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AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON SEPTEMBER 22, 2014

Registration No. 333-195787

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



Amendment No. 3
to

Form S-1
REGISTRATION STATEMENT UNDER THE
THE SECURITIES ACT OF 1933



JP Energy Partners LP
(Exact name of Registrant as Specified in Its Charter)

Delaware
(State or Other Jurisdiction of
Incorporation or Organization)
  4610
(Primary Standard Industrial
Classification Code Number)
  27-2504700
(I.R.S. Employer Identification
Number)

600 East Las Colinas Boulevard
Suite 2000
Irving, Texas 75039
(972) 444-0300
(Address, Including Zip Code, and Telephone Number, including
Area Code, of Registrant's Principal Executive Offices)

J. Patrick Barley
President and Chief Executive Officer
600 East Las Colinas Boulevard
Suite 2000
Irving, Texas 75039
(972) 444-0300
(Name, Address, Including Zip Code, and Telephone Number, Including Area Code, of Agent for Service)



Copies to:

Ryan J. Maierson
John M. Greer
Latham & Watkins LLP
811 Main Street, Suite 3700
Houston, Texas 77002
(713) 546-5400

 

William J. Cooper
Andrews Kurth LLP
1350 I St. NW, Suite 110
Washington, DC 20005
(202) 662-2700

 

Jon W. Daly
Andrews Kurth LLP
600 Travis Street, Suite 4200
Houston, Texas 77002
(713) 220-4200



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



          If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, 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(c) 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. (Check one):

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



CALCULATION OF REGISTRATION FEE

               
 
Title of Each Class of Securities
To Be Registered

  Amount to be
Registered(1)

  Proposed Maximum
Aggregate Offering
Per Unit(2)

  Proposed Maximum
Aggregate Offering
Price(1)(2)

  Amount of
Registration Fees(3)

 

Common units representing limited partner interests

  15,812,500   $21.00   $332,062,500   $42,770

 

(1)
Estimated pursuant to Rule 457(a) under the Securities Act of 1933, as amended. includes 2,062,500 additional common units that the underwriters have the option to purchase.

(2)
Estimated solely for the purpose of calculating the registration fee.

(3)
The Registrant previously paid $25,760 of the total registration fee in connection with the previous filing of the Registration Statement on May 8, 2014.

          The 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 or until the Registration Statement shall become effective on such date as the Securities and Exchange Commission, acting pursuant to said Section 8(a), may determine.


Table of Contents

The information in this preliminary 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 preliminary prospectus is not an offer to sell these securities and it is not soliciting an offer to buy these securities in any state where the offer or sale is not permitted.

Subject to Completion, dated September 22, 2014

PROSPECTUS


GRAPHIC

JP Energy Partners LP

13,750,000 Common Units
Representing Limited Partner Interests


This is an initial public offering of common units representing limited partner interests of JP Energy Partners LP. We are offering 13,750,000 common units in this offering. No public market currently exists for our common units. We have been approved to list our common units on the New York Stock Exchange under the symbol "JPEP." We anticipate that the initial public offering price will be between $19.00 and $21.00 per common unit.

As a result of certain laws and regulations to which we are or may in the future become subject, we may require owners of our common units to certify that they are both United States citizens and subject to United States federal income taxation on our income. If you are not both a citizenship eligible holder and a rate eligible holder, your common units may be subject to redemption.

Investing in our common units involves risks. Please read "Risk Factors" beginning on page 22 of this prospectus. These risks include the following:

    We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution, or any distribution, to holders of our common and subordinated units.

    On a pro forma basis we would not have had sufficient distributable cash flow to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2013 or for the twelve months ended June 30, 2014, with shortfalls of $23.1 million for the year ended December 31, 2013 and $33.0 million for the twelve months ended June 30, 2014.

    We face intense competition in all of our business segments. Competitors that are able to supply our customers with similar services or products at a lower price could reduce our revenues.

    Our general partner and its affiliates, including Lonestar Midstream Holdings, LLC, JP Energy Development LP, ArcLight Energy Partners Fund V, L.P. and ArcLight Capital Partners, LLC, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders.

    Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

    Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

    Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our distributable cash flow would be substantially reduced.

    Our unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

 
  Per Common Unit   Total  

Price to the public

  $     $    

Underwriting discounts and commissions(1)

  $     $    

Proceeds to us (before expenses)

  $     $    

(1)
Excludes an aggregate structuring fee equal to 0.50% of the gross proceeds of this offering payable by us to Barclays Capital Inc. and Merrill Lynch, Pierce, Fenner & Smith Incorporated. Please read "Underwriting."

We have granted to the underwriters a 30-day option to purchase up to an additional 2,062,500 common units on the same terms and conditions as set forth above if the underwriters sell more than 13,750,000 common units in this offering.

Neither the Securities and Exchange Commission nor any other 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 underwriters expect to deliver the common units on or about                           , 2014.


Barclays            
BofA Merrill Lynch        
    RBC Capital Markets    
        Deutsche Bank Securities



BMO Capital Markets   Baird   Simmons & Company International   Stephens Inc.

Janney Montgomery Scott

Prospectus dated                           , 2014


Table of Contents

GRAPHIC


Table of Contents


TABLE OF CONTENTS

 
  Page  

PROSPECTUS SUMMARY

    1  

Overview

    1  

Our Assets and Operations

    2  

How We Conduct Our Business

    4  

Our Business Strategies

    5  

Our Competitive Strengths

    5  

Our Relationship with JP Development and ArcLight

    6  

Risk Factors

    7  

Recapitalization Transactions and Partnership Structure

    8  

Organizational Structure After the Recapitalization Transactions

    9  

Management of JP Energy Partners LP

    10  

Principal Executive Offices and Internet Address

    10  

Summary of Conflicts of Interest and Duties

    10  

The Offering

    12  

Summary Historical and Pro Forma Combined Consolidated Financial and Operating Data

    18  

RISK FACTORS

   
22
 

Risks Related to Our Business

    22  

Risks Inherent in an Investment in Us

    41  

Tax Risks

    51  

USE OF PROCEEDS

   
56
 

CAPITALIZATION

   
57
 

DILUTION

   
58
 

CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

   
59
 

General

    59  

Our Minimum Quarterly Distribution

    61  

Unaudited Combined Pro Forma Distributable Cash Flow for the Year Ended December 31, 2013 and the Twelve Months Ended June 30, 2014

    62  

JP Energy Partners LP Unaudited Combined Pro Forma Distributable Cash Flow

    64  

Estimated Distributable Cash Flow for the Twelve Months Ending September 30, 2015

    65  

JP Energy Partners LP Estimated Distributable Cash Flow

    67  

Assumptions and Considerations

    68  

Revenues, Cost of Sales and Adjusted Gross Margin

    69  

PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

   
79
 

Distributions of Available Cash

    79  

Operating Surplus and Capital Surplus

    80  

Capital Expenditures

    82  

Subordinated Units and Subordination Period

    83  

Distributions of Available Cash From Operating Surplus During the Subordination Period

    84  

Distributions of Available Cash From Operating Surplus After the Subordination Period

    85  

General Partner Interest and Incentive Distribution Rights

    85  

Percentage Allocations of Available Cash From Operating Surplus

    86  

General Partner's Right to Reset Incentive Distribution Levels

    86  

Distributions From Capital Surplus

    89  

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

    90  

Distributions of Cash Upon Liquidation

    90  

i


Table of Contents

 
  Page  

SELECTED HISTORICAL AND PRO FORMA COMBINED CONSOLIDATED FINANCIAL AND OPERATING DATA

    93  

Non-GAAP Financial Measures

    95  

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

   
98
 

Overview

    98  

Recent Developments

    98  

How We Evaluate Our Operations

    99  

General Trends and Outlook

    101  

Factors Affecting the Comparability of Our Financial Results

    103  

Results of Operations

    104  

Liquidity and Capital Resources

    122  

Internal Controls and Procedures

    129  

Critical Accounting Policies and Estimates

    130  

INDUSTRY

   
134
 

General

    134  

Crude Oil Market Trends

    134  

Shifting Refinery Dynamics

    136  

Key Areas of Operation

    136  

Crude Oil Industry Value Chain

    137  

Refined Products Industry Overview

    139  

NGL Industry Overview

    140  

BUSINESS

   
143
 

Overview

    143  

Our Acquisition History

    143  

How We Conduct Our Business

    144  

Our Business Strategies

    144  

Our Competitive Strengths

    147  

Our Relationship With JP Development and ArcLight

    149  

Our Assets and Operations

    151  

Competition

    159  

Seasonality and Volatility

    160  

Insurance

    160  

Regulation of the Industry and Our Operations

    161  

Environmental Matters

    162  

Trademarks and Tradenames

    168  

Title to Properties and Permits

    168  

Office Facilities

    168  

Employees

    168  

Legal Proceedings

    169  

MANAGEMENT

   
170
 

Management of JP Energy Partners LP

    170  

Directors and Executive Officers of JP Energy GP II LLC

    171  

Board Leadership Structure

    176  

Board Role in Risk Oversight

    176  

ii


Table of Contents

 
  Page  

Compensation Discussion and Analysis

    176  

Compensation Overview

    177  

Determination of Compensation Awards

    178  

Director Compensation

    187  

SECURITY OWNERSHIP AND CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

   
188
 

CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS

   
190
 

Distributions and Payments to Our General Partner and Its Affiliates

    190  

Agreements With Affiliates in Connection With the Transactions

    191  

Other Transactions With Related Persons

    192  

Procedures for Review, Approval and Ratification of Related Person Transactions

    195  

CONFLICTS OF INTEREST AND DUTIES

   
196
 

Conflicts of Interest

    196  

Duties of the General Partner

    202  

DESCRIPTION OF THE COMMON UNITS

   
206
 

The Units

    206  

Transfer Agent and Registrar

    206  

Transfer of Common Units

    206  

OUR PARTNERSHIP AGREEMENT

   
208
 

Organization and Duration

    208  

Purpose

    208  

Capital Contributions

    208  

Voting Rights

    208  

Limited Liability

    210  

Issuance of Additional Securities

    211  

Amendment of Our Partnership Agreement

    211  

Merger, Consolidation, Conversion, Sale or Other Disposition of Assets

    213  

Termination and Dissolution

    214  

Liquidation and Distribution of Proceeds

    215  

Withdrawal or Removal of Our General Partner

    215  

Transfer of General Partner Interest

    216  

Transfer of Ownership Interests in Our General Partner

    216  

Transfer of Incentive Distribution Rights

    216  

Change of Management Provisions

    217  

Limited Call Right

    217  

Redemption of Ineligible Holders

    217  

Meetings; Voting

    218  

Status as Limited Partner

    219  

Indemnification

    219  

Reimbursement of Expenses

    219  

Books and Reports

    219  

Right to Inspect Our Books and Records

    220  

Registration Rights

    220  

Exclusive Forum

    220  

UNITS ELIGIBLE FOR FUTURE SALE

   
221
 

Rule 144

    221  

Our Partnership Agreement and Registration Rights

    221  

Lock-Up Agreements

    222  

iii


Table of Contents

 
  Page  

Registration Statement on Form S-8

    222  

MATERIAL FEDERAL INCOME TAX CONSEQUENCES

   
223
 

Partnership Status

    224  

Limited Partner Status

    225  

Tax Consequences of Unit Ownership

    225  

Tax Treatment of Operations

    232  

Disposition of Common Units

    233  

Uniformity of Units

    235  

Tax-Exempt Organizations and Other Investors

    236  

Administrative Matters

    237  

Recent Legislative Developments

    240  

State, Local, Foreign and Other Tax Considerations

    240  

INVESTMENT IN JP ENERGY PARTNERS LP BY EMPLOYEE BENEFIT PLANS

   
242
 

UNDERWRITING

   
244
 

Commissions and Expenses

    244  

Option to Purchase Additional Common Units

    245  

Lock-Up Agreements

    245  

Offering Price Determination

    246  

Indemnification

    246  

Directed Unit Program

    246  

Stabilization, Short Positions and Penalty Bids

    246  

Electronic Distribution

    247  

New York Stock Exchange

    247  

Discretionary Sales

    248  

Stamp Taxes

    248  

Relationships

    248  

FINRA

    248  

Selling Restrictions

    248  

VALIDITY OF THE COMMON UNITS

   
251
 

EXPERTS

   
251
 

INDEPENDENT AUDITORS

   
251
 

CHANGE IN ACCOUNTING FIRM

   
252
 

WHERE YOU CAN FIND ADDITIONAL INFORMATION

   
252
 

FORWARD-LOOKING STATEMENTS

   
253
 

INDEX TO FINANCIAL STATEMENTS

   
F-1
 

APPENDIX A—THIRD AMENDED AND RESTATED LIMITED PARTNERSHIP AGREEMENT OF JP ENERGY PARTNERS LP

   
A-1
 

APPENDIX B—GLOSSARY OF TERMS

   
B-1
 

        You should rely only on the information contained in this prospectus or in any free writing prospectus we may authorize to be delivered to you. We have not, and the underwriters have not, authorized any other person to provide you with information different from that contained in this prospectus and any free writing prospectus. If anyone provides you with different or inconsistent information, you should not rely on it. We are not, and the underwriters are not, making an offer to sell these securities in any jurisdiction where an offer or sale is not permitted.

iv


Table of Contents

        This prospectus contains forward-looking statements that are subject to a number of risks and uncertainties, many of which are beyond our control. Please read "Risk Factors" and "Forward-Looking Statements."


Industry and Market Data

        The data included in this prospectus regarding the oil and gas industry, including descriptions of trends in the market and our position and the position of our competitors within the industry, is based on a variety of third-party sources, including independent industry publications, government publications and other published independent sources, information obtained from customers, distributors, suppliers and trade and business organizations and publicly available information, as well as our good faith estimates, which have been derived from management's knowledge and experience in the industry in which we operate. Based on management's knowledge and experience we believe that the third-party sources are reliable and that the third-party information included in this prospectus or in our estimates is accurate and complete.

v


Table of Contents


PROSPECTUS SUMMARY

        This summary highlights selected information contained elsewhere in this prospectus. You should carefully read this entire prospectus, including "Risk Factors" and the historical and unaudited pro forma combined financial statements and related notes included elsewhere in this prospectus before making an investment decision. Unless otherwise indicated, the information in this prospectus assumes (i) an initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus) and (ii) that the underwriters do not exercise their option to purchase additional common units. You should read "Risk Factors" beginning on page 22 for more information about important factors that you should consider before purchasing our common units.

        Unless the context otherwise requires, references in this prospectus to "JP Energy Partners," "the Partnership," "we," "our," "us," or like terms refer to JP Energy Partners LP and its subsidiaries, and references to "our general partner" refer to JP Energy GP II LLC, our general partner. References to "our sponsor" or "Lonestar" refer to Lonestar Midstream Holdings, LLC, which, together with JP Energy GP LLC and CB Capital Holdings II, LLC, two entities owned by certain members of our management, owns and controls our general partner. References to "ArcLight Capital" refer to ArcLight Capital Partners, LLC and references to "ArcLight Fund V" refer to ArcLight Energy Partners Fund V, L.P. References to "ArcLight" refer collectively to ArcLight Capital and ArcLight Fund V. ArcLight Capital manages ArcLight Fund V, which controls our general partner through its ownership and control of Lonestar.


Overview

        We are a growth-oriented limited partnership formed in May 2010 by members of management and further capitalized in June 2011 by ArcLight to own, operate, develop and acquire a diversified portfolio of midstream energy assets. Our operations currently consist of four business segments: (i) crude oil pipelines and storage, (ii) crude oil supply and logistics, (iii) refined products terminals and storage and (iv) NGL distribution and sales. Together our businesses provide midstream infrastructure solutions for the growing supply of crude oil, refined products and NGLs in the United States. Since our formation, our primary business strategy has been to focus on:

    owning, operating and developing midstream assets serving areas experiencing dramatic increases in drilling activity and production growth, as well as serving key crude oil, refined product and NGL distribution hubs;

    providing midstream infrastructure solutions to users of liquid petroleum products in order to capitalize on changing product flows between producing and consuming markets resulting from the significant growth in hydrocarbon production across the United States; and

    operating one of the largest portable propane cylinder exchange businesses in the United States and capitalizing on the increase in demand and extended applications for portable propane cylinders.

        We intend to continue to expand our business by acquiring and constructing additional midstream infrastructure assets and by increasing the utilization of our existing assets to gather, transport, store and distribute crude oil, refined products and NGLs. Our crude oil businesses are situated in high-growth areas, including the Permian Basin, Mid-Continent and Eagle Ford shale, and provide us with a footprint to increase our volumes as these areas experience further drilling and production growth. In addition, we believe we have a competitive advantage with regard to the sourcing of opportunities to build, own and operate additional crude oil pipelines due to the insights in the market that we obtain while providing services to customers in our crude oil supply and logistics segment. We believe that our NGL distribution and sales segment will continue to grow due to our recent expansion

 

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Table of Contents

into new geographic markets, an increased market presence in our existing areas of operation and the increase in industrial and commercial applications for NGLs such as in oilfield and agricultural services.

        Since our formation and the formation of our affiliate, JP Energy Development LP ("JP Development"), in July 2012, our management team has successfully established a strategic midstream platform through us and JP Development by way of 25 third-party acquisitions and numerous organic capital projects. The following table sets forth our aggregate net income and the Adjusted EBITDA for each of our business segments on a pro forma combined consolidated basis for the year ended December 31, 2013 and for the six months ended June 30, 2014.

($ in millions)
  Pro Forma
Combined Consolidated
Year Ended
December 31, 2013
  Pro Forma
Combined
Consolidated
Six Months Ended
June 30, 2014
 

Total net loss

  $ (10.4 ) $ (14.3 )

Adjusted EBITDA(1):

             

Crude oil pipelines and storage

    14.7     10.1  

Crude oil supply and logistics

    14.7     1.7  

Refined products terminals and storage

    16.1     5.1  

NGL distribution and sales

    15.5     7.6  

Discontinued operations(2)

    2.0     1.0  

Corporate and other(3)

    (27.5 )   (13.5 )
           

Total Adjusted EBITDA

  $ 35.5   $ 12.0  

(1)
Adjusted EBITDA is a financial measure not presented in accordance with generally accepted accounting principles in the United States ("GAAP"). For a definition of Adjusted EBITDA and a reconciliation to net income and to net cash provided by (used in) operating activities, its most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures."

(2)
In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

(3)
Includes general partnership expenses associated with managing all reportable segments. Includes the impact of approximately $14.1 million and $5.8 million in professional fees incurred during the pro forma combined year ended December 31, 2013 and the pro forma combined six months ended June 30, 2014, respectively, related to the preparation and audit of financial statements contained in this prospectus, a significant portion of which we do not expect to incur in future periods. Excludes $3.5 million of incremental general and administrative expenses that we expect to incur as a result of being a publicly traded partnership.


Our Assets and Operations

    Crude Oil Pipelines and Storage

        Our crude oil pipelines and storage segment consists of two businesses: (i) an intrastate crude oil pipeline system in the Permian Basin known as the Silver Dollar Pipeline System and (ii) a crude oil storage facility located in Cushing, Oklahoma. As an early mover in areas with significant production of crude oil, we believe our established relationships with highly active producers and marketers in these regions will provide us with opportunities to expand our crude oil pipelines and storage segment through the construction of additional infrastructure.

 

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Table of Contents

        The Silver Dollar Pipeline System provides crude oil gathering services for producers targeting the Southern Wolfcamp play in the Midland Basin. The system currently consists of approximately 50 miles of high-pressure steel pipeline with throughput capacity of approximately 100,000 barrels per day and an interconnection to a third-party long-haul transportation pipeline. Our operations are underpinned by long-term, fee-based contracts with leading producers in the Southern Wolfcamp. One significant contract has a remaining term of approximately nine years and contains an acreage dedication related to crude oil production from approximately 110,000 acres in Crockett and Schleicher counties, Texas. Another significant contract has a remaining term of approximately five years and contains a minimum volume commitment that was amended in March 2014 to significantly increase the volumes committed thereunder. This contract amendment and other anticipated commercial opportunities in the area have enabled us to undertake expansion projects involving the construction of approximately 30 miles of additional pipeline, including an interconnection to a second long-haul transportation pipeline, which we expect to be completed in the fourth quarter of 2014. We believe that these expansion projects will significantly increase the Silver Dollar Pipeline System's gathering footprint and take-away capacity and will provide our customers with access to new markets.

        Our crude oil storage facility in Cushing, Oklahoma has an aggregate shell capacity of approximately 3.0 million barrels, all of which is dedicated to one customer pursuant to a long-term, fee-based storage services contract with a remaining term of approximately 3.0 years as of June 30, 2014. We generate crude oil storage revenues by charging this customer a fixed monthly fee per barrel of shell capacity that is not contingent on the customer's actual usage of our storage tanks.

    Crude Oil Supply and Logistics

        Our crude oil supply and logistics segment manages the physical movement of crude oil from origination to final destination largely through our network of owned and leased assets. Our assets and operations are located in areas of substantial crude oil production growth, including the Permian Basin, Mid-Continent and Eagle Ford shale. We own and operate a fleet of approximately 135 crude oil gathering and transportation trucks and approximately 30 crude oil truck injection stations and terminals. We also lease crude oil storage tanks in Cushing, Oklahoma with a shell capacity of approximately 700,000 barrels pursuant to a long-term lease with a third party. Due to the limited pipeline infrastructure in some of the basins in which we operate, our crude oil gathering and transportation trucks provide immediate access for customers to transport their crude oil to the most advantageous outlets, including pipelines, rail terminals and local refining centers.

        We primarily generate revenues in our crude oil supply and logistics segment by purchasing crude oil from producers, aggregators and traders at an index price less a discount and selling crude oil to producers, traders and refiners at a price linked to the same index. We also perform blending services in this segment whereby we purchase varying qualities of crude oil, which we blend in our leased storage tanks to WTI or other specifications. The majority of activities that are carried out within our crude oil supply and logistics segment are designed to produce a stable baseline of results in a variety of market conditions, while at the same time providing upside opportunities. Please read "—How We Conduct Our Business" for more details.

    Refined Products Terminals and Storage

        Our refined products terminals and storage segment has aggregate storage capacity of approximately 1.3 million barrels at two refined products terminals located in North Little Rock, Arkansas and Caddo Mills, Texas. Our North Little Rock terminal has storage capacity of approximately 550,000 barrels from 11 tanks and is primarily supplied by a refined products pipeline operated by Enterprise TE Products Pipeline Company LLC, which we refer to as the TEPPCO Pipeline. Our Caddo Mills terminal has storage capacity of approximately 770,000 barrels from 10 tanks and is primarily supplied by the Explorer Pipeline. We generate fee-based revenues with customers with

 

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whom we maintain longstanding relationships under contracts that, consistent with industry practice, typically contain evergreen provisions after an initial term of six months to two years. We also generate revenue from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units. A majority of the customers in our refined products terminals and storage segment are large, well-known oil companies and independent refiners.

    NGL Distribution and Sales

        Our NGL distribution and sales segment consists of three businesses in which we generate fee-based or margin-based revenue: (i) portable cylinder tank exchange, (ii) NGL sales and (iii) NGL transportation. We currently operate the third-largest propane cylinder exchange business in the United States, covering all 48 states in the continental United States through a network of over 17,700 distribution locations, which includes grocery stores, pharmacies, convenience stores and hardware stores. Our NGL sales business involves the retail, commercial and wholesale sale of NGLs and other refined products (including sales of gasoline and diesel to our oilfield service and agricultural customers) in six states in the Southwest and Midwest to approximately 88,800 customers through our distribution network of 44 customer service locations. Our NGL transportation business utilizes a fleet of approximately 43 hard shell tank trucks that gather and transport NGLs for producers, gas processing plants, refiners and fractionators located in the Eagle Ford shale and Permian Basin.

        The variety of services we offer in our NGL distribution and sales segment and the combination of our spring- and summer-weighted cylinder exchange business with our fall- and winter-weighted NGL sales business allows us to reduce the overall seasonal volatility in volumes. On a pro forma combined consolidated basis for the year ended December 31, 2013, we sold approximately 65 million gallons of NGLs in our cylinder exchange and NGL sales businesses, selling approximately 41% during the second and third quarters of 2013 and 59% during the first and fourth quarters of 2013.


How We Conduct Our Business

        We conduct our business through fee-based and margin-based arrangements.

        Fee-based.    We charge our customers a capacity, throughput or volume-based fee that is not contingent on commodity price changes. Our fee-based services include the operations in our crude oil pipelines and storage segment, our refined products terminals and storage segment, and the NGL transportation services we provide in our NGL distribution and sales segment. Our fee-based businesses are governed by tariffs or other negotiated fee agreements between us and our customers with terms ranging from one month to 10 years.

        Margin-based.    We purchase and sell crude oil in our crude oil supply and logistics segment and NGLs and refined products in our NGL distribution and sales segment. A substantial portion of our margin related to the purchase and sale of crude oil in our crude oil supply and logistics segment is derived from "fee equivalent" transactions in which we concurrently purchase and sell crude oil at prices that are based on the same index, thereby generating revenue consisting of a margin plus our purchase, transportation, handling and storage costs. In our NGL distribution and sales segment, sales prices to our customers generally provide for a margin plus the cost of our products to our customers. We also perform blending services in our crude oil supply and logistics segment and our refined products terminals and storage segment, which allows us to generate additional margin based on the difference between our cost to purchase and blend the products and the market sales price of the finished blended product. We manage commodity price exposure through the structure of our sales and supply contracts and through a managed hedging program. Our risk management policy permits the use of financial instruments to reduce the exposure to changes in commodity prices that occur in the normal course of business but prohibits the use of financial instruments for trading or to speculate on future changes in commodity prices.

 

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Our Business Strategies

        Our principal business objective is to increase the quarterly cash distributions that we pay to our unitholders over time while ensuring the ongoing stability of our business and cash flows. We expect to achieve this objective by pursuing the following business strategies:

    Capitalize on organic growth opportunities and increase utilization of our existing assets.  We intend to identify and pursue organic growth opportunities and increase the utilization of our assets to increase the cash flows of our existing businesses. For example, as of June 30, 2014, our Silver Dollar Pipeline System is connected to producers that control approximately 321,000 acres in Crockett, Reagan and Schleicher counties, Texas and we are in advanced negotiations with these and other producers in the area to connect substantial additional acreage to the system. Additionally, the recently-completed national expansion of the cylinder exchange business in our NGL distribution and sales segment has resulted in a new three-year contract with a national convenience store owner and operator and its franchisees to provide propane cylinders to all of their gas stations in California, Oregon and Washington. We believe the national expansion of our cylinder exchange business will allow us to compete for additional large-volume or national accounts.

    Pursue strategic and accretive acquisition opportunities from our affiliates and third parties.  We intend to pursue accretive acquisition opportunities from our affiliates and third parties that will complement, expand and diversify our asset base and cash flows. In addition, we intend to leverage the industry relationships of our management team to generate additional acquisition opportunities. Historically, our acquisitions have largely been privately negotiated opportunities sourced through our management team's proprietary relationships.

    Focus on fee-based and margin-based businesses with limited commodity price exposure.  We intend to continue adding operations that focus on providing services to our customers under fee-based and margin-based arrangements. We plan to pursue opportunities in all of our segments with an emphasis on limiting commodity price exposure either through contract structure or through a managed hedging program. Please read "—How We Conduct Our Business" for more information on how we manage our commodity price exposure.

    Maintain financial flexibility and a disciplined capital structure.  We intend to pursue a disciplined financial policy and maintain a conservative capital structure to allow us to pursue accretive acquisitions and execute on organic growth opportunities even in challenging capital market environments. Pro forma for this offering, we would have had $153.7 million in borrowing capacity under our revolving credit facility as of June 30, 2014. Issued and outstanding letters of credit, which reduced borrowing capacity, totaled $46.3 million as of June 30, 2014. We believe our financial flexibility positions us to take advantage of future growth opportunities without incurring debt beyond appropriate levels.


Our Competitive Strengths

        We believe that we are well-positioned to successfully execute our business strategies by capitalizing on the following competitive strengths:

    Stable cash flows from contractual arrangements and diversified operations.  Our contractual arrangements and diversified operations help us generate stable, predictable cash flows. We provide many of our services under long-term or evergreen contracts with customers with whom we have longstanding relationships. Pursuant to our contractual arrangements, substantially all of our cash flows are derived from fee-based or margin-based services, which minimizes our direct commodity price exposure. Our cash flows also benefit from our diverse operations in both geographic location and services offered to our customers.

 

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    Strategically located assets that provide organic growth opportunities.  The majority of our assets are located in areas characterized by strong demand for the services we currently provide as well as a need for additional midstream infrastructure, providing us with attractive future growth prospects. For example, our Silver Dollar Pipeline System is among the first pipelines put into service to provide crude oil transportation services to producers in the Southern Wolfcamp play, which has recently emerged as an area of significant new production growth in the Permian Basin. Additionally, we believe the national expansion of our cylinder exchange business gives us the capability to compete for new large-volume or national accounts and provides us with economies of scale and significant cost savings in product procurement, transportation and general administration.

    Relationships with JP Development and ArcLight Fund V.  We consider our relationships with JP Development, our affiliate with whom we share a common management team, and ArcLight Fund V, which has a substantial ownership interest in us, to be significant strengths. JP Development was formed in July 2012 by members of our management team and ArcLight for the express purpose of supporting our growth. We acquired the Silver Dollar Pipeline System, a portfolio of crude oil supply and logistics assets and our fleet of NGL transportation trucks from JP Development in February 2014 and we believe that our relationship with JP Development will provide us with future growth opportunities. We also believe that ArcLight Fund V's substantial ownership interest in us will provide ArcLight with an incentive to support our growth through opportunities other than those sourced from JP Development. Please read "—Our Relationship With JP Development and ArcLight."

    Experienced and entrepreneurial management team.  Averaging approximately 17 years of experience in the energy industry, our management team has expertise in key areas of the crude oil, refined products and natural gas liquids industries as well as in infrastructure development, acquisitions and the integration of acquired businesses. For example, since our formation in May 2010, our management team has successfully grown our and JP Development's operations through 25 third-party acquisitions. Please read "Business—Our Acquisition History."

    Strong sponsor with significant industry expertise.  Through Lonestar, ArcLight Fund V is the principal owner of our general partner and the sole owner of JP Development. We believe that ArcLight Capital, which controls ArcLight Fund V, has substantial experience as a private equity investor in the energy industry, having managed the investment of more than $10 billion in energy companies and assets since its inception. By providing us with strategic guidance and financial expertise, we believe our relationship with ArcLight will greatly enhance our ability to grow our asset base and cash flows.


Our Relationship with JP Development and ArcLight

        Our affiliate, JP Development, is a growth-oriented limited partnership that was formed in July 2012 by members of our management team and ArcLight for the express purpose of supporting our growth. JP Development intends to acquire growth-oriented midstream assets and to develop organic capital projects and then offer those assets for sale to us after they have been sufficiently developed such that their financial profile is suitable for us.

        Since its formation, our management team and ArcLight have successfully grown JP Development through the acquisition of midstream assets and the execution of growth projects strategically located in our current areas of operation as well as new areas for expansion. In February 2014, we acquired from JP Development an intrastate crude oil pipeline system as well as a portfolio of crude oil logistics and NGL transportation and distribution assets for aggregate consideration valued at approximately $319 million. We refer to this transaction as the JP Development Dropdown. Please read "Business—Our Relationship With JP Development and ArcLight—JP Development Dropdown."

 

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        We believe that ArcLight Fund V's and our management's collective ownership of (i) 95% of our general partner, which owns all of our incentive distribution rights, (ii) a 56.1% limited partner interest in us and (iii) 100% of the partnership interests in JP Development create a unique and strong incentive for ArcLight to support the successful execution of our business plan and to pursue projects and acquisitions that will enhance the overall value of our business.

        We believe that our relationship with JP Development and ArcLight will provide us with future growth opportunities. JP Development has granted us a right of first offer on all of its current and future assets and ArcLight Fund V has granted us a right of first offer with respect to a 50% indirect interest in Republic Midstream, LLC, an ArcLight portfolio company ("Republic"). The right of first offer with respect to JP Development's current and future assets is for a period of five years from the closing of this offering and the right of first offer with respect to Republic is for eighteen months from the closing of this offering. A description of JP Development's current assets and Republic, which we collectively refer to as the ROFO Assets, is provided below:

    an approximately 115-mile intrastate crude oil pipeline, known as the Great Salt Plains Pipeline, that runs from Cherokee, Oklahoma to Cushing, Oklahoma and serves the Mississippian Lime play;

    an approximately 75-mile interstate crude oil pipeline, known as the Red River Pipeline, serving the Fort Worth Basin that originates in Grayson County, Texas and runs to its principal terminus at the Elmore City Station in Garvin County, Oklahoma; and

    a 100% member interest in Republic Midstream Gathering II, LLC, which owns a 50% indirect interest in Republic. Republic has agreed to build, own and operate certain crude oil midstream assets for Penn Virginia Corp. in the Eagle Ford shale region. Republic's initial assets will consist of a 180-mile crude oil gathering system in Gonzales and Lavaca Counties in Texas that will deliver the gathered volumes to a 144-acre central delivery terminal in Lavaca County that is capable of storing and blending crude oil volumes. Republic has also agreed to construct a 12-inch, 30-mile takeaway pipeline from the central delivery terminal. Subject to entering into definitive documentation, we have agreed to perform certain commercial services for Republic, including working with producers to transport crude oil from the wellhead to end markets.

        Please read "Business—Our Relationship With JP Development and ArcLight" for additional discussion of JP Development's assets and "Certain Relationships and Related Party Transactions—Agreements With Affiliates in Connection With the Transactions—Right of First Offer Agreement" for additional information about our right of first offer.

        While our relationship with JP Development and ArcLight is a significant strength, it is also a source of potential conflicts. Please read "Conflicts of Interest and Duties" and "Risk Factors—Risks Inherent in an Investment in Us—Our general partner and its affiliates, including Lonestar, JP Development, ArcLight Fund V and ArcLight Capital, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders." Additionally, we have no control over JP Development's business decisions or operations and JP Development is under no obligation to adopt a business strategy that favors us.


Risk Factors

        An investment in our common units involves risks associated with our business, our partnership structure and the tax characteristics of our common units. You should carefully consider the risks described in "Risk Factors" and the other information in this prospectus before investing in our common units.

 

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Recapitalization Transactions and Partnership Structure

        At or prior to the closing of this offering, the following transactions, which we refer to as the recapitalization transactions, will occur.

        Prior to the closing of this offering:

    we will distribute approximately $92.1 million of accounts receivable that comprise our gross working capital assets to our existing partners, pro rata in accordance with their ownership interest in us; and

    each Class A common unit, Class B common unit and Class C common unit (collectively, the "Existing Common Units") will split into approximately 0.89 common units, resulting in an aggregate of 22,677,004 outstanding Existing Common Units; and

    an aggregate of 18,213,502 Existing Common Units held by our existing partners will automatically convert into 18,213,502 subordinated units representing a 80.3% interest in us prior to this offering, and a 50.0% interest in us after the closing of this offering, with 4,463,502 Existing Common Units remaining representing a 19.7% interest in us (the "Remaining Existing Common Units").

        At the closing of this offering:

    the Remaining Existing Common Units will automatically convert on a one-to-one basis into 4,463,502 common units representing a 12.3% interest in us;

    the 45 general partner units in us held by our general partner will be recharacterized as a non-economic general partner interest in us;

    we will issue 13,750,000 common units to the public in this offering representing a 37.7% interest in us; and

    we will use the net proceeds from this offering and from the borrowings under our revolving credit facility for the purposes set forth in "Use of Proceeds."

 

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Organizational Structure After the Recapitalization Transactions

        After giving effect to the transactions described above, our units will be held as follows:

Public Common Units

    37.7 %

Lonestar:

       

Common Units

    10.1 %

Subordinated Units

    41.1 %

Management:

       

Common Units

    1.0 %

Subordinated Units

    4.0 %

Other Investors:

       

Common Units

    1.2 %

Subordinated Units

    4.9 %

Non-Economic General Partner Interest

     
       

Total

    100.0 %
       

        The following diagram depicts our organizational structure after giving effect to the transactions described above.

CHART


(1)
Lonestar is owned and controlled by ArcLight Energy Partners Fund V, L.P., an investment fund controlled by ArcLight Capital Partners, LLC.

(2)
The remaining 5.0% of our general partner is owned indirectly by one of the members of our board of directors. Please read "Security Ownership and Certain Beneficial Owners and Management."

(3)
Includes the original investors in us, certain of our employees who hold unit awards and persons who were issued securities representing limited partner interests in us in connection with certain prior acquisitions. Please read "Security Ownership and Certain Beneficial Owners and Management."

 

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Management of JP Energy Partners LP

        We are managed and operated by the board of directors and executive officers of JP Energy GP II LLC, our general partner. Lonestar and certain members of management own our general partner and have the right to appoint its entire board of directors, including the independent directors appointed in accordance with the listing standards of the New York Stock Exchange (the "NYSE"). Unlike shareholders in a publicly traded corporation, our unitholders will not be entitled to elect our general partner or the board of directors of our general partner. For more information about the directors and executive officers of our general partner, please read "Management—Directors and Executive Officers of JP Energy GP II LLC."

        In order to maintain operational flexibility, our operations will be conducted through, and our operating assets will be owned by, various operating subsidiaries. However, neither we nor our subsidiaries have any employees. Our general partner has the sole responsibility for providing the personnel necessary to conduct our operations, whether through directly hiring employees or by obtaining the services of personnel employed by others. All of the personnel that will conduct our business immediately following the closing of this offering will be employed or contracted by our general partner and its affiliates, but we sometimes refer to these individuals in this prospectus as our employees.


Principal Executive Offices and Internet Address

        Our principal executive offices are located at 600 East Las Colinas Boulevard, Suite 2000, Irving, Texas 75039, and our telephone number is (972) 444-0300. Our website is located at www.jpenergypartners.com. We intend to make our periodic reports and other information filed with or furnished to the Securities and Exchange Commission ("SEC") available free of charge through our website as soon as reasonably practicable after those reports and other information are electronically filed with or furnished to the SEC. Information on our website or any other website is not incorporated by reference into this prospectus and does not constitute a part of this prospectus.


Summary of Conflicts of Interest and Duties

    General

        Under our partnership agreement, our general partner has a duty to manage us in a manner it believes is in the best interests of our partnership. However, the officers and directors of our general partner also have a duty to manage the business of our general partner in a manner that is in the best interests of its owners, including Lonestar and ArcLight. As a result of this relationship, conflicts of interest may arise in the future between us and our unitholders, on the one hand, and our general partner and its affiliates, including JP Development, Lonestar and ArcLight, on the other hand. For example, our general partner will be entitled to make determinations that affect the amount of cash distributions we make to the holders of our common units, which in turn has an effect on whether our general partner receives incentive cash distributions. For a more detailed description of the conflicts of interest and fiduciary duties of our general partner, please read "Conflicts of Interest and Duties."

    Partnership Agreement Replacement of Fiduciary Duties

        Delaware law provides that Delaware limited partnerships may, in their partnership agreements, expand, restrict or eliminate the fiduciary duties owed by the general partner to limited partners and the partnership. Our partnership agreement contains various provisions replacing the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing the duties of our general partner and contractual methods of resolving conflicts of interest. The effect of these provisions is to restrict the remedies available to unitholders for actions that might otherwise constitute breaches of our general partner's fiduciary duties. Our partnership agreement also provides that

 

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affiliates of our general partner, including Lonestar, JP Development and ArcLight, are not restricted from competing with us and that neither our general partner nor its affiliates have any obligation to present business opportunities to us. By purchasing a common unit, the purchaser agrees to be bound by the terms of our partnership agreement, and pursuant to the terms of our partnership agreement each holder of common units consents to various actions and potential conflicts of interest contemplated in our partnership agreement that might otherwise be considered a breach of fiduciary or other duties under Delaware law. Please read "Conflicts of Interest and Duties—Duties of the General Partner" for a description of the fiduciary duties imposed on our general partner by Delaware law, the replacement of those duties with contractual standards under our partnership agreement and certain legal rights and remedies available to holders of our common units and subordinated units.

    ArcLight, Lonestar and JP Development May Compete Against Us

        Although our relationships with ArcLight, Lonestar and JP Development are valuable to us, they are also a source of potential conflict. For example, our partnership agreement does not prohibit ArcLight, Lonestar, JP Development or their affiliates, other than our general partner, from owning assets or engaging in businesses that compete directly or indirectly with us. In addition, ArcLight and Lonestar or their affiliates, other than JP Development and ArcLight Fund V, which are subject to the right of first offer described under "—Our Relationship With JP Development and ArcLight," may invest in other publicly traded partnerships or acquire, construct or dispose of additional midstream or other assets in the future, without any obligation to offer us the opportunity to acquire or construct any of those assets.

        For a more detailed description of the conflicts of interest and the duties of our general partner, please read "Conflicts of Interest and Duties."

 

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The Offering

Common units offered to the public   13,750,000 common units.

 

 

15,812,500 common units if the underwriters exercise in full their option to purchase additional common units from us.

Units outstanding after this offering

 

18,213,502 common units and 18,213,502 subordinated units, each representing a 50.0% limited partner interest in us. In addition, our general partner will own a non-economic general partner interest in us.

Use of proceeds

 

Prior to the closing of this offering, we will distribute approximately $92.1 million of accounts receivable that comprise our gross working capital to our existing partners, pro rata in accordance with their ownership interest in us.

 

 

We expect to receive net proceeds of approximately $257.1 million from the sale of common units in this offering based on the initial public offering price of $20.00 per common unit (the mid-point of the price range set forth on the cover of this prospectus), after deducting underwriting discounts and structuring fees but before estimated offering expenses.

 

 

We intend to use the net proceeds from this offering to (i) pay estimated offering expenses of approximately $2.0 million, (ii) redeem 100% of our issued and outstanding Series D preferred units for approximately $42.4 million, (iii) repay $195.6 million of debt outstanding under our revolving credit facility and (iv) replenish approximately $17.1 million of working capital.

 

 

Immediately following the repayment of a portion of the outstanding debt under our revolving credit facility with a portion of the net proceeds from this offering, we will borrow approximately $75.0 million thereunder. We will use the proceeds from that borrowing to replenish our working capital.

 

 

The net proceeds from any exercise by the underwriters of their option to purchase additional common units from us will be used to redeem from Lonestar a number of common units from our existing partners, pro rata, equal to the number of common units issued upon exercise of the option at a price per common unit equal to the net proceeds per common unit in this offering before expenses but after deducting underwriting discounts and the structuring fee. Please read "Underwriting."

Cash distributions

 

We intend to make a minimum quarterly distribution of $0.3250 per unit to the extent we have sufficient cash from operations after establishment of cash reserves and payment of fees and expenses, including payments to our general partner.

 

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    For the quarter in which this offering closes, we will pay a prorated distribution on our units covering the period from the completion of this offering through December 31, 2014, based on the actual length of that period.

 

 

In general, we will pay any cash distributions we make each quarter in the following manner:

 

first, 100% to the holders of common units, until each common unit has received a minimum quarterly distribution of $0.3250 plus any arrearages from prior quarters;

 

second, 100% to the holders of subordinated units, until each subordinated unit has received a minimum quarterly distribution of $0.3250; and

 

third, 100% to all unitholders, pro rata, until each unit has received a distribution of $0.37375.


 

 

If cash distributions to our unitholders exceed $0.37375 per unit in any quarter, our general partner will receive increasing percentages, up to 50.0%, of the cash we distribute in excess of that amount due to its ownership of all of our incentive distribution rights. In certain circumstances, our general partner, as the initial holder of our incentive distribution rights, has the right to reset the target distribution levels described above to higher levels based on our cash distributions at the time of the exercise of this reset election. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions."

 

 

If we do not generate sufficient available cash from operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

 

 

The amount of pro forma available cash generated during the year ended December 31, 2013 and the twelve months ended June 30, 2014 would not have been sufficient to allow us to pay the minimum quarterly distribution on all of our units during those periods. Specifically, the amount of pro forma available cash generated during the year ended December 31, 2013 would have been sufficient to pay 100% of the minimum quarterly distribution on all of our common units during that period, but only $0.0085 per subordinated unit, or approximately 2.6% of the minimum quarterly distribution on our subordinated units, during that period. Likewise, the amount of pro forma available cash generated during the twelve months ended June 30, 2014 would have been sufficient to pay a distribution of $0.1976 per common unit per quarter ($0.7904 per common unit on an annualized basis), or approximately 60.8% of the minimum quarterly distribution, during that period, and we would not have been able to pay any distributions on our subordinated units during that period.

 

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    We believe, based on our financial forecast and related assumptions included in "Cash Distribution Policy and Restrictions on Distributions—Estimated Distributable Cash Flow for the Twelve Months Ending June 30, 2015," that we will have sufficient available cash to pay the aggregate minimum quarterly distribution of $47.4 million on all of our common units and subordinated units for the twelve months ending June 30, 2015. However, we do not have a legal obligation to pay distributions at our minimum quarterly distribution rate or at any other rate except as provided in our partnership agreement and there is no guarantee that we will make quarterly cash distributions to our unitholders. Please read "Cash Distribution Policy and Restrictions on Distributions."

Subordinated units

 

Lonestar and certain members of our management will initially own approximately 90.2% of our subordinated units. The principal difference between our common units and our subordinated units is that for any quarter during the subordination period, the subordinated units will not be entitled to receive any distribution until the common units have received the minimum quarterly distribution for such quarter plus any arrearages in the payment of the minimum quarterly distribution from prior quarters during the subordination period. Subordinated units will not accrue arrearages.

Conversion of subordinated units

 

The subordination period will end on the first business day after we have earned and paid at least (i) $1.30 (the minimum quarterly distribution on an annualized basis) on each outstanding common unit and subordinated unit for each of three consecutive, non-overlapping four-quarter periods ending on or after September 30, 2017 or (ii) $1.95 (150.0% of the annualized minimum quarterly distribution) on each outstanding common unit and subordinated unit and the related distributions on the incentive distribution rights for any four-quarter period ending on or after September 30, 2015, in each case provided there are no arrearages on our common units at that time.

 

 

The subordination period also will end upon the removal of our general partner other than for cause if no subordinated units or common units held by the holders of subordinated units or their affiliates are voted in favor of that removal.

 

 

When the subordination period ends, all subordinated units will convert into common units on a one-for-one basis, and all common units will no longer be entitled to arrearages. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period."

 

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Issuance of additional units   Our partnership agreement authorizes us to issue an unlimited number of additional units without the approval of our unitholders. Our unitholders will not have preemptive or participation rights to purchase their pro rata share of any additional units issued. Please read "Units Eligible for Future Sale" and "Our Partnership Agreement—Issuance of Additional Securities."

Limited voting rights

 

Our general partner will manage and operate us. Unlike the holders of common stock in a corporation, our unitholders will have only limited voting rights on matters affecting our business. Our unitholders will have no right to elect our general partner or its directors on an annual or other continuing basis. Our general partner may not be removed except by a vote of the holders of at least 662/3% of our outstanding units, including any units owned by our general partner and its affiliates, voting together as a single class. Upon consummation of this offering, affiliates of our general partner, including Lonestar, will own an aggregate of 56.1% of our common and subordinated units (or 11.9% and 90.2%, respectively, of our common and subordinated units, if the underwriters exercise their option to purchase additional common units in full). This will give affiliates of our general partner, including Lonestar, the ability to prevent the removal of our general partner. Please read "Our Partnership Agreement—Voting Rights."

Limited call right

 

If at any time our general partner and its affiliates own more than 80.0% of our outstanding common units, our general partner has the right, but not the obligation, to purchase all of our remaining common units at a price equal to the greater of (i) the average of the daily closing price of our common units over the 20 trading days preceding the date that is three business days before notice of exercise of the call right is first mailed and (ii) the highest per-unit price paid by our general partner or any of its affiliates for common units during the 90-day period preceding the date such notice is first mailed. At the completion of this offering and assuming no exercise of the underwriters' option to purchase additional common units, our general partner and its affiliates will own approximately 22.1% of our common units. Please read "Our Partnership Agreement—Limited Call Right."

 

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Redemption of ineligible holders   Units held by persons who our general partner determines are not "citizenship eligible holders" or "rate eligible holders" will be subject to redemption. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, and will generally include individuals and entities who are United States citizens. Rate eligible holders are:

 

individuals or entities subject to United States federal income taxation on the income generated by us; or

 

entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity's owners are domestic individuals or entities subject to such taxation.


 

 

We will have the right, which we may assign to any of our affiliates, but not the obligation, to redeem all of the common units of any holder that is not a citizenship eligible holder or a rate eligible holder or that has failed to certify or has falsely certified that such holder is a citizenship eligible holder or a rate eligible holder. The redemption price will be equal to the market price of the common units as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. The units held by any person the general partner determines is not a citizenship eligible holder or a rate eligible holder will not be entitled to voting rights.

 

 

Please read "Our Partnership Agreement—Redemption of Ineligible Holders."

Estimated ratio of taxable income to distributions

 

We estimate that if you own the common units you purchase in this offering through the record date for distributions for the period ending December 31, 2017, you will be allocated, on a cumulative basis, an amount of federal taxable income for that period that will be 20% or less of the cash distributed to you with respect to that period. For example, if you receive an annual distribution of $1.30 per unit, we estimate that your average allocable federal taxable income per year will be no more than approximately $0.26 per unit. Thereafter, the ratio of allocable taxable income to cash distributions to you could substantially increase. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Ratio of Taxable Income to Distributions" for the basis of this estimate.

 

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Material federal income tax consequences   For a discussion of the material federal income tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States, please read "Material Federal Income Tax Consequences."

Directed Unit Program

 

At our request, the underwriters have reserved for sale up to 5.0% of the common units being offered by this prospectus for sale at the initial public offering price to the directors, director nominees and executive officers of our general partner and certain other employees and consultants of our general partner and its affiliates. We do not know if these persons will choose to purchase all or any portion of these reserved common units, but any purchases they do make will reduce the number of common units available to the general public. Please read "Underwriting—Directed Unit Program."

Exchange listing

 

We have been approved to list our common units on the New York Stock Exchange under the symbol "JPEP."

 

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Summary Historical and Pro Forma Combined Consolidated Financial and Operating Data

        The table set forth below presents, as of the dates and for the periods indicated, our summary historical and pro forma combined consolidated financial and operating data.

        The summary historical consolidated financial data presented as of December 31, 2012 and December 31, 2013 and for the years ended December 31, 2011, December 31, 2012 and December 31, 2013 have been derived from our audited historical consolidated financial statements included elsewhere in this prospectus. The summary historical consolidated financial data presented as of June 30, 2013 and June 30, 2014 and for the six months ended June 30, 2013 and June 30, 2014 are derived from our unaudited historical condensed consolidated financial statements.

        The summary pro forma combined consolidated statement of operations for the six months ended June 30, 2014 includes the pro forma effects of the recapitalization transactions, including this offering, described under "—Recapitalization Transactions and Partnership Structure" as if the recapitalization transactions, including this offering, occurred on January 1, 2013. The summary pro forma combined consolidated balance sheet as of June 30, 2014 was prepared as if the recapitalization transactions, including this offering, occurred on June 30, 2014. The summary pro forma combined consolidated statement of operations for the year ended December 31, 2013 gives effect to (i) our acquisition of the Silver Dollar Pipeline System as if it had occurred on January 1, 2013 and (ii) the recapitalization transactions, including this offering, as if they had occurred on January 1, 2013.

        During 2013, we determined that our previously issued audited consolidated financial statements as of December 31, 2012 and results of operations for the year ended December 31, 2012 contained errors. We evaluated those errors and determined that the impact of these errors was material to the results of operations for the year ended December 31, 2012. Accordingly, our previously audited consolidated balance sheet at December 31, 2012 and the statement of operations and statement of cash flows for the year ended December 31, 2012 have been restated to reflect the correction of the errors, including the correction of immaterial errors. Please read note 3 of our consolidated financial statements included elsewhere in this prospectus.

        On February 12, 2014, we acquired certain assets from JP Development. Because we and JP Development are both affiliates of ArcLight, this was a transaction between commonly controlled entities and we were required to account for the transaction in a manner similar to the pooling of interest method of accounting. Under this method of accounting, we reflected in our balance sheet the acquired assets at JP Development's historical carryover basis instead of reflecting the fair market value of assets and liabilities of the acquired assets. In addition, we have retrospectively adjusted our financial statements to include the operating results of the acquired assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began). Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—JP Development Acquisition and Recast of Historical Financial Statements."

        For a detailed discussion of the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with our unaudited pro forma combined consolidated financial statements and audited and unaudited consolidated financial statements included elsewhere in this prospectus. Among other things, those historical and pro forma combined consolidated financial statements include more detailed information regarding the basis of presentation for the information in the following table.

        The following table presents Adjusted EBITDA, distributable cash flow and adjusted gross margin, financial measures that are not presented in accordance with GAAP. We use Adjusted EBITDA, distributable cash flow and adjusted gross margin in our business as we believe they are important supplemental measures of our performance. We define Adjusted EBITDA as net income (loss) plus (minus) interest expense (income), income tax expense (benefit), depreciation and amortization expense, asset impairments, (gains) losses on asset sales, certain non-cash charges such as non-cash

 

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equity compensation, non-cash vacation expense, non-cash (gains) losses on commodity derivative contracts (total (gain) loss on commodity derivatives less net cash flow associated with commodity derivatives settled during the period) and selected (gains) charges and transaction costs that are unusual or non-recurring. We define distributable cash flow as Adjusted EBITDA less net cash interest paid, income taxes paid and maintenance capital expenditures. We define adjusted gross margin as total revenues minus cost of sales, excluding depreciation and amortization, and certain non-cash charges such as non-cash vacation expense and non-cash gains (losses) on derivative contracts (total gains (losses) on commodity derivatives less net cash flow associated with commodity derivatives settled during the period).

        For a reconciliation of Adjusted EBITDA, distributable cash flow and adjusted gross margin to their most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures." For a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."

 

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  Pro Forma  
 
   
   
   
  Six Months
Ended
June 30,
 
 
  Year Ended December 31,    
  Six Months
Ended
June 30,
2014
 
 
  Year Ended
December 31,
2013
 
($ in thousands, except per unit amounts)
  2011   2012(1)   2013(1)   2013   2014  
 
   
  (Restated
and Recast)

   
  (unaudited)
  (unaudited)
 

Statement of Operations Data:

                                           

Total revenue

  $ 67,156   $ 427,581   $ 2,102,233   $ 987,804   $ 865,817   $ 2,105,201   $ 865,817  

Costs and expenses:

                                           

Cost of sales, excluding depreciation and amortization

    49,048     368,791     1,964,631     918,957     798,193     1,964,631     798,193  

Operating expenses

    9,584     28,640     61,925     28,202     35,266     62,996     35,266  

General and administrative

    6,053     20,983     45,284     20,313     23,879     45,699 (2)   23,838 (2)

Depreciation and amortization

    2,841     13,856     33,345     15,186     20,165     36,524     20,165  

Loss on disposal of assets

    68     1,142     1,492     998     661     1,492     661  
                               

Operating income (loss)

    (438 )   (5,831 )   (4,444 )   4,148     (12,347 )   (6,141 )   (12,306 )

Other income (expense):

                                           

Interest (expense)

    (633 )   (3,405 )   (9,075 )   (3,815 )   (5,551 )   (4,714 )   (2,308 )

Loss on extinguishment of debt

    (95 )   (497 )           (1,634 )        

Other income, net

        247     688     195     504     688     504  
                               

Income (loss) before income taxes

    (1,166 )   (9,486 )   (12,831 )   528     (19,028 )   (10,167 )   (14,110 )

Income tax (expense) benefit

    (35 )   (222 )   (208 )   (305 )   (156 )   (227 )   (156 )
                               

Net income (loss) from continuing operations

    (1,201 )   (9,708 )   (13,039 )   223     (19,184 )   (10,394 )   (14,266 )

Net income (loss) from discontinued operations(3)

        1,320     (1,182 )   (23 )   (9,608 )        
                               

Net income (loss)

  $ (1,201 ) $ (8,388 ) $ (14,221 ) $ 200   $ (28,792 ) $ (10,394 ) $ (14,266 )

General partner's interest in pro forma net income (loss)

                                           

Common unit holder's interest in pro forma net income (loss)

                                  (5,197 )   (7,133 )

Subordinated unit holder's interest in pro forma net income (loss)

                                  (5,197 )   (7,133 )

Pro forma net income per common unit

                                  (0.29 )   (0.39 )

Pro forma net income per subordinated unit

                                  (0.29 )   (0.39 )

Weighted average number of limited partner units outstanding

                                           

Common units

                                  18,213,502     18,213,502  

Subordinated units

                                  18,213,502     18,213,502  

Statement of Cash Flows Data:

                                           

Cash provided by (used in):

                                           

Operating activities

  $ (5,895 ) $ (6,990 ) $ 13,882   $ 24,778   $ 7,572              

Investing activities(4)

    (26,860 )   (292,334 )   (27,735 )   (13,986 )   (4,936 )            

Financing activities(5)

    34,825     304,991 (4)   6,988     (11,482 )   (4,744 )            

Other Financial Data(6):

                                           

Adjusted gross margin

    18,108     57,203     136,491   $ 68,938   $ 68,553   $ 139,459   $ 68,553  

Adjusted EBITDA

  $ 2,825   $ 14,560   $ 34,284     23,855     12,038     35,527     12,035  

Distributable cash flow

    1,902     11,341     23,755     18,710     6,286     24,288     7,044  

Balance Sheet Data:

                                           

Cash and cash equivalents

  $ 4,432   $ 10,099   $ 3,234   $ 9,409   $ 1,126         $ 108,451  

Accounts receivable, net

    12,246     80,551     122,919     79,038     158,265           50,940  

Property, plant and equipment, net

    27,720     191,864     238,093     194,201     232,690           232,690  

Total assets

    65,931     562,124     843,402     556,910     842,472           839,713  

Total long-term debt (including current maturities)      

    16,948     167,739     184,846     165,901     183,322           76,722  

Total partners' capital

    41,466     314,153     533,393     308,808     505,506           609,601  

Operating Data(7):

                                           

Crude oil pipeline throughput (Bbl/d)

            13,738 (7)       19,652     8,885 (8)   19,652  

Crude oil sales (Bbl/d)

        24,201     53,471     51,372     42,411     53,471     42,411  

Refined products terminals throughput (Mgal/d)            

        2,400     2,901     2,834     2,699     2,901     2,699  

NGL and refined product sales (Gal/d)

    61,314     128,775     180,850     182,463     199,016     180,850     199,016  

(1)
Our historical combined consolidated financial and operating data for the years ended December 31, 2012 and 2013 have been retrospectively adjusted for the JP Development Dropdown. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—JP Development Acquisition and Recast of Historical Financial Statements."

 

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(2)
Includes the impact of professional fees of approximately $14.1 million and $5.8 million for the pro forma combined year ended December 31, 2013 and the pro forma combined six months ended June 30, 2014, respectively, a significant portion of which we do not expect to incur in future periods. Excludes estimated incremental cash expense associated with being a publicly traded partnership of approximately $3.5 million, including costs associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent fees, incremental officer and director liability expenses and director compensation.

(3)
In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

(4)
Cash used in investing activities includes the cash consideration paid for third party acquisitions during the years ended December 31, 2011, 2012 and 2013, as described in greater detail in "Management's Discussion and Analysis of Financial Condition and Results of Operations."

(5)
Cash provided by financing activities for the year ended December 31, 2012 includes the issuance of units and borrowings under our 2011 revolving credit facility to finance the purchase of certain third party acquisitions during the year ended December 31, 2012, as described in greater detail in "Management's Discussion and Analysis of Financial Condition and Results of Operations."

(6)
Adjusted gross margin, Adjusted EBITDA and distributable cash flow are financial measures that are not presented in accordance with GAAP. Please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures."

(7)
Represents the average daily throughput volume in our crude oil pipelines and storage segment, the average daily sales volume in our crude oil supply and logistics segment, the average daily throughput volume in our refined products terminals and storage segment and the average daily sales volume in our NGL distribution and sales segment.

(8)
The Silver Dollar Pipeline System was placed into service in April 2013 and acquired by us in October 2013. Average throughput for the year ended December 31, 2013 represents throughput from the date of acquisition through year end, while average throughput for the pro forma year ended December 31, 2013 represents throughput from the date the Silver Dollar Pipeline System was placed into service through year end.

 

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RISK FACTORS

        Investing in our common units involves a high degree of risk. You should carefully consider the risks described below with all of the other information included in this prospectus before deciding to invest in our common units. Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. If any of the following risks actually occur, they may materially harm our business and our financial condition and results of operations. In this event, we might not be able to pay distributions on our common units, the trading price of our common units could decline and you could lose part or all of your investment.


Risks Related to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to pay the minimum quarterly distribution, or any distribution, to holders of our common and subordinated units.

        In order to pay the minimum quarterly distribution of $0.3250 per unit per quarter, or $1.30 per unit on an annualized basis, we will require available cash of approximately $11.8 million per quarter, or $47.4 million per year, based on the number of common and subordinated units that will be outstanding immediately after completion of this offering. We may not have sufficient available cash from operating surplus each quarter to enable us to pay the minimum quarterly distribution.

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

    the price of, and the demand for, crude oil, refined products and NGLs in the markets we serve;

    the volumes of crude oil that we gather, transport and store, the throughput volumes at our refined products terminals and our NGL sales volumes;

    the fees we receive for the crude oil, refined products and NGL volumes we handle;

    pressures from our competitors, some of which may have significantly greater resources than us;

    the cost of propane that we buy for resale, including due to disruptions in its supply, and whether we are able to pass along cost increases to our customers;

    competitive pressures from other energy sources such as natural gas, which could reduce existing demand for propane;

    the risk of contract cancellation, non-renewal or failure to perform by our customers, and our inability to replace such contracts and/or customers;

    leaks or releases of hydrocarbons into the environment that result in significant costs and liabilities;

    the level of our operating, maintenance and general and administrative expenses; and

    regulatory action affecting our existing contracts, our operating costs or our operating flexibility.

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

    the level of capital expenditures we make;

    our cost of acquisitions, if any;

    our debt service requirements and other liabilities;

    expenses that our general partner incurs on our behalf and are reimbursed by us, which expenses are not subject to any caps or other limits pursuant to our partnership agreement;

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    fluctuations in our working capital needs;

    our ability to borrow funds and access the capital markets;

    restrictions contained in our revolving credit facility and other debt agreements;

    the amount of cash reserves established by our general partner; and

    other business risks affecting our cash levels.

On a pro forma basis we would not have had sufficient distributable cash flow to pay the full minimum quarterly distribution on all of our units for the year ended December 31, 2013 or for the twelve months ended June 30, 2014, with shortfalls of $23.1 million for the year ended December 31, 2013 and $33.0 million for the twelve months ended June 30, 2014.

        The amount of pro forma distributable cash flow generated during the year ended December 31, 2013 was $24.3 million, which would have allowed us to pay 100% of the minimum quarterly distribution on all of our common units during that period, but only $0.0085 per subordinated unit, or approximately 2.6% of the minimum quarterly distribution on our subordinated units, during that period. Specifically, on a pro forma basis, we would have experienced a shortfall of approximately $23.1 million for the year ended December 31, 2013. The amount of pro forma distributable cash flow generated during the twelve months ended June 30, 2014 was $14.4 million, which would have allowed us to pay a distribution of $0.1976 per common unit per quarter ($0.7904 per common unit on an annualized basis), or approximately 60.8% of the minimum quarterly distribution, during that period, and we would not have been able to pay any distributions on our subordinated units during that period. Specifically, on a pro forma basis, we would have experienced a shortfall of approximately $33.0 million for the twelve months ended June 30, 2014. For a calculation of our ability to make cash distributions to our unitholders based on our historical as adjusted results, please read "Cash Distribution Policy and Restrictions on Distributions." If we are not able to generate additional cash for distribution to our unitholders in future periods, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.

The assumptions underlying the forecast of Adjusted EBITDA, distributable cash flow and adjusted gross margin that we include in "Cash Distribution Policy and Restrictions on Distributions" are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks and uncertainties that could cause actual results to differ materially from those forecasted.

        The forecast set forth in "Cash Distribution Policy and Restrictions on Distributions" includes our forecasted results of operations, Adjusted EBITDA, distributable cash flow and adjusted gross margin for the twelve months ending June 30, 2015. The financial forecast has been prepared by management, and we have not received an opinion or report on it from our or any other independent auditor. The assumptions underlying the forecast are inherently uncertain and are subject to significant business, economic, financial, regulatory and competitive risks, including risks that expansion projects do not result in an increase in transported, sold and stored volumes, and uncertainties that could cause actual results to differ materially from those forecasted. If we do not achieve the forecasted results, we may not be able to pay the full minimum quarterly distribution or any amount on our common or subordinated units, in which event the market price of our common units may decline materially.

A sustained decrease in demand for crude oil, refined products or NGLs in the areas we serve could reduce our revenues.

        A sustained decrease in demand for crude oil, refined products or NGLs in the areas we serve could reduce our revenues, which could have a material adverse effect on our financial condition,

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results of operations and cash flows. Factors that could lead to a decrease in market demand for crude oil, refined products or NGLs include:

    lower demand by consumers for refined products or crude oil as a result of adverse economic conditions, an increase in the market price of crude oil, an increase in the market price of gasoline or other refined products, use by consumers of alternative fuels or an increase in the fuel economy of vehicles;

    lower drilling activity in the areas served by our crude oil gathering and transportation business as a result of a decrease in the market price of crude oil or for other reasons; and

    fluctuations in the demand for crude oil, such as those caused by refinery downtime or shutdowns.

        Certain of our operating costs and expenses are fixed and do not vary with the volumes we transport or redeliver. These costs and expenses may not decrease ratably or at all should we experience a reduction in the volumes we sell, transport or redeliver. As a result, we may experience declines in our margin and profitability if our volumes decrease.

We have some short-term contracts and other contracts that can be canceled on 60 days' notice and will have to be renegotiated or replaced periodically. Our failure to replace contracts that are canceled or expire on acceptable terms, or at all, could cause our revenues to decline and reduce our ability to make distributions to our unitholders.

        Many of our contracts in our NGL sales and distribution segment have terms as short as one month, and substantially all of our contracts with customers in our refined products terminals and storage segment have evergreen provisions after an initial term of six months to two years and are cancellable on as little as 60 days' notice. In addition, many of our contracts in our crude oil supply and logistics segment either have terms as short as one month or have evergreen provisions and are cancellable on as little as 60 days' notice. As these NGL or crude oil contracts expire or if a refined products contract is canceled, we may not be able to extend, renegotiate or replace these contracts and the terms of any renegotiated contracts may not be as favorable as the contracts they replace. In addition, while the majority of the revenue in our crude oil pipelines and storage segment is generated pursuant to long-term contracts, our customers may negotiate for more favorable terms upon any renewal.

        Our ability to extend or replace contracts could be impacted by a number of factors beyond our control, including competition, the level of supply and demand for crude oil and refined products in our areas of operations, general economic conditions and regulatory developments. To the extent we are unable to renew our contracts on terms that are favorable to us, our revenue and cash flows could decline and our ability to make cash distributions to our unitholders could be materially adversely affected.

We face intense competition in all of our business segments. Competitors that are able to supply our customers with similar services or products at a lower price could reduce our revenues.

        We are subject to competition from other providers of crude oil transportation, storage, supply and logistics services, refined products terminals and storage services and NGL distribution and sales services, including national, regional and local companies engaged in these activities. Some of these competitors are substantially larger than us and may have greater financial resources. Our ability to compete could be affected by many factors, including:

    price competition;

    the perception that another company can provide better service; and

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

        In addition, our general partner and its affiliates, including JP Development, Lonestar and ArcLight, may engage in competition with us. If we are unable to compete with services offered by our competitors, including possibly our general partner or its affiliates, it could have a material adverse effect on our financial condition, results of operations and cash flows.

We have material weaknesses in our internal control over financial reporting. If one or more material weaknesses persist or if we otherwise fail to establish and maintain effective internal control over financial reporting, our ability to accurately report our financial results could be adversely affected.

        Prior to the completion of this offering, we have been a private entity with limited accounting personnel and other supervisory resources to adequately execute our accounting processes and address our internal control over financial reporting. In connection with the audits of our financial statements for the years ended December 31, 2011, 2012 and 2013, our independent registered public accounting firm identified material weaknesses in internal control over financial reporting relating to (1) accounting resources and policies (including maintaining an effective control environment), (2) accounting for business combinations and (3) information technology. A "material weakness" is a deficiency, or combination of deficiencies, in internal control over financial reporting, such that there is a reasonable possibility that a material misstatement of our annual or interim financial statements will not be prevented or detected on a timely basis. We did not have sufficient personnel with an appropriate level of accounting knowledge and experience commensurate with our financial reporting requirements. As a result, we did not design and maintain:

    formal accounting policies and formal review controls;

    effective controls over accounting for business combinations, including controls related to the valuation of assets acquired and liabilities assumed, and the integration of the businesses by applying consistent accounting policies and processes to determine compliance with industry standards and regulations; and

    adequate policies and procedures with respect to the primary components of information technology general controls, including the approval and review of access controls, system implementation and migration controls, and change management controls.

        These material weaknesses resulted in audit adjustments in the years ended December 31, 2011, 2012 and 2013 and the three months ended March 31, 2012 and 2013, and six months ended June 30, 2013, and a restatement of our financial statements for the years ended December 31, 2011 and 2012, and the three months ended March 31, 2012 and 2013. Management has determined that the excessive product gains at a refined products terminal described in Note 10 to the consolidated financial statements for the six months ended June 30, 2014 was an additional effect of the material weakness related to business combinations and information technology described above. Also, management has determined that the excessive product gains at a refined products terminal relate to not designing and maintaining effective controls to determine compliance with industry standards and regulations during the integration of the acquired business. As a result, the description of the business combination material weakness at June 30, 2014 was expanded to include this aspect of the material weakness related to integration of acquired businesses.

        While we have begun the process of implementing additional processes and controls related to accounting and financial reporting, we will not complete our implementation until after this offering is completed. During the course of the implementation, we may identify additional control deficiencies, which could give rise to other material weaknesses, in addition to the material weaknesses described above. Each of the material weaknesses described above or any newly identified material weakness could result in a misstatement of our accounts or disclosures that would result in a material

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misstatement of our annual or interim consolidated financial statements that would not be prevented or detected.

If we do not properly maintain and improve our measurement and quality control processes and procedures across all of our business segments, we may have measurement and quality errors or contamination, which may result in lost revenues or the incurrence of additional costs.

        We are implementing measurement and quality control processes and procedures across all of our business segments. To the extent we do not properly maintain and improve such procedures, we may have measurement and quality errors or contamination that could result in lost revenues or the incurrence of additional costs. For example, in the third quarter of 2014 we became aware that certain of our measurement and quality control processes at our North Little Rock terminal were not in compliance with certain industry standards and had resulted in excessive product gains for the North Little Rock terminal. We have notified our customers and are in the process of returning a certain amount of refined products to such customers for the period from November 2012 (the month we acquired the North Little Rock terminal) through July 2014. If we are unable to reach a resolution on this matter, customers may assert claims against us for damages. The uncertainties of litigation and the uncertainties related to the collection of insurance and indemnification coverage make it difficult to accurately predict the ultimate financial effect of these claims, if any are ultimately asserted. If we are unsuccessful in defending a claim or elect to settle a claim, we could incur costs that could have a negative effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

We are not currently required to make an assessment of our internal control over financial reporting.

        We are not currently required to comply with the SEC's rules implementing Section 404 of the Sarbanes Oxley Act of 2002 ("Sarbanes Oxley") and are therefore not required to make a formal assessment of the effectiveness of our internal control over financial reporting for that purpose. Upon becoming a publicly traded partnership, we will be required to comply with the SEC's rules implementing Sections 302 and 404 of Sarbanes Oxley, which will require our management to certify financial and other information in our quarterly and annual reports and provide an annual management report on the effectiveness of our internal control over financial reporting. Although we will be required to disclose changes made to our internal control over financial reporting and procedures on a quarterly basis, we will not be required to make our first annual assessment of our internal control over financial reporting pursuant to Section 404 of Sarbanes Oxley and our independent registered public accounting firm will not be required to issue an attestation report on the effectiveness of our internal control over financial reporting until the fiscal year ending December 31, 2015. In order to have effective control over financial reporting, we will need to implement additional internal controls, reporting systems and procedures.

        Given the difficulties inherent in the design and operation of internal control over financial reporting, we can provide no assurance as to our, or our independent registered public accounting firm's, future conclusions about the effectiveness of our internal control over financial reporting, and we may incur significant costs in our efforts to comply with Section 404. Any failure to implement and maintain effective internal control over financial reporting will subject us to regulatory scrutiny and could result in a loss of confidence in our reported financial information, which could have an adverse effect on our business and would likely have a negative effect on the trading price of our common units.

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Because of the natural decline in production from our customers' existing wells in our areas of operation, we depend, in part, on producers replacing declining production and also on our ability to secure new sources of crude oil. Any decrease in the volumes of crude oil that we transport could adversely affect our business and operating results.

        The crude oil volumes that support our crude oil pipelines and storage segment and crude oil supply and logistics segment depend on the level of production from crude oil wells on which we rely for throughput or sales and transportation volumes, which may be less than expected and will naturally decline over time. As a result, our cash flows associated with these wells will also decline over time. In order to maintain or increase throughput or sales and transportation volumes in these segments, we must obtain new sources of crude oil. In our crude oil pipelines and storage segment, the primary factors affecting our ability to obtain non-dedicated sources of crude oil include (i) the level of successful drilling activity in our areas of operation, (ii) our ability to compete for volumes from successful new wells and (iii) our ability to compete successfully for volumes from sources connected to other pipelines.

        We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells on which we rely for throughput or sales and transportation volumes or the rate at which production from such wells declines. In addition, we have no control over producers or their drilling or production decisions, which are affected by, among other things:

    the availability and cost of capital;

    prevailing and projected oil, natural gas and NGL prices;

    demand for oil, natural gas and NGLs;

    levels of reserves;

    geological considerations;

    environmental or other governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and

    the availability of drilling rigs and other costs of production and equipment.

        Fluctuations in energy prices can also greatly affect the development of oil reserves. Drilling and production activity generally decreases as oil prices decrease. Declines in oil prices could have a negative impact on exploration, development and production activity, and if sustained, could lead to a material decrease in exploration and production activity. Any sustained decline of exploration or production activity in our areas of operation could lead to reduced utilization of our assets.

        Because of these and other factors, even if oil reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. If reductions in drilling activity result in our inability to maintain throughput in our crude oil pipelines and storage segment and our sales and transportation volumes in our crude oil supply and logistics segment, our revenue and cash flow could be reduced and our ability to make cash distributions to our unitholders could be adversely affected.

We do not intend to obtain independent evaluations of oil reserves connected to our Silver Dollar Pipeline System on a regular or ongoing basis; therefore, in the future, volumes of oil on our Silver Dollar Pipeline System could be less than we anticipate.

        We do not intend to obtain independent evaluations of oil reserves connected to our Silver Dollar Pipeline System on a regular or ongoing basis. Accordingly, we may not have independent estimates of total reserves dedicated to our Silver Dollar Pipeline System or the anticipated life of such reserves. If the total reserves or estimated life of the reserves connected to our Silver Dollar Pipeline System are less than we anticipate and if our customers are unable to secure additional sources of crude oil production it could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

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Our success in our crude oil pipelines business depends, in part, on drilling activity and our ability to attract and maintain customers in a limited number of geographic areas.

        Our Silver Dollar Pipeline System is located in the Southern Wolfcamp and we intend to focus future capital expenditures on developing our business in this area. Due to our focus on the Southern Wolfcamp, an adverse development in oil production from this area would have a greater impact on our financial condition and results of operations than if we spread expenditures more evenly over a wider geographic area. For example, a change in the rules and regulations governing operations in or around the Southern Wolfcamp basin could cause producers to reduce or cease drilling or to permanently or temporarily shut-in their production within the area, which could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We may not be able to increase throughput and resulting revenue due to competition and other factors, which could limit our ability to grow our crude oil pipelines and storage segment.

        Our ability to increase our throughput and resulting revenue is subject to numerous factors beyond our control, including competition from third parties and the extent to which our Silver Dollar Pipeline System has available takeaway capacity. To the extent that we lack available capacity on our Silver Dollar Pipeline System for additional volumes, we may not be able to compete effectively with third-party systems for additional oil production in our areas of operation. In addition, our efforts to attract new customers may be adversely affected by our desire to provide services pursuant to contracts that are effectively fee-based. Our potential customers may prefer to obtain services pursuant to other forms of contractual arrangements under which we would be required to assume direct commodity exposure.

Our crude oil supply and logistics operations involve market and regulatory risks.

        As part of our crude oil supply and logistics activities, we purchase crude oil at prices determined by prevailing market conditions. Following our purchase of crude oil, we generally resell crude oil at a higher price under a sales contract that is generally comparable in terms to our purchase contract, including any price escalation provisions. The profitability of our crude oil logistics operations may be affected by the following factors:

    our ability to negotiate crude oil purchase and sales agreements in changing markets on a timely basis;

    reluctance of customers to enter into long-term purchase contracts;

    consumers' willingness to use other fuels instead of the end products in the crude oil supply chain;

    the timing of imbalance or volume discrepancy corrections and their impact on our financial results;

    the ability of our customers to make timely payment; and

    any inability we may have to match purchase and sale of crude oil on comparable terms.

We depend on a relatively limited number of customers for a significant portion of our revenues. The loss of, or material nonpayment or nonperformance by, any one or more of these customers could adversely affect our ability to make cash distributions to our unitholders.

        We rely on a limited number of customers for a substantial portion of our revenues. Glencore Ltd. and Chesapeake Energy Marketing, Inc. each accounted for more than 10% of our total revenue for the year ended December 31, 2013, at approximately 50% and 13%, respectively. Parnon Energy, Inc. and Glencore, Ltd. each accounted for more than 10% of our total revenue for the year ended December 31, 2012, at approximately 30% and 17%, respectively. Glencore, Ltd., Chesapeake Energy Marketing, Inc. and Phillips 66 each accounted for more than 10% of our total revenue for the six

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months ended June 30, 2014, at approximately 37%, 15% and 12%, respectively. Glencore, Ltd. accounted for more than 10% of our total revenue for the six months ended June 30, 2013, at approximately 50%. We may be unable to negotiate extensions or replacements of contracts with our key customers on favorable terms or at all. In addition, these key customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. Furthermore, our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. The loss of all or even a portion of the contracted volumes of these key customers, as a result of competition, creditworthiness or otherwise, could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

Midstream capacity constraints and interruptions could impact our operations.

        We rely on various midstream facilities and systems in connection with our crude oil supply and logistics operations. Such midstream systems include the systems we operate, as well as systems operated by third parties. When possible, we gain access to midstream systems that provide the most advantageous downstream market prices available to us. Regardless of who operates the midstream systems we rely upon, a portion of the supply in our crude oil supply and logistics business may be interrupted or shut-in from time to time due to loss of access to plants, pipelines or gathering systems. Such access could be lost due to a number of factors, including, but not limited to, weather conditions, accidents, field labor issues or strikes. Additionally, we and third parties may be subject to constraints that limit our ability to construct, maintain or repair midstream facilities needed in connection with our crude oil supply and logistics operations. Such interruptions or constraints could negatively impact our profitability.

The risk management policy governing our crude oil supply activities cannot eliminate all risks associated with our crude oil supply and logistics business, and we cannot ensure that employees of our general partner will fully comply with the policy at all times, both of which could impact our financial and operational results and, in turn, our ability to make cash distributions to our unitholders.

        We have in place a risk management policy that seeks to establish limits for the exposure in our crude oil supply and logistics business by requiring that we restrict net open positions through the concurrent purchase and sale of like quantities of crude oil to create transactions intended to lock in positive margins based on the timing, location or quality of the crude oil purchased and delivered. Our risk management policy, however, cannot eliminate all risks. Any event that disrupts our anticipated physical supply of crude oil could create a net open position that would expose us to risk of loss resulting from price changes.

        Moreover, we are exposed to price movements on products that are not hedged, including certain of our inventory, such as linefill, which must be maintained to operate our crude oil pipeline system. We are also exposed to certain price risks related to basis differentials. Basis differentials can be created to the extent that we hold or sell crude oil of a grade or quality at a location or at a time that differs from the specific delivery terms with respect to grade, quality, time or location of the applicable offsetting agreement. If this occurs, we may not be able to use the physical markets to fully hedge our price risk. Our exposure to price risks could impact our operational and financial results and our ability to make cash distributions to our unitholders.

        We are also subject to the risk that employees of our general partner involved in our crude oil supply operations may not comply at all times with our risk management policy. We cannot ensure that all violations of our risk management policy, particularly if deception or other intentional misconduct is involved, will be detected prior to our businesses being materially affected.

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A prolonged decline in index prices at Cushing, relative to other index prices, could reduce the demand for the services we provide in our crude oil storage business.

        In recent years, a shortfall in takeaway pipeline capacity has at times led to an oversupply of crude oil at Cushing. This was cited as a principal reason for the decline in the West Texas Intermediate Index ("WTI Index") price used at Cushing relative to other crude oil price indexes, including the Brent Crude Index over the same period. While the WTI Index price has recovered compared to the Brent Crude Index, a renewed decline in the WTI Index price relative to other index prices may reduce demand for our transportation of crude oil to, and storage at our facility in, Cushing, which could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders.

The results of our crude oil storage business could be adversely affected during periods in which the overall forward market for crude oil is backwardated.

        The results of our crude oil storage business are influenced by the overall forward market for crude oil. A contango market (meaning that the price of crude oil for future delivery is higher than the current price) has a favorable impact on the demand for crude oil storage as it allows a party to simultaneously purchase crude oil at current prices for storage and sell at higher prices for future delivery. Conversely, a backwardated market (meaning that the price of crude oil for future deliveries is lower than current prices) can negatively affect the demand for crude oil storage because there is little incentive to store crude oil when prices offered for future delivery are expected to be lower. Accordingly, a backwardated market can negatively impact the demand for crude oil storage. If the forward market for crude oil is backwardated at times when we are renewing our crude oil storage contract or entering into new crude oil storage contracts, it could adversely affect the results in our crude oil storage business.

All of our operations have indirect exposure to changes in commodity prices and some of our operations have direct exposure to commodity price changes.

        Our operations have limited direct exposure to changes in commodity prices. However, the volumes of crude oil that we transport, store or supply, refined products that we handle and NGLS that we distribute and sell are indirectly affected by commodity prices because many of our customers have direct exposure to commodity prices. If our customers are negatively impacted by changes in commodity prices, they may, among other things, reduce the services they purchase from us. For example, lower crude oil prices could suppress drilling activity, which would reduce demand for our crude oil pipeline, storage or supply and logistics services, while higher refined products prices could decrease consumer demand for refined products, which could reduce demand for services we provide at our refined products terminals.

        In addition, in our refined products terminals and storage segment, we also generate revenue from (i) blending activities, such as ethanol blending and butane blending, and (ii) our vapor recovery units. Our blending activities are subject to direct commodity price exposure. Any significant reduction in the amount of services we provide to our customers because of direct or indirect commodity price exposure and any significant reduction in the refined products that we sell could have a material adverse effect on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

We do not operate our crude oil storage facility.

        TEPPCO Partners L.P., a wholly owned subsidiary of Enterprise Products Partners L.P., serves as the operator of our crude oil storage facility. Under the operating agreement governing TEPPCO's operation of our facility, we are liable for any losses or claims arising from damage to our property or personal injury claims of our personnel that may result from the actions of the operator, even if such losses or claims result from the operator's gross negligence or willful misconduct. If disputes arise over

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operation of our crude oil storage facility, or if our operator fails to provide the services contracted under the agreement, our business, results of operation, financial condition and ability to make cash distributions to our unitholders could be adversely affected.

Increased trucking regulations may increase our costs or make it more difficult for us to attract or retain qualified drivers, which could negatively affect our results of operations.

        In connection with the services we provide, we operate as a motor carrier and, therefore, are subject to regulation by the Department of Transportation (the "DOT"), and by various state agencies. These regulatory authorities exercise broad powers, governing activities such as the authorization to engage in motor carrier operations and regulatory safety. There are additional regulations specifically relating to the trucking industry that we are subject to, including testing and specification of equipment and product handling requirements. The trucking industry is subject to possible regulatory and legislative changes that may affect the economics of the industry by requiring changes in operating practices or by changing the demand for common or contract carrier services or the cost of providing truckload services. These possible changes include increasingly stringent environmental regulations, changes in the regulations that govern the amount of time a driver may drive in any specific period, onboard black box recorder devices or limits on vehicle weight and size.

        In addition, the already substantial competition for qualified drivers in the trucking industry may increase because of regulatory requirements. For instance, Comprehensive Safety Analysis 2010 ("CSA") has been implemented by the Federal Motor Carrier Safety Administration, an agency of the DOT, to monitor and improve commercial motor vehicle safety by measuring the safety record of both the motor carrier and the driver. The requirements of CSA could shrink the pool of qualified drivers and increase the costs we incur in order to attract, train and retain qualified drivers. In addition, a shortage of qualified drivers could increase driver turnover rates, which might limit growth in our crude oil supply and logistics or other segments.

Our refined products terminals are dependent upon their interconnections with terminals and pipelines owned and operated by others.

        Our refined products terminals are dependent upon their interconnections with other terminals and pipelines owned and operated by third parties to reach end markets and as a significant source of supply. Our North Little Rock terminal is supplied by the TEPPCO Pipeline while our Caddo Mills terminal is supplied by the Explorer Pipeline. Reduced or interrupted throughput on these pipelines or outages at terminals with which our refined products terminals share interconnects because of weather or other natural events, testing, line repair, damage, reduced operating pressures or other causes could result in our being unable to deliver refined products to our customers from our terminals or receive products for storage at our terminals, which could adversely affect our cash flows and revenues. In addition, in the event that one of the pipelines depended upon by either of our refined products terminals modifies its tariff to discontinue service for one or more of the products throughput at our terminals, we will have to discontinue selling or secure an alternate supply of such product. This could have a material adverse impact on the throughput volumes and revenues of our refined products terminals and storage segment.

The assets in our refined products terminals and storage segment have been in service for several decades.

        Our refined products terminals and storage assets are generally long-lived assets. Our North Little Rock terminal has been in service for approximately 34 years, and our Caddo Mills terminal has been in service for approximately 29 years. The age and condition of these assets could result in increased maintenance or remediation expenditures. Any significant increase in these expenditures could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

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Warm weather in the winter heating season or inclement weather in the summer grilling season could lower demand for propane.

        Weather conditions have a significant impact on the demand for propane for both heating and agricultural purposes. Many of our customers rely on propane primarily as a heating source during the winter. For the year ended December 31, 2013, on a pro forma basis, we sold approximately 61% of our retail, commercial and wholesale propane volumes during the first and fourth quarters of the year.

        Actual weather conditions can vary substantially from year to year, significantly affecting our financial performance. For example, average temperatures in five of the six states in which we operate our NGL sales business were 21%, 5% and 3% warmer than normal for 2012, 2011 and 2010, respectively, as measured by the number of heating degree days reported by the National Oceanic and Atmospheric Administration (the "NOAA"). For 2013, the average temperature in the six states in which we operate was consistent with the average temperature measured by the NOAA.

        Conversely, our cylinder exchange business experiences higher volumes in the spring and summer, which includes the majority of the grilling season. For the year ended December 31, 2013, on a pro forma basis, we sold approximately 60% of the propane volumes in our cylinder exchange business during the second and third quarters of the year. Sustained periods of poor weather, particularly in the grilling season, can reduce consumers' propensity to purchase and use grills and other propane-fueled appliances, thereby reducing demand for cylinder exchange and our outdoor products.

Sudden and sharp propane cost increases cannot be passed on to customers with contracted pricing arrangements and these contracted pricing arrangements will adversely affect our profit margins if they are not immediately hedged with an offsetting propane purchase commitment.

        Results of operations related to the retail distribution of propane is primarily based on the cents-per-gallon difference between the sales price we charge our customers and our costs to purchase and deliver propane to our propane distribution locations. We enter into propane sales commitments with a portion of our customers that provide for a contracted price agreement for a specified period of time. The propane cost per gallon is subject to various market conditions and may fluctuate based on changes in demand, supply and other energy commodity prices, such as crude oil and natural gas prices. We employ risk management techniques that attempt to mitigate risks related to the purchasing, storing, transporting and selling of propane. However, sudden and sharp propane cost increases cannot be passed on to customers with contracted pricing arrangements. In addition, even upon the expiration of short-term contracts, we may face competitive or relationship pressure to minimize any price increases. Therefore, these commitments expose us to product price risk and reduced profit margins if those transactions are not immediately hedged with an offsetting propane purchase commitment.

High prices for propane can lead to customer conservation and attrition, resulting in reduced demand for our products.

        Propane prices are subject to fluctuations in response to changes in wholesale prices and other market conditions beyond our control. Therefore, our average retail sales prices can vary significantly within a heating season or from year to year as wholesale prices fluctuate with propane commodity market conditions. During periods of high propane costs our selling prices generally increase. High prices can lead to customer conservation and attrition, resulting in reduced demand for our products.

We are dependent on certain principal propane suppliers, which increases the risks from an interruption in supply and transportation.

        During the year ended December 31, 2013 and the six months ended June 30, 2014, we purchased 55% and 66%, respectively, of our propane needs from four suppliers. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from

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alternative locations might be materially higher and our earnings could be affected. Additionally, in certain areas, based on favorable pricing or the strategic location of certain supply points, a single supplier may provide more than 75% of our propane requirements for that area. Although we have relationships with other suppliers in these areas and have the ability to acquire product elsewhere, in the event of a supply disruption with our primary suppliers in certain regions, we could be forced to purchase propane at a less favorable price and with a higher transportation cost. Accordingly, disruptions in supply in certain areas could also have an adverse impact on our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Energy efficiency, advances in technology and competition from other energy sources may affect demand for propane and increases in propane prices may cause our residential customers to increase their conservation efforts.

        The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has generally reduced the demand for propane. Propane also competes with other sources of energy such as electricity, natural gas and fuel oil, some of which can be less costly for equivalent energy value. In particular, the gradual expansion of the nation's natural gas distribution systems has increased the availability of affordable natural gas in rural areas, which historically found propane to be the more cost-effective choice. We cannot predict the effect that future conservation measures, technological advances in heating, conservation, energy generation or other devices or the development of alternative energy sources might have on our operations. As the price of propane increases, some of our customers tend to increase their conservation efforts and thereby decrease their consumption of propane.

If the independently owned third-party haulers that we rely upon for the delivery of propane cylinders from our production facilities to certain of our distribution depots do not perform as expected, or if we or these third-party haulers are not able to manage growth effectively, our relationships with our customers may be adversely impacted and our delivery of propane by cylinder exchange may decline.

        We rely in part on independently owned third-party haulers to deliver cylinders from our production facilities to certain of our distribution depots. Accordingly, our success depends on our ability to maintain and manage relationships with these third-party haulers. We exercise only limited influence over the resources that the third-party haulers devote to the delivery of cylinders. We could experience a loss of consumer or retailer goodwill if our third-party haulers do not adhere to our quality control and service guidelines or fail to ensure the timely delivery of an adequate supply of propane cylinders to certain of our production depots. In addition, the number of retail locations accepting delivery of our propane by cylinder exchange and, subsequently, the retailer's corresponding sales have historically grown significantly along with the creation of our third-party hauler network. Accordingly, our haulers must be able to adequately service an increasing number of propane cylinder deliveries to our distribution depots so that we can service our retail accounts. If we or our third-party haulers fail to manage the growth of our cylinder exchange operations effectively, our financial results from our delivery of propane by cylinder exchange may be adversely affected.

A significant increase in motor fuel costs or other commodity prices may adversely affect our profits.

        Motor fuel is a significant operating expense for us in connection with the operation of both our crude oil supply and logistics and NGL distribution and sales segments. Because we do not attempt to hedge motor fuel price risk, a significant increase in motor fuel prices will result in increased transportation costs to us. The price and supply of motor 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. Additionally, we may be affected by increases in the cost of materials

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used to produce portable propane cylinders. As a result, any increases in these prices may adversely affect our profitability and competitiveness.

Our failure or our counterparties' failure to perform on obligations under commodity derivative and financial derivative contracts could have a material adverse effect on our financial condition, results of operations and cash flows.

        We enter into in hedging arrangements on a rolling twelve-month basis to manage the cost of propane in our cylinder exchange business. We also may from time to time enter into derivative instruments to hedge our exposure to variable interest rates. Volatility in the oil and gas commodities sector for an extended period of time or intense volatility in the near-term could impair our or our counterparties' ability to meet margin calls, which could cause us or our counterparties to default on commodity and financial derivative contracts. This could have a material adverse effect on our liquidity or our ability to procure product supply at prices reasonable to us or at all.

We are exposed to the credit risks, and certain other risks, of our key customers and other counterparties.

        In connection with the acquisition of certain of our assets, we have entered into agreements pursuant to which various counterparties have agreed to indemnify us, subject to certain limitations, for (i) certain pre-closing environmental liabilities discovered within specified time periods after the date of the applicable acquisition, (ii) certain matters arising from the pre-closing ownership and operation of assets and (iii) ongoing remediation related to the assets. Our business, results of operations, financial condition and our ability to make cash distributions to our unitholders could be adversely affected in the future if these third parties fail to satisfy an indemnification obligation owed to us.

We intend to grow our business in part by seeking strategic acquisition opportunities. If we are unable to make acquisitions on economically acceptable terms from JP Development, ArcLight Fund V or third parties, our future growth will be affected, and the acquisitions we do make may reduce, rather than increase, our cash generated from operations on a per unit basis.

        Our ability to grow is dependent, in part, on our ability to make acquisitions that increase our cash generated from operations on a per unit basis. The acquisition component of our strategy is based in large part on our expectation of ongoing divestitures of midstream energy assets by industry participants, including our affiliates. Subject to the right of first offer granted to us, JP Development and ArcLight Fund V are under no obligation to offer to sell us assets and a material decrease in such divestitures by industry participants would limit our opportunities for future acquisitions and could adversely affect our ability to grow our operations and increase our cash distributions to our unitholders.

        If we are unable to make accretive acquisitions, whether because we are (i) unable to identify attractive acquisition candidates or negotiate acceptable purchase contracts, (ii) unable to obtain financing for these acquisitions on economically acceptable terms or (iii) outbid by competitors or for any other reason, then our future growth and ability to increase cash distributions could be limited. Furthermore, even if we do make acquisitions that we believe will be accretive, these acquisitions may nevertheless result in a decrease in the cash generated from our operations on a per unit basis.

        Any acquisition involves potential risks, including, among other things:

    mistaken assumptions about volumes, revenue and costs, including operational synergies;

    an inability to secure adequate customer commitments to use the acquired assets or businesses;

    an inability to successfully integrate the assets or businesses we acquire, particularly given the relatively small size of our management team and its limited history with our assets;

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    the assumption of unknown liabilities;

    limitations on rights to indemnity from the seller;

    unforeseen difficulties operating in new geographic areas and business lines; and

    customer or key employee losses at the acquired businesses.

        If we consummate any future acquisitions, our capitalization and results of operations may change significantly, and our unitholders will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources.

Our right of first offer to acquire certain ArcLight assets and all of JP Development's existing and future assets is subject to risks and uncertainty, and ultimately we may not acquire any of those assets.

        Our Right of First Offer Agreement with JP Development and ArcLight Fund V provides us with a right of first offer on (i) JP Development's existing and future assets for a period of five years from the closing of this offering and (ii) ArcLight Fund V's indirect 50% interest in Republic for a period of eighteen months from the closing of this offering. The consummation and timing of any future acquisitions of these assets will depend upon, among other things, JP Development's and ArcLight Fund V's willingness to offer these assets for sale, our ability to negotiate acceptable purchase agreements and commercial agreements with respect to such assets and our ability to obtain financing on acceptable terms. We can offer no assurance that we will be able to successfully consummate any future acquisitions pursuant to our right of first offer, and JP Development and ArcLight Fund V are under no obligation to accept any offer that we may choose to make in response to any notice by JP Development or ArcLight of their intent to transfer assets. In addition, certain of the assets covered by our right of first offer may require substantial capital expenditures in order to maintain compliance with applicable regulatory requirements or otherwise make them suitable for our commercial needs. For these or a variety of other reasons, we may decide not to exercise our right of first offer if and when any of JP Development's or ArcLight Fund V's assets are offered for sale, and our decision will not be subject to unitholder approval. Please read "Certain Relationships and Related Party Transactions—Agreements With Affiliates in Connection With the Transactions—Right of First Offer Agreement."

Our construction of new assets may not result in revenue increases and will be subject to regulatory, environmental, political, legal and economic risks, which could adversely affect our results of operations and financial condition.

        One of the ways we intend to grow our business is through organic growth projects. The construction of additions or modifications to our existing assets and the construction of new midstream assets involve numerous regulatory, environmental, political, legal and economic uncertainties that are beyond our control. Such expansion projects may also require the expenditure of significant amounts of capital, and financing may not be available on economically acceptable terms or at all. If we undertake these projects, they may not be completed on schedule, at the budgeted cost, or at all. Moreover, our revenue may not increase immediately upon the expenditure of funds on a particular project.

Our growth strategy requires access to new capital. Tightened capital markets or increased competition for investment opportunities could impair our ability to grow.

        We continuously consider potential acquisitions and opportunities for organic growth projects. Our ability to fund our capital projects and make acquisitions depends on whether we can access the necessary financing to fund these activities. Any limitations on our access to capital or increase in the cost of that capital could significantly impair our growth strategy. In addition, a variety of factors

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beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, changes in key benchmark interest rates, the adoption of new or amended banking or capital market laws or regulations, the re-pricing of market risks and volatility in capital and financial markets. Due to these factors, we cannot be certain that funding for our capital needs will be available from bank credit arrangements or the capital markets on acceptable terms. If funding is not available when needed, or is available only on unfavorable terms, we may be unable to implement our growth strategy, enhance our existing business, complete acquisitions and organic growth projects, take advantage of business opportunities or respond to competitive pressures, any of which could have a material adverse effect on our revenues and results of operations.

Our business is subject to federal, state and local laws and regulations that govern the product quality specifications of the crude oil and refined products that we gather, store, transport and handle.

        The crude oil and refined products that we gather, store, transport and handle are sold by our customers for consumption into the public market. Various federal, state and local agencies have the authority to prescribe specific product quality specifications to commodities sold into the public market. Changes in product quality specifications could reduce our throughput volume, require us to incur additional handling costs or require the expenditure of significant capital. In addition, different product specifications for different markets impact the fungibility of products transported and stored in our refined products terminals and could require the construction of additional facilities to segregate products with different specifications. We may be unable to recover these costs through increased revenues.

We are subject to stringent environmental laws and regulations that may expose us to significant costs and liabilities.

        Our operations are subject to stringent and complex federal, state and local environmental laws and regulations that govern the discharge of materials into the environment or otherwise relate to environmental protection. These laws include federal and state laws that impose obligations related to air emissions, regulate the cleanup of hazardous substances that may be or have been released at properties currently or previously owned or operated by us or at locations to which our wastes are or have been transported for disposal, regulate discharges from our facilities into state and federal waters, including wetlands, establish strict liability for releases of oil into waters of the United States, impose requirements for the storage, treatment and disposal of solid and hazardous waste from our facilities, relate to the protection of endangered flora and fauna and impose requirements on the use, storage and disposal of various chemicals and chemical substances at our facilities.

        These laws and regulations may impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital or operating expenditures to limit or prevent releases of materials from our facilities, and the imposition of substantial liabilities and remedial obligations for pollution resulting from our operations or at locations currently or previously owned or operated by us. Joint and several strict liability may be incurred, without regard to fault, under certain of these environmental laws and regulations in connection with discharges or releases of hydrocarbon wastes on, under or from our properties and facilities, some of which have been used for midstream activities for a number of years, oftentimes by third parties not under our control. Private parties, including the owners of the facilities where any wastes we generate are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage. Numerous governmental authorities, such as the Environmental Protection Agency (the "EPA") and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, oftentimes requiring difficult and costly corrective actions or costly pollution control measures. Failure to comply

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with these laws, regulations and permits may result in the assessment of administrative, civil and criminal penalties, the imposition of remedial obligations and the issuance of injunctions limiting or preventing some or all of our operations. In addition, we may experience a delay in obtaining or be unable to obtain required permits or regulatory authorizations, which may cause us to lose potential and current customers, interrupt our operations and limit our growth and revenue. More stringent laws and regulations may be adopted in the future. We may not be able to recover all or any of these costs from insurance.

Climate change legislation or regulatory initiatives could result in increased operating costs and reduced demand for the services we provide.

        On December 15, 2009, the EPA officially published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") 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 allow the EPA to adopt and implement regulations that restrict emissions of GHGs under existing provisions of the Clean Air Act ("CAA"). In June 2010, the EPA adopted the Prevention of Significant Deterioration and Title V Greenhouse Gas Tailoring Rule, which phases in permitting requirements for stationary sources of GHGs, beginning January 2, 2011. This rule "tailors" these permitting programs to apply to certain stationary sources of GHG emissions in a multi-step process, with the largest sources first subject to permitting. In addition, the EPA has adopted a mandatory GHG emissions reporting program that imposes reporting and monitoring requirements on various types of facilities and industries. In November 2010, the EPA expanded its GHG reporting rule to include onshore and offshore oil and natural gas production, processing, transmission, storage, and distribution facilities, requiring reporting of GHG emissions from such facilities on an annual basis. In addition, the EPA has continued to adopt GHG regulations of other industries, such as the March 2012 proposed GHG rule restricting future development of coal-fired power plants.

        While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If Congress undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs on operations and reduce demand for refined products.

        Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would affect our business, any such future laws and regulations could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, oil and gas, which could reduce the demand for crude oil or refined products produced or distributed by our customers, which could in turn reduce revenues we are able to generate by providing services to our customers. Accordingly, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Also, some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations.

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Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil, natural gas and NGL production in our areas of operation, which could adversely impact our business and results of operations.

        Increased regulation of hydraulic fracturing could result in reductions or delays in crude oil, natural gas and NGL production by our customers, which could materially adversely impact our revenues. Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into geographic formations to stimulate hydrocarbon production. Although we do not engage in hydraulic fracturing activities, an increasing percentage of hydrocarbon production by our customers and suppliers is developed from unconventional sources, such as shales, that require hydraulic fracturing as part of the completion process. Hydraulic fracturing is typically regulated by state oil and gas commissions. Some states, including those in which we operate, have adopted, and other states are considering adopting, regulations that could impose more stringent disclosure and/or well construction requirements on hydraulic fracturing operations. In addition, a number of federal agencies, including the EPA and the Department of Energy, are analyzing, or have been requested to review, a variety of environmental issues associated with hydraulic fracturing, and have asserted federal regulatory authority over the process. Moreover, Congress from time to time has proposed legislation to more closely and uniformly regulate hydraulic fracturing at the federal level. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for our customers to perform fracturing to stimulate production from tight formations. Restrictions on hydraulic fracturing could also reduce the volume of hydrocarbons that our customers produce, and could thereby adversely affect our revenues and results of operations.

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance. If a significant accident or event occurs for which we are not adequately insured or if we fail to recover all anticipated insurance proceeds for significant accidents or events for which we are insured, our operations and financial results could be adversely affected.

        Our operations are subject to all of the risks and hazards inherent in the crude oil transportation, storage, supply and logistics, refined products terminals and storage and NGL distribution and sales industries, including:

    damage to our facilities, vehicles and equipment caused by hurricanes, tornadoes, floods, fires and other natural disasters, acts of terrorism and actions by third parties;

    inadvertent damage from construction, vehicles, farm and utility equipment;

    leaks of crude oil, NGLs and other hydrocarbons or losses of crude oil or NGLs as a result of the malfunction of equipment or facilities;

    ruptures, fires and explosions; and

    other hazards that could also result in personal injury, loss of life, pollution or suspension of operations.

        These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example our business interruption/loss of income insurance provides limited coverage in the event of damage to any of our underground storage tanks. In addition, although we are insured for environmental pollution resulting from certain environmental incidents, we may not be insured against all environmental incidents that might occur, some of which may result in toxic tort claims. If a significant incident occurs for which we are not fully insured, it could adversely affect our operations and financial condition. Furthermore, we may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates.

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We are subject to litigation risks that could adversely affect our operating results to the extent not covered by insurance.

        Our operations are subject to all operating hazards and risks normally associated with handling, storing and delivering combustible liquids such as NGLs, refined products and crude oil. We have been, and are likely to continue to be, a defendant in various legal proceedings and litigation arising in the ordinary course of business, both as a result of these operating hazards and risks and as a result of other aspects of our business. We are self-insured for general and product, workers' compensation and automobile liabilities up to predetermined amounts above which third-party insurance applies. We cannot guarantee that our insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that these levels of insurance will be available at economical prices, or that all legal matters that arise will be covered by our insurance programs.

Because our common units will be yield-oriented securities, 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 are likely to increase in the future. As a result, interest rates on our 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 is impacted by our level of our 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, our ability to issue equity or incur debt for acquisitions or other purposes and our ability to make cash distributions at intended levels.

Debt we may incur in the future could limit our flexibility to obtain financing and to pursue other business opportunities.

        Upon the closing of this offering, we expect to have approximately $75.0 million of total indebtedness and $153.7 million available for future borrowings under our revolving credit facility. Our future 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 cash distributions to our unitholders will be reduced by that portion of our cash flow required to make 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 upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory and other factors, some of which are beyond our control. If our operating results are not sufficient to service any future indebtedness, we will 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 not be able to effect any of these actions on satisfactory terms or at all.

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Restrictions in our revolving credit facility could adversely affect our business, financial condition, results of operations, ability to make distributions to our unitholders and value of our common units.

        Our revolving credit facility limits our ability to, among other things:

    incur or guarantee additional debt;

    make distributions on or redeem or repurchase units;

    make certain investments and acquisitions;

    make capital expenditures;

    incur certain liens or permit them to exist;

    enter into certain types of transactions with affiliates;

    merge or consolidate with or into another company; and

    transfer, sell or otherwise dispose of our assets.

        Our revolving credit facility contains covenants requiring us to maintain certain financial ratios. Our ability to meet those financial ratios and tests can be affected by events beyond our control, and we cannot assure you that we will meet those ratios and tests. For example, for the three months ended June 30, 2014, we were not in compliance with the leverage ratio covenant calculated for the twelve-month rolling period ended June 30, 2014. In addition, if we do not close this offering before November 14, 2014 we will be required to obtain a waiver from the lenders under our revolving credit facility because we anticipate that we will be in violation of the leverage ratio covenant.

        The provisions of our revolving credit facility may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with, or obtain a waiver of, the provisions of our revolving credit facility could result in a default or an event of default that could enable our lenders to terminate the remaining commitments under our revolving credit facility and declare the outstanding principal thereunder, together with accrued and unpaid interest, to be immediately due and payable. If the payment of our debt is accelerated, our assets may be insufficient to repay such debt in full, and our unitholders could experience a partial or total loss of their investment.

Cyber-attacks and threats could have a material adverse effect on our operations.

        Cyber-attacks may significantly affect our operations and those of our customers. Strategic targets, such as energy-related assets, may be at greater risk of future attacks than other targets in the United States. We do not maintain specialized insurance for possible liability resulting from a cyber-attack on our assets that may shut down all or part of our business. We currently are implementing our own cyber security programs and protocols; however, we cannot guarantee their effectiveness. A significant cyber-attack could have a material adverse effect on our operations or those of our customers.

The risk of terrorism, political unrest and hostilities in the Middle East or other energy producing regions may adversely affect the economy and our business.

        Terrorist attacks, political unrest and hostilities in the Middle East or other energy producing regions may adversely impact the price and availability of crude oil, refined products and NGLs, as well as our results of operations, our ability to raise capital and our future growth. The impact that the foregoing may have on our industry in general, and on us in particular, is not known at this time. An act of terror could result in disruptions of crude oil and NGL supplies and markets, and our infrastructure or facilities could be direct or indirect targets. Terrorist activity may also hinder our ability to gather and transport crude oil, refined products and NGLs if our means of transportation

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become damaged as a result of an attack. We have opted to purchase insurance coverage for terrorist acts within our property and casualty insurance programs, but we can give no assurance that our insurance coverage will be adequate to fully compensate us for any losses to our business or property resulting from terrorist acts.

Derivatives legislation adopted by Congress could have an adverse impact on our ability to hedge risks associated with our business.

        The Dodd-Frank Act was signed into law in 2010 and regulates derivative transactions, which include certain instruments used in our risk management activities. Among the other provisions of the Dodd-Frank Act that may affect derivative transactions are those relating to establishment of capital and margin requirements for certain derivative participants, establishment of business conduct standards, recordkeeping and reporting requirements and imposition of position limits. The Dodd-Frank Act and regulations promulgated thereunder could increase the operational and transactional cost of derivatives contracts and affect the number and/or creditworthiness of counterparties available to us.

Our ability to operate our business effectively could be impaired if we fail to attract and retain key management personnel and employees.

        Our ability to operate our business and implement our strategies will depend on our continued ability to attract and retain highly skilled management personnel with energy industry experience. Competition for these persons in the energy industry is intense. For instance, given the overall demand for crude oil transportation services, qualified drivers of crude oil gathering and transportation trucks are in high demand. We may be unable to attract and retain enough qualified drivers to effectively service our customers. Additionally, given our size, we may be at a disadvantage, relative to our larger competitors, in the competition to attract and retain such personnel. We may not be able to continue to employ our senior executives and key personnel or attract and retain qualified personnel in the future, and our failure to retain or attract senior executives and key personnel could have a material adverse effect on our ability to effectively operate our business.

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

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


Risks Inherent in an Investment in Us

Our general partner and its affiliates, including Lonestar, JP Development and ArcLight, have conflicts of interest with us and limited duties to us and our unitholders, and they may favor their own interests to our detriment and that of our unitholders.

        Following this offering, CB Capital Holdings II, LLC and JP Energy GP LLC (two entities that are owned and controlled by certain members of management) and Lonestar will own and control our general partner and its non-economic general partner interest in us. In addition, management will own an aggregate 5.0% limited partner interest in us (or a 4.5% limited partner interest in us if the underwriters exercise in full their option to purchase additional common units) and Lonestar will own a 51.2% limited partner interest in us (or a 46.5% limited partner interest in us if the underwriters exercise in full their option to purchase additional common units). Although our general partner has a

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duty to manage us in a manner that it believes is in the best interests of our partnership and our unitholders, the directors and officers of our general partner also have a duty to manage our general partner in a manner that is in the best interests of its owners. Conflicts of interest may arise between CB Capital Holdings II, LLC, JP Energy GP LLC, Lonestar, JP Development and ArcLight and their affiliates, including our general partner, on the one hand, and us and our unitholders, on the other hand. In resolving these conflicts, our general partner may favor its own interests and the interests of its affiliates, including Lonestar, JP Development and ArcLight, over the interests of our unitholders. These conflicts include, among others, the following:

    neither our partnership agreement nor any other agreement requires CB Capital Holdings II, LLC, JP Energy GP LLC, Lonestar, JP Development or ArcLight to pursue a business strategy that favors us;

    our partnership agreement replaces the fiduciary duties that would otherwise be owed by our general partner with contractual standards governing its duties, limiting our general partner's liabilities and restricting the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty;

    certain officers and directors of our general partner are officers or directors of affiliates of our general partner, including CB Capital Holdings II, LLC, JP Energy GP LLC, Lonestar and JP Development, and also devote significant time to the business of these entities and are compensated accordingly;

    affiliates of our general partner are not limited in their ability to compete with us and may offer business opportunities or sell midstream assets to parties other than us, subject to the right of first offer that JP Development and ArcLight Fund V have granted us;

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

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

    our general partner will determine the amount and timing of many of our cash expenditures and whether a cash expenditure is classified as an expansion capital expenditure, which would not reduce our operating surplus, or a maintenance capital expenditure, which would reduce our operating surplus. This determination can affect the amount of cash that is distributed to our unitholders and to our general partner, the amount of adjusted operating surplus generated in any given period and the ability of subordinated units to convert into common units;

    our general partner will determine which costs incurred by it are reimbursable by us;

    our general partner may cause us to borrow funds in order to permit the payment of cash distributions, even if the purpose or effect of the borrowing is to make a distribution on the subordinated units, to make incentive distributions or to accelerate expiration of the subordination period;

    our partnership agreement permits us to classify up to $30.0 million as operating surplus, even if it is generated from asset sales, non-working capital borrowings or other sources that would otherwise constitute capital surplus. This cash may be used to fund distributions on our subordinated units or to our general partner in respect of the incentive distribution rights;

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    our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered to us or entering into additional contractual arrangements with any of these entities on our behalf;

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

    our general partner may exercise its right to call and purchase all of our common units not owned by it and its affiliates if it and its affiliates own more than 80.0% of our outstanding common units;

    our general partner controls the enforcement of obligations owed to us by our general partner and its affiliates, including (i) the right of first offer granted to us by JP Development and (ii) the performance of one of the truck transportation agreements in our crude oil gathering and transportation business, each as described in greater detail in "Certain Relationships and Related Party Transactions";

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

    our general partner may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to our general partner's incentive distribution rights without the approval of the conflicts committee of the board of directors of our general partner, which we refer to as our conflicts committee, or our unitholders. This election may result in lower distributions to our common unitholders in certain situations.

        Under the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers, directors and owners. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our unitholders. Please read "Conflicts of Interest and Duties."

Affiliates of our general partner, including Lonestar, JP Development and ArcLight, may compete with us, and neither our general partner nor its affiliates have any obligation to present business opportunities to us.

        Neither our partnership agreement nor any other agreement will prohibit affiliates of our general partner, including Lonestar, JP Development and ArcLight, from owning assets or engaging in businesses that compete directly or indirectly with us. For example, ArcLight Fund V is the majority owner of the general partner of another publicly traded master limited partnership in the midstream segment of the energy industry, which may compete with us in the future. In addition, Lonestar, JP Development, ArcLight and other affiliates of our general partner may acquire, construct or dispose of midstream assets in the future without any obligation to offer us the opportunity to purchase any of those assets, subject to the right of first offer that JP Development and ArcLight Fund V, have granted us. As a result, competition from affiliates of our general partner, including Lonestar, JP Development LP and ArcLight, could materially adversely impact our results of operations and distributable cash flow.

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Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow and make acquisitions.

        Our partnership agreement requires that we distribute all of our available cash to our unitholders. As a result, we expect to rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. Therefore, to the extent we are unable to finance our growth externally, our cash distribution policy will significantly impair our ability to grow. In addition, because we will 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 revolving credit facility on our ability to issue additional units, including units ranking senior to the common units as to distribution or liquidation, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional 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 reduce the amount of distributable cash flow available to our unitholders.

Other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions, and our general partner has considerable discretion to establish cash reserves that would reduce the amount of available cash we distribute to unitholders.

        Generally, our available cash is comprised of cash on hand at the end of a quarter plus cash on hand resulting from any working capital borrowings made after the end of the quarter less cash reserves established by our general partner. Our partnership agreement permits our general partner to establish cash reserves for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements), to comply with applicable law or agreements to which we are a party, or to provide funds for future distributions to unitholders. As a result, even when there is no change in the amount of distributable cash flow that we generate, our general partner has considerable discretion to establish cash reserves, which would result in a reduction the amount of available cash we distribute to unitholders. Accordingly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so.

Our partnership agreement replaces our general partner's fiduciary duties to holders of our common units with contractual standards governing its duties.

        Our partnership agreement contains provisions that eliminate the fiduciary standards to which our general partner would otherwise be held by state fiduciary duty law and replaces those duties with several different contractual standards. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, free of any duties to us and our unitholders other than the implied contractual covenant of good faith and fair dealing, which means that a court will enforce the reasonable expectations of the parties where the language in our partnership agreement does not provide for a clear course of action. This provision entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. By purchasing a common unit, a unitholder is treated as having consented to the provisions in our partnership agreement, including the provisions discussed above. Please read "Conflicts of Interest and Duties—Duties of the General Partner."

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Our partnership agreement restricts the remedies available to holders of our common and subordinated units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

        Our partnership agreement contains provisions that restrict the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty under state fiduciary duty law. For example, our partnership agreement provides that:

    whenever our general partner makes a determination or takes, or declines to take, any other action in its capacity as our general partner, our general partner is required to make such determination, or take or decline to take such other action, in good faith and will not be subject to any other or different standard imposed by our partnership agreement, Delaware law, or any other law, rule or regulation, or at equity;

    our general partner will not have any liability to us or our unitholders for decisions made in its capacity as a general partner so long as it acted in good faith (for additional information related to the meaning of "good faith," please read "Conflicts of Interest and Duties—Duties of the General Partner");

    our general partner and its officers and directors will not be liable for monetary damages to us or our limited partners resulting from any act or omission unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or its officers and directors, as the case may be, engaged in intentional fraud or willful misconduct or, in the case of a criminal matter, acted with knowledge that the conduct was criminal; and

    our general partner will not be in breach of its obligations under our partnership agreement or its fiduciary duties to us or our limited partners if a transaction with an affiliate or the resolution of a conflict of interest is approved in accordance with, or otherwise meets the standards set forth in, our partnership agreement.

        In connection with a situation involving a transaction with an affiliate or a conflict of interest, our partnership agreement provides that any determination by our general partner must be made in good faith, and that our conflicts committee and the board of directors of our general partner are entitled to a presumption that they acted in good faith. In any proceeding brought by or on behalf of any unitholder or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption. Please read "Conflicts of Interest and Duties."

If you are not both a citizenship eligible holder and a rate eligible holder, your common units may be subject to redemption.

        In the future, we may acquire or construct assets that are subject to regulation by the Federal Energy Regulatory Commission ("FERC"), and we may enter into leases with, or obtain permits or other authorizations from, the federal government that place citizenship requirements on our investors. In order to avoid (i) any material adverse effect on the maximum applicable rates that can be charged to customers by our subsidiaries on any assets that are subject to rate regulation by FERC or analogous regulatory body and (ii) any substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or other authorization, in which we have an interest, we have adopted certain requirements regarding those investors who may own our common units. Citizenship eligible holders are individuals or entities whose nationality, citizenship or other related status does not create a substantial risk of cancellation or forfeiture of any property, including any governmental permit, endorsement or authorization, in which we have an interest, and will generally include individuals and entities who are United States citizens. Rate eligible holders are individuals or entities subject to United States federal income taxation on the income generated by us or entities not subject to United States federal income taxation on the income generated by us, so long as all of the entity's

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owners are subject to such taxation. Please read "Description of the Common Units—Transfer of Common Units." If you are not a person who meets the requirements to be a citizenship eligible holder and a rate eligible holder, you run the risk of having your units redeemed by us at the market price as of the date three days before the date the notice of redemption is mailed. The redemption price will be paid in cash or by delivery of a promissory note, as determined by our general partner. In addition, if you are not a person who meets the requirements to be a citizenship eligible holder, you will not be entitled to voting rights. Please read "Our Partnership Agreement—Redemption of Ineligible Holders."

Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce our distributable cash flow. The amount and timing of such reimbursements will be determined by our general partner.

        Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Lonestar, for expenses they incur and payments they make on our behalf. Under our partnership agreement, we will reimburse our general partner and its affiliates for certain expenses incurred on our behalf, including, among other items, compensation expense for all employees required to manage and operate our business. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The expenses for which we are required to reimburse our general partner and its affiliates are not subject to any caps or other limits. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders. Please read "Cash Distribution Policy and Restrictions on Distributions."

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors.

        Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Unitholders did not elect our general partner or the board of directors of our general partner and will have no right to elect our general partner or the board of directors of our general partner on an annual or other continuing basis. The board of directors of our general partner is chosen by the members of our general partner, which are controlled by members of our management and by Lonestar. Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. As a result of these limitations, the price at which our common units will trade could be reduced because of the absence or reduction of a takeover premium in the trading price. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders' ability to influence the manner or direction of our management.

Even if holders of our common units are dissatisfied, they cannot initially remove our general partner without its consent.

        Our unitholders will be unable initially to remove our general partner without its consent because our general partner and its affiliates will own sufficient units upon completion of the offering to be able to prevent its removal. The vote of the holders of at least 662/3% of all outstanding common units and subordinated units voting together as a single class is required to remove our general partner. At closing, our general partner and its affiliates will own 56.1% of our common units and subordinated units (excluding common units purchased by officers, directors and director nominees of our general partner and its affiliates under our directed unit program). Also, if our general partner is removed without cause during the subordination period and common units and subordinated units held by our general partner and its affiliates are not voted in favor of that removal, all remaining subordinated

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units will automatically be converted into common units, and any existing arrearages on the common units will be extinguished. A removal of our general partner under these circumstances would adversely affect the common units by prematurely eliminating their distribution and liquidation preference over the subordinated units, which would otherwise have continued until we had met certain distribution and performance tests. "Cause" is narrowly defined under our partnership agreement to mean that a court of competent jurisdiction has entered a final, non-appealable judgment finding the general partner liable for actual fraud or willful or wanton misconduct in its capacity as our general partner. Cause does not include most cases of charges of poor management of the business, so the removal of our general partner because of the unitholders' dissatisfaction with our general partner's performance in managing our partnership will most likely result in the termination of the subordination period.

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

        Unitholders' voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20.0% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees, and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Our general partner interest or the control of our general partner may be transferred to a third party without unitholder consent.

        Our general partner may transfer its non-economic general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of our general partner's members to transfer their membership interests in our general partner to a third party. The new members of our general partner would then be in a position to replace the board of directors and officers of our general partner and to control the decisions taken by the board of directors and officers of our general partner.

Our general partner may transfer its incentive distribution rights to a third party without unitholder consent.

        Our general partner may transfer its incentive distribution rights to a third party at any time without the consent of our unitholders. If our general partner transfers its incentive distribution rights to a third party but retains its non-economic general partner interest, our general partner may not have the same incentive to grow our partnership and increase quarterly distributions to unitholders over time as it would if it had retained ownership of its incentive distribution rights. For example, a transfer of incentive distribution rights by our general partner could reduce the likelihood of Lonestar or its affiliates, including JP Development, selling or contributing midstream assets to us, as Lonestar and its affiliates would have less of an economic incentive to grow our business, which in turn would impact our ability to grow our asset base.

You will experience immediate and substantial dilution in pro forma net tangible book value of $14.52 per common unit.

        The assumed initial public offering price of $20.00 per common unit exceeds our pro forma net tangible book value of $5.48 per unit. Based on an assumed initial public offering price of $20.00 per common unit, you will incur immediate and substantial dilution of $14.52 per common unit. This dilution results primarily because our assets are recorded in accordance with GAAP at their historical cost, and not their fair value. Please read "Dilution."

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We may issue additional units without unitholder approval, which would dilute unitholder interests.

        At any time, we may issue an unlimited number of limited partner interests of any type without the approval of our unitholders and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such limited partner interests. Further, neither our partnership agreement nor our revolving credit facility prohibits the issuance of equity securities that may effectively rank senior to our common units as to distributions or liquidations. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

    our unitholders' proportionate ownership interest in us will decrease;

    the amount of distributable cash flow available for distribution on each unit may decrease;

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

    the ratio of taxable income to distributions may increase;

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

    the market price of our common units may decline.

Our general partner may cause us to borrow funds in order to make cash distributions, even where the purpose or effect of the borrowing benefits our general partner or its affiliates.

        In some instances, our general partner may cause us to borrow funds under our revolving credit facility, from Lonestar or its affiliates or otherwise from third parties in order to permit the payment of cash distributions. These borrowings are permitted even if the purpose and effect of the borrowing is to enable us to make a distribution on the subordinated units, to make incentive distributions or to hasten the expiration of the subordination period.

Our general partner has a limited call right that may require you to sell your common units at an undesirable time or price.

        If at any time our general partner and its affiliates own more than 80.0% of our common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then-current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units. At the completion of this offering and assuming no exercise of the underwriters' option to purchase additional common units, our general partner and its affiliates will own approximately 22.1% of our common units (excluding any common units purchased by officers, directors and director nominees of our general partner under our directed unit program). At the end of the subordination period (which could occur as early as September 30, 2015), assuming no additional issuances of common units (other than upon the conversion of the subordinated units) and no exercise of the underwriters' option to purchase additional common units, our general partner and its affiliates will own approximately 56.1% of our common units (excluding any common units purchased by officers and directors of our general partner under our directed unit program). For additional information about the call right, please read "Our Partnership Agreement—Limited Call Right."

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

        A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made non-recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some jurisdictions. You could be liable for our obligations as if you were a general partner if a court or government agency were to determine that:

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

    your right to act with other unitholders to remove or replace the general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitute "control" of our business.

        Please read "Our Partnership Agreement—Limited Liability" for a discussion of the implications of the limitations of liability on a unitholder.

Unitholders may have to repay distributions that were wrongfully distributed to them.

        Under certain circumstances, unitholders may have to repay amounts wrongfully distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the "Delaware Act"), we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received an impermissible distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Transferees of common units are liable for the obligations of the transferor to make contributions to the partnership that are known to the transferee at the time of the transfer and for unknown obligations if the liabilities could be determined from our partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

There is no existing market for our common units, and a trading market that will provide you with adequate liquidity may not develop. The price of our common units may fluctuate significantly, and you could lose all or part of your investment.

        Prior to this offering, there has been no public market for our common units. After this offering, there will be only 13,750,000 publicly traded common units. In addition, affiliates of our general partner, including CB Capital Holdings II, LLC, JP Energy GP LLC and Lonestar, will own 4,025,754 of our common units and 16,427,252 of our subordinated units, representing an aggregate 56.1% limited partner interest in us. We do not know the extent to which investor interest will lead to the development of a trading market or how liquid that market might be. You may not be able to resell your common units at or above the initial public offering price. Additionally, the lack of liquidity may result in wide bid-ask spreads, contribute to significant fluctuations in the market price of our common units and limit the number of investors who are able to buy our common units.

        The initial public offering price for the common units offered hereby will be determined by negotiations between us and the representatives of the underwriters and may not be indicative of the market price of our common units that will prevail in the trading market. The market price of our common units may decline below the initial public offering price. The market price of our common units may also be influenced by other factors, many of which are beyond our control.

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Our general partner, or any transferee holding incentive distribution rights, may elect to cause us to issue common units to it in connection with a resetting of the target distribution levels related to its incentive distribution rights without the approval of our conflicts committee or the holders of our common units. This could result in lower distributions to holders of our common units.

        Our general partner has the right, at any time when there are no subordinated units outstanding and it has received distributions on its incentive distribution rights at the highest level to which it is entitled (50.0%) for each of the prior four consecutive fiscal quarters, to reset the initial target distribution levels at higher levels based on our distributions at the time of the exercise of the reset election. Following a reset election, the minimum quarterly distribution will be adjusted to equal the reset minimum quarterly distribution, and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution.

        If our general partner elects to reset the target distribution levels, it will be entitled to receive a number of common units. The number of common units to be issued to our general partner will be equal to that number of common units that would have entitled their holder to an average aggregate quarterly cash distribution in the prior two quarters equal to the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion. It is possible, however, that our general partner could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its incentive distribution rights and may, therefore, desire to be issued common units rather than retain the right to receive distributions based on the initial target distribution levels. This risk could be elevated if our incentive distribution rights have been transferred to a third party. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that they would have otherwise received had we not issued new common units in connection with resetting the target distribution levels. Additionally, our general partner has the right to transfer all or any portion of our incentive distribution rights at any time, and such transferee will have the same rights as our general partner relative to resetting target distributions if our general partner concurs that the tests for resetting target distributions have been fulfilled. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

Our management team does not have experience managing our business as a stand-alone publicly traded partnership, and if they are unable to manage our business as a publicly traded partnership our business may be affected.

        Our management team does not have experience managing our business as a publicly traded partnership. Unlike private companies, publicly traded entities are subject to substantial rules and regulations, including rules and regulations promulgated by the SEC and rules governing listed entities on the NYSE. If we are unable to manage and operate our partnership as a publicly traded partnership, our business and results of operations will be adversely affected.

The NYSE does not require a publicly traded partnership like us to comply with certain of its corporate governance requirements.

        We have been approved to list our common units on the NYSE. Because we will be a publicly traded partnership, the NYSE does not require us to have a majority of independent directors on our general partner's board of directors or to establish a compensation committee or a nominating and corporate governance committee. Accordingly, unitholders will not have the same protections afforded to certain corporations that are subject to all of the NYSE corporate governance requirements. Please read "Management—Management of JP Energy Partners LP."

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We will incur increased costs as a result of being a publicly traded partnership.

        We have no history operating as a publicly traded partnership. As a publicly traded partnership, we will incur significant legal, accounting and other expenses. In addition, Sarbanes Oxley and related rules implemented by the SEC and the NYSE have mandated changes in the corporate governance practices of publicly traded companies. We expect these rules and regulations to increase our legal and financial compliance costs and to make our activities more time-consuming and costly. For example, as a result of becoming a publicly traded partnership, we are required to have at least three independent directors, create an audit committee and adopt policies regarding internal controls and disclosure controls and procedures, including the preparation of reports on internal controls over financial reporting. In addition, we will incur additional costs associated with our publicly traded partnership reporting requirements. We also expect these new rules and regulations to make it more difficult and more expensive for our general partner to obtain director and officer liability insurance and possibly to result in our general partner having to accept reduced policy limits and coverage. As a result, it may be more difficult for our general partner to attract and retain qualified persons to serve on its board of directors or as executive officers.

        We have included $3.5 million of estimated incremental annual costs associated with being a publicly traded partnership in our financial forecast included elsewhere in this prospectus. However, it is possible that our actual incremental costs of being a publicly traded partnership will be higher than we currently estimate.


Tax Risks

        In addition to reading the following risk factors, please read "Material Federal Income Tax Consequences" for a more complete discussion of the expected material federal income tax consequences of owning and disposing of our common units.

Our tax treatment depends on our status as a partnership for federal income tax purposes. If the Internal Revenue Service ("IRS") were to treat us as a corporation for federal income tax purposes, which would subject us to entity-level taxation, or if we were otherwise subjected to a material amount of additional entity-level taxation, then our distributable cash flow to our unitholders would be substantially reduced.

        The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested a ruling from the IRS on this matter.

        Despite the fact that we are a limited partnership under Delaware law, it is possible in certain circumstances for a partnership such as ours to be treated as a corporation for federal income tax purposes. A change in our business or a change in current law could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity.

        If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35.0%, and would likely pay state and local income tax at varying rates. Distributions would generally be taxed again as corporate dividends (to the extent of our current and accumulated earnings and profits), and no income, gains, losses, deductions or credits would flow through to you. Because a tax would be imposed upon us as a corporation, our distributable cash flow would be substantially reduced. In addition, changes in current state law may subject us to additional entity-level taxation by individual states. Because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, the State of Texas currently imposes a franchise tax on the taxable margin of corporations and other entities, including limited partnerships. Imposition of any such taxes may substantially reduce the distributable cash flow available for distribution to you. Therefore, if we

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were treated as a corporation for federal income tax purposes or otherwise subjected to a material amount of entity-level taxation, there would be a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

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

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

        The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial interpretation at any time. For example, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. Any modification to the federal income tax laws and interpretations thereof may or may not be retroactively applied and could make it more difficult or impossible for us to be treated as a partnership for federal income tax purposes. Please read "Material Federal Income Tax Consequences—Partnership Status." We are unable to predict whether any such changes will ultimately be enacted. However, it is possible that a change in law could affect us, and any such changes could negatively impact the value of an investment in our common units.

Our unitholders' share of our income will be taxable to them for federal income tax purposes even if they do not receive any cash distributions from us.

        Because a unitholder will be treated as a partner to whom we will allocate taxable income that could be different in amount than the cash we distribute, a unitholder's allocable share of our taxable income will be taxable to it, which may require the payment of federal income taxes and, in some cases, state and local income taxes, on its share of our taxable income even if it receives no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

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

        We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take, and the IRS's positions may ultimately be sustained. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel's conclusions or the positions we take and such positions may not ultimately be sustained. A court may not agree with some or all of our counsel's conclusions or the positions we take. Any contest with the IRS, and the outcome of any IRS contest, may have a materially adverse impact on the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by our unitholders (including holders of our subordinated units) because the costs will reduce our distributable cash flow.

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

        If our unitholders sell common units, they will recognize a gain or loss for federal income tax purposes equal to the difference between the amount realized and their tax basis in those common units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their common units, the amount, if any, of such prior excess distributions with respect to the common units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such common units at a price greater than its tax basis in those common units, even if the price received is less than its original cost. Furthermore, a substantial portion of the amount realized on any sale of common units, whether or not representing gain, may be taxed as ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder's share of our nonrecourse liabilities, a unitholder that sells common units may incur a tax liability in excess of the amount of cash received from the sale. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Recognition of Gain or Loss."

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

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

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

        Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. Our counsel is unable to opine as to the validity of such filing positions. It also could affect the timing of these tax benefits or the amount of gain from your sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns. Please read "Material Federal Income Tax Consequences—Tax Consequences of Unit Ownership—Section 754 Election" for a further discussion of the effect of the depreciation and amortization positions we will adopt.

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

        We will prorate our items of income, gain, loss and deduction for federal income tax purposes between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The use of this proration method may not be permitted under existing Treasury Regulations, and, accordingly, our counsel is unable to opine as to the validity of this method. Recently, however, the Treasury

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Department issued proposed regulations that provide a safe harbor pursuant to which publicly traded partnerships may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we will adopt. If the IRS were to challenge this method or new Treasury Regulations were issued, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders. Latham & Watkins LLP has not rendered an opinion with respect to whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury Regulations. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Allocations Between Transferors and Transferees."

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

        Because a unitholder whose common units are loaned to a "short seller" to effect a short sale of common units may be considered as having disposed of the loaned common units, he may no longer be treated for federal income tax purposes as a partner with respect to those common units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Latham & Watkins LLP has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to effect a short sale of common units; therefore, our unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller are urged to consult a tax advisor to discuss whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from loaning their common units.

We will adopt certain valuation methodologies and monthly conventions for federal income tax purposes that may result in a shift of income, gain, loss and deduction between our general partner (as the holder of our incentive distribution rights) and our unitholders. The IRS may challenge this treatment, which could adversely affect the value of our common units.

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

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

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The sale or exchange of 50.0% or more of our capital and profits interests during any twelve-month period will result in the termination of our partnership for federal income tax purposes.

        We will be considered to have technically terminated our partnership for federal income tax purposes if there is a sale or exchange of 50.0% or more of the total interests in our capital and profits within a twelve-month period. For purposes of determining whether the 50.0% threshold has been met, multiple sales of the same interest will be counted only once. Our technical termination would, among other things, result in the closing of our taxable year for all unitholders, which would result in us filing two tax returns (and our unitholders could receive two Schedules K-1 if relief was not available, as described below) for one fiscal year and could result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in his taxable income for the year of termination. Our termination currently would not affect our classification as a partnership for federal income tax purposes, but instead we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections, including a new election under Section 754 of the Internal Revenue Code, and could be subject to penalties if we are unable to determine that a termination occurred. The IRS has announced a publicly traded partnership technical termination relief program whereby, if a publicly traded partnership that technically terminated requests publicly traded partnership technical termination relief and such relief is granted by the IRS, among other things, the partnership will only have to provide one Schedule K-1 to unitholders for the year notwithstanding two partnership tax years. Please read "Material Federal Income Tax Consequences—Disposition of Common Units—Constructive Termination" for a discussion of the consequences of our technical termination for federal income tax purposes.

As a result of investing in our common units, you may become subject to state and local taxes and return filing requirements in jurisdictions where we operate or own or acquire properties.

        In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we conduct business or control property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We initially expect to conduct business in every state in the continental United States. Many of these states currently impose a personal income tax on individuals. As we make acquisitions or expand our business, we may control assets or conduct business in additional states that impose a personal income tax. It is your responsibility to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in our common units. Please consult your tax advisor.

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USE OF PROCEEDS

        We expect to receive net proceeds of approximately $257.1 million from the sale of            common units in this offering, based on an assumed initial public offering price of $20.00 per common unit (the midpoint of the price range set forth on the cover of this prospectus) after deducting underwriting discounts and structuring fees but before estimated offering expenses. We intend to use these net proceeds as follows:

    pay estimated offering expenses of approximately $2.0 million;

    redeem 100% of our issued and outstanding Series D preferred units for approximately $42.4 million;

    repay $195.6 million of the debt outstanding under our revolving credit facility; and

    replenish approximately $17.1 million of working capital.

        Please read "Prospectus Summary—Recapitalization Transactions and Partnership Structure."

        As of August 31, 2014, we had approximately $195.6 million of debt outstanding under our revolving credit facility. Borrowings under our revolving credit facility bear interest at 3.62% and are due on February 19, 2019. Our outstanding indebtedness was incurred to primarily fund third party acquisitions and for general partnership purposes.

        Immediately following the repayment of a portion of the outstanding debt under our revolving credit facility with a portion of the net proceeds from this offering, we will borrow approximately $75.0 million thereunder. We will use the proceeds from that borrowing to replenish our working capital.

        Prior to the closing of this offering, we will distribute approximately $92.1 million of accounts receivable that comprise our gross working capital to our existing partners, pro rata in accordance with their ownership interest in us.

        The net proceeds from any exercise by the underwriters of their option to purchase additional common units will be used to redeem a number of common units from our existing partners, pro rata, equal to the number of common units issued upon exercise of the option at a price per common unit equal to the net proceeds per common unit in this offering before expenses but after deducting underwriting discounts and the structuring fee. Accordingly, any exercise of the underwriters' option will not affect the total number of units outstanding or the amount of cash needed to pay the minimum quarterly distribution on all units. Please read "Underwriting."

        An increase or decrease in the initial public offering price of $1.00 per common unit would cause the net proceeds from the offering, after deducting underwriting discounts, the structuring fee and offering expenses, to increase or decrease by $10.9 million and $14.9 million, respectively, based on an assumed initial public offering price of $20.00 per common unit, the midpoint of the price range set forth on the cover of this prospectus. Each increase of 1.0 million common units offered by us, together with a concurrent $1.00 increase in the assumed public offering price of $20.00 per common unit, the midpoint of the price range set forth on the cover of this prospectus, would increase net proceeds to us from this offering by approximately $30.5 million. Similarly, each decrease of 1.0 million common units offered by us, together with a concurrent $1.00 decrease in the assumed initial offering price of $20.00 per common unit, would decrease the net proceeds to us from this offering by approximately $32.6 million. If the proceeds increase due to a higher initial public offering price then we will distribute those additional proceeds, pro rata, to our existing equityholders. If the proceeds decrease due to a lower initial public offering price, then we will reduce the amount of working capital that will be replenished by an equal amount.

        Affiliates of Barclays Capital Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, RBC Capital Markets, LLC, Deutsche Bank Securities, Inc. and BMO Capital Markets Corp. are lenders under our revolving credit facility and, accordingly, will receive a portion of the net proceeds of this offering. The underwriters may, from time to time, engage in transactions with and perform services for us and our affiliates in the ordinary course of business. Please read "Underwriting."

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CAPITALIZATION

        The following table shows:

    our historical cash and cash equivalents and capitalization as of June 30, 2014; and

    our pro forma capitalization as of June 30, 2014, giving effect to the pro forma adjustments described in our unaudited pro forma consolidated financial data included elsewhere in this prospectus, including this offering and the application of the net proceeds of this offering in the manner described under "Use of Proceeds" and the other transactions described under "Prospectus Summary—Recapitalization Transactions and Partnership Structure."

        This table is derived from, should be read together with and is qualified in its entirety by reference to the audited historical consolidated financial statements and the accompanying notes and the pro forma combined consolidated financial data and accompanying notes included elsewhere in this prospectus.

 
  As of June 30, 2014  
($ in thousands)
  Historical   Pro Forma  

Cash and cash equivalents

  $ 1,126   $ 108,451  
           

Debt:

             

Revolving credit facility(1)

  $ 181,600   $ 75,000  

Other debt(2)

    1,722     1,722  
           

Total long-term debt (including current maturities)

  $ 183,322   $ 76,722  
           

Partners' capital:

             

Series D preferred units

  $ 40,057   $  

General partner interest

    (12,323 )    

Class A common units

    394,393      

Class B common units

    10,491      

Class C common units

    72,888      

Common units—Public

        252,366  

Common units—JP Energy

        70,314  

Subordinated units

        286,921  
           

Total partners' capital

  $ 505,506   $ 609,601  
           

Total capitalization

  $ 688,828   $ 686,323  
           

(1)
As of August 31, 2014, we had approximately $195.6 million of indebtedness outstanding under our revolving credit facility.

(2)
Consists of other notes payable.

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DILUTION

        Dilution is the amount by which the offering price per common unit in this offering will exceed the pro forma net tangible book value per unit after the offering. On a pro forma basis as of June 30, 2014, after giving effect to the offering of common units and the related transactions, our net tangible book value was approximately $199.6 million, or $5.48 per unit. Purchasers of common units in this offering will experience substantial and immediate dilution in pro forma net tangible book value per common unit for financial accounting purposes, as illustrated in the following table.

Assumed initial public offering price per common unit

        $ 20.00  

Pro forma net tangible book value per unit before the offering(1)

  $ 2.33        

Increase in net tangible book value per unit attributable to purchasers in the offering

  $ 3.15        
             

Less: Pro forma net tangible book value per unit after the offering(2)

          5.48  
             

Immediate dilution in net tangible book value per common unit to purchasers in the offering(3)(4)

        $ 14.52  
             

(1)
Determined by dividing the number of units (4,463,502 common units and 18,213,502 subordinated units) to be issued to the general partner and its affiliates and other investors for their contribution of assets and liabilities to us into the pro forma net tangible book value of the contributed assets and liabilities.

(2)
Determined by dividing the number of units to be outstanding after this offering (18,213,502 total common units and 18,213,502 subordinated units) and the application of the related net proceeds into our pro forma net tangible book value, after giving effect to the application of the net proceeds of this offering.

(3)
If the initial public offering price were to increase or decrease by $1.00 per common unit, then dilution in net tangible book value per common unit would equal $15.29 and $13.75, respectively.

(4)
Because the total number of units outstanding following this offering will not be impacted by any exercise of the underwriters' option to purchase additional common units and any net proceeds from such exercise will not be retained by us, there will be no change to the dilution in net tangible book value per common unit to purchasers in this offering due to any such exercise of the option.

        The following table sets forth the number of units that we will issue and the total consideration contributed to us by the general partner and its affiliates and other investors in respect of their units and by the purchasers of common units in this offering upon consummation of the transactions contemplated by this prospectus.

 
  Units Acquired   Total Consideration  
($ in millions)
  Number   %   Amount   %  

General partner and its affiliates and other investors(1)(2)

    22,677,004     62.0 % $ (39,352,580 )   0.0 %

Purchasers in this offering

    13,750,000     38.0 % $ 275,000,000     100.0 %
                   

Total

    36,427,004     100.0 % $ 235,647,420     100.0 %
                   

(1)
Upon the consummation of the transactions contemplated by this prospectus, our general partner and its affiliates and other investors will own 4,463,502 common units and 18,213,502 subordinated units.

(2)
Assumes the underwriters' option to purchase additional common units is not exercised.

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CASH DISTRIBUTION POLICY AND RESTRICTIONS ON DISTRIBUTIONS

        The following discussion of our cash distribution policy should be read in conjunction with the specific assumptions included in this section. In addition, "Forward-Looking Statements" and "Risk Factors" should be read for information regarding statements that do not relate strictly to historical or current facts and regarding certain risks inherent in our business.

        For additional information regarding our historical and pro forma results of operations, please refer to our historical consolidated financial statements and accompanying notes and the pro forma combined consolidated financial data and accompanying notes included elsewhere in this prospectus.


General

    Rationale for Our Cash Distribution Policy

        Our partnership agreement requires that we distribute all of our available cash quarterly. This requirement reflects a basic judgment that our unitholders will be better served by distributing our available cash rather than retaining it, because, among other reasons, we believe we will generally finance any expansion capital expenditures from external financing sources. However, other than the requirement in our partnership agreement to distribute all of our available cash each quarter, we have no legal obligation to make quarterly cash distributions in this or any other amount, and our general partner has considerable discretion to determine the amount of our available cash each quarter. Generally, our available cash is our (i) cash on hand at the end of a quarter after the payment of our expenses and the establishment of cash reserves and (ii) cash on hand resulting from working capital borrowings made after the end of the quarter. Because we are not subject to an entity-level federal income tax, we expect to have more cash to distribute than would be the case if we were subject to federal income tax. If we do not generate sufficient available cash from operations, we may, but are under no obligation to, borrow funds to pay the minimum quarterly distribution to our unitholders.

    Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy

        Although our partnership agreement requires that we distribute all of our available cash quarterly, there is no guarantee that we will make quarterly cash distributions to our unitholders at our minimum quarterly distribution rate or at any other rate, and we have no legal obligation to do so. In addition, our general partner has considerable discretion in determining the amount of our available cash each quarter. The following factors will affect our ability to make cash distributions, as well as the amount of any cash distributions we make:

    Our ability to pay cash distributions will be subject to restrictions on cash distributions under our revolving credit facility. One such restriction would prohibit us from making cash distributions while an event of default has occurred and is continuing under our revolving credit facility. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility."

    The amount of cash that we distribute and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Specifically, our general partner will have the authority to establish cash reserves for the prudent conduct of our business and for future cash distributions to our unitholders, and the establishment of or increase in those reserves could result in a reduction in cash distributions from levels we currently anticipate. Any decision to establish cash reserves made by our general partner in good faith will be binding on our unitholders.

    While our partnership agreement requires us to distribute all of our available cash, our partnership agreement, including the provisions requiring us to make cash distributions, may be amended. During the subordination period our partnership agreement may not be amended without the approval of our public common unitholders, except in a limited number of circumstances when our general partner can amend our partnership agreement without any unitholder approval. For a description of these limited circumstances, please read "Our

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      Partnership Agreement—Amendment of Our Partnership Agreement—No Unitholder Approval." However, after the subordination period has ended our partnership agreement may be amended with the consent of our general partner and the approval of a majority of the outstanding common units, including common units owned by our general partner and its affiliates. At the closing of this offering, Lonestar and our management will own our general partner and Lonestar will indirectly own an aggregate of approximately 51.2% of our outstanding common units and subordinated units (excluding common units purchased by officers, directors and director nominees of our general partner under our directed unit program). Please read "Our Partnership Agreement—Amendment of Our Partnership Agreement."

    Under Section 17-607 of the Delaware Act, we may not make a distribution if the distribution would cause our liabilities to exceed the fair value of our assets.

    We may lack sufficient cash to pay distributions to our unitholders due to cash flow shortfalls attributable to a number of operational, commercial or other factors as well as increases in our operating or general and administrative expenses, principal and interest payments on our debt, tax expenses, working capital requirements and anticipated cash needs. Our distributable cash flow available for distribution to unitholders is directly impacted by our cash expenses necessary to run our business and will be reduced dollar-for-dollar to the extent such uses of cash increase. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Available Cash."

    Our ability to make cash distributions to our unitholders depends on the performance of our subsidiaries and their ability to distribute cash to us. The ability of our subsidiaries to make cash distributions to us may be restricted by, among other things, the provisions of future indebtedness, applicable state partnership and limited liability company laws and other laws and regulations.

    If and to the extent our available cash materially declines from quarter to quarter, we may elect to reduce the amount of our quarterly distributions in order to service or repay our debt or fund expansion capital expenditures.

        To the extent that our general partner determines not to distribute the full minimum quarterly distribution with respect to any quarter during the subordination period, the common units will accrue an arrearage equal to the difference between the minimum quarterly distribution and the amount of the distribution actually paid with respect to that quarter. The aggregate amount of any such arrearages must be paid on the common units before any distributions of available cash from operating surplus may be made on the subordinated units and before any subordinated units may convert into common units. Any shortfall in the payment of the minimum quarterly distribution with respect to any quarter during the subordination period may decrease the likelihood that our quarterly distribution rate would increase in subsequent quarters. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period."

    Our Ability to Grow is Dependent on Our Ability to Access External Expansion Capital

        Our partnership agreement requires us to distribute all of our available cash to our unitholders on a quarterly basis. As a result, we expect that we will rely primarily upon external financing sources, including borrowings under our revolving credit facility and the issuance of debt and equity securities, to fund future acquisitions and other expansion capital expenditures. To the extent we are unable to finance growth with external sources of capital, the requirement in our partnership agreement to distribute all of our available cash will significantly impair our ability to grow. In addition, because we will distribute all of our available cash, our growth may not be as fast as businesses that reinvest all of their available cash to expand ongoing operations. Our revolving credit facility will restrict our ability to incur additional debt, including through the issuance of debt securities. Please read "Risk Factors—Risks Related to Our Business—Restrictions in our revolving credit facility could adversely affect our

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business, financial condition, results of operations, ability to make distributions to our unitholders and value of our common units." To the extent we issue additional units, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our cash distributions per unit. There are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to our common units, and our unitholders will have no preemptive or other rights (solely as a result of their status as unitholders) to purchase any such additional units. If we incur additional debt (under our revolving credit facility or otherwise) to finance our growth strategy, we will have increased interest expense, which in turn will reduce the available cash that we have to distribute to our unitholders. Please read "Risk Factors—Risks Related to Our Business—Debt we may incur in the future could limit our flexibility to obtain financing and to pursue other business opportunities."


Our Minimum Quarterly Distribution

        Upon the consummation of this offering, our partnership agreement will provide for a minimum quarterly distribution of $0.3250 per unit for each whole quarter, or $1.30 per unit on an annualized basis. Our ability to make cash distributions at the minimum quarterly distribution rate will be subject to the factors described above under "—General—Limitations on Cash Distributions and Our Ability to Change Our Cash Distribution Policy." Quarterly distributions, if any, will be made within 45 days after the end of each calendar quarter to holders of record on or about the first day of each such month. If the distribution date does not fall on a business day, we will make the distribution on the first business day immediately preceding the indicated distribution date. We do not expect to make distributions for the period that begins on October 1, 2014 and ends on the day prior to the closing of this offering other than the distribution to be made to our existing equityholders in connection with the closing of this offering as described in "Prospectus Summary—Recapitalization Transactions and Partnership Structure" and "Use of Proceeds." We will adjust the amount of our first distribution for the period from the closing of this offering through December 31, 2014 based on the actual length of the period. The amount of available cash needed to pay the minimum quarterly distribution on all of our common units and subordinated units to be outstanding immediately after this offering for one quarter and on an annualized basis, assuming no exercise by the underwriters of their option to purchase additional common units, is summarized in the following table:

 
   
  Minimum Quarterly Distributions  
 
  Number of Units   One Quarter   Annualized
(Four Quarters)
 

Common units held by Public

    13,750,000   $ 4,468,750   $ 17,875,000  

Common units held by Lonestar

    3,667,305     1,191,874     4,767,497  

Common units held by Management

    358,449     116,496     465,983  

Common units held by Other Investors

    437,748     142,268     369,073  

Subordinated units held by Lonestar

    14,964,588     4,863,491     19,453,964  

Subordinated units held by Other Investors

    1,786,250     580,531     2,322,125  

Subordinated units held by Management

    1,462,664     475,366     1,901,463  
               

Total

    36,427,004   $ 11,838,776   $ 47,355,105  
               

        Our general partner will hold the incentive distribution rights, which entitle the holder to increasing percentages, up to a maximum of 50.0%, of the cash we distribute in excess of $0.37375 per unit per quarter.

        During the subordination period, before we make any quarterly distributions to our subordinated unitholders, our common unitholders are entitled to receive payment of the full minimum quarterly distribution for such quarter plus any arrearages in distributions of the minimum quarterly distribution from prior quarters. Please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units and Subordination Period." We cannot guarantee, however, that we will pay the minimum quarterly distribution on our common units in any quarter.

        Although holders of our common units may pursue judicial action to enforce provisions of our partnership agreement, including those related to requirements to make cash distributions as described

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above, our partnership agreement provides that any determination made by our general partner in its capacity as our general partner must be made in good faith and that any such determination will not be subject to any other standard imposed by the Delaware Act or any other law, rule or regulation or at equity. Our partnership agreement provides that, in order for a determination by our general partner to be made in "good faith," our general partner must believe that the determination is in the best interests of our partnership. Please read "Conflicts of Interest and Duties."

        The provision in our partnership agreement requiring us to distribute all of our available cash quarterly may not be modified without amending our partnership agreement; however, as described above, the actual amount of our cash distributions for any quarter is subject to fluctuations based on the amount of cash we generate from our business, the amount of reserves our general partner establishes in accordance with our partnership agreement and the amount of available cash from working capital borrowings.

        Additionally, our general partner may reduce the minimum quarterly distribution and the target distribution levels if legislation is enacted or modified that results in our becoming taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes. In such an event, the minimum quarterly distribution and the target distribution levels may be reduced proportionately by the percentage decrease in our available cash resulting from the estimated tax liability we would incur in the quarter in which such legislation is effective. The minimum quarterly distribution will also be proportionately adjusted in the event of any distribution, combination or subdivision of common units in accordance with the partnership agreement, or in the event of a distribution of available cash from capital surplus. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels." The minimum quarterly distribution will also automatically be adjusted in connection with the resetting of the target distribution levels related to our general partner's incentive distribution rights. In connection with any such reset, the minimum quarterly distribution will be reset to an amount equal to the average cash distribution amount per common unit for the two quarters immediately preceding the reset. Please read "Provisions of our Partnership Agreement Relating to Cash Distributions—General Partner's Right to Reset Incentive Distribution Levels."

        In the sections that follow, we present in detail the basis for our belief that we will be able to fully fund our annualized minimum quarterly distribution of $1.30 per unit for the twelve months ending September 30, 2015. In those sections, we present two tables:

    "Unaudited Combined Pro Forma Distributable Cash Flow," in which we present the amount of cash we would have had available for distribution on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, derived from our unaudited pro forma financial data that is included in this prospectus, as adjusted to give pro forma effect to this offering and the related recapitalization transactions; and

    "Estimated Distributable Cash Flow," in which we provide our estimated forecast of our ability to generate sufficient distributable cash flow for us to pay the minimum quarterly distribution on all units for the twelve months ending June 30, 2015.


Unaudited Combined Pro Forma Distributable Cash Flow for the Year Ended December 31, 2013 and the Twelve Months Ended June 30, 2014

        If we had completed this offering and the other transactions contemplated by this prospectus on January 1, 2013, our unaudited combined pro forma distributable cash flow for the year ended December 31, 2013 would have been approximately $24.3 million. This amount would have been sufficient to pay 100% of the minimum quarterly distribution on all of our common units during that period, but only $0.0085 per subordinated unit, or approximately 2.6% of the minimum quarterly distribution on our subordinated units, during that period. Specifically, on a pro forma basis, we would have experienced a shortfall of approximately $23.1 million for the year ended December 31, 2013. If we had completed this offering and the other transactions contemplated by this prospectus on July 1,

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2013, our unaudited combined pro forma distributable cash flow for the twelve months ended June 30, 2014 would have been approximately $14.4 million. This amount would have been sufficient to pay a distribution of $0.1976 per common unit per quarter ($0.7904 per common unit on an annualized basis), or approximately 60.8% of the minimum quarterly distribution, during that period, and we would not have been able to pay any distributions on our subordinated units during that period. Specifically, on a pro forma basis, we would have experienced a shortfall of approximately $33.0 million for the twelve months ended June 30, 2014.

        Our unaudited combined pro forma distributable cash flow for the year ended December 31, 2013 and the twelve months ended June 30, 2014 takes into account $3.5 million of incremental annual general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership. This amount is an estimate, and our general partner will ultimately determine the actual amount of these incremental annual general and administrative expenses to be reimbursed by us in accordance with our partnership agreement. Incremental annual general and administrative expenses related to being a publicly traded partnership include expenses associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent fees, incremental officer and director liability expenses and director compensation. These expenses are not reflected in our historical financial statements or our unaudited pro forma consolidated financial statements included elsewhere in this prospectus.

        We based the pro forma adjustments on currently available information and specific estimates and assumptions. The pro forma amounts below do not purport to present our results of operations had this offering been completed as of the date indicated. In addition, distributable cash flow is primarily a cash accounting concept, while our unaudited pro forma consolidated financial statements have been prepared on an accrual basis. As a result, you should view the amount of pro forma distributable cash flow only as a general indication of the amount of distributable cash flow that we might have generated had we completed this offering on the dates indicated.

        The following table illustrates, on a pro forma basis for the year ended December 31, 2013 and the twelve months ended June 30, 2014, the amount of distributable cash flow that would have been available for distribution to our unitholders, assuming that this offering had been completed at the beginning of each such period. Each of the adjustments reflected or presented below is explained in the footnotes to such adjustments.

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JP Energy Partners LP

Unaudited Combined Pro Forma Distributable Cash Flow

($ in millions, except per unit data)
  Year Ended
December 31,
2013
  Twelve Months
Ended
June 30, 2014
 

Total revenue

  $ 2,105.2   $ 1,983.2  

Costs and expenses:

             

Cost of sales, excluding depreciation and amortization

    1,964.6     1,843.9  

Operating expenses

    63.0     69.7  

General and administrative(1)

    45.7     48.9  

Depreciation and amortization

    36.5     41.5  

Loss on disposal of assets

    1.5     1.1  
           

Total operating expenses

    2,111.3     2,005.1  
           

Operating income (loss)

    (6.1 )   (21.9 )

Other income (expense):

             

Interest expense

    (4.7 )   (4.9 )

Other income (expense), net

    0.7     1.0  
           

Loss from continuing operations before income tax:

    (10.1 )   (25.8 )

Income tax expense(2)

    (0.2 )   (0.1 )
           

Pro forma net income (loss) from continuing operations(3)

    (10.3 )   (25.9 )

Add:

             

Depreciation and amortization

    36.5     41.5  

Interest expense

    4.7     4.9  

Discontinued operations(4)

    2.0     1.4  

Unit-based compensation

    0.9     1.2  

Loss on disposal of assets

    1.5     1.1  

Total gain on commodity derivative contracts

    (0.9 )   (1.5 )

Net cash receipts (payments) for commodity derivatives settled during the period

    (0.2 )   0.9  

Income tax expense(2)

    0.2     0.1  

Transaction costs and other non-cash items

    1.1     0.7  
           

Pro forma Adjusted EBITDA(5)

    35.5     24.4  

Less:

             

Incremental general and administrative expenses of being a publicly traded partnership(6)

    3.5     3.5  

Cash interest paid, net of interest income(7)

    4.1     3.9  

Cash income taxes paid(2)

    0.1     0.2  

Expansion capital expenditures(8)

    277.4     265.4  

Maintenance capital expenditures(8)

    3.5     2.4  

Add:

             

Capital contributions and borrowings to fund expansion capital expenditures           

    277.4     265.4  
           

Pro forma distributable cash flow

  $ 24.3   $ 14.4  
           

Implied cash distribution at the minimum quarterly distribution rate:

             

Annualized minimum quarterly distribution per unit

  $ 1.30   $ 1.30  

Distributions to public common unitholders

    17.9     17.9  

Distributions to Lonestar—common units

    4.8     4.8  

Distributions to Lonestar—subordinated units

    19.5     19.5  

Distributions to Management—common units

    0.5     0.5  

Distributions to Management—subordinated units

    1.9     1.9  

Distributions to Other Investors—common units

    0.5     0.5  

Distributions to Other Investors—subordinated units

    2.3     2.3  
           

Total distributions to unitholders(9)

  $ 47.4   $ 47.4  
           

Excess (shortfall) of pro forma distributable cash flow over the aggregate annualized minimum quarterly distribution

  $ (23.1 ) $ (33.0 )
           

Percent of minimum quarterly distribution payable to common unitholders

    100 %   61 %
           

Percent of minimum quarterly distribution payable to subordinated unitholders

    2.6 %   %
           

(1)
Includes segment general and administrative expenses of $16.2 million and $18.6 million for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively, which includes items such as

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    management, sales and regional office expenses that are directly related to the operations of our business segments. Also includes corporate general and administrative expenses of $29.5 million and $30.3 million for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively, which includes professional fees of $14.1 million and $12.7 million for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively, a significant portion of which we do not expect to incur during the twelve months ending September 30, 2015. The professional fees incurred during the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014 primarily related to (i) audits of our 2011 and 2012 financial statements as well as reviews of our quarterly financial statements for the three months ended March 31, 2013 and June 30, 2013, (ii) audits related to several significant acquisitions that took place during the period, (iii) valuation services associated with our acquisitions in 2011 and 2012 and (iv) contract labor costs in our accounting group to manage additional accounting and financial reporting matters.

(2)
Represents a 1.0% state tax on gross margin, which is generally defined as total revenue minus cost of sales, from our operations in Texas.

(3)
Pro forma net income (loss) for the year ended December 31, 2013 gives effect to the pro forma adjustments reflected in our unaudited pro forma combined consolidated financial statements included elsewhere in this prospectus.

(4)
In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

(5)
Adjusted EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures," and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."

(6)
Represents estimated cash expense associated with being a publicly traded partnership, such as expenses associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent fees, incremental officer and director liability expenses and director compensation.

(7)
Represents "Interest expense" adjusted to exclude amortization of deferred financing costs.

(8)
Historically, we have not made a distinction between maintenance capital expenditures and expansion capital expenditures. Under our partnership agreement, maintenance capital expenditures are capital expenditures made to maintain our operating income or operating capacity, while expansion capital expenditures are capital expenditures that we expect will increase our operating income or operating capacity over the long term. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, expansion capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or facilities. For the year ended December 31, 2013, our pro forma capital expenditures inclusive of acquisitions totaled $280.9 million. We estimate that $3.5 million of our pro forma capital expenditures were maintenance capital expenditures and $277.4 million were expansion capital expenditures, of which $44.2 million were unrelated to acquisitions and $233.2 million were acquisition-related. For the twelve months ended June 30, 2014, our pro forma capital expenditures inclusive of acquisitions totaled $267.8 million. We estimate that $2.4 million of our pro forma capital expenditures were maintenance capital expenditures and $265.4 million were expansion capital expenditures, of which $33.1 million were unrelated to acquisitions and $232.3 million were acquisition-related. For a discussion of our maintenance capital expenditures and our expansion capital expenditures, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures."

(9)
Totals may not sum due to rounding.

Estimated Distributable Cash Flow for the Twelve Months Ending September 30, 2015

        We forecast that our estimated distributable cash flow for the twelve months ending September 30, 2015 will be approximately $56.8 million. This amount would exceed by $9.4 million the amount needed to pay the aggregate annualized minimum quarterly distribution of $47.4 million on all of our units for the twelve months ending September 30, 2015. To the extent we experience a shortfall in distributable cash flow in any particular quarter, including during the twelve months ending September 30, 2015, our partnership agreement will allow us to use cash on hand or borrow funds under our credit facility to cover such a shortfall in order to pay our minimum quarterly distribution.

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        We have not historically made public projections as to future operations, earnings or other results of our business. However, our management has prepared the forecast of estimated distributable cash flow and related assumptions set forth below to supplement our historical consolidated financial statements and our unaudited pro forma consolidated financial statements in support of our belief that we will generate sufficient cash to pay the aggregate annualized minimum quarterly distribution on all of our units for the twelve months ending September 30, 2015. This forecast is a forward-looking statement and should be read together with the historical consolidated financial statements and the accompanying notes included elsewhere in this prospectus, our unaudited pro forma consolidated financial statements and the accompanying notes included elsewhere in this prospectus, "Management's Discussion and Analysis of Financial Condition and Results of Operations" and "—Assumptions and Considerations." The accompanying prospective financial information was not prepared with a view toward complying with the published guidelines of the SEC or guidelines established by the American Institute of Certified Public Accountants with respect to prospective financial information, but, in the view of our management, was prepared on a reasonable basis, reflects the best currently available estimates and judgments, and presents, to the best of management's knowledge and belief, the assumptions on which we base our belief that we will generate sufficient distributable cash flow to pay the aggregate annualized minimum quarterly distribution on all of our units for the twelve months ending September 30, 2015. However, this information is not fact and should not be relied upon as being necessarily indicative of future results, and readers of this prospectus are cautioned not to place undue reliance on the prospective financial information.

        The prospective financial information included in this prospectus has been prepared by, and is the responsibility of, our management. Neither our independent registered public accounting firm, nor any other independent accountants have compiled, examined or performed any procedures with respect to the prospective financial information contained herein, nor have they expressed any opinion or any other form of assurance with respect thereto. The report of our independent registered public accounting firm included in this prospectus relates to our historical consolidated financial statements. It does not extend to the prospective financial information and should not be read to do so.

        When considering our financial forecast, you should keep in mind the risk factors and other cautionary statements under "Risk Factors." Any of the risks discussed in this prospectus, to the extent they are realized, could cause our actual results of operations to vary significantly from those that would enable us to generate our estimated distributable cash flow for the twelve months ending September 30, 2015.

        We do not undertake any obligation to release publicly the results of any future revisions we may make to the financial forecast or to update this financial forecast to reflect events or circumstances after the date of this prospectus. In light of this, the statement that we believe we will have sufficient distributable cash to allow us to pay the aggregate annualized minimum quarterly distribution on all of our units for the twelve months ending September 30, 2015 should not be regarded as a representation by us, the underwriters or any other person that we will make such distribution. Therefore, you are cautioned not to place undue reliance on this information.

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JP Energy Partners LP

Estimated Distributable Cash Flow

 
  Three Months Ending    
 
 
  Twelve Months
Ending
September 30,
2015
 
($ in millions, except per unit amounts)
  December 31,
2014
  March 31,
2015
  June 30,
2015
  September 30,
2015
 

Revenue:

                               

Crude oil pipeline and storage

  $ 31.0   $ 34.9   $ 44.9   $ 62.8   $ 173.6  

Crude oil supply and logistics

    475.9     565.3     628.8     647.3     2,317.3  

Refined products terminaling and storage

    7.9     9.7     6.0     5.5     29.1  

NGL distribution and sales

    54.8     66.1     54.5     52.7     228.1  
                       

Total operating revenue

    569.6     676.0     734.2     768.3     2,748.1  

Operating expenses:

                               

Cost of sales, excluding depreciation and amortization

    530.2     631.0     686.5     719.2     2,566.9  

Operating expenses

    16.5     18.4     19.7     19.0     73.6  

General and administrative(1)

    9.8     11.2     9.8     10.0     40.8  

Depreciation and amortization

    11.2     12.2     13.4     13.6     50.4  
                       

Total operating expenses

    567.7     672.8     729.4     761.8     2,731.7  
                       

Operating income

    1.9     3.2     4.8     6.5     16.4  

Interest expense(2)

    1.2     1.4     1.8     2.0     6.4  

Other expense

    0.6     0.6     0.6     0.6     2.4  

Income tax expense(3)

    0.1     0.1     0.1     0.1     0.4  
                       

Net income

        1.1     2.3     3.8     7.2  

Add:

                               

Depreciation and amortization

    11.2     12.2     13.4     13.6     50.4  

Interest expense, net

    1.2     1.4     1.8     2.0     6.4  

Income tax expense(3)

    0.1     0.1     0.1     0.1     0.4  

Non-cash charges

    0.6     0.6     0.6     0.6     2.4  
                       

Adjusted EBITDA(4)

    13.1     15.4     18.2     20.1     66.8  

Less:

                               

Cash interest paid, net of interest income(5)

    1.1     1.2     1.6     1.7     5.6  

Expansion capital expenditures(6)

    34.9     44.8     24.3     4.7     108.7  

Maintenance capital expenditures(6)

    0.7     0.9     0.9     1.5     4.0  

Income tax expense(3)

    0.1     0.1     0.1     0.1     0.4  

Add:

                               

Borrowings to fund expansion capital expenditures

    34.9     44.8     24.3     4.7     108.7  
                       

Estimated distributable cash flow

  $ 11.2   $ 13.2   $ 15.6   $ 16.8   $ 56.8  

Implied cash distribution at the minimum quarterly distribution rate:

                               

Annualized minimum quarterly distribution per unit

  $ 0.3250   $ 0.3250   $ 0.3250   $ 0.3250   $ 1.30  

Distributions to public common unitholders            

    4.5     4.5     4.5     4.5     17.9  

Distributions to Lonestar—common units            

    1.2     1.2     1.2     1.2     4.8  

Distributions to Lonestar—subordinated units            

    4.9     4.9     4.9     4.9     19.5  

Distributions to Management—common units            

    0.1     0.1     0.1     0.1     0.5  

Distributions to Management—subordinated units            

    0.4     0.4     0.4     0.4     1.9  

Distributions to Other Investors—common units            

    0.1     0.1     0.1     0.1     0.5  

Distributions to Other Investors—subordinated units

    0.6     0.6     0.6     0.6     2.3  

Total distributions to unitholders(7)

    11.8     11.8     11.8     11.8     47.4  

Excess (shortfall) of distributable cash flow over the aggregate annualized minimum quarterly distribution

    (0.6 )   1.4     3.8     5.0     9.4  

Percent of minimum quarterly distribution payable to common unitholders

    100 %   100 %   100 %   100 %   100 %

Percent of minimum quarterly distribution payable to subordinated unitholders

    90 %   100 %   100 %   100 %   100 %

(1)
Includes estimated annual incremental cash expense associated with being a publicly traded partnership of approximately $3.5 million, including costs associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent fees, incremental officer and director liability expenses and director compensation.

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(2)
Assumes an aggregate of $152.8 million of average borrowings over the twelve months ending September 30, 2015, bearing interest at a weighted-average rate of approximately 2.88%. This rate is based on a forecast of LIBOR and prime rates during the period. The $6.4 million of interest expense that we expect to incur during the twelve months ending September 30, 2015 relates to $5.3 million of interest on our expected revolving credit facility borrowings, unused commitment fees and letters of credit fees, $0.8 million of amortization of deferred financing costs and $0.3 million of interest on our other debt.

(3)
Represents a 1.0% state tax on gross margin, which is generally defined as total revenue minus cost of sales, from our operations in Texas.

(4)
Adjusted EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures," and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."

(5)
Represents "Interest expense" adjusted to exclude amortization of deferred financing costs.

(6)
Historically, we have not made a distinction between maintenance capital expenditures and expansion capital expenditures. Under our partnership agreement, maintenance capital expenditures are capital expenditures made to maintain our operating income or operating capacity, while expansion capital expenditures are capital expenditures that we expect will increase our operating income or operating capacity over the long term. Examples of maintenance capital expenditures are those made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows. In contrast, expansion capital expenditures are those made to acquire additional assets to grow our business, to expand and upgrade our systems and facilities and to construct or acquire similar systems or facilities. For a discussion of our maintenance capital expenditures and our expansion capital expenditures, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures."

(7)
Totals may not sum due to rounding.


Assumptions and Considerations

        Based on a number of specific assumptions, we believe our estimated distributable cash flow for the twelve months ending September 30, 2015 will be $56.8 million, compared to $24.3 million during the pro forma year ended December 31, 2013 and $14.4 million during the pro forma twelve months ended June 30, 2014. Because we believe it is not reasonably possible to forecast gains or losses on commodity derivative contracts and selected charges or any unusual or non-recurring costs or gains for future periods, we have assumed none for the twelve months ending September 30, 2015. Our estimate does not assume any incremental revenues, expenses or other costs associated with acquisitions of businesses, but does include identified organic growth opportunities as described below.

    General Considerations

        Substantially all of the anticipated increase in our estimated distributable cash flow for the twelve months ending September 30, 2015, compared to the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, is primarily attributable to:

    acquisitions and organic growth projects that have recently been commenced or placed into service but which were either not included or only partially included in our results for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, including:

    a full year of operations on our Silver Dollar Pipeline System, which was placed into service in April 2013;

    growth in our crude oil supply and logistics segment, primarily from expanding our business in the Permian Basin in January 2014;

    the addition of at-the-rack ethanol blending capabilities at our refined products terminal in North Little Rock, Arkansas in March 2014 and the addition of vapor recovery units at both of our refined products terminals in the fourth quarter of 2013; and

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      the expansion of our cylinder exchange business into all 48 states in the continental United States in the first quarter of 2014, including the addition of a new three-year contract with a national convenience store owner and operator and its franchisees to provide propane cylinders to all of their gas stations in California, Oregon and Washington;

    other pending acquisitions and organic growth initiatives which we expect to be consummated or placed into service in the near-term and included in our operations and results for the forecast period, including:

    the addition of ethanol blending activities at our refined products terminal in Caddo Mills, Texas and butane blending capabilities at our refined products terminal in North Little Rock, Arkansas;

    expansion projects on our Silver Dollar Pipeline System and new volume commitments from third party customers; and

    the procurement of additional large-volume or national sales contracts as a result of the national expansion of our cylinder exchange business; and

    a reduction in general and administrative expenses due to approximately $14.1 million and $12.7 million of professional fees incurred during the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively, a significant portion of which we do not expect to incur during the twelve month period ending September 30, 2015, related to:

    audits of our 2011 and 2012 financial statements as well as reviews of our quarterly financial statements for the three months ended March 31, 2013 and June 30, 2013;

    audits related to several significant acquisitions which took place during the period;

    valuation services associated with our acquisitions in 2011 and 2012; and

    contract labor costs due to an increase in personnel in our accounting group to manage additional accounting and financial reporting matters.

        While the assumptions disclosed in this prospectus are not all-inclusive, the assumptions listed are those that we believe are significant to our forecasted results of operations and any assumptions not discussed were not deemed significant. We believe our actual results of operations will approximate those reflected in our forecast, but we can give no assurance that our forecasted results will be achieved. There likely will be differences between our forecast and our actual results and those differences could be material. If the forecast is not achieved, we may not be able to make distributions on our units at the minimum quarterly distribution rate or at all.

    Commodity Price Volatility

        We are exposed to volatility in crude oil, refined products and NGL commodity prices. We manage such exposure through the structure of our sales and supply contracts and through a managed hedging program. As a result, our forecast is not contingent on a particular set of assumptions regarding commodity prices. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosure About Market Risk."


Revenues, Cost of Sales and Adjusted Gross Margin

        We define adjusted gross margin as total revenues minus cost of sales, excluding depreciation and amortization, and certain non-cash charges such as non-cash vacation expense and non-cash gains (losses) on derivative contracts (total gains (losses) on commodity derivatives less net cash flow associated with commodity derivatives settled during the period). Because we believe it is not reasonably possible to forecast unrealized gains or losses on derivatives for future periods, we have assumed none for the twelve months ending September 30, 2015.

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        We view adjusted gross margin as an important measure of our performance and operations because it provides a meaningful comparison of the financial performance of our business segments without the impact of changes in commodity prices between the pro forma and forecast periods, as these changes generally have similar and offsetting impacts on both revenues and cost of sales, excluding depreciation and amortization.

        Adjusted gross margin is a supplemental financial measure which is not presented in accordance with GAAP. We believe that the presentation of adjusted gross margin in this prospectus provides information useful to investors in assessing our financial condition and results of operations. The GAAP measure most directly comparable to adjusted gross margin is operating income (loss). Adjusted gross margin should not be considered an alternative to operating income (loss) or any other measure of financial performance or liquidity presented in accordance with GAAP. For a reconciliation of adjusted gross margin to operating income (loss), please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures."

        We estimate that our adjusted gross margin will be $181.2 million for the twelve months ending September 30, 2015, compared to $139.5 million for the pro forma year ended December 31, 2013 and $139.0 million for the pro forma twelve months ended June 30, 2014. Our forecasted volumes have been estimated for each of our segments based on our pro forma historical volumes and take into consideration contracts with third parties, as well as our organic growth initiatives. Our estimated adjusted gross margin assumes a consistent renewal rate by our customers with respect to these contracts.

    Crude Oil Pipelines and Storage

        We estimate that $41.3 million of our total adjusted gross margin will be generated from our crude oil pipelines and storage segment for the twelve months ending September 30, 2015, compared to $19.5 million for the pro forma year ended December 31, 2013 and $24.6 million for the pro forma twelve months ended June 30, 2014. The following table compares our total crude oil pipelines and storage revenues, cost of sales, excluding depreciation and amortization, and adjusted gross margin for the periods indicated.

 
  Pro Forma   Forecasted  
($ in millions, unless otherwise noted)
  Year Ended
December 31, 2013
  Twelve Months Ended
June 30, 2014
  Twelve Months Ending
September 30, 2015
 

Financial data:

                   

Revenues

  $ 28.4   $ 61.6   $ 173.6  

Cost of sales, excluding depreciation and amortization(1)

    8.9     37.0     132.3  
               

Adjusted gross margin

    19.5     24.6     41.3  

Operational data:

                   

Average daily pipeline throughput (barrels per day)(2)          

    8,885     15,178     55,091  

(1)
Includes intersegment cost of sales, excluding depreciation and amortization, of $5.6 million, $30.8 million and $120.5 million for the pro forma year ended December 31, 2013, twelve months ended June 30, 2014 and twelve months ending September 30, 2015, respectively, which were eliminated upon consolidation.

(2)
The Silver Dollar Pipeline System was placed into service in April 2013.

        The anticipated increase in adjusted gross margin in our crude oil pipelines and storage segment for the twelve months ending September 30, 2015 compared to the pro forma year ended December 31, 2013 and pro forma twelve months ended June 30, 2014 relates primarily to (i) the additional amount of time the Silver Dollar Pipeline System will be fully operational in the forecast

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period, (ii) higher anticipated pipeline throughput from an existing customer and (iii) the expansion of our pipeline system, which is currently underway.

        We expect a substantial increase in daily pipeline throughput for the twelve months ending September 30, 2015 compared to the year ended December 31, 2013 and the twelve months ended June 30, 2014 because the Silver Dollar Pipeline System will be fully operating throughout the entire forecast period.

        We believe that there will be increased production in the areas we serve. We believe we will be able to increase volumes under our existing long-term agreements, which contain acreage dedications or minimum volume commitments, due to the anticipated increase in drilling activity in the Southern Wolfcamp and because an existing customer amended its long-term agreement with us in March 2014 to substantially increase its committed volumes.

        This contract amendment and other anticipated commercial opportunities in the Southern Wolfcamp have enabled us to undertake expansion projects which we believe will further increase daily pipeline throughput during the twelve months ending September 30, 2015. These expansion projects involve the construction of approximately 30 miles of additional pipeline, including an interconnection to a second long-haul transportation pipeline expected to be completed in the fourth quarter of 2014. We believe this will significantly increase the Silver Dollar Pipeline System's gathering footprint and take-away capacity and allow us to obtain new volume commitments, including some from existing customers in our crude oil supply and logistics segment.

        We have forecast an adjusted gross margin in our crude oil storage business that is consistent with our results for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014.

    Crude Oil Supply and Logistics

        We estimate that $28.5 million of our total adjusted gross margin, or $1.15 per barrel sold, will be generated from our crude oil supply and logistics segment for the twelve months ending September 30, 2015, compared to $26.3 million, or $1.35 per barrel sold, for the pro forma year ended December 31, 2013 and $19.5 million, or $1.09 per barrel sold, for the pro forma twelve months ended June 30, 2014. During the twelve months ending September 30, 2015, we estimate that our average barrels sold will be 68,095 barrels per day compared to 53,471 and 49,027 barrels per day for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively. This increase is primarily due to an expansion of our operations in other geographic regions such as the Permian Basin, Mid-Continent and Eagle Ford shale.

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        The following table compares our total crude oil supply and logistics revenues, cost of sales, excluding depreciation and amortization, and adjusted gross margin for the periods indicated.

 
  Pro Forma   Forecasted  
($ in millions, unless otherwise noted)
  Year Ended
December 31, 2013
  Twelve Months Ended
June 30, 2014
  Twelve Months Ending
September 30, 2015
 

Financial data:

                   

Revenues(1)

  $ 1,878.5   $ 1,729.5   $ 2,437.8  

Cost of sales, excluding depreciation and amortization

    1,852.2     1,710.3     2,409.3  
               

Adjusted gross margin

    26.3     19.5 (2)   28.5  

Operational data:

                   

Average barrels sold per day

    53,471     49,027     68,095  

Adjusted gross margin per barrel

  $ 1.35   $ 1.09   $ 1.15  

(1)
Includes intersegment revenues of $5.6 million, $30.8 million and $120.5 million for the pro forma year ended December 31, 2013, twelve months ended June 30, 2014 and twelve months ending September 30, 2015, respectively, which were eliminated upon consolidation.

(2)
Excludes non-cash expense of $0.3 million.

        We believe that we will be able to meet the anticipated increase in demand for our crude oil supply and logistics services through the expansion of our operations into the Eagle Ford shale during the second quarter of 2014, expected growth in sales volumes in the Permian Basin from the planned expansion of our Silver Dollar Pipeline System during the forecast period and our management's experience and customer relationships. The increases in sales volumes are partially offset by an expected decrease in sales volumes in the Mid-Continent region from increased competition. However, we expect the growth in sales volumes in the Eagle Ford shale and Permian Basin to significantly offset any decrease in sales volumes in the Mid-Continent region. We have forecast a reduction in adjusted gross margin per barrel due to our expectation of increased competition in the Mid-Continent region and the assumption that our blending activities will generate lower margins as compared to the pro forma year ended December 31, 2013.

    Refined Products Terminals and Storage

        We estimate that $17.2 million of our total adjusted gross margin, or $0.017 per gallon of throughput, will be generated from our refined products terminals and storage segment for the twelve months ending September 30, 2015, compared to approximately $19.3 million, or $0.018 per gallon of throughput, for the pro forma year ended December 31, 2013 and approximately $18.9 million, or $0.018 per gallon of throughput, for the pro forma twelve months ended June 30, 2014. During the twelve months ending September 30, 2015, we estimate that our refined products terminals throughput will be 2.7 million gallons per day compared to 2.9 million gallons per day for the pro forma year ended December 31, 2013 and 2.8 million gallons per day for the pro forma twelve months ended June 30, 2014.

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        The following table compares our total refined products terminals and storage revenues, cost of sales, excluding depreciation and amortization, and adjusted gross margin for the periods indicated.

 
  Pro Forma   Forecasted  
($ in millions, unless otherwise noted)
  Year Ended
December 31, 2013
  Twelve Months
Ended
June 30, 2014
  Twelve Months Ending
September 30, 2015
 

Financial data:

                   

Revenues

  $ 24.0   $ 24.8   $ 29.1  

Cost of sales, excluding depreciation and amortization

    4.7     5.9     11.9  
               

Adjusted gross margin

    19.3     18.9     17.2  

Operational data:

                   

Throughput (Mgal/d)

    2,901     2,834     2,713  

Adjusted gross margin per gallon

  $ 0.018   $ 0.018   $ 0.017  

        The anticipated decrease in adjusted gross margin in our refined products terminals and storage segment for the twelve months ending September 30, 2015 compared to the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014 primarily relates to an expected reduction in revenues from product sales. In the third quarter of 2014, we discovered that certain elements of our product measurement and quality control processes at our refined products terminal in North Little Rock, Arkansas were resulting in excessive product gains for JP Energy. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards, and we are in the process of returning a certain amount of refined products to customers. As a result, we believe it is reasonably likely that the new processes and procedures that we are undertaking will result in a decrease in revenues from product sales in our refined products terminals and storage segment in future periods relative to historical periods, although this reduction may be partially offset by an operational excellence initiative that we are undertaking at both of our refined products terminals.

    NGL Distribution and Sales

        We estimate that $94.2 million of our total adjusted gross margin, or $1.26 per gallon of NGL sold, will be generated in our NGL distribution and sales segment for the twelve months ending September 30, 2015, compared to $74.4 million, or $1.13 per gallon of NGL sold, for the pro forma year ended December 31, 2013 and $76.0 million, or $1.10 per gallon of NGL sold, for the pro forma twelve months ended June 30, 2014. We expect an increase in adjusted gross margin per gallon of NGL sold for the twelve months ending September 30, 2015 compared to the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014 primarily due to a greater percentage of volumes sold in our cylinder exchange business, which generates a higher adjusted gross margin per gallon.

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        The following table compares our total NGL distribution and sales revenues, cost of sales, excluding depreciation and amortization, and adjusted gross margin for the periods indicated.

 
  Pro Forma   Forecasted  
($ in millions, unless otherwise noted)
  Year Ended
December 31, 2013
  Twelve Months Ended
June 30, 2014
  Twelve Months Ending
September 30, 2015
 

Financial data:

                   

Revenues

  $ 179.9   $ 198.1   $ 228.1  

Cost of sales, excluding depreciation and amortization

    104.4     121.5     133.9  

Adjusted gross margin

    74.4 (1)   76.0 (2)   94.2  

Operational data:

                   

NGL and refined product sales (gallons per day)(3)

    180,850     189,059     205,446  

Adjusted gross margin per gallon

  $ 1.13   $ 1.10   $ 1.26  

(1)
Excludes total gain from commodity derivative contracts and net cash payments for commodity derivatives settled during the period of $0.9 million and $0.2 million, respectively.

(2)
Excludes total gain from commodity derivative contracts and net cash receipts for commodity derivatives settled during the period of $1.5 million and $0.9 million, respectively.

(3)
Includes gasoline and diesel gallons sold primarily to our oilfield services and agricultural customers.

        The anticipated increase in adjusted gross margin in our NGL distribution and sales segment for the twelve months ending September 30, 2015 compared to the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014 primarily relates to our assumption that the volume of NGLs sold will increase by 9.0 million gallons for the twelve months ending September 30, 2015, or 13.6%, compared to the pro forma year ended December 31, 2013 and by 6.0 million gallons, or 8.6%, compared to the pro forma twelve months ended June 30, 2014, due to increased activity from our cylinder exchange distribution network related to our national expansion. We recently completed the expansion of our cylinder exchange business into all 48 states in the continental United States through the construction of two new production facilities and associated distribution depots serving Arizona, California and Utah. We believe this expansion will provide us with economies of scale and significant cost savings in product procurement, transportation and general administration. As a result of this expansion, we were successful in obtaining a new, three-year contract with a national convenience store owner and operator and its franchisees to provide propane cylinders to their gas stations in California, Oregon and Washington. We believe that we will be able to add additional large-volume or national accounts due to our ability to provide services nationwide and have assumed in this forecast that we do so.

    Operating Expenses

        Our operating expenses include payroll, wages, utility costs, fleet costs, repairs and maintenance costs, rent, fuel, insurance premiums, taxes and other operating costs. We estimate that operating expenses for the twelve months ending September 30, 2015 will be $73.6 million, compared to $63.0 million for the pro forma year ended December 31, 2013 and $69.7 million for the pro forma twelve months ended June 30, 2014. The $10.6 million increase in our operating expenses for the twelve months ending September 30, 2015 compared to the pro forma year ended December 31, 2013 is due to the following:

    a $0.3 million increase in our crude oil pipelines and storage segment primarily due to the growth of the Silver Dollar Pipeline System;

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    a $1.0 million increase in our refined products terminals and storage segment as a result of an increase in personnel expense;

    a $9.8 million increase in our NGL distribution and sales segment as a result of (i) additional costs related to new large-volume or national accounts we expect to enter into as a result of our recent national expansion as well as (ii) other organic growth projects in our cylinder exchange business; partially offset by

    a $0.5 million decrease in our crude oil supply and logistics segment primarily due to a reduction in fleet maintenance.

        The $3.9 million increase in our operating expenses for the twelve months ending September 30, 2015 compared to the pro forma twelve months ended June 30, 2014 is due to the following:

    a $0.8 million increase in our refined products terminals and storage segment as a result of an increase in personnel expense;

    a $5.8 million increase in our NGL distribution and sales segment as a result of (i) additional costs related to new large-volume or national accounts we expect to enter into as a result of our recent national expansion as well as (ii) other organic growth projects in our cylinder exchange business; offset by

    a $2.7 million decrease in operating expenses at our North Little Rock, Arkansas refined products terminal. In the third quarter of 2014, we discovered that certain elements of our product measurement and quality control at our refined products terminal in North Little Rock, Arkansas were not in compliance with industry standards and certain regulations. As a result, the terminal under-delivered refined products to its customers and consequently, recognized excessive gains on refined products generated during the terminal's normal terminal and storage process. We have undertaken procedures to improve and remediate our measurement and quality control processes to be in compliance with industry standards, and we are in the process of returning a certain amount of refined products to customers. We estimated the volume of refined products to be returned to customers of approximately 24,000 barrels, which amounts to an estimated value of $2.7 million as of June 30, 2014. Accordingly, we recorded this charge to operating expenses during the pro forma twelve months ended June 30, 2014 and will update the estimated accrual each reporting period based on changes in estimate related to volumes returned, market prices and other changes.

        In addition, our pro forma results for the year ended December 31, 2013 and the twelve months ended June 30, 2014 do not include a full year of expense for two individually insignificant acquisitions made in our NGL distribution and sales segment in the second half of 2013.

    General and Administrative Expenses

        Our general and administrative expenses includes payroll and office expenses, professional fees and insurance costs. We estimate that general and administrative expenses for the twelve months ending September 30, 2015 will be $40.8 million, compared to $45.7 million for the pro forma year ended December 31, 2013 and $48.9 million for the pro forma twelve months ended June 30, 2014. Corporate costs are expected to comprise approximately $22.6 million of general and administrative expenses for the twelve months ending September 30, 2015 compared to approximately $29.5 million of general and administrative expenses for the pro forma year ended December 31, 2013 and approximately $30.3 million for the pro forma twelve months ended June 30, 2014. The remaining amounts included in general and administrative expenses include items such as management, sales and regional office expenses that are directly related to the operations of our business segments. The $4.9 million decrease in our general and administrative expenses compared to the pro forma year ended December 31, 2013 is due to the following:

    a $12.5 million decrease in professional fees related to the commencement of our initial public offering during the pro forma year ended December 31, 2013; partially offset by

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    a $3.5 million anticipated increase of incremental expenses of being a publicly traded partnership, which includes costs associated with SEC reporting requirements, tax return and Schedule K-1 preparation and distribution, independent audit fees, legal fees, investor relations, Sarbanes Oxley compliance, stock exchange listing, register and transfer agent fees, incremental officer and director liability expenses and director compensation.

    a $2.3 million increase in corporate personnel expense as our pro forma results for the year ended December 31, 2013 do not include a full year of expense from additional headcount made during the second half of 2013 to support the growth of our business;

    a $2.5 million increase in our NGL distribution and sales segment as a result (i) growth projects in our cylinder exchange business and (ii) our pro forma results for the year ended December 31, 2013 do not include a full year of expense from two individually insignificant acquisitions made in the second half of 2013.

        The $8.1 million decrease in our general and administrative expenses compared to the pro forma twelve months ended June 30, 2014 is due to the following:

    an $11.1 million decrease in professional fees related to the commencement of our initial public offering during the pro forma year twelve months ended June 30, 2014; partially offset by

    a $3.5 million anticipated increase of incremental expenses of being a publicly traded partnership as discussed above.

    Adjusted EBITDA

        We estimate that Adjusted EBITDA for the twelve months ending September 30, 2015 will be $66.8 million, compared to $35.5 million for the pro forma year ended December 31, 2013 and $24.4 million for the pro forma twelve months ended June 30, 2014. We use Adjusted EBITDA in our segment analysis because it is an important supplemental measure of our performance.

        The anticipated increase in Adjusted EBITDA is primarily attributed to items previously discussed and is provided on a segment basis in the table below.

 
  Pro Forma   Forecasted  
($ in millions)
  Year Ended
December 31, 2013
  Twelve Months
Ended June 30, 2014
  Twelve Months
Ending September 30, 2015
 

Crude oil pipelines and storage

  $ 14.7   $ 19.5   $ 36.0  

Crude oil supply and logistics

    14.7     7.9     17.6  

Refined products terminals and storage

    16.1     12.4     13.3  

NGL distribution and sales

    15.5     12.0     22.5  

Discontinued operations(1)

    2.0     1.4      

Public partnership general and administrative expenses(2)

            (3.5 )

Corporate and other(3)

    (27.5 )   (28.8 )   (19.1 )
               

Total Adjusted EBITDA(4)

  $ 35.5   $ 24.4   $ 66.8  

(1)
In June 2014, we completed the sale of our crude oil logistics operations in the Bakken region of North Dakota, Montana and Wyoming.

(2)
Incremental general and administrative expenses that we expect to incur as a result of becoming a publicly traded partnership are not included in our Adjusted EBITDA for the pro forma periods but are included for the forecast period.

(3)
Includes general partnership expenses associated with managing all reportable segments, which includes the impact of professional fees of approximately $14.1 million and $12.7 million for the pro forma year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively. As previously discussed, we expect these professional fees to decrease by $12.5 million and $11.1 million for the twelve months ending September 30, 2015 compared to the pro forma

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    year ended December 31, 2013 and the pro forma twelve months ended June 30, 2014, respectively.

(4)
Adjusted EBITDA is a financial measure not presented in accordance with GAAP. For a definition of Adjusted EBITDA and a reconciliation to its most directly comparable financial measures calculated in accordance with GAAP, please read "Selected Historical and Pro Forma Combined Consolidated Financial and Operating Data—Non-GAAP Financial Measures," and for a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."

    Depreciation and Amortization

        We estimate that depreciation and amortization expense for the twelve months ending September 30, 2015 will be $50.4 million, compared to $36.5 million for the pro forma year ended December 31, 2013 and $41.5 million for the pro forma twelve months ended June 30, 2014. Estimated depreciation and amortization expense reflects management's estimates, which are based on consistent average depreciable asset lives and depreciation and amortization methodologies. The increase in depreciation and amortization expense is primarily attributable to our expected increase in maintenance capital expenditures and expansion capital expenditures during the twelve months ending September 30, 2015.

    Capital Expenditures

        We estimate that total non-acquisition related capital expenditures for the twelve months ending September 30, 2015 will be $112.7 million, compared to non-acquisition related capital expenditures of $47.7 million for the pro forma year ended December 31, 2013 and $35.5 million for the pro forma twelve months ended June 30, 2014.

        Maintenance capital expenditures.    We estimate that we will spend $4.0 million on maintenance capital expenditures for the twelve months ending September 30, 2015, compared to $3.5 million spent during the pro forma year ended December 31, 2013 and $2.4 million spent during the pro forma twelve months ended June 30, 2014. We believe our forecasted maintenance capital expenditures are consistent with historical spending. The types of maintenance capital expenditures that we expect to incur include vehicle replacement costs for our crude oil service fleet, repairs to our NGL customer service centers, replacement and tank maintenance for our cylinder exchange business and replacement of rack loading equipment at our refined products terminals. For a discussion of our maintenance capital expenditures, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures."

        Expansion capital expenditures.    We estimate that we will spend $108.7 million on expansion capital expenditures for the twelve months ending September 30, 2015, compared to $44.2 million for the pro forma year ended December 31, 2013 and $33.1 million for the pro forma twelve months ended June 30, 2014. Of the expansion capital expenditures for the pro forma year ended December 31, 2013 and pro forma twelve months ended June 30, 2014, $22.0 million and $13.2 million, respectively related to expansion projects to our Silver Dollar Pipeline System. Our planned capital expenditures primarily relate to the following, all of which will be funded by borrowings under our revolving credit facility:

    In March 2014, we amended a five-year agreement with an existing customer to significantly increase that customer's minimum volume commitment and allowed us to commit to expand the Silver Dollar Pipeline System by adding 30 miles of additional pipeline, including an interconnection to a second long-haul transportation pipeline. We expect to complete these projects in the fourth quarter of 2014 at a cost of approximately $15.9 million, $5.4 million of which will be incurred during the twelve months ending September 30, 2015.

    Based on ongoing discussions with producers and marketers in the Southern Wolfcamp, during the twelve months ending September 30, 2015, we expect to incur an additional $78.1 million of

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      expansion capital expenditures to (i) build additional laterals underpinned by acreage dedications or volume commitments, (ii) connect additional central production facilities, (iii) add storage capacity, (iv) build additional truck injection stations and (v) interconnect with an additional third-party long-haul crude oil transportation pipeline. The new interconnection will increase takeaway capacity of the Silver Dollar Pipeline System and further diversify the market access we offer our customers.

    The addition of new large-volume or national accounts in our cylinder exchange business, which is expected to cost $9.3 million during the twelve months ending September 30, 2015 and is expected to be completed by the end of 2015.

    The addition of diluent capabilities at our Caddo Mills refined products terminal, which is expected to cost $4.0 million during the twelve months ending September 30, 2015 and is expected to be completed by the second quarter of 2015.

    The addition of butane blending at our North Little Rock refined products terminal, which is expected to cost $3.2 million during the twelve months ending September 30, 2015 and is expected to be completed by the fourth quarter of 2014.

    The remaining $8.7 million of expansion capital expenditures relate primarily to various planned organic growth projects within our crude oil supply and NGL sales businesses.

        For a discussion of our expansion capital expenditures, please read "Provisions of Our Partnership Agreement Relating to Cash Distributions—Capital Expenditures."

    Financing

        Cash and indebtedness.    Upon the completion of this offering and after using the net proceeds from this offering to repay amounts outstanding under our revolving credit facility as described in "Use of Proceeds," we expect to have approximately $75.0 million of outstanding indebtedness under our revolving credit facility, with available capacity of approximately $200.0 million. Our revolving credit facility contains an accordion feature that will allow us to increase the borrowing capacity from $275.0 million to $425.0 million, subject to obtaining additional or increased lender commitments. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility."

        We expect that our future sources of liquidity, including cash flow from operations and available borrowing capacity under our revolving credit facility, will be sufficient to fund capital expenditures included in this forecast. We intend to fund our forecasted expansion capital expenditures with borrowings under to our revolving credit facility.

        Interest expense.    Our average borrowings for the twelve months ending September 30, 2015 are expected to be approximately $152.8 million and bear interest at an estimated weighted-average rate of 2.88%. Accordingly, we expect to incur $6.4 million of interest expense during the twelve months ending September 30, 2015 related to $5.3 million of interest expense on our expected credit facility borrowings, unused commitment fees and letters of credit fees, $0.8 million of amortization of deferred financing costs and $0.3 million of interest on our other debt.

    Regulatory, Industry, Economic and Other Factors

        Our forecast for the twelve month period ending September 30, 2015, is based on the following significant assumptions related to regulatory, industry and economic factors:

    there will not be any new federal, state or local regulation of any of the businesses we operate, or any new interpretation of existing regulations, that will be materially adverse to our business;

    there will not be any major adverse change in the midstream energy sector, any of the businesses we operate, commodity prices, capital or insurance markets or general economic conditions;

    there will not be any material accidents, weather-related incidents, unscheduled downtime or similar unanticipated events with respect to our facilities or those of third parties on which we depend;

    we will not make any acquisitions or other significant expansion capital expenditures (other than as described above); and

    market, insurance and overall economic conditions will not change substantially.

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

        Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.


Distributions of Available Cash

    General

        Our partnership agreement requires that, within 45 days after the end of each quarter, beginning with the quarter ending December 31, 2014 we distribute all of our available cash to unitholders of record on the applicable record date. We will adjust the amount of our distribution for the period from the completion of this offering through December 31, 2014 based on the actual length of the period.

    Definition of Available Cash

        Available cash generally means, for any quarter, all cash and cash equivalents on hand at the end of that quarter:

    less, the amount of cash reserves established by our general partner to:

    provide for the proper conduct of our business (including reserves for our future capital expenditures and anticipated future debt service requirements);

    comply with applicable law, any of our debt instruments or other agreements; or

    provide funds for distributions to our unitholders and to our general partner for any one or more of the next four quarters (provided that our general partner may not establish cash reserves for distributions if the effect of the establishment of such reserves will prevent us from distributing the minimum quarterly distribution on all common units and any cumulative arrearages on such common units for the current quarter);

    plus, if our general partner so determines, all or any portion of the cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of such quarter.

        The purpose and effect of the last bullet point above is to allow our general partner, if it so decides, to use cash from working capital borrowings made after the end of the quarter but on or before the date of determination of available cash for that quarter to pay distributions to unitholders. Under our partnership agreement, working capital borrowings are generally borrowings that are made under a credit facility, commercial paper facility or similar financing arrangement, and in all cases are used solely for working capital purposes or to pay distributions to partners and with the intent of the borrower to repay such borrowings within twelve months with funds other than from additional working capital borrowings.

    Intent to Distribute the Minimum Quarterly Distribution

        Under our current cash distribution policy, we intend to make a minimum quarterly distribution to the holders of our common units and subordinated units of $0.3250 per unit, or $1.30 per unit on an annualized basis, to the extent we have sufficient cash from our operations after the establishment of cash reserves and the payment of costs and expenses, including reimbursements of expenses to our general partner. However, there is no guarantee that we will pay the minimum quarterly distribution on our units in any quarter. The amount of distributions paid under our policy and the decision to make any distribution is determined by our general partner, taking into consideration the terms of our partnership agreement. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Revolving Credit Facility" for a discussion of

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the restrictions included in our revolving credit facility that may restrict our ability to make distributions.

    General Partner Interest and Incentive Distribution Rights

        Initially, our general partner will own a non-economic general partner interest. Our general partner holds incentive distribution rights that will entitle it to receive increasing percentages, up to a maximum of 50.0%, of the cash we distribute from operating surplus (as defined below) in excess of $0.37375 per unit per quarter. The maximum distribution of 50.0% does not include any distributions that our general partner or its affiliates may receive on common or subordinated units that they own. Please read "—General Partner Interest and Incentive Distribution Rights" for additional information.


Operating Surplus and Capital Surplus

    General

        All cash distributed to unitholders will be characterized as either being paid from "operating surplus" or "capital surplus." We treat distributions of available cash from operating surplus differently than distributions of available cash from capital surplus.

    Operating Surplus

        We define operating surplus as:

    $30.0 million (as described below); plus

    all of our cash receipts after the closing of this offering, excluding cash from interim capital transactions (as defined below), provided that cash receipts from the termination of a commodity hedge or interest rate hedge prior to its specified termination date shall be included in operating surplus in equal quarterly installments over the remaining scheduled life of such commodity hedge or interest rate hedge; plus

    working capital borrowings made after the end of a quarter but on or before the date of determination of operating surplus for that quarter; plus

    cash distributions (including incremental distributions on incentive distribution rights) paid in respect of equity issued, other than equity issued in this offering, to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date the capital asset commences commercial service and the date that it is abandoned or disposed of; less

    all of our operating expenditures (as defined below) after the closing of this offering; less

    the amount of cash reserves established by our general partner to provide funds for future operating expenditures; less

    all working capital borrowings not repaid within twelve months after having been incurred, or repaid within such 12-month period with the proceeds of additional working capital borrowings.

        As described above, operating surplus does not reflect actual cash on hand that is available for distribution to our unitholders and is not limited to cash generated by operations. For example, it includes a provision that will enable us, if we choose, to distribute as operating surplus up to $30.0 million of cash we receive in the future from non-operating sources such as asset sales, issuances of securities and long-term borrowings that would otherwise be distributed as capital surplus. In addition, the effect of including, as described above, certain cash distributions on equity interests in operating surplus will be to increase operating surplus by the amount of any such cash distributions. As

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a result, we may also distribute as operating surplus up to the amount of any such cash that we receive from non-operating sources.

        The proceeds of working capital borrowings increase operating surplus and repayments of working capital borrowings are generally operating expenditures (as described below) and thus reduce operating surplus when repayments are made. However, if working capital borrowings, which increase operating surplus, are not repaid during the twelve month period following the borrowing, they will be deemed repaid at the end of such period, thus decreasing operating surplus at such time. When such working capital borrowings are in fact repaid, they will not be treated as a further reduction in operating surplus because operating surplus will have been previously reduced by the deemed repayment.

        We define interim capital transactions as (i) borrowings, refinancings or refundings of indebtedness (other than working capital borrowings and items purchased on open account or for a deferred purchase price in the ordinary course of business) and sales of debt securities, (ii) sales of equity securities, (iii) sales or other dispositions of assets, other than sales or other dispositions of inventory, accounts receivable and other assets in the ordinary course of business and sales or other dispositions of assets as part of normal asset retirements or replacements and (iv) capital contributions received by us.

        We define operating expenditures as all of our cash expenditures, including, but not limited to, taxes, reimbursements of expenses of our general partner and its affiliates, officer, director and employee compensation, debt service payments, payments made in the ordinary course of business under interest rate hedge contracts and commodity hedge contracts (provided that payments made in connection with the termination of any interest rate hedge contract or commodity hedge contract prior to the expiration of its settlement or termination date specified therein will be included in operating expenditures in equal quarterly installments over the remaining scheduled life of such interest rate hedge contract or commodity hedge contract and amounts paid in connection with the initial purchase of a rate hedge contract or a commodity hedge contract will be amortized at the life of such rate hedge contract or commodity hedge contract), maintenance capital expenditures (as discussed in further detail below), and repayment of working capital borrowings; provided, however, that operating expenditures will not include:

    repayments of working capital borrowings where such borrowings have previously been deemed to have been repaid (as described above);

    payments (including prepayments and prepayment penalties) of principal of and premium on indebtedness other than working capital borrowings;

    expansion capital expenditures;

    payment of transaction expenses (including taxes) relating to interim capital transactions;

    distributions to our partners;

    repurchases of partnership interests (excluding repurchases we make to satisfy obligations under employee benefit plans); or

    any other expenditures or payments using the proceeds of this offering that are described in "Use of Proceeds."

    Capital Surplus

        Capital surplus is defined in our partnership agreement as any distribution of available cash in excess of our cumulative operating surplus. Accordingly, except as described above, capital surplus would generally be generated by:

    borrowings other than working capital borrowings;

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    sales of our equity and debt securities;

    sales or other dispositions of assets, other than inventory, accounts receivable and other assets sold in the ordinary course of business or as part of ordinary course retirement or replacement of assets; and

    capital contributions received.

    Characterization of Cash Distributions

        All available cash distributed by us on any date from any source will be treated as distributed from operating surplus until the sum of all available cash distributed by us since the closing of this offering equals the operating surplus from the closing of this offering through the end of the quarter immediately preceding that distribution. We anticipate that distributions from operating surplus will generally not represent a return of capital. However, operating surplus, as defined in our partnership agreement, includes certain components, including a $30.0 million cash basket, that represent non-operating sources of cash. Consequently, it is possible that all or a portion of specific distributions from operating surplus may represent a return of capital. Any available cash distributed by us in excess of our cumulative operating surplus will be deemed to be capital surplus under our partnership agreement. Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering and as a return of capital. We do not anticipate that we will make any distributions from capital surplus.


Capital Expenditures

        Maintenance capital expenditures are cash expenditures (including expenditures for the construction or development of new capital assets or the replacement, improvement or expansion of existing capital assets) made to maintain our operating income or operating capacity. We expect that a primary component of maintenance capital expenditures will include expenditures to repair, refurbish and replace pipelines, to connect new wells to maintain throughput, for routine vehicle replacement costs for our crude oil service fleet and our NGL hard shell tank trucks, repairs to our NGL customer service centers, replacement and tank maintenance for our cylinder exchange business and replacement of rack loading equipment at our refined products terminals.

        Expansion capital expenditures are cash expenditures incurred for acquisitions or capital improvements that we expect will increase our operating capacity or operating income over the long-term. Expansion capital expenditures include interest payments (and related fees) on debt incurred to finance all or a portion of expansion capital expenditures in respect of the period from the date that we enter into a binding obligation to commence the construction, development, replacement, improvement or expansion of a capital asset and ending on the earlier to occur of the date that such capital improvement commences commercial service and the date that such capital improvement is abandoned or disposed of. Examples of expansion capital expenditures include the acquisition of equipment, or the construction, development or acquisition of additional crude oil storage facilities, crude oil pipelines, crude oil gathering and transportation trucks, refined products terminals, cylinder exchanges cages, NGL hard shell tank trucks and cylinders and related or similar midstream assets.

        Maintenance capital expenditures reduce operating surplus, but expansion capital expenditures do not. Capital expenditures that are made in part for maintenance capital purposes and in part for expansion capital purposes will be allocated as maintenance capital expenditures or expansion capital expenditures by our general partner.

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Subordinated Units and Subordination Period

    General

        Our partnership agreement provides that, during the subordination period (which we define below), the common units will have the right to receive distributions of available cash from operating surplus each quarter in an amount equal to $0.3250 per common unit, which amount is defined in our partnership agreement as the minimum quarterly distribution, plus any arrearages in the payment of the minimum quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units. These units are deemed "subordinated" because for a period of time, referred to as the subordination period, the subordinated units will not be entitled to receive any distributions until the common units have received the minimum quarterly distribution plus any arrearages from prior quarters. Furthermore, no arrearages will be paid on the subordinated units. The practical effect of the subordinated units is to increase the likelihood that, during the subordination period, there will be available cash to be distributed on the common units.

    Subordination Period

        Except as described below, the subordination period will begin on the closing date of this offering and will extend until the first business day following the distribution of available cash in respect of any quarter beginning after September 30, 2017, that each of the following tests are met:

    distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $1.30 (the annualized minimum quarterly distribution), for each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date;

    the adjusted operating surplus (as defined below) generated during each of the three consecutive, non-overlapping four-quarter periods immediately preceding that date equaled or exceeded the sum of $1.30 (the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during those periods on a fully diluted basis; and

    there are no arrearages in payment of the minimum quarterly distribution on the common units.

        For the period after the closing of this offering through December 31, 2014, our partnership agreement will prorate the minimum quarterly distribution based on the actual length of the period, and use such prorated distribution for all purposes, including in determining whether the test described above has been satisfied.

    Early Termination of the Subordination Period

        Notwithstanding the foregoing, the subordination period will automatically terminate on the first business day following the distribution of available cash in respect of any quarter, beginning with the quarter ending September 30, 2015, that each of the following tests are met:

    distributions of available cash from operating surplus on each of the outstanding common units and subordinated units equaled or exceeded $1.95 (150.0% of the annualized minimum quarterly distribution) for the four-quarter period immediately preceding that date;

    the adjusted operating surplus (as defined below) generated during the four-quarter period immediately preceding that date equaled or exceeded the sum of (i) $1.95 (150.0% of the annualized minimum quarterly distribution) on all of the outstanding common units and subordinated units during that period on a fully diluted basis and (ii) the corresponding distributions on the incentive distribution rights; and

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    there are no arrearages in payment of the minimum quarterly distributions on the common units.

    Expiration Upon Removal of the General Partner

        In addition, if the unitholders remove our general partner other than for cause:

    the subordinated units held by any person will immediately and automatically convert into common units on a one-for-one basis, provided (i) neither such person nor any of its affiliates voted any of its units in favor of the removal and (ii) such person is not an affiliate of the successor general partner;

    if all of the subordinated units convert pursuant to the foregoing, all cumulative common unit arrearages on the common units will be extinguished and the subordination period will end; and

    our general partner will have the right to convert its general partner interest and its incentive distribution rights into common units or to receive cash in exchange for those interests.

    Expiration of the Subordination Period

        When the subordination period ends, each outstanding subordinated unit will convert into one common unit and will thereafter participate pro rata with the other common units in distributions of available cash.

    Adjusted Operating Surplus

        Adjusted operating surplus is intended to reflect the cash generated from operations during a particular period and therefore excludes net drawdowns of reserves of cash established in prior periods. Adjusted operating surplus for a period consists of:

    operating surplus generated with respect to that period (excluding any amount attributable to the item described in the first bullet of the definition of operating surplus); less

    any net increase in working capital borrowings with respect to that period; less

    any net decrease in cash reserves for operating expenditures with respect to that period not relating to an operating expenditure made with respect to that period; plus

    any net decrease in working capital borrowings with respect to that period; plus

    any net decrease made in subsequent periods to cash reserves for operating expenditures initially established with respect to that period to the extent such decrease results in a reduction in adjusted operating surplus in subsequent periods; plus

    any net increase in cash reserves for operating expenditures with respect to that period required by any debt instrument for the repayment of principal, interest or premium.


Distributions of Available Cash From Operating Surplus During the Subordination Period

        We will make distributions of available cash from operating surplus for any quarter during the subordination period in the following manner:

    first, 100.0% to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter;

    second, 100.0% to the common unitholders, pro rata, until we distribute for each outstanding common unit an amount equal to any arrearages in payment of the minimum quarterly distribution on the common units for any prior quarters during the subordination period;

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    third, 100.0% to the subordinated unitholders, pro rata, until we distribute for each outstanding subordinated unit an amount equal to the minimum quarterly distribution for that quarter; and

    thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        The preceding discussion is based on the assumption that we do not issue additional classes of equity securities.


Distributions of Available Cash From Operating Surplus After the Subordination Period

        We will make distributions of available cash from operating surplus for any quarter after the subordination period in the following manner:

    first, 100.0% to all unitholders, pro rata, until we distribute for each outstanding unit an amount equal to the minimum quarterly distribution for that quarter; and

    thereafter, in the manner described in "—General Partner Interest and Incentive Distribution Rights" below.

        The preceding discussion is based on the assumption that we do not issue additional classes of equity securities.


General Partner Interest and Incentive Distribution Rights

        Our general partner owns a non-economic general partner interest in us, which does not entitle it to receive cash distributions. However, our general partner may in the future own common units or other equity interests in us, and will be entitled to receive distributions on such interests.

        Incentive distribution rights represent the right to receive an increasing percentage (15.0%, 25.0% and 50.0%) of quarterly distributions of available cash from operating surplus after the minimum quarterly distribution and the target distribution levels have been achieved. 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 discussion assumes that there are no arrearages on the common units and that our general partner continues to own the incentive distribution rights.

        If for any quarter:

    we have distributed available cash from operating surplus to the common unitholders and subordinated unitholders in an amount equal to the minimum quarterly distribution; and

    we have distributed available cash from operating surplus on outstanding common units in an amount necessary to eliminate any cumulative arrearages in payment of the minimum quarterly distribution;

then, we will distribute any additional available cash from operating surplus for that quarter among the unitholders and our general partner in the following manner:

    first, 100.0% to all unitholders, pro rata, until each unitholder receives a total of $0.37375 per unit for that quarter (the "first target distribution");

    second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives a total of $0.40625 per unit for that quarter (the "second target distribution");

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    third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives a total of $0.4875 per unit for that quarter (the "third target distribution"); and

    thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner (in its capacity as the holder of our incentive distribution rights).


Percentage Allocations of Available Cash From Operating Surplus

        The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner (in its capacity as the holder of our incentive distribution rights) 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 (in its capacity as the holder of our incentive distribution rights) 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 target amount." The percentage interests shown for our unitholders and our general partner (in its capacity as the holder of our incentive distribution rights) 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 (in its capacity as the holder of our incentive distribution rights) assume that our general partner has not transferred its incentive distribution rights and that there are no arrearages on common units.

 
   
   
  Marginal Percentage Interest
in Distributions
 
 
  Total Quarterly Distribution
Per Unit Target Amount
  Unitholders   General Partner
(in Its Capacity as
the Holder of Our
Incentive
Distribution Rights)
 

Minimum quarterly distribution

             $0.32500         100 %    

First target distribution

  above $0.32500   up to $0.37375     100 %    

Second target distribution

  above $0.37375   up to $0.40625     85 %   15 %

Third target distribution

  above $0.40625   up to $0.48750     75 %   25 %

Thereafter

  above $0.48750         50 %   50 %


General Partner's Right to Reset Incentive Distribution Levels

        Our general partner, as the initial holder of our incentive distribution rights, has the right under our partnership agreement, subject to certain conditions, to elect to relinquish the right to receive incentive distribution payments based on the initial target distribution levels and to reset, at higher levels, the minimum quarterly distribution amount and target distribution levels upon which the incentive distribution payments to our general partner would be set. If our general partner transfers all or a portion of the incentive distribution rights in the future, then the holder or holders of a majority of our incentive distribution rights will be entitled to exercise this right. The following discussion assumes that our general partner holds all of the incentive distribution rights at the time that a reset election is made. Our general partner's right to reset the minimum quarterly distribution amount and the target distribution levels upon which the incentive distributions payable to our general partner are based may be exercised, without approval of our unitholders or the conflicts committee, at any time when there are no subordinated units outstanding, we have made cash distributions to the holders of the incentive distribution rights at the highest level of incentive distribution for each of the four consecutive fiscal quarters immediately preceding such time and the amount of each such distribution did not exceed adjusted operating surplus for such quarter, respectively. If our general partner and its affiliates are not the holders of a majority of the incentive distribution rights at the time an election is

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made to reset the minimum quarterly distribution amount and the target distribution levels, then the proposed reset will be subject to the prior written concurrence of the general partner that the conditions described above have been satisfied. The reset minimum quarterly distribution amount and target distribution levels will be higher than the minimum quarterly distribution amount and the target distribution levels prior to the reset such that our general partner will not receive any incentive distributions under the reset target distribution levels until cash distributions per unit following this event increase as described below. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would otherwise not be sufficiently accretive to cash distributions per common unit, taking into account the existing levels of incentive distribution payments being made to our general partner.

        In connection with the resetting of the minimum quarterly distribution amount and the target distribution levels and the corresponding relinquishment by our general partner of incentive distribution payments based on the target distributions prior to the reset, our general partner will be entitled to receive a number of newly issued common units based on a predetermined formula described below that takes into account the "cash parity" value of the average cash distributions related to the incentive distribution rights received by our general partner for the two quarters immediately preceding the reset event as compared to the average cash distributions per common unit during that two-quarter period.

        The number of common units that our general partner would be entitled to receive from us in connection with a resetting of the minimum quarterly distribution amount and the target distribution levels then in effect would be equal to the quotient determined by dividing (x) the average aggregate amount of cash distributions received by our general partner in respect of its incentive distribution rights during the two consecutive fiscal quarters ended immediately prior to the date of such reset election by (y) the average of the aggregate amount of cash distributed per common unit during each of these two quarters.

        Following a reset election, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (which amount we refer to as the "reset minimum quarterly distribution") and the target distribution levels will be reset to be correspondingly higher such that we would distribute all of our available cash from operating surplus for each quarter thereafter as follows:

    first, 100.0% to all unitholders, pro rata, until each unitholder receives an amount equal to 115.0% of the reset minimum quarterly distribution for that quarter;

    second, 85.0% to all unitholders, pro rata, and 15.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives an amount per unit equal to 125.0% of the reset minimum quarterly distribution for the quarter;

    third, 75.0% to all unitholders, pro rata, and 25.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until each unitholder receives an amount per unit equal to 150.0% of the reset minimum quarterly distribution for the quarter; and

    thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner (in its capacity as the holder of our incentive distribution rights).

        The following table illustrates the percentage allocations of available cash from operating surplus between the unitholders and our general partner (in its capacity as the holder of our incentive distribution rights) at various cash distribution levels (i) pursuant to the cash distribution provisions of our partnership agreement in effect at the completion of this offering, as well as (ii) following a hypothetical reset of the minimum quarterly distribution and target distribution levels based on the

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assumption that the average quarterly cash distribution amount per common unit during the two fiscal quarters immediately preceding the reset election was $0.50.

 
   
   
  Marginal Percentage Interest
in Distributions
   
   
 
  Quarterly Distribution Per Unit
Prior to Reset
  Common
Unitholders
  General Partner
(in Its Capacity as
the Holder of Our
Incentive
Distribution Rights)
  Quarterly Distribution Per Unit
Following Hypothetical Reset

Minimum quarterly distribution

          $0.32500         100.0 %                $0.5000    

First target distribution

  above $0.32500   up to $0.37375     100.0 %     above $0.5000   up to $0.5750(1)

Second target distribution

  above $0.37375   up to $0.40625     85.0 %   15.0 % above $0.5750(1)   up to $0.6250(2)

Third target distribution

  above $0.40625   up to $0.48750     75.0 %   25.0 % above $0.6250(2)   up to $0.7500(3)

Thereafter

  above $0.48750         50.0 %   50.0 % above $0.7500(3)    

(1)
This amount is 115.0% of the hypothetical reset minimum quarterly distribution.

(2)
This amount is 125.0% of the hypothetical reset minimum quarterly distribution.

(3)
This amount is 150.0% of the hypothetical reset minimum quarterly distribution.

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and our general partner (in its capacity as the holder of our incentive distribution rights), based on an average of the amounts distributed for the two quarters immediately prior to the reset. The table assumes that immediately prior to the reset there would be 36,427,004 common units outstanding, and the average distribution to each common unit would be $0.5000 per quarter for the two consecutive non-overlapping quarters prior to the reset.

 
  Quarterly Distribution Per Unit
Prior to Reset
  Cash Distributions to
Common Unitholders
Prior to Reset
  Cash Distribution to
General Partner
(in its Capacity as
the Holder of Our
Incentive
Distribution Rights)
Prior to Reset
  Total Distributions  

Minimum quarterly distribution

          $0.32500       $ 11,838,776   $   $ 11,838,776  

First target distribution

  above $0.32500   up to $0.37375     1,775,816         1,775,816  

Second target distribution

  above $0.37375   up to $0.40625     1,183,878     208,920     1,392,797  

Third target distribution

  above $0.40625   up to $0.48750     2,959,694     986,565     3,946,259  

Thereafter

  above $0.48750         455,338     455,338     910,675  
                       

          $ 18,213,502   $ 1,650,822   $ 19,864,324  
                       

        The following table illustrates the total amount of available cash from operating surplus that would be distributed to the unitholders and the general partner (in its capacity as the holder of our incentive distribution rights), with respect to the quarter after the reset occurs. The table reflects that, as a result of the reset, there would be 39,728,648 common units outstanding and that the average distribution to each common unit would be $0.50. The number of common units issued as a result of the reset was calculated by dividing (x) 1,650,822 as the average of the amounts received by the general partner in respect of its incentive distribution rights for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, by (y) the average of the cash distributions made on each common

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unit per quarter for the two consecutive non-overlapping quarters prior to the reset as shown in the table above, or $0.50000.

 
   
   
   
  Cash Distribution to
General Partner After Reset
   
 
 
   
   
  Cash
Distributions
to Common
Unitholders
After Reset
   
 
 
  Quarterly Distribution Per Unit
After Reset
  Common
Units
  Incentive
Distribution
Rights
  Total   Total
Distributions
 

Minimum quarterly distribution

          $0.50000       $ 18,213,502   $ 1,650,822   $   $ 1,650,822   $ 19,864,324  

First target distribution

  above $0.50000   up to $0.57500                          

Second target distribution

  above $0.57500   up to $0.62500                          

Third target distribution

  above $0.62500   up to $0.75000                          

Thereafter

  above $0.75000                              
                               

          $ 18,213,502   $ 1,650,822   $   $ 1,650,822   $ 19,864,324  
                               

        Our general partner will be entitled to cause the minimum quarterly distribution amount and the target distribution levels to be reset on more than one occasion, provided that it may not make a reset election except at a time when it has received incentive distributions for the immediately preceding four consecutive fiscal quarters based on the highest level of incentive distributions that it is entitled to receive under our partnership agreement.


Distributions From Capital Surplus

    How Distributions From Capital Surplus Will Be Made

        We will make distributions of available cash from capital surplus, if any, in the following manner:

    first, 100.0% to all unitholders, pro rata, until we distribute for each common unit that was issued in this offering, an amount of available cash from capital surplus equal to the initial public offering price in this offering;

    second, 100.0% to all unitholders, pro rata, until we distribute for each common unit, an amount of available cash from capital surplus equal to any unpaid arrearages in payment of the minimum quarterly distribution on the outstanding common units; and

    thereafter, as if they were from operating surplus.

        The preceding discussion is based on the assumption we do not issue additional classes of equity securities.

    Effect of a Distribution From Capital Surplus

        Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from this initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the "unrecovered initial unit price." Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered initial unit price. Because distributions of capital surplus will reduce the minimum quarterly distribution after any of these distributions are made, it may be easier for our general partner to receive incentive distributions and for the subordinated units to convert into common units. However, any distribution of capital surplus before the unrecovered initial unit price is reduced to zero cannot be applied to the payment of the minimum quarterly distribution or any arrearages.

        Once we distribute capital surplus on a unit issued in this offering in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50.0% being paid to the unitholders, pro rata, and 50.0% to the holder of our incentive distribution rights.

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Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

        In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:

    the minimum quarterly distribution;

    target distribution levels;

    the unrecovered initial unit price; and

    the arrearages in payment of the minimum quarterly distribution on the common units.

        For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered initial unit price would each be reduced to 50.0% of its initial level, and each subordinated unit would be split into two subordinated units. We will not make any adjustment by reason of the issuance of additional units for cash or property.

        In addition, if legislation is enacted or if the official interpretation of existing law is modified by a governmental authority, so that we become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, our partnership agreement specifies that the minimum quarterly distribution and the target distribution levels for each quarter may be reduced by multiplying each distribution level by a fraction, the numerator of which is available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) and the denominator of which is the sum of available cash for that quarter (reduced by the amount of the estimated tax liability for such quarter payable by reason of such legislation or interpretation) plus our general partner's estimate of our aggregate liability for the quarter for such income taxes payable by reason of such legislation or interpretation. To the extent that the actual tax liability differs from the estimated tax liability for any quarter, the difference may be accounted for in subsequent quarters.


Distributions of Cash Upon Liquidation

    General

        If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and holders of the incentive distribution rights, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

        The allocations of gain and loss upon liquidation are intended, to the extent possible, to entitle the holders of outstanding common units to a preference over the holders of outstanding subordinated units upon our liquidation, to the extent required to permit common unitholders to receive their unrecovered initial unit price plus the minimum quarterly distribution for the quarter during which liquidation occurs plus any unpaid arrearages in payment of the minimum quarterly distribution on the common units. However, there may not be sufficient gain upon our liquidation to enable the holders of common units to fully recover all of these amounts, even though there may be distributable cash flow available to the holders of subordinated units. Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights.

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    Manner of Adjustments for Gain

        The manner of the adjustment for gain is set forth in our partnership agreement. If our liquidation occurs before the end of the subordination period, we will allocate any gain to our partners in the following manner:

    first, 100.0% to the common unitholders, pro rata, until the capital account for each common unit is equal to the sum of:

    (1)
    the unrecovered initial unit price;

    (2)
    the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs; and

    (3)
    any unpaid arrearages in payment of the minimum quarterly distribution;

    second, 100.0% to the subordinated unitholders, pro rata, until the capital account for each subordinated unit is equal to the sum of:

    (1)
    the unrecovered initial unit price; and

    (2)
    the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;

    third, 100.0% to all unitholders, pro rata, until we allocate under this paragraph an amount per unit equal to:

    (1)
    the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

    (2)
    the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 100.0% to the unitholders, pro rata, for each quarter of our existence;

    fourth, 85.0% to all unitholders, pro rata, and 15.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until we allocate under this paragraph an amount per unit equal to:

    (1)
    the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

    (2)
    the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85.0% to the unitholders, pro rata, and 15.0% to our general partner (in its capacity as the holder of our incentive distribution rights) for each quarter of our existence;

    fifth, 75.0% to all unitholders, pro rata, and 25.0% to our general partner (in its capacity as the holder of our incentive distribution rights), until we allocate under this paragraph an amount per unit equal to:

    (1)
    the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

    (2)
    the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75.0% to the unitholders, pro rata, and 25.0% to our general partner (in its capacity as the holder of our incentive distribution rights) for each quarter of our existence;

    thereafter, 50.0% to all unitholders, pro rata, and 50.0% to our general partner (in its capacity as the holder of our incentive distribution rights).

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        The percentages set forth above are based on the assumption that our general partner has not transferred its incentive distribution rights and that we do not issue additional classes of equity securities.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that clause (3) of the second bullet point above and all of the fourth bullet point above will no longer be applicable.

    Manner of Adjustments for Losses

        If our liquidation occurs before the end of the subordination period, after making allocations of loss to the unitholders in a manner intended to offset in reverse order the allocations of gains that have previously been allocated, we will generally allocate any loss to our unitholders in the following manner:

    first, 100.0% to the holders of subordinated units in proportion to the positive balances in their capital accounts, until the capital accounts of the subordinated unitholders have been reduced to zero; and

    thereafter, 100.0% to the holders of common units in accordance with their percentage interest in us.

        If the liquidation occurs after the end of the subordination period, the distinction between common units and subordinated units will disappear, so that all of the first bullet point above will no longer be applicable.

    Adjustments to Capital Accounts

        We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we generally will allocate any unrealized and, for tax purposes, unrecognized gain resulting from the adjustments to the unitholders and the holders of our incentive distribution rights in the same manner as we allocate gain upon liquidation. By contrast to the allocations of gain, and except as provided above, we generally will allocate any unrealized and unrecognized loss resulting from the adjustments to capital accounts upon the issuance of additional units to the unitholders based on their percentage ownership of us. In this manner, prior to the end of the subordination period, we generally will allocate any such loss equally with respect to our common and subordinated units. In the event we make negative adjustments to the capital accounts as a result of such loss, future positive adjustments resulting from the issuance of additional units will be allocated in a manner designed to reverse the prior negative adjustments, and special allocations will be made upon liquidation in a manner that results, to the extent possible, in our unitholders' capital account balances equaling the amounts they would have been if no earlier adjustments for loss had been made.

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SELECTED HISTORICAL AND PRO FORMA COMBINED CONSOLIDATED FINANCIAL AND OPERATING DATA

        The table set forth below presents, as of the dates and for the periods indicated, our selected historical and pro forma combined consolidated financial and operating data.

        The selected historical consolidated financial data presented as of December 31, 2012 and December 31, 2013 and for the years ended December 31, 2011, December 31, 2012 and December 31, 2013 have been derived from our audited historical consolidated financial statements included elsewhere in this prospectus. The summary historical consolidated financial data presented as of June 30, 2013 and June 30, 2014 and for the six months ended June 30, 2013 and June 30, 2014 are derived from our unaudited historical condensed consolidated financial statements.

        The summary pro forma combined consolidated statement of operations for the six months ended June 30, 2014 includes the pro forma effects of the recapitalization transactions, including this offering, described under "—Recapitalization Transactions and Partnership Structure" as if the recapitalization transactions, including this offering, occurred on January 1, 2013. The selected historical consolidated financial data presented as of December 31, 2010 and for the period for May 5, 2010 (date of inception) to December 31, 2010 is derived from our unaudited historical consolidated financial statements that are not included in this prospectus.

        The selected pro forma combined consolidated balance sheet as of June 30, 2014 was prepared as if the recapitalization transactions occurred on June 30, 2014. The selected pro forma combined consolidated statement of operations for the year ended December 31, 2013 gives effect to (i) our acquisition of the Silver Dollar Pipeline System as if it had occurred on January 1, 2013 and (ii) the recapitalization transactions, including this offering, as if they had occurred on January 1, 2013.

        During 2013, we determined that our previously issued audited consolidated financial statements as of December 31, 2012 and results of operations for the year ended December 31, 2012 contained errors. We evaluated those errors and determined that the impact of these errors was material to the results of operations for the year ended December 31, 2012. Accordingly, our previously audited consolidated balance sheet at December 31, 2012 and the statement of operations and statement of cash flows for the year ended December 31, 2012 have been restated to reflect the correction of the errors, including the correction of immaterial errors. Please read note 3 of our consolidated financial statements included elsewhere in this prospectus.

        On February 12, 2014, we acquired certain assets from JP Development. Because we and JP Development are both affiliates of ArcLight, this was a transaction between commonly controlled entities and we were required to account for the transaction in a manner similar to the pooling of interest method of accounting. Under this method of accounting, we reflected in our balance sheet the acquired assets at JP Development's historical carryover basis instead of reflecting the fair market value of assets and liabilities of the acquired assets. In addition, we have retrospectively adjusted our financial statements to include the operating results of the acquired assets from the dates these assets were originally acquired by JP Development (the dates upon which common control began). Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—Recent Developments—JP Development Acquisition and Recast of Historical Financial Statements."

        For a detailed discussion of the following table, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations." The following table should also be read in conjunction with our unaudited pro forma combined consolidated financial statements and audited and unaudited consolidated financial statements included elsewhere in this prospectus. Among other things, those historical and pro forma combined consolidated financial statements include more detailed information regarding the basis of presentation for the information in the following table.

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        The following table presents Adjusted EBITDA, distributable cash flow and adjusted gross margin, financial measures that are not presented in accordance with GAAP. For a discussion of how we derive these measures and a reconciliation of Adjusted EBITDA, distributable cash flow and adjusted gross margin to their most directly comparable financial measures calculated in accordance with GAAP, please read "—Non-GAAP Financial Measures." For a discussion of how we use Adjusted EBITDA to evaluate our operating performance, please read "Management's Discussion and Analysis of Financial Condition and Results of Operations—How We Evaluate Our Operations."

 
   
   
   
   
   
   
  Pro Forma  
 
  Unaudited Period
from May 5, 2010
(date of inception)
to December 31,
2010
  Year Ended
December 31,
  Six Months Ended
June 30,
 
 
   
  Six Months
Ended
June 30,
2014
 
 
  Year Ended
December 31,
2013
 
($ in thousands, except per unit amounts)
  2011   2012(1)   2013(1)   2013   2014  
 
   
   
  (Restated and recast)
   
  (unaudited)
  (unaudited)
 

Statement of Operations Data:

                                                 

Total revenue

  $ 8,541   $ 67,156   $ 427,581   $ 2,102,233   $ 987,804   $ 865,817   $ 2,105,201   $ 865,817  

Costs and expenses:

                                                 

Cost of sales, excluding depreciation and amortization

    6,853     49,048     368,791     1,964,631     918,957     798,193     1,964,631     798,193  

Operating expenses

    1,656     9,584     28,640     61,925     28,202     35,266     62,996     35,266  

General and administrative

    2,163     6,053     20,983     45,284     20,313     23,879     45,699 (2)   23,838 (2)

Depreciation and amortization

    437     2,841     13,856     33,345     15,186     20,165     36,524     20,165  

Loss on disposal of assets

        68     1,142     1,492     998     661     1,492     661  
                                   

Operating income (loss)

    (2,568 )   (438 )   (5,831 )   (4,444 )   4,148     (12,347 )   (6,141 )   (12,306 )

Other income (expense):

                                                 

Interest (expense)

    (57 )   (633 )   (3,405 )   (9,075 )   (3,815 )   (5,551 )   (4,714 )   (2,308 )

Loss on extinguishment of debt

        (95 )   (497 )           1,634          

Other income, net

            247     688     195     504     688     504  
                                   

Income (loss) before income taxes

    (2,625 )   (1,166 )   (9,486 )   (12,831 )   528     (19,208 )   (10,167 )   (14,110 )

Income tax (expense) benefit

        (35 )   (222 )   (208 )   (305 )   (156 )   (227 )   (156 )
                                   

Net income (loss) from continuing operations

    (2,625 )   (1,201 )   (9,708 )   (13,039 )   223     (19,184 )   (10,394 )   (14,266 )

Net income (loss) from discontinued operations(3)

            1,320     (1,182 )   (23 )   (9,608 )        
                                   

Net income (loss)

    (2,625 )   (1,201 )   (8,388 )   (14,221 ) $ 200   $ (28,792 ) $ (10,394 ) $ (14,266 )

General partner's interest in pro forma net income (loss)

                                                 

Common unit holder's interest in pro forma net income (loss)

                                        (5,197 )   (7,133 )

Subordinated unit holder's interest in pro forma net income (loss)