity of three months or less at the date of purchase to be cash equivalents.

Restricted cash represents cash deposits to help sustain the TransMontaigne credit facility committed amounts. Restricted cash amounts of approximately $1.0 million and $1.1 million at December 31, 2013 and 2012, respectively, are included in other current assets in the accompanying combined balance sheets.

(f) Inventories

Our inventories are composed of volumes held in pipelines and terminals and volumes in transit via truck and rail. Our inventories consist of refined petroleum products, primarily gasolines and distillates, ethanol and crude oil. As these inventories are directly held by Morgan Stanley, which is a broker/dealer, the inventories presented in the accompanying combined balance sheets are carried at fair value to follow the practices of broker/dealer accounting and to be consistent with Morgan Stanley's historical accounting policies. As noted in the Basis of Presentation, we have applied the parent entity's accounting policies. Historical cost was not reasonably available from Morgan Stanley.

(g) Derivative contracts and variation margin payables

Certain of our commodity contract purchases and sales with firmly committed pricing structures qualify as over-the-counter derivative instruments. Our over-the-counter derivative instruments are reported as assets and liabilities and are measured at fair value in the accompanying combined balance sheets in accordance with generally accepted accounting principles. The net changes in the fair value of our over-the-counter derivative contracts are included within cost of product sold in the accompanying combined statements of comprehensive income (loss).

We also enter into derivative risk management contracts, principally NYMEX futures contracts, which are measured at fair value to manage our exposure to changes in commodity prices that are intended to offset the changes in the values of our inventories. We evaluate our market risk exposure from an overall portfolio basis that considers changes in physical inventories. At December 31, 2013 and 2012, net unrealized losses on our unsettled futures derivative contracts were recorded as variation margin payables in the accompanying combined balance sheets and are included within cost of product sold in the accompanying combined statements of comprehensive income (loss).

(h) Inventories due under exchange agreements

We enter into refined product exchange agreements with major oil companies. Exchange agreements generally are fixed term agreements that involve our receipt of a specified volume of product at one location in exchange for delivery by us of a specified volume of product at a different location. The amount recorded represents the fair value of inventory due to others under exchange agreements. At December 31, 2013 and 2012, current liabilities include inventory due to others under

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

exchange agreements of 271,429 barrels and 277,652 barrels, respectively, with a fair value of approximately $28.4 million and $28.3 million, respectively.

(i) Property, plant and equipment

Depreciation is computed using the straight-line method. Estimated useful lives are 15 to 25 years for terminals and pipelines and 3 to 25 years for furniture, fixtures and equipment. All items of property, plant and equipment are carried at cost. Expenditures that increase capacity or extend useful lives are capitalized. Repairs and maintenance are expensed as incurred.

We evaluate long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying value of an asset group may not be recoverable based on expected undiscounted future cash flows attributable to that asset group. If an asset group is impaired, the impairment loss to be recognized is the excess of the carrying amount of the asset group over its estimated fair value.

(j) Investments in unconsolidated affiliates

We account for investments in unconsolidated affiliates, which we do not control but do have the ability to exercise significant influence over, using the equity method of accounting. Under this method, the investment is recorded at acquisition cost, increased by our proportionate share of any earnings and additional capital contributions and decreased by our proportionate share of any losses, distributions received, and amortization of any excess investment. Excess investment is the amount by which our total investment exceeds our proportionate share of the book value of the net assets of the investment entity. We evaluate our investments in unconsolidated affiliates for impairment whenever events or circumstances indicate there is a loss in value of the investment that is other than temporary. In the event of impairment, we would record a charge to earnings to adjust the carrying amount to fair value.

(k) Environmental obligations

We accrue for environmental costs that relate to existing conditions caused by past operations when estimable. Environmental costs include initial site surveys and environmental studies of potentially contaminated sites, costs for remediation and restoration of sites determined to be contaminated and ongoing monitoring costs. Liabilities for environmental costs at a specific site are initially recorded, on an undiscounted basis, when it is probable that we will be liable for such costs, and a reasonable estimate of the associated costs can be made based on available information. Such an estimate includes our share of the liability for each specific site and the sharing of the amounts related to each site that will not be paid by other potentially responsible parties, based on enacted laws and adopted/regulations and policies. Adjustments to initial estimates are recorded, from time to time, to reflect changing circumstances and estimates based upon additional information developed in subsequent periods. Estimates of our ultimate liabilities associated with environmental costs are particularly difficult to make with certainty due to the number of variables involved, including the early stage of investigation at certain sites, the lengthy time frames required to complete remediation, technology changes, alternatives available and the evolving nature of environmental laws and regulations.

We periodically file claims for insurance recoveries of certain environmental remediation costs with our insurance carriers under our comprehensive liability policies.We recognize our insurance recoveries in the period that we assess the likelihood of recovery as being probable (i.e., likely to occur).

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Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

(l) Asset retirement obligations

Asset retirement obligations are legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development or normal use of the asset. Generally accepted accounting principles require that the fair value of a liability related to the retirement of long-lived assets be recorded at the time a legal obligation is incurred. Once an asset retirement obligation is identified and a liability is recorded, a corresponding asset is recorded, which is depreciated over the remaining useful life of the asset. After the initial measurement, the liability is adjusted to reflect changes in the asset retirement obligation. If and when it is determined that a legal obligation has been incurred, the fair value of any liability is determined based on estimates and assumptions related to retirement costs, future inflation rates and interest rates. Our long-lived assets consist of above-ground storage facilities and underground pipelines. We are unable to predict if and when these long-lived assets will become obsolete and require dismantlement. We have not recorded an asset retirement obligation, or corresponding asset, because the future dismantlement and removal dates of our long-lived assets are indeterminable and the amount of any associated costs are believed to be insignificant. Changes in our assumptions and estimates may occur as a result of the passage of time and the occurrence of future events.

(m) Income taxes

Our income taxes are presented on a separate return basis, although our historical operations were included in the U.S. federal and state filings of Morgan Stanley or its subsidiaries. We utilize the asset and liability method of accounting for income taxes. Under this method, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply in the years in which these temporary differences are expected to be recovered or settled. Changes in tax rates are recognized in income in the period that includes the enactment date. We periodically assess the likelihood that we will be able to recover our deferred tax assets and reflect any changes in our estimate to the valuation allowance, with an adjustment to earnings.

In assessing our need for a valuation allowance, we look to the future reversal of our taxable temporary differences, taxable income in carryback years, the feasibility of tax planning and estimated future taxable income. The valuation allowance may be affected by changes in tax law, statutory tax rates and estimated future income.

TLP is treated as a partnership for federal income taxes. As a partnership, all income, gains, losses, expenses, deductions and tax credits generated by TLP flow through to the unitholders of the partnership.

(2) CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE

Our primary marketing and distribution areas are located in the Midwest, Florida and the Southeast regions of the United States. We have a concentration of trade receivable balances due from major integrated oil companies, independent oil companies and other wholesalers. These concentrations of customers may affect our overall credit risk in that the customers may be similarly affected by changes in economic, regulatory or other factors. Our customers' historical and future credit positions are analyzed prior to extending credit. We manage our exposure to credit risk through credit analysis,

F-404

Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(2) CONCENTRATION OF CREDIT RISK AND TRADE ACCOUNTS RECEIVABLE (Continued)

credit approvals, credit limits and monitoring procedures, and for certain transactions we may request letters of credit, prepayments or guarantees.

Pipeline sales accounts receivable consist of uncollected sales occurring while our inventory product is located in a pipeline, such as the Colonial and Plantation pipelines located in Southeast regions of the United States. Product sold in the pipeline never reaches our terminals. Whereas rack sales accounts receivable consist of uncollected sales sold out of our terminals, or third party terminals that we lease. Our pipeline sales tend to be to major integrated oil companies, for which our counterparty credit risk is deemed minimal, and thus we have not historically recorded any allowance for doubtful accounts related to these receivables. We maintain allowances for potentially uncollectible accounts receivable related to our rack sales. We write off accounts receivable against the allowance for doubtful accounts when collection efforts have been exhausted.

Rack sales accounts receivable, net consists of the following (in thousands):

	December 31, 2013			December 31, 2012

Trade accounts receivable	$	247,329		$	313,194
Less allowance for doubtful accounts		(3,809	)		(5,437	)


	$	243,520		$	307,757

The following table presents a rollforward of our allowance for doubtful accounts (in thousands):

	Balance at beginning of period		Charged to expenses		Deductions			Balance at end of period

2013	$	5,437	$	—	$	(1,628	)	$	3,809
2012	$	5,438	$	646	$	(647	)	$	5,437

No single customer accounted for 10% or more of total revenues for the years ended December 31, 2013 or 2012.

On the December 31, 2013 combined balance sheet, approximately $75 million of accounts receivable are reported net of accounts payable to the same counterparty.

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Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(3) INVENTORIES

Our inventories are carried at fair value (see Note 1 of Notes to consolidated financial statements), and the classes of inventories are as follows (amounts and volume of barrels in thousands):

Inventories in pipelines and terminals:

	December 31, 2013				December 31, 2012

	Amount		Barrels		Amount		Barrels
Gasoline	$	400,120		3,618	$	438,820		3,978
Distillate		220,702		1,736		155,828		1,200
Ethanol		7,946		98		38,667		401
Crude oil		799		8		19,480		211
Other		—		—		7,249		1,139


	$	629,567		5,460	$	660,044		6,929

Inventories in transit via truck and rail:

	December 31, 2013				December 31, 2012

	Amount		Barrels		Amount		Barrels
Gasoline	$	16,725		176	$	25,898		256
Distillate		13,516		111		3,501		30
Ethanol		17,193		218		27,141		288
Crude oil		5,782		59		1,019		11
Other		—		—		2,144		57


	$	53,216		564	$	59,703		642

(4) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net is as follows (in thousands):

	December 31, 2013			December 31, 2012

Land	$	57,568		$	57,701
Terminals, pipelines and equipment		601,921			591,788
Furniture, fixtures and equipment		20,941			15,235
Construction in progress		3,691			8,101


		684,121			672,825
Less accumulated depreciation		(238,626	)		(205,638	)


	$	445,495		$	467,187

(5) INVESTMENT IN UNCONSOLIDATED AFFILIATES

At December 31, 2013 and 2012, our investments in unconsolidated affiliates include a 42.5% ownership interest in Battleground Oil Specialty Terminal Company LLC ("BOSTCO") and a 50%

F-406

Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(5) INVESTMENT IN UNCONSOLIDATED AFFILIATES (Continued)

interest in Frontera Brownsville LLC ("Frontera"). BOSTCO is a terminal facility construction project for approximately 7.1 million barrels of storage capacity at an estimated cost of approximately $535 million. BOSTCO is located on the Houston Ship Channel and began initial commercial operations in the fourth quarter of 2013. Frontera is a terminal facility located in Brownsville, Texas that includes approximately 1.5 million barrels of light petroleum product storage capacity, as well as related ancillary facilities.

The following table summarizes our investments in unconsolidated affiliates:

	Percentage of ownership December��31,						Carrying value (in thousands) December 31,

	2013			2012			2013		2012
BOSTCO		42.5	%		42.5	%	$	186,181	$	78,930
Frontera		50	%		50	%		25,424		26,234


Total investments in unconsolidated affiliates							$	211,605	$	105,164

At December 31, 2013 and 2012, our investment in BOSTCO includes approximately $6.4 million and $2.7 million, respectively, of excess investment related to a one time buy-in fee to acquire our 42.5% interest and capitalization of interest on our investment during the construction of BOSTCO. Excess investment is the amount by which our investment exceeds our proportionate share of the book value of the net assets of the BOSTCO entity.

Earnings (loss) from investments in unconsolidated affiliates were as follows (in thousands):

	Year ended December 31, 2013			Year ended December 31, 2012

BOSTCO	$	(826	)	$	—
Frontera		505			558


Total earnings from unconsolidated affiliates	$	(321	)	$	558

Additional capital investments in unconsolidated affiliates were as follows (in thousands):

	Year ended December 31, 2013		Year ended December 31, 2012

BOSTCO	$	108,077	$	78,930
Frontera		152		1,236


Additional capital investments in unconsolidated affiliates	$	108,229	$	80,166

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Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(5) INVESTMENT IN UNCONSOLIDATED AFFILIATES (Continued)

Cash distributions received from unconsolidated affiliates were as follows (in thousands):

	Year ended December 31, 2013		Year ended December 31, 2012

BOSTCO	$	—	$	—
Frontera		1,467		1,435


Cash distributions from unconsolidated affiliates	$	1,467	$	1,435

The summarized financial information of our unconsolidated affiliates was as follows (in thousands):

Balance sheets:

	BOSTCO December 31,						Frontera December 31,

	2013			2012			2013			2012
Current assets	$	30,776		$	21		$	4,465		$	4,209
Long-term assets		458,707			231,537			47,691			50,013
Current liabilities		(66,469	)		(52,233	)		(1,308	)		(1,754	)
Long-term liabilities		—			—			—			—


Net assets	$	423,014		$	179,325		$	50,848		$	52,468

Statements of comprehensive income (loss):

	BOSTCO Year ended December 31,						Frontera Year ended December 31,

	2013			2012			2013			2012
Revenue	$	3,917		$	—		$	12,388		$	11,539
Expenses		(5,854	)		(7	)		(11,378	)		(10,423	)


Net earnings and comprehensive income (loss)	$	(1,937	)	$	(7	)	$	1,010		$	1,116

(6) DERIVATIVE CONTRACTS

The Company purchases and sells commodities, such as gasoline, distillate, ethanol and crude oil. The Company generally follows a policy of using over-the-counter commodity derivatives as components of market strategies designed to enhance margins. The results of these strategies can be significantly impacted by factors such as the volatility of the relationship between the value of commodity derivatives and the prices of the underlying commodities, counterparty contract defaults, and volatility of transportation markets.

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Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(6) DERIVATIVE CONTRACTS (Continued)

The majority of the Company's commodity purchase and sales contracts qualify as over-the-counter derivative instruments and the change in fair value is reported in cost of product sold within the marketing and distribution section of the accompanying combined statements of comprehensive income (loss). Changes in the fair value of our derivatives are recognized in earnings. The Company reports the fair value of its over-the-counter derivative assets and liabilities on the combined balance sheets as derivative contract assets and liabilities.

The Company has established guidelines to manage and mitigate credit risk within risk tolerances. The Company attempts to mitigate its credit exposure by setting tenor and credit limits commensurate with counterparty financial strength and obtaining master netting agreements. The use of master netting agreements is driven by industry practice, and anticipated volumes and complexity of the business relationship with the counterparty.

��The following table provides information about our derivative asset contract positions, net at December 31, 2013 (in thousands):

Derivative type		Gross derivative assets			Counterparty liabilities netted against assets			Fair value of derivative assets, net

Bilateral over-the-counter contracts		$	54,119		$	(6,747	)	$	47,372

The following table provides information about our derivative asset contract positions, net at December 31, 2012 (in thousands):

Derivative type		Gross derivative assets			Counterparty liabilities netted against assets			Fair value of derivative assets, net

Bilateral over-the-counter contracts		$	22,868		$	(9,478	)	$	13,390

The following table provides information about our derivative liability contract positions, net at December 31, 2013 (in thousands):

Derivative type		Gross derivative liabilities			Counterparty assets netted against liabilities			Fair value of derivative liabilities, net

Bilateral over-the-counter contracts		$	36,870		$	(6,804	)	$	30,066

The following table provides information about our derivative liability contract positions, net at December 31, 2012 (in thousands):

Derivative type		Gross derivative liabilities			Counterparty assets netted against liabilities			Fair value of derivative liabilities, net

Bilateral over-the-counter contracts		$	21,425		$	(9,478	)	$	11,947

(7) BANK DEBT

TLP Credit Facility

On March 9, 2011, TLP entered into an amended and restated senior secured credit facility, or the "TLP credit facility", which has been subsequently amended from time to time. The TLP credit facility

F-409

Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(7) BANK DEBT (Continued)

provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined: $339.2 million at December 31, 2013). TLP may elect to have loans under the TLP credit facility that bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. TLP's obligations under the TLP credit facility are secured by a first priority security interest in favor of the lenders in the majority of the TLP assets.

The terms of the TLP credit facility include covenants that restrict TLP's ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of its "available cash" as defined in the TLP partnership agreement. TLP may make acquisitions and investments that meet the definition of "permitted acquisitions"; "other investments" which may not exceed 5% of "consolidated net tangible assets"; and "permitted JV investments". Permitted JV investments include up to $225 million of investments in BOSTCO, the "Specified BOSTCO Investment". In addition to the Specified BOSTCO Investment, under the terms of the TLP credit facility, TLP may make an additional $75 million of other permitted JV investments (including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

The following table summarizes the assets and liabilities of TLP at December 31, 2013 (in thousands):


Cash and cash equivalents	$	3,263
Trade accounts receivable, net		6,427
Receivables from affiliates		2,257
Other current assets		3,478
Property, plant and equipment, net		407,045
Investments in unconsolidated affiliates		211,605
Other assets, net		14,357


Total assets	$	648,432




Trade accounts payable	$	5,717
Accrued liabilities		16,189
Long-term debt		212,000
Other noncurrent liabilities		6,059
Equity attributable to noncontrolling interests		359,418
Equity attributable to parent		49,049


Total liabilities and equity	$	648,432

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(7) BANK DEBT (Continued)

secured leverage ratio test (not to exceed 3.75 times) in the event TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). If TLP were to fail any financial performance covenant, or any other covenant contained in the TLP credit facility, TLP would seek a waiver from its lenders under such facility. If TLP were unable to obtain a waiver from its lenders and the default remained uncured after any applicable grace period, TLP would be in breach of the TLP credit facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. TLP was in compliance with all of the financial covenants under the credit facility as of December 31, 2013.

For the years ended December 31, 2013 and 2012, the weighted average interest rate on borrowings under the TLP credit facility was approximately 2.5% and 2.4%, respectively. At December 31, 2013 and 2012, TLP's outstanding borrowings under the TLP credit facility were $212 million and $184 million, respectively. At December 31, 2013 and 2012, TLP had no outstanding letters of credit.

TLP has an effective universal shelf registration statement on Form S-3 with the Securities and Exchange Commission that expires in June 2016. TLP Finance Corp., a 100% owned subsidiary of TLP, may act as a co-issuer of any debt securities issued pursuant to that registration statement. TLP and TLP Finance Corp. have no independent assets or operations. TLP's operations are conducted by its subsidiaries, including its 100% owned operating company subsidiary, TransMontaigne Operating Company L.P. Each of TransMontaigne Operating Company L.P. and TLP's other 100% owned subsidiaries (other than TLP Finance Corp., whose sole purpose is to act as co-issuer of any debt securities) may guarantee the debt securities. TLP expects that any guarantees will be full and unconditional and joint and several, subject to certain automatic customary releases, including sale, disposition, or transfer of the capital stock or substantially all of the assets of a subsidiary guarantor, exercise of legal defeasance option or covenant defeasance option, and designation of a subsidiary guarantor as unrestricted in accordance with the indenture. There are no significant restrictions on the ability of TLP or any guarantor to obtain funds from its subsidiaries by dividend or loan. None of the assets of TLP or a guarantor represent restricted net assets pursuant to the guidelines established by the Securities and Exchange Commission.

TransMontaigne Credit Facility

TransMontaigne has a senior secured working capital credit facility, or the "TransMontaigne credit facility" that provides for a maximum borrowing line of credit equal to the lesser of (i) $150 million or (ii) the borrowing base, which is a function of, among other things, restricted cash maintained in a specified account, accounts receivable, inventory and certain reserve adjustments as defined in the facility (as defined: $118.9 million at December 31, 2013). In addition, outstanding letters of credit are counted against the maximum borrowing capacity available at any time. Borrowings under the TransMontaigne credit facility bear interest (at TransMontaigne's option) based on a base rate plus an applicable margin, or LIBOR plus an applicable margin; the applicable margins range from 2% to 3% and are a function of the average excess borrowing base availability. In addition, TransMontaigne pays a commitment fee ranging from 0.50% to 0.625% per annum on the total amount of the unused commitments. Borrowings under the TransMontaigne credit facility are secured by the majority of the TransMontaigne's and its wholly-owned subsidiaries' assets, which excludes all TLP assets. The principal balance of loans and any accrued and unpaid interest is scheduled to be due and payable in full on the

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(7) BANK DEBT (Continued)

maturity date August 15, 2015. TransMontaigne primarily utilizes the facility to finance its crude oil marketing operations through the issuance of letters of credit to crude oil producers.

For the years ended December 31, 2013 and 2012, the weighted average interest rate on letters of credit under the TransMontaigne credit facility was approximately 2.6% and 2.7%, respectively. At December 31, 2013 and 2012, TransMontaigne had no outstanding borrowings under the TransMontaigne credit facility. At December 31, 2013 and 2012, TransMontaigne's outstanding letters of credit were approximately $51.0 million and $52.5 million, respectively.

In connection with the July 1, 2014 sale to NGL, and immediately prior thereto, the TransMontaigne credit facility was terminated.

(8) INCOME TAXES

The Company's operating results have been included in the consolidated U.S. Federal and state income tax returns of Morgan Stanley. The amounts presented in the combined financial statements related to the Company's income taxes as determined as if the taxes were prepared on a separate tax return basis. Our separate return basis tax attributes may not reflect the tax positions taken or to be taken by Morgan Stanley. In many cases, the tax losses and other tax attributes of TransMontaigne have been utilized or are available to be utilized by Morgan Stanley, and may remain with Morgan Stanley after the separation of the Company from Morgan Stanley.

Income tax (expense) benefit from continuing operations on a separate return basis consists of the following (in thousands):

	Years ended December 31,

	2013			2012
Current:
Federal income taxes	$	—		$	—
State income taxes		(242	)		(188	)


Current income taxes		(242	)		(188	)


Deferred:
Federal income taxes		—			—
State income taxes		—			—


Deferred income taxes		—			—


Income tax benefit (expense)	$	(242	)	$	(188	)

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(8) INCOME TAXES (Continued)

Income tax expense differs from the amount computed by applying the federal statutory corporate income tax rate of 35% to pretax earnings as a result of the following (in thousands):

	Years ended December 31,

	2013			2012
Computed "expected" tax benefit (expense)	$	(13,117	)	$	62,864
Increase (reduction) in income taxes resulting from:
Nontaxable portion of NCI in TLP		8,247			9,480
Change in valuation allowance		5,393			(80,754	)
State income taxes, net of federal income tax benefit		(619	)		8,415
Other, net		(146	)		(193	)


Income tax benefit (expense)	$	(242	)	$	(188	)

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities are as follows (in thousands):

	December 31, 2013			December 31, 2012

Current deferred tax assets (liabilities):
Accrued liabilities, principally due to differences in accounting methods	$	5,184		$	6,608


Long-term deferred tax assets (liabilities):
Intangible assets, principally due to differences in amortization methods	$	(1,159	)	$	(1,258	)
Investment in TransMontaigne Partners		(29,271	)		(26,969	)
Intangible assets, principally due to differences in amortization methods and impairment allowances		2,117			2,800
Net operating losses		85,019			84,776
Plant and equipment, principally due to differences in depreciation methods		(5,989	)		(4,663	)


Total long-term deferred tax assets		50,717			54,686


Valuation allowance		(55,901	)		(61,294	)


Net deferred tax assets (liabilities)	$	—		$	—

As of December 31, 2013 and 2012, TransMontaigne had no unrecognized tax benefits. There was no change in the amount of unrecognized tax benefits as a result of tax positions taken during the year or in prior periods or due to settlements with taxing authorities or lapses of applicable statutes of limitations. TransMontaigne is open to federal and state tax audits until the applicable statutes of limitations expire, including those applicable to Morgan Stanley. Tax audits are currently in process for several jurisdictions where TransMontaigne was part of the consolidated tax filings of Morgan Stanley. As a result, the statute of limitations is open for tax years since 2006. After consideration of tax losses made available to Morgan Stanley, TransMontaigne has state net operating loss carryforwards of $16.6 million and $9.6 million, respectively, which expire in the years 2015 to 2033, that will be

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(8) INCOME TAXES (Continued)

available to offset future taxable income after the Transaction. Due to the change in ownership of TransMontaigne, the net operating losses could be subject to certain limitations under Section 382 of the Internal Revenue Code of 1986, as amended.

In assessing the realizability of deferred tax assets, management considers whether it is more likely than not that some portion or all of the deferred tax assets will be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. The Company considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Based upon the expected timing of the reversal of taxable temporary differences and the realizability of the deferred tax assets on a separate return basis over the periods in which the deferred tax assets are deductible, the Company believes the "more likely than not" criterion has not been satisfied as of December 31, 2013 and 2012, and the benefits of future deductible differences have been fully valued.

(9) FAIR VALUE MEASUREMENTS

Generally accepted accounting principles define fair value, establish a framework for measuring fair value and require disclosures about fair value measurements. Generally accepted accounting principles also establish a fair value hierarchy that maximizes the use of relevant observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect their placement within the fair value hierarchy levels. The three levels of the fair value hierarchy are:


Level 1	—	Unadjusted quoted prices available in active markets that are accessible at the measurement date for identical unrestricted assets or liabilities. This level primarily consists of financial instruments such as exchange-traded securities and listed derivatives.
Level 2	—	Pricing inputs include quoted prices for identical or similar assets and liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability, and inputs that are derived principally from or corroborated by observable market data by correlation or other means.
Level 3	—	Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs reflect management's best estimate of fair value using its own assumptions about the assumptions a market participant would use in pricing the asset or liability.

The Company's inventory related assets and liabilities, its over-the-counter commodity purchase and sale derivative contracts and its variation margin payables are classified as Level 2 of the fair value hierarchy. The Company estimates fair values based on exchange quoted commodity prices, adjusted as appropriate for contract terms (including maturity) and differences in local markets. These differences are generally valued using inputs from broker or dealer quotations, published indices and consumer pricing services. The determination of the fair values for the derivative contracts and variation margin payables also factor the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit, and priority interests), and also the impact of the

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(9) FAIR VALUE MEASUREMENTS (Continued)

Company's nonperformance risk on its liabilities. The Company is able to classify these fair value balances based on the observability of inputs.

	December 31, 2013

	Level 1		Level 2		Level 3		Total
Assets carried at fair value (in thousands):
Inventories in pipelines and terminals	$	—	$	629,567	$	—	$	629,567
Inventories in transit via truck and rail		—		53,216		—		53,216
Derivative contracts		—		47,372		—		47,372
Liabilities carried at fair value (in thousands):
Inventories due under exchange agreements		—		31,280		—		31,280
Derivative contracts		—		30,066		—		30,066
Variation margin payables		—		35,528		—		35,528

	December 31, 2012

	Level 1		Level 2		Level 3		Total
Assets carried at fair value (in thousands):
Inventories in pipelines and terminals	$	—	$	660,044	$	—	$	660,044
Inventories in transit via truck and rail		—		59,703		—		59,703
Derivative contracts		—		13,390		—		13,390
Liabilities carried at fair value (in thousands):
Inventories due under exchange agreements		—		35,343		—		35,343
Derivative contracts		—		11,947		—		11,947
Variation margin payables		—		30,633		—		30,633

The Company also has financial instruments that are not accounted for at fair value, which generally accepted accounting principles require we disclose the fair value. The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that constitute financial instruments and were not accounted for at fair value as of December 31, 2013 and 2012. We believe the carrying amounts of these financial instruments reasonably approximate their fair values due

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(9) FAIR VALUE MEASUREMENTS (Continued)

to their short-term nature, and in the case of our bank debt due to the borrowings bearing interest at current market interest rates.

	December 31, 2013

	Level 1		Level 2		Level 3		Total
Assets for which the carrying value approximates fair value (in thousands):
Cash and cash equivalents	$	74,762	$	—	$	—	$	74,762
Rack sales accounts receivable, net		—		243,520		—		243,520
Pipeline sales accounts receivable		—		684,881		—		684,881
Other pipeline accrued receivables		—		6,123		—		6,123
Other current assets—restricted cash		1,000		—		—		1,000
Liabilities for which the carrying value approximates fair value (in thousands)
Accounts payable		—		64,351		—		64,351
Product purchases accounts payable		—		785,112		—		785,112
Excise taxes payable		—		39,648		—		39,648
Other pipeline accrued payables		—		20,589		—		20,589
Bank debt		—		212,000		—		212,000

	December 31, 2012

	Level 1		Level 2		Level 3		Total
Assets for which the carrying value approximates fair value (in thousands):
Cash and cash equivalents	$	15,156	$	—	$	—	$	15,156
Rack sales accounts receivable, net		—		307,757		—		307,757
Pipeline sales accounts receivable		—		520,944		—		520,944
Other pipeline accrued receivables		—		2,808		—		2,808
Other current assets—restricted cash		1,120		—		—		1,120
Liabilities for which the carrying value approximates fair value (in thousands)
Accounts payable		—		100,651		—		100,651
Product purchases accounts payable		—		705,863		—		705,863
Excise taxes payable		—		55,139		—		55,139
Other pipeline accrued payables		—		18,953		—		18,953
Bank debt		—		184,000		—		184,000

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(10) COMMITMENTS AND CONTINGENCIES

At December 31, 2013, future minimum lease payments under our non-cancelable operating leases are as follows (in thousands):

Years ending December 31:	Office space		Rail cars		Property and equipment		Total

2014	$	2,049	$	1,960	$	3,753	$	7,762
2015		2,104		408		3,920		6,432
2016		2,159		238		3,997		6,394
2017		2,150		—		2,989		5,139
2018		1,412		—		588		2,000
Thereafter		1,192		—		3,891		5,083


	$	11,066	$	2,606	$	19,138	$	32,810

Rental expense under operating leases is as follows (in thousands):

	Years ended December 31,

	2013		2012
Office space	$	1,772	$	1,870
Rail cars		6,887		2,288
Property and equipment		3,573		1,471


	$	12,232	$	5,629

(11) SUBSEQUENT EVENTS

We have evaluated subsequent events through November 5, 2014, which is the date the financial statements were available to be issued, except for Note 12, as to which we have evaluated subsequent events through December 24, 2014.

On July 1, 2014, Morgan Stanley consummated the sale of its indirect 100% ownership interest in TransMontaigne Inc. to NGL. TransMontaigne Inc. is the indirect parent and sole member of TransMontaigne GP L.L.C., which is the sole general partner of TLP, a publically traded master limited partnership. The sale also included Morgan Stanley's limited partnership interests in TLP, the assignment from an affiliate of Morgan Stanley to NGL of certain terminaling services agreements with TLP, and the transfer of certain inventory owned by Morgan Stanley.

In connection with the July 1, 2014 sale to NGL, and immediately prior thereto, the TransMontaigne credit facility was terminated.

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Regulation S-X, certain historical financial data of the Company is shown below, with the operations of TLP shown separately from the other assets and operations of the Company. Under TLP's credit agreement, TLP may make distributions of cash to the extent of its "available cash" as defined in TLP's partnership agreement. There are no significant restrictions upon the ability of the parent or any of the guarantor subsidiaries to obtain funds from their other respective subsidiaries by dividend or loan. NGL is the parent entity of the guarantors of NGL's notes, and NGL is not part of these combined financial statements; as a result, no parent entity activity is shown in the condensed consolidating tables below.

Combining balance sheet at December 31, 2013

	December 31, 2013

	Guarantor Entities		Non-Guarantor Entities		Combining Adjustments			Combined
	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	71,499	$	3,263	$	—		$	74,762
Rack sales accounts receivable, net		238,924		6,612		(2,016	)		243,520
Pipeline sales accounts receivable		684,881		—		—			684,881
Inventories in pipelines and terminals		629,567		—		—			629,567
Inventories in transit via truck and rail		53,216		—		—			53,216
Derivative contracts		47,372		—		—			47,372
Other pipeline accrued receivables		6,123		—		—			6,123
Intercompany receivables		—		2,072		(2,072	)		—
Other		24,596		3,478		(10,526	)		17,548


		1,756,178		15,425		(14,614	)		1,756,989
Property, plant and equipment, net		38,450		407,045		—			445,495
Investment in non-guarantor entities		49,049		—		(49,049	)		—
Investment in unconsolidated affiliates		—		211,605		—			211,605
Other assets		6,146		14,357		(2,146	)		18,357


	$	1,849,823	$	648,432	$	(65,809	)	$	2,432,446




LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	58,634	$	5,717	$	—		$	64,351
Product purchases accounts payable		785,112		—		—			785,112
Excise taxes payable		39,648		—		—			39,648
Inventories due under exchange agreements		31,280		—		—			31,280
Derivative contracts		30,066		—		—			30,066
Accrued environmental obligations		4,303		—		—			4,303
Variation margin payables		35,528		—		—			35,528
Other pipeline accrued payables		20,589		—		—			20,589
Intercompany payables		2,072		—		(2,072	)		—
Other accrued liabilities		21,543		16,189		(14,469	)		23,263


		1,028,775		21,906		(16,541	)		1,034,140
Bank debt		—		212,000		—			212,000
Other		3,522		6,059		(219	)		9,362


Total liabilities		1,032,297		239,965		(16,760	)		1,255,502


Equity:
Equity attributable to noncontrolling interests		—		359,418		—			359,418
Equity attributable to parent		817,526		49,049		(49,049	)		817,526


		817,526		408,467		(49,049	)		1,176,944


	$	1,849,823	$	648,432	$	(65,809	)	$	2,432,446

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Combining balance sheet at December 31, 2012

	Guarantor Entities		Non-Guarantor Entities		Combining Adjustments			Combined

	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	8,411	$	6,745	$	—		$	15,156
Rack sales accounts receivable, net		302,535		5,222		—			307,757
Pipeline sales accounts receivable		520,944		—		—			520,944
Inventories in pipelines and terminals		660,044		—		—			660,044
Inventories in transit via truck and rail		59,703		—		—			59,703
Derivative contracts		13,390		—		—			13,390
Other pipeline accrued receivables		2,808		—		—			2,808
Intercompany receivables		—		2,848		(2,848	)		—
Other		17,860		4,579		(7,372	)		15,067


		1,585,695		19,394		(10,220	)		1,594,869
Property, plant and equipment, net		39,486		427,701		—			467,187
Investment in non-guarantor entities		49,532		—		(49,532	)		—
Investment in unconsolidated affiliates		—		105,164		—			105,164
Other assets		5,575		17,542		(3,648	)		19,469


	$	1,680,288	$	569,801	$	(63,400	)	$	2,186,689




LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	89,841	$	10,810	$	—		$	100,651
Product purchases accounts payable		705,863		—		—			705,863
Excise taxes payable		55,139		—		—			55,139
Inventories due under exchange agreements		35,343		—		—			35,343
Derivative contracts		11,947		—		—			11,947
Accrued environmental obligations		6,215		—		—			6,215
Variation margin payables		30,633		—		—			30,633
Other pipeline accrued payables		18,953		—		—			18,953
Intercompany payables		2,848		—		(2,848	)		—
Other accrued liabilities		23,349		15,606		(11,020	)		27,935


		980,131		26,416		(13,868	)		992,679
Bank debt		—		184,000		—			184,000
Other		1,247		10,648		—			11,895


Total liabilities		981,378		221,064		(13,868	)		1,188,574


Equity:
Equity attributable to noncontrolling interests		—		299,205		—			299,205
Equity attributable to parent		698,910		49,532		(49,532	)		698,910	��


		698,910		348,737		(49,532	)		998,115


	$	1,680,288	$	569,801	$	(63,400	)	$	2,186,689

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Combining statements of operations and comprehensive income for the year ended December 31, 2013

	Guarantor Entities			Non-Guarantor Entities			Combining Adjustments			Combined

	(in thousands)
Marketing and distribution:
Revenues	$	8,579,362		$	—		$	—		$	8,579,362
Cost of product sold and other direct costs and expenses		(8,526,753	)		—			63,033			(8,463,720	)


Net operating margins, exclusive of depreciation and amortization shown separately below		52,609			—			63,033			115,642


Terminals and pipelines:
Revenues		2,067			158,886			(101,109	)		59,844
Direct costs and expenses		1,900			(69,390	)		38,076			(29,414	)


Net operating margins, exclusive of depreciation and amortization shown separately below		3,967			89,496			(63,033	)		30,430


Total net operating margins		56,576			89,496			—			146,072


Costs and expenses:
Selling, general, and administrative		(45,132	)		(19,887	)		—			(65,019	)
Depreciation and amortization		(4,693	)		(29,568	)		—			(34,261	)
Loss on disposition of assets, net		(728	)		(1,294	)		—			(2,022	)
Loss from unconsolidated affiliates		—			(321	)		—			(321	)


Total costs and expenses		(50,553	)		(51,070	)		—			(101,623	)


Operating income		6,023			38,426			—			44,449


Other income (expenses):
Equity in earnings of non-guarantor entities		11,136			—			(11,136	)		—
Interest expense		(2,287	)		(3,687	)		—			(5,974	)
Foreign currency transaction loss		—			(13	)		—			(13	)


Total other income (expenses)		8,849			(3,700	)		(11,136	)		(5,987	)


Earnings before income taxes		14,872			34,726			(11,136	)		38,462
Income tax expense		(242	)		—			—			(242	)


Net income		14,630			34,726			(11,136	)		38,220
Noncontrolling interests share in earnings of TransMontaigne Partners		—			(23,590	)		—			(23,590	)


Net income attributable to parent		14,630			11,136			(11,136	)		14,630
Other comprehensive income—foreign currency translation adjustments attributable to noncontrolling interests		—			56			—			56
Other comprehensive income—foreign currency translation adjustments attributable to parent		—			27			—			27


Comprehensive income	$	14,630		$	11,219		$	(11,136	)	$	14,713

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Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Combining statements of operations and comprehensive income (loss) for the year ended December 31, 2012

	Year Ended December 31, 2012

	Guarantor Entities			Non-Guarantor Entities			Combining Adjustments			Combined
	(in thousands)
Marketing and distribution:
Revenues	$	10,877,459		$	—		$	—		$	10,877,459
Cost of product sold and other direct costs and expenses		(11,047,081	)		—			63,733			(10,983,348	)


Net operating margin loss, exclusive of depreciation and amortization shown separately below		(169,622	)		—			63,733			(105,889	)


Terminals and pipelines:
Revenues		3,521			156,239			(107,045	)		52,715
Direct costs and expenses		1,418			(65,964	)		43,312			(21,234	)


Net operating margins, exclusive of depreciation and amortization shown separately below		4,939			90,275			(63,733	)		31,481


Total net operating margins (loss)		(164,683	)		90,275			—			(74,408	)


Costs and expenses:
Selling, general, and administrative		(47,541	)		(20,430	)		—			(67,971	)
Depreciation and amortization		(4,007	)		(28,260	)		—			(32,267	)
Gain on disposition of assets, net		856			—			—			856
Earnings from unconsolidated affiliates		—			558			—			558


Total costs and expenses		(50,692	)		(48,132	)		—			(98,824	)


Operating income (loss)		(215,375	)		42,143			—			(173,232	)


Other income (expenses):
Equity in earnings of non-guarantor entities		11,486			—			(11,486	)		—
Interest expense		(2,927	)		(3,622	)		—			(6,549	)
Foreign currency transaction gain		—			51			—			51


Total other income (expenses)		8,559			(3,571	)		(11,486	)		(6,498	)


Earnings (loss) before income taxes		(206,816	)		38,572			(11,486	)		(179,730	)
Income tax expense		(188	)		—			—			(188	)


Net income (loss)		(207,004	)		38,572			(11,486	)		(179,918	)
Noncontrolling interests share in earnings of TransMontaigne Partners		—			(27,086	)		—			(27,086	)


Net income (loss) attributable to parent		(207,004	)		11,486			(11,486	)		(207,004	)
Other comprehensive income—foreign currency translation adjustments attributable to noncontrolling interests		—			128			—			128
Other comprehensive income—foreign currency translation adjustments attributable to parent		—			63			—			63


Comprehensive income (loss)	$	(207,004	)	$	11,677		$	(11,486	)	$	(206,813	)

F-421

Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statements of cash flows for the year ended December 31, 2013

	Guarantor Entities			Non-Guarantor Entities			Combined

	(in thousands)
Net cash provided by (used in) operating activities	$	(49,183	)	$	64,235		$	15,052
Cash flows from investing activities:
Investments in unconsolidated affiliates		—			(108,229	)		(108,229	)
Capital expenditures		(3,567	)		(13,838	)		(17,405	)
Proceeds from sale of assets		185			2,109			2,294


Net cash used in investing activities		(3,382	)		(119,958	)		(123,340	)


Cash flows from financing activities:
Proceeds from issuance of TransMontaigne Partners' common units		—			68,774			68,774
Borrowings of bank debt		—			168,500			168,500
Repayments of bank debt		—			(140,500	)		(140,500	)
Net capital contributed by (distributed to) affiliated entities		115,403			(11,578	)		103,825
Distributions paid to noncontrolling TransMontaigne Partners' common units		—			(32,419	)		(32,419	)
Purchase of common units by TransMontaigne Partners' long-term incentive plan		250			(585	)		(335	)


Net cash provided by financing activities		115,653			52,192			167,845


Increase (decrease) in cash and cash equivalents		63,088			(3,531	)		59,557
Foreign currency translation effect on cash		—			49			49


Cash and cash equivalents at beginning of period		8,411			6,745			15,156


Cash and cash equivalents at end of period	$	71,499		$	3,263		$	74,762

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Table of Contents

Notes to Combined Financial Statements (Continued)

Years ended December 31, 2013 and 2012

(12) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statements of cash flows for the year ended December 31, 2012

	Guarantor Entities			Non-Guarantor Entities			Combined

	(in thousands)
Net cash provided by operating activities	$	301,677		$	64,311		$	365,988
Cash flows from investing activities:
Investments in unconsolidated affiliates		—			(80,166	)		(80,166	)
Capital expenditures		(7,613	)		(23,565	)		(31,178	)
Proceeds from sale of assets		1,086			18,000			19,086


Net cash used in investing activities		(6,527	)		(85,731	)		(92,258	)


Cash flows from financing activities:
Borrowings of bank debt		—			147,000			147,000
Repayments of bank debt		—			(83,000	)		(83,000	)
Deferred debt issuance costs		—			(736	)		(736	)
Net capital distributed to affiliated entities		(363,032	)		(12,045	)		(375,077	)
Distributions paid to noncontrolling TransMontaigne Partners' common units		—			(29,801	)		(29,801	)
Purchase of common units by TransMontaigne Partners' long-term incentive plan		215			(454	)		(239	)


Net cash provided by (used in) financing activities		(362,817	)		20,964			(341,853	)


Decrease in cash and cash equivalents		(67,667	)		(456	)		(68,123	)
Foreign currency translation effect on cash		—			63			63


Cash and cash equivalents at beginning of period		76,078			7,138			83,216


Cash and cash equivalents at end of period	$	8,411		$	6,745		$	15,156


						��

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Table of Contents

Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners

Condensed Combined Balance Sheets

(Unaudited and in thousands)

	June 30, 2014		December 31, 2013

ASSETS
Current assets:
Cash and cash equivalents	$	71,549	$	74,762
Rack sales accounts receivable, net		198,702		243,520
Pipeline sales accounts receivable		202,795		684,881
Inventories in pipelines and terminals		542,187		629,567
Inventories in transit via truck and rail		44,844		53,216
Derivative contracts		6,375		47,372
Other pipeline accrued receivables		3,803		6,123
Other		38,551		17,548


		1,108,806		1,756,989
Property, plant and equipment, net		431,486		445,495
Investment in unconsolidated affiliates		234,002		211,605
Other assets		16,676		18,357


	$	1,790,970	$	2,432,446




LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	120,656	$	64,351
Product purchases accounts payable		229,363		785,112
Excise taxes payable		28,324		39,648
Inventories due under exchange agreements		5,788		31,280
Derivative contracts		7,765		30,066
Accrued environmental obligations		4,208		4,303
Variation margin payables		16,888		35,528
Other pipeline accrued payables		12,813		20,589
Other accrued liabilities		35,320		23,263


		461,125		1,034,140
Bank debt		234,000		212,000
Other		4,491		9,362


Total liabilities		699,616		1,255,502


Equity:
Equity attributable to noncontrolling interests		355,624		359,418
Equity attributable to parent		735,730		817,526


		1,091,354		1,176,944


	$	1,790,970	$	2,432,446

See accompanying notes to condensed combined financial statements.

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Table of Contents

Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Condensed Combined Statements of Comprehensive Loss

(Unaudited and in thousands)

	Six months ended June 30, 2014			Six months ended June 30, 2013

Marketing and distribution:
Revenues	$	4,000,573		$	4,678,070
Cost of product sold and other direct costs and expenses		(3,948,828	)		(4,648,787	)


Net operating margins, exclusive of depreciation and amortization shown separately below		51,745			29,283


Terminals and pipelines:
Revenues		33,650			31,537
Direct costs and expenses		(16,833	)		(15,075	)


Net operating margins, exclusive of depreciation and amortization shown separately below		16,817			16,462


Total net operating margins		68,562			45,745


Costs and expenses:
Selling, general and administrative		(41,166	)		(32,060	)
Depreciation and amortization		(17,346	)		(17,018	)
Gain (loss) on disposition of assets, net		98			(845	)
Earnings from unconsolidated affiliates		1,438			36


Total costs and expenses		(56,976	)		(49,887	)


Operating income (loss)		11,586			(4,142	)


Other income (expenses):
Interest expense		(3,065	)		(2,625	)
Amortization of deferred financing costs		(687	)		(687	)
Foreign currency transaction loss		—			(8	)


Total other expenses		(3,752	)		(3,320	)


Earnings (loss) before income taxes		7,834			(7,462	)
Income tax expense		(302	)		(102	)


Net income		7,532			(7,564	)
Noncontrolling interests share in earnings of TransMontaigne Partners		(13,677	)		(13,759	)


Net loss attributable to parent		(6,145	)		(21,323	)
Other comprehensive income—foreign currency translation adjustments attributable to noncontrolling interests		—			2


Comprehensive loss	$	(6,145	)	$	(21,321	)

See accompanying notes to condensed combined financial statements.

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Table of Contents

Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Condensed Combined Statement of Equity

Six months ended June 30, 2014

(Unaudited and in thousands)

	Equity attributable to noncontrolling interests			Equity attributable to Parent, Net			Total equity

Balance at December 31, 2013	$	359,418		$	817,526		$	1,176,944
Distributions paid to non-controlling TransMontaigne Partners' common units		(17,408	)		—			(17,408	)
Purchase of common units by TransMontaigne Partners' long-term incentive plan		(177	)		—			(177	)
Deferred equity-based compensation related to restricted phantom units and other		114			—			114
Net income (loss)		13,677			(6,145	)		7,532
Net capital distributed to parent company		—			(75,651	)		(75,651	)


Balance at June 30, 2014	$	355,624		$	735,730		$	1,091,354

See accompanying notes to condensed combined financial statements.

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Table of Contents

Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP

Condensed Combined Statements of Cash Flows

(Unaudited and in thousands)

	Six months ended June 30, 2014			Six months ended June 30, 2013

Net cash provided by (used in) operating activities	$	94,190		$	(98,771	)


Cash flows from investing activities:
Investments in unconsolidated affiliates		(23,397	)		(70,956	)
Capital expenditures		(3,755	)		(12,912	)
Proceeds from sale of assets		1			89


Net cash used in investing activities		(27,151	)		(83,779	)


Cash flows from financing activities:
Borrowings of bank debt		56,000			119,500
Repayments of bank debt		(34,000	)		(49,500	)
Net capital contributed by (distributed to) parent company		(74,667	)		185,059
Distributions paid to non-controlling TransMontaigne Partners' common units		(17,408	)		(15,016	)
Purchase of common units by TransMontaigne Partners' long-term incentive plan		(177	)		(166	)
Other		—			(398	)


Net cash provided by (used in) financing activities		(70,252	)		239,479


Increase (decrease) in cash and cash equivalents		(3,213	)		56,929
Foreign currency translation effect on cash		—			46


Cash and cash equivalents at beginning of period		74,762			15,156


Cash and cash equivalents at end of period	$	71,549		$	72,131
Supplemental disclosures of cash flow information:
Cash paid for interest	$	3,140		$	2,426




Property, plant and equipment acquired with accounts payable	$	75		$	246

See accompanying notes to condensed combined financial statements.

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Table of Contents

Notes to Condensed Combined Financial Statements

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) Nature of business

The accompanying combined interim financial statements include the accounts of all operations of the Businesses Associated with TransMontaigne Inc. Acquired by NGL Energy Partners LP (collectively, the "Company", "we", "us" or "our"). On July 1, 2014, Morgan Stanley consummated the sale of its indirect 100% ownership interest in the Business to NGL Energy Partners LP ("NGL"). TransMontaigne Inc. is the indirect parent and sole member of TransMontaigne GP L.L.C., which is the sole general partner ("General Partner") of TransMontaigne Partners L.P. ("TLP" or the "Partnership"), a publicly traded master limited partnership. The sale also included Morgan Stanley's limited partnership interests in TLP, the assignment from an affiliate of Morgan Stanley to NGL of certain terminaling services agreements with TLP, and the transfer of certain inventory owned by Morgan Stanley (collectively, the "Transaction"). The Transaction does not involve the sale or purchase of any of the limited partnership units in TLP held by the public and the TLP limited partnership units continue to trade on the New York Stock Exchange.

TransMontaigne's less than wholly-owned subsidiary includes the publicly traded master limited partnership of TLP. TLP was formed in February 2005 as a Delaware limited partnership to own and operate refined petroleum products terminaling and transportation facilities. TLP conducts its operations in the United States along the Gulf Coast, in the Midwest, in Houston and Brownsville, Texas, along the Mississippi and Ohio rivers and in the Southeast. TLP provides integrated terminaling, storage, transportation and related services for companies engaged in the trading, distribution and marketing of light refined petroleum products, heavy refined petroleum products, crude oil, chemicals, fertilizers and other liquid products. TransMontaigne and NGL, subsequent to the Transaction, have an interest in TLP through the ownership of approximately 20% of the limited partner interests, a 2% general partner interest and the incentive distribution rights.

(b) Basis of presentation and use of estimates

In preparing the accompanying unaudited condensed combined financial statements, we have followed the accounting policies of Morgan Stanley, a broker-dealer, and TransMontaigne Inc., which are in accordance with United States generally accepted accounting principles or "GAAP" for interim financial information. Accordingly, the unaudited condensed combined financial statements do not include all the information and notes required by GAAP for complete annual financial statements. However, we believe that the disclosures made are adequate to make the information not misleading. The combined financial statements of the Company have been prepared from the separate records maintained by Morgan Stanley and TransMontaigne Inc. and may not necessarily be indicative of the conditions that would have existed, or the results of operations, if the Company had been operated as an unaffiliated entity. Because a direct ownership relationship did not exist among all the various assets

F-428

Table of Contents

Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(1) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Continued)

comprising the Company, Morgan Stanley's net investment in the Company is shown as net parent equity, in lieu of owner's equity, in the combined financial statements. All intercompany balances have been eliminated. Transactions between us and Morgan Stanley operations have been identified in the combined financial statements as transactions between affiliates. In the opinion of management, all adjustments have been reflected that are necessary for a fair presentation of the combined financial statements.

(c) Significant accounting policies

The Company's significant accounting policies are consistent with those disclosed in Note 1 of the Company's audited combined financial statements for the years ended December 31, 2013 and 2012.

(2) INVENTORIES

Our inventories are carried at fair value, and the classes of inventories are as follows (amounts and volume of barrels in thousands):

Inventories in pipelines and terminals:

	June 30, 2014				December 31, 2013

	Amount		Barrels		Amount		Barrels
Gasoline	$	306,119		2,477	$	400,120		3,618
Distillate		218,843		1,758		220,702		1,736
Ethanol		17,196		228		7,946		98
Crude oil		—		—		799		8
Other		29		2		—		—


	$	542,187		4,465	$	629,567		5,460

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Table of Contents

Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(2) INVENTORIES (Continued)

Inventories in transit via truck and rail:

	June 30, 2014				December 31, 2013

	Amount		Barrels		Amount		Barrels
Gasoline	$	—		—	$	16,725		176
Distillate		15,680		127		13,516		111
Ethanol		7,554		87		17,193		218
Crude oil		21,610		208		5,782		59


	$	44,844		422	$	53,216		564

(3) PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment, net is as follows (in thousands):

	June 30, 2014			December 31, 2013

Land	$	57,568		$	57,568
Terminals, pipelines and equipment		603,812			601,921
Furniture, fixtures and equipment		21,366			20,941
Construction in progress		4,487			3,691


		687,233			684,121
Less accumulated depreciation		(255,747	)		(238,626	)


	$	431,486		$	445,495

(4) DERIVATIVE CONTRACTS

The majority of the Company's commodity purchase and sales contracts qualify as over-the-counter derivative instruments and the change in fair value is reported in cost of product sold within the marketing and distribution section of the accompanying combined interim statements of comprehensive income (loss). Changes in the fair value of our derivatives are recognized in earnings. The Company reports the fair value of its over-the-counter derivative assets and liabilities on the combined balance sheets as derivative contract assets and liabilities.

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Table of Contents

Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(4) DERIVATIVE CONTRACTS (Continued)

netting agreements is driven by industry practice, and anticipated volumes and complexity of the business relationship with the counterparty.

The following table provides information about our derivative asset contract positions, net at June 30, 2014 (in thousands):

Derivative type		Gross derivative assets			Counterparty liabilities netted against assets			Fair value of derivative assets, net

Bilateral over-the-counter contracts		$	11,099		$	(4,724	)	$	6,375

The following table provides information about our derivative asset contract positions, net at December 31, 2013 (in thousands):

Derivative type		Gross derivative assets			Counterparty liabilities netted against assets			Fair value of derivative assets, net

Bilateral over-the-counter contracts		$	54,119		$	(6,747	)	$	47,372

The following table provides information about our derivative liability contract positions, net at June 30, 2014 (in thousands):

Derivative type		Gross derivative liabilities			Counterparty assets netted against liabilities			Fair value of derivative liabilities, net

Bilateral over-the-counter contracts		$	12,460		$	(4,695	)	$	7,765

The following table provides information about our derivative liability contract positions, net at December 31, 2013 (in thousands):

Derivative type		Gross derivative liabilities			Counterparty assets netted against liabilities			Fair value of derivative liabilities, net

Bilateral over-the-counter contracts		$	36,870		$	(6,804	)	$	30,066

(5) BANK DEBT

TLP Credit Facility

On March 9, 2011, TLP entered into an amended and restated senior secured credit facility, or the "TLP credit facility", which has been subsequently amended from time to time. The TLP credit facility provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined $345.7 million at June 30, 2014). TLP may elect to have loans under the TLP credit facility that bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.5% per annum, depending on the total leverage ratio then in effect. TLP's obligations under the TLP credit facility are secured by a first priority security interest in favor of the lenders in the majority of the TLP assets.

F-431

Table of Contents

Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(5) BANK DEBT (Continued)

The terms of the TLP credit facility include covenants that restrict TLP's ability to make cash distributions, acquisitions and investments, including investments in joint ventures. TLP may make distributions of cash to the extent of its "available cash" as defined in the TLP partnership agreement. TLP may make acquisitions and investments that meet the definition of "permitted acquisitions"; "other investments" which may not exceed 5% of "consolidated net tangible assets"; and "permitted JV investments". Permitted JV investments include up to $225 million of investments in Battleground Oil Specialty Terminal Company LLC ("BOSTCO"), the "Specified BOSTCO Investment". In addition to the Specified BOSTCO Investment, under the terms of the TLP credit facility, TLP may make an additional $75 million of other permitted JV investments (including additional investments in BOSTCO). The principal balance of loans and any accrued and unpaid interest are due and payable in full on the maturity date, March 9, 2016.

The TLP credit facility also contains customary representations and warranties (including those relating to organization and authorization, compliance with laws, absence of defaults, material agreements and litigation) and customary events of default (including those relating to monetary defaults, covenant defaults, cross defaults and bankruptcy events). The primary financial covenants contained in the credit facility are (i) a total leverage ratio test (not to exceed 4.75 times), (ii) a senior secured leverage ratio test (not to exceed 3.75 times) in the event TLP issues senior unsecured notes, and (iii) a minimum interest coverage ratio test (not less than 3.0 times). If TLP were to fail any financial performance covenant, or any other covenant contained in the TLP credit facility, TLP would seek a waiver from its lenders under such facility. If TLP were unable to obtain a waiver from its lenders and the default remained uncured after any applicable grace period, TLP would be in breach of the TLP credit facility, and the lenders would be entitled to declare all outstanding borrowings immediately due and payable. TLP was in compliance with all of the financial covenants under the credit facility as of June 30, 2014.

At June 30, 2014 and December 31, 2013, TLP's outstanding borrowings under the TLP credit facility were $234 million and $212 million, respectively. At June 30, 2014 and December 31, 2013, TLP had no outstanding letters of credit.

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Table of Contents

Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(5) BANK DEBT (Continued)

The following table summarizes the assets and liabilities of TLP at June 30, 2014 (in thousands):


Cash and cash equivalents	$	1,469
Trade accounts receivable, net		8,638
Receivables from affiliates		3,449
Other current assets		3,249
Property, plant and equipment, net		394,319
Investments in unconsolidated affiliates		234,002
Other assets, net		13,167


Total assets	$	658,293




Trade accounts payable	$	4,868
Accrued liabilities		10,788
Long-term debt		234,000
Other noncurrent liabilities		4,753
Equity attributable to noncontrolling interests		355,624
Equity attributable to parent		48,260


Total liabilities and equity	$	658,293

TransMontaigne Credit Facility

TransMontaigne has a senior secured working capital credit facility, or the "TransMontaigne credit facility" that provides for a maximum borrowing line of credit equal to the lesser of (i) $150 million or (ii) the borrowing base, which is a function of, among other things, restricted cash maintained in a specified account, accounts receivable, inventory and certain reserve adjustments as defined in the facility (as defined: $103.2 million at June 30, 2014). In addition, outstanding letters of credit are counted against the maximum borrowing capacity available at any time. Borrowings under the TransMontaigne credit facility bear interest (at TransMontaigne's option) based on a base rate plus an applicable margin, or LIBOR plus an applicable margin; the applicable margins range from 2% to 3% and are a function of the average excess borrowing base availability. In addition, TransMontaigne pays a commitment fee ranging from 0.50% to 0.625% per annum on the total amount of the unused commitments. Borrowings under the TransMontaigne credit facility are secured by the majority of the TransMontaigne's and its wholly-owned subsidiaries' assets, which excludes all TLP assets. The principal balance of loans and any accrued and unpaid interest is scheduled to be due and payable in full on the maturity date August 15, 2015. TransMontaigne primarily utilizes the facility to finance its crude oil marketing operations through the issuance of letters of credit to crude oil producers.

At June 30, 2014 and December 31, 2013, TransMontaigne had no outstanding borrowings under the TransMontaigne credit facility. At June 30, 2014 and December 31, 2013, TransMontaigne's outstanding letters of credit were approximately $67.1 million and $51.0 million, respectively.

In connection with the July 1, 2014 sale to NGL, and immediately prior thereto, the TransMontaigne credit facility was terminated.

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Table of Contents

Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(6) INCOME TAXES

The difference between the income tax benefit reported in the accompanying combined statements of operations and the federal statutory tax rate of 35% relates primarily to the impact of state income taxes, valuation allowance against deferred tax assets, and to the fact that TLP is treated as a partnership for U.S. federal income tax purposes. Because of this, no provision for U.S. federal income taxes has been reflected in the accompanying combined financial statements related to TLP. As a partnership, all income, gains, losses, expenses, deductions and tax credits generated by TLP flow through to the unitholders of the partnership. Income tax expense recorded relates to current state taxes due from tax returns filed on a legal entity basis.

(7) FAIR VALUE MEASUREMENTS

F-434

Table of Contents

Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(7) FAIR VALUE MEASUREMENTS (Continued)

The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2014 and December 31, 2013.

	June 30, 2014

	Level 1		Level 2		Level 3		Total
Assets carried at fair value (in thousands):
Inventories in pipelines and terminals	$	—	$	542,187	$	—	$	542,187
Inventories in transit via truck and rail		—		44,844		—		44,844
Derivative contracts		—		6,375		—		6,375
Liabilities carried at fair value (in thousands):
Inventories due under exchange agreements		—		5,788		—		5,788
Derivative contracts		—		7,765		—		7,765
Variation margin payables		—		16,888		—		16,888

	December 31, 2013

	Level 1		Level 2		Level 3		Total
Assets carried at fair value (in thousands):
Inventories in pipelines and terminals	$	—	$	629,567	$	—	$	629,567
Inventories in transit via truck and rail		—		53,216		—		53,216
Derivative contracts		—		47,372		—		47,372
Liabilities carried at fair value (in thousands):
Inventories due under exchange agreements		—		31,280		—		31,280
Derivative contracts		—		30,066		—		30,066
Variation margin payables		—		35,528		—		35,528

The Company also has financial instruments that are not accounted for at fair value, which generally accepted accounting principles require we disclose the fair value. The following tables set forth by level within the fair value hierarchy the Company's assets and liabilities that constitute financial instruments and were not accounted for at fair value as of June 30, 2014 and December 31, 2013. We believe the carrying amounts of these financial instruments reasonably approximate their fair

F-435

Table of Contents

Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(7) FAIR VALUE MEASUREMENTS (Continued)

values due to their short-term nature, and in the case of our bank debt due to the borrowings bearing interest at current market interest rates.

	June 30, 2014

	Level 1		Level 2		Level 3		Total
Assets for which the carrying value approximates fair value (in thousands):
Cash and cash equivalents	$	71,549	$	—	$	—	$	71,549
Rack sales accounts receivable, net		—		198,702		—		198,702
Pipeline sales accounts receivable		—		202,795		—		202,795
Other pipeline accrued receivables		—		3,803		—		3,803
Other current assets-restricted cash		28,526		—		—		28,526
Liabilities for which the carrying value approximates fair value (in thousands):
Accounts payable		—		120,656		—		120,656
Product purchases accounts payable		—		229,363		—		229,363
Excise taxes payable		—		28,324		—		28,324
Other pipeline accrued payables		—		12,813		—		12,813
Bank debt		—		234,000		—		234,000

	December 31, 2013

	Level 1		Level 2		Level 3		Total
Assets for which the carrying value approximates fair value (in thousands):
Cash and cash equivalents	$	74,762	$	—	$	—	$	74,762
Rack sales accounts receivable, net		—		243,520		—		243,520
Pipeline sales accounts receivable		—		684,881		—		684,881
Other pipeline accrued receivables		—		6,123		—		6,123
Other current assets-restricted cash		1,000		—		—		1,000
Liabilities for which the carrying value approximates fair value (in thousands):
Accounts payable		—		64,351		—		64,351
Product purchases accounts payable		—		785,112		—		785,112
Excise taxes payable		—		39,648		—		39,648
Other pipeline accrued payables		—		20,589		—		20,589
Bank debt		—		212,000		—		212,000

Accounts receivable are reported net of an allowance for doubtful accounts. As of June 30, 2014 and December 31, 2013, the allowances for doubtful accounts were $3.4 million and $3.8 million, respectively.

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(8) SUBSEQUENT EVENTS

We have evaluated subsequent events through November 5, 2014, which is the date the financial statements were available to be issued, except for Note 9, as to which we have evaluated subsequent events through December 24, 2014.

On July 1, 2014, Morgan Stanley consummated the sale of its indirect 100% ownership interest in TransMontaigne Inc. to NGL. TransMontaigne Inc. is the indirect parent and sole member of TransMontaigne GP L.L.C., which is the sole general partner of TLP, a publicly traded master limited partnership. The sale also included Morgan Stanley's limited partnership interests in TLP, the assignment from an affiliate of Morgan Stanley to NGL of certain terminaling services agreements with TLP, and the transfer of certain inventory owned by Morgan Stanley.

In connection with the July 1, 2014 sale to NGL, and immediately prior thereto, the TransMontaigne credit facility was terminated.

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information

Subsequent to the July 2014 acquisition of the Company by NGL, TransMontaigne Inc. and certain of its subsidiaries became guarantors of certain of NGL's notes, and the other assets and operations acquired from Morgan Stanley were placed into a subsidiary of NGL that also guarantee these notes. As a result, this activity is presented in the guarantor column in the condensed consolidating tables below. TLP and its subsidiaries are not guarantors of these notes. Pursuant to Rule 3-10 of Regulation S-X, certain historical financial data of the Company is shown below, with the operations of TLP shown separately from the other assets and operations of the Company. Under TLP's credit agreement, TLP may make distributions of cash to the extent of its "available cash" as defined in TLP's partnership agreement. There are no significant restrictions upon the ability of the parent or any of the guarantor subsidiaries to obtain funds from their other respective subsidiaries by dividend or loan. NGL is the parent entity of the guarantors of NGL's notes, and NGL is not part of these combined financial statements; as a result, no parent entity activity is shown in the condensed consolidating tables below.

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining balance sheet at June 30, 2014

	Guarantor Entities		Non-Guarantor Entities		Combining Adjustments			Combined

	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	70,080	$	1,469	$	—		$	71,549
Rack sales accounts receivable, net		189,673		9,029		—			198,702
Pipeline sales accounts receivable		202,795		—		—			202,795
Inventories in pipelines and terminals		542,187		—		—			542,187
Inventories in transit via truck and rail		44,844		—		—			44,844
Derivative contracts		6,375		—		—			6,375
Other pipeline accrued receivables		3,803		—		—			3,803
Intercompany receivables		—		3,058		(3,058	)		—
Other		37,769		3,249		(2,467	)		38,551


		1,097,526		16,805		(5,525	)		1,108,806
Property, plant and equipment, net		37,167		394,319		—			431,486
Investment in non-guarantor entities		48,260		—		(48,260	)		—
Investment in unconsolidated affiliates		—		234,002		—			234,002
Other assets		5,157		13,167		(1,648	)		16,676


	$	1,188,110	$	658,293	$	(55,433	)	$	1,790,970




LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	115,788	$	4,868	$	—		$	120,656
Product purchases accounts payable		229,363		—		—			229,363
Excise taxes payable		28,324		—		—			28,324
Inventories due under exchange agreements		5,788		—		—			5,788
Derivative contracts		7,765		—		—			7,765
Accrued environmental obligations		4,208		—		—			4,208
Variation margin payables		16,888		—		—			16,888
Other pipeline accrued payables		12,813		—		—			12,813
Intercompany payables		3,058		—		(3,058	)		—
Other accrued liabilities		28,385		10,788		(3,853	)		35,320


		452,380		15,656		(6,911	)		461,125
Bank debt		—		234,000		—			234,000
Other		—		4,753		(262	)		4,491


Total liabilities		452,380		254,409		(7,173	)		699,616


Equity:
Equity attributable to noncontrolling interests		—		355,624		—			355,624
Equity attributable to parent		735,730		48,260		(48,260	)		735,730


		735,730		403,884		(48,260	)		1,091,354


	$	1,188,110	$	658,293	$	(55,433	)	$	1,790,970

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining balance sheet at December 31, 2013

	Guarantor Entities		Non-Guarantor Entities		Combining Adjustments			Combined

	(in thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	71,499	$	3,263	$	—		$	74,762
Rack sales accounts receivable, net		238,924		6,612		(2,016	)		243,520
Pipeline sales accounts receivable		684,881		—		—			684,881
Inventories in pipelines and terminals		629,567		—		—			629,567
Inventories in transit via truck and rail		53,216		—		—			53,216
Derivative contracts		47,372		—		—			47,372
Other pipeline accrued receivables		6,123		—		—			6,123
Intercompany receivables		—		2,072		(2,072	)		—
Other		24,596		3,478		(10,526	)		17,548


		1,756,178		15,425		(14,614	)		1,756,989
Property, plant and equipment, net		38,450		407,045		—			445,495
Investment in non-guarantor entities		49,049		—		(49,049	)		—
Investment in unconsolidated affiliates		—		211,605		—			211,605
Other assets		6,146		14,357		(2,146	)		18,357


	$	1,849,823	$	648,432	$	(65,809	)	$	2,432,446




LIABILITIES AND EQUITY
Current liabilities:
Accounts payable	$	58,634	$	5,717	$	—		$	64,351
Product purchases accounts payable		785,112		—		—			785,112
Excise taxes payable		39,648		—		—			39,648
Inventories due under exchange agreements		31,280		—		—			31,280
Derivative contracts		30,066		—		—			30,066
Accrued environmental obligations		4,303		—		—			4,303
Variation margin payables		35,528		—		—			35,528
Other pipeline accrued payables		20,589		—		—			20,589
Intercompany payables		2,072		—		(2,072	)		—
Other accrued liabilities		21,543		16,189		(14,469	)		23,263


		1,028,775		21,906		(16,541	)		1,034,140
Bank debt		—		212,000		—			212,000
Other		3,522		6,059		(219	)		9,362


Total liabilities		1,032,297		239,965		(16,760	)		1,255,502


Equity:
Equity attributable to noncontrolling interests		—		359,418		—			359,418
Equity attributable to parent		817,526		49,049		(49,049	)		817,526


		817,526		408,467		(49,049	)		1,176,944


	$	1,849,823	$	648,432	$	(65,809	)	$	2,432,446

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statement of operations for the six months ended June 30, 2014

	Guarantor Entities			Non-Guarantor Entities			Combining Adjustments			Combined

	(in thousands)
Marketing and distribution:
Revenues	$	4,000,573		$	—		$	—		$	4,000,573
Cost of product sold and other direct costs and expenses		(3,979,083	)		—			30,255			(3,948,828	)


Net operating margins, exclusive of depreciation and amortization shown separately below		21,490			—			30,255			51,745


Terminals and pipelines:
Revenues		2,719			77,412			(46,481	)		33,650
Direct costs and expenses		(1,271	)		(31,788	)		16,226			(16,833	)


Net operating margins, exclusive of depreciation and amortization shown separately below		1,448			45,624			(30,255	)		16,817


Total net operating margins		22,938			45,624			—			68,562


Costs and expenses:
Selling, general, and administrative		(31,645	)		(9,521	)		—			(41,166	)
Depreciation and amortization		(2,550	)		(14,796	)		—			(17,346	)
Gain on disposition of assets, net		98			—			—			98
Earnings from unconsolidated affiliates		—			1,438			—			1,438


Total costs and expenses		(34,097	)		(22,879	)		—			(56,976	)


Operating income (loss)		(11,159	)		22,745			—			11,586


Other income (expenses):
Equity in earnings of non-guarantor entities		6,401			—			(6,401	)		—
Interest expense		(1,085	)		(2,667	)		—			(3,752	)


Total other income (expenses)		5,316			(2,667	)		(6,401	)		(3,752	)

					��
Earnings (loss) before income taxes		(5,843	)		20,078			(6,401	)		7,834
Income tax expense		(302	)		—			—			(302	)


Net income (loss)		(6,145	)		20,078			(6,401	)		7,532
Noncontrolling interests share in earnings of TransMontaigne Partners		—			(13,677	)		—			(13,677	)


Net income (loss) atributable to parent	$	(6,145	)	$	6,401		$	(6,401	)	$	(6,145	)

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statements of operations and comprehensive income (loss) for the six months ended June 30, 2013

	Guarantor Entities			Non-Guarantor Entities			Combining Adjustments			Combined

	(in thousands)
Marketing and distribution:
Revenues	$	4,678,070		$	—		$	—		$	4,678,070
Cost of product sold and other direct costs and expenses		(4,681,232	)		—			32,445			(4,648,787	)


Net operating margins (loss), exclusive of depreciation and amortization shown separately below		(3,162	)		—			32,445			29,283


Terminals and pipelines:
Revenues		3,111			80,296			(51,870	)		31,537
Direct costs and expenses		(478	)		(34,022	)		19,425			(15,075	)


Net operating margins, exclusive of depreciation and amortization shown separately below		2,633			46,274			(32,445	)		16,462


Total net operating margins (loss)		(529	)		46,274			—			45,745


Costs and expenses:
Selling, general, and administrative		(22,310	)		(9,750	)		—			(32,060	)
Depreciation and amortization		(2,219	)		(14,799	)		—			(17,018	)
Loss on disposition of assets, net		(845	)		—			—			(845	)
Earnings from unconsolidated affiliates		—			36			—			36


Total costs and expenses		(25,374	)		(24,513	)		—			(49,887	)


Operating income (loss)		(25,903	)		21,761			—			(4,142	)


Other income (expenses):
Equity in earnings of non-guarantor entities		6,007			—			(6,007	)		—
Interest expense		(1,321	)		(1,991	)		—			(3,312	)
Foreign currency transaction loss		—			(8	)		—			(8	)


Total other income (expenses)		4,686			(1,999	)		(6,007	)		(3,320	)


Earnings (loss) before income taxes		(21,217	)		19,762			(6,007	)		(7,462	)
Income tax (expense) benefit		(104	)		2			—			(102	)


Net income (loss)		(21,321	)		19,764			(6,007	)		(7,564	)
Noncontrolling interests share in earnings of TransMontaigne Partners		—			(13,759	)		—			(13,759	)


Net income (loss) attributable to parent		(21,321	)		6,005			(6,007	)		(21,323	)
Other comprehensive income—foreign currency translation adjustments attributable to noncontrolling interests		—			2			—			2


Comprehensive income (loss)	$	(21,321	)	$	6,007		$	(6,007	)	$	(21,321	)

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statements of cash flows for the six months ended June 30, 2014

	Guarantor Entities			Non-Guarantor Entities			Combined

	(in thousands)
Net cash provided by operating activities	$	67,200		$	26,990		$	94,190
Cash flows from investing activities:
Investments in unconsolidated affiliates		—			(23,397	)		(23,397	)
Capital expenditures		(1,143	)		(2,612	)		(3,755	)
Proceeds from sale of assets		1			—			1


Net cash used in investing activities		(1,142	)		(26,009	)		(27,151	)


Cash flows from financing activities:
Borrowings of bank debt		—			56,000			56,000
Repayments of bank debt		—			(34,000	)		(34,000	)
Net capital distributed to affiliated entities		(67,477	)		(7,190	)		(74,667	)
Distributions paid to noncontrolling TransMontaigne Partners' common units		—			(17,408	)		(17,408	)
Purchase of common units by TransMontaigne Partners' long-term incentive plan		—			(177	)		(177	)


Net cash used in financing activities		(67,477	)		(2,775	)		(70,252	)


Decrease in cash and cash equivalents		(1,419	)		(1,794	)		(3,213	)


Cash and cash equivalents at beginning of period		71,499			3,263			74,762


Cash and cash equivalents at end of period	$	70,080		$	1,469		$	71,549

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Notes to Condensed Combined Financial Statements (Continued)

As of June 30, 2014 and December 31, 2013 and for the six months

ended June 30, 2014 and 2013 (unaudited)

(9) Condensed Consolidating Guarantor and Non-Guarantor Financial Information (Continued)

Condensed combining statements of cash flows for the six months ended June 30, 2013

	Guarantor Entities			Non-Guarantor Entities			Combined

	(in thousands)
Net cash provided by (used in) operating activities	$	(131,253	)	$	32,482		$	(98,771	)
Cash flows from investing activities:
Investments in unconsolidated affiliates		—			(70,956	)		(70,956	)
Capital expenditures		(2,536	)		(10,376	)		(12,912	)
Proceeds from sale of assets		89			—			89


Net cash used in investing activities		(2,447	)		(81,332	)		(83,779	)


Cash flows from financing activities:
Borrowings of bank debt		—			119,500			119,500
Repayments of bank debt		—			(49,500	)		(49,500	)
Net capital contributed by (distributed to) affiliated entities		191,244			(6,185	)		185,059
Distributions paid to noncontrolling TransMontaigne Partners' common units		—			(15,016	)		(15,016	)
Purchase of common units by TransMontaigne Partners' long-term incentive plan		—			(166	)		(166	)
Other		—			(398	)		(398	)


Net cash provided by financing activities		191,244			48,235			239,479


Increase (decrease) in cash and cash equivalents		57,544			(615	)		56,929
Foreign currency translation effect on cash		—			46			46


Cash and cash equivalents at beginning of period		8,411			6,745			15,156


Cash and cash equivalents at end of period	$	65,955		$	6,176		$	72,131

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LETTER OF TRANSMITTAL

to Tender
Outstanding Unregistered 6.875% Senior Notes due 2021
of
NGL ENERGY PARTNERS LP
NGL ENERGY FINANCE CORP.
Pursuant to the Exchange Offer and Prospectus dated , 2014

THE EXCHANGE OFFER AND WITHDRAWAL RIGHTS WILL EXPIRE AT 5:00 P.M., NEW YORK CITY TIME, ON , 20 (THE "EXPIRATION DATE"), UNLESS THE EXCHANGE OFFER IS EXTENDED BY THE ISSUERS (AS DEFINED BELOW).

The Exchange Agent for the Exchange Offer is:
U.S. Bank National Association

By Registered or Certified Mail, Overnight Delivery or Hand Delivery:

U.S. Bank National Association
Corporate Trust Services
Attn: Specialized Finance Department
111 Fillmore Ave. E
St. Paul, Minnesota 55107

FACSIMILE TRANSMISSION: (651) 466-7372

CONFIRM BY TELEPHONE: (800) 934-6802

If you wish to exchange currently outstanding unregistered 6.875% Senior Notes due 2021 ("old notes") for an equal aggregate principal amount at maturity of registered 6.875% Senior Notes due 2021 ("new notes") pursuant to the exchange offer, you must validly tender (and not withdraw) old notes to the Exchange Agent prior to the Expiration Date.

The undersigned hereby acknowledges receipt of the prospectus, dated , 2014 (the "Prospectus"), of NGL Energy Partners LP and NGL Energy Finance Corp. (collectively, the "Issuers"), and this letter of transmittal (the "Letter of Transmittal"), which together describe the Issuers' offer (the "Exchange Offer") to exchange the old notes for a like principal amount of the new notes that have been registered under the Securities Act of 1933, as amended (the "Securities Act"). Capitalized terms used but not defined herein have the respective meanings given to them in the Prospectus.

The Issuers reserve the right, at any time or from time to time, to extend the Exchange Offer at their discretion, in which event the term "Expiration Date" shall mean the latest date to which the Exchange Offer is extended. The Issuers shall notify the Exchange Agent and each registered holder of the old notes of any extension by oral or written notice prior to 9:00 a.m., New York City time, on the next business day after the previously scheduled Expiration Date.

This Letter of Transmittal is to be used by holders of the old notes. Tender of old notes is to be made according to the Automated Tender Offer Program ("ATOP"), of the Depository Trust Company ("DTC"), pursuant to the procedures set forth in the Prospectus under the caption "Exchange Offer—Procedures for Tendering." DTC participants that are accepting the Exchange Offer must transmit their acceptance to DTC, which will verify the acceptance and execute a book-entry delivery to the Exchange Agent's DTC account. DTC will then send a computer-generated message known as an "agent's

A-1

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message" to the Exchange Agent for its acceptance. For you to validly tender your old notes in the Exchange Offer, the Exchange Agent must receive, prior to the Expiration Date, an agent's message under the ATOP procedures that confirms that:

•: DTC has received your instructions to tender your old notes; and
•: you agree to be bound by the terms of this Letter of Transmittal.

BY USING THE ATOP PROCEDURES TO TENDER OLD NOTES, YOU WILL NOT BE REQUIRED TO DELIVER THIS LETTER OF TRANSMITTAL TO THE EXCHANGE AGENT. HOWEVER, YOU WILL BE BOUND BY ITS TERMS, AND YOU WILL BE DEEMED TO HAVE MADE THE ACKNOWLEDGEMENTS AND THE REPRESENTATIONS AND WARRANTIES IT CONTAINS, JUST AS IF YOU HAD SIGNED IT.

PLEASE READ THE ACCOMPANYING INSTRUCTIONS CAREFULLY.

Ladies and Gentlemen:

(1) By tendering old notes in the Exchange Offer, you acknowledge receipt of the Prospectus and this Letter of Transmittal.

(2) By tendering old notes in the Exchange Offer, you represent and warrant that you have full authority to tender the old notes described above and will, upon request, execute and deliver any additional documents deemed by the Issuers to be necessary or desirable to complete the tender of old notes.

(3) You understand that the tender of the old notes pursuant to all of the procedures set forth in the Prospectus will constitute an agreement between the undersigned and the Issuers as to the terms and conditions set forth in the Prospectus.

(4) By tendering old notes in the Exchange Offer, you acknowledge that the Exchange Offer is being made in reliance upon interpretations contained in no-action letters issued to third parties by the staff of the Securities and Exchange Commission (the "SEC"), including Exxon Capital Holdings Corp., SEC No-Action Letter (available May 13, 1988), Morgan Stanley & Co., Inc., SEC No-Action Letter (available June 5, 1991) and Shearman & Sterling, SEC No-Action Letter (available July 2, 1993), that the new notes issued in exchange for the old notes pursuant to the Exchange Offer may be offered for resale, resold and otherwise transferred by holders thereof without compliance with the registration and prospectus delivery provisions of the Securities Act (other than a broker-dealer who purchased old notes exchanged for such new notes directly from the Issuers to resell pursuant to Rule 144A or any other available exemption under the Securities Act, and any such holder that is an "affiliate" of the Issuers within the meaning of Rule 405 under the Securities Act), provided that such new notes are acquired in the ordinary course of such holders' business and such holders are not participating in, and have no arrangement with any other person to participate in, the distribution of such new notes.

(5) By tendering old notes in the Exchange Offer, you hereby represent and warrant that:

(a): the new notes acquired pursuant to the Exchange Offer are being obtained in the ordinary course of your business, whether or not you are the holder;
(b): neither you nor, to your knowledge, any other person has an arrangement or understanding with any person to participate in the distribution (within the meaning of the Securities Act) of such new notes and you are not engaged and do not intend to engage in the distribution (within the meaning of the Securities Act) of such new notes;

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(c): you are not an "affiliate," as such term is defined under Rule 405 promulgated under the Securities Act, of the Issuers; and
(d): if you are a broker-dealer, you will receive the new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities, and you acknowledge that you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes.

You may, if you are unable to make all of the representations and warranties contained in Item 5 above and as otherwise permitted in the Registration Rights Agreement (as defined below), elect to have your old notes registered in the shelf registration statement described in the registration rights agreement, dated as of October 16, 2013 (the "Registration Rights Agreement"), by and among the Issuers, the initial guarantors party thereto and RBC Capital Markets, LLC, as representative of the Initial Purchasers (as defined therein). Such election may be made by notifying the Issuers in writing at, Attention: Atanas H. Atanasov. By making such election, you agree, as a holder of old notes participating in a shelf registration, to indemnify and hold harmless the Issuers, the guarantors, and their respective directors, each of the officers of the Issuers and the guarantors who signs such shelf registration statement, and each person who controls the Issuers or any of the guarantors, within the meaning of either the Securities Act or the Securities Exchange Act of 1934, as amended, and the respective officers, directors, partners, employees, representatives and agents of each such person, from and against any and all losses, claims, damages or liabilities caused by any untrue statement or alleged untrue statement of a material fact contained in any shelf registration statement or prospectus, or in any supplement thereto or amendment thereof, or caused by the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein, in the light of the circumstances under which they were made, not misleading; but only with respect to information relating to the undersigned furnished in writing by or on behalf of the undersigned expressly for use in a shelf registration statement, a prospectus or any amendments or supplements thereto. Any such indemnification shall be governed by the terms and subject to the conditions set forth in the Registration Rights Agreement, including, without limitation, the provisions regarding notice, retention of counsel, contribution and payment of expenses set forth therein. The above summary of the indemnification provisions of the Registration Rights Agreement is not intended to be exhaustive and is qualified in its entirety by the Registration Rights Agreement.

(6) If you are a broker-dealer that will receive new notes for your own account in exchange for old notes that were acquired as a result of market-making activities or other trading activities, you acknowledge, by tendering old notes in the Exchange Offer, that you will deliver a prospectus in connection with any resale of such new notes; however, by so acknowledging and by delivering a prospectus, you will not be deemed to admit that you are an "underwriter" within the meaning of the Securities Act.

(7) If you are a broker-dealer and old notes held for your own account were not acquired as a result of market-making or other trading activities, such old notes cannot be exchanged pursuant to the Exchange Offer.

(8) Any of your obligations hereunder shall be binding upon your successors, assigns, executors, administrators, trustees in bankruptcy and legal and personal representatives.

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INSTRUCTIONS
FORMING PART OF THE TERMS AND CONDITIONS OF THE EXCHANGE OFFER

1. Book-Entry Confirmations

Any confirmation of a book-entry transfer to the Exchange Agent's account at DTC of old notes tendered by book-entry transfer (a "Book-Entry Confirmation"), as well as an agent's message and any other documents required by this Letter of Transmittal, must be received by the Exchange Agent at its address set forth herein prior to 5:00 p.m., New York City time, on the Expiration Date.

2. Partial Tenders

Tenders of old notes will be accepted only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. The entire principal amount of old notes delivered to the Exchange Agent will be deemed to have been tendered unless otherwise communicated to the Exchange Agent. If the entire principal amount of all old notes is not tendered, then old notes for the principal amount of old notes not tendered and new notes issued in exchange for any old notes accepted will be delivered to the holder via the facilities of DTC promptly after the old notes are accepted for exchange.

3. Validity of Tenders

All questions as to the validity, form, eligibility (including time of receipt), acceptance and withdrawal of tendered old notes will be determined by the Issuers, in their sole discretion, which determination will be final and binding. The Issuers reserve the absolute right to reject any or all tenders not in proper form or the acceptance for exchange of which may, in the opinion of counsel for the Issuers, be unlawful. The Issuers also reserve the absolute right to waive any of the conditions of the Exchange Offer or any defect or irregularity in the tender of any old notes. The Issuers' interpretation of the terms and conditions of the Exchange Offer (including the instructions on this Letter of Transmittal) will be final and binding on all parties. Unless waived, any defects or irregularities in connection with tenders of old notes must be cured within such time as the Issuers shall determine. Although the Issuers intend to notify holders of defects or irregularities with respect to tenders of old notes, neither the Issuers, the Exchange Agent nor any other person shall be under any duty to give notification of any defects or irregularities in tenders or incur any liability for failure to give such notification. Tenders of old notes will not be deemed to have been made until such defects or irregularities have been cured or waived. Any old notes received by the Exchange Agent that are not properly tendered and as to which the defects or irregularities have not been cured or waived will be returned by the Exchange Agent to the tendering holders, unless otherwise provided in this Letter of Transmittal, as soon as practicable following the Expiration Date.

4. Requests for Assistance or Additional Copies

Requests for assistance or for additional copies of the Prospectus or this Letter of Transmittal may be directed to the Exchange Agent at the address or telephone number set forth on the cover page of this Letter of Transmittal. Holders may also contact their broker, dealer, commercial bank, trust company or other nominee for assistance concerning the Exchange Offer.

5. Withdrawal

Tenders may be withdrawn only pursuant to the limited withdrawal rights set forth in the Prospectus under the caption "Exchange Offer—Withdrawal of Tenders."

6. No Guarantee of Late Delivery

There is no procedure for guarantee of late delivery in the Exchange Offer.

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Dealer Prospectus Delivery Obligation

Until , 2015, all dealers that effect transactions in these securities, whether or not participating in the offering, may be required to deliver a prospectus. This is in addition to the dealers' obligation to deliver a prospectus when acting as underwriters and with respect to unsold allotments or subscriptions.

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SUBJECT TO COMPLETION, DATED DECEMBER 24, 2014

PROSPECTUS

NGL Energy Partners LP
NGL Energy Finance Corp.

Offer to Issue
Up to $400,000,000 of
5.125% Senior Notes due 2019

That Have Been Registered Under
the Securities Act of 1933
("new notes")

In Exchange For

Up to $400,000,000 of
5.125% Senior Notes due 2019
That Have Been Not Registered Under
the Securities Act of 1933

("old notes")

Terms of the New Notes:

•: The terms of the new notes are identical to the terms of the old notes that were issued in July 2014, except that the new notes will be registered under the Securities Act of 1933, as amended, (the "Securities Act") and therefore freely tradable, and will not contain restrictions on transfer, registration rights or provisions for additional interest.

Terms of the Exchange Offer:

•: We are offering to issue new notes in exchange for the same principal amount of old notes.
•: Interest on the new notes will accrue from the last interest payment date on the notes at the rate of 5.125% per annum, and will be payable on January 15 and July 15 of each year.
•: The exchange offer expires at 5:00 p.m., New York City time, on , 2015, unless extended.
•: Tenders of old notes may be withdrawn at any time prior to the expiration of the exchange offer.
•: Your exchange of old notes for new notes will not be a taxable event for U.S. federal income tax purposes. Please read "Certain U.S. Federal Income Tax Consequences."

You should carefully consider the risks set forth under "Risk Factors" beginning on page 12 of this prospectus for a discussion of factors you should consider before participating in the exchange offer.

The date of this prospectus is , 2014.

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		Page

WHERE YOU CAN FIND MORE INFORMATION			ii
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS			iii
PROSPECTUS SUMMARY			1
RISK FACTORS			12
EXCHANGE OFFER			34
RATIO OF EARNINGS TO FIXED CHARGES			42
USE OF PROCEEDS			43
SELECTED CONSOLIDATED HISTORICAL FINANCIAL AND OPERATING DATA			44
BUSINESS			45
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS			72
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK			138
MANAGEMENT			140
EXECUTIVE COMPENSATION			146
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS			157
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
DESCRIPTION OF NOTES			160
PLAN OF DISTRIBUTION			218
CERTAIN U.S. FEDERAL INCOME TAX CONSEQUENCES			219
LEGAL MATTERS			220
EXPERTS			220
INDEX TO FINANCIAL STATEMENTS			F-1

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WHERE YOU CAN FIND MORE INFORMATION

NGL Energy Partners LP
6120 South Yale Avenue
Suite 805
Tulsa, Oklahoma 74136
(918) 481-1119

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CAUTIONARY STATEMENT
REGARDING FORWARD-LOOKING STATEMENTS

•: 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;

iii

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•: hazards or operating risks incidental to the transporting and distributing of petroleum products that may not be fully covered by insurance;
•: the maturity of the crude oil and natural gas liquids industries and competition from other marketers;
•: the loss of key personnel;
•: the ability to hire drivers;
•: the ability to renew contracts with key customers;
•: the ability to maintain or increase the margins we realize for our terminal, barging, trucking, and water disposal and recycling and discharge services;
•: the ability to renew leases for general purpose and high pressure railcars;
•: the ability to renew leases for underground natural gas liquids storage;
•: the nonpayment or nonperformance by our customers;
•: the availability and cost of capital and our ability to access certain capital sources;
•: a deterioration of the credit and capital markets;
•: the ability to successfully identify and consummate strategic acquisitions 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;
•: any reduction or the 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.; and
•: other risks and uncertainties, including those described under "Risk Factors."

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PROSPECTUS SUMMARY

NGL Energy Partners LP

Overview

At September 30, 2014, our operations include:

•: Ourcrude oil logistics segment, the assets of which include owned and leased crude oil storage terminals, pipeline injection stations, a fleet of trucks, a fleet of leased and owned railcars, and a fleet of barges and towboats, and a 50% interest in a crude oil pipeline. Our crude oil logistics segment purchases crude oil from producers and transports it for resale at owned and leased pipeline injection points, storage terminals, barge loading facilities, rail facilities, refineries, and other trade hubs.
•: Ourwater solutions segment, the assets of which include water treatment and disposal facilities. Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, and from the sale of recycled water and recovered hydrocarbons.
•: Ourliquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 22 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, petrochemical plants, and other participants in the wholesale markets.
•: Ourretail propane segment, 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.
•: Ourrefined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.7% limited partner interest in TransMontaigne Partners L.P. ("TLP"), which conducts refined products terminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC ("BOSTCO") and a 50% interest in Frontera Brownsville LLC, which are entities that own refined products storage facilities.

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Our Ownership and Organizational Structure

The following chart provides a simplified overview of our organizational structure as of September 30, 2014:

(1): The notes are currently guaranteed by all of our restricted subsidiaries (other than NGL Energy Finance Corp.) that are obligors under certain of our indebtedness, including our Credit Agreement. See "Description of Notes—Note Guarantees" and "—Additional Note Guarantees."
(2): Includes (i) NGL Crude Logistics, LLC which includes the operations of our crude oil logistics, refined products and renewables business, (ii) NGL Water Solutions, LLC, which includes the operations of our water solutions business, (iii) NGL Liquids, LLC, which includes the operations of our liquids business and (iv) NGL Propane, LLC, which includes the operations of our retail propane business.

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Recent Developments

Grand Mesa Acquisition

Facility Increase Agreement

Principal Executive Offices

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The Exchange Offer

On July 9, 2014 we completed a private offering of the old notes. We entered into a registration rights agreement with the initial purchasers in the private offering pursuant to which we agreed to deliver to you this prospectus and to use commercially reasonable efforts to cause the registration statement of which his prospectus forms a part to be declared effective by the SEC on or before July 9, 2015.


Old Notes		$400 million aggregate principal amount of 5.125% Senior Notes due 2019, issued pursuant to Rule 144A and Regulation S promulgated under the Securities Act. Transfer restrictions apply to the old notes.
New Notes		Up to $400 million aggregate principal amount of 5.125% Senior Notes due 2019. The terms of the new notes are identical to the terms of the old notes, except that the new notes will be registered under the Securities Act, and will not have restrictions on transfer, registration rights or provisions for additional interest.
		Except as provided below, we believe that the new notes may be offered for resale, resold and otherwise transferred by you without compliance with the registration and prospectus delivery provisions of the Securities Actprovided that:
		• the new notes are being acquired in the ordinary course of business,
		• you are not participating, do not intend to participate, and have no arrangement or understanding with any person to participate in the distribution of the new notes issued to you in the exchange offer,
		• you are not our affiliate, and
		• you are not a broker-dealer tendering old notes acquired directly from us for your account.
		Our belief is based on interpretations by the staff of the SEC, as set forth in no-action letters issued to third parties that are not related to us. The SEC has not considered this exchange offer in the context of a no-action letter, and we cannot assure you that the SEC would make similar determinations with respect to this exchange offer. If any of these conditions are not satisfied, or if our belief is not accurate, and you transfer any new notes issued to you in the exchange offer without delivering a resale prospectus meeting the requirements of the Securities Act or without an exemption from registration of your new notes from those requirements, you may incur liability under the Securities Act. We will not assume, nor will we indemnify you against, any such liability. Each broker-dealer that receives new notes for its own account in exchange for old notes, where the old notes were acquired by such broker-dealer as a result of market-making or other trading activities, must acknowledge that it will deliver a prospectus in connection with any resale of such new notes. See "Plan of Distribution."

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Exchange Offer		We are offering to issue freely tradable new notes in exchange for the same principal amount of new notes. The old notes may be tendered only in minimum denominations of $2,000 and integral multiples of $1,000 in excess thereof. We will issue new notes in exchange for all old notes that are validly tendered and not withdrawn prior to the expiration of the exchange offer. We will cause the exchange to be effected promptly after the expiration date of the exchange offer.
		The new notes will evidence the same debt as the old notes and will be issued under and entitled to the benefits of the same indenture that governs the old notes. Because we have registered the offers and sales of the new notes, the new notes will not be subject to transfer restrictions, and holders of old notes that have tendered and had their outstanding notes accepted in the exchange offer will have no further registration rights.
Expiration Date		The exchange offer will expire at 5:00 p.m., New York City time, on , 20 , unless we decide to extend it.
Conditions to the Exchange Offer		The registration rights agreement does not require us to accept old notes for exchange if the exchange offer, or the making of any exchange by a holder of the old notes, would violate any applicable law or interpretation of the staff of the Securities and Exchange Commission. The exchange offer is not conditioned on a minimum aggregate principal amount of old notes being tendered. Please read "Exchange Offer—Conditions to the Exchange Offer" for more information about the conditions to the exchange offer.
Procedures for Tendering Old Notes		To participate in the exchange offer, you must follow the procedures established by The Depository Trust Company, or DTC, for tendering notes held in book-entry form. These procedures for using DTC's Automated Tender Offer Program, or ATOP, require that (i) the exchange agent receive, prior to the expiration date of the exchange offer, a computer generated message known as an "agent's message" that is transmitted through ATOP, and (ii) DTC confirms that:
		• DTC has received your instructions to exchange your notes; and
		• you agree to be bound by the terms of the letter of transmittal.
		By transmitting an agent's message, you will represent to us that, among other things:
		• the new notes you receive will be acquired in the ordinary course of your business;
		• you are not participating, and you have no arrangement with any person or entity to participate, in the distribution of the new notes;

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		• you are not our "affiliate," as defined in Rule 405 under the Securities Act, or a broker-dealer tendering old notes acquired directly from us for resale pursuant to Rule 144A or any other available exemption under the Securities Act; and
		• if you are not a broker-dealer, that you are not engaged in and do not intend to engage in the distribution of the new notes.
		For more information on tendering your old notes, please refer to the section in this prospectus entitled "Exchange Offer—Terms of the Exchange Offer," "—Procedures for Tendering," and "Description of Notes—Book-Entry, Delivery and Form."
Guaranteed Delivery Procedures		None.
Withdrawal of Tenders		You may withdraw your tender of old notes at any time prior to the expiration date. To withdraw, you must submit a notice of withdrawal to the exchange agent using ATOP procedures before 5:00 p.m., New York City time, on the expiration date of the exchange offer. Please refer to the section in this prospectus entitled "Exchange Offer—Withdrawal of Tenders."
Acceptance of Old Notes and Delivery of New Notes		If you fulfill all conditions required for proper acceptance of old notes, we will accept any and all old notes that you properly tender in the exchange offer on or before 5:00 p.m., New York City time, on the expiration date. We will return any old notes that we do not accept for exchange to you without expense promptly after the expiration date and acceptance of the old notes for exchange. Please refer to the section in this prospectus entitled "Exchange Offer—Terms of the Exchange Offer."
Fees and Expenses		We will bear expenses related to the exchange offer. Please refer to the section in this prospectus entitled "Exchange Offer—Fees and Expenses."
Use of Proceeds		The issuance of the new notes will not provide us with any new proceeds. We are making this exchange offer solely to satisfy our obligations under the registration rights agreement entered into in connection with the initial issuance of the old notes.
Consequences of Failure to Exchange Old Notes		If you do not exchange your old notes in this exchange offer, you will no longer be able to require us to register the old notes under the Securities Act, except in limited circumstances provided under the registration rights agreement. In addition, you will not be able to resell, offer to resell or otherwise transfer the old notes unless we have registered the old notes under the Securities Act, or unless you resell, offer to resell or otherwise transfer them under an exemption from the registration requirements of, or in a transaction not subject to, the Securities Act.

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U.S. Federal Income Tax Considerations		The exchange of old notes for new notes in the exchange offer will not be a taxable event for U.S. federal income tax purposes. Please read "Certain U.S. Federal Income Tax Consequences."
Exchange Agent		We have appointed U.S. Bank National Association as exchange agent for the exchange offer. You should direct questions and requests for assistance, as well as requests for additional copies of this prospectus or the letter of transmittal, to the exchange agent addressed as follows: U.S. Bank National Association, Corporate Trust Services, Attention: Specialized Finance Department, 111 Fillmore Ave. E., St. Paul, MN 55107. Eligible institutions may make requests by facsimile at (651) 466-7372, and may confirm facsimile delivery by calling (800) 934-6802.

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Terms of the New Notes


Issuers		NGL Energy Partners LP and NGL Energy Finance Corp.
		NGL Energy Finance Corp., a Delaware corporation, is a 100% owned subsidiary of NGL Energy Partners LP that was organized for the sole purpose of being a co-issuer of certain of our indebtedness, including the new notes. NGL Energy Finance Corp. has no operations and no revenue other than as may be incidental to its activities as co-issuer of our indebtedness.
Notes Offered		$400 million aggregate principal amount of 5.125% Senior Notes due 2019.
Maturity Date		July 15, 2019.
Interest		Interest on the new notes will accrue from July 9, 2014 at a rate of 5.125% per annum (calculated using a 360-day year).
		Interest on the new notes is payable on January 15 and July 15 of each year.
Ranking		Like the old notes, the new notes will be the unsecured senior obligations of each of the Issuers. Accordingly, they will rank:
		• pari passu in right of payment with all existing and future unsecured senior indebtedness of each of the Issuers;
		• senior in right of payment to any future subordinated indebtedness of each of the Issuers;
		• structurally subordinated to all obligations of any of our subsidiaries; and
		• effectively junior in right of payment to all existing and future secured indebtedness of each of the Issuers, including indebtedness under the our revolving credit agreement (the "Credit Agreement") and our 6.65% Senior Secured Notes due 2022 (the "Existing Senior Secured Notes"), which are secured by substantially all of the assets of NGL Energy, to the extent of the value of the assets of the Issuers constituting collateral securing such indebtedness.
		See "Risk Factors—Risks Related to the Notes—The notes and the guarantees are unsecured and effectively subordinated to our and our subsidiary guarantors' existing and future secured indebtedness.."

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		As of September 30, 2014, we had $2,442.4 million of total long-term indebtedness, $1,329.5 million of which was secured indebtedness, and we had $904.3 million of remaining borrowing capacity under our Credit Agreement (net of $209.2 million of outstanding letters of credit).
		The guarantees will rank:
		• pari passu in right of payment with all existing and future unsecured senior indebtedness of each guarantor;
		• senior in right of payment to any future subordinated indebtedness of each guarantor; and
		• effectively junior in right of payment to all existing and future secured indebtedness of each guarantor, including indebtedness under the Credit Agreement and the Existing Senior Secured Notes, to the extent of the value of the assets of each guarantor constituting collateral securing such indebtedness.
Optional Redemption		We may, from time to time prior to June 15, 2019, redeem all or a part of the new notes, at a redemption price equal to 100% of the aggregate principal amount of the new notes redeemed, plus a "make-whole" premium and accrued and unpaid interest, if any, to the redemption date.
Change of Control		If we experience certain kinds of changes of control, we must give holders of the new notes the opportunity to sell us their new notes at 101% of their principal amount, plus accrued and unpaid interest, if any.

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Certain Covenants		The indenture governing the new notes contains certain covenants limiting our ability and the ability of our restricted subsidiaries to, under certain circumstances:
		• pay distributions on, purchase or redeem our common equity or purchase or redeem our subordinated debt;
		• incur or guarantee additional indebtedness or issue preferred units;
		• create or incur certain liens;
		• enter into agreements that restrict distributions or other payments from our restricted subsidiaries to us;
		• consolidate, merge or transfer all or substantially all of our assets; and
		• engage in transactions with affiliates.
		These covenants are subject to important exceptions and qualifications as described in this prospectus under the caption "Description of Notes—Covenants." In addition, certain of the covenants listed above will terminate before the new notes mature if any two of the three specified rating agencies assign the new notes an investment grade rating in the future and no events of default exist under the indenture. Any covenants that cease to apply to us as a result of achieving investment grade ratings will not be restored, even if the credit ratings assigned to the new notes later fall below investment grade.
Absence of Established Market for the New Notes		The new notes generally will be freely transferable, but will also be new securities for which there will not initially be a market. There can be no assurance as to the development or liquidity of any market for the new notes.
		We do not intend to apply for a listing of the new notes on any securities exchange or for the inclusion of the new notes on any automated dealer quotation system.

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Ratio of Earnings to Fixed Charges

	NGL Energy Partners LP										NGL Supply, Inc.

	Six Months Ended September 30, 2014		Year Ended March 31, 2014		Year Ended March 31, 2013		Year Ended March 31, 2012		Six Months Ended March 31, 2011		Six Months Ended September 30, 2010		Year Ended March 31, 2010
Ratio of earnings to fixed charges		(a)		1.53x		1.75x		1.91x		5.59x		(b)		6.32x

(a): Due to NGL Energy Partners LP's loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2014. NGL Energy Partners LP would have needed to generate an additional $60.1 million of earnings to achieve a ratio of 1:1.
(b): Due to NGL Supply, Inc.'s loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2010. NGL Supply, Inc. would have needed to generate an additional $3.9 million of earnings to achieve a ratio of 1:1.

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RISK FACTORS

Risks Related to Investing in the New Notes

Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects and our ability to make payments on the notes.

•: requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and limiting our flexibility in planning for or reacting to changes in our business and the industry in which we operate;
•: increasing our vulnerability to economic downturns and adverse developments in our business;
•: limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
•: placing restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
•: placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and
•: making it more difficult for us to satisfy our obligations under the notes or other debt and increasing the risk that we may default on our debt obligations.

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We have a holding company structure in which our subsidiaries conduct our operations and own our operating assets.

Despite our current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.

The notes and the guarantees are unsecured and effectively subordinated to our and our subsidiary guarantors' existing and future secured indebtedness.

The notes and the guarantees are structurally subordinated to all liabilities of our non-guarantor subsidiaries.

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Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

We may not have the funds necessary to finance the repurchase of the notes in connection with a change of control offer required by the indenture.

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Federal and state statutes allow courts, under specific circumstances, to void guarantees and require noteholders to return payments received from subsidiary guarantors.

•: received less than reasonably equivalent value or fair consideration for the incurrence of such guarantee;
•: was insolvent or rendered insolvent by reason of such incurrence; was engaged in a business or transaction for which the subsidiary guarantor's remaining assets constituted unreasonably small capital; or
•: intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature.

•: the sum of its debts, including contingent liabilities, was greater than the fair saleable value of all of its assets;
•: if the present fair saleable value of its assets was less than the amount that would be required to pay its probable liability on its existing debts, including contingent liabilities, as
•: they become absolute and mature; or
•: it could not pay its debts as they become due.

If an active trading market does not develop for the new notes you may not be able to resell them.

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

Risks Related to our Business

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, the purchase agreement governing our outstanding 6.65% senior secured notes due 2022 (the "Note Purchase Agreement") and indentures governing our outstanding 6.875% senior notes due 2021 and our outstanding 5.125% Senior Notes due 2019 (the "Indentures") that limit the amount and types of indebtedness that we may incur to finance acquisitions and which may adversely affect our ability to service our debt obligations, including the notes;
•: 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.

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Any acquisitions we make in pursuit of our growth strategy are subject to potential risks, including, but not limited to:

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

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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 to service our debt obligations, including the notes, 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.

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

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

Our refined products and renewables segments also face significant competition for refined products and renewables supplies and also for customers for our services.

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

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

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

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reputational damage, expenditures for remediation and liability for natural resource damages, property damage and personal injuries.

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

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Our use of derivative financial instruments could have an adverse effect on our results of operations.

Some of our operations could become subject to the jurisdiction of the FERC.

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Competition from alternative energy sources may cause us to lose customers, thereby negatively impacting our financial condition and results of operations.

Energy efficiency and new technology may reduce the demand for propane and adversely affect our operating results.

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

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

•: 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.

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

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

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

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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.

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

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

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

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

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

A significant increase in fuel prices may adversely affect our transportation costs.

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

The risk of terrorism and political unrest in various energy producing regions may adversely affect the economy and the price and availability of products.

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operations could negatively impact our ability to transport propane to our locations. These risks could potentially negatively impact our results of operations.

We depend on the leadership and involvement of key personnel for the success of our businesses.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

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EXCHANGE OFFER

Purpose and Effect of the Exchange Offer

We sold the old notes on July 9, 2014 pursuant to the purchase agreement, dated as of June 24, 2014, by and among us, our subsidiary guarantors and the initial purchasers named therein. The old notes were subsequently offered by the initial purchasers to qualified institutional buyers pursuant to Rule 144A under the Securities Act and to non-U.S. persons pursuant to Regulation S under the Securities Act.

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purchaser of old notes who is an "affiliate" of ours or who intends to participate in the exchange offer for the purpose of distributing the related new notes:

•: will not be able to rely on the interpretation of the staff of the SEC,
•: will not be able to tender its old notes in the exchange offer, and
•: must comply with the registration and prospectus delivery requirements of the Securities Act in connection with any sale or transfer of the old notes unless such sale or transfer is made pursuant to an exemption from such requirements.

•

the exchange offer is not permitted by applicable law or SEC policy;

•

for any reason the exchange offer is not consummated within 30 business days after October 16, 2014; or

•

prior to the 20th business day following the consummation of this offering, any holder notifies us that:

•: the holder is prohibited by applicable law or SEC policy from participating in the exchange offer;
•: the holder may not resell the new notes acquired in the exchange offer to the public without delivering a prospectus, and the prospectus contained in the exchange offer is not appropriate or available for such resales by such purchaser; or
•: the holder is a broker-dealer and holds old notes acquired directly from us or one of our affiliates that are not freely tradeable, and such holder cannot participate in the exchange offer.

If:

(1): the Issuers and the subsidiary guarantors become obligated under the registration rights agreement to file a shelf registration statement and fail to do so on or before the shelf filing deadline;
(2): any registration statement required by the registration rights agreement is not declared effective by the SEC on or prior to the date specified for such effectiveness (the "Effectiveness Target Date");

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(3): the Issuers and the subsidiary guarantors fail to consummate the exchange offer within 30 business days of the Effectiveness Target Date with respect to the exchange offer registration statement; or
(4): the shelf registration statement or the exchange offer registration statement is declared effective by the SEC but thereafter ceases to be effective or usable for its intended purpose (with such event referred to in clauses (1) through (4) above, a "Registration Default");

Terms of the Exchange Offer

The exchange offer is not conditioned upon any minimum aggregate principal amount of old notes being tendered for exchange.

As of the date of this prospectus, $400.0 million in aggregate principal amount of the old notes is outstanding. This prospectus and the letter of transmittal are being sent to all registered holders of old

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notes. There will be no fixed record date for determining registered holders of old notes entitled to participate in the exchange offer.

Expiration Date

The exchange offer will expire at 5:00 p.m., New York City time, on , 2015, unless, in our sole discretion, we extend it.

Extensions, Delays in Acceptance, Termination or Amendment

Any such notice relating to the extension of the exchange offer will disclose the number of securities tendered as of the date of the notice, as required by Rule 14e-1(d) under the Exchange Act.

We expressly reserve the right at our sole discretion:

•: to delay accepting the old notes, provided that any such delay is done in a manner consistent with Rule 14e-1(c) of the Exchange Act;
•: to extend the exchange offer;
•: to terminate the exchange offer and not accept old notes not previously accepted if any of the conditions listed under "—Conditions to the Exchange Offer" are not satisfied or waived by us, by giving oral or written notice of such delay, extension or termination to the exchange agent; or
•: to amend the terms of the exchange offer in any manner.

Following the commencement of the exchange offer, we currently anticipate that we would only delay accepting old notes tendered in the exchange offer due to an extension of the expiration date.

We will follow any delay in acceptance, extension or termination as promptly as practicable by oral or written notice to the exchange agent.

Any such delay in acceptance, extension, termination or amendment will be followed as promptly as practicable by oral or written notice thereof to the registered holders of old notes. If we amend the

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If we delay accepting any old notes or terminate the exchange offer, we will promptly return any old notes deposited pursuant to the exchange offer as required by Rule 14e-1(c).

Conditions to the Exchange Offer

�� In addition, we will not be obligated to accept for exchange the old notes of any holder that has not made to us the representations described under "—Purpose and Effect of the Exchange Offer," "—Procedures for Tendering" and "Plan of Distribution" and such other representations as may be reasonably necessary under applicable SEC rules, regulations or interpretations to allow us to use an appropriate form to register the issuance of the new notes under the Securities Act.

Procedures for Tendering

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There is no procedure for guaranteed late delivery of the notes.

Determinations Under the Exchange Offer

When We Will Issue New Notes

In all cases, we will issue new notes for old notes that we have accepted for exchange under the exchange offer only after the exchange agent timely receives:

•: a book-entry confirmation of such old notes into the exchange agent's account at DTC; and
•: a properly transmitted agent's message.

Return of Old Notes Not Accepted or Exchanged

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Your Representations to Us

By agreeing to be bound by the letter of transmittal, you will represent to us that, among other things:

•: any new notes that you receive will be acquired in the ordinary course of your business;
•: you have no arrangement or understanding with any person or entity to participate in the distribution of the new notes;
•: you are not our "affiliate," as defined in Rule 405 of the Securities Act;
•: if you are a broker-dealer that will receive new notes for your own account in exchange for old notes, you acquired those notes as a result of market-making activities or other trading activities and you will deliver a prospectus (or, to the extent permitted by law, make available a prospectus) in connection with any resale of such new notes; and
•: if you are a broker-dealer that participates in the exchange offer with respect to old notes acquired for your own account as a result of market-making activities or other trading activities, you have not entered into any arrangement or understanding with us or any of our "affiliates" to distribute the new notes.

Withdrawal of Tenders

Fees and Expenses

We will pay the cash expenses to be incurred in connection with the exchange offer. They include:

•: all registration and filing fees and expenses;
•: all fees and expenses of compliance with federal securities and state "blue sky" or securities laws;

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•: accounting and legal fees, disbursements and printing, messenger and delivery services, and telephone costs; and
•: related fees and expenses.

Transfer Taxes

Consequences of Failure to Exchange

Accounting Treatment

Other

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RATIO OF EARNINGS TO FIXED CHARGES

	NGL Energy Partners LP										NGL Supply, Inc.

	Six Months Ended September 30, 2014		Year Ended March 31, 2014		Year Ended March 31, 2013		Year Ended March 31, 2012		Six Months Ended March 31, 2011		Six Months Ended September 30, 2010		Year Ended March 31, 2010
Ratio of earnings to fixed charges		(a)		1.53x		1.75x		1.91x		5.59x		(b)		6.32x

(a): Due to NGL Energy Partners LP's loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2014. NGL Energy Partners LP would have needed to generate an additional $60.1 million of earnings to achieve a ratio of 1:1.
(b): Due to NGL Supply, Inc.'s loss for the period, the ratio was less than 1:1 for the six months ended September 30, 2010. NGL Supply, Inc. would have needed to generate an additional $3.9 million of earnings to achieve a ratio of 1:1.

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USE OF PROCEEDS

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SELECTED CONSOLIDATED HISTORICAL FINANCIAL AND OPERATING DATA

				NGL Energy Partners LP								NGL Supply, Inc.

	Six Months Ended September 30, 2014			Year Ended March 31,						Six Months Ended March 31, 2011		Six Months Ended September 30, 2010
				Year Ended March 31,											Year Ended March 31, 2010
				2014		2013		2012							Year Ended March 31, 2010
	(in thousands, except per unit data)
Income Statement Data(1)
Total revenues	$	9,029,140		$	9,699,274	$	4,417,767	$	1,310,473	$	622,232	$	316,943		$	735,506
Total cost of sales		8,713,518			9,132,699		4,039,110		1,217,023		583,032		310,908			708,215
Operating income (loss)		(12,785	)		106,565		87,307		15,030		14,837		(3,795	)		6,661
Interest expense		(49,145	)		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		(59,199	)		47,655		47,940		7,876		12,679		(2,515	)		3,636
Basic and diluted earnings (loss) per common unit		(0.93	)		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	$	(61,635	)	$	85,236	$	132,634	$	90,329	$	34,009	$	(30,749	)	$	7,480
Cash distributions paid per common unit (subsequent to IPO)		1.14			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		82,851			165,148		72,475		7,544		1,440		280			582
Acquisitions of businesses, including additional consideration paid on prior period acquisitions		658,764			1,268,810		490,805		297,401		17,400		123			3,113
Balance Sheet Data—Period End(1)
Total assets	$	6,551,679		$	4,167,223	$	2,291,618	$	749,519	$	163,833	$	148,596		$	111,580
Total long-term obligations, exclusive of current maturities		2,437,351			1,639,578		742,641		199,389		65,936		18,940			8,851
Redeemable preferred stock		—			—		—		—		—		—			3,000
Total equity		2,314,830			1,531,853		889,418		405,329		47,353		36,811			46,403
Volume Information(1)
Retail propane and distillates sold (gallons)		55,854			197,326		173,232		79,886		34,932		3,747			15,514
Wholesale propane sold (gallons)(2)		423,992			1,190,106		912,625		659,921		372,504		226,330			623,510
Wholesale other products sold (gallons)		384,235			786,671		505,529		134,999		49,465		46,092			53,878
Crude oil sold (barrels)		40,806			46,107		24,373		—		—		—			—
Water delivered (barrels)		51,804			62,774		25,009		—		—		—			—
Refined products sold (gallons)		1,221,949			412,974		—		—		—		—			—

(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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BUSINESS

Overview

•: 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.

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

Initial Public Offering

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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.
•: 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.

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•: 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

Our Business 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

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•: 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.
•: 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.

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•: 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

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 own seven storage terminal facilities, as summarized below:

Location		Storage Capacity (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

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

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

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•: 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.

•: 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.

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

Water Solutions

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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.

Location		Processing Capacity (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.

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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.

•: 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.

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Liquids

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.

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

Facility		Throughput Capacity (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

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.

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

	Leased Storage Space (in gallons)

Storage Facility	Beginning April 1, 2014		At March 31, 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

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

•: price;
•: availability of supply;

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•: 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.

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 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.

•: we require certain customers to prepay or place deposits for their purchases;
•: we require certain customers to post letters of credit on a portion of our receivables;
•: we require certain customers to take delivery of their contracted volume ratably to help control the account balance rather than allowing them to take delivery of propane at their discretion;
•: we review receivable aging analyses regularly to identify issues or trends that may develop; and
•: we require our 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.

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Retail Propane

The following table shows the number of our customer service locations and satellite distribution locations by state:

State

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

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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.

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.

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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.

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

•: customers are billed on a timely basis;

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•: 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.

Refined Products

•: 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 refined products primarily from eight suppliers, which consist primarily of large energy and petrochemicals companies.

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•: 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

•: 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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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

Government Regulation

Regulation of the Oil and Natural Gas Industries

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Environmental Regulation

•: 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.

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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.

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Greenhouse Gas Regulation

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Safety and Transportation

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�� With respect to the transportation of propane, distillates, crude oil, and water, we are subject to regulations promulgated under federal legislation, including the Federal Motor Carrier Safety Act and the Homeland Security Act of 2002. Regulations under these statutes cover the security and transportation of hazardous materials and are administered by the United States Department of Transportation ("DOT"). Specifically, crude oil pipelines are subject to regulation by the DOT, through the Pipeline and Hazardous Materials Safety Administration ("PHMSA"), under the Hazardous Liquid Pipeline Safety Act of 1979 ("HLPSA"), which requires PHMSA to develop, prescribe, and enforce minimum federal safety standards for the storage and transportation of hazardous liquids by and comparable state statutes with respect to design, installation, testing, construction, operation, replacement and management of pipeline facilities. HLPSA covers petroleum and petroleum products and requires any entity that owns or operates pipeline facilities to comply with such regulations, to permit access to and copying of records and to file certain reports and provide information as required by the United States Secretary of Transportation. These regulations include potential fines and penalties for violations. The Pipeline Safety Act of 1992 added the environment to the list of statutory factors that must be considered in establishing safety standards for hazardous liquid pipelines, established safety standards for certain "regulated gathering lines," and mandated that regulations be issued to establish criteria for operators to use in identifying and inspecting pipelines located in high consequence areas ("HCAs"), defined as those areas that are unusually sensitive to environmental damage, that cross a navigable waterway, or that have a high population density. In the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006, Congress required mandatory inspections for certain 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

Occupational Health Regulations

Legal Proceedings

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Available Information on our Website

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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS

Overview

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.

At September 30, 2014, our operations include:

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

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•: Our water solutions segment, the assets of which include water treatment and disposal facilities. Our water solutions segment generates revenues from the treatment and disposal of wastewater generated from crude oil and natural gas production, and from the sale of recycled water and recovered hydrocarbons.
•: Our liquids segment, which supplies natural gas liquids to retailers, wholesalers, refiners, and petrochemical plants throughout the United States and in Canada, and which provides natural gas liquids terminaling services through its 22 terminals throughout the United States and railcar transportation services through its fleet of leased and owned railcars. Our liquids segment purchases propane, butane, and other products from refiners, processing plants, producers, and other parties, and sells the product to retailers, refiners, petrochemical plants, and other participants in the wholesale markets.
•: Our retail propane segment, which sells propane, distillates, and equipment and supplies to end users consisting of residential, agricultural, commercial, and industrial customers and to certain re-sellers in more than 20 states.
•: Our refined products and renewables segment, which conducts gasoline, diesel, ethanol, and biodiesel marketing operations. We also own the 2.0% general partner interest and a 19.7% limited partner interest in TransMontaigne Partners L.P. ("TLP"), which conducts refined products terminaling operations. TLP also owns a 42.5% interest in Battleground Oil Specialty Terminal Company LLC ("BOSTCO") and a 50% interest in Frontera Brownsville LLC, which are entities that own refined products storage facilities.

Crude Oil Logistics

The range of low and high spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma and the prices at March 31, 2014 were as follows:

	Spot Price Per Barrel

Year Ended:	Low		High		At Period End
March 31, 2014	$	86.68	$	110.53	$	101.58
March 31, 2013		77.69		106.16		97.23

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The range of low and high spot prices per barrel of NYMEX West Texas Intermediate Crude Oil at Cushing, Oklahoma and the prices at September 30, 2014 were as follows:

	Spot Price Per Barrel

	Low		High		At Period End
Three Months Ended September 30,
2014	$	91.16	$	105.34	$	91.16
2013		97.99		110.53		102.33
Six Months Ended September 30,
2014	$	91.16	$	107.26	$	91.16
2013		86.68		110.53		102.33

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

Water Solutions

Liquids

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The range of low and high spot propane prices per gallon at Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, and the prices at March 31, 2014 were as follows:

	Conway, Kansas						Mt. Belvieu, Texas

	Spot Price Per Gallon						Spot Price Per Gallon
	Spot Price Per Gallon				Spot Price Per Gallon At Period End		Spot Price Per Gallon				Spot Price Per Gallon At Period End
Year Ended:	Low		High		Spot Price Per Gallon At Period End		Low		High		Spot Price Per Gallon At Period End
March 31, 2014	$	0.77	$	4.33	$	1.03	$	0.81	$	1.73	$	1.06
March 31, 2013		0.50		0.96		0.90		0.71		1.22		0.96
March 31, 2012		0.90		1.49		0.98		1.17		1.63		1.24

The range of low and high spot butane prices per gallon at Mt. Belvieu, Texas and the prices at March 31, 2014 were as follows:

	Spot Price Per Gallon

Year Ended:	Low		High		At Period End
March 31, 2014	$	1.08	$	1.64	$	1.26
March 31, 2013		1.14		1.93		1.45

The range of low and high spot propane prices per gallon at Conway, Kansas and Mt. Belvieu, Texas, two of our main pricing hubs, and the prices at period end were as follows:

	Conway, Kansas						Mt. Belvieu, Texas

	Spot Price Per Gallon						Spot Price Per Gallon
	Low		High		At Period End		Low		High		At Period End
Three Months Ended September 30,
2014	$	1.00	$	1.10	$	1.03	$	0.99	$	1.11	$	1.04
2013		0.81		1.16		1.01		0.86		1.19		1.05
Six Months Ended September 30,
2014	$	0.96	$	1.13	$	1.03	$	0.99	$	1.13	$	1.04
2013		0.77		1.16		1.01		0.81		1.19		1.05

The range of low and high spot butane prices per gallon at Mt. Belvieu, Texas and the prices at period end were as follows:

	Spot Price Per Gallon

	Low		High		At Period End
Three Months Ended September 30,
2014	$	1.21	$	1.30	$	1.22
2013		1.19		1.44		1.38
Six Months Ended September 30,
2014	$	1.20	$	1.30	$	1.22
2013		1.08		1.44		1.38

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

Retail Propane

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markets. These margins fluctuate over time due to supply and demand conditions. Weather conditions have a significant impact on our sales volumes and prices, as a significant portion of our sales are to residential customers who purchase propane and distillates for home heating purposes.

Refined Products

Renewables

Recent Developments

Development of Crude Oil Rail Transloading Facility

Grand Mesa Pipeline, LLC

On September 5, 2014, we formed the Grand Mesa Pipeline, LLC ("Grand Mesa") joint venture in which we have a 50% ownership interest. Grand Mesa expects to build a crude oil pipeline with

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initial capacity exceeding 130,000 barrels per day, originating in Weld County, Colorado, and terminating at our crude oil storage terminal in Cushing, Oklahoma.

TransMontaigne Inc.

Water Solutions Facilities

During October and November 2014, we purchased five facilities under this development agreement and paid $52.2 million of cash for these facilities.

Water Supply Company

In June 2014, we acquired an interest in a water supply company that expands our water solutions business in the DJ Basin.

Summary Discussion of Operating Results for the Three Months Ended September 30, 2014

During the three months ended September 30, 2014, we generated operating income of $7.8 million, compared to operating income of $9.9 million during the three months endedSeptember 30, 2013.

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processed, which was due to increased demand for existing facilities and to the development and acquisition of new facilities.

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Consolidated Results of Operations

The following table summarizes our historical unaudited condensed consolidated statements of operations for the periods indicated:

	Three Months Ended September 30,						Six Months Ended September 30,

	2014			2013			2014			2013
	(in thousands)
Total revenues	$	5,380,526		$	1,593,937		$	9,029,140		$	2,979,894
Total cost of sales		5,179,465			1,488,850			8,713,518			2,791,926
Operating and general and administrative expenses		143,192			70,081			238,933			137,580
Depreciation and amortization		50,099			25,061			89,474			47,785


Operating income (loss)		7,770			9,945			(12,785	)		2,603
Earnings of unconsolidated entities		3,697			—			6,262			—
Interest expense		(28,651	)		(11,060	)		(49,145	)		(21,682	)
Other, net		(617	)		419			(1,008	)		469


Loss before income taxes		(17,801	)		(696	)		(56,676	)		(18,610	)
Income tax (provision) benefit		1,922			(236	)		887			170


Net loss		(15,879	)		(932	)		(55,789	)		(18,440	)
Less: Net income allocated to general partner		(11,056	)		(2,451	)		(20,437	)		(4,139	)
Less: Net income attributable to noncontrolling interests		(3,345	)		(9	)		(3,410	)		(134	)


Net loss attributable to parent equity	$	(30,280	)	$	(3,392	)	$	(79,636	)	$	(22,713	)

						��

Segment Operating Results for the Three Months Ended September 30, 2014 and 2013

Items Impacting the Comparability of Our Financial Results

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Volumes

	Three Months Ended September 30,

Segment	2014		2013		Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)		21,549		9,280		12,269
Water solutions
Water delivered (barrels)		30,869		16,459		14,410
Liquids
Propane sold (gallons)		240,234		183,415		56,819
Other products sold (gallons)		197,510		195,292		2,218
Retail propane
Propane sold (gallons)		23,551		20,599		2,952
Distillates sold (gallons)		3,434		3,072		362
Refined products and renewables
Refined products sold (gallons)		890,141		—		890,141
Renewable products sold (gallons)		51,557		—		51,557

Operating Income (Loss) by Segment

Our operating income (loss) by segment is as follows:

	Three Months Ended September 30,

Segment	2014			2013			Change
	(in thousands)
Crude oil logistics	$	38		$	5,884		$	(5,846	)
Water solutions		14,792			2,913			11,879
Liquids		10,929			14,605			(3,676	)
Retail propane		(3,062	)		(4,520	)		1,458
Refined products and renewables		8,822			—			8,822
Corporate and other		(23,749	)		(8,937	)		(14,812	)


Operating income	$	7,770		$	9,945		$	(2,175	)

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Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the periods indicated:

	Three Months Ended September 30,

	2014		2013		Change
	(in thousands)
Revenues:
Crude oil sales	$	2,108,117	$	1,013,061	$	1,095,056
Crude oil transportation and other		13,082		9,794		3,288


Total revenues(1)		2,121,199		1,022,855		1,098,344
Expenses:
Cost of sales		2,093,744		1,000,982		1,092,762
Operating expenses		12,432		11,760		672
General and administrative expenses		5,745		899		4,846
Depreciation and amortization expense		9,240		3,330		5,910


Total expenses		2,121,161		1,016,971		1,104,190


Segment operating income	$	38	$	5,884	$	(5,846	)

(1): Revenues include $10.1 million and $8.8 million of intersegment sales during the three months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

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Water Solutions

The following table summarizes the operating results of our water solutions segment for the periods indicated:

	Three Months Ended September 30,					Change

	2014			2013		Acquisitions(1)			Other
	(in thousands)
Revenues:
Water treatment and disposal	$	47,572		$	28,823	$	14,861		$	3,888
Water transportation		5,147			5,367		1,354			(1,574	)


Total revenues		52,719			34,190		16,215			2,314
Expenses:
Cost of sales		(9,439	)		3,782		1,152			(14,373	)
Operating expenses		29,019			15,003		13,947			69
General and administrative expenses		774			1,054		126			(406	)
Depreciation and amortization expense		17,573			11,438		5,708			427


Total expenses		37,927			31,277		20,933			(14,283	)


Segment operating income	$	14,792		$	2,913	$	(4,718	)	$	16,597

(1): Represents the change in revenues and expenses attributable to acquisitions subsequent to June 30, 2013. The cost of sales amount shown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities.

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Operating Income. Our water solutions segment generated operating income of $14.8 million during the three months ended September 30, 2014, compared to operating income of $2.9 million

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Liquids

The following table summarizes the operating results of our liquids segment for the periods indicated:

	Three Months Ended September 30,

	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	240,433	$	191,437	$	48,996
Other product sales		306,625		308,606		(1,981	)
Other revenues		6,814		9,250		(2,436	)


Total revenues(1)		553,872		509,293		44,579
Expenses:
Cost of sales—propane		230,729		184,565		46,164
Cost of sales—other products		293,262		292,142		1,120
Cost of sales—other		4,222		7,106		(2,884	)
Operating expenses		9,183		6,800		2,383
General and administrative expenses		2,163		1,403		760
Depreciation and amortization expense		3,384		2,672		712


Total expenses		542,943		494,688		48,255


Segment operating income	$	10,929	$	14,605	$	(3,676	)

(1): Revenues include $14.1 million and $24.4 million of intersegment sales during the three months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the periods indicated:

	Three Months Ended September 30,

	2014			2013			Change
	(in thousands)
Revenues:
Propane sales	$	48,552		$	40,651		$	7,901
Distillate sales		11,530			10,562			968
Other revenues		8,276			8,198			78


Total revenues		68,358			59,411			8,947
Expenses:
Cost of sales—propane		27,434			21,848			5,586
Cost of sales—distillates		9,840			9,265			575
Cost of sales—other		2,620			2,457			163
Operating expenses		21,205			20,997			208
General and administrative expenses		2,637			2,493			144
Depreciation and amortization expense		7,684			6,871			813


Total expenses		71,420			63,931			7,489


Segment operating loss	$	(3,062	)	$	(4,520	)	$	1,458

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Refined Products and Renewables


Revenues:
Refined products sales	$	2,489,795
Renewables sales(1)		117,425


Total revenues		2,607,220
Expenses:
Cost of sales—refined products		2,435,868
Cost of sales—renewables(1)		114,983
Operating expenses		29,838
General and administrative expenses		5,792
Depreciation and amortization expense		11,917


Total expenses		2,598,398


Segment operating income	$	8,822

(1): Revenues and cost of sales include $4.9 million and $2.0 million, respectively, associated with freely tradable Renewable Identification Numbers ("RINs") with no corresponding sales volume during the three months ended September 30, 2014.

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Cost of Sales. Our cost of refined products sales was $2.4 billion during the three months ended September 30, 2014, as we sold 890.1 million gallons at an average cost of $2.74 per gallon.

Operating Expenses. Our refined products and renewables segment incurred $29.8 million of operating expenses during the three months ended September 30, 2014.

Depreciation and Amortization Expense. Our refined products and renewables segment incurred $11.9 million of depreciation and amortization expense during the three months ended September 30, 2014.

Corporate and Other

The operating loss within "corporate and other" includes the following components:

	Three Months Ended September 30,

	2014			2013			Change
	(in thousands)
Equity-based compensation expense	$	(13,745	)	$	(3,217	)	$	(10,528	)
Acquisition expenses		(3,230	)		(785	)		(2,445	)
Other corporate expenses		(6,774	)		(4,935	)		(1,839	)


	$	(23,749	)	$	(8,937	)	$	(14,812	)

�� The increase in equity-based compensation expense is due primarily to $10.5 million of expense associated with restricted units granted in July 2014 to certain employees as a discretionary bonus that vested in September 2014.

Acquisition expenses during the three months ended September 30, 2014 related primarily to the acquisition of TransMontaigne.

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Segment Operating Results for the Six Months Ended September 30, 2014 and 2013

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of Crescent and Cierra Marine in July 2013, Gavilon Energy in December 2013 and TransMontaigne in July 2014. We expanded our water solutions business through several acquisitions of water disposal and transportation businesses, including Big Lake in July 2013, OWL in August 2013, Coastal in September 2013, and other water disposal facilities subsequent to September 30, 2013. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy and expanded with our July 2014 acquisition of TransMontaigne. The results of operations of our liquids and retail propane segments are impacted by seasonality, primarily due to the increase in volumes sold during the peak heating season from October through March. In addition, product price fluctuations can have a significant impact on our sales volumes and revenues. For these and other reasons, our results of operations for the six months ended September 30, 2014 are not necessarily indicative of the results to be expected for the full fiscal year.

Volumes

The following table summarizes the volume of product sold and water delivered during the six months ended September 30, 2014 and 2013. Volumes shown in the following table include intersegment sales.

	Six Months Ended September 30,

Segment	2014		2013		Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)		40,806		18,535		22,271
Water solutions
Water delivered (barrels)		51,804		26,498		25,306
Liquids
Propane sold (gallons)		423,992		310,834		113,158
Other products sold (gallons)		384,235		373,722		10,513
Retail propane
Propane sold (gallons)		47,142		43,992		3,150
Distillates sold (gallons)		8,712		8,176		536
Refined products and renewables
Refined products sold (gallons)		1,221,949		—		1,221,949
Renewable products sold (gallons)		104,591		—		104,591

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Operating Income (Loss) by Segment

Our operating income (loss) by segment is as follows:

	Six Months Ended September 30,

Segment	2014			2013			Change
	(in thousands)
Crude oil logistics	$	1,501		$	12,493		$	(10,992	)
Water solutions		13,885			5,956			7,929
Liquids		10,016			12,490			(2,474	)
Retail propane		(4,648	)		(6,024	)		1,376
Refined products and renewables		7,567			—			7,567
Corporate and other		(41,106	)		(22,312	)		(18,794	)


Operating income (loss)	$	(12,785	)	$	2,603		$	(15,388	)

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the periods indicated:

	Six Months Ended September 30,

	2014		2013		Change
	(in thousands)
Revenues:
Crude oil sales	$	4,035,061	$	1,941,595	$	2,093,466
Crude oil transportation and other		25,196		19,729		5,467


Total revenues(1)		4,060,257		1,961,324		2,098,933
Expenses:
Cost of sales		4,001,158		1,917,876		2,083,282
Operating expenses		28,417		21,175		7,242
General and administrative expenses		10,210		1,766		8,444
Depreciation and amortization expense		18,971		8,014		10,957


Total expenses		4,058,756		1,948,831		2,109,925


Segment operating income	$	1,501	$	12,493	$	(10,992	)

(1): Revenues include $19.8 million and $16.5 million of intersegment sales during the six months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

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Water Solutions

The following table summarizes the operating results of our water solutions segment for the periods indicated:

	Six Months Ended September 30,				Change

	2014		2013		Acquisitions(1)			Other
	(in thousands)
Revenues:
Water treatment and disposal	$	89,288	$	47,511	$	28,627		$	13,150
Water transportation		10,745		7,192		6,954			(3,401	)


Total revenues		100,033		54,703		35,581			9,749
Expenses:
Cost of sales		1,134		4,365		4,984			(8,215	)
Operating expenses		48,748		24,010		23,141			1,597
General and administrative expenses		1,601		1,578		199			(176	)
Depreciation and amortization expense		34,665		18,794		15,348			523


Total expenses		86,148		48,747		43,672			(6,271	)


Segment operating income	$	13,885	$	5,956	$	(8,091	)	$	16,020

(1): Represents the change in revenues and expenses attributable to acquisitions subsequent to March 31, 2013. The cost of sales amount shown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities.

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Liquids

The following table summarizes the operating results of our liquids segment for the periods indicated:

	Six Months Ended September 30,

	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	462,879	$	315,274	$	147,605
Other product sales		594,984		558,459		36,525
Other revenues		12,530		18,114		(5,584	)


Total revenues(1)		1,070,393		891,847		178,546
Expenses:
Cost of sales—propane		449,636		302,108		147,528
Cost of sales—other products		574,524		541,077		33,447
Cost of sales—other		7,403		12,474		(5,071	)
Operating expenses		18,248		15,532		2,716
General and administrative expenses		3,981		2,790		1,191
Depreciation and amortization expense		6,585		5,376		1,209


Total expenses		1,060,377		879,357		181,020


Segment operating income	$	10,016	$	12,490	$	(2,474	)

(1): Revenues include $55.5 million and $46.0 million of intersegment sales during the six months ended September 30, 2014 and 2013, respectively, that are eliminated in our condensed consolidated statements of operations.

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segregated based on the location of the inventory. During periods of declining prices, our margins are reduced, as the weighted-average costing pool includes inventory that was purchased when prices were higher.

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Retail Propane

The following table summarizes the operating results of our retail propane segment for the periods indicated:

	Six Months Ended September 30,

	2014			2013			Change
	(in thousands)
Revenues:
Propane sales	$	100,578		$	87,342		$	13,236
Distillate sales		30,225			28,431			1,794
Other revenues		15,457			15,898			(441	)


Total revenues		146,260			131,671			14,589
Expenses:
Cost of sales—propane		56,721			47,027			9,694
Cost of sales—distillates		25,876			24,509			1,367
Cost of sales—other		4,821			5,100			(279	)
Operating expenses		42,687			41,839			848
General and administrative expenses		5,548			5,109			439
Depreciation and amortization expense		15,255			14,111			1,144


Total expenses		150,908			137,695			13,213


Segment operating loss	$	(4,648	)	$	(6,024	)	$	1,376

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Refined Products and Renewables


Revenues:
Refined products sales	$	3,476,018
Renewables sales(1)		248,699


Total revenues		3,724,717
Expenses:
Cost of sales—refined products		3,418,880
Cost of sales—renewables(1)		246,284
Operating expenses		31,462
General and administrative expenses		7,763
Depreciation and amortization expense		12,761


Total expenses		3,717,150


Segment operating income	$	7,567

(1): Revenues and cost of sales include $6.7 million and $4.4 million, respectively, associated with freely tradable RINs with no corresponding sales volume during the six months ended September 30, 2014.

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Cost of Sales. Our cost of refined products sales was $3.4 billion during the six months ended September 30, 2014, as we sold 1.2 billion gallons at an average cost of $2.80 per gallon.

Operating Expenses. Our refined products and renewables segment incurred $31.5 million of operating expenses during the six months ended September 30, 2014.

Depreciation and Amortization Expense. Our refined products and renewables segment incurred $12.8 million of depreciation and amortization expense during the six months ended September 30, 2014.

Corporate and Other

The operating loss within "corporate and other" includes the following components:

	Six Months Ended September 30,

	2014			2013			Change
	(in thousands)
Equity-based compensation expense	$	(21,659	)	$	(10,292	)	$	(11,367	)
Acquisition expenses		(4,328	)		(1,368	)		(2,960	)
Other corporate expenses		(15,119	)		(10,652	)		(4,467	)


	$	(41,106	)	$	(22,312	)	$	(18,794	)

Acquisition expenses during the six months ended September 30, 2014 related primarily to the acquisition of TransMontaigne.

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Interest Expense

	Revolving Credit Facility					2019 Notes					2021 Notes					2022 Notes					TLP Credit Facility

	Average Balance Outstanding (in thousands)		Average Interest Rate			Average Balance Outstanding (in thousands)		Interest Rate			Average Balance Outstanding (in thousands)		Interest Rate			Average Balance Outstanding (in thousands)		Interest Rate			Average Balance Outstanding (in thousands)		Average Interest Rate
Three Months Ended September 30,
2014	$	1,026,011		2.48	%	$	360,870		5.13	%	$	450,000		6.88	%	$	250,000		6.65	%	$	246,750		2.70	%
2013		572,353		3.63	%		—		—			—		—			250,000		6.65	%		—		—
Six Months Ended September 30,
2014	$	987,224		2.38	%	$	181,424		5.13	%	$	450,000		6.88	%	$	250,000		6.65	%	$	246,750		2.70	%
2013		521,202		3.65	%		—		—			—		—			250,000		6.65	%		—		—

The increased level of debt outstanding during the three months and six months ended September 30, 2014 is due primarily to borrowings to finance acquisitions.

Income Tax Provision

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Noncontrolling Interests

Seasonality

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Consolidated Results of Operations—Year ended March 31, 2014

The following table summarizes our historical consolidated statements of operations for the years ended March 31, 2014, 2013, and 2012:

	Year Ended March 31,

	2014			2013			2012
	(in thousands)
Total revenues	$	9,699,274		$	4,417,767		$	1,310,473
Total cost of sales		9,132,699			4,039,110			1,217,023
Operating and general and administrative expenses		339,256			222,497			63,309
Depreciation and amortization		120,754			68,853			15,111


Operating income		106,565			87,307			15,030
Earnings of unconsolidated entities		1,898			—			—
Interest expense		(58,854	)		(32,994	)		(7,620	)
Loss on early extinguishment of debt		—			(5,769	)		—
Other, net		86			1,521			1,055


Income before income taxes		49,695			50,065			8,465
Income tax provision		(937	)		(1,875	)		(601	)


Net income		48,758			48,190			7,864
Net (income) loss attributable to noncontrolling interests		(1,103	)		(250	)		12


Net income attributable to parent equity	$	47,655		$	47,940		$	7,876

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

Interest Expense

	Revolving Credit Facilities					Senior Notes					Unsecured Notes

Year Ended:	Average Balance Outstanding (in thousands)		Average Interest Rate			Average Balance Outstanding (in thousands)		Interest Rate			Average Balance Outstanding (in thousands)		Interest Rate
March 31, 2014	$	588,375		3.04	%	$	250,000		6.65	%	$	205,890		6.88	%
March 31, 2013		405,114		3.56	%		195,890	��	6.65	%		—		—
March 31, 2012		125,859		4.48	%		—		—			—		—

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that had not yet been amortized. This expense is reported as "Loss on early extinguishment of debt" in our consolidated statement of operations for the year ended March 31, 2013.

The increased levels of debt outstanding during the periods from fiscal 2012 through fiscal 2014 are due primarily to borrowings to finance acquisitions.

Income Tax Provision

Noncontrolling Interests

Segment Operating Results

Items Impacting the Comparability of Our Financial Results

Our current and future results of operations may not be comparable to our historical results of operations for the periods presented, due to business combinations. We expanded our crude oil logistics business through a number of acquisitions, including our acquisitions of High Sierra in June 2012, Pecos in November 2012, Third Coast in December 2012, Crescent in July 2013, and Gavilon Energy in December 2013. We expanded our water solutions business through several acquisitions of water disposal and transportation businesses, including High Sierra in June 2012, Big Lake in July 2013, OWL in August 2013, and Coastal in September 2013. We expanded our liquids business through the acquisitions of SemStream in October 2011 and High Sierra in June 2012. We expanded our retail propane operations through the acquisitions of Osterman in October 2011, Pacer in January 2012, North American in February 2012, and Downeast in May 2012. Our refined products and renewables businesses began with our December 2013 acquisition of Gavilon Energy.

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Volumes

	Year Ended March 31,

Segment	2014		2013		Change
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)		46,107		24,373		21,734
Water solutions
Water delivered (barrels)		62,774		25,009		37,765
Liquids
Propane sold (gallons)		1,190,106		912,625		277,481
Other products sold (gallons)		786,671		505,529		281,142
Retail propane
Propane sold (gallons)		162,361		144,379		17,982
Distillates sold (gallons)		34,965		28,853		6,112
Refined products
Refined products sold (gallons)		412,974		—		412,974
Renewables
Renewables sold (gallons)		150,925		—		150,925

Our refined products and renewables segments began with the December 2013 acquisition of Gavilon Energy.

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Operating Income (Loss) by Segment

Our operating income (loss) by segment for the years ended March 31, 2014 and 2013 was as follows:

	Year Ended March 31,

Segment	2014			2013			Change
	(in thousands)
Crude oil logistics	$	678		$	34,236		$	(33,558	)
Water solutions		10,317			8,576			1,741
Liquids		71,888			30,336			41,552
Retail propane		61,285			46,869			14,416
Refined products		4,080			—			4,080
Renewables		2,434			—			2,434
Corporate and other		(44,117	)		(32,710	)		(11,407	)


Operating income	$	106,565		$	87,307		$	19,258

Crude Oil Logistics

The following table summarizes the operating results of our crude oil logistics segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,

	2014		2013		Change
	(in thousands)
Revenues:
Crude oil sales	$	4,559,923	$	2,322,706	$	2,237,217
Crude oil transportation and other		36,469		16,442		20,027


Total revenues(1)		4,596,392		2,339,148		2,257,244
Expenses:
Cost of sales		4,515,244		2,267,507		2,247,737
Operating expenses		53,872		25,484		28,388
General and administrative expenses		4,487		2,745		1,742
Depreciation and amortization expense		22,111		9,176		12,935


Total expenses		4,595,714		2,304,912		2,290,802


Segment operating income	$	678	$	34,236	$	(33,558	)

(1): Revenues include $37.8 million of intersegment sales during the year ended March 31, 2014 and $22.9 million of intersegment sales during the year ended March 31, 2013 that are eliminated in our consolidated statements of operations.

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Energy, Pecos, and Third Coast, among others. Of this increase, $1.0 billion was attributable to Gavilon Energy.

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Water Solutions

The following table summarizes the operating results of our water solutions segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,				Change

	2014		2013		Acquisitions(1)		Other
	(in thousands)
Revenues:
Water treatment and disposal	$	125,788	$	54,334	$	64,119	$	7,335
Water transportation		17,312		7,893		14,231		(4,812	)


Total revenues		143,100		62,227		78,350		2,523
Expenses:
Cost of sales		11,738		5,611		9,325		(3,198	)
Operating expenses		58,178		25,452		35,377		(2,651	)
General and administrative expenses		7,762		1,665		1,239		4,858
Depreciation and amortization expense		55,105		20,923		26,955		7,227


Total expenses		132,783		53,651		72,896		6,236


Segment operating income	$	10,317	$	8,576	$	5,454	$	(3,713	)

(1): Represents the change in revenues and expenses attributable to acquisitions subsequent to the merger with High Sierra. The cost of sales amount shown in this column does not include derivative gains and losses, as these cannot be attributed to specific facilities.

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Liquids

The following table summarizes the operating results of our liquids segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,

	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	1,632,948	$	841,448	$	791,500
Other product sales		1,231,965		858,276		373,689
Other revenues		31,062		33,954		(2,892	)


Total revenues(1)		2,895,975		1,733,678		1,162,297
Expenses:
Cost of sales—propane		1,559,266		801,694		757,572
Cost of sales—other products		1,179,944		836,747		343,197
Cost of sales—other		24,439		20,950		3,489
Operating expenses		42,977		27,605		15,372
General and administrative expenses		6,443		5,261		1,182
Depreciation and amortization expense		11,018		11,085		(67	)


Total expenses		2,824,087		1,703,342		1,120,745


Segment operating income	$	71,888	$	30,336	$	41,552

(1): Revenues include $245.6 million of intersegment sales during the year ended March 31, 2014 and $128.9 million of intersegment sales during the year ended March 31, 2013 that are eliminated in our consolidated statements of operations.

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unrealized losses on derivatives. During the year ended March 31, 2013, our cost of wholesale propane sales was $801.7 million, as we sold 912.6 million gallons at an average cost of $0.88 per gallon. Our cost of wholesale propane sales during the year ended March 31, 2013 was reduced by $3.2 million of unrealized gains on derivatives.

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During the year ended March 31, 2013, operating income was reduced by $4.3 million of unrealized losses on derivatives.

Retail Propane

The following table summarizes the operating results of our retail propane segment for the years ended March 31, 2014 and 2013:

	Year Ended March 31,

	2014		2013		Change
	(in thousands)
Revenues:
Propane sales	$	388,225	$	288,410	$	99,815
Distillate sales		127,672		106,192		21,480
Other revenues		35,918		35,856		62


Total revenues		551,815		430,458		121,357
Expenses:
Cost of sales—propane		233,110		155,118		77,992
Cost of sales—distillates		109,058		90,772		18,286
Cost of sales—other		11,531		12,688		(1,157	)
Operating expenses		96,936		88,651		8,285
General and administrative expenses		11,017		10,864		153
Depreciation and amortization expense		28,878		25,496		3,382


Total expenses		490,530		383,589		106,941


Segment operating income	$	61,285	$	46,869	$	14,416

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Refined Products


Revenues	$	1,180,895
Expenses:
Cost of sales		1,172,754
Operating expenses		3,887
General and administrative expenses		65
Depreciation and amortization expense		109


Total expenses		1,176,815


Segment operating income	$	4,080

Revenues. Our refined products segment generated $1.2 billion of revenue during the year ended March 31, 2014, selling 413.0 million gallons at an average price of $2.86 per gallon.

Cost of Sales. Our cost of sales was $1.2 billion during the year ended March 31, 2014, as we sold 413.0 million gallons at an average cost of $2.84 per gallon.

Operating Expenses. Our refined products segment incurred $3.9 million of operating expenses during the year ended March 31, 2014.

General and Administrative Expenses. Our refined products segment incurred $0.1 million of general and administrative expenses during the year ended March 31, 2014.

Depreciation and Amortization Expense. Our refined products segment incurred $0.1 million of depreciation and amortization expense during the year ended March 31, 2014.

Operating Income. Our refined products segment generated $4.1 million of operating income during the year ended March 31, 2014.

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Renewables


Revenues	$	176,781
Expenses:
Cost of sales		171,422
Operating expenses		2,318
General and administrative expenses		91
Depreciation and amortization expense		516


Total expenses		174,347


Segment operating income	$	2,434

Revenues. Our renewables segment generated $176.8 million of revenue during the year ended March 31, 2014, selling 150.9 million gallons at an average price of $1.17 per gallon.

Cost of Sales. Our cost of sales was $171.4 million during the year ended March 31, 2014, as we sold 150.9 million gallons at an average cost of $1.14 pergallon.

Operating Expenses. Our renewables segment incurred $2.3 million of operating expenses during the year ended March 31, 2014.

General and Administrative Expenses. Our renewables segment incurred $0.1 million of general and administrative expenses during the year ended March 31, 2014.

Depreciation and Amortization Expense. Our renewables segment incurred $0.5 million of depreciation and amortization expense during the year ended March 31, 2014.

Operating Income. Our renewables segment generated $2.4 million of operating income during the year ended March 31, 2014.

Corporate and Other

The operating loss within "corporate and other" includes the following components:

	Year Ended March 31,

	2014			2013			Change
	(in thousands)
Compressor leasing business	$	2,336		$	(1	)	$	2,337
Natural gas business		1,363			—			1,363
Equity-based compensation expense		(17,804	)		(10,138	)		(7,666	)
Acquisition expenses		(6,908	)		(5,602	)		(1,306	)
Other corporate expenses		(23,104	)		(16,969	)		(6,135	)


	$	(44,117	)	$	(32,710	)	$	(11,407	)

Operating income of our compressor leasing business for the year ended March 31, 2014 includes a $4.4 million gain from the sale of the business in February 2014.

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Year Ended March 31, 2013
Compared to Year Ended March 31, 2012

Volumes Sold or Delivered

	Year Ended March 31,				Change Resulting From

	Year Ended March 31,				Retail Combinations(1)		SemStream Combination			High Sierra Combinations(2)
Segment	2013		2012		Retail Combinations(1)		SemStream Combination			High Sierra Combinations(2)		Other
	(in thousands)
Crude oil logistics
Crude oil sold (barrels)		24,373		—		—		—			24,373		—
Water solutions
Water delivered (barrels)		25,009		—		—		—			25,009		—
Liquids
Propane sold (gallons)		912,625		659,921		—			(3)		140,632		112,072
Other products sold (gallons)		505,529		134,999		—			(3)		320,283		50,247
Retail propane
Propane sold (gallons)		144,379		78,236		54,949		—			—		11,194
Distillates sold (gallons)		28,853		1,650		27,027		—			—		176

(1): This data includes the operations of Osterman (acquired in October 2011) from April 1, 2012 through September 30, 2012, Pacer (acquired in January 2012) from April 1, 2012 through December 31, 2012, North American (acquired in February 2012) from April 1, 2012 through January 31, 2013, Downeast (acquired in May 2012), and certain other smaller retail propane business acquired during fiscal 2013.

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(2): This data includes the operations of High Sierra (acquired in June 2012), Pecos (acquired in November 2012), and other subsequent acquisitions of smaller crude oil and water solutions businesses.
(3): Although the SemStream combination enabled us to significantly expand our wholesale operations, it is not possible to determine which of the volumes sold subsequent to the combination were specifically attributable to the SemStream combination and which were attributable to our historical wholesale business.

Operating Income by Segment

Our operating income by segment is as follows:

	Year Ended March 31,

Segment	2013			2012			Change
	(in thousands)
Crude oil logistics	$	34,236		$	—		$	34,236
Water solutions		8,576			—			8,576
Liquids		30,336			9,735			20,601
Retail propane		46,869			9,616			37,253
Corporate and other		(32,710	)		(4,321	)		(28,389	)


Operating income	$	87,307		$	15,030		$	72,277

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Crude Oil Logistics


Revenues:
Crude oil sales	$	2,322,706
Crude oil transportation and other		16,442


Total revenues(1)		2,339,148
Expenses:
Cost of sales		2,267,507
Operating expenses		25,484
General and administrative expenses		2,745
Depreciation and amortization expense		9,176


Total expenses		2,304,912


Segment operating income	$	34,236

(1): Revenues include $22.9 million of intersegment sales that are eliminated in our consolidated statement of operations.

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Water Solutions


Revenues:
Water treatment and disposal	$	54,334
Water transportation		7,893


Total revenues		62,227
Expenses:
Cost of sales		5,611
Operating expenses		25,452
General and administrative expenses		1,665
Depreciation and amortization expense		20,923


Total expenses		53,651


Segment operating income	$	8,576

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Liquids

The following table compares the operating results of our liquids segment for the years ended March 31, 2013 and 2012:

					Change Resulting From

	Year Ended March 31,
	Year Ended March 31,				High Sierra Combination
	2013		2012		High Sierra Combination		Other
	(in thousands)
Revenues:
Propane sales	$	841,448	$	923,022	$	115,606	$	(197,180	)
Other product sales		858,276		251,627		563,211		43,438
Other revenues		33,954		2,462		19,053		12,439


Total revenues(1)		1,733,678		1,177,111		697,870		(141,303	)
Expenses:
Cost of sales—propane		801,694		904,082		109,851		(212,239	)
Cost of sales—other products		836,747		246,995		546,588		43,164
Costs of sales—other		20,950		1,776		8,637		10,537
Operating expenses		27,605		8,124		15,097		4,384
General and administrative expenses		5,261		2,738		1,693		830
Depreciation and amortization expense		11,085		3,661		3,101		4,323


Total expenses		1,703,342		1,167,376		684,967		(149,001	)


Segment operating income	$	30,336	$	9,735	$	12,903	$	7,698

(1): Revenues include $128.9 million of intersegment sales during the year ended March 31, 2013 and $66.0 million of intersegment sales during the year ended March 31, 2012 that are eliminated in our consolidated statements of operations.

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Transportation and other revenues for the year ended March 31, 2013 relate primarily to fees charged for transporting customer-owned product by railcar.

Other cost of sales for the year ended March 31, 2013 relate primarily to the cost of leasing railcars used in the transportation of customer-owned product.

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March 31, 2013, our liquids segment incurred $1.7 million of general and administrative expenses related to the operations of High Sierra.

Retail Propane

The following table compares the operating results of our retail propane segment for the years ended March 31, 2013 and 2012:

					Change Resulting From

	Year Ended March 31,				Change Resulting From
	Year Ended March 31,				Retail Combinations(1)
	2013		2012		Retail Combinations(1)		Other
	(in thousands)
Revenues:
Propane sales	$	288,410	$	175,417	$	117,686	$	(4,693	)
Distillate sales		106,192		6,547		99,410		235
Other sales		35,856		17,370		20,752		(2,266	)


Total revenues		430,458		199,334		237,848		(6,724	)
Expenses:
Cost of sales—propane		155,118		117,722		63,080		(25,684	)
Cost of sales—distillates		90,772		5,728		84,933		111
Cost of sales—other		12,688		6,692		6,516		(520	)
Operating expenses		88,651		39,176		47,454		2,021
General and administrative expenses		10,864		8,950		5,409		(3,495	)
Depreciation and amortization expense		25,496		11,450		13,059		987


Total expenses		383,589		189,718		220,451		(26,580	)


Segment operating income	$	46,869	$	9,616	$	17,397	$	19,856

(1): This data includes the operations of Osterman (acquired in October 2011) from April 1, 2012 through September 30, 2012, Pacer (acquired in January 2012) from April 1, 2012 through December 31, 2012, North American (acquired in February 2012) from April 1, 2012 through January 31, 2013, Downeast (acquired in May 2012), and certain other smaller retail propane business acquired during fiscal 2013.

Revenues. Propane sales for the year ended March 31, 2013 increased $113.0 million as compared to propane sales of $175.4 million during the year ended March 31, 2012. The principal reason for the

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increase in propane sales was the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane sales were lower during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to a decline in the average price per gallon sold of $0.33 during the year ended March 31, 2013, as compared to an average price per gallon sold of $2.24 during the year ended March 31, 2012. Excluding the effect of these acquisitions, volumes sold during the year ended March 31, 2013 were higher than volumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder than that of fiscal 2012. The winter of fiscal 2012 was one of the warmest on record, and these warm weather conditions resulted in a decrease in the demand for propane.

We generated $106.2 million of revenue from the sales of distillates during the year ended March 31, 2013, consisting of 28.9 million gallons sold at an average selling price of $3.68 per gallon.

Cost of Sales. Propane cost of sales for the year ended March 31, 2013 increased $37.4 million as compared to propane cost of sales of $117.7 million during the year ended March 31, 2012. This increase in propane cost of sales is due primarily to the acquisitions of Osterman, Pacer, North American, and Downeast. Excluding the impact of these acquisitions, propane cost of sales was lower during the year ended March 31, 2013 than during the year ended March 31, 2012, due primarily to a decline in the average cost per gallon sold of $0.47 during the year ended March 31, 2013, as compared to an average price per gallon sold of $1.50 during the year ended March 31, 2012. Excluding the effect of these acquisitions, volumes sold during the year ended March 31, 2013 were higher than volumes sold during the year ended March 31, 2012, due primarily to the fact that the fiscal 2013 winter was colder than that of fiscal 2012.

We had $90.8 million of cost of sales for distillates during the year ended March 31, 2013, consisting of 28.9 million gallons sold at an average cost of $3.15 per gallon.

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Seasonality

Seasonality impacts our liquids and retail propane segments. A large portion of our retail propane operation is in the residential market where propane is used primarily for heating. During the year ended March 31, 2014, 74% of our retail propane volume was sold during the peak heating season from October through March. Consequently, for these two segments, sales, operating profits and operating cash flows are generated mostly in the third and fourth quarters of each fiscal year. See "—Liquidity, Sources of Capital and Capital Resource Activities—Cash Flows."

Liquidity, Sources of Capital and Capital Resource Activities

Our principal sources of liquidity and capital are the cash flows from our operations and borrowings under our Revolving Credit Facility. Our cash flows from operations are discussed below.

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Credit Agreement

	Amount

Expansion Capital Facility—
LIBOR borrowings	$	137,000	1.91	%
Working Capital Facility—
LIBOR borrowings		942,500	1.91	%

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certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) a breach by the Partnership or its subsidiaries of any material representation or warranty or any covenant made in the Credit Agreement, or (iii) certain events of bankruptcy or insolvency.

At September 30, 2014, we were in compliance with the covenants under the Credit Agreement.

2019 Notes

At September 30, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2019 Notes.

2021 Notes

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various customary representations, warranties, and additional covenants, including, without limitation, limitations on fundamental changes and limitations on indebtedness and liens. Our obligations under the purchase agreement and the indenture may be accelerated following certain events of default (subject to applicable cure periods), including, without limitation, (i) the failure to pay principal or interest when due, (ii) experiencing an event of default on certain other debt agreements, or (iii) certain events of bankruptcy or insolvency.

At September 30, 2014, we were in compliance with the covenants under the purchase agreement and indenture governing the 2021 Notes.

2022 Notes

At September 30, 2014, we were in compliance with the covenants under the Note Purchase Agreement.

TLP Credit Facility

On March 9, 2011, TLP entered into an amended and restated senior secured credit facility ("TLP Credit Facility"), which has been subsequently amended from time to time. The TLP Credit Facility

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provides for a maximum borrowing line of credit equal to the lesser of (i) $350 million and (ii) 4.75 times Consolidated EBITDA (as defined in the TLP Credit Facility: $352.9 million at September 30, 2014). TLP may elect to have loans under the TLP Credit Facility that bear interest either (i) at a rate of LIBOR plus a margin ranging from 2% to 3% depending on the total leverage ratio then in effect, or (ii) at the base rate plus a margin ranging from 1% to 2% depending on the total leverage ratio then in effect. TLP also pays a commitment fee on the unused amount of commitments, ranging from 0.375% to 0.50% per annum, depending on the total leverage ratio then in effect. TLP's obligations under the TLP Credit Facility are secured by a first priority security interest in favor of the lenders in the majority of TLP assets.

At September 30, 2014, TLP had $252.0 million of outstanding borrowings under the TLP Credit Facility and no outstanding letters of credit.

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Cash and cash equivalents	$	726
Accounts receivable—trade, net		12,252
Accounts receivable—affiliates		1,105
Inventories		1,613
Prepaid expenses and other current assets		1,363
Property, plant and equipment, net		504,272
Goodwill		29,118
Intangible assets, net		38,571
Investments in unconsolidated entities		268,410
Other noncurrent assets		1,910
Accounts payable—trade		(4,009	)
Accounts payable—affiliates		(146	)
Accrued expenses and other payables		(11,625	)
Advance payments received from customers		(141	)
Long-term debt		(252,000	)
Other noncurrent liabilities		(4,247	)


Net assets	$	587,172

Revolving Credit Balances

The following table summarizes Revolving Credit Facility borrowings:

	Average Daily Balance		Lowest Balance		Highest Balance

	(in thousands)
Six Months Ended September 30, 2014:
Expansion borrowings	$	346,855	$	114,000	$	578,500
Working capital borrowings		640,369		339,500		1,024,500
TLP credit facility		246,750		228,000		258,500
Six Months Ended September 30, 2013:
Expansion borrowings	$	440,423	$	255,000	$	546,000
Working capital borrowings		80,779		—		229,500

Business Combinations

Subsequent to our IPO, we significantly expanded our operations through a number of business combinations, as described under "Business—Acquisitions Subsequent to Initial Public Offering."

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Cash Flows

The following summarizes the sources (uses) of our cash flows:

	Six Months Ended September 30,

Cash Flows Provided by (Used in):	2014			2013
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	19,091		$	60,976
Changes in operating assets and liabilities		(80,726	)		(109,720	)


Operating activities	$	(61,635	)	$	(48,744	)
Investing activities		(750,288	)		(476,854	)
Financing activities		813,306			519,565

	Year Ended March 31,

Cash Flows Provided by (Used in):	2014			2013			2012
	(in thousands)
Operating activities, before changes in operating assets and liabilities	$	243,303		$	146,395		$	20,459
Changes in operating assets and liabilities		(158,067	)		(13,761	)		69,870


Operating activities	$	85,236		$	132,634		$	90,329
Investing activities		(1,455,373	)		(546,621	)		(296,897	)
Financing activities		1,369,016			417,716			198,063

Operating Activities. �� The seasonality of our natural gas liquids businesses has a significant effect on our cash flows from operating activities. The changes in our operating assets and liabilities caused by the seasonality of our retail and wholesale natural gas liquids businesses also have a significant impact on our net cash flows from operating activities. Increases in natural gas liquids prices will tend to result in reduced operating cash flows due to the need to use more cash to fund increases in inventories, and price decreases tend to increase our operating cash flow due to lower cash requirements to fund increases in inventories.

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Financing Activities. Changes in our cash flow from financing activities include advances from and repayments on our revolving credit facilities, either to fund our operating or investing requirements. In periods where our cash flows from operating activities are reduced (such as during our first and second quarters), we may fund the cash flow deficits through our Working Capital Facility. During the six months ended September 30, 2014, we borrowed $175.5 million on our revolving credit facilities (net of repayments). During the six months ended September 30, 2014, we issued the 2019 Notes for $400.0 million. During the six months ended September 30, 2014, we received net proceeds of $370.4 million from the sale of our common units. During the six months ended September 30, 2013, we borrowed $168.5 million on our Revolving Credit Facility (net of repayments). During the six months ended September 30, 2013, we received net proceeds of $415.1 million from the sale of our common units. During the year ended March 31, 2014, we borrowed $444.5 million on our Revolving Credit Facility (net of repayments) and issued $450.0 million of Unsecured Notes. During the year ended March 31, 2014, we paid $24.6 million of debt issuance costs. During the year ended March 31, 2013, we borrowed $263.5 million on our revolving credit facilities (net of repayments) and issued $250.0 million of Senior Notes. During the year ended March 31, 2013, we paid $20.2 million of debt issuance costs. During the year ended March 31, 2012, we borrowed $149.0 million on our revolving credit facilities (net of repayments), primarily to fund acquisitions.

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The following table summarizes the distributions declared since our IPO:

Date Declared	Record Date	Date Paid	Amount Per Unit		Amount Paid To Limited Partners		Amount Paid To General Partner

					(in thousands)		(in thousands)
July 25, 2011	August 3, 2011	August 12, 2011	$	0.1669	$	2,467	$	3
October 21, 2011	October 31, 2011	November 14, 2011		0.3375		4,990		5
January 24, 2012	February 3, 2012	February 14, 2012		0.3500		7,735		10
April 18, 2012	April 30, 2012	May 15, 2012		0.3625		9,165		10
July 24, 2012	August 3, 2012	August 14, 2012		0.4125		13,574		134
October 17, 2012	October 29, 2012	November 14, 2012		0.4500		22,846		707
January 24, 2013	February 4, 2013	February 14, 2013		0.4625		24,245		927
April 25, 2013	May 6, 2013	May 15, 2013		0.4775		25,605		1,189
July 25, 2013	August 5, 2013	August 14, 2013		0.4938		31,725		1,739
October 23, 2013	November 4, 2013	November 14, 2013		0.5113		35,908		2,491
January 23, 2014	February 4, 2014	February 14, 2014		0.5313		42,150		4,283
April 24, 2014	May 5, 2014	May 15, 2014		0.5513	��	43,737		5,754
July 24, 2014	August 4, 2014	August 14, 2014		0.5888		52,036		9,481
October 23, 2014	November 4, 2014	November 14, 2014		0.6088		53,902		11,141

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Contractual Obligations

The following table summarizes our contractual obligations at September 30, 2014 for our fiscal years ending thereafter:

			Six Months Ending March 31, 2015		Years Ending March 31,

	Total		Six Months Ending March 31, 2015		2016		2017		2018		Thereafter
	(in thousands)
Principal payments on long-term debt—
Expansion capital borrowings	$	137,000	$	—	$	—	$	—	$	—	$	137,000
Working capital borrowings		942,500		—		—		—		—		942,500
2019 Notes		400,000		—		—		—		—		400,000
2021 Notes		450,000		—		—		—		—		450,000
2022 Notes		250,000		—		—		—		25,000		225,000
TLP Credit Facility		252,000		—		252,000		—		—		—
Other long-term debt		10,913		2,345		3,128		2,362		1,459		1,619
Interest payments on long-term debt—
Revolving credit facility(1)		115,595		14,097		28,194		28,194		28,194		16,916
2019 Notes		102,500		10,250		20,500		20,500		20,500		30,750
2021 Notes		232,031		15,469		30,938		30,938		30,938		123,748
2022 Notes		91,438		8,313		16,625		16,625		16,209		33,666
TLP Credit Facility(1)		5,868		3,352		2,516		—		—		—
Other long-term debt		655		220		206		123		78		28
Letters of credit		209,188		—		—		—		—		209,188
Future minimum lease payments under noncancelable operating leases		507,354		71,007		106,384		88,666		74,265		167,032
Future minimum throughput payments under noncancelable agreements(2)		441,168		41,822		95,050		82,916		62,565		158,815
Fixed-price commodity purchase commitments		102,000		101,344		656		—		—		—
Index-price commodity purchase commitments(3)		984,872		950,613		34,259		—		—		—


Total contractual obligations	$	5,235,082	$	1,218,832	$	590,456	$	270,324	$	259,208	$	2,896,262




Natural gas liquids gallons under fixed-price purchase commitments (thousands)(4)		88,574		87,944		630		—		—		—
Natural gas liquids gallons under index-price purchase commitments (thousands)(4)		528,459		520,243		8,216		—		—		—
Crude oil barrels under index-price purchase commitments (thousands)(4)		4,437		4,079		358		—		—		—

(1): The estimated interest payments on our revolving credit facilities are based on principal and letters of credit outstanding at September 30, 2014. See Note 7 to our condensed consolidated financial statements included in this Quarterly Report for additional information on our revolving credit facilities.
(2): At September 30, 2014, we had agreements with crude oil and refined products pipeline operators obligating us to minimum throughput payments in exchange for pipeline capacity commitments.
(3): Index prices are based on a forward price curve at September 30, 2014. A theoretical change of $0.10 per gallon in the underlying commodity price at September 30, 2014 would result in a change of $52.8 million in the value of our index-price natural gas liquids purchase commitments. A theoretical change of $1.00 per barrel in the underlying commodity price at September 30, 2014 would result in a change of $4.4 million in the value of our index-price crude oil purchase commitments.

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(4): At September 30, 2014, we had fixed-price and index-price sales contracts for 278.4 million and 370.6 million gallons of natural gas liquids, respectively. At September 30, 2014, we had index-price sales contracts for 3.9 million barrels of crude oil.

Off-Balance Sheet Arrangements

Environmental Legislation

Trends

Crude Oil Logistics

Water Solutions

Our opportunity to earn revenues in our water solutions business is based on the level of production of natural gas and crude oil in the areas where our facilities are located. Currently, production levels are increasing, and we are expanding our operations in Colorado and Texas to meet this demand.

During the year ended March 31, 2014, we completed three separate acquisitions of water solutions businesses with operations in Texas. As a result, the geographic mix of our water solutions

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segment has changed, and we expect a greater share of the revenues from this segment to be generated from our operations in the Permian and Eagle Ford Basins in Texas than in the past.

Liquids

Retail Propane

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had a favorable impact on product margins, based on the fact that we purchased inventory when prices, and therefore our average cost of inventory, were lower than when we sold the inventory. The sharp rise in prices may increase the collectability risk of accounts receivable, and the recent high prices may create downward pressure on future demand, as some customers may invest in making their homes more energy efficient or may take other steps to reduce their need for propane.

Refined Products and Renewables

Recent Accounting Pronouncement

Critical Accounting Policies

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Revenue Recognition

Impairment of Long-Lived Assets

Asset Retirement Obligations

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

Amortization of Intangible Assets

Business Combinations

We have made in the past, and expect to make in the future, acquisitions of other businesses. We record business combinations using the "acquisition method," in which the assets acquired and liabilities assumed are recorded at their estimated fair values. Fair values of assets acquired and liabilities assumed are based upon available information and may involve us engaging an independent third party to perform an appraisal. Estimating fair values can be complex and subject to significant business judgment. We must also identify and include in the allocation all acquired tangible and intangible assets that meet certain criteria, including assets that were not previously recorded by the acquired entity. The estimates most commonly involve property, plant and equipment and intangible assets, including those with indefinite lives. The estimates also include the fair value of contracts including commodity purchase and sale agreements, storage and transportation contracts, and employee compensation commitments. The excess of the purchase price over the net fair value of acquired assets over the assumed liabilities is recorded as goodwill, which is not amortized but is reviewed annually for impairment. Generally, we have up to one year from the acquisition date to finalize the identification and valuation of assets acquired and liabilities assumed. The impact of subsequent changes to the identification of assets and liabilities may require retrospective adjustments to our previously-reported consolidated financial position and results of operations.

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Inventory

Equity-Based Compensation

Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. These units vest in tranches, subject to the continued service of the recipients.

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

Amortization of Intangible Assets

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

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Business Combinations

Inventories

Equity-Based Compensation

Our general partner has granted certain restricted units to employees and directors under a long-term incentive plan. These units vest in tranches, subject to the continued service of the recipients.

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

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QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Interest Rate Risk

Commodity Price and Credit Risk

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extended period of time, reduce demand by encouraging end users to conserve or convert to alternative energy sources.

	Increase (Decrease) To Fair Value

Crude oil (crude oil logistics segment)	$	(3,699	)
Crude oil (water solutions segment)		(10,595	)
Propane (liquids segment)		5,519
Other products (liquids segment)		(930	)
Refined products (refined products and renewables segment)		(51,414	)
Renewables (refined products and renewables segment)		346

Fair Value

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MANAGEMENT

Board of Directors of our General Partner

•: experience in business, government, education, technology or public interests;
•: high-level managerial experience in large organizations;
•: breadth of knowledge regarding our business and industry;
•: specific skills, experience or expertise related to an area of importance to us, such as energy production, consumption, distribution or transportation, government, policy, finance or law;
•: moral character and integrity;
•: commitment to our unitholders' interests;
•: ability to provide insights and practical wisdom based on experience and expertise;
•: ability to read and understand financial statements; and
•: ability to devote the time necessary to carry out the duties of a director, including attendance at meetings and consultation on partnership matters.

Directors and Executive Officers

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of, the board of directors of our general partner. The following table shows information regarding the current directors of our general partner and our executive officers.

Name		Position with NGL Energy Holdings LLC

H. Michael Krimbill	60	Chief Executive Officer and Director
Atanas H. Atanasov	41	Chief Financial Officer and Treasurer
James J. Burke	58	President, NGL Energy Partners and Director
Shawn W. Coady	52	President and Chief Operating Officer, Retail Division and Director
Todd M. Coady	56	Vice President, Administration
David C. Kehoe	55	Executive Vice President, NGL—Crude Logistics
Patrice A. Lemon	53	Senior Vice President, Accounting
Vincent J. Osterman	57	President, Eastern Retail Propane Operations and Director
Stephen L. Cropper	64	Director
Bryan K. Guderian	54	Director
James C. Kneale	62	Director
John T. Raymond	43	Director
Patrick Wade	44	Director

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also serves as the Managing Director of Impact Energy Services, LLC. Mr. Burke received his B.S. from University of Colorado in 1978.

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as a director of the National Propane Gas Association, Propane Gas Association of New England, Energi Holdings, Inc., and the Board of Advisors of the Gaudette Insurance Agency.

Mr. Raymond is also currently a director of American Energy Ohio Holdings, LLC, Ferus Inc., Ferus Natural Gas Fuels Inc., Iron Ore Holdings, Lighthouse Oil & Gas GP, LLC, MarkWest Utica

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

Director Appointment Rights

Board Leadership Structure and Role in Risk Oversight

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Audit Committee

•: retain and terminate our independent registered public accounting firm;
•: approve all auditing services and related fees and the terms thereof performed by our independent registered public accounting firm; and
•: establish policies and procedures for the pre-approval of all non-audit services and tax services to be rendered by our independent registered public accounting firm.

Compensation Committee

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

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

Corporate Governance

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Meeting of Non-Management Directors and Communications with Directors

EXECUTIVE COMPENSATION

Compensation Discussion and Analysis

The year "2014" in the Compensation Discussion and Analysis and the summary compensation table refers to our fiscal year ended March 31, 2014.

Introduction

Our "named executive officers" for fiscal 2014 were:

•: H. Michael Krimbill — Chief Executive Officer
•: Atanas H. Atanasov — Chief Financial Officer and Treasurer
•: James J. Burke — President
•: Shawn W. Coady — President and Chief Operating Officer, Retail Division
•: David C. Kehoe — Executive Vice President, NGL Crude Logistics

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Compensation Philosophy

Our executive compensation program is designed to provide a total compensation package that allows us to:

•: Attract and retain individuals with the background and skills necessary to successfully execute our business strategies;
•: Motivate those individuals to reach short-term and long-term goals in a way that aligns their interests with the interests of our unitholders; and
•: Reward success in reaching those goals.

Factors Enhancing Alignment with Unitholder Interests

•: Majority of officer pay is incentive compensation at risk based on annual financial performance and growth in unitholder value
•: Equity-based incentives are the largest single component of officer compensation
•: 50% of officers' equity awards subject to achievement of above-median total unitholder return relative to our performance peer group
•: No excise tax gross-ups
•: Compensation committee engages an independent compensation adviser

Compensation Setting Process

Our compensation program for our named executive officers supports our philosophy of pay-for-performance.

•: Role of Management: Our Chief Executive Officer also provides periodic recommendations to the compensation committee and the board of directors regarding the compensation of our other named executive officers.
•: Role of the Compensation Committee's Consultant: In carrying out its responsibilities for establishing, implementing and monitoring the effectiveness of our executive compensation philosophy, plans and programs, our compensation committee has the authority to engage outside experts to assist in its deliberations. During fiscal 2014, the compensation committee received compensation advice and data from Pearl Meyer & Partners ("PM&P"). PM&P conducted a competitive review of the principal components of compensation for our executives, including our Named Executive Officers. PM&P also provided input on peer group selection (compensation and performance peers), and short and long-term incentive plan design. The compensationcommittee reviewed the services provided by PM&P and determined that they are independent in providing executive compensation consulting services. In making this determination, the compensation committee noted that during fiscal 2014:
•: PM&P did not provide any services to the Company or management other than compensation consulting services requested by or with the approval of the compensation committee;

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•: PM&P does not provide, directly or indirectly through affiliates, any non-compensation services such as pension consulting or human resource outsourcing;
•: PM&P maintains a conflicts policy, which was provided to the compensation committee with specific policies and procedures designed to ensure independence;
•: Fees paid to PM&P by NGL Energy Partners during fiscal 2014 were less than 1% of PM&P's total revenue;
•: None of the PM&P consultants working on Company matters had any business or personal relationship with compensation committee members;
•: None of the PM&P consultants working on Company matters (or any consultants at PM&P) had any business or personal relationship with any executive officer of the Company; and
•: None of the PM&P consultants working on Company matters own Company stock.

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Elements of Executive Compensation

			Objective Supported

Element	Primary Purpose	How Amount Determined	Attract & Retain		Motivate & Pay for Performance		Unitholder Alignment
Base Salary	• Fixed income to compensate executive officers for their level of responsibility, expertise and experience	• Based on competition in the marketplace for executive talent and abilities		X
Cash Bonus Awards	• Rewards achievement of specific annual financial and operational performance goals	• Based on the named executive officer's relative contribution to achieving or exceeding annual goals		X		X		X
	• Recognizes individual contributions to our performance
Long-Term Equity Incentive Awards	• Motivates and rewards the achievement of long-term performance goals, including increasing the market price of our common units and the quarterly distributions to our unitholders	• Based on the named executive officer's expected contribution to long-term performance goals		X		X		X
	• Provides a forfeitable long-term incentive to encourage executive retention

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Base Salary

•: Mr. Krimbill's base salary of $120,000 was originally determined as part of the negotiations for our formation transactions. In setting the base salaries, the parties considered various factors, including the compensation needed to attract or retain the officers, the historical compensation of the officers, and each officer's expected individual contribution to our performance. At the request of Mr.��Krimbill, the parties agreed that he should receive a lower base salary than our other executive officers at the time because, as our Chief Executive Officer, a significant portion of his compensation should be performance-based, to further align his interests with the interests of our unitholders. In February 2012, the base salary of Mr. Krimbill was reduced to $60,000, based on our operating and financial performance as a result of an unusually warm winter. The base salary of Mr. Krimbill was restored to $120,000 effective November 12, 2012.
•: Mr. Atanasov's base salary of $195,000 was negotiated prior to his joining our management team in November 2011. The base salary of Mr. Atanasov was increased in July 2013 to $250,000.
•: Mr. Burke and Mr. Kehoe's base salaries, which became effective on June 19, 2012 when they joined our management team upon completion of our merger with High Sierra, were $353,000 and $293,000, respectively. The base salaries of Mr. Burke and Mr. Kehoe were increased in July 2013 to $375,000 and $340,000, respectively.
•: Dr. Coady's base salary of $300,000 was determined as part of the negotiations for our formation transactions. In February 2012, the base salary of Dr. Coady was reduced to $200,000 based on our operating and financial performance as a result of an unusually warm winter. The base salary of Dr. Coady was restored to $300,000 effective November 12, 2012.

Cash Bonus Awards


Atanas H. Atanasov			195,000
James J. Burke			450,000
Shawn W. Coady			200,000
David C. Kehoe			425,000

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The cash bonus program for fiscal 2015 is still under development, as further described in the "Fiscal 2015 Compensation Program" section below.

Long-Term Equity Incentive Awards

The long-term equity incentive award program for fiscal 2015 is still under development, as further described in the "Competitive Review and Fiscal 2015 Compensation Program" section below.

Severance and Change in Control Benefits

401(k) Plan

Other Benefits

Competitive Review and Fiscal 2015 Compensation Program

During fiscal 2014, PM&P conducted a competitive review of our executive compensation program and provided input to the compensation committee regarding competitive compensation levels and

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compensation program design. In order to provide guidance to the compensation committee regarding competitive rates of compensation, PM&P collected pay data from the following sources:

•: Compensation surveys including data from published compensation surveys representative of other energy industry and broader general industry companies with revenues of between $1 billion and $6 billion; and
•: Peer group data including pay data from 10-K and proxy filings for a group of 20 publicly-traded midstream oil & gas partnerships of similar size and scope to us.

Compensation Peer Group Companies


AmeriGas Partners LP	Enbridge Energy Partners, L.P.	Crosstex Energy LP
Ferrellgas Partners LP	NuStar Energy L.P.	DCP Midstream Partners LP
Star Gas Partners, L.P.	Targa Resources Partners LP	Martin Midstream Partners LP
Suburban Propane Partners, L.P.	Buckeye Partners, L.P.	Regency Energy Partners LP
ONEOK Partners, L.P.	Genesis Energy LP	Boardwalk Pipeline Partners, LP
Kinder Morgan Energy Partners, L.P.	Crestwood Midstream Partners LP	Western Gas Partners LP
Williams Partners L.P.	Magellan Midstream Partners LP

Employment Agreements

We do not have employment agreements with any of our named executive officers.

Deductibility of Compensation

Relation of Compensation Policies and Practices to Risk Management

Compensation Committee Interlocks and Insider Participation

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Summary Compensation Table for 2014

The following table includes the compensation earned by our named executive officers for fiscal years 2012-2014.

Name and Position

H. Michael Krimbill	2014	117,693	475,000	—	6,493	599,186
Chief Executive Officer	2013	82,849	—	—	2,492	85,341
	2012	110,769	—	—	2,700	113,469
Atanas H. Atanasov(4)	2014	232,500	195,000	259,696	7,038	694,234
Chief Financial Officer	2013	195,000	—	743,440	2,738	941,178
James J. Burke(5)	2014	367,385	450,000	—	24,651	842,036
President	2013	275,630	—	836,400	13,015	1,125,045
Shawn W. Coady	2014	300,000	200,000	—	19,630	519,630
President and Chief Operating Officer, Retail Division	2013	238,462	—	613,700	17,730	869,892
	2012	285,587	—	—	20,950	306,537
David C. Kehoe(5)	2014	323,731	425,000	—	15,932	764,663
Executive Vice President, NGL Crude Logistics	2013	228,781	—	836,400	13,490	1,078,671

(1): Amounts for fiscal 2014 include discretionary bonuses paid in 2014 based on contributions of the individuals since the time they joined the Partnership through the date of the bonus and based on expectations of future performance. Amounts payable based on fiscal 2014 performance, if any, have not yet been determined, but are expected to be determined during the first or second quarters of fiscal 2015.
(2): The fair values of the restricted units shown in the table above were calculated based on the closing market prices of our limited partner units on the grant dates, with adjustments made to reflect the fact that the restricted units are not entitled to distributions during the vesting period. The impact of the lack of distribution rights during the vesting period was estimated using the value of the most recent distribution prior to the grant date and assumptions that a market participant might make about future distribution growth. This calculation of fair value is consistent with the provisions of ASC 718.
(3): The amounts in this column include matching contributions to our 401(k) plan. Amounts for Mr. Burke and Mr. Kehoe each include $8,124 for club memberships. The fiscal 2014 amount for Mr. Burke includes $9,000 for a car allowance. Amounts in this column for Dr. Coady include matching contributions to our 401(k) plan of $8,750 for fiscal 2014. Amounts in this column for Dr. Coady also include the incremental cost of the use of a company car, including depreciation, maintenance, insurance, and fuel, of $10,880 for fiscal 2014.
(4): Mr. Atanasov was not a named executive officer prior to fiscal 2013.
(5): Mr. Burke and Mr. Kehoe joined our management team upon completion of our merger with High Sierra on June 19, 2012.

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Restricted Unit Awards

2014 Grants of Plan Based Awards Table

The number of restricted units granted to our named executive officers, and their grant date fair value, are summarized below:

Name	Grant Date

H. Michael Krimbill	n/a	—	—
Atanas H. Atanasov	June 27, 2013	10,000	259,696
James J. Burke	n/a	—	—
Shawn W. Coady	n/a	—	—
David C. Kehoe	n/a	—	—

Outstanding Equity Awards as of March 31, 2014

The number of unvested restricted units outstanding at March 31, 2014, and their fair values at March 31, 2014, are summarized below:

Name

H. Michael Krimbill	—	—
Atanas H. Atanasov	32,000	1,200,960
James J. Burke	40,000	1,501,200
Shawn W. Coady	10,000	375,300
David C. Kehoe	40,000	1,501,200

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2014 Option Exercises and Stock Vested

Name

H. Michael Krimbill	—	—
Atanas H. Atanasov	10,000	304,900
James J. Burke	10,000	304,900
Shawn W. Coady	10,000	304,900
David C. Kehoe	10,000	304,900

Subsequent to vesting, these individuals received distributions of $1.54 on each of the vested units during the fiscal year ended March 31, 2014.

Potential Payments upon Termination or Change in Control

Director Compensation

•: an annual retainer of $60,000;
•: an annual retainer of $10,000 for the chairman of the audit committee; and
•: an annual retainer of $5,000 for each member of the audit committee other than the chairman.

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Director Compensation for Fiscal 2014

The following table sets forth the compensation earned during fiscal 2014 by each director who is not an officer or employee of our general partner:

Name

Stephen L. Cropper	65,000	—	65,000
Bryan K. Guderian	65,000	—	65,000
James C. Kneale	70,000	—	70,000

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SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED UNITHOLDER MATTERS

Security Ownership of Certain Beneficial Owners and Management

The following table sets forth the beneficial ownership, as of May 23, 2014 of our units by:

•: each person or group of persons known by us to be a beneficial owner of more than 5% of our outstanding units;
•: each director of our general partner;
•: each named executive officer of our general partner; and
•: all directors and executive officers of our general partner as a group.

Beneficial Owners

5% or greater unitholders (other than officers and directors):
SemGroup Corporation(2)	9,133,409	12.23	%	—	—		11.33	%
Oppenheimer Funds, Inc.(3)	8,559,178	11.46	%	—	—		10.62	%
Goldman Sachs Asset Management, L.P.(4)	4,938,229	6.61	%	—	—		6.12	%
Directors and officers:
Atanas H. Atanasov(5)	43,908	*		—	—		*
James J. Burke(6)	308,259	*		—	—		*
Shawn W. Coady(7)	1,326,370	1.78	%	1,125,351	19.01	%	3.04	%
Stephen L. Cropper	25,000	*		—	—		*
Bryan K. Guderian	20,000	*		—	—		*
David C. Kehoe(8)	315,823	*		—	—		*
James C. Kneale(9)	17,500	*		—	—		*
H. Michael Krimbill(10)	970,557	1.30	%	497,846	8.41	%	1.82	%
Vincent J. Osterman(11)	3,955,437	5.29	%	—	—		4.94	%
Patrick Wade	—	—		—	—		—
John T. Raymond(12)	2,176,634	2.91	%	—	—		2.70	%
All directors and executive officers as a group (15 persons)(13)	10,491,438	14.04	%	2,747,198	46.41	%	16.45	%

*

Less than 1.0%

(1): Based on 74,706,160 common units and 5,919,346 subordinated units outstanding at May 23, 2014.
(2): The mailing address for SemGroup Corporation is 6120 S. Yale Avenue, Suite 700, Tulsa, OK 74136. SemGroup Corporation also owns an 11.78% interest in our general partner. The information related to SemGroup Corporation, including the number of common units held, is based upon its Form 4 filed with the SEC on June 10, 2013.
(3): The mailing address for OppenheimerFunds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281. OppenheimerFunds, Inc. reported shared voting and dispositive power with respect to all common units beneficially owned. The information related to

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OppenheimerFunds, Inc. is based on OppenheimerFunds, Inc.'s Form 13G filed with the SEC on April 10, 2014.

(4): The mailing address for Goldman Sachs Asset Management, L.P. is 200 West Street, New York, NY 10282. Goldman Sachs Asset Management, L.P. reported shared voting and dispositive power with respect to all common units beneficially owned. The information related to Goldman Sachs Asset Management, L.P. is based on Goldman Sachs Asset Management, L.P.'s Form 13G filed with the SEC on February 13, 2014.
(5): Atanas H. Atanasov also owns a 0.40% interest in our general partner.
(6): Impact Development, LLC owns 33,872 of these common units. Impact Development, LLC is solely owned by James J. Burke, who may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. Impact Development, LLC also owns a 2.87% interest in our general partner.
(7): Shawn W. Coady owns 21,330 of these common units. SWC Family Partnership LP owns 1,195,040 of these common units and 1,125,351 of these subordinated units. SWC Family Partnership LP is solely owned by SWC General Partner, LLC, of which Shawn W. Coady is the sole partner. Shawn W. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. The 2012 Shawn W. Coady Irrevocable Insurance Trust, which was established for the benefit of Shawn W. Coady's children, owns 110,000 of these common units. Shawn W. Coady may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. Shawn W. Coady also owns a 12.27% interest in our general partner through Coady Enterprises, LLC, of which he owns 100% of the membership interests.
(8): David C. Kehoe also owns a 0.75% interest in our general partner through DCK GP, LLC, of which he owns 100% of the membership interests.
(9): Of these common units, 12,500 are owned by the Suzanne and Jim Kneale Living Trust.
(10): Krim2010, LLC owns 407,002 of these common units and all of these subordinated units. Krimbill Enterprises LP, H. Michael Krimbill and James E. Krimbill own 90.89%, 4.05%, and 5.06% of Krim2010, LLC, respectively. H. Michael Krimbill exercises the sole voting and investment power for Krimbill Enterprises LP. H. Michael Krimbill may be deemed to have sole voting and investment power over these units, but disclaims such beneficial ownership except to the extent of his pecuniary interest therein. H. Michael Krimbill also owns a 14.81% interest in our general partner through KrimGP2010, LLC, of which he owns 100% of the membership interests. KrimGP2010 LLC owns 363,555 of these common units. KrimGP2010 LLC is solely owned by H. Michael Krimbill. H. Michael Krimbill may be deemed to have sole voting and investment power over these units.
(11): Vincent J. Osterman owns 30,000 of these common units. The remaining common units are owned by AO Energy, Inc. (110,587 common units), E. Osterman, Inc. (394,350 common units), E. Osterman Gas Services, Inc. (301,700 common units), E. Osterman Propane, Inc. (669,300 common units), Milford Propane, Inc. (559,784 common units), Osterman Family Foundation (192,816 common units), Osterman Propane, Inc. (1,445,850 common units), Propane Gas, Inc. (36,450 common units) and Saveway Propane Gas Service, Inc. (214,600 common units). Each of these holding entities may be deemed to have sole voting and investment power over its own common units and Propane Gas, LLC, as sole shareholder of Propane Gas, Inc., may be deemed to have sole voting and investment power over those common units. Vincent J. Osterman is a director, executive officer and shareholder or member

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of each of these entities and may be deemed to have sole voting and investment power over 729,300 common units and shared voting and investment power (with his father, Ernest Osterman) over 3,281,137 common units, but disclaims beneficial ownership except to the extent of his pecuniary interest therein. Vincent J. Osterman also owns a 0.75% interest in our general partner through VE Properties XI LLC.

(12): EMG NGL HC, LLC owns all of these common units. John T. Raymond is the Chief Executive Officer and Managing Partner of NGP MR GP, LLC, the general partner of NGP MR, LP, the general partner of NGP Midstream & Resources, LLC, a member holding a majority interest in EMG NGL HC, LLC. John T. Raymond may be deemed to have shared voting and investment power over these units, but disdains beneficial ownership except to the extent of his pecuniary interest therein. EMG I NGL GP Holdings, LLC, an affiliate of EMG NGL HC, LLC, owns a 6.73% interest in our general partner. EMG II NGL GP Holdings, LLC, an affiliate of EMG NGL HC, LLC, owns a 5.36% interest in our general partner.
(13): The directors and executive officers of our general partner also collectively own a 68.00% interest in our general partner.

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DESCRIPTION OF NOTES

You can find the definitions of certain terms used in this description under the subheading "—Definitions." In this description, the words "NGL Energy," "us," "our" and "we" refer only to NGL Energy Partners LP and not to any of its Subsidiaries, and the words "Finance Corp." refer solely to NGL Energy Finance Corp. The term "Issuers" refers to NGL Energy and Finance Corp., collectively.

The Issuers will issue new notes under an indenture dated as of the Issue Date (the "indenture"), among the Issuers, the Guarantors and U.S. Bank National Association, as trustee (the "trustee"), in exchange for old notes issued under the indenture in a private transaction that was not subject to the registration requirements of the Securities Act. See "Notice to Investors." The terms of the notes will include those stated in the indenture and those made part of the indenture by reference to the Trust Indenture Act of 1939, as amended (the "Trust Indenture Act").

The registered holder of a note will be treated as the owner of it for all purposes. Only registered holders will have rights under the indenture and all references to "holders" in this description are to registered holders of notes.

Brief Description of the Notes and the Note Guarantees

The Notes

The new notes will:

•: be general unsecured obligations of each of the Issuers;
•: be non-recourse to our general partner;
•: rankpari passu in right of payment with all existing and future unsubordinated Indebtedness of each of the Issuers, including the Existing Senior Notes;
•: rank senior in right of payment to any future subordinated Indebtedness of each of the Issuers;
•: be structurally subordinated to all obligations of any of our Subsidiaries;
•: be unconditionally guaranteed by the Guarantors on a senior unsecured basis; and
•: rank effectively junior in right of payment to all existing and future secured Indebtedness of each of the Issuers, including indebtedness under the Credit Agreement and the Existing Senior Secured Notes, which are secured by substantially all of the assets of NGL Energy and the Guarantors, to the extent of the assets of the Issuers constituting collateral securing such Indebtedness. See "Risk Factors—Risks Related to the Notes—The notes and the guarantees will be unsecured and effectively subordinated to our and our subsidiary guarantors' existing and future secured indebtedness." and "Risk Factors—Risks Related to the Notes—The notes and the guarantees will be structurally subordinated to all indebtedness of our non-guarantor subsidiaries."

The Note Guarantees

Initially, the notes will be guaranteed by each Restricted Subsidiary (other than Finance Corp.) that is a Domestic Subsidiary and an obligor under the Credit Agreement. In the future, other Restricted Subsidiaries will be required to guarantee the notes under the circumstances described below under "—Covenants—Additional Note Guarantees."

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Each guarantee of the notes will:

•: be a general unsecured obligation of the applicable Guarantor;
•: rankpari passu in right of payment with all existing and future unsubordinated Indebtedness of such Guarantor, including the guarantees of the Existing Senior Notes;
•: rank senior in right of payment to any future subordinated Indebtedness of such Guarantor; and
•: rank effectively junior in right of payment to all existing and future secured Indebtedness of such Guarantor, including indebtedness under the Credit Agreement and the Existing Senior Secured Notes, to the extent of the assets of such Guarantor constituting collateral securing such Indebtedness.

As of the Issue Date, all of our Restricted Subsidiaries will guarantee the notes, other than NGL Gateway Terminals, Inc., High Sierra Energy GP, LLC, High Sierra Shared Services, LLC, Petro Source Products, LLC, NGL Crude Canada ULC, Indigo Injection #3-1, LLC, Atlantic Propane LLC and NGL Hutch, LLC. As of the Issue Date, none of these Subsidiaries guarantees (or is otherwise liable for) any Obligations under any Credit Facility, including the Credit Agreement.

As of the Issue Date, all of our Subsidiaries will be "Restricted Subsidiaries." However, under the circumstances described below under the caption "—Covenants—Designation of Restricted and Unrestricted Subsidiaries," we will be permitted to designate certain of our Subsidiaries as "Unrestricted Subsidiaries." Our Unrestricted Subsidiaries will not be subject to many of the restrictive covenants in the indenture. In the event of a bankruptcy, liquidation or reorganization of any Unrestricted Subsidiary, such Unrestricted Subsidiary will pay the holders of its debt and its trade creditors before it will be able to distribute any of its assets to NGL Energy.

Principal, Maturity and Interest

The Issuers will issue up to $400.0 million in aggregate principal amount of new notes in this exchange offer. The Issuers may issue additional notes under the indenture from time to time after this offering. Any issuance of additional notes is subject to all of the covenants in the indenture, including the covenant described below under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock." The notes and any additional notes subsequently issued under the indenture will be treated as a single class for all purposes under the indenture, including, without limitation, waivers, amendments, redemptions and offers to purchase. The Issuers will issue notes in denominations of $2,000 and integral multiples of $1,000 in excess of $2,000. The notes will mature on July 15, 2019.

Interest on the notes will accrue at the rate of 5.125% per annum and will be payable semi-annually in arrears on January 15 and July 15, beginning on January 15, 2015. The Issuers will make each interest payment to the holders of record on the immediately preceding January 1 and July 1.

Methods of Receiving Payments on the Notes

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an account in the United States of America. All other payments on the notes will be made at the office or agency of the paying agent and registrar in New York, New York, unless we elect to make interest payments by check mailed to the noteholders at their address set forth in the register of holders.

Paying Agent and Registrar for the Notes

Transfer and Exchange

Note Guarantees

(1) immediately after giving effect to such transaction or series of related transactions, no Default or Event of Default exists; and

(2) either:

(b) such transaction or series of transactions does not violate the provisions of the indenture described under the caption "—Repurchase at the Option of Holders—Asset Sales."

The Note Guarantee of a Guarantor will be released automatically:

(1) in connection with any sale or other disposition of all or substantially all of the properties or assets of that Guarantor, by way of merger, consolidation or otherwise, to a Person that is not

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(either before or after giving effect to such transaction) NGL Energy or a Restricted Subsidiary of NGL Energy, if the sale or other disposition does not violate the "Asset Sales" provisions of the indenture described below under the caption "—Repurchase at the Option of Holders—Asset Sales";

(3) if NGL Energy designates such Guarantor to be an Unrestricted Subsidiary in accordance with the applicable provisions of the indenture;

(5) upon the liquidation or dissolution of such Guarantor, provided no Default or Event of Default occurs as a result thereof or has occurred or is continuing;

(7) at such time as such Guarantor is no longer required to be a Guarantor pursuant to the provisions of the covenant described under the caption "—Covenants—Additional Note Guarantees."

Optional Redemption

Except as described below in this section or in the next-to-last paragraph of "—Repurchase at the Option of Holders—Change of Control," the notes are not redeemable at our option. On one or more occasions on or after June 15, 2019 (one month prior to maturity), NGL Energy may redeem all or a part of the notes, at a redemption price equal to 100% of the principal amount of the notes redeemed plus accrued and unpaid interest, if any, on the notes redeemed to but excluding, the redemption date, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date. On one or more occasions prior to June 15, 2019 (one month prior to maturity), NGL Energy may redeem all or a part of the notes, at a redemption price equal to the Make-Whole Price, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date.

"Make-Whole Price" with respect to any notes to be redeemed, means an amount equal to the greater of:

(1) 100% of the principal amount of such notes; and

(2) the sum of the present values of (a) 100% of the principal amount of such notes and (b) the remaining scheduled payments of interest from the redemption date to June 15, 2019 (not including any portion of such payments of interest accrued as of the redemption date) discounted back to the redemption date on a semi-annual basis (assuming a 360-day year consisting of twelve 30-day months) at the Treasury Rate (as defined below) plus 50 basis points;

plus, in the case of both (1) and (2), accrued and unpaid interest on such notes, if any, to the redemption date.

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"Comparable Treasury Issue" means, with respect to notes to be redeemed, the U.S. Treasury security selected by an Independent Investment Banker as having a maturity most nearly equal to the period from the redemption date to July 15, 2019, that would be utilized at the time of selection and in accordance with customary financial practice, in pricing new issues of corporate debt securities of a comparable maturity; provided that if such period is less than one year, then the U.S. Treasury security having a maturity of one year shall be used.

"Independent Investment Banker" means RBS Securities Inc., Deutsche Bank Securities Inc. and RBC Capital Markets, LLC, or one of their respective successors, or, if such firms or their respective successors, if any, as the case may be, are unwilling or unable to select the Comparable Treasury Issue, an independent investment banking institution of national standing appointed by NGL Energy.

"Primary Treasury Dealer" means a U.S. government securities dealer in the City of New York.

"Reference Treasury Dealer" means each of RBS Securities Inc., Deutsche Bank Securities Inc. and RBC Capital Markets, LLC and two additional Primary Treasury Dealers selected by NGL Energy, and their respective successors;provided, however, that if any such firm or any such successor, as the case may be, shall cease to be a Primary Treasury Dealer, NGL Energy shall substitute therefor another Primary Treasury Dealer.

The notice of redemption with respect to the foregoing redemption need not set forth the Make-Whole Price but only the manner of calculation thereof. NGL Energy will notify the trustee of the Make-Whole Price with respect to any redemption promptly after the calculation, and the trustee shall not be responsible for such calculation.

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Selection and Notice

If less than all of the notes are to be redeemed at any time, the trustee will select notes for redemption on a pro rata basis (or, in the case of notes in global form, the trustee will select notes for redemption based on the method of The Depository Trust Company ("DTC") that most nearly approximates a pro rata selection), unless otherwise required by law or applicable stock exchange requirements.

On and after the redemption date, interest ceases to accrue on notes or portions of notes called for redemption, unless NGL Energy defaults in making the redemption payment. Any redemption or notice of redemption may, at our discretion, be subject to one or more conditions precedent.

Open Market Purchases; No Mandatory Redemption or Sinking Fund

We may at any time and from time to time purchase notes in the open market or otherwise. The Issuers are not required to make mandatory redemption or sinking fund payments with respect to the notes.

Repurchase at the Option of Holders

Change of Control

If a Change of Control occurs, each holder of notes will have the right, except as provided below, to require NGL Energy to repurchase all or any part (equal to $2,000 or an integral multiple of $1,000 in excess thereof) of that holder's notes pursuant to an offer ("Change of Control Offer") on the terms set forth in the indenture. In the Change of Control Offer, NGL Energy will offer to make a cash payment (a "Change of Control Payment") equal to 101% of the aggregate principal amount of notes repurchased plus accrued and unpaid interest on the notes repurchased to the date of purchase (the "Change of Control Purchase Date"), subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date. Within 30 days following any Change of Control, NGL Energy will send a notice to each holder of notes describing the transaction or transactions that constitute the Change of Control and offering to repurchase properly tendered notes on the Change of Control Purchase Date specified in the notice, which date will be no earlier than 30 days and no later than 60 days from the date such notice is sent, pursuant to the procedures required by the indenture and described in such notice. NGL Energy will comply with the requirements of Rule 14e-1 under the Exchange Act and any other securities laws and regulations thereunder to the extent those laws and regulations are applicable in connection with the repurchase of the notes of any series as a result of a Change of Control. To the extent that the provisions of any securities laws or regulations conflict with the Change of Control provisions of the indenture, NGL Energy will comply with the applicable securities laws and regulations and will not be deemed to have breached its obligations under the Change of Control provisions of the indenture by virtue of such compliance.

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(1) deposit with the paying agent an amount equal to the Change of Control Payment in respect of all notes or portions of notes properly tendered; and

The paying agent will promptly mail or wire transfer to each holder of notes properly tendered the Change of Control Payment for such notes (or, if all the notes are then in global form, make such payment through the facilities of DTC), and the trustee will promptly authenticate and mail (or cause to be transferred by book entry) to each holder a new note equal in principal amount to any unpurchased portion of the notes surrendered, if any; provided that each such new note will be in a principal amount of $2,000 or an integral multiple of $1,000 in excess of $2,000. Any note so accepted for payment will cease to accrue interest on and after the Change of Control Purchase Date, unless NGL Energy defaults in making the Change of Control Payment. NGL Energy will publicly announce the results of the Change of Control Offer on or as soon as practicable after the Change of Control Purchase Date.

NGL Energy will not be required to make a Change of Control Offer upon a Change of Control, if (1) a third party makes the Change of Control Offer in the manner, at the time and otherwise in compliance with the requirements set forth in the indenture applicable to a Change of Control Offer made by NGL Energy and purchases all notes properly tendered and not withdrawn under the Change of Control Offer, (2) notice of redemption of all outstanding notes has been given pursuant to the indenture as described above under the caption "—Selection and Notice," unless and until there is a default in payment of the applicable redemption price, or (3) in connection with or in contemplation of any Change of Control, NGL Energy has made an offer to purchase (an "Alternate Offer") any and all notes validly tendered at a cash price equal to or higher than the Change of Control Payment and has purchased all notes properly tendered in accordance with the terms of the Alternate Offer. Notwithstanding anything to the contrary contained in the indenture, a Change of Control Offer or Alternate Offer may be made in advance of a Change of Control, conditioned upon the consummation of such Change of Control, if a definitive agreement is in place for the Change of Control at the time the Change of Control Offer or Alternate Offer is made.

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record date to receive interest due on an interest payment date that is on or prior to the redemption date).

Asset Sales

NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, consummate an Asset Sale unless:

(2) at least 75% of the consideration received in the Asset Sale by NGL Energy or such Restricted Subsidiaries (considered together on a cumulative basis, with all consideration received by NGL Energy or any of its Restricted Subsidiaries in respect of other Asset Sales consummated since the Measuring Date) is in the form of cash or Cash Equivalents. For purposes of this provision, each of the following will be deemed to be cash:

(1) to repay, redeem or repurchase any Senior Debtprovided that such repayment, redemption or repurchase may close up to 45 days after the end of such 365-day period;

(2) to invest in or acquire Additional Assets; or

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(3) to make capital expenditures in respect of a Permitted Business.

Pending the final application of any Net Proceeds, NGL Energy or any of its Restricted Subsidiaries may temporarily reduce revolving credit borrowings or otherwise invest the Net Proceeds in any manner that is not prohibited by the indenture. An amount equal to any Net Proceeds from Asset Sales that are not applied or invested as provided in in clauses (1) through (3) of the immediately preceding paragraph will constitute "Excess Proceeds." Within ten Business Days after the aggregate amount of Excess Proceeds exceeds $30.0 million, the Issuers will make an offer (an "Asset Sale Offer") to all holders of notes and all holders of other Indebtedness that ispari passu with the notes containing provisions similar to those set forth in the indenture with respect to offers to purchase, prepay or redeem with the proceeds of sales of assets to purchase, prepay or redeem the maximum principal amount of notes and such otherpari passu Indebtedness (plus all accrued interest on the Indebtedness and the amount of all fees and expenses, including premiums, incurred in connection therewith) that may be purchased, prepaid or redeemed out of the Excess Proceeds. The offer price in any Asset Sale Offer will be equal to 100% of the principal amount, plus accrued and unpaid interest, if any, to but excluding the date of purchase, prepayment or redemption, subject to the rights of holders of notes on the relevant record date to receive interest due on the relevant interest payment date, and will be payable in cash. If any Excess Proceeds remain after consummation of an Asset Sale Offer, NGL Energy or any Restricted Subsidiary may use those Excess Proceeds for any purpose not otherwise prohibited by the indenture. If the aggregate principal amount of notes and otherpari passu Indebtedness tendered in (or required to be prepaid or redeemed in connection with) such Asset Sale Offer exceeds the amount of Excess Proceeds, the trustee will select the notes and such otherpari passu Indebtedness to be purchased on apro rata basis (except that any notes represented by a note in global form will be selected by such method as DTC or its nominee or successor may require or, where such nominee or successor is the trustee, a method that most nearly approximates pro rata selection as the trustee deems fair and appropriate unless otherwise required by law), based on the amounts tendered or required to be prepaid or redeemed (with such adjustments as may be deemed appropriate by NGL Energy so that only notes in denominations of $2,000, or an integral multiple of $1,000 in excess thereof, will be purchased). Upon completion of each Asset Sale Offer, the amount of Excess Proceeds will be reset at zero.

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NGL Energy is prohibited from purchasing notes, NGL Energy could seek the consent of its senior lenders to the purchase of notes or could attempt to refinance the borrowings that contain such prohibition. If NGL Energy does not obtain a consent or repay those borrowings, NGL Energy will remain prohibited from purchasing notes. In that case, NGL Energy's failure to purchase tendered notes would constitute an Event of Default under the indenture which could, in turn, constitute a default under the other indebtedness. Finally, the Issuers' ability to pay cash to the holders of notes upon a repurchase may be limited by NGL Energy's then-existing financial resources. See "Risk Factors—Risks Relating to the Notes—We may not have the funds necessary to finance the repurchase of the notes in connection with a change of control offer required by the indenture."

Covenants

Covenant Termination

(a) clause (4) of the covenant described under "—Covenants—Merger, Consolidation or Sale of Substantially All Assets" and

(b) the provisions of the indenture described above under the following headings:

•: "—Repurchase at the Option of Holders—Asset Sales;"
•: "—Covenants—Restricted Payments;"
•: "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock;"
•: "—Covenants—Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries;" and
•: "—Covenants—Transactions with Affiliates."

Furthermore, after an Investment Grade Rating Event, NGL Energy may not designate any of its Subsidiaries as Unrestricted Subsidiaries.

Restricted Payments

NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly:

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(4) make any Restricted Investment

(a) Available Cash from Operating Surplus with respect to NGL Energy's preceding fiscal quarter;plus

(b) 100% of the aggregate net cash proceeds, and the Fair Market Value of any Capital Stock of Persons engaged primarily in a Permitted Business or other long-term assets that are used or useful in a Permitted Business, in each case received by NGL Energy since the Measuring Date from (x) a contribution to the common equity capital of NGL Energy from any Person (other than a Restricted Subsidiary) or (y) the issuance and sale (other than to a Restricted Subsidiary) of Equity Interests (other than Disqualified Stock) of NGL Energy or from the issuance or sale (other than to a Restricted Subsidiary) of convertible or exchangeable Disqualified Stock or convertible or exchangeable debt securities of NGL Energy that have been converted into or exchanged for such Equity Interests (other than Disqualified Stock);plus

(c) to the extent that any Restricted Investment that was made after the Measuring Date is sold for cash or Cash Equivalents or otherwise liquidated or repaid for cash or Cash Equivalents, the cash return of capital with respect to such Restricted Investment (less the cost of disposition, if any);plus

(d) the amount equal to the net reduction in Restricted Investments since the Measuring Date resulting from (i) dividends, repayments of loans or advances, or other transfers of assets, in each case, to NGL Energy or any of its Restricted Subsidiaries from any Person (including, without limitation, any Unrestricted Subsidiary) or (ii) the redesignation of Unrestricted Subsidiaries as Restricted Subsidiaries, in each case, to the extent such amounts have not been included in Available Cash for any period commencing on or after the Measuring Date (items (b), (c) and (d) being referred to as "Incremental Funds"); minus

(e) the aggregate amount of Incremental Funds previously expended pursuant to this clause (I) and clause (II) below; or

(II) if the Fixed Charge Coverage Ratio for the Trailing Four Quarters is less than 1.75 to 1.0, such Restricted Payment, together with the aggregate amount of all other Restricted Payments

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made by NGL Energy and its Restricted Subsidiaries during the fiscal quarter in which such Restricted Payment is made (excluding Restricted Payments permitted by clauses (2), (3), (4), (5), (6), (7), (8), (9), (10) and (11) of the next succeeding paragraph), is less than the sum, without duplication, of:

(a) $200.0 million, less the aggregate amount of all prior Restricted Payments made by NGL Energy and its Restricted Subsidiaries pursuant to this clause (II)(a) since the Issue Date;plus

(b) Incremental Funds to the extent not previously expended pursuant to this clause (II) or clause (I) above;

The preceding provisions will not prohibit:

(2) the making of any Restricted Payment in exchange for, or out of the net cash proceeds of the substantially concurrent (a) contribution (other than from a Restricted Subsidiary) to the equity capital of NGL Energy or (b) sale (other than to a Restricted Subsidiary) of Equity Interests of NGL Energy (other than Disqualified Stock), with a sale being deemed substantially concurrent if such purchase, redemption, defeasance or other acquisition or retirement for value occurs not more than 120 days after such sale;provided,however, that the amount of any such net cash proceeds that are utilized for any such purchase, redemption, defeasance or other acquisition or retirement for value will be excluded (or deducted, if included) from the calculation of Available Cash and Incremental Funds;

(4) the payment of any dividend or distribution by a Restricted Subsidiary to the holders of its Equity Interests on apro rata basis;

(5) as long as no Default has occurred and is continuing or would be caused thereby, the purchase, redemption or other acquisition or retirement for value of any Equity Interests of NGL Energy or any Restricted Subsidiary held by any of current or former directors or employees of the General Partner, NGL Energy or of any Restricted Subsidiary;provided,however, that the aggregate price paid for all such purchased, redeemed, acquired or retired Equity Interests may not exceed $7.5 million in any fiscal year (with any portion of such $7.5 million amount that is unused in any fiscal year to be carried forward to successive fiscal years and added to such amount)plus, to the extent not previously applied or included, (a) the cash proceeds received by NGL Energy or any of its Restricted Subsidiaries from sales of Equity Interests of NGL Energy to employees or directors of the General Partner, NGL Energy or its Affiliates that occur after the Measuring Date (to the extent the cash proceeds from the sale of such Equity Interests have not otherwise been applied to the payment of Restricted Payments by virtue of clause (I)(b) or (II)(b) of the first paragraph of this covenant) and (b) the cash proceeds of key man life insurance policies received by NGL Energy or any of its Restricted Subsidiaries after the Measuring Date;

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(10) as long as no Default has occurred and is continuing or would be caused thereby, the declaration and payment of regularly scheduled or accrued dividends to holders of any class or series of Disqualified Stock of NGL Energy or any preferred securities of any Restricted Subsidiary issued on or after the Issue Date in accordance with the covenant described below under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock;"

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Incurrence of Indebtedness and Issuance of Preferred Stock

NGL Energy will not, and will not permit any of its Restricted Subsidiaries to, directly or indirectly, create, incur, issue, assume, Guarantee or otherwise become directly or indirectly liable, contingently or otherwise, with respect to (collectively, "incur"; with "incurrence" having a correlative meaning) any Indebtedness (including Acquired Debt), and NGL Energy will not issue any Disqualified Stock and will not permit any of its Restricted Subsidiaries to issue any shares of preferred stock;provided, however, that NGL Energy may incur Indebtedness (including Acquired Debt) and issue Disqualified Stock, and its Restricted Subsidiaries may incur Indebtedness (including Acquired Debt) and issue preferred stock, if the Fixed Charge Coverage Ratio for NGL Energy's most recently ended four full fiscal quarters for which internal financial statements are available immediately preceding the date on which such additional Indebtedness is incurred or such Disqualified Stock or such preferred stock is issued, as the case may be, would have been at least 2.0 to 1.0, determined on apro forma basis (including apro forma application of the net proceeds therefrom), as if the additional Indebtedness had been incurred or the Disqualified Stock or the preferred stock had been issued, as the case may be, at the beginning of such four-quarter period.

(1) the incurrence by NGL Energy or any of its Restricted Subsidiaries of additional Indebtedness and letters of credit under Credit Facilities in an aggregate principal amount at any one time outstanding under this clause (1) with letters of credit being deemed to have a principal amount equal to the maximum potential liability of NGL Energy and its Restricted Subsidiaries thereunder) not to exceed the greater of (a) $2.2 billion and (b) $700.0 millionplus 35.0% of the Total Assets of NGL Energy determined on the date of such incurrence;

(2) the incurrence by NGL Energy or its Restricted Subsidiaries of Existing Indebtedness;

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provided that, immediately after giving effect to any such incurrence, the principal amount of all Indebtedness incurred pursuant to this clause (4) and then outstanding does not exceed the greater of (a) $75.0 million and (b) 3.25% of the Total Assets of NGL Energy;

(6) the incurrence by NGL Energy or any of its Restricted Subsidiaries of intercompany Indebtedness between or among NGL Energy and any of its Restricted Subsidiaries;provided, however, that:

(b) (i) any subsequent issuance or transfer of Equity Interests that results in any such Indebtedness being held by a Person other than NGL Energy or a Restricted Subsidiary and (ii) any sale or other transfer of any such Indebtedness to a Person that is neither NGL Energy nor a Restricted Subsidiary, will be deemed, in each case, to constitute an incurrence of such Indebtedness by NGL Energy or such Restricted Subsidiary, as the case may be, that was not permitted by this clause (6);

(7) the issuance by any of NGL Energy's Restricted Subsidiaries to NGL Energy or to any of its Restricted Subsidiaries of shares of preferred stock;provided, however, that:

(a) any subsequent issuance or transfer of Equity Interests that results in any such preferred stock being held by a Person other than NGL Energy or a Restricted Subsidiary; and

(8) the incurrence by NGL Energy or any of its Restricted Subsidiaries of Hedging Obligations in the ordinary course of business and not for speculative purposes;

(11) the incurrence by NGL Energy or any of its Restricted Subsidiaries of Indebtedness constituting reimbursement obligations with respect to letters of credit;provided that, upon the

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drawing of such letters of credit, such obligations are reimbursed within 30 days following such drawing;

(13) the incurrence by NGL Energy or any of its Restricted Subsidiaries of Permitted Acquisition Indebtedness;

(15) the incurrence by NGL Energy or any of its Restricted Subsidiaries of additional Indebtedness and the issuance by NGL Energy of any Disqualified Stock,provided that, immediately after giving effect to any such incurrence or issuance, the amount of all such Indebtedness and Disqualified Stock incurred or issued pursuant to this clause (15) and then outstanding (including all Indebtedness and Disqualified Stock incurred or issued to Refinance any Indebtedness or Disqualified Stock incurred or issued pursuant to this clause (15)) does not exceed the greater of (a) $75.0 million and (b) 3.25% of the Total Assets of NGL Energy determined on the date of such incurrence.

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not be deemed to be an incurrence of Indebtedness or an issuance of preferred stock or Disqualified Stock for purposes of this covenant;provided that, in each such case, the amount thereof is included in Fixed Charges of NGL Energy as accrued to the extent required by the definition of such term.

Liens

Dividend and Other Payment Restrictions Affecting Restricted Subsidiaries

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(3) sell, lease or transfer any of its properties or assets to NGL Energy or any of its Restricted Subsidiaries.

However, the preceding restrictions will not apply to encumbrances or restrictions existing under or by reason of:

(2) the indenture, the notes and the Note Guarantees;

(3) agreements governing other Indebtedness permitted to be incurred under the provisions of the covenant described above under the caption "—Covenants—Incurrence of Indebtedness and Issuance of Preferred Stock" and any amendments, restatements, modifications, renewals, supplements, refundings, replacements or refinancings of those agreements;provided that the encumbrances or restrictions therein are, in the reasonable good faith judgment of the Chief Financial Officer of the General Partner, not materially more restrictive, taken as a whole, than the provisions contained in the Credit Agreement and in the indenture as in effect on the Issue Date;

(5) applicable law, rule, regulation, order, approval, license, permit or similar restriction;

(7) customary non-assignment provisions in contracts or licenses, easements or leases, in each case, entered into in the ordinary course of business;

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(13) any instrument governing Indebtedness of a FERC Subsidiary;provided that such Indebtedness was otherwise permitted by the terms of the indenture to be incurred;

(14) encumbrances or restrictions on cash, Cash Equivalents or other deposits or net worth imposed by customers under contracts entered into in the ordinary course of business;

(16) Hedging Obligations permitted from time to time under the indenture; and

Merger, Consolidation or Sale of Assets

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however, that Finance Corp. may not consolidate or merge with or into any Person other than a corporation satisfying such requirement so long as NGL Energy is not a corporation;

(3) immediately after such transaction, no Default or Event of Default exists;

Notwithstanding the second preceding paragraph, NGL Energy is permitted to reorganize as any other form of entity,provided that:

(2) the entity so formed by or resulting from such reorganization is an entity organized or existing under the laws of the United States, any state thereof or the District of Columbia;

(4) immediately after such reorganization no Default or Event of Default exists; and

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Transactions with Affiliates

(2) NGL Energy delivers to the trustee:

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members of the Conflicts Committee approving the Affiliate transaction or series of related Affiliate Transactions are disinterested) or a majority of the disinterested members of the Board of Directors of NGL Energy, if any.

The following items will not be deemed to be Affiliate Transactions and, therefore, will not be subject to the provisions of the prior paragraph:

(2) transactions between or among NGL Energy and/or its Restricted Subsidiaries;

(3)�� transactions with a Person (other than an Unrestricted Subsidiary) that is an Affiliate of NGL Energy solely because NGL Energy owns, directly or through a Subsidiary, an Equity Interest in, or controls, such Person;

(5) any issuance of Equity Interests (other than Disqualified Stock) to, or receipt of capital contributions from, Affiliates of NGL Energy;

(6) Restricted Payments that do not violate the provisions of the indenture described above under the caption "—Covenants—Restricted Payments" or any Permitted Investments;

(11) payment of loans or advances to employees not to exceed $5.0 million in the aggregate at any one time outstanding;

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Business Activities of Finance Corp.

Additional Note Guarantees

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Designation of Restricted and Unrestricted Subsidiaries

Any designation of a Subsidiary of NGL Energy as an Unrestricted Subsidiary will be evidenced to the trustee by filing with the trustee a certified copy of a resolution of the Board of Directors of NGL Energy giving effect to such designation and an Officers' Certificate certifying that such designation complied with the preceding conditions and was permitted by the covenant described above under the caption "—Covenants—Restricted Payments." If, at any time, any Unrestricted Subsidiary would fail to meet the preceding requirements as an Unrestricted Subsidiary, it will thereafter cease to be an Unrestricted Subsidiary for purposes of the indenture and any Indebtedness of such Subsidiary will be deemed to be incurred by a Restricted Subsidiary as of such date and, if such Indebtedness is not permitted to be incurred as of such date under the covenant described under the caption "—Incurrence of Indebtedness and Issuance of Preferred Stock," NGL Energy will be in default of such covenant.

Reports

(2) all current reports that would be required to be filed with the SEC on Form 8-K if NGL Energy were required to file such reports.

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accept such reports or information, if NGL Energy has posted such reports or information, respectively, on its website, and such reports or information, respectively, are available to holders of notes through internet access.

Except as provided above, all such reports will be prepared in all material respects in accordance with all of the rules and regulations applicable to such reports.

Events of Default and Remedies

Each of the following is an "Event of Default" with respect to the notes:

(1) default for 30 days in the payment when due of interest on the notes;

(2) default in the payment when due (at maturity, upon redemption or otherwise) of the principal of, or premium, if any, on, the notes;

(3) failure by NGL Energy to comply with its obligations under "—Covenants—Merger, Consolidation or Sale of Substantially All Assets" or to consummate a purchase of notes when

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required pursuant to the covenants described under the caption "—Repurchase at the Option of Holders;"

(6) default under any mortgage, indenture or instrument under which there may be issued or by which there may be secured or evidenced any Indebtedness for money borrowed by NGL Energy or any of its Restricted Subsidiaries (or the payment of which is guaranteed by NGL Energy or any of its Restricted Subsidiaries), whether such Indebtedness or Guarantee now exists, or is created after the Issue Date, if that default:

(b) results in the acceleration of such Indebtedness prior to its Stated Maturity,

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(1) such holder has previously given the trustee written notice that an Event of Default is continuing;

(2) holders of at least 25% in aggregate principal amount of the then outstanding notes make a written request to the trustee to pursue the remedy;

(3) such holder or holders offer and, if requested, provide to the trustee security or indemnity reasonably satisfactory to the trustee against any loss, liability or expense;

(4) the trustee does not comply with such request within 60 days after receipt of the request and the offer of security or indemnity; and

(5) during such 60-day period, holders of a majority in aggregate principal amount of the then outstanding notes do not give the trustee a direction inconsistent with such request.

The holders of a majority in aggregate principal amount of the then outstanding notes by written notice to the trustee may, on behalf of the holders of all of the notes, rescind an acceleration or waive any existing Default or Event of Default and its consequences under the indenture, if the rescission would not violate any judgment or decree, except a continuing Default or Event of Default, in the payment of interest or premium, if any on, or the principal of, the notes.

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No Personal Liability of Directors, Officers, Employees and Unitholders and No Recourse to General Partner

Legal Defeasance and Covenant Defeasance

(3) the rights, powers, trusts, duties and immunities of the trustee under the indenture, and the Issuers' and the Guarantors' obligations in connection therewith; and

(4) the Legal Defeasance provisions of the indenture.

In order to exercise either Legal Defeasance or Covenant Defeasance:

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(7) NGL Energy must deliver to the trustee an Officers' Certificate, stating that all conditions precedent set forth in clauses (1) through (6) of this paragraph have been complied with; and

(8) NGL Energy must deliver to the trustee an opinion of counsel, stating that all conditions precedent set forth in clauses (2), (3) and (5) of this paragraph have been complied with.

Amendment, Supplement and Waiver

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Without the consent of each holder of notes affected, an amendment, supplement or waiver may not (with respect to any notes held by a non-consenting holder):

(1) reduce the principal amount of notes whose holders must consent to an amendment, supplement or waiver;

(3) reduce the rate of or change the time for payment of interest, including default interest, on any note;

(5) make any note payable in currency other than that stated in the notes;

(8) release any Guarantor from any of its obligations under its Note Guarantee or the indenture, except in accordance with the terms of the indenture; or

(9) make any change in the preceding amendment, supplement and waiver provisions.

Notwithstanding the preceding, without the consent of any holder of notes, the Issuers, the Guarantors and the trustee may amend or supplement the indenture, the notes or the Note Guarantees:

(1) to cure any ambiguity, defect or inconsistency;

(2) to provide for uncertificated notes in addition to or in place of certificated notes;

(4) to make any change that would provide any additional rights or benefits to the holders of notes or that does not adversely affect the legal rights under the indenture of any holder;

(5) to comply with requirements of the SEC in order to effect or maintain the qualification of the indenture under the Trust Indenture Act;

(7) to provide for the issuance of additional notes in accordance with the limitations set forth in the indenture as of the Issue Date;

(8) to secure the notes or the Note Guarantees;

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(9) to add any additional Guarantor or to evidence the release of any Guarantor from its Note Guarantee, in each case as provided in the indenture; or

(10) to evidence or provide for the acceptance of appointment under the indenture of a successor trustee.

Satisfaction and Discharge

(1) either:

(3) the Issuers or any Guarantor have paid or caused to be paid all sums payable by them under the indenture; and

Concerning the Trustee

U.S. Bank National Association will be the trustee under the indenture.

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Governing Law

The indenture, the notes and the Note Guarantees will be governed by, and construed in accordance with, the laws of the State of New York.

Book-Entry, Delivery and Form

Depository Procedures

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either directly or indirectly (collectively, the "Indirect Participants"). Persons who are not Participants may beneficially own securities held by or on behalf of DTC only through the Participants or the Indirect Participants. The ownership interests in, and transfers of ownership interests in, each security held by or on behalf of DTC are recorded on the records of the Participants and Indirect Participants.

DTC has also advised the Issuers that, pursuant to procedures established by it:

(1) upon deposit of the Global Notes, DTC will credit the accounts of the Participants designated by the initial purchasers with portions of the principal amount of the Global Notes; and

(2) any other matter relating to the actions and practices of DTC or any of its Participants or Indirect Participants.

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Euroclear or Clearstream, as the case may be, by their respective depositaries; however, such cross-market transactions will require delivery of instructions to Euroclear or Clearstream, as the case may be, by the counterparty in such system in accordance with the rules and procedures and within the established deadlines (Brussels time) of such system. Euroclear or Clearstream, as the case may be, will, if the transaction meets its settlement requirements, deliver instructions to its respective depositary to take action to effect final settlement on its behalf by delivering or receiving interests in the relevant Global Note in DTC, and making or receiving payment in accordance with normal procedures for same-day funds settlement applicable to DTC. Euroclear participants and Clearstream participants may not deliver instructions directly to the depositaries for Euroclear or Clearstream.

Exchange of Global Notes for Certificated Notes

A Global Note is exchangeable for Certificated Notes if:

(2) the Issuers, at their option, notify the trustee in writing that they elect to cause the issuance of Certificated Notes; or

(3) there has occurred and is continuing an Event of Default with respect to the notes and DTC notifies the trustee of its decision to exchange the Global Notes for Certificated Notes.

Exchange of Certificated Notes for Global Notes

Same Day Settlement and Payment

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The Issuers expect that secondary trading in any Certificated Notes will also be settled in immediately available funds.

Definitions

"Acquired Debt" means, with respect to any specified Person:

(2) Indebtedness secured by a Lien encumbering any asset acquired by such specified Person.

"Additional Assets" means:

(1) any property or assets (other than Indebtedness and Capital Stock) to be used by NGL Energy or a Restricted Subsidiary in a Permitted Business;

(2) the Capital Stock of a Person that becomes a Restricted Subsidiary as a result of the acquisition of such Capital Stock by NGL Energy or another Restricted Subsidiary; or

provided, however, that, in the case of clauses (2) and (3), such Restricted Subsidiary is primarily engaged in a Permitted Business.

"Asset Sale" means:

(1) the sale, lease, conveyance or other disposition of any assets or rights by NGL Energy or any of NGL Energy's Restricted Subsidiaries;provided that the sale, lease, conveyance or other disposition of all or substantially all of the assets of NGL Energy and its Restricted Subsidiaries taken as a whole will be governed by the provisions of the indenture described above under the